EPA-600/2-76-064
March 1976
Environmental Protection Technology Series
ATMOSPHERIC POLLUTION POTENTIAL FROM
FOSSIL FUEL RESOURCE EXTRACTION,
ON-SITE PROCESSING, AND TRANSPORTATION
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
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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 five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides (he new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/2-76-064
March 1976
ATMOSPHERIC POLLUTION POTENTIAL
FROM FOSSIL FUEL RESOURCE EXTRACTION,
ON-SITE PROCESSING, AND TRANSPORTATION
by
E.G. Cavanaugh, G. M. Clancy, J.D. Colley, P.S. Dzierlenga,
V.M. Felix, B.C. Jones, andT.P. Nelson
Radian Corporation
P.O. Box 9948
Austin, Texas 78766
Contract No. 68-02-1319, Task 19
ROAP No. 21ADD-042
Program Element No. 1AB013
EPA Task Officer: L. Lorenzi, Jr.
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
Information in this report was compiled for the pur-
pose of providing the Environmental Protection Agency with
technical information relative to atmospheric emissions from
facilities for extraction, on-site processing, and transporta-
tion of fuel resources. Fuel resources considered are coal,
oil shale, oil, and gas.
The nature of each operation is described, including
past, present, and projected future practices. Potential air
emissions from each type of facility are defined and quantified,
where possible. The status of monitoring methods and control
techniques for these emissions are discussed.
Areas where research and development can be usefully
applied to production and air emission control problems are
identified.
111
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TABLE OF CONTENTS
Page
ABSTRACT iii
LIST OF TABLES vii
LIST OF FIGURES xii
1.0 SUMMARY . 1
1.1 Project Objectives 1
1.2 Study Approach 2
1.3 Conclusions and Comments 5
2.0 PROCESS TECHNOLOGY DESCRIPTION 11
2.1 Coal Production 11
2.1.1 Underground Mining 11
2.1.2 Coal Preparation Plant 17
2.1.3 Surface Mining 20
2.1.4 In-Situ Combustion of Coal 25
2.2 Oil Shale Extraction 29
2.2.1 Room and Pillar Mining 29
2.2.2 Surface Mining 33
2.2.3 Sizing Operations 36
2.2.4 In-Situ Processing 38
2.3 Oil Production 43
2.3.1 Oil Removal 43
2.3.2 Brine Removal 46
2.3.3 Oil-Gas Separation 51
2.3.4 Crude Storage 51
2.3.5 Water Treating 53
2.3.6 Secondary, Tertiary Recovery 58
2.3.7 In-Situ Combustion 59
2.4 Gas Production 61
2.4.1 Gas Field Operations 61
2.4.2 Gas Processing Plant Operations 64
2.5 Transportation 77
2.5.1 Coal Transportation 77
2.5.2 Crude Oil Transportation 82
2.5.3 Gas Pipeline Transportation 85
iv
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TABLE OF CONTENTS (Cont.)
Page
3.0 IDENTIFICATION OF EMISSIONS . 87
3.1 Coal Production Modules 89
3.1.1 Strip Mine Module 89
3.1.2 Room and Pillar Mining Module 102
3.1.3 In-Situ Coal Production Module 112
3.2 Oil Shale Extraction Modules 116
3.2.1 Surface Mine Module 116
3.2.2 Room and Pillar Mine Module 122
3.2.3 In-Situ Shale Oil Production 127
3.3 Oil Production Module 134
3.4 Gas Production Module 145
3.5 Transportation Modules 156
3.5.1 Coal Transportation Modules 156
3.5.2 Oil Transportation Modules. . . 166
3.5.3 Gas Transportation Module 176
3.6 Comparison of Module Emissions 178
4.0 MONITORING TECHNOLOGY 182
4.1 Ambient Air Quality Monitoring 184
4.1.1 Background 184
4;1.2 General Monitoring Considerations 186
4.2 Source Monitoring for Air 190
4.2.1 Background 190
4.2.2 General Monitoring Procedures 193
5.0 EMISSION CONTROL TECHNOLOGY 196
5.1 Particulate Control Systems 197
5.1.1 Sources of Particulate Emissions 197
5.1.2 Control Methods for Particulate Emissions . . . 201
v
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TABLE OF CONTENTS (Cont.) •
Page
5.2 S02 Control Systems 213
5.3 Hydrocarbon Control Systems 217
5.4 Nitrogen Oxides Control Systems 222
5.5 Carbon Monoxide Control Systems 226
5.6 Fugitive [Emissions Control.. . . 229
6.0 POTENTIAL PRODUCTION PROBLEMS. . ..'234
6.1 Coal Production 234
6.1.1 Underground Mining Operations ... 234
6.1.2 Surface Mining Operations ... 236
6.1.3 Coal Preparation 237
6.2 Oil and Gas Production 243
6.2.1 Drilling Operations 243
6.2.2 Production Phase 245
f-
7.0 AREAS FOR RESEARCH AND DEVELOPMENT 261
REFERENCES '269
CONVERSION FACTORS 277
vi
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LIST OF TABLES
Page
TABLE 1.3-1 COMPARISON OF EMISSIONS FROM EXTRACTION
MODULES 6
TABLE 1.3-2 COMPARISON OF EMISSIONS FROM TRANSPORTA-
TION MODULES 7
TABLE 2.1-1 ESTIMATED BITUMINOUS AND LIGNITE
PRODUCTION FOR 1973 12
TABLE 2.1-2 COMPARISON OF CONVENTIONAL, CONTINUOUS,
AND LONGWALL MINING 18
TABLE 2.3-1 OIL PRODUCTION OPERATING OPTIONS 44
TABLE 2.3-2 CLASSIFICATION OF PRIME MOVERS 45
TABLE 2.4-1 TYPICAL DISTRIBUTION OF COMPONENTS IN U.S.
NATURAL GAS AT THE WELL 63
TABLE 2.4-2 TYPICAL ACID GAS TREATING PROCESSES. ... 68
TABLE 3.1-1 SUMMARY OF ATMOSPHERIC EMISSIONS - STRIP
MINING COAL MODULE 90
TABLE 3.1-2 MODULE EMISSIONS - STRIP MINING COAL
MODULE 97
TABLE 3.1-3 AIR EMISSION FACTORS FOR HEAVY-DUTY
DIESEL ENGINES 98
TABLE 3.1-4 THERMAL DRYERS 101
vii
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LIST OF TABLES (Cont.)
Page
TABLE 3.1-5 EMISSION FACTORS FOR THERMAL DRYING WITH
A FLUIDIZED-BED DRYER 101
TABLE 3.1-6 SUMMARY OF ATMOSPHERIC EMISSIONS - ROOM
AND PILLAR COAL MINE MODULE 103
TABLE 3.1-7 MODULE EMISSIONS - ROOM AND PILLAR COAL
MINE MODULE 108
TABLE 3.1-8 AIR EMISSION FACTORS FOR HEAVY-DUTY
DIESEL ENGINES Ill
TABLE 3.1-9 EMISSION FACTORS FOR BURNING REFUSE
PILES Ill
TABLE 3.1-10 SUMMARY OF ATMOSPHERIC EMISSIONS - IN-SITU
COAL PRODUCTION MODULE 113
TABLE 3.1-11 TYPICAL GAS ANALYSIS OF IN-SITU COAL FUEL
GAS 115
TABLE 3.2-1 SUMMARY OF ATMOSPHERIC EMISSIONS - OIL
SHALE SURFACE MINING MODULE 117
TABLE 3.2-2 MODULE EMISSIONS - OIL SHALE SURFACE MINE
MODULE 119
TABLE 3.2-3 SUMMARY OF ATMOSPHERIC EMISSIONS - OIL
SHALE ROOM AND PILLAR MINE MODULE 123
TABLE 3.2-4 MODULE EMISSIONS - OIL SHALE ROOM AND
PILLAR MINE MODULE 126
viii
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LIST OF TABLES (Cont.)
Page
TABLE 3.2-5 SUMMARY OF ATMOSPHERIC EMISSIONS - IN-SITU
SHALE OIL PRODUCTION MODULE 128
TABLE 3.2-6 CHARACTERISTICS OF GASES FROM IN-SITU
RETORTING 131
TABLE 3.2-7 MODULE EMISSIONS - IN-SITU OIL SHALE
PRODUCTION MODULE 133
TABLE 3.3-1 SUMMARY OF ATMOSPHERIC EMISSIONS -
DOMESTIC CRUDE PRODUCTION MODULE 135
TABLE 3.3-2 MODULE EMISSIONS - DOMESTIC CRUDE OIL
PRODUCTION MODULE 139
TABLE 3.3-3 AIR EMISSION FACTORS FOR THE COMBUSTION
OF NATURAL GAS AND FUEL OIL 140
TABLE .3.3-4 HEATER TREATER HEAT REQUIREMENTS 141
TABLE 3.3-5 STEAM GENERATOR HEAT LOADS 141
TABLE 3.3-6 MISCELLANEOUS OIL PRODUCTION EMISSION
FACTORS 143
TABLE 3.3-7 EMISSION FACTORS FOR FLARING AND OIL
DISCHARGE 143
TABLE 3.4-1 SUMMARY OF ATMOSPHERIC EMISSIONS - GAS
PRODUCTION MODULE 146
TABLE 3.4-2 MODULE HEAT REQUIREMENT - GAS PRODUCTION
MODULE 151
TABLE 3.4-3 MODULE EMISSIONS - GAS PRODUCTION AND
PROCESSING MODULE 152
ix
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LIST OF TABLES (Cont.)
Paee
TABLE 3.4-4 EMISSION FACTORS FOR GAS PRODUCTION
MODULE 153
TABLE 3..5-1 SUMMARY OF ATMOSPHERIC EMISSIONS- RAIL
TRANSPORT OF COAL MODULE 157
TABLE 3.5-2 WORK OUT-PUT - BASED LOCOMOTIVE EMISSION
FACTORS 159
TABLE 3.5-3 FUEL - BASED LOCOMOTIVE EMISSION FACTORS . 159
TABLE 3.5-4 SUMMARY OF ATMOSPHERIC EMISSIONS - BARGE
TRANSPORT OF COAL MODULE 163
TABLE 3.5-5 EMISSION FACTORS FOR HEAVY-DUTY, DIESEL
POWERED VEHICLES 165
TABLE 3.5-6 SUMMARY OF ATMOSPHERIC EMISSIONS - CRUDE
OIL PIPELINE TRANSPORTATION MODULE .... 167
TABLE 3.5-7 SUMMARY OF ATMOSPHERIC EMISSIONS - CRUDE
OIL TANKER WHILE IN-TRANSIT 170
TABLE 3.5-8 SUMMARY OF ATMOSPHERIC EMISSIONS - CRUDE
OIL TANKER WHILE IN BERTH 171
TABLE 3.5-9 SUMMARY OF ATMOSPHERIC EMISSIONS - CRUDE
OIL RAIL TRANSPORTATION MODULE 174
TABLE 3.5-10 SUMMARY OF ATMOSPHERIC EMISSIONS - NATURAL
GAS PIPELINE TRANSPORTATION MODULE .... 177
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LIST OF TABLES (Cont.)
TABLE 3.6-1 COMPARISON OF EMISSIONS FROM EXTRACTION
MODULES 180
TABLE 3.6-2 COMPARISON OF EMISSIONS FROM TRANSPORTA-
TION MODULES 181
TABLE 4.1-1 SUMMARY OF AMBIENT AIR STANDARDS 185
TABLE 4.2-1 PROPOSED EMISSION LIMITS FOR COAL
PREPARATION PLANTS 191
TABLE 5.1-1 PARTICULATE CONTROLS FOR CRUSHING AND
SCREENING OPERATIONS 206
TABLE 5.1-2 PARTICULATE EMISSION CONTROLS FOR COAL
THERMAL DRYERS 212
TABLE 5.2-1 PROCESSES FOR GLAUS TAIL GAS TREATMENT . . 214
XI
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LIST OF FIGURES
FIGURE 2.1-1
FIGURE 2.1-2
FIGURE 2.1-3
FIGURE 2.1-4
FIGURE 2.1-5
FIGURE 2.1-6
FIGURE 2.1-7
FIGURE 2.2-1
FIGURE 2.2-2
FIGURE 2.2-3
FIGURE 2.2-4
Page
THE THREE TYPES OF ACCESS USED IN
UNDERGROUND COAL MINES 13
ILLUSTRATION OF ROOM AND PILLAR MINING
USING CONVENTIONAL (BLASTING) AND
CONTINUOUS MINING TECHNIQUES 15
ILLUSTRATION OF LONGWALL MINING
TECHNIQUE 16
WET COAL CLEANING PROCESS 21
DRY COAL CLEANING PROCESS 22
AREA MINING 24
U.S. PATENT ON IN-SITU GASIFICATION OF
COAL UTILIZING NON-HYPERSENSITIVE
EXPLOSIVES 27
ROOM AND PILLAR MINE 30
STEPS INVOLVED IN OIL SHALE SURFACE
MINING 34
SHALE SIZING OPERATIONS 37
SCHEMATIC REPRESENTATION OF AN IN-SITU
RETORTING OPERATION 40
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LIST OF FIGURES (Cont.)
FIGURE 2.2-5
FIGURE 2.3-1
FIGURE 2.3-2
FIGURE 2.3-3
FIGURE 2.3-4 .
FIGURE 2.3-5
FIGURE 2.3-6
FIGURE 2.3-7
FIGURE 2.4-1
FIGURE 2.4-2
FIGURE 2.4-3
FIGURE 2.4-4
FIGURE 2.4-5
FIGURE 2.4-6
Page
WELL MOVEMENT IN IN-SITU SHALE PROCESS. 41
HEATER TREATER 48
PICTORIAL ASSEMBLY OF PETRECO ELECTRIC
DEHYDRATOR 49
WASH TANK 50
OIL-GAS SEPARATORS 52
BOLTED STEEL TANK 54
VAPOR RECOVERY SYSTEM 55
WASTEWATER SYSTEM 57
FLOW DIAGRAM FOR THREE-STAGE WELLHEAD
SEPARATION UNIT 65
NATURAL GAS PROCESSING PLANT 67
TYPICAL AMINE TREATING UNIT 70
GLAUS SULFUR RECOVERY UNIT 71
TWO BED SOLID ADSORBENT TREATER 73
TYPICAL GLYCOL DEHYDRATION UNIT 74
Xlll
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LIST OF FIGURES (Cont.)
FIGURE 2.5-1
FIGURE 3.1-1
FIGURE 3.1-2
FIGURE 3.1-3
FIGURE 3.1-4
FIGURE 3.1-5
FIGURE 3.2-2
FIGURE 3.2-3
FIGURE 3.3-1
FIGURE 3.4-1
FIGURE 3.4-2
FIGURE 6.1-1
FIGURE 6.1-2
FIGURE A-l
BULK COAL MOVEMENTS 79
TYPICAL DRAGLINE OPERATION 92
STRIP MINING COAL MODULE 93
COAL CLEANING PLANT 94
TYPICAL SHAFT-TYPE MINE 104
ROOM AND PILLAR COAL MINE 106
OIL SHALE UNDERGROUND MINE 124
IN-SITU SHALE OIL PRODUCTION MODULE . . 129
CRUDE OIL PRODUCTION 137
GAS PROCESSING PLANT 147
NITROGEN OXIDES EMISSIONS FROM STATIONARY
INTERNAL COMBUSTION ENGINES 154
RELATIVE WATER SURPLUS OR DEFICIENCY
IN THE UNITED STATES 241
LARGE RIVERS OF THE UNITED STATES ... 242
SURFACE-WATER LAWS 253
xiv
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LIST OF FIGURES (Cont.)
Page
FIGURE A-2 GROUND-WATER LAWS 255
xv
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1.0 SUMMARY
1.1 Project Objectives
The objective of this report is to provide technical
information on the atmospheric environmental problem definition
associated with the production, on-site processing, and trans-
portation of coal, oil, and gas. This report includes the
following major elements:
(1) A review of the current status of coal,
oil, and gas production technology
including on-site processing and
transportation.
(2) A review of the oil shale mining tech-
nology, including in-situ shale oil
production.
(3) Modules developed to represent typical
processing sequences for the production
and transportation of these fuels.
(4) Identification of the source, quantity,
and composition of atmospheric emissions
from each module.
(5) A review of monitoring methods applicable
to known or projected emission sources.
(6) A review and comparison of control methods
which may be employed in the production and
transportation modules.
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(7) Identification of problem areas associated
with extraction processes.
(8) Identification of priority work areas
for research and development.
1.2 Study Approach
The work performed in this study has been divided into
essentially two areas: (1) the identification of atmospheric
emissions and emission sources for the various technologies and
(2) the evaluation of environmental requirements resulting from
these emissions in terms of monitoring methods, control tech-
niques, plant impact problems, and areas requiring research and
development. Sections 2.0 and 3.0 of this report review the
various extraction, processing, and transmission technologies
and establish the emissions associated with each. Sections 4.0
through 7.0 address various environmental problems associated
with these emissions.
A modular approach is utilized in this study whereby
segments of the industries examined are represented as typical
operating units, each with its characteristic atmospheric
emissions. The initial step in establishing these modules
includes a review of the technology involved in each industry.
Extraction and transportation alternatives are considered, as
are options for on-site upgrading. State-of-the art descriptions
for the coal, shale oil, petroleum oil, and gas production and
transportation industries presented in Section 2.0 are the basis
for process modules derived in Section 3.0.
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This report is limited to the air emissions from these
technologies. Criteria pollutants such as particulates, SO ,
X
CO, NO , and hydrocarbons are quantified in Section 3.0 to the
A.
extent such information was available from the literature. There
was no attempt to quantify trace elements, trace organics, or
potentially hazardous chemicals in air emissions; nor were liquid
effluents and solid wastes addressed in detail in this study.
Modules presented in this report are as follows:
Production
strip mining of coal
room and pillar coal mining
in-situ coal gasification
surface oil shale mining
room and pillar oil shale mining
in-situ shale oil production
oil well production
gas well production
Transportation
coal by rail
coal by barge
coal by pipeline
oil by rail
oil by tanker
oil by pipeline
gas by pipeline
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Three coal extraction methods are presented. Similar mining
modules for oil shale are included to illustrate the similari-
ties and differences in the two technologies. Module capacities
or flow rates were assumed typical of current commercial plant
operations. After each module basis is established in terms of
operation, capacity, and energy or fuel demand, the character
and sources of emissions for that module are identified. Module
emissions per equivalent unit of fuel value handled are also
compared in this report.
Regulations and monitoring techniques applicable to
the identified emission sources are discussed in Section 4.0.
Ambient air sampling and analytical methods are discussed.
Problem areas associated with monitoring technology, such as
accuracy and costs, are identified and gaps in technology noted.
Emission control techniques are addressed in Section
5.0. Potential control methods are described and alternative
control methods are compared. Special problems, such as measure-
ment and control of fugitive emissions, are discussed. Control
methods for achieving maximum pollutant reduction are identified
and techniques having potentital for near zero discharge are
described.
Problems associated with extraction technologies are
presented in Section 6.0. Criteria such as raw material supply,
energy supply, product transportation, and federal, state and
local laws are discussed.
Priority work for research and development activities
is suggested in Section 7.0. Areas related to pollutant identi-
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fication, emission quantification, and control methods are
identified. Priority areas for control methods are established
based on the extent of pollutants controlled, on the need for
further control, on the degree of control possible, on the
impact and energy requirements of the control methods, and on
the status and cost of developments.
1.3 Conclusions and Comments
Air Emissions Overview
This study compares air emissions from facilities for
extracting and transporting fuels that represent the principle
sources, both present and future, of the nation's fossil fuel
energy supply. It is convenient and reasonable to compare
expected emissions from these operations on the basis of pounds
of emissions per unit of energy delivered.
Tables 1.3-1 and 1.3-2 coptain data summarizing much
of the investigations performed during this project. Estimated
emissions of criteria pollutants are given in pounds per day
for each "energy module" of one trillion Btu per day. The
technologies studied range from those defined as established
practice to those for which virtually no industrial experience
has been logged. For example, emissions from strip mining and
room and pillar mining of coal, both well established technolo-
gies, can reasonably be estimated with greater confidence than
those from in-situ shale oil recovery, which is virtually an
undeveloped industry. The value of these comparisons, however,
is allowing examination of the magnitude of emissions from
technologies both familiar and new, especially as they may impact
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TABLE 1.3-1
COMPARISON OF EMISSIONS FROM EXTRACTION MODULES
Basis: 10'*Btu/Day Fuel Output
Air Emissions. Ib/day
Coal Mining
Pollutant
Particular*
SO,
CO
K°«
Hydrocarbons
Strip
11,900
273
2.290
3.740
432
(11
(IS, 200)
( 8,730)
( 2.610)
( 7.870)
< 568)
Room and
6,190
8.530
562
4,560
352,000
Pillar [2]
(84,000)
(125.000)
(233,000)
( 42,900)
(391.000)
Xn-Sltu [31
5.500
HA
30.000
NA
6S.OOO
Oil Shale Hinlnc
.Surface [4]
65.200
1.680
14.100
23.100
2.620
Room and
Pillar [5]
• U.100
39.3
335
550
64.2
Zn-Sltu [61
107.000
239.000
414.000
12.400
48.000
Oil Well
Production [71
1.130
12.910
8.290
20,400
21.300
Cat Bell
Production 181
200
44.900
200
63.000
273.000
(11 Adjusted from 6,300 TPD run-of-mine coal (12,000 Btu/lb). Emissions In parentheses include emissions from physical coal cleaning.
(2) Adjusted from 6,300 TPO run-of-nine coal (12,000 Btu/lb). Mining emission value* include emissions from physical coal cleaning. Emission*
in parentheses include emissions from burning refuse piles. '
[3] Adjusted fro.i lO'Btu/day fuel gas produced. Data on SO and NO emissions were hot available,
[4] Adjusted from 50,000 bbl/day of upgraded shale oil capacity (5.6xx lO'fltu/bbl).
[5] Adjusted from 50,000 bbl/day of upgraded shale oil capacity (5.6 x 10*Btu/bbl).
(6] Adjusted from 50.000 bbl/day of upgraded shale oil capacity (5.6 x 10*Btu/bbl).
[7] Values adjusted from module producing 1.000 BPO crude oil (5.6 x 10(Btu/bbl), assuming us* of water flooding, hester treater, and SOZ
brine concent.
[8] Values adjusted from production of 5.0 x lO'sCFD gas (1000 Btu/SCF).
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TABLE 1.3-2
COMPARISON OF EMISSIONS FROM TRANSPORTATION MODULES
Basis: 1012Btu/Day Fuel Output
Coal Transportation
Pollutant.
?srticulates
S0x
CO
S0*
Hydrocarbons
Rail til
1.260
2.840
3,410
17.700
8,200
Barire (2!
281
583
4.880
8,020
931
Slurry
Pipeline [3]
Negligible
Negligible
Negligible
Negligible
Negligible
Air Emissions, Ib/day
Rail Tar.ker
Transportation Transportation of Oil [51
of Oil (4] In-Transit Loading Unloading
1,730
3,980
5,250
27,500
107,000
370
Neg.
480
3,300
3
30
Neg.
40
18,000
3
30
Neg.
40
16,000
?ipelina
Pipeline
Tra-sportation Transportation
of Oil (61 "of Gas [7j
122
253
2,110
3,470
403
Negligible
Negligible
Negligible
241,000
Negligible
II] Adjusted frc=v 12.600 cons of coal transported (12,000 Btu/lb).
[2]Adj-js = ed fro=j 20,000 TFD coal transported (12,000 Btu/lb).
[3] A slurry pipeline powered by electrically driven punp stations should have negligible atmospheric emissions directly associated
with the pipeline.
14] Adjusted frcr-. 10£cal/day oil transported (5.5 x 10s Bcu/bbl) .
[3] Adjusted frca transportation of 325,000 3?D oil (5.6 x 106Btu/bbl)
[=] Adj-js:ad fros transportation of 42,000g?3 oil (5.6 x 106Dtu/bbl).
I7j Adjusted frc= transportation of 80.2 XXSCFD pipeline gas (1000 Btu/SCF).
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the environment as the quantities and natures of fuels change.
The possible trends to extraction of Western coals
can change the nature of emissions considerably. Compared to
room and pillar methods, strip mining operations have minimal
hydrocarbon emissions, but larger particulates, while in-situ
coal combustion to produce low-Btu fuel gas will be a high car-
bon monoxide emitter. Refuse burning at existing room and
pillar coal mines is a major contributor to emissions from these
operations.
Oil shale mining and in-situ removal of shale oil
must be considered as potential sources of domestic energy
because of the huge deposits of oil shale in the Western United
States. Much of the oil shale extraction technology is similar
to coal extraction and therefore has comparable types of emissions.
The quantity of emissions are probably much greater than the coal
extraction emissions due to the order-of-magnitude larger quantity
of material handled per unit of recoverable energy. It is expected
that solid disposal and land use impacts will be of greater concern
than air emissions from oil shale operations, except possibly with
in-situ removal.
Oil and gas well emissions are well established
through years of experience. While criteria pollutants from
gas wells are by nature quite large, especially hydrocarbons
and sulfur and nitrogen compounds, the remoteness of most wells
tends to minimize the impact of these emissions.
Transportation modules do not appear to be serious
emitters. Oil transportation by rail is a potential source of
hydrocarbon emissions; however, this is a little-used means of
transporting domestic oil. NO exhausted from gas-fired com-
X
pressor drivers is a major emission from gas pipeline operations.
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Modular Concept
Considerable value was derived in using the modular
approach to expressing the various technologies. First, it
allowed each process or operation to be examined as an actual
commercial unit. The types of equipment from which emissions
are known to come were studied individually. Examples are
emissions from diesel-fueled vehicles, coal-fired dryers, and
gas-fired compressors. Second, much of the equipment used in
established industries, such as coal mining and processing, will
undoubtedly be used also in less developed technologies. Thus,
there are emissions data translatable to new technology based
on knowledge of existing boilers, grinders, compressors, and so
forth.
Monitoring and Control Technologies
The technologies for monitoring criteria pollutants
are fairly well established. Still to be resolved, however, is
the relationship between what leaves an extraction or transpor-
tation module and how that emission impacts the environment.
Devices for controlling the criteria pollutants are also avail-
able, although the relationship between source emissions, the
areas impacted, and emission regulations is often obscure.
The need for further work in ambient air quality and
air emissions is underlined in Section 7.0. Work in some mine
areas relating to ambient air quality is suggested. A similar
block of tasks for air emissions technology has been recommended.
Other work considered useful involves studies updating costs of
the extraction and transportation modules. Other areas of concern
are water monitoring, effluent control, and solid waste disposal
-9-
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problems which are outside the scope of this program, but which
are closely related environmental problems. Non-criteria air
emissions, especially potentially hazardous compounds from
extraction and transportation modules, will receive considerable
attention in the future.
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2.0 PROCESS TECHNOLOGY DESCRIPTION
Descriptions of the present status of the coal, oil,
and gas production and transportation technologies are presented
in this section of the report. The operations associated with
each of the technologies are identified, and various alternatives
are discussed. Typical processing sequences are presented for
each production industry. This state-of-the-art review provides
a basis for the selection of specific modules to represent the
technologies for emission determinations in Section 3.0.
2.1 Coal Production
Due to the present-day emphasis on coal as an energy
source, coal production has become of primary national interest.
The types of mining operations used can be divided into two
categories, underground mining and surface mining. The under-
ground mining techniques are conventional room and pillar,
continuous room and pillar, and longwall. The surface mining
techniques are strip or area mining and contour and auger mining.
A summary of 1973 production rates for the various methods is
given in Table 2.1-1 (NI-036). Extraction of coal as a gas by
in-situ gasification techniques can also be considered as a
potential method of removing coal energy from the ground, although
this technique is in the experimental phase of development.
2.1.1 Underground Mining
The development of all three types of underground
mines follows the same procedures. First, at least three main
accesses or shafts are strategically driven to the coal bed.
The accesses can be of three types: drift, slope, or shaft.
These types of accesses are shown in Figure 2.1-1 (TR-049).
-11-
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TABLE 2.1-1
ESTIMATED BITUMINOUS AND LIGNITE
PRODUCTION FOR 1973
Millions
Underground Mining of Tons Percent of Total
Continuous Room & Pillar 181.0 30.7
Longwall 8.0 1.3
Conventional Room & Pillar 102.0 17.3
Surface Mining
Strip Mining 283.0 48.0
Auger Mining 16.0 2.7
Total 590.0 100.0
-12-
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LESS THAN;
*30 DEC !
K^^^a^Ksftas^iSss;
DRIFT
SLOPE
SHAFT
FIGURE 2.1-1
THE THREE TYPES OF ACCESS USED
IN UNDERGROUND COAL MINES
-13-
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Once the main accesses have been constructed, two parallel main
entries into the coal bed are driven in the direction of the
mining operation. From the main entries, panel entries are
driven and divide the coal seam into blocks. Finally, from the
panel entries, butt entries are made into the coal seam. The
butt entries will result in the formation of "pillars" which
support the roof. This is the room and pillar or advance type
mine. This method of mining will recover approximately 50
percent of the coal. If the ground can be allowed to subside,
an additional 35 percent of the total amount of coal can be
removed by retreat mining. Instead of the butt entries a long-
wall technique can be used in which the entire side of the panel
is mined at once leaving no pillar. Longwall mining removes 80
to 85 percent of the coal in the mine (TR-049).
Room and pillar mining, as previously mentioned, is
either performed by conventional methods or by continuous miners.
Figure 2.1-2 illustrates both of these methods (TR-049). In
conventional methods the coal seam is blasted and then loaded by
electric loaders on shuttle cars or conveyors and hauled to the
main conveyor or mine rail car train. With the electric continu-
ous miner the coal is scraped from the seam and loaded directly
on a conveyor or shuttle car. The coal is transported to the
-,_ •
main conveyor or mine rail car train, and from there out of
the mine.
Longwall mining has been very popular in Europe but is
not used extensively in the United States. The longwall process
is shown in Figure 2.1-3 (TR-049). The electric longwall miner
advances laterally down the panel scraping and shearing the coal
-14-
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I
M
Ul
(A) CONVENTIONAL 4
MINING
(B) CONTINUOUS
MINING
FIGURE 2.1-2 ILLUSTRATION OF ROOM AND PILLAR
MINING USING CONVENTIONAL
(BLASTING) AND CONTINUOUS MINING
TECHNIQUES
-------
LONGWALL
PANEL
. BELT
CONVEYOR
HEADPIECE
LONGWALL MINING
REQUIRES MULTIPLE ENTRY
DEVELOPMENT ON EACH
SIDE OF THE PANEL TO PROVIDE
VENTILATION, ACCESS, AND
CONVEYOR ROUTES.
TAILPIECE
LONGITUDINAL
ADVANCEMENT
SHEARING
DRUM
LATERAL
ADVANCEMENT
FIGURE 2.1-3 ILLUSTRATION OF LONGWALL MINING
TECHNIQUE
-------
from the seam. The coal is automatically loaded on a self-
advancing conveyor and transported to the main conveyor or mine
rail car train. The roof is supported at the mine face by self-
advancing hydraulic roof supports. Behind the supports, the
roof is allowed to collapse. The subsidence is sometimes enhanced
by blasting to ensure a more controlled cave-in rate (TR-049).
The advantages and disadvantages of room and pillar
conventional and continuous mining and longwall mining are given
in Table 2.1-2 (TR-049).
Ventilation in the mine is generally provided by
induced draft fans. At the mining faces where methane production
is high,additional ventilation is required to maintain methane
concentrations to less than 1.0 volume percent (TR-049). Dust
in the mine is controlled by water or chemical sprays. Dusty
conveyors, in particular, are covered to reduce emissions. If
crushing is performed in the mine, dust emissions resulting
from the crushers can be contained and controlled by fabric
filters or wet scrubbers.
2.1.2 Coal Preparation Plant
The coal from the mine is hauled to the surface by
conveyors or shuttle cars. In the case of shaft mines, skips
are used to lift coal to the surface. On the surface, the coal
is prepared to various degrees depending on the demand for
various coals in the area. There are three types of coal prep-
aration plants: (1) "complete preparation" - those that clean
both coarse and fine coal, (2) "partial preparation" - those
that clean only coarse coal, and (3) "coal crushing" - where the
coal is merely crushed to a specific size (EN-220).
-17-
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TABLE 2.1-2
COMPARISON OF CONVENTIONAL, CONTINUOUS, AND
LONGWALL MINING
LONGWALL
CONTINUOUS ROOM
AND PILLAR
CONVENTIONAL
ROOM AND PILLAR
Advantages
CO
i
Increases production i
Eliminates some permanent
roof support cost
Cuts cost of ventilation,
storage, and rock dusting <
by 45%.
Provides better ventilation,
roof support.
Requires less supervision.
Safer-superior method where
roof conditions are poor.
Involves fewer work cycles, less
equipment, and normally produces
more per man than conventional
mining.
.Permits more concentrated mining
with fewer supervisory and venti-
lation problems.
Effective in coalbeds with
high hardness ratings,
large partings* and varying
dimensions.
Produces less fine coal.
Efficient where roof and
floor planes undulate-
Disadvantages •
Requires large, level,
straight blocks of coal free
from obstructions with
seam height minimum of
39".
Requires high capital invest-
ment for equipment.
Involves costly equipment
moves (30-150 man-shifts
to move 300 tons of equip-
ment).
Not effective where hardness
ratings are high, partings4 large,
floor and ceiling planes undulate,
and roof conditions are poor.
Not effective where seam heights
vary greatly.
Cannot be used where coal size
is critical.
Provides inefficient face haulage.
Requires numerous work
cycles.
Involves larger crew and
more equipment with
attendant supervisory and
maintenance problems.
Produces less per man.
Provides inefficient face
haulage.
Not efficient where roof
conditions are poor.
Partings are impure bands in coalbeds.
-------
The first operation in all three types of preparation
plants is crushing and screening of the coal. Crushing releases
entrained impurities such as clay, rock, and other inorganic
material, generally called ash. The coal is sometimes recrushed
to ensure separation of these entrained materials. The coal is
screened and routed to various cleaning processes or to storage
bins depending on the sizes of the crushed coal. Cleaning
processes are either wet, dry, or a combination of both.
Wet cleaning utilizes specific gravity differences
between the coal and the separated materials. The coal along
with the refuse after being crushed is submerged in an aqueous
solution of predetermined specific gravity. These specific gravi-
ties range from 1.30 (approximately the specific gravity of coal)
to as high as 2.00 (ZI-014). Generally, the lowest specific
gravity will give the best separation of both the pyritic sulfur
and the ash materials from the coal. This, however, results in
a low total yield of coal. Finer crushing of the coal helps
increase the yield while maintaining low sulfur and ash contents.
It should be noted, however, that it is impractical to transport
fine coal (1/4 to 3/8 inch) in open railroad cars due to windage
losses and storage problems (ZI-014). The degree of crushing and
the specific gravity of the floatation liquid is determined by
the demand for specific quality coals. Further separation of
smaller diameter coal and refuse ash can be performed by dense
media cyclones or froth floatation units.
After the coal is wetted in the separation process,
it is dried mechanically by dewatering screens which are followed
by centrifugal dryers or vacuum filters for small particles. For
finer coals with low moisture content (3 to 6 percent) secondary
-19-
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drying by thermal dryers is required. Three types of thermal
dryers are fluidized, flash, and multilouvered dryers. Fluidized
bed types are used for approximately 67 percent of thermal dry-
ing applications (HI-083). In 1972, 18.2 percent of all mechani-
cally cleaned coal was thermal dried (US-144). A complete wet
cleaning system is shown in Figure 2..1-4 (ZI-014).
Dry cleaning of coal involves separation of the refuse
ash from the coal by pulsating air on air tables (EN-220). The
coal and refuse become stratified by the air into a bed with
the heavier refuse on the bottom. The upper layer of coal is
separated and stored in bins for loading on trucks, barges, or
unit trains. The particulate emissions from the air tables are
controlled by multiple cyclones followed by fabric filters. A
typical dry cleaning process is shown in Figure 2.1-5 (EN-220).
2.1.3 Surface Mining
The two types of surface mining of coal are strip or
area mining and auger or contour mining. These operations are
briefly described below.
The conventional strip or area mine is used mainly in
relatively flat terrain where the coal seam is parallel to the
surface. This technique is ideal for western coals. The area
mine is started with a box-cut or trench extending from one side
of the vein to the other. If the overburden is rock or shale
it will have to be blasted. Six-inch blasting holes are drilled
to the coal seam in a square grid of 15 to 25 feet and a typical
charge of 300 pounds of ammonium nitrate and fuel oil packaged
in tubes is placed in the holes (ST-166). The blasting material is
-20-
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RAW COAL IN
i
ho
MIST
ELIMINATOR
PRIMARY
COLLECTORS
WET
CLEANING
±
MECHANICAL
DRYING
3
WATER
TREATMENT
REFUSE
BIN
'IA T0
)y STORAGE
v
FIGURE 2.1-4 WET COAL CLEANING PROCESS
-------
RAW COAL IN
ho
N>
SECONDARY
COLLECTORS
PRIMARY
COLLECTORS
TO
STORAGE SILO
FIGURE 2.1-5 DRY COAL CLEANING PROCESS
-------
detonated with electric blasting caps. The overburden is removed
by electric™or diesel-powered stripping shovels or draglines.
The uncovered coal is loaded by loading shovels into trucks or
conveyors and transported out of the mine, after which the coal
is crushed and may be mechanically cleaned. The overburden from
each successive parallel cut by the stripping shovel or dragline
is deposited on a spoil bank located in the preceding trench.
Strip mining has a recovery rate of 80 to 90 percent with coal
losses mainly due to spillage and losses in transit (ST-166).
A typical area mining operation is shown in Figure 2.1-6 (EN-096).
The depth of overburden which can be removed economi-
cally will depend on the thickness of the coal seam. As a rule,
area mining can be performed where overburdens are not more than
200 feet thick (ST-166). Greater depths may become economically
feasible in the future depending on technology, economics, and
environmental concerns.
Contour and auger mining are performed in hilly terrain.
The contour mine is developed in the same methods as the area mine
except that the mine is excavated in a path following the terrain
of the particular area. The mining equipment used in contour
mining is generally smaller than that used for area mining
(ST-166). When the side walls of the mine become too high for
strip mining, augers are used to recover additional coal. Large
augers are driven horizontally about 200 feet into a coal seam
(EN-096). Coal is recovered in a form of chips similar to wood
chips from a drill bit. The introduction of dual and multiple
augers has helped increase the percent recovery of coal from
thin seams. The auger holes are backfilled by special compaction
techniques. Recovery rates for auger mining are thought to be
-23-
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Reclaimed Area
Original Ground ~>f^
Surface
FIGURE 2.1-6 AREA MINING
-24-
-------
around 75 percent but may be as low as 20 to 50 percent in
actual operation (ST-166). The major losses are from coal left
between the auger holes.
2.1.4 In-Situ Combustion of Coal
i
In-situ combustion of coal to produce a low Btu gas
phase for utility power generation in the U.S. is in the pilot
plant testing phase of development. The Bureau of Mines has per-
formed numerous tests at an in-situ pilot plant located at Hanna,
Wyoming (KA-124).
In-situ processing steps consist of pregasification
followed by gasification and production. The main feature of
pregasification is preparation of the bed by linking definable
points in the coal seam such as the inlet and outlet boreholes
or shafts. These linking processes generally increase the
permeability of the coal bed and allow for a smoother and
faster gasification process. Some coal seams are naturally quite
permeable and do not require "pregasification." The majority of
coal seams, however, do require some pretreatment. Methods of
linking the desired points in the bed include electrolinking,
pneumatic linking, and fracturing by hydraulic pressure,
explosives, or possibly nuclear reaction (KA-124, GA-104).
Electrolinking is performed by passing a current through
the coal seam carbonizing the coal. The rearrangement within the
coal structure increases its permeability. Pneumatic linking
involves pretreating the coal seam by passing high-pressure air
through it before the gasification step. Fracturing the seam
will obviously increase its permeability. Another possible link-
ing method is simply drilling holes through the coal seam from
the inlet air shaft to the existing gas shaft.
-25-
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The gasification of the coal seam includes introduction
of the gasifying agents, contacting of the agents with the coal,
recovery of combustion products, and control of the process.
The methods of gasification are classified as shaft-type,
shaftless-type, or a combination of both. Shaft-type gasifica-
tion requires the drilling of underground channels or passageways.
Shaftless requires only surface drilling operations.
The gasifying agents used are oxygen, steam, and carbon
dioxide. These gases are introduced in varying proportions and
contacted with the pretreated coal seam. The oxygen is combusted
with the carbon in the coal to form carbon dioxide. Water vapor
reacts with the coal to produce carbon monoxide and hydrogen.
Other reactions with the coal form more carbon monoxide, carbon
dioxide, and hydrogen. The exiting gas contains carbon monoxide,
carbon dioxide, hydrogen, water vapor, nitrogen, and various
volatile organics from the coal seam (GA-104). The exiting gas
stream will also contain heavier entrained hydrocarbons and
hydrogen sulfide. The heavy hydrocarbons can be removed by a
knockout tank while the hydrogen sulfide is removed by chemical
treating such as amine absorption. A typical in-situ gasification
process is diagrammed in Figure 2.1-7 (KA-124).
Experience with in-situ gasification has revealed the
following areas of technical difficulty (GA-104, KA-124):
(1) the heating value of gas is low and
tends to decrease with time,
(2) gas leakage from the gasification
area is common,
-26-
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No. 3,734,180 (May 22, 1973) V.W. Rhoades, Cities Service Oil
Company
224
213
202 overburden
210 Injection Well
213 Compressor
214 Fuel Gas and/or oxidizer
220 Production Well
228 Crumbled Coal
226 Combustion Front
227 Charred Residual
224 Fuel Gas Product
225 Coal Tar Products
[S7J
ABSTRACT
Two or more wells are drilled into a coal seam. The
wells are completed so as to isolate all other strata
from the coal seam and a radially extended horizontal
fracture is directed by introduction of a non-hypersen-
sitive explosive under hydraulic fracturing conditions
so as to connect the wclis communitively. The exple-
tive is ignited so that a horizontally and vcr.iczily
directed fracture network is formed within the coal
system. A combustion front is ignited and propagated
through the fractured network to produce combustible
gases and coal tar liquids.
3 Claims, 2 Drawing Figures
FIGURE 2.1-7 U.S. PATENT ON IN-SITU GASIFICATION OF COAL
UTILIZING NON-HYPERSENSITIVE EXPLOSIVES
-27-
-------
(3) the net percentage of coal energy
recovered is small,
(4) the groundwater can penetrate the
gasification zone and extinguish the
process combustion,
(5) the burned-out area can collapse
causing surface subsidence problems,
(6) the flame front is hard to control
directionally, and
(7) the coal beds are often not uniform;
combustion generally occurs with a
poor burning front.
Despite these disadvantages, in-situ coal gasification has the
following advantages over conventional mining (GA-104):
(1) the cost of equipment is much less,
(2) underground labor and its inherent
hazards are eliminated, and
(3) coal seams which are deep and other-
wise unminable can be recovered by
in-situ gasification.
-28-
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\
2.2 Oil Shale Extraction
Oil shale mining procedures consist of basically the
same techniques that are utilized in coal mining. The main
differences between the two industries are based on the massive
solids handling problems associated with oil shale extraction.
A typical oil shale deposit may contain 30 gallons of oil per
ton of shale. Approximately 73,700 tons per day of this raw
shale must be extracted to support a 50,000 bpd upgrading or
refinery facility.
Oil shale production methods include underground
(room and pillar) mining, surface mining, and in-situ oil shale
processing. In-situ processing is still in the developmental
stage. Room and pillar mining and surface mining are the more
advanced procedures since these methods rely on more conventional
extraction techniques.
Depending upon the physical characteristics at the
particular oil shale site, oil shale may be mined by either
surface or underground methods. Most actual experience with oil
shale involves underground mining. Underground mining techniques
are more universally applicable to the various oil shale deposits
than surface mining, and as a result probably will be extensively
utilized in the development of a shale oil industry. The Bureau
of Mines has demonstrated the feasibility of room and pillar
mining for oil shale at its facility near Rifle, Colorado.
2.2.1 Room and Pillar Mining
In room and pillar mining, pillars of shale are left in
place at appropriate intervals within the mine to provide roof
support. A schematic view of the room and pillar mining
-29-
-------
technique is shown below in Figure 2.2-1. Due to the large
amount of shale that must be extracted in order to produce a
significant amount of oil, room and pillar shale mining is more
like an underground quarrying operation. A typical raw shale
bed is 40 feet thick with a density of 90 lb/ft3 (US-093).
Underground extraction is estimated to be capable of removing
approximately 65% of the shale from a typical mine (HI-083).
SHALE
PILLAR
4
DIRECTION OF
MINING
FIGURE 2.2-1 ROOM AND PILLAR MINE
The normal mining method is to mine one side of the
mine on the advance to the tract limits, and mine the remaining
side on the retreat. Production panels would typically be mined
in a 30-foot-high-heading with a 20-foot-high-bench. Rooms and
pillars would be 60 ft wide.
Extraction is accomplished by drilling and blasting
the shale. The broken shale is loaded onto diesel trucks and
transported to a portable crusher. Crusher discharge is conveyed
to underground storage bins. From the storage bin, shale is
transported to secondary crushers on the surface.
Mine ventilation is accomplished by fans located in
the shale hoisting shafts. All atmospheric emissions exit
the mine with this ventilated air stream. Emissions within
the mine result from the drilling and blasting operation, the
diesel powered trucks, and the primary crusher. Fugitive dust
within the mine may be controlled by water sprays, while parti-
culates from the primary crushers may be reduced by use of water
scrubbers or bag filters.
-30-
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Water resulting from mine drainage and shale pile run-
off is routed to evaporation, containment ponds. ' This water may
be used for road dust control, shale pile wetting, and particu-
late control systems'. If the mine is close to the upgrading
facilities, the'mine water may be clarified and used as make-up
water for the upgrading facilities. Water initially pumped from
the mine should be of good quality; however, the water salinity
will probably increase with mine life. Another potential demand
for mine water is the reclamation operation. Water demand for
revegetation is not well defined. The water allocated for
revegetation in the environmental impact analysis for the TOSCO
II Parachute Creek Plant is 700 gpm (CO-175).
A major problem associated with oil shale extraction
involves solids waste handling and ultimate disposal of the
spent shale. Most shale oil production schemes plan to utilize
the mine site for disposal of some of the processed shale from
the retorting facility while the remaining spent shale will have
to be landfilled elsewhere. Approximately 90 wt % of the shale
remains after extraction and is returned to the mine as spent
shale. However, even with maximum compaction, the shale increases
in size by about 12 vol % during processing (US-093). Still,
about 60 percent of the processed shale may be back-filled in
an underground mine substantially reducing the surface disposal
impact. This is a major advantage of underground over surface
mining. The exact amount of back-fill depends on the type of
spent shale, degree of compaction, moisture content, and mine
volume used.
Spent shale may be returned to the mine by trucks,
conveyors, or a slurry piepline. If slurried, the slurry water
has to be collected in the mine and returned to the surface.
-31-
-------
The portion of the spent shale that cannot be accom-
modated underground must be contained on the surface. Although
the fixed-land requirement for an underground mine is only about
10 acres, land must be available for disposal of both the over-
burden from the mine opening and the spent shale. Land require-
ment for an underground mine is determined from estimates for an
underground mine capable of supplying shale for a 50,000 bpd
shale oil facility (US-093). An estimate of the land impact is
as follows:
(1) mine development: 20 acres
(2) solid waste disposal assuming 60% return
of processed shale underground: 51 acre/
year
(3) crushing facilities: 40 acres
Assuming a thirty-year mine life, the total land impact is 1600
acres.
Surface disposal of solid waste may be achieved by
either containment (box canyons) or reclamation. Land reclama-
tion and revegetation is a desirable method for reducing the land
impact of the shale oil industry; however, procedures required
to properly restore and revegetate the land have not been
adequately defined. Total cost, time, and water requirements
have not been accurately established.
-32-
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2.2.2 Surface Mining
Surface mining consists of removal of the overburden
followed by mining of the underlying oil shale in a quarry-like
operation. Factors effecting the suitability of surface mining
are the ratio of the overburden to the shale to be mined and the
availability of a disposal area for the overburden. Surface
mining has the advantages over underground mining of being
accomplished at a lower cost and with less manpower (HI-083, and
being inherently safer. Unfortunately, potential sites for surface
mining are limited. Another disadvantage is a high land impact
since all of the spent shale and solid waste must be handled on the
surface.
Overburden at potential surface mining sites ranges
from 100 feet to 800 feet in depth, averaging approximately 450
feet. Due to the required mine depth, several bench levels
must be provided to develop sufficient working forces to meet
production rates. An average mine slope of 45° with a working
slope of 35° is typical (US-093). Overburden and shale is
extracted by drilling and blasting. Blasted raw shale is hauled
by trucks to primary crushers in the pit. Shale from the crusher
is removed from the mine by conveyor to secondary crushing and
screening facilities. The secondary crushing and screening.
facilities may be located at the upgrading plant site. Major
processing steps associated with a surface mining operation are
shown in Figure 2.2-2.
Emission sources associated with the surface mining
facilities include excavation blasting, road dust from trans-
portation of oil shale and overburden, combustion emissions from
-33-
-------
OVERBURDEN
REMOVAL
SOLIDS DISPOSA
AND
BACKFILLING
REVEGETATION
SHALE
EXTRACTION
SPENT
.SHALE
FROM
MINE
MINE
DRAINAGE
CRUSHING
AND
GRINDING
WASTE
WATER
TREATMENT
WATER
FOR
DUST .
CONTROL
SHALE
STORAGE
PRODUCT
SHALE
SHALE PILE
RUNOFF
FIGURE 2.2-2
STEPS INVOLVED IN OIL SHALE SURFACE
MINING
-------
diesel-powered equipment, and primary and secondary crushing
operations. Primary control for fugitive dust is by water
spraying. Particulates generated in the crushing operations
may be reduced by wet scrubbers or fabric filters.
Water resulting from surface mine drainage and shale
pile runoff is also routed to evaporation/containment ponds.
Potential uses for this water have been previously noted for
underground mining (Section 2.2.1).
A major problem associated with surface mining is solids
disposal. Overburden as well as processed shale must be disposed
of on the surface. Initially overburden and spent shale is.
hauled off site to some containment area. Overburden may be
removed to the containment site by trucks or conveyor. Spent
shale may be returned to the containment area by truck, conveyor
or slurry pipeline. Only after mined-out areas of the pit become
available can backfilling begin. Since solid waste cannot be
disposed of underground, the land impact associated with surface
mining is higher than room and pillar mining.
The land requirement for a surface mine producing .shale
for a 50,000 bpd upgrading facility is determined from estimates
for a surface mining operation for a 100,000 bpd shale oil facil-
ity (US-093). An estimate of the land impact is as follows:
(1) mine development: 28 acres/year
(2) permanent overburden disposal: 500 acres
(3) low-grade shale storage: 75 acres
-35-
-------
(4) disposal of spent shale: 73 acres/year
Assuming a 30-year mine life, the total land impact is approxi-
mately 3600 acres. A land reclamation/revegetation operation
should be part of a surface mining operation; however, reclama-
tion procedures are still in conceptual and developmental stages.
Reclamation requirements in terms of cost, equipment, time, and
water have not been accurately established.
2.2.3 Sizing Operations
Sizing operations which may be performed on raw shale
include primary, secondary, and tertiary crushing, screening and
briquetting. The amount of sizing required depends upon the
specific retorting process being utilized. Retorts that rely
on solid-solid heat transfer require a smaller size feed than
retorts which rely on gas-solid heat transfer. The TOSCO
II retort requires that the shale be ground to less than 0.5
inches while Union and Gas Combustion retorts can accommodate
ore up to 3.5 inches. Typical operations in a shale sizing
facility are shown in Figure 2.2-3.
In order to minimize costs of transporting the raw
shale, the crushers are located close to the blasting operation,
usually within the room and pillar mine or in the surface mining
pit. From the primary crushers the shale is conveyed to second-
ary and tertiary crushers outside the mine or pit. The remaining
sizing operations may be performed either at the mine site or
at the retorting site.
-36-
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Receiving hopper
Primary crushing
1
L-
3p70 tph. _^-\__
\;^
From tertiarv| -v
crusher / "*»
3P50 tph. '=$' """"^P 1
-3°in. *"**»*J-^'/'
Surge storage
screen
1 ^
r~ 1 Vibratory feeder
N. ^x^Primary crusher Secondary crushing Tertiary crushing
" ,. .J^-^"^^., 3D60 tnh
^^.-^2^ | -»0-5th. 4PM) tph. -4.bin.
* Vibratory feeder ^^ *
/*. ./ / /*. Vibratory feeder
l—f \-i s^ Grizzly bar / l_r \J .s
CCD OU1^/' screen / CED ail^_^ Grizzly bar screen
"\ 1 i i .X i 1 1 i hopper
i 1 ' " *U30,V?1i
I Spliltci 1 • " 3.0 in.
\_/\_/\f To retorting plant ^15 tph
i i r~ *
\ / T 120 tph. -3/l6in. |
gg^^ V / / ' '
f |^V..t i j ' \ / ' \ /Vibratory feeder / \ s 1
1 " r i \f ' \j •••"•""•j ••.!.»" ) LJ 11'5
.. » ^' J^m*\H m II '' °P>^ '' ^ tP" * ( To retor'-in8
Vibratory feeder ' ^~h )* 1 Bnquetting Briquettes ' "'""'
^/•^ jff w machine , 3^030 tph'
1 ( j 1 i
Screening plant Briquetting plant *'^^.. •£
FIGURE 2.2-3 SHALE SIZING OPERATIONS
Source: US-093
-------
After secondary and tertiary crushing the shale is
conveyed to shale storage hoppers. From the storage hoppers
the shale may be fed directly to the retort. Pieces of the oil
shale which are too small for direct feeding are separated from
the larger shale by a screening process, crushed to very small
pieces with a hammermill, and then compacted into briquettes
suitable for routing to the retort along with the other shale
feedstock.
The entire sizing facility is a potential source of
fugitive dust emissions. Particulate control techniques such as
water spraying and shale wetting must be utilized as well as
control systems such as wet scrubbers or bag filters in order to
minimize dust emissions.
2.2.4 In-Situ Processing
In-situ processing schemes have been proposed for
retorting the shale in place, thus avoiding the solids handling
problems associated with the more conventional mining techniques.
In-situ processing involves fracturing the shale, injection of
retorting fluids, retorting of the shale in place, and recovery
of the product. This technique is still in the development
stage. Many approaches to achieving efficient in-situ retorting
are being investigated; however, no full-scale commercial units
have yet been constructed.
Potential methods for preparation of the shale bed
include hydraulic, electrical, chemical explosive, and nuclear
fracturing. Once the shale is fractured a retorting fluid
(hot gas or steam) is introduced through injection wells. The
gas is injected at a sufficient rate to maintain a satisfactory
temperature and/or flame front within the shale formation. The
-38-
-------
shale is brought to the retorting temperature (900°F) and the
kerogen is converted to a liquid shale oil. The hot gases create
a pressure differential within the formation forcing the shale
oil vapors to the producing wells. Product is brought to the
i
surface as a gas with entrained liquid through a row of produc-
tion wells parallel to the injection facilities. A schematic
view of an iri-situ processing operation is shown in Figure 2.2-4.
The parallel rows of wells (injection and production) will be
moved across the shale tract as the in-situ processing progresses.
An illustration of this progress is shown in Figure 2.2-5.
Once the product is brought to the surface, conventional
oil processing can be used. Liquids pumped from the shale and
removed from the off-gas stream are routed to the upgrading
facilities. The off-gas stream, which has a heating value of
approximately 30 Btu/scf is primarily recycled into the shale
formation. The gas which, for practical reasons, is not injected
is treated for acid gas removal and flared.
The only emission sources associated with this oil
shale mining process are the flared gas and fugitive emissions
resulting from retort combustion gases, leaks of volatile shale
oil, and dust from unpaved roads. Emission from the flared gas
may be controlled by conventional stack gas control methods
while road wetting can be used to reduce the fugitive dust emis-
sions. Good housekeeping techniques will minimize the fugitive
combustion gas and shale oil emissions.
-39-
-------
FIGURE 2.2-4
SCHEMATIC REPRESENTATION OF AN IN SITU RETORTING OPERATION
AIR
J
ATMOSP'J^E
A
I
RECIRCULATED
GAS INJECTION
07L AND GAS
RECOVERY
OIL SHALE
V
V
V
^rrr^-fTj=^. OVERBURDEN ^-^.^~
PROFILE
'\'l
riv
N/V-
OIL SHALE
— BURNED OUT
4- FIRE 4-
RETORTING.
GAS DRIVE-
Source: (EN-204)
-------
Restored
area
i^
v_*
R
It
f't
:'
e
C '"•
S ^'
»->
*„!,
0
r 0
i
P
1
u
g
g
1
0
0
0
0
0
—
0-* _ e o
- R-
. _ — _
®-*e 9 O
_ t _
- o-
-------
The major problems associated with the development of
in-situ oil shale processing include improving:
methods of artificially inducing sufficient
permeability to allow effective passage
of gases and liquids,
control of the process from the surface,
and
product recovery methods.
-42-
-------
2.3 Oil Production
The modern day oil production facility has been engi-
neered to be a high recovery, nonpolluting operation. Many old
and proven techniques such as gas-lift and plunger-lift produc-
tion operations are -still being used. Newer technology involving
secondary and tertiary recovery methods along xvith safeguards
against potentially hazardous pollution have received considerable
attention :in recent years. This report deals only with surface
operations of oil production.
2.3.1 Oil Removal
Although many options are available, the processing
sequence for an oil production facility is reasonably straight-
forward. The first step is removing the oil from the wellhead.
The oil can be removed by the three methods shown in Table 2.3-1.
i
Emissions from the wellhead operations will depend on the type
of prime mover involved in the pumping operation. Natural flow
involves no prime mover and thus will emit only fugitive losses
characteristic of hydrocarbons in the crude oil.
Plunger lift, which includes the conventional sucker-
rod pump and the hydraulic pump, or gas lift will require a
prime mover for either pumping or compressing. A list of
available prime movers is shown in Table 2.3-2 (FR-121). The
electric motor is the most convenient, and it is emission free.
However, electricity may not be available, in which case internal
combustion-type engines are often used. Common fuels used in
internal combustion-type engines are natural gas, refinery gas,
LP gases (butane and propane), diesel fuel, and light fuel oils.
Fuels found to be unsuitable are direct well gases which are
_43_
-------
TABLE 2.3-1
OIL PRODUCTION OPERATING OPTIONS
Well Head
1) Natural Flow
2) Plunger Lift
3) Gas Lift
t
Injection ^
1) Flood Water
2) Steam
3) Solvents (i.e.,
4) Surfactants
— ^- Gathering System ^>-Emulsion
Water
Breaking "^> Knockout ^- Oil-Gas Separation
1) Direct Flowing 1) Gravity
2) Heated for Heavy Crudes 2) Electrical
3) Pressure Reduction 3) Heate
Secondary Waste Water
Treatment <^
1) Filtration
2) Degassing
alcohol) 3) Aeration
r Tr eater
\l
Water
1) 2-Stage
2) 3-Stage
3) 4-Stage
4) Singl
Treatment
1) Floatation Cell
2) Aerated Lagoons
3) Evaporation Ponds
\
e
/
Storage Tank
5) High Pressure Miscible Gas
6) Polymers
7) High Pressure Air with
In situ Combustion
Automatic Transfer •«<$-
1) Meter Type
2) Volumetric Dump
Storage
1) Bolted Steel Tank
2) Wooden Tank
3) Welded Steel Tank
4) Plastic Tank
5) Cone-bottom Tank
-------
TABLE 2.3-2
CLASSIFICATION OF PRIME MOVERS
1. Slow-speed* single- or twin-cylinder
two-cycle gas engines
2. Slow-speed single cylinder four-cycle
gas engines
3. High-speed** multiple-cylinder four-cycle
gas engines
4. Slow-speed diesel or oil-burning engines
5. High-speed diesel engines
6. Electric motors
Slow-speed is 750 rpm or less.
High-speed is 750 rpm or greater,
SOURCE: FR-121
-45-
-------
"wet
Most
" or gases which contain over 2 percent sulfur (FR-121).
fuels require some type of on-site storage.
The oil from the wellheads is brought together to a
central oil-water-gas separation facility by a gathering system
consisting of piping from the wellheads and a central collecting
manifold. The simplest gathering system is a direct flow system
where oil from the wells is merely piped to a common manifold and
then on to the separation facility. This system works for wells
operating essentially with equal producing pressures. If pres-
sures are not equal, a gathering system which provides for
pressure reduction before entering the manifold is employed. If
the wells are producing heavy crudes, and especially if steam
injection is being used, the gathering system may have to be
heated by some means such as steam tracing in order to keep
liquids flowing in the lines.
2.3.2 Brine Removal
The brine and oil from the oil field is usually in an
emulsion form. This emulsion must be broken before the brine
content in the crude can be reduced to an acceptable level of
about two weight percent. This operation consists of destabiliz-
ing the film between the oil and water droplets, coalescence of
the oil droplets, and gravitational separation of the oil and
water phases. The dehydration processes have residence times
of around twenty minutes (CH-182). The four methods used in
dehydrating emulsions are (1) heating, (2) chemical treating,
(3) electrical, and (4) gravity settling.
-46-
-------
Heater treaters are commonly used for emulsion breaking.
The brine-oil emulsion is destabilized simply by the application
of heat. The heaters are often direct-fired, although indirect-
fired ones are also available (CH-182). A typical heater treater
is shown in Figure 2.3-1 (FR-121).
Chemical treating is performed by altering the chemical
compositions at the interfacial film and destabilization by
surface-active agents. Separation can be enhanced by addition
of heat and is completed in some type of gravity settler.
Electrical dehydrators include a preheating step to
reduce the viscosity of the crude, followed by exposure of the
crude to a high-voltage alternating electrical field. The
electrical field causes the polar water particles to increase
their random motion, thus enhancing their coalescing properties.
An electric dehydrator is shown in Figure 2.3-2 (CH-182).
Gravity settling is usually performed in a wash tank.
The wash tank has three parts: (1) a bulk separator for free
gas, (2) a bulk separator for free water, and (3) a quiescent
tank for settling of suspended solids and water droplets. The
bulk gas separator is usually a gas "boot" located in the inlet
line to the wash tank. The bulk separator for free water is the
lower section of the wash tank while the quiescent tank for
settling of suspended solids and water droplets is the upper
section of the tank. A typical wash tank is shown in Figure
2.3-3 (FR-121). A wash tank may be used as a knockout tank.
before or after a heater treater, chemical dehydrator or electri-
cal dehydrator.
_47.
-------
CAS. IMUISIOM AND
fill WATII INUT
EMULSION LESS FIEE
WATEI MOVES DOWN
TO TIEATING
COMMITMENT
EMULSION WATII
OUTUT
FIGURE 2.3-1 HEATER TREATER
-43-
-------
VD
1 Transformer
2 High voltage •nlranct bushing
3 Reactor
Liquid level controller
Vessel
Platform & ladder
Man way
Wear plate
9 Switchboard
10 Ground connections
11 Adjustable sampler & outside conn.
12 Upper energized elecvode
13 Lower grounded electrode
14 Lower electrode hanger rod
15 Level control float & shield
16 Inlet distributor
17 Outlet collector
IB Internal float switch
19 Energized electrode insulator
20 Water draw-off
21 Outlet connection
22 Pilot light
PICTORIAL ASSIMBir
-IMOICAIf UNItOHH OIHICIIOH Of
IIOH IHHOUCH-OUI VISSll
FIGURE 2.3-2 PICTORIAL ASSEMBLY OF PETRECO ELECTRIC DEHYDRATOR
-------
Po*er fluid
and production
Weir bo*
level control
Cos
Overflow
Water
Water level
-Sample box
N Power oil
FIGURE 2.3-3 WASH TANK
,50-
-------
2.3.3 Oil-Gas Separation
After the brine has been removed to an acceptable
level, the oil and gas are separated. Oil and gas separations
are classfied as to the number of stages, the shape, and the
number of p'hases separated. The number of stages is determined
by the pressure of the incoming oil and gas mixture. For high-
pressure fluids a greater number of stages will be required.
Very low-pressure crudes may be routed directly to a storage tank
i
which is considered as one stage of oil and gas separation.
Separators are horizontal, vertical, or spherical.
The shape is determined by the oil to gas ratio. For high oil
to gas ratios horizontal Separators are used, and for low ratios
vertical separators are used. Spherical separators are used for
intermediate ratios. All three types of separators are shown
in Figure 2.3-4 (FR-121). Separators are either two- or three-
phase units. In two-phase units only oil and gas are separated
while three-phase units separate oil, gas, and water. The gases
recovered can be segregated as to pressure or as to "wetness"
("wet" gases are those containing condensable hydrocarbons).
The recovered gas is piped to a gas treating plant for further
sweetening and purification. In remote areas, the off-gas may
be reinjected or flared.
2.3.4 Crude Storage
The final dehydrated and degasified crude is held in
surge or storage tanks to await shipment via pipeline, train,
barge, or tanker. The most common storage tank is the bolted
steel tank. This type of tank has the advantage of being easily
.51.
-------
Z'-SAFETYPOP
VALVE
PRESSURE
GAUGE
GAS
OUTLET
MIST EXTRACTOR
CENTRIFUGAL-TYPE
INLET DEFLECTOR
FLOAT
DEFLECTOR
TO PLATE
WELL FLUID
INLET-
OIL LEVEL
GAUGE COCKS
a
GAUGE GLASS
DRAIN
OIL
OUTLET
Schematic diagram of typical spherical two-phase oil and gas separator with
float-operated lever-type oil control valve.
&"
NONWEIGMTEO
FLOAT
Sclinnmtic diagram of typi-
cal vortical two-phase oil and gas
wparator.
.GAS BPV
FLOAT NOZZLE
GAS OUT
VANE-TYPE MIST EXTRACTOR
FLUID
IN
OIL OUT
INLET SEPARATING
ELEMENT
-NONWEIGHTED FLOAT
SECTION'A-A'
Schematic diagram of typical horizontal two-phase oil and gas separator.
FIGURE 2.3-4 OIL-GAS SEPARATORS
-52-
-------
transported, dismantled, and repaired. A bolted steel tank is
shown in Figure 2.3-^5 (FR-121) . Other types of tanks which can
be used are wooden, welded steel, plastic, and cone-bottom tanks.
A tank battery should contain at least two tanks and usually have
a capacity equal to four days' production (FR-121).
With the increase in value of lighter hydrocarbons, the
recovery of these hydrocarbons has become economically feasible.
Installation of floating roof tanks or some type of floating
covers reduces hydrocarbon emissions from tanks. Vapor recovery
systems can also be used to recover vapors but are more expensive
than floating roofs. Vapor recovery systems have the advantage
of being able to recover vapors from other sources such as dehy-
dration or loading facilities. A schematic flowsheet for a
typical vapor recovery system is shown in Figure 2.3-6.
If the crude is to be transported by pipeline, the
crude from the storage tanks is transferred by a lease automatic
custody transfer (LACT) system. There are two types of transfer
units: the meter type and the volumetric dump. In the meter
type the oil is deaerated and then run through a metering system
to determine the volume. The volumetric dump determines the oil
volume through alternately filling and dumping calibrated tanks.
Both units also automatically sample the crude for residual basic
sediment, water content, and oil gravity (CH-182).
2.3.5 Water Treating
The water from the dehydrator, knock-out tanks, and
three-phase separators, if used, must be further treated before
being discharged as waste water or reinjected back into the well
•53
-------
^r
^14 PLAIN INTERCHANGE-
f ABLE A.RI. SINGLE-
PUNCHED STAVES
X-13 PLAIN INTERCHANGEABLE
API. SINGLE -PUNCHED
STAVES
1 A.PI. SINGLE-PUNCHED
CLEANOUT STAVE
^EXTENDED CLEANOUT
BOTTOM SEGMENTS
S?
/
20" A.RI. STANDARD
DOME W30 HOLE
COVER AND GASKET
INSIDE LADDER
LADDER BRACKET
BOTTOM CENTER PLATE
W/3B HOLE GASKET
BOTTOM SEGMENT
AND CENTER PLATE
r
uj
>
<
(/>
fe
B
CO
y
2
<
P
m
?
T;
-
--
!
g
^
1
c\
^
L 1 1 *gii t i/g" _Q • i
.29-21; SPACES _ ''
-JAi"MIN
22" BOLT CIRCLE
SPACES
t 29 EQUAL SPACES
LOW 500. HIGH 1.000. AND 1.500
BBL TANKS
DECK SEGMENT
i 22.076 BOLT
CIRCLE
ft"
AV-V>/Z 2r9'*3z" BOLT CIRCLE
29 EQUAL SPACES
STAVE WITH ONE ROW OF
BOLT HOLES IN VERTICAL SEAMS
LOW 50O, HIGH 1.000. AND 1.500
B3L TANKS
High 1.000-bbl API bolted-steel tank showing stave, deck, and bottom segments.
FIGURE 2.3-5 BOLTED STEEL TANK
-------
HEATER TREATER
V
REGULATORS
"DRY" GAS
STORAGE
CONDENSATE RETURN LINE
FUEL GAS
FOR
HEATER
TREATER
FIGURE 2.3-6 VAPOR RECOVERY SYSTEM
-55-
-------
through steam injectors or water flooding. The flotation cell
type wastewater treater is a commonly used primary water treating
facility. This system utilizes air or gas injection upstream
of the main wastewater process pump. The air and the chemical
coagulants, if required, are thoroughly mixed inside the pump.
The discharge flow from the pump enters the retention tank where
air is dissolved under 2-3 atmospheres of pressure. As the
wastewater enters the flotation cell, the pressure is released
to atmospheric pressure and the air comes out of solution.
Small sludge and oil particles become floatable on the bubbles
or foam and pass to the top where the rotating skimming arm sweeps
the oil sludge into a compartment for removal. The same drive
shaft also rotates a bottom grit scraper arm for the separate
removal of settled solids to the grit collecting box. A flota-
tion cell wastewater system is shown in Figure 2.3-7 (CH-182).
Other possible wastewater treatment methods include sedimentation
followed by aeration, aerated lagoons, or evaporation ponds. The
type system employed is determined primarily by the ultimate use
of the wastewater.
If the treated water is to be further used for either
steam generation or water flooding, it must be filtered to remove
the suspended solids. A sand filter or a diatomaceous earth
filter may be used. The solids concentration must be lowered
as much as possible to eliminate particulate buildup in the
injection well.
The wastewater often must be treated for removal of
dissolved H2S. This can be accomplished by one of the following
methods: (1) aeration, (2) vacuum degassing, (3) countercurrent
gas stripping, or (4) chemical treatment (CH-182).
-56-
-------
v~
^
j"';y
ft;M
__
-•-'-'"I
"-•iji"
^% -•----— |
ill! )"-•[
/
"" (>'
i*
Fully pressurized flotation cell; waste water system (P and I flow diagram). (Cour-
tesy of Pollution Control Engineering, Inc., Los Angeles, California.)
Dual flotation cell; waste water system. (Courtesy of Pollution Control Engineering,
Inc., Los Angeles, California.)
FIGURE 2.3-7 WASTE WATER SYSTEM
-57-
-------
2.3.6 Secondary, Tertiary Recovery
Water flooding and steam injection are the main tech-
niques for secondary recovery of crude oil. The injection
system consists of a central high-pressure water pump for water
flooding or a steam generator for steam injection, plus a distri-
bution system. For water flooding systems, each wellhead may
have its own high-pressure pump. Selection of the system is
dependent on economics and the characteristics of the crude
being recovered. Steam injection is generally used to recover
heavier crudes.
Although secondary recovery methods tend to increase
the crude production, they by no means effect complete crude
recovery from the reservoir (HO-172). As the value of hydro-
carbons increases, additional or tertiary recovery of the resid-
ual is becoming economically feasible. Tertiary recovery
processes include injection of material into the reservoir either
to decrease the viscosity of the crude, to make the crude oil
miscible with water or other hydrocarbons, or to plug pores in
swept-out reservoir areas. Injection of these materials will
involve some type of high-pressure pump or compressor.
Typical materials injected to decrease the viscosity
are hydrocarbons, soluble gases (such as C02), and surfactants.
To enhance miscibility with water, LFG-enriched gas, high-
pressure gas, alcohols, soluble oils, and micellar solutions are
injected into the wells. The plugging of pores reduces backflow
of crude oil. As pore plugging agents, emulsions or caustics
are shown to have the best field success, while foams, precipi-
tators, silica, and gels have been shown to have economic draw-
backs (HO-172). Polymers such as polyacrylamides and
-58-
-------
polysaccharides have also been used for selective plugging.
These polymers also tend to improve the fluid mobility of the
recovered crude.
2.3.7 In-Situ Combustion
As with coal and shale oil, crude oil can also be
recovered by in-situ combustion techniques, although the tech-
nology applicable to oil production is quite new. Three methods
of in-situ oil production are generally cited: (1) forward
combustion, (2) reverse combustion, and (3) "wet" combustion;
Forward combustion consists of injecting air into a
reservoir to establish a flow path for the movement of combustion
gases, igniting the crude oil by using a bottom-hole heater or
burner, and propagating the combustion front by continuous air
injection. As the burning zone advances from the injection well,
it pushes oil and water to the surrounding producing wells
(CH-182).
The reverse combustion process is operated in a similar
manner except that in this case producing wells are ignited
rather than the injection wells. The burning front moves counter-
current to air flow toward the injection well and after reaching
the injector may reverse direction and burn back to the producing
well like a normal combustion process (CH-182).
"Wet" combustion is also much the same as forward in-
situ combustion except that water is added along with the
injection air. Water injection offers three advantages over
conventional dry in-situ combustion: (1) more efficient heat
-------
distribution, (2) reduced fuel requirements, and (3) faster
movement of the combustion front through the reservoir. These
advantages relate to more efficient use of combustion air (WE-134)
All of the procedures described above may be used for
onshore or offshore oil production. Offshore production has the
added problem of limited space, therefore, proper design of equip-
ment becomes especially important. Special consideration must
be given to design of offshore facilities for the prevention of
oil spills. While spills are of concern in both onshore and
offshore production, offshore spills are generally more difficult
to contain and can create severe environmental problems.
.60.
-------
2.4 Gas Production
Natural gas is a degradation product resulting from
the decomposition of buried organic matter. It is found in recent
sediments deposited in both freshwater and saltwater environments,
in ancient sedimentary rocks, in subsurface aquifers, in fine
fractures in coal seams, and even in metamorphic rocks. As of
1969, there were 114,500 wells producing gas from such formations
(PR-052). Wells are classified as gas wells or oil wells based
on the ratio of oil/gas produced. For example, Texas law defines
an oil well as " any well which produces one (1) barrel or
more of crude petroleum oil to each one hundred thousand (100,000)
cubic feet of natural gas" (PR-052).
In this section, only those operations involved in
producing the natural gas from basically pure gas reservoirs are
discussed. Gases extracted from different producing fields have
widely varying compositions. Most field gases contain some
undesirable compounds such as COa, HaS, HaO, and combined sulfur
compounds which must be removed prior to sales. Typical proces-
sing facilities for upgrading the gas to market specifications
are described in this section.
2.4.1 Gas Field Operations
Two basic types of fields exist from which pas is
produced. One is the "dry" gas field in which no hydrocarbons
heavier than methane and ethane are produced and the only
processing required is dehydration and acid-gas removal. The
other type is the "wet" or "condensate" field where a clear
condensate is produced with the gas. Besides acid-gas removal
and dehydration, separation of these heavier hydrocarbons is a
necessary step in achieving acceptable natural gas specifications.
-61-
-------
Although the composition of natural gas at the wellhead varies
from field to field, each well produces some or all of the
following components:
paraffinic hydrocarbons, principally
methane with some ethane and propane,
and lesser amounts of Cn and heavier
hydrocarbons.
napthenic hydrocarbons
water
nitrogen
oxygen
helium
carbon dioxide
hydrogen sulfide
other sulfur compounds; e.g., carbonyl
sulfide, CS2 and RSH
The typical distribution of components in a U.S.
natural gas well is shown in Table 2.4-1. The initial pro-
duction step involves withdrawal of the gas from the well at
the reservoir pressure. The gas is then passed through a water
knock-out drum to remove any water and piped to a gas plant
where it is processed to meet sales specifications.
Condensate fields are operated somewhat differently.
In these fields retrograde condensation often occurs. This is
a phenomenon signified by the condensation of liquids out of the
gas as the pressure is reduced. Thus, when the high pressure
gas is introduced into a lower pressure system through a choke,
-62-
-------
TABLE 2.4-1
TYPICAL DISTRIBUTION OF COMPONENTS IN
U.S. NATURAL GAS AT THE WELL
Component Volume Percent
He 0-2
N2 0-16
CH, 60 - 99
C2H6 1 - 20
C3H8 0.5 - 6.5
C..HJO+ 0 - 4.5
C02 0-5
SOURCE: TE-172
-63-
-------
liquid forms. Liquid also condenses in the formation as the
field pressure drops and unfortunately does not completely
vaporize at the abandonment pressure of the field. Cycling
plants are designed to prevent this loss in product. The
natural gas produced is processed on site to recover natural
gasoline, and the residue gas is reinjected to maintain reser-
voir pressure. This separation of the condensates from the gas
stream is accomplished by "stage trapping" of the well stream.
This stage separation can be defined as a process in which gas
and condensate are separated into liquid and vapor phases by
two or more equilibrium-flash vaporizations at successively
lower pressures (PR-052). A simplified diagram of a three-step
separator is shown in Figure 2.4-1.
2.4.2 Gas Processing Plant Operations
Partially dehydrated, raw natural gas is sent to a gas
processing plant which is usually located near the field. Here
the field gas is processed to meet sales specifications of
utility gas distributors and companies. Some typical specifica-
tions are as follows (CH-182):
(1) A hydrogen sulfide content of less
than 0.25 grains per 100 cubic feet
and a total sulfur content of less
than 3 grains per 100 cubic feet are
usually required.
(2) Water and hydrocarbon dew point
temperatures may range from as high
as 50°F in the south to as low as
0°F in cold areas.
-64-
-------
HIGH PRESSURE NATURAL GAS
I
c^
Ul
WATER
KNOCKOUT
FILTER
00
INTERMEDIATE PRESSURE
NATURAL GAS
-0
i-t
&
GAS-CONDENSATE SEPARATORS
GAS WELL
LOW PRESSURE
NATURAL GAS
LEASE
TANK
(FIELD)
WATER (TO WASTE OR RETURN TO RESERVOIR)
VENT
LEASE
CONDENSATE
FIGURE 2.4-1 FLOW DIAGRAM FOR THREE-STAGE
WELLHEAD SEPARATION UNIT
-------
(3) Air content is usually limited to
1 to 5%.
(4) Carbon dioxide is usually limited to
1 to 5%.
(5) Gross heating value range is specified.
A minimum might be 1000 Btu per cubic
foot. Often gas is sold on a Btu basis
with a penalty or credit for each 50 Btu
per cubic foot change in heating value
above or below some base value.
The processing plant has three distinct sections:
(1) acid gas removal usually followed by a Glaus sulfur recovery
plant; (2) gas dehydration; and (3) heavy hydrocarbon separation.
A typical arrangement of these processes is shown in Figure 2.4-2
The following sections describe more fully these gas plant
operations.
Acid Gas Removal
There are over twenty methods available for the removal
of acid gas constituents, carbon dioxide and hydrogen sulfide.
Methods developed range from the simple water-wash techniques
to the molecular sieve removal methods. The majority of acid
gas removal procedures used in gas plants are characterized by
the processes listed in Table 2.4-2.
A frequently used method for separation of acid gas is
by absorption with an amine solution. The basic flow is shown
-66-
-------
Acid
Gases
Raw Natural
Sulfur Removal
Elemental Sulfur
Acid Gas Removal
Dehydration
Heavy Hydrocarbon Recovery
Clean
-^•Natural
Gas
Recovered
Heavy
Hydrocarbons
FIGURE 2.4-2 NATURAL GAS PROCESSING PLANT
-------
TABLE 2.4-2
TYPICAL-ACID GAS TREATING PROCESSES
Process
Benfield
Diglycolamine or Economine
Fluor Solvent
Girbitol or MEA
Molecular Sieves
Selexol
Sulfinol
Special Features
Used for gases containing high
CO2 and H2S concentrations
Used to remove COS and RSH,
as well as C02 and H2S
Used for gases with high
concentrations of C.02 and H2S
Most commonly used process in
gas industry today
Used on low acid gas concen-
trations (<100 grains H2S/100
ft3) and for H20 and RSH removals
Used on high C02 with low H2S,
especially when H2S goes to
Claus plant
Used on wide range of H2S and
C02 concentrations
-68-
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in Figure 2.4-3. Other common treating absorbents are aqueous
solutions of the ethanol amines or alkali carbonates. In these
processes the sour natural gas is passed countercurrent to a
stream of the solution in a packed or tray tower. The H2S and
COz are absorbed by the solution, sweetening the gas. After
leaving the absorber, the rich' solution enters a regenerator
where the acid gases are stripped from the solution usually by
heating, but also by pressure reduction in flash vessels, or
by an inert gas stripping. The regenerated solution is then
pumped back to the absorber where a new cycle begins.
Molecular sieves, are dry bed absorbers. This technol-
ogy has been receiving increasing attention in the gas industry.
Advantages of molecular sieves include simplified operation,
reliability, and a wide range of cleanup capabilities. The
molecular sieve can be used for removal of all polar contaminates
present in the gas, including water vapor, sulfur- and oxygen-
bearing compounds.
Sulfur Conversion
The original technique for conversion of HaS to sulfur
was the Glaus-Chance process. It has been modified considerably
in recent years. The Mathieson Chemical Company has developed
a considerably improved version which has been used successfully
in numerous modern installations. A schematic flow diagram of
this process is shown in Figure 2.4-4.
In the reaction furnace, HaS is combusted with a sub-
stoichiometric air supply. Some sulfur is formed here and
removed, while the rest of the gases pass to a series of two or
-69-
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ABSORBER
REGENERATOR
Treated Gas
o
i
Sour
Natural Gas
Lean Amine Solution
Sour Gas
Steam
Rich Arninc Solution
FIGURE 2.4-3 TYPICAL AMINE TREATING UNIT
-------
«dd
got
Hot-got bypott
turner and
noction
ctiomhw
Steam |b"
(higkptiwn)
•IH
J Wast*. \
Steam
i pntH
1
S
at
o
")
M
•»
x^1
£'
"x.
-a
£•£
9 >
5 n
On
I*
[team
pnnu
1
w
cu
1
n)
f~*
Tj.b
ij
n nMm ,
(In pnuun)
boiler
7
T
T
fafcr
T
Sttta
FIGURE 2.4-4 CLAUS SULFUR RECOVERY UNIT
-71-
-------
three catalytic converters. In these converters unreacted H2S
combines with the S02 formed in the reaction furnace, producing
elemental sulfur which is then removed by condensation from the
process. Efficiencies for the unit range from 90 to 98 weight
percent sulfur recovery. Efficiencies attainable are dependent
on the H2S concentration in the feed, the quality of the catalyst
used, and the number of catalytic stages.
Dehydration
The most common impurity in natural gas is water. Its
removal is accomplished by dehydration with a dry desiccant or
glycol solution. Desiccants commonly used are activated alumina,
silica gel, and molecular sieves. Figure 2.4-5 shows a typical
two-bed solid adsorbent treater used for dehydration. While
one desiccant bed is removing water from process gas, the other
is being regenerated by heat and then cooled. Frequently a
three-bed system is installed. One unit is adsorbing, one is
being heated or regenerated, and the third is being cooled.
Another gas dehydrating method involves contacting the
wet gas with hygroscopic substances such as diethylene glycol
(DEC) and triethylene glycol (TEG). These chemicals are efficient
drying media, chemically stable and readily available at a
moderate cost.
A typical glycol dehydration plant is pictured in Figure
2.4-6. Water vapor is continuously absorbed from the wet gas
stream by countercurrent contact with a glycol solution. The
dried gas passes out the top of this column. Wet glycol passes
to a regenerator section where the glycol is dehydrated and sent
back to the absorber.
-72-
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DRY NATURAL GAS
IXh
ADSORBENT
BED
REGENERATION
GAS
HEATER
ADSORBENT
BED .
TO FUEL LINE
A
-fcj-
-E>3-
WET NATURAL GAS
COOLER
LIQUID K.O.
FIGURE 2.4-5 TWO BED SOLID ADSORBENT TREATER
-------
STRIPPING GAS AND WATER VAPOR OUT
DRY GAS
GLYCOL
GAS
CONTACTOR
WET
NATURAL GAS
STRIPPER
^
\
*
I
S:
^ STRIPPER C
X )
) SURGE TANK
LEAN GLYCOL
FIGURE 2.4-6 TYPICAL GLYCOL DEHYDRATION UNIT
-------
Heavy Hydrocarbon Stripping
Several processes are currently used in the United
States to achieve gas separation. These processes involve
various combinations 'of absorption, refrigeration, compression,
adsorption, fractionation, cryogenic separation, and turbo-
expansion. With the exception of the fractionation process,
heavy hydrocarbon stripping processes are usually identified by
the method used to separate ethane and heavier hydrocarbons
from the raw natural gas feed. Brief descriptions of commonly
used separation processes are given in the following section.
!
Included are absorption, refrigerated absorption, refrigeration,
compression, and adsorption (PR-052).
In an absorption process the wet field gas is contacted
with an absorber oil in a packed or bubble tray column. Propane
and heavier hydrocarbons are absorbed by the oil while most of
the ethane and methane pass through the absorber. The enriched
absorber oil is then taken to a stripper where the absorbed
propane and heavier compounds are stripped from the oil.
The natural gas feed to a refrigerated absorption
process must be dehydrated to a minus 40°F dew point prior to
entering the unit. All hydrocarbons except methane are absorbed
by absorber oil operating at minus 40°F. These absorbed hydro-
carbons and the oil are passed through a series of fractionation
columns from which ethane, propane, and heavier hydrocarbons are
removed as product streams.
In refrigeration, a cryogenic process, the natural gas
must be dried to a dew point of minus 150°F or lower, using
-75-
-------
molecular sieve beds. The dry gas is then passed through a heat
exchanger where it is cooled to minus 35°F. Condensed hydro-
carbons are removed in a gas-liquid separator. The gas from the
separator is cooled to minus 135°F and passed through a second
separator where more condensed liquids drop out. The liquids
from two separators are fed to a series of distillation columns
where methane, ethane, propane, butanes, natural gasoline, and
other products are recovered.
A compression process uses two stages of compression,
each followed by cooling and gas-liquid separation, to produce
a wet natural gas product and natural gasoline. This is not a
widely used process. Less than 3% of the gas processing plants
in the United States are using compression only for gas separa-
tion.
The adsorption processes consist of two or more beds
of activated carbon. The beds are used alternatively, with one
or more beds on stream while the others are being regenerated.
The activated carbon adsorbs all hydrocarbons except methane.
The bed is regenerated by means of heat and steam, which remove
the adsorbed hydrocarbons as a vapor. This vapor is then con-
densed permitting the water to be separated from the liquid
hydrocarbons. The resulting hydrocarbon product is fed to a
fractionation process where the various components are separated.
About 12 percent of the existing natural gas plants in the
United States use an adsorption process.
-76-
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2.5 Transportation
This section contains a review of the current technol-
ogies used in the transportation of coal, oil, and gas. Specif-
ically, the modes of transportation discussed are coal transporta-
tion by railway, barge, and slurry pipeline; oil transportation
by railway, barge, and pipeline; gas transportation by pipeline.
2.5.1 Coal Transportation
In the United States today, coal is transported by
either railway, barge, or slurry pipeline. By far the most
prominent method of coal transportation is railroads. Barge
transportation is geographically limited, and coal slurry pipe-
lines are a relatively new transportation mode. The coal
transportation pattern as of 1973 was approximately as shown
below:
1973 ESTIMATED LONG DISTANCE COAL MOVEMENTS
Millions of
Transport Mode Tons/Year
Railroad 400
Inland Waterway 150
Slurry Pipeline 5
Rail Transportation of Coal
Coal is a bulk commodity and the cost of transportation
from mine to market accounts for a significant portion of the
price paid by the consumer. The first rail transportation of
coal was in single-car shipments in mixed trains. As individual
-77-
-------
producers increased their output, multiple-car shipments in
mixed trains were initiated. As production increased to modern
levels, the trend was toward all-coal haulage for greater
efficiency and economy. Both efficiency and economy have reached
their present maximum in the unit train concept (GL-038).
Four principal types of gathering and distribution
systems have evolved (see Figure 2.5-1). In Movement A, several
small producers use a marshalling yard at the producers' end to
assemble, an all-coal train for movement to a distribution point
for forwarding to several small consumers. In Movement B, one
producer uses an all-coal train for movement to a distribution
point for forwarding to several small consumers. In Movement C,
several small producers use a marshalling yard at the producers'
end to assemble an all-coal train for movement to a single
consumer. In Movement D, one producer utilizes an all-coal train
for a movement to one consumer.
Physically, a unit train consists of a dedicated set
of haulage equipment loaded at one origin, unloaded at one
destination each trip, and moving in both directions on a pre-
determined schedule. Although Movement D contains the basic
elements of the unit train concept, it is not strictly in that
classification. Movement types A, B, C, and D traditionally
have been planned and managed by the railroad in response to
instructions from the shipper. Planning is short range and
often inefficient; carriers are frequently not informed by
either the producer or the consumer of their long-term plans.
This long-term planning and management capability is the element
needed to make the transition from the earlier modes of coal
shipment to the unit train. As the tonnage of coal transport
-78-
-------
OTHER THAN UNIT TRAIN
(Minimum tonnage per movement required)
•
MOVEMENT
A
MOVEMENT
B
t
MOVEMENT
C
MOVEMENT
D
Several
producers
Single
producer
Several
producers
Single
producer
1 ^">^,^ ^Marshaling yard Distribution point , ^x-"* ^
, , ^*"-r-* — i Single haul — all-cool train , t , — ""^ , ,
1 1 ^^J -1 \ l^^ | 1
dK"^ ^^IZI
Distribution point -, ^^x-* — ' '
r— — i Single haul — all-coal train ,-« — x**^ , ,
1 ' ' 1 t^^ 1 1
^^^C=]
1 ^^^^ ^Marshaling yard
i , ^**^«1 t» i Single haul — alhcool train , ,
C=K^^
__^_ Single haul — all-coal train _
Several
consumers
Several
consumer
Single
consumer
Single
consumer
UNIT TRAIN
(Large minimum movement per train and year required)
Centrali-ed unit train
loading facility
Several
small
producers
Sinale haul —all-coal train
(Dedicated set of equipment)
Two
producers
with unit
train
loading
fociiilies
(One dedicated set of equipment
for both operations)
Single haul-oil-coal tram
Single haul— oMoal train
(Dedicated eel of equipment)
FIGURE 2.5-1 BULK COAL MOVEMENTS
-------
increases, it is expected that unit train haulage will become
more widely used.
Railroads consider three kinds of volume shipments as
unit train movements. In Movement E, (Figure 2.5-1) several
small producers, with centralized unit train loading facilities
and dedicated transportation equipment, ship to one large con-
sumer. In Movement F, two coal producers, each with rapid
loading and storage facilities and with dedicated transportation
equipment, move the product to one large consumer. Finally, in
Movement G, dedicated equipment delivers coal from a single
producer to a single consumer. In the limit, the same company
may be the producer and consumer, and also the owner of the unit
train equipment, which leases only rail service from the rail-
road company.
The major source of air emissions from coal-hauling
trains results from the diesel-fired train locomotives. These
locomotives require 750 Btu per ton-mile (AM-115). Another
contribution to emissions is the fugitive dust arising from the
loading, transfer, and unloading of the coal.
Barge Transportation of Coal
Most coal moving on United States inland waterways is
carried in unmanned barges having drafts of six to fourteen feet,
Barges, usually in groups or strings, may be moved by either a
towboat (pushing) or a tug (pulling), both of which are usually
powered by diesel engines. The diesel towboat which replaced
the stern wheeler on the rivers, canals, and harbors is respon-
sible for increasing the importance of the barge and towing
vessel industry over the last 25 years (AM-115).
-80-
-------
Low energy requirement is a basic advantage of water
transportation. The movement of coal by barge requires 500 Btu
of energy for every ton-mile of cargo moved (AM-115). Exhaust
from tugboat engines is the major source of air emissions.
Fugitive dust lost during loading, transfer, unloading of the
coal, and in transit, is another source of emissions.
The operations involved in the shipping of coal by
the inland waterways on barges are relatively simple. Coal is
first loaded onto the barges from a canal or river terminal.
Loading usually is accomplished with a tipple which allows for
a continuous, easily measured method of moving large amounts of
coal. From the loading terminal, the barges are moved by tow-
boat to the consumer. Coal is transferred from barge to storage
pile at the consumer's water terminal using draglines.
Coal Slurry Pipeline
The hydraulic transport of solids by pipeline is a
well-developed technology (AD-021, AU-006, BA-233, DU-061,
GO-055, PI-044, SK-024, ST-188). Their characteristics are
well understood and have been demonstrated by laboratory and
pilot tests and by mathematical models.
Basically, coal in slurry form is transported from
mine to power plant via pipeline system in the following manner:
coal in roughly 2 inches in diameter chunks is delivered to a
preparation plant where it is reduced to approximately % inch
diameter sizing. This is done by crushing and pulverizing the
coal by wet grinding and rod mills (LO-084, MO-103, MO-126).
-81-
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In the rod mills, water is introduced to the pulverized
coal to form the slurry. Coal concentration in the slurry is
in the range of 45-55 wt. % (WA-043, WA-140). Specific gravity
of the slurry is about 1.40. The slurry is pumped into mechan-
ically agitated storage tanks where it is stirred to maintain
an average concentration of 50% solids by weight. The slurry
is then fed into the pipeline from the storage tanks by a
centrifugal charge pump, followed by a high-pressure positive
displacement pump. An average flow velocity of 5.0 ft/sec is
maintained throughout the pipeline by pumps that are spaced
along the line at 60 to 100 mile intervals (WA-125, WA-126,
AU-019, CO-197, HU-088, WA-153). The pipeline terminates at the
power plant where the slurry is discharged to slurry tanks.
2.5.2 Crude Oil Transportation
A transportation network consisting of pipelines,
tankers, barges, rail tank cars, and tank trucks carry crude
petroleum to refineries for processing. Of the crude oil
received at the refineries in 1970, 77.4 percent was received
by pipeline, 21.5 percent by tankers, and the remaining 1.1 per-
cent by tank cars and tank trucks (BA-234).
Crude Oil Transportation by Rail
As with rail transportation of coal, diesel electric
locomotives are used in the shipping of crude oil by rail.
However, less than one percent of the oil moved in the United
States is shipped on the railways. The railways' share of oil
transportation is small because of the extensive network of
oil pipelines in the United States and its greater efficiency
in moving oil.
-82-
-------
When oil is transported by rail, it is first loaded
into a tank car at a. terminal. These tank cars range from a
capacity of 2,000 gallons to 34,500 gallons, which is the
current maximum allowed by the Department of Transportation.
Loading is accomplished either through the top or the bottom of
the tank car. Once loaded, the tank car is coupled with either
a mixed freight train or an all-oil train for shipment. Unload-
ing of the oil is accomplished through the bottom of the tank
car upon arrival at its destination. This type transportation
of crude oil characteristically does not follow any predetermined
schedules as with unit train operations in shipping coal.
Atmospheric discharge of pollutants occurs from (1)
diesel combustion in the locomotives and (2) hydrocarbon losses
in transit and during loading and unloading of the oil.
Crude Oil Transportation by Tanker
With the increased industrial growth throughout the
world, the demand for energy resources has risen accordingly.
Over the last 25 year period, the growth rate for petroleum
tanker cargoes outstripped the expansion of world trade as a
whole. This rapid expansion is a result of the distribution
and geographical location of the major supply and demand centers
for crude oil. The world's oil reserves are primarily located
in lesser developed countries. The primary demand for this
widely used fuel, however, is concentrated in the highly, develop-
ed industrial nations, most notably Western Europe, Japan, and
the United States. As a result, the oil must be moved distances
averaging some 6,000 to 12,000 miles.
-83-
-------
To meet this need, the world tanker fleet has expanded
accordingly. By 1971, tanker tonnage at 162.9 million dead-
weight tons (DWT) comprised about 48 percent of the world fleet.
Of equal interest is the fact that the average size of tankers
in operation has tripled over the same 25 year period. Tankers
in the 300,000 DWT class are in general use today, with 500,000
DWT tankers just beginning operations (US-124).
These large tankers are-powered with steam turbines.
Fuel oil is the primary fuel used in the boilers (EN-071).
Atmospheric emissions associated with the transportation of
crude oil by tanker would result from the flue gases from these
boilers. Also, some fugitive hydrocarbon losses result from the
loading, transit, and unloading of the crude.
Crude Oil Transportation by Pipeline
Approximately 77.4 percent of the crude oil transported
is moved by pipeline. In the petroleum industry, three basic
types of pipeline systems are used: the gathering pipeline
system, the trunkline system, and the distribution system. The
gathering pipeline system transports crude oil from individual
oil wells and other production units to a central location. The
trunkline system transports crude oil from the central location
to a processing facility or a refinery. The distribution system
transports the refinery products to the various consumers. Of
these pipeline systems, the trunkline system is of interest in
this study, and is referred to as the crude oil pipeline system.
The technology of crude oil transportation by pipeline
is well developed and has been applied for decades. Although
-84-
-------
there have been a number of innovations in crude oil transporta-
tion, its technology continues to advance in the areas of
materials, techniques of pipe manufacture, and improved design
and methods of construction for both pipelines and stations
(PE-097, PE-098).
A crude pipeline system consists of pipes and pump
stations. Pipe sizes range from a nominal diameter of 6 inches,
with a flow of 7700 barrels per day, to 48 inches with as much
as a million barrels per day (PE-098). Pump stations are either
electric or diesel powered. In the early 1960's, they were
spaced approximately every 80 to 90 miles (BA-224), whereas the
newer ones are spaced about every 100 to 150 miles (BA-234).
Air emissions from crude oil pipelines result from
these pump stations. Electric-powered stations of course have
no emissions, but the diesel-powered stations do emit some
pollutants from the internal combustion engines which drive the
pumps.. Also, small hydrocarbon emissions result from leaks
located at flanges, pump seals, valve stems, etc., located in
these stations.
2.5.3 Gas Pipeline Transportation
Gas transmission by pipeline is a well-proven tech-
nology that is continuously being upgraded by the development
of new methods to cope with a changing environment. This change
is brought about by the increasing demand for natural gas and
the topographic and climatic conditions of the potential sources,
such as the Arctic regions or the arid, temperate and mountainous
western regions of the United States.
-85-
-------
The transport of natural gas to major markets is
primarily accomplished by pipelines. Current pipelines are 24,
30, 36, and 42-inch diameter systems (ST-204, VA-093). The
compressor stations located along the pipeline are driven either
by gas"engines, gas turbines, or electric motors. The frequency
of compressor stations is one every 50 to 75 miles. A typical
gas pipeline system might consist of a 36-inch diameter pipe
with compressor stations every 60 miles. The energy required
at these booster stations is dependent upon the pipeline pressure
being used in transmission. It is estimated that 4.2 percent of
the energy throughput in a pipeline is needed for compression
power (BA-234).
The atmospheric emissions associated with gas pipe-
lines come from these compressor stations. The exhaust gases
from the natural gas burned in supplying the power for the
compressor and the fugitive hydrocarbon losses from pump seals,
valve stems, etc. are the two sources of these air emissions.
New technology is expected to produce solutions to
some engineering problems -- such as the development of larger
diameter piping systems, i.e., 48 to 60-inch diameter pipe, and
higher operating pressures on the order of 1500 psi to 2000 psi
(HA-246, KA-134, VA-093).
-86-
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3.0 IDENTIFICATION OF EMISSIONS
Based on the general processing information presented
in Section 2.0, representative process modules are derived in
this section. The following modules are discussed:
Production
strip mining of coal
room and pillar coal mining
in-situ coal gasification
surface oil shale mining
room and pillar oil shale mining
in-situ shale oil production
oil well production
gas well production
Transportation
coal by rail
coal by barge
coal by pipeline
oil by rail
oil by tanker
oil by pipeline
gas by pipeline
Three modules are presented for coal extraction due to the
various production alternatives available. Oil shale extraction
uses the same mining techniques as used in coal extractions;
however, it has a greater solids handling requirement. There-
fore, oil shale mining modules are presented in a manner that
illustrates the similarities in and differences between the two
technologies.
-87-
-------
Module capacities or flow rates are based on typical
commercial scale operations. After each module is defined in
terms of operating conditions, capacities, and energy or fuel
demand, the emission sources and emissions are presented. Only
air emissions are addressed in this study and only criteria
pollutants (i.e., particulates, S02, CO, N0x, and HC) are quantified,
All emissions are related to the module basis allow-
ing for convenient assessment of a typical plant or operational
impact. Emissions from all modules are also adjusted to a common
Btu output basis for comparison of emission impacts among the
various technologies.
-88-
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3.1 Coal Production Modules
Coal mining operation and equipment choices are ex-
tremely varied and in general are determined by the local geology
and other natural conditions. As a result, no single mining
procedure can be presented as representative of the entire indus-
try. In order to accurately represent the different technologies
of the coal mining industry, modules are presented in the follow-
ing sections for strip mining, room and pillar mining, and in-
situ gasification of coal. Although modules for auger mining
and longwall (or conventional) underground mining are not presented,
it is postulated that the air emissions resulting from these
mining modules will be approximately equivalent to strip mining
and room and pillar mining, respectively.
3.1.1 Strip Mine Module
Module Basis
The strip mine module is examined both for mining fol-
lowed by physical cleaning of coal and for mining without physical
coal cleaning. The strip mine module basis is 5,000 tons per day
of cleaned coal. A 20 percent waste removal in the physical coal
cleaning operation and a thermal dryer fuel demand of 1.3 percent
of the thermally dried coal is assumed. Run-of-mine coal is used
for the strip mine module without coal cleaning. The equivalent
coal production rates allows convenient comparison of module
emissions. In 1972, 31.6 percent of all the coal extracted by
strip mining was mechanically cleaned (US-144). A summary
of emissions from both of the strip mining modules (with and with-
out physical cleaning) is shown in Table 3.1-1.
-89-
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TABLE 3.1-1
SUMMARY OF ATMOSPHERIC EMISSIONS
Strip Mining Coal Module
Basis: 6,300 ton/day R.O.M. coal
Without Physical With Physical
Air Emissions (lb/day)* Coal Cleaning Coal Cleaning
Particulates 1,800 2,400
SC-2 41 1,330
NOX 566 1,190
CO 344 394
Hydrocarbons 66 86
*The differences are based on air emissions from the
thermal dryer and diesel powered equipment associated
with the physical cleaning operation.
-90-
-------
Module Description
The strip mine module is considered to be in steady
state operation. This means that the mine pit has already been
opened and the mine is in production. In this module, any
overburden excavated on a continuous basis is moved to the rear
of the mine and refilled as a reclaiming operation. The over-
burden is removed from the mine by an electric dragline. The
dragline operation is shown in Figure 3.1-1. The exposed coal
is removed from the mine and loaded on 100 ton diesel trucks by
two electric loading shovels, each with a capacity of 10 cubic
yards. The trucks have a net weight to gross weight ratio of
0.57. They haul the coal to a preparation plant where the coal
is crushed prior to transportation or mechanical cleaning.
After the crushing operation, the coal is conveyed to
a tipple where it is loaded on unit trains or barges. If mechani-
cal cleaning is included, the coal is run through secondary
crushing prior to screening operations. After screening, the
coal is physically washed to remove the ash and part of the
sulfur. It is assumed 50 percent of the mechanically cleaned
coal is thermally dried and 50 percent is mechanically dried.
The amount of coal thermally dried depends on the demand for
low-moisture coal. The cleaned coal is stored in bins prior
to transportation to end use or conversion facilities.
Additional equipment within the mine includes two 300
hp bulldozers assigned for cleanup around the loading shovel and
two 385 hp bulldozers for leveling land in the reclamation
operation. The overburden stripping operations continue three
shifts each day, seven days per week while coal loading is re-
quired only one shift per day on a seven-day week basis. The
coal strip mine module is shown in Figure 3.1-2 and the coal
cleaning plant shown in Figure 3.1-3.
-91-
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Surface
Coal Leading
Cut
Open Cut
Plan View
25.80'
Speil /
I 5.1'
60'
120'
Section View
60'
FIGURE 3.1-1 TYPICAL DRAGLINE OPERATION
SOURCE: ST-166
-92-
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EXCAVATION
OVERBURDEN
REMOVAL
RECLAIMING
THE
STRIP MINE
REMOVAL OF
EXPOSED
COAL SEAM
i
VO
TRANSPORTING
OF COAL
OUT OF MINE
REFUSE
COAL CLEANING
PLANT
LOADING AND
SHIPPING OF
COAL
THERMAL
DRYING
FIGURE 3.1-2 STRIP MINING COAL MODULE
MECHANICAL
DRYING
-------
RUN
MINT COAL
—]
COAL I
DRCAKEK OH
CRUSHI.H
_L !^?" * °
MIDDLINGS"
WATF.R
BAUM TYPE JIG
I
3"xO
^ _r—H rj 1
—[MIDDLINGS| I REFUSE I
-I.GO SP GR.
FLOAT COAL
3/8" * 0
CLASSIFYING U
DEWATEIilUG
SCREENS
{
3/0" xO
1
3"x3/0"
IMPACT CRUSHER
SCREEN AT 3/0"
3/8" » 0
^/
SIEVE OEND Q
DESt. MING
SCREENS
!•
3/B" x 30 M
i
DENSE-MEDIA
CYCLONES
1 30 M
J
I.GO x 1.
-1.35 SP GR.
i FLOAT COAL
CENTRIFUGAL
DRYERS
1
x 0
COLLECTING 3°MxO _ Two
STAGE 1
SUMP (1 PUMPS HYDRO CYCLONES]
35 SINK
).
WET
GRINDING
MILLS
"
1
L
HIGH SULFUR
REJECTS „
30M K 0
^ E
/
c
?OTH CONCENTRATE
VACUUM FILTER ]
1 HEAT 01! Y ING
| SYSTEM
)
FROTH
FLOTATION
UNITS
1
-. i A 1 L 1 N G 5
S i
3/0" K 30 M
3/0" x 0
DRIED PRODUCT
FIGURE 3.1-3
COAL CLEANING PLANT
(Zl-014)
-94-
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Assumptions used in the strip mining modules include:
(1) The preparation plant is located 3.0 miles
from the coal production site (ST-166),
(2) The average depth of overburden is 48 feet
and has a density of 100 pounds per
cubic foot (HI-083).
(3) The average coal seam is 5.2 feet and has
a density of 81 pounds per cubic foot
(HI-083),
(4) A typical strip mine pit is 100 feet by
2,000 feet (HI-083),
(5) The run-of-mine coal has a heating value
of 12,000 Btu/lb and a sulfur content of
3.0 weight percent (HI-083), and
(6) 20 percent of the run-of-mine coal is
removed as ash refuse in the coal clean-
ing operation (SC-194).
These values are based on national averages. Emissions related
to specific coals will vary from the emissions presented in this
section depending on coal quality and physical layout of the
plant. Western coals would have a lower heating value, a
smaller percent sulfur, and a lower quantity of ash associated
with the coal (less than 10 percent ash). A strip mining opera-
tion without a mechanical cleaning facility would probably be
used for this low ash, low sulfur coal.
-95-
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Module Atmospheric Emissions
Four possible sources of air emissions are associated
with the strip mining module:
(1) emissions from diesel-powered vehicles,
(2) particulate emissions from the prepara-
tion plant and loading facilities,
(3) fugitive dust emissions from the opera-
tions within the mine, and
(4) emissions from thermal drying (if used).
Emissions from the various sources are given in Table 3.1-2.
The diesel fuel demand for the bulldozers is based on
the assumption that during the working shifts they are operated
80 percent of the time. The diesel fuel demand for the diesel
trucks carrying the coal to the preparation plant is calculated
using a factor of 7 gallons per 1000 ton-miles (HI-083). The
total diesel fuel consumption is calculated to be 1,540 gallons
per day. The emission factors for heavy duty diesel powered
vehicles are given in Table 3.1-3. The electric dragline and
electric shovels associated with the strip mine operation con-
sume approximately 28,300 kwh per day (ST-166). The electricity
to power these shovels is assumed to come from an outside source.
Module grinding and crushing operations are performed
out of the pit area. If mechanical cleaning is not involved, the
coal will be run through a primary crusher only. If the coal is
mechanically cleaned, it is assumed 10 percent of the run-of-
mine coal will have to be recrushed in a secondary crusher. The
fugitive particulate emission factor for primary crushing is 0.1
-96-
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TABLE 3.1-2
MODULE EMISSIONS
Strip Mining Coal Module
Basis: 6,300 ton/day R.O.M. coal
Emissions (Ib/day)
Source Particulates S02 CO Hydrocarbons NOV
Vehicle Emissions 20 41 344 66 566
Overburden Removal* 1160
Primary Crushing* 126
Loading and Unloading
at the Prepara-
tion Plant** 39 ____
Loading in the Pit* 506
Vehicular Travel* 40
Thermal Drying** 505 1290 35 17 603
Vehicle Emissions from
Refuse Hauling
Operations 0.9 1.8 15 2.9 25
TOTAL 2400 1330 394 M 1190
*80 percent particulate control by water spraying and dust control
techniques.
**90 percent particulate control by wet scrubbers.
-97-
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TABLE 3.1-3
AIR EMISSION FACTORS FOR HEAVY-DUTY DIESEL ENGINES
Pollutant
Particulates
Sulfur Oxides (as S02)
CO
Hydrocarbons
Nitrogen Oxides (as N02)
Aldehydes (as HCHO)
Organic Acids
Emission Factor
lb/103 gal of Diesel Fuel
13
27
225
37
370
3
3
Source: (EN-071)
-98-
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pound of suspended particulates per ton crushed. This value is
derived from rock handling operations (EN-071). The emissions
from the primary crusher are assumed to 80% reduced by use
of water sprays. The coal to the secondary crusher is completely
wetted by water sprays. The fugitive dust from the secondary
grinding operation is therefore assumed to be negligible.
Other fugitive dust sources at the preparation plant
are the loading and unloading facilities. An uncontrolled emis-
sion factor of 0.4 pound per ton unloaded is used for the enter-
ing raw coal and the exiting dried coal.. This emission factor
was originally derived from the unloading of coal at a coke
plant (EN-071). It is assumed the mechanically dried coal and
the ash refuse emit 8070 less dust due to their greater moisture
content. Both loading and unloading facilities are equipped
with a negative pressure apparatus used in conjunction with a
wet scrubber for 99% reduction of the dust emission caused
by loading and unloading. The preparation plant is also equipped
with a fabric air filtering system. The particulate emissions
from within the plant are difficult to quantify and highly variable;
however, it is assumed that the dust emissions from the prepara-
!
tion plant are negligible due to the use of a fabric filter.
Fugitive dust from within the mine is also difficult to
quantify. It is quite variable and depends upon climatic condi-
tions. Uncontrolled dust emissions from overburden disposal are
estimated at 5,800 Ib per day (EN-204). This emission includes
dust from blasting, dust from dragline operations, and dust from
the operation of the two 385 hp bulldozers. The dust is assumed
to be reduced approximately 80 percent by judicious use of water
spraying (EN-204). The fugitive dust emission factor of 0.4 Ib
per ton is also used for the in mine loading of diesel trucks by
the electric loading shovels (EN-071). This emission factor is
assumed to include the emissions from the two 300 hp bulldozers
-99-
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in the mine. Fugitive dust created by vehicle traffic within
the mine is estimated at 200 Ibs per day (EN-204). Windage losses
are assumed negligible. Dust from the loading operation and
vehicle traffic is also assumed to be reduced by 80 percent as
a result of water spraying (EN-204).
Approximately 1.3 percent of the thermally dried coal
is burned in the thermal dryer (HI-083). For the strip mining
module, this would be 34 tons per day. Thermal dryers presently
being used in the coal industry are classified as fluidized bed,
multilouver, and flash drier types (Table 3.1-4). The strip
mining module uses a fluidized bed type thermal dryer. The
cleaned coal which is fired in the thermal dryer is assumed to
have a sulfur content of 1.0 wt percent (HI-083). The emission
factors utilized to determine emissions from the coal-fired ther-
mal dryer are given in Table 3.1-5. Particulates from the thermal
dryer are controlled by a wet scrubber. Baghouses are explosion
hazards and not considered suitable for this type of operation.
Additional emissions result from hauling the ash refuse
from the preparation plant to the mining reclamation site.
The transportation is assumed done by 55-ton capacity diesel
trucks. The reclamation site is assumed to be three miles
from the preparation plant. The added diesel consumption is
calculated to be 67 gallons per day (HI-083).
-100-
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Fluidized Bed
Multilouver
Flash Drier
TABLE 3.1-4
THERMAL DRYERS
Percent Used -,
in Coal Industry
67
22
11
Particulate Emission
Factor 2
Ib/ton Uncontrolled
20
25
16
;(HI-083)
(EN-071)
Pollutant
soa
N0x
CO
Hydrocarbons
Aldehydes
TABLE 3.1-5
EMISSION FACTORS FOR THERMAL DRYING
WITH A FLUIDIZED BED DRYER
Ib/ton of Coal Combusted
Uncontrolled
38 S*
18
1
0.5
0.005
Reference
BA-234
BA-234
EN-071
EN-071
EN-071
* S Equals the Weight Percent Sulfur in Coal
Assuming 99% reduction with controls, the particulate emission
factor will be 0.2 Ib/ton of coal run through the fluidized
bed dryer (EN-071). This is based on a dryer controlled with
a cyclone and a wet scrubber.
-101-
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3.1.2 Room and Pillar Mining Module
Module Basis
The basis for the room and pillar coal mining module
is a cleaned coal production rate of 5,000 tons per day.
Assuming a 20 percent waste removal in the physical coal clean-
ing operation and a thermal dryer fuel demand of 1.3% of the
thermally dried coal, the run-of-mine coal is determined to be
6,300 tons per day. In 1972, 70% of all coal mined undergound
was mechanically cleaned (US-144). A summary of the emissions
from the room and pillar mining module is shown in Table 3.1-6.
Two sets of emissions are presented for the room and pillar mine,
the difference being the inclusion of emissions from burning
refuse piles.
Module Description
The room and pillar mine module is a typical shaft-
type mine as shown in Figure 3.1-4. The mine is assumed to be
in steady-state operation. This means that the shafts have been
drilled and the mine is producing coal on a regular basis. The
coal is mined by five electrical continuous miners. The mined
coal is crushed and conveyed to the preparation plant on the
surface. The entire mine system is ventilated by air at a rate
of one million scfm.
In the preparation plant the coal is crushed and
screened, and the oversized coal chunks are routed through a
secondary crusher. Approximately 1070 of the run-of-mine coal
is assumed to require secondary crushing. After crushing,
the coal is physically washed to remove the ash and part of
the sulfur as sulfur pyrites. Fifty percent of the cleaned
-102-
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TABLE 3.1-6
SUMMARY OF ATMOSPHERIC EMISSIONS
Room and Pillar Coal Mine Module
Basis: 6,300 ton/day R.O.M. Coal
Air Emissions Ib/day Ib/day*
Particulates 936 12,700
S02 1,290 18,900
NOX 690 6,490
CO 85.2 35,300
Hydrocarbons 53,200 59,100
^Includes emissions from burning refuse piles
-103-
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AIR SHAFT
COAL SHIPPING
VIA TRAIN
=• en
^OAL CLEANING
REFUSE
MAIN SHAFT
COAL SEAM
REFUSE PILE
FIGURE 3.1-4
TYPICAL SHAFT-TYPE MINE
o
-F>
l
-------
coal is then thermally dried and fifty percent mechanically
dried. The amount of coal thermally dried depends on the demand
for low moisture coal. The cleaned coal is stored in bins
and then loaded on unit trains or barges for transport to end
use or conversion facilities.
The ash refuse from the physical cleaning operation is
hauled via truck to a refuse dump assumed to be located approxi-
mately one mile from the preparation plant. The refuse is
reclaimed by the use of a 385 hp bulldozer. A block flow
sheet for room and pillar mining operations is shown in Figure
3.1-5. Cleaning operations are the same as those shown earlier
in Figure 3.1-3.
The following assumptions are used in establishing
the room and pillar module:
(1) The coal mine emits methane at a rate of
200 ft3/ton of coal mined (DE-148).
(2) Ventilated air dust emissions will meet
the Federal effluent air quality standard
concentration of 2.0 mg/m3 (HI-097).
(3) The run-of-mine coal has a heating value
of 12,000 Btu/lb and a sulfur content
of 3.0 wt % (HI-083).
(4) Twenty percent of the run-of-mine coal
is removed as ash refuse in the coal
cleaning operation (SC-194).
These values are based on national averages.
-105-
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INDUCED DRAFT
VENTILATION
SYSTEM
VENTILATED AIR
@ 2.0 mg/m3 dust and < 0.1 vol. 7, methane
COAL MINE AND
MINING
OPERATIONS
COAL
CLEANING
FLUE GAS
THERMAL
DRYING
COAL REFUSE
AND TAILINGS
MECHANICAL
DRYING
FINAL COAL
PRODUCT
LOADING AND
SHIPPING
FIGURE 3.1-5 ROOM AND PILLAR COAL MIKE
o
cr>
i
-------
Module Atmospheric Emissions
In the room and pillar mine module there are six
possible sources of air emissions: (1) mine ventilation system,
(2) thermal dryer, (3) final coal product loading operations,
(4) refuse transfer system from the preparation plant, (5) diesel-
powered vehicles, and (6) burning refuse. The module emissions
from the various sources are shown in Table 3.1-7.
The vented air is calculated to have a flow of one
million cubic feet per minute. This value is based on a design
criteria set to keep the methane concentrations below 0.1 vol
percent of the air in the mine (TR-049). The methane production
rate in the underground mine module is 200 cubic feet per ton
of coal mined (DE-148). Therefore, the total methane emission
rate is calculated as 880 cubic feet per minute. The ventila-
tion air in the mine is produced by an induced draft system
equipped with a large electric exhaust fan. The ventilated
air is exhausted to the atmosphere with no further treating.
Particulate emission levels in the mine are maintained
at the federal standard of 2.0 mg per cubic meter (HI-097).
Particulate emissions from the continuous miners at the mine
face may reach levels as high as 40 mg per cubic meter (TR-049).
The particulate matter generated by the continuous miners are,
however, controlled by air scrubbing systems equipped on the
miners. The air scrubbing systems are Venturi-type scrubbers
with mini-cyclones and water spraying apparatus (HI-097). Venti-
lation air rates at the mine face are maintained between 6,000
and 20,000 scfm to dilute any methane that is produced from
the mining operation (TR-049). Fugitive dust within the mine
also results from primary crushing. The module primary crusher
has a dust emission factor of 0.1 Ib of suspended solids per ton
-107-
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TABLE 3.1-7
o
00
Source
Ventilated Air
Thermal Drying*
Coal Loading*
Transfer & Refuse
Vehicle Emissions
Burning Refuse
TOTAL
Room
Basis
Particulates
11
12
180
505
18
230
2.9
,750
,700
MODULE
EMISSIONS
and Pillar Coal Mine Module
: 6,300 ton/day R.O.M. Coal
Emissions (Ib/day)
S02
-
1,280
-
-
6.0
17,600
18,900
CO
-
35
-
-
50
35,200
35,300
Hydrocarbons
53,
-
-
5,
59,
200
17
9.6
800
000
NO
-
603
-
-
83
5,800
6,490
*99% particulate control by wet scrubber
-------
crushed (EN-071). This factor is originally derived from rock
crushing operations. This dust is assumed to be reduced 80%
by use of water sprays. The final quantity of suspended dust
is diluted in the ventilation air.
The fugitive dust from the secondary grinding operation
in the preparation plant is generally quite minor and assumed
negligible in this room and pillar module. The reason for this
assumption is that the coal which is being crushed is completely
wetted and therefore is no real source of particulates.
The thermal drying operation for room and pillar mining
is the same as for the surface mining module. It is assumed
that 50% of the mechanically cleaned coal is thermally dried.
A fluidized-bed thermal dryer is used. The thermal dryer will
combust 34 tons per day of coal. The emission factors for the
thermal dryer are the same as those shown in Tables 3.1-4 and
3.1-5. Particulates from the thermal dryer are controlled by
a Venturi wet scrubbing system. Baghouses are not used due to
the explosion hazard. The thermally dried coal and mechanically
dried coal are stored in enclosed bins before loading on unit
trains or barges. Fugitive dust within the preparation plant is
quite variable and difficult to quantify. The atmospheric
emissions are controlled by a fabric filter and are assumed to
be negligible.
The loading operations are a source of considerable
particulate emissions. A particulate emission factor of 0.4
pounds per ton loaded is used for the thermally dried coal.
This emission factor is cited as the emission factor for loading
coal into hoppers at a coke plant (EN-071). It is assumed
the mechanically cleaned coal will have 80% less emissions due
to the fact that it has a greater moisture content. To reduce
the particulate emissions to the atmosphere, a negative pressure
-109-
-------
hood equipped with a wet scrubber is employed. This type of
system reduces particulates 99% (EN-071).
Fugitive dust emissions also result from the transfer
of refuse from the coal cleaning plant to the land reclamation
refuse dump. An uncontrolled emission factor of 0.4 Ib per ton
is assumed for loading and unloading operations, assuming the
refuse has characteristics similar to coal. Windage losses
are assumed to be negligible. Loading and unloading fugitive
losses are assumed to be reduced 80% by water spraying (EN-204).
Controlled fugitive dust emissions from 46 vehicle miles per
day due to refuse transport are estimated at 4.0 pounds (EN-204).
Controlled fugitive dust for reclamation operations is calcula-
ted to be 25 pounds per day. The calculated value of fugitive
dust from the reclamation operation is based on data taken from
disposal of overburden for an oil shale operation (EN-204).
Dust control is by water spraying.
Vehicle emissions include combustion emissions from the
diesel trucks hauling the refuse and the bulldozer excavating
the refuse pile. The refuse trucks carry 55 tons and have a
net weight to gross weight ratio of 0.57. The module diesel
fuel consumption is calculated to be 223 gallons per day. This
value is based on a fuel consumption rate by the trucks of seven
gallons per 1000 ton-miles and assumes that one bulldozer rated
at 385 hp is operated eight hours daily (HI-083). The emission
factors for diesel fuel combustion are shown in Table 3.1-8.
Emissions calculated from aldehyde and organic acid emission
factors are considered as hydrocarbons.
The final air emission source is burning refuse piles.
The emission factors, given in Table 3.1-9, are calculated from
1968 data on burning refuse piles (US-144, CO-168). These
emissions are not necessarily related to a refuse production
rate but rather to the total amount of refuse accumulated.
-110-
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TABLE 3.1-8
AIR EMISSION FACTORS FOR HEAVY-DUTY DIESEL ENGINES
Emission Factor
Pollutant lb/103 gal of Diesel Fuel
Particulates 13
Sulfur Oxides (as S02) 27
CO 225
Hydrocarbons 37
Nitrogen Oxides (as N02) 370
Aldehydes (as HCHO) • 3
Organic Acids 3
Source: (EN-071)
TABLE 3.1-9
EMISSION FACTORS FOR BURNING REFUSE PILES
(CO-168, US-144)
Emission Factor
Pollutant (Ib/ton of Refuse)
CO 17.8
NOX 2.95
Hydrocarbons 2.95
SO 8-89
s
Particulates
-111-
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3.1.3 In-Situ Coal Production Module
Present work in the area of in-situ coal gasification
has been in experimental and developmental stages. On the basis
of technical and economic experience to date, it is difficult
to foresee when commercial operations will be a reality. However,
in-situ coal gasification could be of value in areas where coal
is too deep to strip mine and the bed is too thin to economically
underground mine. Data for this report was taken from field
tests done by the Bureau of Mines at Hanna, Wyoming (KA-124).
Module Basis
The in-situ module is based on a fuel gas production
rate of 109 Btu/day. The fuel gas has a heating value of
approximately 250 Btu/scf (KA-124). A summary of the environ-
mental impact is given in Table 3.1-10.
Module Description
The in-situ coal combustion equipment arrangement is
much the same as in-situ oil production. There is an injection
well for introducing the air or oxidizer into the coal bed.
The coal is combusted in the bed forcing a low Btu fuel gas
along with vaporized heavy hydrocarbons into a production well.
On the surface the fuel gas will be separated from the coal tar
products. If necessary, the fuel gas could be further treated
for sulfur removal. The module presented here will assume the
fuel gas needs no further treating.
-112-
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TABLE 3.1-10
SUMMARY OF ATMOSPHERIC EMISSIONS
In Situ Coal Production Module
Basis: 10? Btu/day Fuel Gas Produced
Air Emissions Ib/day
Particulates 5.5
CO 30.0
Hydrocarbons (CH4)
-113-
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Module Atmospheric Emissions
The only anticipated air emissions from the in-situ
coal production site are fugitive emissions from high-pressure
equipment and from vehicle movement around the surface facili-
ties. Emission factors for the high-pressure equipment cannot
be derived based on the Hanna, Wyoming, data because of the large
leakage losses due to inadequate seals around the various wells
drilled into the coal. A total environmental emission of 0.22
volume percent of the fuel gas produced is suggested. This
suggested emission factor is based on a reported value for
miscellaneous hydrocarbons from gas wells (BA-234). The compo-
sition of the fuel gas is given in Table 3.1-11. The total
volumetric flow rate of the fuel gas is calculated to be 4 x 106
scf/day for a production of 109 Btu/day. A controlled fugitive
dust emission rate is estimated at 5.5 Ib/day (EN-204). This
factor is based on 5 miles of unpaved roads with 50 vehicle
miles traveled daily. It should be noted that plans for in-situ
coal gasification include connection with an on-site power plant
facility. The compressor driver in the module is assumed to be
powered with steam or electricity from this power plant.
-114-
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TABLE 3.1-11
TYPICAL GAS ANALYSIS OF IN-SITU COAL FUEL GAS
Source: Hanna In-Situ Gasification Experiment
Component Mole Percent
Ha 8.2
oa i.o
N2 50.7
CH4 16.5
CO 4.3
C2 1.6
CO, 17.1
3
Other 0.5
Source: (KA-124)
-115-
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3.2 Oil Shale Extraction Modules
Many of the techniques utilized in the oil shale
industry are essentially the same as in the coal industry;
however, the amount of solids handled is much greater. In this
section, three types of shale oil extraction techniques will be
examined for possible air emissions. The techniques are surface
mining, room and pillar mining, and in-situ shale oil production.
3.2.1 Surface Mine Module
The techniques used in the surface mining of oil shale
are very similar to strip mining of coal. Therefore, similar
emission factors to those in the strip mining of coal will be
used to calculate air emissions from this oil shale module.
Module Basis
The shale oil surface mining module is based on a re-
moval rate of oil shale equal to 73,700 tons/day. This is
enough oil shale to produce 50,000 bbl/day of upgraded shale oil,
The oil shale has an oil content of 30 gallons/ton of shale.
This value is believed to be near the minimum allowable oil con-
tent to make oil shale processing economically feasible (US-093).
A summary of the environmental impact is given in Table 3.2-1.
Module Description
The surface mining oil shale module is assumed to be
in a steady-state operation. This means the pit has been opened
and oil shale is being removed at a rate of 73,700 tons/day.
The oil shale bed is assumed to be 40 ft thick and has a density
of 90 Ibs/cu ft (US-093).
-116-
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TABLE 3.2-1
SUMMARY OF ATMOSPHERIC EMISSIONS
Oil Shale Surface Mining Module
Basis: 73,700 tons/day of Processable Oil Shale
Air Emissions Ibs/day
Particulates 18,100
S0g 467
NOX 6,400
CO 3,890
Hydrocarbons 744
-117-
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The overburden is assumed to be 450 ft and have a
density of 100 Ibs/ cu ft (HI-083). The overburden is also being
removed by trucks to a reclaiming site assumed one mile away.
The overburden after being hauled to the disposal site is assumed
graded by two 385 hp bulldozers operating eight hours daily.
The oil shale itself is assumed hauled by truck 2,000
feet in the oil shale pit to the primary crusher and conveying
system. The hauling is being done by 55-ton trucks with a fuel
consumption of 7 gallons/1000 ton miles and a net weight to gross
weight ratio of 0.57 (HI-083). The oil shale is loaded in the
mine by electric shovels.
The oil shale, after being crushed in the pit area, is
transported out of the mine to the shale oil plant site. The oil
shale can be transported by conveyors or be pumped as a slurry
of about 50 percent solids (US-093). This module will assume
conveyor transport. The oil shale will be further crushed through
secondary and tertiary crushing and screening operations as a
preparation for shale oil extraction. Typical steps involved
in oil shale surface mining are shown in Figure 2.2-2.
Module Atmospheric Emissions
There are four possible sources of air emissions from
the oil shale production module: (1) excavation and blasting,
(2) fugitive dust emissions from transporting the oil shale and
overburden, (3) vehicle emissions from the combustion of diesel
fuel, and (4) primary, secondary, and tertiary crushing and
screening operations. Emissions from the various sources are
listed in Table 3.2-2.
Dust emissions from excavation and blasting arc variable
and uncertain. The uncontrolled particulate emission race is
estimated at 7,290 pounds per day (EN-204). These emissions
-118-
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Basis:
TABLE 3.2-2
MODULE EMISSIONS
(Ib/day)
Oil Shale Surface Mine Module
73,700 ton/day of Processable Oil Shale
Particulates
1,460
11,800
61
neg
225
1,470
3,100
SO 2 CO
Hydrocarbons
NO,
18,100
467 3,890
467 3,890
744
Excavation & Blasting*
Transporting Fugitive
Dust
- Truck Loading &
Unloading*
- Truck Hauling*
- Conveying
Vehicle Emissions
Primary Crushing*
Secondary & Tertiary
Crushing**
TOTAL
* 80 percent dust control from fugitive dust control techniques
** 99 percent dust control from bag houses or wet scrubbers
744
6,400
6,400
-------
can be reduced approximately 80% using various particulate
control techniques (EN-204). Therefore, the final module fugitive
emission rate for oil shale excavation and blasting is 1,460 Ibs
per day.
Fugitive dust emissions from transporting the oil
shale and overburden can occur during the truck hauling or the
conveying operations. Assuming windage losses negligible, the
major dust source will be the loading and unloading of trucks.
The uncontrolled particulate emission factor used for each
loading and each unloading operation is 0.4 Ibs per ton of
material loaded or unloaded (EN-071). This emission factor comes
from the uncontrolled loading of coal hoppers at a coke plant and
is suggested as a basis for evaluation of oil shale loading
operations. Once again 80% dust control is believed possible
due to settled dust and judicious use of water spraying.
Fugitive dust due to vehicular traffic on unpaved roads within
the mines is estimated at 61 pounds per day (EN-204). The
conveying system is covered, and thus the fugitive dust emissions
from it can be assumed negligible (HI-083).
Diesel fuel consumption for the 55-ton trucks is cal-
culated from a factor of 7 gal/1,000 ton-mile and a net weight
to gross weight ratio of 0.57 (HI-083). The diesel consumption
for trucks is calculated to be 16,900 gal/day. The diesel fuel
consumption of the bulldozers is calculated to be 390 gal/day.
Emission factors for diesel fuel consumption are the same as
those given in Table 3.1-8.
-120-
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The primary crushing in the mine has an uncontrolled
suspended solids emission factor of 0.1 pound per ton crushed
(EN-071). As previously mentioned this factor was originally
derived from rock handling operations. The suspended dust is
assumed 80% controlled by water or chemical spraying. After the
initial crushing the oil shale is transported out of the strip
mine on a covered conveyor. Secondary and tertiary crushing and
screening are performed in an enclosed building equipped with
either a baghouse or wet scrubber giving 997« control of suspended
dust emitted from within. The uncontrolled suspended solids
emission factors for secondary and tertiary crushing and screening
are 0.6 pounds per ton and 3.6 pounds per ton of oil shale
crushed, respectively (EN-071). These emissions factors also
are derived from rock-handling processes.
-121-
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3.2.2 Room and Pillar Mine Module
Room and pillar mining of oil shale is very similar
to room and pillar mining of coal. Therefore, similar emission
factors will be used to calculate air emissions for the oil shale
module.
Module Basis
The shale oil room and pillar mine module is based on
a removal rate of oil shale equal to 73,700 ton/day. This is
enough oil shale to produce 50,000 bbl/day of shale oil (US-093)•
The oil shale has an oil content of 30 gallons/ton of shale. This
value is believed to be near the minimum allowable oil content
to make oil shale processing economically feasible (US-093). A
summary of the environmental impact is given in Table 3.2-3.
Module Description
The room and pillar mine module is assumed to be in
steady-state operation. This means the mine development has
been completed and the mine is producing oil shale at a rate of
73,700 tons daily. The oil shale bed is assumed 40 feet thick and
has a density of 90 Ib/cu ft (US-093). The oil shale is broken
up by explosives and loaded into diesel-powered 55-ton trucks
by electric front-end loaders. The trucks transport the cil
shale to the primary crusher located in the mine where the oil
shale is reduced to sizes below 10 inches (US-093). From there
the oil shale is conveyed to the surface and fed to secondary
and tertiary crushing and screening operations. The final
crushed oil shale product is then transported to a nearby oil
shale processing plant. The mine is ventilated by two 1,000,000
cfm fans (US-093). A flow sheet of room and pillar mining is
shown in Figure 3.2-2.
-122-
-------
TABLE 3.2-3
SUMMARY OF ATMOSPHERIC EMISSIONS
Oil Shale Room and Pillar Mine Module
Basis: 73,700 ton/day of Processable Oil Shale
Air Emissions Ib/day
Particulates 3,680
S0?
NOX 154
CO 94
Hydrocarbon 18
-123-
-------
OIL SHALE UNDERGROUND MINE
(BASIS: OIL SHALE FOR 50,000 BBL/DAY RETORTING PLANT)
UNDERGROUND MINE
ROOM AND PILLAR
VENTILLATED AIR
AT 2.0 mg/m3
DUST CONCENTRATION
73,700 TONS/DAY
PRIMARY CRUSHERS
(IN MINE)
SECONDARY AND
TERTIARY CRUSHING
AND SCREENING
OIL SHALE TO
PROCESSING UNIT
73.550 TONS/DAY
DUST RECOVERY
SYSTEM
VENTILATED AIR
OIL SHALE DUST
150 TONS/DAY
CONVEYED
TO SPENT
SHALE DISPOSAL
FIGURE 3.2-2
-124-
-------
Module Atmospheric Emissions
There are four possible sources of emissions from the
room and pillar oil shale mine: (1) blasting and primary crush-
ing in the mine, (2) secondary and tertiary crushing and screen-
ing operations, (3) vehicle emissions, and (4) miscellaneous
fugitive dust emissions. Emissions from the specific sources
are listed in Table 3.2-4.
Blasting, primary crushing, and vehicle emissions
leave the mine with ventilation air. Water spraying is used to
reduce fugitive dust emissions from all three sources in the
mine. The dust level in the mine is assumed to be at the
maximum level set by the federal government of 2.0 mg/m3 (HI-097),
and therefore the total dust emitted from this mine is calcu-
lated to be 360 Ib/day.
The 55-ton trucks are assumed to travel 1,500 feet
between extraction and primary crushing in the mine (US-093).
The trucks have a diesel fuel consumption of 7 gallons/1000
ton mile. Using a factor of a net weight to gross weight ratio
of 0.57, the diesel fuel consumption .is calculated to be 373
gallons/day. The vehicle emissions are calculated using emission
factors given in Table 3.1-8. The crushed oil shale is trans-
ported out of the mine on covered conveyors. Dust emissions
from the conveyors are negligible (HI-083).
Secondary and tertiary crushing and screening opera-
tions on the surface are assumed to be enclosed and to be 99%
controlled by the use of either fabric filters or wet scrubbers
(EN-071). The particulate emission factors for uncontrolled
secondary and tertiary crushing and screening are 0.6 pounds of
suspended solids and 3.6 pounds of suspended solids per ton of
material crushed, respectively (EN-071). These emission
factors were originally derived from rock-handling operations.
-125-
-------
TABLE 3.2-4
MODULE EMISSIONS
(Ib/day)
Oil Shale Room and Pillar Mine Module
Basis: 73,700 ton/day of Processable Oil Shale
Particulates
Blasting & Primary
Crushing
360
S02
CO Hydrocarbons NO
Ni
Secondary & Tertiary 3,100
Crushing & Screening*
Vehicle Emissions
5.5
11.2
93.5
17.9
154
Miscellaneous Fugitive
Dust**
TOTAL
220
3,680
11.2
93.5
17.9
154
* 99 percent controlled by either fabric filters or wet scrubbers
** 80 percent controlled by dust control techniques
-------
Fugitive dust emissions are estimated at about 220 lb/
day (EN-204). These dust sources include 5 miles of unpaved
roads on the surface and permanent disposal of the oil shale.
These fugitive sources are assumed controlled by water spraying
or other dust control techniques.
3.2.3 In-Situ Shale Oil Production
In-situ type shale oil production is presently only in
the experimental stages and there is no assurance when commer-
cial technology will be developed. During the past 20 years
there have been several in-situ retorting programs conducted by
both industry and government. Problems relating to insufficient
natural permeability of the oil shale and inability to control
the process have arisen. Additional field-scale operations are
needed because of the difficulty in designing useful laboratory-
scale experiments.
Module Basis
The in-situ shale oil production module is based on a
production rate of 50,000 bbl/day of upgraded shale oil. The
summary of the module air emissions is given in Table 3.2-5.
Module Description
A conceptual design of an in-situ retorting operation
is given in Figure 3.2-3. Following are the four essential steps
in in-situ retorting:
(1) Drilling of wells in front of the
retorting zone
(2) Fracturing of the oil shale
-127-
-------
TABLE 3.2-5
SUMMARY OF ATMOSPHERIC EMISSIONS
In-Situ Shale Oil Production Module
Basis: 50,000 bbl/day of Upgraded Shale Oil
Air Emissions Ib/day
Particulates 30,000
S02 66,800
N0x 12,400
CO 116,000
Hydrocarbons 13.450
-128-
-------
R
e
s
O
Restored
area '
ro
r O
n
g
P
I
u
g
g
i
n
0
0
0
0
0
•MMlM
0
0
- R.
o
o
o
o
Low Btu gas to flare
1.485* 106 scf/cd
Makeup natural __ Makeup gas plus refinery
gas if needed ' 'gas to plant fuel system
Gas/oil mist
and water vapor
Gas/oil
separation
and
recovery
plant
In-situ shale oil
49.100 bbl/cd
Retort water
Oil
upgrading
plant
(refinery)
-z-
o
n"
560.000 gal/cd
e
0-f "• O
Air
compression
plant
i
Upgraded oil
50.000 tbi/cd
Sulfur, 38 tons/ed.
Ammonia. 130 tons/cd
Refinery waste water
100.000 gal/cd
Waste water
treatment plant
Treated water for refinery
or other plant uses
Legend 660.000 gal/cd
O Drilling well
O Producing well
® Injection well
0 Plugged well
Q Surface monument removed
Flow Diagram of 50,000-Barrel-Per-Calendar-Day In Situ Recovery System
FIGURE 3.2-3 IN-SITU SHALE OIL PRODUCTION MODULE
Source: (US-093)
-------
(3) Injection of air and recirculation gas
and formation of a temperature and pres-
sure gradient within the oil shale
(4) Recovery of the product
The air is compressed to about 100 psig by a steam-driven
compressor. The steam is generated in an on-site shale .oil up-
grading plant. In-situ shale oil is recovered along with retort
water and a low-Btu gas. The heating value of the gas is
below that required for a self-sustaining flame; therefore,
the gas must be incinerated in an existing boiler or in a
large heater. Before burning, the gas must be treated for
sulfur removal. Removal of the hydrogen sulfide is of concern
because conventional processes are unable to remove HaS at
concentrations less than 0.1 vol percent from low-pressure
gases (EN-204). Advanced technologies will have to be applied
to this problem.
Module Atmospheric Emissions
A major source of air emissions from the in-situ
retorting process is the flared low Btu gas from the gas/oil
separation and recovery plant. The flared gas flow rate is
approximately 1,485 x 10s scf/day (US-093). The expected compo-
sition of this gas before treating is given in Table 3.2-6. The
HaS is assumed to be reduced to a 250 ppm concentration (EN-204),
The hydrogen sulfide is combusted to SOa in the flare or
incinerator. The CO in the gas is assumed to be reduced 99
percent during incineration (EN-204). The particulate emissions
factor from the flared gas is assumed equal to the emission
factor for the firing of a fuel gas, 0.02 lb/1,000 scf (EN-071).
-130-
-------
TABLE 3.2-6
CHARACTERISTICS OF GASES FROM IN-SITU RETORTING -1
Concentration
Component Volume-Percent
Nitrogen 73.7
Oxygen 3.4
Propane 0.2
Carbon Dioxide 21.4
Carbon Monoxide 0.1
Hydrogen Sulfide 0.1
Butanes 0.1
Methane 0.5
Ethane 0.5
1 Heating value approximately 30 Btu/scf,
Yield from operation at level of 50,000 barrels/day upgraded
shale oil approximately 1.5 x 106 scf/CD
Source: (US-093)
-131-
-------
The hydrocarbon emission factor for the flared low-Btu gas
is assumed to be equal to the hydrocarbons resulting from
combustion of an equivalent amount (heating value) of natural
gas. This value is calculated by multiplying the hydrocarbon
emission factor for natural gas by the ratio of the heating
value of the low Btu gas to that of a fuel gas (EN-071). This
calculated emission factor is 0.0012 Ibs/1,000 scf. The nitro-
gen oxide emission is estimated as 12,400 Ibs/day (EN-204).
Miscellaneous fugitive gas emission at the wellhead
is estimated at 0.22 volume percent of the fuel gas. This
emission factor is based on reported miscellaneous gas losses
occuring at gas wells (BA-234). There will also be miscellaneous
hydrocarbon emissions due to the production of the liquid shale
oil. The assumed emission factor is 4 lb/103 gallon of oil
produced (BA-234). Fugitive dust emissions are estimated to
be 5.5 Ibs/day (EN-204). These emissions are from 5 miles of
unpaved roads with 50 vehicle miles traveled per day. The
module emissions from various sources are given in Table 3.2-7.
-132-
-------
TABLE 3.2-7
MODULE EMISSIONS
(Ib/day)
In-Situ Oil Shale Production Module
Basis: 50,000 bbl/day Upgraded Shale Oil Production
Flared Low Btu Gas
(After Sulfur Removal)
Miscellaneous Gas
Emissions
Fugitive Hydrocarbon
Emission for Shale
Oil Liquid Production
Fugitive Dust
TOTAL
Particulates
30,000
negl.
-
5.5
30,000
so2
66,200
582
-
-
66,800
CO NO Hydrocarbons
116,000 12,400 1,780
255 NA 3,420
8,250
_
116,000 12,400 13,450
* SO? calculated from equivalent HaS emitted.
-------
3.3 Oil Production Module
Module Basis
The oil production module presented here is based on
a typical crude oil production rate of 1,000 bbl/day. This
value represents the final crude oil output. The module values
in the following sections are determined from this 1,000 bbl/day
basis. Modules for both water flooding and steam injection are
described. These modules are further divided depending on the
percentage of brine in the emulsion removed from the well. A
summary of the environmental impact or combinations of these
variables is given in Table 3.3-1.
Module Description
The module for oil production is based on one gather-
ing system fed by several oil wells. The wellheads are the
plunger lift type equipped with prime movers which operate on
electricity. From the gathering system, the oil-brine emulsion
is fed into a water knockout tank. To enhance the oil-water
separation in the knockout tanks, the oil-brine emulsion is
pretreated in a heater treater which destabilizes the
emulsion. The light hydrocarbon gases are then removed in an
oil-gas separation section consisting of three spherical sepa-
ration tanks operating at progressively decreasing pressures.
The released gas is sent directly to a gas treating plant.
The brine from the emulsion breaking system is combined
with the brine from the water knockout tank and run through a
flotation cell wastewater treater. The flotation cell treater
removes sludge, grit, and oil particles from the wastewater.
The treated water is used for either steam generation or water
-134-
-------
TABLE 3.3-1
DOMESTIC CRUDE PRODUCTION MODULE
Basis: 1,000 bbl/day Crude Production
AIR EMISSIONS
(Ib/day)
Pollutant
Particulates
S02"
CO
Hydrocarbons***
NOX
.Water Flooding
Without
Heater Treater*
2.5
5.2
43.2
114.0
71.5
Water Flooding
With
Heater Treater
(57. Brine)
3.2
18.3
43.8
114.0
79.5
Water Flooding
With
Heater Treater
(50% Brine)
6.3
72.3
46.4
119.0
114.0
Water Flooding
With
Heater Treater
(85% Brine)
10.9
155.0
50.3
126.0
168.0
Steam
Injection**
Heater Treater
(5% Brine)
23.4
69.2
4.5 .
112.0
47.6
Steam
Injection**
Heater Treater
(507. Brine)
532.0
1,170.0
94.5
204.0
956.0
Steam
Injection**
Heater Treater
(85% Brine)
3,030
6.420
529
641
5,320
LO
Ln
I
* Either chemical or electrical emulsion breaking is used
** Assuming all the water from the brine is converted to steam
*** HC emission include emissions calculated from aldehyde emission factors..
-------
flooding. It must be filtered to remove the suspended solids.
The solids concentration is lowered as much as possible to
eliminate particulate buildup in the injection well. A sand
filter is normally used for this purpose. The water is also
treated for removal of dissolved H2S, which contributes to
corrosion in the pipes and machinery and is also an atmospheric
emission problem. H2S removal from the wastewater is usually
accomplished by countercurrent gas stripping (CH-182).
Storage facility for crude oil from the separation
unit is equipped with a vapor recovery system. The vapor
recovery system is also tied in with the heater treater to
capture any vapor emissions from that unit. The crude oil is
transferred from the storage tanks to the pipeline by a lease
automatic custody transfer pumping system. This unit also
automatically samples the crude for analysis of sediment, water
content and oil gravity.
The injection system for either water flooding or
steam injection consists of a central high-pressure water
pump for water flooding or a steam generator for steam injection
and a distribution system. The use of either system is depend-
ent on economics and the characteristics of the crude oil being
recovered.
The same flowsheet for an oil production site can be
used for either onshore or offshore oil production. This flow
diagram is shown in Figure 3.3-1.
-136-
-------
CRUDE OIL PRODUCTION
10
OIL
WELL(S)
CRUDE OIL
-BRINE ^
EMULSION
INJECTION
SYSTEM
I
STEAM
GENERATOR OR
WATER FLOODING
I
FLOOD
WATER
FILTER
SYSTEM
HIGH PRESSURE .GAS
HIGH PRESSURE GAS
GATHERING
SYSTEMS
MULSION
IREAKING*-
FLOTATION
CELL WASTE
WATER
TREATMENT
WATER
KNOCK-
OUT
CRUDE
OIL .
BRINE
INTER PRESS. GAS
LOW PRESS.
GAS
^AJ3^^_S_E£_A_RAjnqjY |
EFFLUENT WATER
CRUDE OIL (TO PIPELINE)
TO GAS
'TREATING
_TO GAS
"TREATING
CRUDE OIL
STORAGE
WITH VAPOR
RECOVERY
FIGURE 3.3-1
-------
Module Atmospheric Emissions
The air emissions from the oil production module
come from three possible sources: (1) the heater treater, (2)
the steam generator if steam injection is used or the diesel-
operated pump if water flooding is used, and (3) miscellaneous
hydrocarbon emissions. The emissions are dependent on the
quantity of water or brine in the crude oil. In steam genera-
tion for steam injection, it is assumed that all of the brine
which has been separated is reinjected. The emissions for the
various units involved in oil production are given in Table 3.3-2,
Heater Treater Emissions
The heater treater used for emulsion breaking is
a direct-fired heater. The heater is assumed to operate at an
80 percent thermal efficiency. The crude emulsion is preheated
in a heat exchanger train which removes heat from the hot crude
and brine streams leaving the heater treater. The heater treater
is normally operated at about 210°F. The fuel used in the heater
is a fuel gas (natural gas) containing about 2,000 ppm hydrogen
sulfide. The emission factors for fuel gas combustion are given
in Table 3.3-3. The heat requirements for various emulsions
are given in Table 3.3-4.
Steam Injection or Water Flooding Emissions
When steam injection is used as a secondary
recovery method, a large pollution source is the steam generator.
The steam generator selected for illustration in this oil
production module is fired with fuel oil containing 0.3 wt. %
-138-
-------
TABLE 3.3-2
DOMESTIC CRUDE OIL PRODUCTION MODULE
Air Emissions
(Ib/day)
Basis: 1,000 bbl/day Crude Oil Production
Heater Treater -
5% Brine
507. Brine
85% Brine
Steam Generator -
57. Brine
507. Brine
85% Brine
Vapor Recovery System
Wastewater Separators
Pumps
Compressors
Relief Valves
Pipeline Valves
Miscellaneous Flaring & Fires
Diesel Pump for Water Flooding
Particulates
0.73
3.76
8.4
22.6
:.528
3.020
-
-
-
-
-
-
0.02
2.5
S02
13.1
67.1
150
55.7
1,100
6,270
-
-
-
-
-
-
0.38
5.2
CO
0.63
3.20
7.14
3.9
91.3
522
-
-
-
.
-
-
Neg
43.2
Hydrocarbons
0.99
5.07
11.3 .
3.0
68.5
392
Neg
7.9
73.8
3.8
7.9
11.6
0.76
7.1
NO,
8.4
43.2
96.6
39.1
91?
5,220
-
-
-
-
-
-
0.05
71.0
Aldehydes
0.11
0.56
1.26
1.0
23-0
130
-
-
-
-
-
-
-
0.6
-------
TABLE 3.3-3
AIR EMISSION FACTORS FOR THE COMBUSTION OF
NATURAL GAS AND FUEL OIL
Particulates
Sulfur Oxides (as S02)
CO
Hydrocarbons
Nitrogen Oxides (as N02)
Aldehydes (as HCHO)
Natural Gas
lb/1000 scf
0.02
2 S *
g
0.017
0.027
0.23
0.003
Fuel Oil
lb/1000 bbl
970
6,720 SQ**
168
126
1,680
42
* S is the equivalent sulfur concentration in the fuel gas
g (lb/1,300 ft3).
** S is the sulfur weight percent in the fuel oil.
SOURCE: (EN-071)
-140-
-------
TABLE 3.3-4
HEATER TREATER HEAT REQUIREMENTS
Basis: 1,000 bbl/day of Final Crude Product
Brine Vol %
5
50
85
Heat
t Requirement Fuel Gas Requirement
(Btu/day) (scf/day)
3.67 x 10
1.88 x 10s
4.20 x 10
3.67 x 10
1.88 x 105
4.20 x 105
TABLE 3.3-5
STEAM GENERATOR HEAT LOADS
Basis: Steam is 80% Vapor
Fuel Oil
Brine
Vol %
5
50
85
Steam Produced
db/day)
1.44 x 105
3.36 x 106
1.92 x 107
Heat Requirement
(Btu/day)
1.47 x 108
3.43 x 109
1.96 x 1010
Requirement
(bbl/day)
23.3
544.0
3,110.0
-141-
-------
sulfur. The emission factors for fuel oil combustion are
shown in Table 3.3-3. The expected heat load will depend on
the amount of steam produced. The steam produced is about 80
percent vapor at 1,500 psig. Expected heat loads for various
brine concentrations are given in Table 3.3-5.
Water flooding requires sizeable pumping capacity.
The amount of injection water needed for this example is assumed
to be 10 gallons per gallon of oil recovered (CH-182). The
injection rate for 1,000 bbl/day crude oil production should be
about 300 gpm. The injection pressure required is around 1,500
psig. From this data it was determined that the module would
require a 440 hp pumping system. The pump was assumed to have
a diesel drive which consumes 192 gallons of diesel fuel per
day. The emission factors for diesel fuel engines were given
in Table 3.1-3.
Miscellaneous Hydrocarbon Emissions
Possible sources of fugitive hydrocarbon emissions
are the following:
wastewater separators,
pumps,
compressors,
relief valves, and
pipeline valves.
Emission factors for each of these sources were tabulated during
a survey of the oil production and refining industry by Monterey-
Santa Cruz County, California, and are given in Table 3.3-6
(MS-001). Another source of miscellaneous emissions is flaring.
Average oil loss through flaring has been estimated to be 2 x 10"s
-142-
-------
TABLE 3.3-6
MISCELLANEOUS OIL PRODUCTION EMISSION FACTORS1
Wastewater Separation
Pump Seals
Compression Seals
Relief Valves
Pipeline Valves
Hydrocarbon Emissions
tons/day* lb/103bbl
0.2 7.9
1.9
0.1
0.2
0.3
73.8
3.8
7.9
11.6
1 (MS-001)
* Based on a production rate of 50,000 bbl/day
TABLE 3.3-7
EMISSION FACTORS FOR FLARING AND OIL DISCHARGE
Emissions (Ib/bbl of Oil Discharged)
Particulate
sos
Hydrocarbons
CO
Flares
1
19
0.1
0.1
2.5
Evaporation
38
Total
1
19
38.1
0.01
2.5
-143-
-------
bbl/bbl produced (BA-234). The emissions from flaring and oil
discharge are given in Table 3.3-7 (BA-234). Crude storage
facilities equipped with vapor recovery systems have negligible
hydrocarbon emissions.
-144-
-------
3.4 Gas Production Module
A module for a typical natural gas production process
is presented in this section. A natural gas processing plant
is also included in the module.
Module Basis
The gas production module is based on a typical com-
mercial-size operation of 500,000 scfd of gas production.
The atmospheric emission values summarized in Table 3.4-1 are
based on this production rate.
Module Description
Several processing steps are necessary in the produc-
tion of pipeline-quality natural gas from a raw wellhead gas.
The first step involves extraction of the gas from its under-
ground reservoir. Reservoir pressures vary from field to
field and are dependent in part upon the time a reservoir has
been producing gas. The gas is extracted from the reservoir
through a producing well. From the wellhead, the gas is passed
first through knockout stages to remove water and to recover
condensates present in the gas stream. These two process steps
are located at the well site. A booster compressor is used to
move the raw gas to a central treating plant, where the gas is
treated to meet sales specifications. Processing at the central
plant involves acid gas removal, dehydration, and recovery of
LPG and natural gasolines. The H2S removed from the gas is
converted in a Glaus plant to elemental sulfur. The cleaned
natural gas is then compressed and sent to product pipelines.
Figure 3.4-1 shows the processing steps associated with a
natural gas production and processing system.
-145-
-------
TABLE 3.4-1
SUMMARY OF ATMOSPHERIC EMISSIONS
Gas Production Module
Module Basis: 500,000 scfd natural gas production
Air Emissions, Ib/day
Particulates 0.10
S02 22.57
N0x 31.58
HC 136
CO 0.10
-146-
-------
GAS PROCESSING PLANT
GAS WELL
&
LIQUID
KNOCKOUT
CONDENSATE
(1000 gal/day)
Basis: 500,000 Scfd
raw gas at the wellhead
t80 Mscfd
ACID GAS
REMOVAL
DEHYDRATION
HEAVY
HYDROCARBON
REMOVAL
NATURAL GAS
PRODUCT
460 Mscfd
HEAVY
HYDROCARBON
1000 gal/day
FIGURE 3.4-1
-------
Often, some heavy hydrocarbons (C7's and C8's) will
be contained in the produced gas. Heavy hydrocarbon production
depends upon the raw gas composition and the on-site processing
equipment. The following raw gas composition is assumed for
this module:
Methane - 89.0% H2S - 0.3%
Ethane - 3.0% C02 - 1.5%
Propane - 1.0% N2, H20, 02 , COS, CS2 - 0.2%
Butanes - 0.5%
Pentane - 0.3%
Hexane - 0.2%
Heptane - 3.0%
Octane - 1.0%
Based on a gas extraction rate of 500,000 scfd and assuming es-
sentially 100% recovery of the heptanes and octanes, some
1000 gal/day of condensate is recovered in the heavy hydrocar-
bon recovery stage. This liquid is stored on-site in a 30,000
gallon tank equipped with a vapor recovery system.
The remaining natural gas has the following slightly
altered composition:
Methane - 92.7% H2S - .3%
Ethane - 3.1% C02 - 1.6%
Propane - 1.0% N2, H20, 02, COS, CS2 - 0.3%
Butane - 0.5%
Pentane - 0.3%
Hexane - 0.2%
-148-
-------
This gas is piped to the processing plant where 70% of the
ethane, 95% of the propane, and 99% of the biltanes and higher
are recovered in a refrigerated absorption unit. The ethane
(10,300 cu ft/day), propane (4,500 cu ft/day), and butanes and
higher (4,950 cu ft/day) are separated and sent via pipeline to
petrochemical plants. Essentially 100% of the natural gasoline
(pentanes and hexanes) is recovered and stored in tankage
equipped with a vapor recovery system.
Process fuel is the only major utility requirement in
the gas production and processing units. At the well site,
the major fuel requirements are drivers for the gas compressors
moving raw gas to the central gas plant. Estimates on the
amount of fuel required for these compressors range from 0.6
percent (CO-129) to 3.2 percent (BA-234) of the gas produced.
Using 3.2 percent of the gas as the amount of fuel required, a
total of 15,000 cu ft/day of raw natural gas would be burned
in a heavy-duty gas engine driving the compressor.
Acid gas removal in the processing plant is accom-
plished in a Girbitol unit which uses MEA (monoethanolamine)
as the absorber liquid. This processing step has a steam re-
quirement of 1.2 pounds of 60 psig steam per pound of acid gas
removed. For this module, the amount of acid gas removed to
meet pipeline specifications is 130 Ibs/day of HaS and 720
Ibs/day of C02- Thus, the unit will require 1000 Ibs of steam
daily. Generation of this steam on-site will require about
0.2 percent of the gas produced in this module.
Utility requirements in the glycol dehydration unit
amount to about 0.1% of gas produced to supply process heat.
-149-
-------
The refrigerated absorption unit used to remove the heavier
hydrocarbons consumes about 0.75 percent of produced gas energy.
Table 3.4-2 summarizes the heat requirements and flow
rates for this module.
Module Atmospheric Emissions
Air emission sources for the gas production area
include fugitive hydrocarbon'losses and combustion products
from the booster station. For the gas processing area, atmos-
pheric emissions result from fuel combustion in the glycol
dehydration unit, the Girbitol unit, and the refrigerated
absorption unit, triethylene glycol from the dehydration
unit, S02 from the Glaus plant, gas flaring, fugitive sulfur
dust from sulfur stockpiles, and miscellaneous fugitive hydro-
carbon leaks. Table 3.4-3 summarizes these emissions.
Miscellaneous (fugitive) hydrocarbon emissions
result from process leaks at pump seals, valve stems, flanges,
etc. Estimates of the quantity of these losses have been re-
ported. It has been estimated that 0.22 percent of the gas
produced is lost due to leaks at the well site and 0.44 percent
escapes as fugitive emissions from the processing plant (BA-234).
This amounts to hydrocarbon emissions of 46.5 Ibs/day at the
well site and 89.3 Ibs/day at the processing plant.
The air emissions from the booster compressor driver
located at the gas well are estimated using EPA emission factors
for heavy-duty gas engines (EN-071). These factors are shown
in Table 3.4-4.
The N(D factor is based on the horsepower require-
X
ment of the booster compressor. Figure 3.4-2 gives the NC-
X
emission rate as a function of compressor horsepower load. The
-150-
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TABLE 3.4-2
Ln
Unit
Well Site Compressor
Girbitol Unit
Glycol Dehydration Unit
Refrigerated Absorption
Unit
MODULE HEAT REQUIREMENT
GAS PRODUCTION MODULE
Heat Requirement
(m Btu/mscf)
32.0
2.1
1.0
7.3
Natural Gas
Flow Rate
(m scfd)
480
480
480
470
Unit Heat
Requirement
(Btu/day)
1.5 x 107
1.0 x 106
4.8 x 105
3.5 x 106
1.99 x 107 Btu/day
-------
TABLE 3.4-3
MODULE EMISSIONS
GAS PRODUCTION AND PROCESSING MODULE
Process
Gas
Pollutant Well Compressor
Particulates Neg.
S02 7.68
^ NOX 31.20
t_n
T3 HC 0.02
CO Neg .
Triethylene Glycol
Atmospheric
Acid Gas
Removal
Unit
0.018
0.0006
0.120
0.003
0.017
Emissions (Ib/day)
Glycol
Dehydration
0.009
0.0003
0.058
0.001
0.008
0.480
Refrigerated
Absorption
0.063
0.002
C.042
0.010
0.060
Flare
0.010
14.784
0.062
0.004
0.011
1. Emission factor modified to include higher sulfur content present in the fuel gas.
2. Emission factor modified to include sulfur coming from Glaus plant tail gas.
-------
TABLE 3.4-4
EMISSION FACTORS! FOR GAS PRODUCTION MODULE
Emissions: Ib/million scf of natural gas burned
Pollutant
Gas Well
Compressor
Glycol, Girbitol
and
Absorption Units
Plant
Flare
Particulates
SO 2
NOX
HC
CO
Neg.
510*
_ Jt
1.2
Neg.
18
0.6
120
3
17
19
28,000^
120
8
20
1. Source: EN-071
2. Based on sulfur content in fuel gas of 0.30 vol. percent.
3. Based on known amount of H2S entering flare from Glaus unit
4. See Figure 3.4-2.
-153-
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100
10
2
0.1
0.01
10
45.4
4.54
0.454
0.0454
100 1.000
LOAD ON ENGINE, horsepower
10.00454
10.000
FIGURE 3.4-2 NITROGEN OXIDES EMISSIONS FROM STATIONARY
INTERNAL COMBUSTION ENGINES
SOURCE: (EN-071)
-154-
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power requirements depend upon pipe lengths and pressure
differences in the gathering system. A load of 125 horsepower
is assumed for assessment purposes in this module.
Emissions from the combustion of natural gas for the
glycol unit, Girbitol unit, and refrigerated absorption unit
were estimated using EPA emission factors for small industrial
boilers (EN-071). These factors are also shown in Table 3.4-4.
The amount of triethylene glycol emitted to the
atmosphere from the dehydration unit is reported to be 0.1
gallons per million cubic feet of gas processed (PR-052).
Sulfur stockpiles recovered from the Glaus plant
are a potential source of air pollution at gas processing
plants. Potential dust emissions can be significantly reduced
by pouring the sulfur into huge blocks for storage. An alter-
native method of stockpiling involves forming small pellets or
chunks of sulfur and allowing these to harden separately.
These techniques can reduce emissions expected for the solid
mound method of stockpiling by as much as 7070 (TR-024) .
Flaring of natural gas at processing plants releases
some atmospheric pollutants. Flare losses estimated to be 0.11
percent of the gas processed have been reported (PR-075).
Emission factors for domestic and commercial heating units are
used (EN-071). It is also assumed that the tail gas from the
Glaus sulfur plant is sent to the flare.
-155-
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3.5 Transportation Modules
This section contains atmospheric emissions data from
specific representative energy transportation facilities. The
energy resources considered are coal, crude oil, and natural gas.
3.5.1 Coal Transportation Modules
Three forms of transportation are considered for the
movement of coal. The following sections deal with atmospheric
emissions from rail, barge, and slurry pipeline facilities used
in coal transportation.
Coal Rail Transport Module
The tonnage of coal transported over the railways
amounts to approximately 72 percent of the nation's annual coal
shipments. Over half of the coal is transported by means of
unit trains. These are rail facilities dedicated exclusively
to coal transport. This module is based on the unit train
concept.
Module Basis
This module is based on the operation of a 126 car
unit train which supplies 12,600 tons of coal per trip to a
power plant. The round trip covers 612 miles in a 48 hour
period. A summary of the atmospheric emissions from this module
is given in Table 3.5-1.
-156-
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TABLE 3.5-1
SUMMARY OF ATMOSPHERIC EMISSIONS
Rail Transport of Coal Module
Basis: 12,600 Tons of Coal Transported Per Trip
Air Emissions
Pollutant Ibs/day
Particulates, in transit 380
S02 . 860
N0x 5,350
HC 2,480
CO 1,030
Particulates, during
unloading 5,040 Ibs/trip
-157-
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Module Description
Coal is loaded on the unit train at the mine site.
After loading is completed, the cars are switched to nine 3,000-
horsepower diesel locomotives for transportation to the power
plant stockpile 306 miles away. These locomotives are of the
2-stroke supercharged road variety which are most often used
for this type operation. Upon arrival at the destination, the
coal is unloaded from the cars through bottom gates.
After the unloading operations are completed, the
train returns over the same track to the mine for another load.
The total elapsed time from leaving the mine full to returning
empty is 48 hours (EN-071).
Module Atmospheric Emissions
The atmospheric emissions associated with transporting
coal result from the diesel fuel burned by the locomotives and the
dust lost in transit and during loading and unloading of the
coal. The diesel emissions are estimated by using work output
and fuel-based emission factors (EN-071). These factors are
shown in Tables 3.5-2 and 3.5-3.
The work output of the unit train is calculated from
the equation:
w = 1 x p x h
-158-
-------
TABLE 3.5-2
WORK OUT-PUT - BASED LOCOMOTIVE EMISSION FACTORS (EN-071)
Pollutant Emission Factor (grams/hp-hr)
CO 1.8
HC 4.0
NO. 9.4
TABLE 3.5-3
FUEL - BASED LOCOMOTIVE EMISSION FACTORS (EN-071)
Pollutant Emission Factor (lb/103 gallons)
Particulates 25
S0?. 57
Aldehydes
Organic Acids
(1) Based on a sulfur content of 0.4 percent in the diesel fuel
(EN-071).
-159-
-------
where:
w = work output (horsepower hours)
1 = load factor (average power produced during
operation divided by available power)
p = available horsepower ..
h = hours of usage at load factor (1).
Using the average load factor of 0.4, the work output
for the 612 mile round trip is 518,400 hp-hrs. The emissions
calculated from the work-output based factors are:
Pollutant Emissions (lb/round trip)
CO 2,060
HC 4,570
NO 10,700
x
Since the work-output emission factors do not include
the other four pollutants (particulates, S02, aldehydes, and
organic acids) emitted from diesel trains, the fuel-based
emission factors are used to estimate these emissions. For an
average load factor of 0.4, the fuel consumption for a 3,000 hp
locomotive is 70 gallons/hr (WH-036).
The total fuel required for the nine locomotives on
the round trip is 30,200 gallons of diesel fuel. The resulting
estimated emissions are:
Emissions
Pollutant Ibs/round trip
Particulates 760
S02 1,720
Aldehydes 170
Organic Acids 210
-160-
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Aldehydes and organic acid emissions are considered as part of
the total hydrocarbons group.
Besides emissions from diesel combustion, the other
potential source of air emissions within this module is the
discharge of coal dust particulates in transit, and during
loading and unloading operations. Reported emission factors for
unloading operations were based on similar operations at a
metallurgical coke manufacturing plant (EN-071). The particu-
late emission factor is 0.4 Ibs per ton of coal unloaded.
Estimates on the atmospheric discharge of particulates
from loading or in transit were not available. A negative
pressure hood vented into a bagfilter is assumed to be used at
the loading facility. The hood, located just above the loadout
chute, is assumed to reduce emissions to a negligible amount.
Once the coal is loaded into the unit cars it is coated with a
chemical spray. While the extent of its application to coal
trains is unknown, the spray is designed to eliminate windage
losses of fines in the transport of the coal.
The unloading losses amount to 5,040 pounds. Since
this atmospheric emission is not a function of the distance
traveled or elapsed time, it is presented in Table 3.5-1
separately.
Coal Barge Transport Module
Coal barges accounted for some 27% of long-distance
coal movements in the United States in 1973. The usual manner
of hauling is by a diesel-powered tug powering a number of
barges. A typical system is described in the following para-
graphs .
-161-
-------
Module Basis
This module is based on barge transportation of
20,000 tons of coal. This amount represents an average shipping
haul for coal transported on inland waterways via barge. Table
3.5-4 summarizes, the atmospheric emissions from this module.
„
This module is not based on a round trip since the tow-
boats used are not generally owned by the company using the coal
and so are not bound to a set schedule such as the unit train.
Module Descriptions
The coal is loaded on barges at a loading site along
the river. Ten barges are required for 20,000 tons of coal.
Once the barges are loaded and lashed together, a towboat with
a 6,000 hp diesel fired power plant delivers the coal to its
destination.
The average speed of the tugboat and barge system is
6 mph. The tug travels an average of 144 miles per day. Upon
arrival at the destination, the tug maneuvers the barges to
dock and returns to the coal shipping port with a load of empty
barges.
Moduie Atmospheric Emissionb
The only air emissions from this module result from
the combustion of diesel fuel in the towboats. The American
Waterways Operators (AM-115) estimate the energy requirement
for inland barge freight to be 500 Btu per ton mile. Thus, the
average daily fuel consumption for a towboat burning 138,000
Btu/gal, diesel fuel is 10,400 gallons per day.
-162-
-------
TABLE 3.5-4
SUMMARY OF ATMOSPHERIC EMISSIONS
Barge Transport of Coal Module
Basis: 20,000 tons of coal
Air Emissions
Ibs/day
Particulates 135
S02(1) 280
NOX 3,850
HC 447
CO 2,340
(1) Based on a diesel fuel sulfur content of 0.2 wt percent
SOURCE: (EN-071)
-163-
-------
By using the emission factors for heavy-duty diesel-
powered vehicles, air emissions from this module are determined
(EN-071). These emission factors are shown in Table 3.5-5.
Coal Slurry Pipeline Transport
Currently, only one coal-s.lurry pipeline is operating
in the United States (CO-244). It is owned by the Southern
Pacific Railroad. The pipeline runs 273 miles from Peabody
Coal Company's Kayenta mine in Arizona to Southern California
Edison's Mohave power plant near Las Vegas. The 18-inch line
can handle 5 million tons of coal per year and provides fuel for
1,200 Mw of power generation.
Pipeline pump stations are located 60 to 100 miles
apart. The Mohave line has electrically powered pump stations.
It is anticipated that future coal-slurry pipelines will also
be powered by electrical pump stations. No air emissions are
directly attributed to the transfer of coal by slurry pipeline;
however, greater emissions do occur at the end-use facility
during and after drying because of fines produced during the
slurry transfer.
-164-
-------
TABLE 3.5-5
EMISSION FACTORS FOR HEAVY-DUTY.
DIESEL POWERED VEHICLES
Emission Factor
Pollutant lb/103 gal Diesel Fuel
Particulates 13
S02(1) 27
NO 370
HC (2) 43
CO 225
(1) Based on a diesel fuel sulfur content of 0.2 wt percent (EN-071)
(2) Emission factor includes aldehydes and organic acids.
-165-
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3.5.2 Oil Transportation Modules
The following sub-sections contain discussions on
emissions from crude oil transportation by pipeline, tanker and
rail.
Oil Pipeline Transport Module
Pipelines are the most important present method of
crude oil movement in terms of volume moved, accounting for
some 77 percent. A typical trunkline system for movement of
crude to refineries is described in this section.
Module Basis
The basis for this module is a 48-inch pipeline which
transports 1,000 barrels per minute of crude oil. Atmospheric
emissions resulting from the transportation of this crude via
pipeline are presented in Table 3.5-6.
Module Description
i
In the petroleum industry, three basic types of pipe-
line systems are used: the gathering pipeline system, the
trunkline system, and the distribution system. The gathering
pipeline system transports crude oil from individual oil wells
and other production units to a main location. The trunkline
system transports crude oil from a main location to a processing
facility or refinery. The distribution system transports the
refinery products to process plants, power plants, and to other
forms of transportation such as tankers or barges. Of these
pipeline systems, the trunkline system is of interest in this
study.
-166-
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TABLE 3.5-6
SUMMARY OF ATMOSPHERIC EMISSIONS
Crude Oil Pipeline Transportation Module
Basis: 1,000 Bbl/minute of crude oil
Air Emissions
Ib/day
Particulates 984
S02(1) 2,040
N0v 28,000
x
(2)
HC ^' 3,250
CO 17,000
(1) Based on sulfur content in fuel of 0.2%(EN-071) .
(2) The total hydrocarbon emissions include aldehydes and organic
acids.
-167-
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A crude pipeline system consists of pipes and pump
stations. For this module, a 48-inch pipe is chosen and.the
throughput is determined using nominal, generalized economic
flow rate correlations. The pipeline spans a 200-mile distance
and requires two pump stations, one at the beginning of the
pipeline and one at the halfway point. These stations are
powered by large internal combustion diesel engines. The
engines require one gallon of diesel for 500 cargo ton-miles of
oil transported (RI-063).
Module Atmospheric Emissions
The air emissions resulting from the transmission of oil
by pipeline occur from the diesel fuel combusted in the booster
stations. For a 48-inch pipeline transporting 42,000 gallons
per minute of oil over a 200-mile distance, the fuel require-
ment to the booster stations is 75,700 gallons per day.
The air emissions are calculated using EPA emission
factors for heavy-duty, diesel-powered vehicles. These emission
factors are given in Table 3.5-5.
-.
Oil•Tanker Transport Module
About 22 percent of the crude deliveries to oil refin-
eries was moved by water transportation in 1970. That fraction
is tending to increase. A typical water transportation system
for crude oil is described in this section.
Module Basis
The module is based on a crude oil tanker with a
capacity of 825,000 barrels of oil. The tanker is assumed to
-168-
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deliver its cargo to one point where the oil is removed entirely.
Atmospheric emissions from the tanker while "in-transit" and
"in-berth" are summarized in Tables 3.5-7 and 3.5-8.
Module Description
Oil tankers are large vessels especially constructed
to carry petroleum products in bulk. The oil is pumped aboard
by shore pumps through pipelines connected to the internal
piping of the tanker and is stored in the cargo holds, separated
by bulkheads into a series of tanks. The crude oil is discharged
by the reverse process with the ship's pumps furnishing the
power to move the oil through pipelines into storage tanks
ashore. Pumps and lines are sized to keep loading and unloading
times to a minimum.
For this module, a tanker with an 825,000 barrel
capacity is used to transport oil from the Middle East to North
America over a 12,000 mile distance. The ship's average speed
is 20 mph. It is powered by an oil-fired boiler which generates
steam for the steam turbines. The tanker loads and unloads at a
rate of 40,000 bbl/hr.
Module Atmospheric Emissions
Air emissions from the tanker are the result of hydro-
carbon evaporation from the storage tanks and combustion products
from the oil used as fuel.
The following factors are used in estimating hydro-
carbon losses while in-transit and from loading and unloading
of the tanker (EN-071).
-169-
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TABLE 3.5-7
SUMMARY OF ATMOSPHERIC EMISSIONS
Crude Oil Tanker While In-Transit
Basis: 825,000 bbl of crude oil/trip
Air Emissions
Ib/day
Particulates 190
1,700
2,200
5,400
CO Neg
S02 1,700(1)
HC 15,400(2)
(1) Assuming fuel oil sulfur content of 0.5% (EN-071).
(2) The total hydrocarbon emissions include the aldehydes emitted.
-170-
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TABLE 3.5-8
SUMMARY OF ATMOSPHERIC EMISSIONS
Crude Oil Tanker While In-Berth
Basis: 825,000 bbl of crude oil
Air Emissions
Ib/day
Particulates 15
S02 152
NOX 200
HC (loading berth) 90,100^2)
HC (unloading berth) 80,000(2)
CO Neg.
(1) Assuming fuel oil sulfur content of 0.5% (EN-071).
(2) The total hydrocarbon emissions include the aldehydes emitted,
-171-
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loading loss, 2.6 Ibs hydrocarbon per
1000 gallons transferred,
unloading loss, 2.3 Ibs hydrocarbon
per 1000 gallons,
transit loss 3.1 Ibs per 1000 gallons of
oil per week
Those emissions resulting from the oil burned in the
boilers are (EN-071):
Emission Factors
Pollutant
Particulate
d)
d)
SO 2
SO 3
CO
HC
N0x
Aldehydes
In-Transit
Ib/mile
0.4
7S
0.1S
0.002
0.20
4.6
0.04
In-Berth
Ib/day
15
300S
4S
0.08
9
200
2
= weight percent sulfur in the fuel; assumed to be 0.5
percent for diesel fuel (EN-071).
Emissions for the tanker while in-transit are calcu-
lated knowing the 12,000 mile distance that the tanker travels.
Approximately 25 days are required for the tanker to cover this
distance. The loading and unloading rate for the crude oil to
and from the tanker is 40,000 bbl/hr. Therefore, the tanker is
at a terminal for approximately 21 hours for loading and 21 hours
for unloading.
-172-
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Oil Rail Transport Module
Less than one percent of the crude oil movement in the
United States is by rail. This is due primarily to the higher
transportation cost of railway versus pipeline transport. The
following sections investigate the atmospheric emissions ex-
pected from a typical size movement of crude oil by rail.
Module Basis
The module is based upon a train transporting 1,000,000
gallons of crude oil on a 24-hour trip, one way, as a typical
transportation mode for crude oil by rail. The atmospheric
emissions resulting from this module are summarized in Table
3.5-9.
Module Description
At a crude oil terminal, the tank cars are loaded for
shipment to a refinery. The oil is loaded through the top of
the cars and free-falls into the tank compartment. After load-
ing the 50 cars with 20,000 gallons of crude oil each, they are
switched over to road-haul locomotives for the trip. Three
3,000 horsepower 2-stroke super charged road locomotives are
needed to power the train assuming 1.5 horsepower per trailing
ton is required (GE-050).
After the 24-hour trip, the cars are uncoupled from
the locomotives at the refinery and unloaded. Since neither
the locomotives nor the cars are generally owned by the oil
company, and thus do not follow a set schedule of transporting
oil, one-way only trips are considered in this module.
-173-
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TABLE 3.5-9
SUMMARY OF ATMOSPHERIC EMISSIONS
CRUDE OIL RAIL TRANSPORTATION-MODULE
Basis: 1,000,000 gallons of oil.(one-way trip for locomotives)
Air Emissions
Ib/day
Particulates
SO 2
N0x
CO
Hydrocarbons (from locomotives)^1'
Hydrocarbons (from loading operations)
Hydrocarbons (from unloading operations)
230
530
3,670
700
1,680
10,600 Ibs/trip
2,000 Ibs/trip
d)
Total hydrocarbon emission from the locomotives include
aldehydes and organic acids.
-174-
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Module Atmospheric Emissions
Atmospheric emissions resulting from the transportation
of crude oil by rail are hydrocarbon evaporation losses and
combustion products from diesel fuel combustion.
Estimates for the amount of hydrocarbons lost during
loading and unloading operations have been reported (EN-071).
Transit hydrocarbon emissions are considered negligible for any
trip shorter than two days (EN-071). The emission factor for
top loading of the oil into the tank car compartment is 10.6 Ibs
of hydrocarbons per 1000 gallons transferred. The unloading
losses are 2.0 Ibs per 1000 gallons transferred. Since these
losses are independent of the length of time of a trip, they
are presented separately in the summary of the module's emis-
sions.
There are also emissions from the three locomotives
powering the train. These emissions are estimated using
emission factors shown in Tables 3.5-2 and 3.5-3 (EN-071).
The total locomotive horsepower output is 177,000
hp-hours. The diesel fuel consumption rate is 130 gallons
per hour for one locomotive operating at a load factor of 0.82
(WH-036). The total fuel consumed for a 24 hour period is
9,360 gallons.
-175-
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3.5.3 Gas Transportation Module
Pipeline movement is the only method used to move
natural gas to major markets and to local distribution facilities
A typical large gas transmission pipeline facility is described
in this section.
Module Basis
This module is based on a 30-inch diameter pipeline
with a gas throughput of 80.2 MM scfd. A summary of atmospheric
emissions from the pipeline transportation of gas is presented
in Table 3.5-10.
Module Description
Current gas pipelines range from 24- to 42-inch
diameter systems (ST-204, VA-093). This module deals with the
air emissions associated with natural gas transmission in a 30-
inch diameter system. Emissions are primarily from gas engines
used to power the compressors in the booster stations. The
stations are located 50 miles apart.
Module Atmospheric Emissions
The EPA emission factor book (EN-071) estimates the
only significant pollutant from booster compressor-dirven
engines is NO . NO is released at a rate of 7,300 Ibs per mil-
X X
lion scf of natural gas combusted. For a typical gas pipeline,
an average of 3.3% of the gas transported is combusted to drive
the gas line booster compressors. Some fugitive hydrocarbons
may potentially be emitted from any leaks around flanges,
compressor seals, and valve stems if poor maintenance practices
are observed; however, these emissions are considered to be
negligible for this module.
-176-
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TABLE 3.5-10
SUMMARY OF ATMOSPHERIC EMISSIONS
Natural Gas Pipeline Transportation Module
Basis: 80.2 MM scfd transported
Air Emissions
IbVday
Particulates Neg.
S02 Neg.
N0x 19,320
HC Neg.
CO Neg.
-177-
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3.6 Comparison of Module Emissions
In the previous subsections the .emission rates are
related to the specific module.charge capacity. This approach
is used to present, in a convenient, manner, the emission impact
of plant sizes typical of each industry and hence to facilitate
the environmental assessment of each.
In this subsection all of the modules are adjusted to
a 1012 Btu/day output of primary product. This is done in order
to present the different module emissions on a common basis and to
provide a useful comparison of the emission impact of the various
technologies.
The comparison of emissions from extraction modules
is presented in Table 3.6-1. ' The large CO emissions associated
with oil well production come primarily from diesel-powered
equipment used in water flooding. Gas production operations
have substantial NO emissions from gas compressors. Large
JC
hydrocarbon fugitive emissions are also reported at gas produc-
tion facilities (BA-234).
Two'sets of emissions from coal strip mining compared
emissions with and without physical coal cleaning operations.
The added impact of burning refuse piles is shown in the room
and pillar coal mining data. The large hydrocarbon emissions
associated with room and pillar mining are based on an assumed
methane production rate during the mining operation of 200 cubic
ft per ton of coal mined (DE-148). Emissions from the in-situ
coal production module are based on fugitive fuel gas losses at
the producing well site.
-178-
-------
The emissions from surface mining of the oil shale
are mainly due to fugitive losses and diesel fuel combustion.
The room and pillar oil shale module has essentially the same
type emissions. Because of thermal drying operations used in
the coal production module, it is difficult to compare the room
and pillar mining operations for coal and oil shale.
Transportation modules are compared in Table 3.6-2.
No atmospheric emissions are directly attributed to coal trans-
portation by slurry pipeline; however, considerable emissions
may occur at the end-use drying facility because of fines
produced in the pipeline. Hydrocarbon emissions associated
with rail transportation of oil are primarily fugitive losses
during loading and unloading. The differences involved with
the sets of emissions for oil tanker in-transit and in-berth
operations are the result of larger power requirements in-transit
(diesel fuel combustion), but fugitive hydrocarbon losses are
greater in-berth. NO emissions associated with pipeline trans-
A.
portation of gas are from gas compressors.
-179-
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TABLE 3.6-1
COMPARISON OF EMISSIONS FROM EXTRACTION MODULES
Basis: 10'2Btu/Day Fuel Output
Air Emissions. Ib/day
Coal Mining
Oil Shale Mining
00
o
1
Pollutant
Particulars
SO,
CO
NO,
Hydrocarbons
Strip
11.900
273
2.290
3.740
432
(11
(15,200)
( 8,730)
( 2.610)
( 7.870)
( 568)
Room and
6,190
8,530
562
4,560
352,000
Pillar [2]
(84,000)
(125,000)
(233,000)
( 42,900)
(391,000)
In-Sltu [31
5,500
NA
30,000
NA
65,000
.Surfsce [4]
65.200
1.680
14.100
23.100
2.620
Room and
Pillar [5]
1
•13.100
39.3
335
550
64.2
In-Sltu [61
107.000
239.000
414.000
12.400
48.000
Oil Well
Production [7]
1.130
12.910
8.290
20.400
21,300
Cat Wtll
Productlcn_m
200
44,900 •
200
'63.000
273.000
(1] Adjusted fro* 6,300 TPD run-of-nine coal (12.000 Btu/lb). Emissions In parentheses include emissions Croat physical coal cleaning.
(2) Adjusted from 6,300 TPD run-of-ninc coal (12.000 Btu/lb). Mining emission valuee include eoleclons from physical coal cleaning. Calssiooa
in parentheses include emissions tron burning refuse piles.
[3] Adjusted fro.-a 10'Btu/day fuel gas produced. Data on SO and NO emissions were hoe available.
[4] Adjusted from SO.000 bbl/day of upgraded shale oil capacity (5.6*x 10(Dtu/bbl).
[S] Adjusted front 50,000 bbl/day of upgraded shale oil capacity (5.6 x 10*Bcu/bbl).
[6] Adjusted froa 50.COO bbl/day of upgraded shale oil capacity (5.6 x 10'fitu/bbl).
[7] Values adjusted froa aodule producing 1,000 BPO crude oil (5.6 x lO'Btu/bbl), aasuaiog uae of water flooding, heater treater. mad SOZ
brioa content.
[8] Valuea adjusted froa production of 5.0 x lO'sCFD gee (1000 Btu/SCT).
-------
TABLE 3.6-2
COMPARISON 0? EMISSIONS FROM TRANSPORTATION MODULES
Basis: 10I2Bt:u/Day Fuel Oucput
Coal Transportation
?p71n?*.rE.
Particulates
S0x
CO
N0x
Hydrocarbons
Sail [ll
1.260
2.840
3.410
17.700
8,200
32TJTC (2)
281
583
4.880
8.020
931
Slurry
Pipeline [3!
Negligible
Negligible
Negligible
Negligible
Negligible
Air Emissions, Ib/day
Rail Tar.kar
Transportation Transportation of Oil [5]
of Oil [4] In-Transit Loading Unloading
1,730
3,980
5,250
27,500
107,000
40
370
Ncg.
480
3,300
3
30
Neg.
40
18,000
3
30
Ncg.
40
16,000
Pipeline Pipeline
Transportation Transportation
of Oil f6) of Gas [7j
122
253
2.110
3,470
403
Negligible
Negligible
Negligible
241.000
Negligible
II] Adjusted froa 12,600 Cons of coal transported (12.000 Btu/lb).
[2] Adjusted fro=i 20,COO TFD coal transported (12,000 Btu/lb).
[2] A slurry pipeline powered by electrically driven punp stations should have negligible atmospheric emissions directly associated
with tho pipeline.
14] Adj-jsrci from IG'gal/day oil transported (5.6 x 106 Btu/bbl).
[5] Adjusted froa transportation of 825,000 3P3 oil (5.6 x 106Btu/bbl)
[s] Adjusted from transportation of 42,000g?a oil (5.6 x 106Bcu/bbl).
[7] Adjusted from transportation of 80.2 XKSCFD pipeline gas (1000 Btu/SCF).
i
M
CO
M
I
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4.0 MONITORING TECHNOLOGY
Monitoring is normally classified- as either source
or ambient. Source monitoring .typically involves measuring
,•
both the concentration and flow rate .in an exit stream to
determine the total amount of a particular species emitted.
Ambient monitoring generally involves measurement of the
concentration of a species at a remote point where it has
been diluted by mixing.
Monitoring may be either continuous or intermittent.
Ambient monitoring is generally performed on a continuous basis
since the regulations are written in terms of the maximum allow-
able average concentration over a particular time interval and
since the dilution of a species depends on mixing conditions
which are difficult to predict with any certainty. Without
continuous monitoring, there is little assurance that the
maximum levels actually are detected.
In source monitoring, the concentrations do not vary so
widely or so rapidly, and maximums may sometimes be predicted
as a consequence of changes in operating parameters (such as
fuels). Regulations often are expressed in terms of allowable
emissions as a function of weight or heat content of the feed-
stock. Because of this, source monitoring has tended to be of
the intermittent type in the past, although continuous source
monitoring is now required for some pollutant species in some
industries.
Whether ambient or source, monitoring methods can be
divided into several categories. These include manual labora-
tory methods, automated laboratory methods, manual field methods,
and automated field methods.
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The impetus for monitoring is normally provided through
a requirement to demonstrate compliance with Federal and/or state
regulations. For many species these regulations include both
source and ambient limits.
Most regulations designate a particular analysis proce-
dure as the standard or "reference" method for a given species.
These reference procedures have tended to be of the manual labora-
tory type since this type of analysis has historically provided
the greatest confidence level in the results. This is probably
because the basic standards in this type work are normally chemi-
cals of reliable purity whereas the standards used in manual or
automatic field methods are often derived from a reference gas
which may be questionable because its concentration is dependent
on certain temperatures or flow rates in a calibration unit.
Field methods do have the advantage that they provide real time
analysis whereas laboratory methods require the collection of
a sample which must then be stabilized or preserved in some
manner to keep it from changing in composition during transport
to the laboratory.
The emissions from the various modules associated
with production, processing, and transportation of coal, oil,
and gas have all been described in earlier sections. These
were described largely in terms of the criteria pollutants
plus a few species such as aldehydes and organic acids.
Both ambient and source monitoring methods are discussed
in this section. A brief review of the Federal regulatory frame-
work will be provided where applicable.
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4.1 Ambient Air Quality Monitoring
4.1.1 Background
For ambient air quality, Federal regulations have estab-
listed certain criteria pollutants, namely, nitrogen dioxide
(N02), sulfur dioxide (S02), carbon monoxide (CO), photochemical
oxidants (03), particulates, and non-methane hydrocarbons (NMHC).
Both primary standards (to safeguard human health) and secondary
standards (to prevent damage to clothes, buildings, plants, ani-
mals, etc.) have been established. The averaging time varies
for different species, with short term averages generally ex-
pressed as "not to be exceeded more than once per year". The
actual regulations are quite lengthy, and are described in the
Federal Register, Volume 36, No. 228, page 22384 and later modi-
fied slightly in Federal Register, Volume 38, No. 178, page 25678.
A summary is provided in Table 4.1-1. It should be noted that all
measurements are to be corrected to reference conditions of 25°C
and 760 mm Hg.
The various states have established their own ambient
air quality regulations, and in many cases they have different
averaging periods and/or more stringent limits than Federal regu-
lations. Due to their wide variety these will not be considered
here, but it is noteworthy that many include regulations on
hydrogen sulfide (H:S).
In addition to specifying limits on the criteria pollu-
tants, the Federal government has also established reference
methods for their analysis. These procedures for particulates,
total oxidants, nitrogen dioxide, and sulfur dioxide are outlined
in Federal Register, Volume 36, No. 84, Part II, April 30, 1971.
For non-methane hydrocarbons, the procedure is defined in Federal
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TABLE 4.1-
SUMMARY OF AMBIENT AIR STANDARDS
All numbers in mi crograms/ cubic meter (yg/m3)
Pollutant
SO 2
Particulate
CO
Total Oxidant
Non-Methane HC
Averaging
Time
Annual
24 hour*
3 hour*
Annual
24 hour*
8 hour*
1 hour*
1 hour*
3 hour*
Primary
Standard
80
365
-
75
260
10,000
40,000
160
160
Secondary
Standard
.
-
1,300
60
150
10,000
40,000
160
160
(6-9 AM)
NO 2
Annual
100
100
*Not to be exceeded more than once per year.
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Register, Volume 36, No. 228, page 22394. Because some of these
procedures are inconvenient for continuous field monitoring, and.
because many other types of analyzers are presently being used
for field monitoring, certain mechanisms have been defined whereby
other analysis procedures may be designated as reference or equi-
valent methods. These mechanisms are outlined in Federal Register,
Volume 40, No. 33, page 7042, 1975. Because many types of in-
struments are currently under evaluation as reference or equiva-
lent methods, it is not possible at this time to specify which
monitoring methods will be acceptable.
4.1.2 General Monitoring Considerations
One of the most difficult areas in ambient air monitor-
ing is the siting of the various monitors. This is especially
true when the purpose of the monitoring is to evaluate the impact
of a particular source. This is typically done based on dispersion
modeling which utilizes historical meteorological data plus data
regarding the source to predict the location of maximum pollutant
concentrations for annual and short term averages. The Environ-
mental Protection Agency has recently undertaken several studies
on optimum siting criteria for several pollutants.
For the reference procedures defined in the Federal
Register, the accuracy of the analysis is given, and it is ex-
pected that any new reference or equivalent methods will be of
equal or greater accuracy. For S02 analysis by the reference
method, the relative standard deviation at the 95 percent con-
fidence level is 4.6 percent. For total oxidants the accuracy
is given as ±7 percent. For carbon monoxide an accuracy of ±1
percent of full scale is given (full scale normally is 58 milli-
grams per cubic meter). The accuracy of particulate analysis
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is given as ±50 percent, and for non-methane hydrocarbons the
accuracy is 2 percent of full scale.
Costs are difficult to assess on a per sample basis
for continuous analysis. Instrument costs are in the following
ranges; however, multicomponent analyzers may be even higher.
Pollutant Thousands of Dollars
S02 4-8
N02 4-8
Ozone 3-5
NMHC 5-10
CO 3-10
Particulates 0.5-15
In some cases a calibration unit costing several thousand dollars
may be required to accomplish a multi-point calibration. In
addition, some type of temperature-controlled shelter is required,
as is a data recording system. Finally, processing the data will
require manpower and/or additional hardware. It can be seen that
actual monitoring costs will depend on availability of facilities
and manpower, and will be different in almost every case. Many
companies now offer an ambient air monitoring service in which
they assume total responsibility for all instrument operation
and data processing, and provide a summary report to the client
on a regular basis.
The most commonly used nitrogen oxide monitors employ
the chemiluminescent technique. This method is specific for
nitric oxide, so nitrogen dioxide must be converted to nitric
oxide prior to its analysis. By obtaining a nitric oxide measure-
ment with and without conversion of nitrogen dioxide, the nitro-
gen dioxide concentration can be obtained by difference. Other
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popular methods for measuring nitrogen oxides include electro-
chemical analyzers, second derivative spectroscopy, bubblers and
colorimetric analyzers, and membrane-electrochemical analyzers
(IN-056).
Sulfur dioxide and hydrogen sulfide are most commonly
measured with flame photometric analyzers. These detectors act-
ually respond to the total sulfur content of a molecule; there-
fore, selectivity scrubbers are installed on the inlet to re-
move all sulfur species but the one of interest. Other analysis
methods for S02 include electrochemical analyzers (membrane and
non-membrane), pulsed fluorescent analyzers, second derivative
spectroscopy analyzers, and colorimetry (IN-056). Both S02 and
H2S can be measured with gas chromatographic analyzers using
flame photometric detectors. Other sulfur species such as
COS, CS2 and CSH compounds can also be measured by this technique.
The most commonly used method for continuous ozone
analysis is the chemiluminescent technique, in which ozone is
reacted with ethylene or in some cases with Rhodamine-B. Other
methods include ultraviolet absorption, electrochemical analyzers,
second derivative spectroscopic analyzers, and wet chemistry bubblers
Carbon monoxide is normally measured with either infra-
red analyzers or gas chromatographs which convert the CO to CHi,
and measure it via a flame ionization detector. Electrochemical
analyzers for CO also are available.
Hydrocarbons are most commonly measured using chromato-
graphic separation of the methane, detection via a flame ioniza-
tion detector, and determination of non-methane hydrocarbons
as the difference between total hydrocarbons and methane (IN-056).
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Continuous analyzers are now available which separate the hydro-
carbons into methane, ethylene, acetylene, and total hydrocarbons.
To obtain a more detailed analysis, a manually operated gas chroma-
tographic system or gas chromatograph - mass spectrescopy combina-
tion is required. This may be achieved by collecting bag samples
and taking them to the laboratory or by installing an instrument
in a field site. Continuous analysis of this sort is difficult
since some concentration of the sample is normally required.
Aldehydes and organic acids are detected by the flame
ionization detectors in regular environmental chromatographs. In
the results, however, they are lumped into the non-methane hydro-
carbons. These species can be detected using bag samples and
laboratory chromatographs or with pulse polarographs.
Particulates are most commonly determined using the
EPA High Volume sampler. A weighed filter is exposed to a
measured flow of air for 24 hours, then reweighed. Average
particulate mass per unit volume for the 24 hour period is obtained.
Other samplers based on mass measurement using beta particles
have become available in recent years. These systems can be
programmed to measure for much shorter time periods than 24 hours.
Samples collected with particulate analyzers can be
subjected to a detailed analysis for content of various trace
elements. The most popular methods for trace element analysis
are *-ray fluorescence, atomic absorption, spark source mass
spectrometry, and neutron activation analysis; however, these
are typically performed in a laboratory and not under real time,
continuous conditions.
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4.2 Source Monitoring for Air
4.2.1 Background
Federal regulations' for source emissions have been
established on an industry by industry basis, and generally are
for new or modified sources only. Many states also have
established emission regulations for various industries;
however, the variety of these is too great and changes too
rapid to be covered in this discussion.
New Source Performance Standards have been proposed
for coal preparation plants (Federal Register, Volume 39, No.
207, page 37922, 1974). It should be emphasized that these are
proposed rules and not promulgated standards. These rules
apply to thermal dryers, pneumatic coal cleaning equipment,
coal processing and conveying equipment (including breakers and
crushers), screening (classifying) equipment, coal storage and
coal transfer points, and coal loading facilities. The proposed
rules are applicable to new or modified sources and hot to
existing sources. A summary of the limits is provided in Table
4.2-1.
Reference Methods have been established for monitoring
emissions from sources. These are as follow:
Method 1 - Sample and Velocity Traverses for
Stationary Sources
Method 2 - Determination of Stack Gas Velocity and
Volumetric Flow Rate
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TABLE 4.2-1
PROPOSED EMISSION LIMITS FOR COAL PREPARATION PLANTS
Thermal Dryers
Pneumatic Coal
Cleaning Equipment
Coal Processing
and Conveying
Coal Storage Systems
Coal Transfer and
Loading Systems
Particulates
0.070 g/dscm*
0.040 g/dscm
Opacity
30%
20%
20%
20%
20%
grams/dry standard cubic meter
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Method 3 - Gas Analysis for Carbon Dioxide, Excess
Air, and Dry Molecular Weight
Method 4 - Determination of Moisture in Stack Gases
Method 5 - Determination of Particulate Emissions from
Stationary Sources
Method 6 - Determination of Sulfur Dioxide Emissions
from Stationary Sources
Method 7 - Determination of Nitrogen Oxides Emissions
from Stationary Sources
Method 8 - Determination of Sulfuric Acid Mist and
Sulfur Dioxide Emissions from Stationary
Sources
Method 9 - Visual Determination of the Opacity of
Emissions from Stationary Sources
Method 10- Determination of Carbon Monoxide Emissions
from Stationary Sources
Method 11- Determination of Hydrogen Sulfide Emissions
from Stationary Sources
Methods 1 through 9 are described in Federal Register,
Volume 36, No. 247, pages 24882-24895. Methods 10 and 11 are
described in Federal Register, Volume 39, No. 47, pages 9319-9323
These reference methods for determining compliance are generally
non-continuous, manual methods.
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The proposed rules for coal preparation plants require
continuous monitoring of temperature of exit gases and pressure
drop through control devices for thermal dryers. The surface
moisture content of product coal from thermal dryers is to be
determined daily using ASTM procedures D2234-72, D2013-72, and
D271-70. EPA methods 1, 2, 3, and 5 are to be used to determine
compliance with the emission limits described earlier. It
should be noted that there is presently some controversy
regarding the methods and significance of opacity determinations.
Interested parties should contact EPA as to the proper procedures.
A report entitled "Processes, Procedures, and Methods
to Control Pollution from Mining Activities" has been prepared
by EPA. Copies are available at the U. S. Government Printing
Office in Washington, D. C.
4.2.2 General Monitoring Procedures
Some of the emissions associated with production,
processing, and transportation of coal, oil, and gas will be
stationary point sources, e.g., thermal dryers for coal. Other
emissions will include stationary area sources, e.g., particulates
from strip mines, and mobile sources such as vehicles and trains.
Each of these different types of sources requires
a different strategy. Mobile source emissions and area source
emissions often must be either monitored using modeling and
ambient air data or estimated using emission factors. Some new
techniques are becoming available for area sources however.
These are basically sensors which provide an integrated signal
over a long path length sampling beam (NA-113).
Monitoring methods for well defined point sources
such as stacks are fairly well established. However, accurate
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source monitoring is more difficult than ambient monitoring.
The gas streams typically are hot, difficult to access, and
the pollutant concentrations may vary as a function of position
in the exit stack. Introduction of standard gases in a mean-
ingful manner often is difficult.
As with ambient monitoring, source monitoring may be
intermittent or continuous, manual or automated. In addition,
continuous monitors can be divided into in-situ and external
systems. The external monitors normally require a sample condi-
tioning system.
As discussed earlier, the reference methods tend to
be of the intermittent manual type. Because of sampling diffi-
culties these tend to be somewhat more expensive than ambient
monitoring. As an example, it has been estimated by EPA that
one particulate analysis using Method 5 will cost from $3,000 to
$10,000 depending on the source, including some 300 man-hours
of effort (Federal Register, Volume 39, No. 47, page 9309). The
Federal Register does not list measurement accuracies for methods
1-11.
The same general instrument types are used for contin-
uous source monitoring as for ambient monitoring. Pollutant
concentrations in stack gases are normally several orders of
magnitude higher than ambient levels so that the instruments
must either be designed for higher levels or dilution systems
must be used. For external monitors, a sample conditioning sys-
tem often is required to provide an air sample suitable for
analysis. This involves filtering out particulates (unless par-
ticulates are being monitored), removing excess water, and pro-
viding for introduction of calibration gases.
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Because sample conditioning systems increase cost and
complexity, and may decrease reliability, several in-situ moni-
tors have been developed. In these systems the detection or
measurement portion is mounted directly in the exit stack. As
with the external monitors, however, calibration is often diffi-
cult. An excellent discussion of external analyzers, in-situ
analyzers, and remote sensors has been provided by Nader (NA-113)
Nitrogen oxides are commonly measured with chemilumi-
nescent analyzers, infrared analyzers, or ultraviolet analyzers.
Sulfur dioxide is measured with ultraviolet analyzers, flame
photometric analyzers, infrared analyzers, or pulsed-fluores-
cence analyzers. Carbon monoxide is most commonly measured with
infrared analyzers. Continuous particulate analyzers utilize
the beta particle detector.
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5.0 EMISSION CONTROL TECHNOLOGY
This section of the report is concerned with emission
controls. In many cases, the controls described are those that
would normally be applied to the emissions estimated for various
modules. In other cases, the controls described are beyond the
current state-of-the-art of development, or are not widely used
in current practice. The degree of application of the control
systems is described. This section is divided into classifica-
tions of control by pollutant type. Particulate emissions'
controls are discussed first, followed by S02, hydrocarbons,
nitrogen oxides, and carbon monoxide. A final subsection deals
with fugitive emissions.
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5 .1 Particulate Control Systems
Particulate pollutants originate from a variety of
sources within the modules presented in Section 3.0, and the
particulate emissions vary widely in physical and chemical
characteristics. Similarly, the available control techniques
vary in type, application, effectiveness, and cost.
The control techniques described herein represent
a broad spectrum of information from many engineering and other
technical fields. The devices, methods, and principles have
been developed and used over many years, and much experience
has been gained in their application. They are the techniques
generally applicable to the broad range of particulate emission
control problems found in the modules of this report.
The proper choice of a method, or combination of methods,
to be applied to any specific source depends on many factors
other than the characteristics of the source itself. While
a certain percentage of control, for example, may be acceptable
for a single source, a much higher degree may be required for the
same source when its emissions combine with those of other sources.
This section is designed to provide a review of the approaches
commonly employed for controlling the sources of particulate
air pollution. It does not review, however, all the possible
combinations of control techniques that might bring about more
extensive control of each individual source.
5.1.1 Sources of Particulate Emissions
Listed within each module presented in Section 3.0
of this report are its potential sources of air emissions.
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The pollutants emitted vary from source to source and module to
module. The following discussion summarizes those specific
sources within the modules which emit particulates as either
a part or all of its pollutants.
Diesel-Fueled Internal Combustion Engines
There are many diesel engines used' in the modules
of this report. The following is a list of the modules which
use diesel equipment and the service that equipment provides:
• Strip Mining Module (coal) - This
module uses diesel trucks for
hauling coal and uses diesel powered
. bulldozers for cleanup and reclama-
tion on the pit.
Room and Pillar Mining Module (coal) -
Diesel trucks haul ash refuse from
the coal preparation plant and a
diesel bulldozer is used at the
refuse dump site.
• Strip Mining Module (Oil Shale) -
Diesel trucks operate below grade
hauling the mined oil shale to a
primary crushing area.
Coal Rail Transportation Module -
Diesel fired locomotives are used.
Coal Barge Transportation Module -
Diesel engines are used to power
the towboats.
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• Oil Rail Transportation Module -
Diesel fired locomotives are used.
Oil Pipeline Transportation Module -
Diesel fueled engines used in the
pump stations.
Oil Production Module - Diesel
fueled engine drives the pump on the
water flooding system.
Boilers and Process Heaters
The boilers and heaters used in the modules discharge
small but measurable amounts of particulates in their flue gases.
The oil production module has a boiler which produces steam for
the secondary recovery system used at the well. This steam
generator burns a fuel oil. The only other boiler used in the
modules is in the transportation of crude oil by tanker. This
boiler also burns fuel oil to supply steam for motive power.
Process heaters are used in both the oil and gas
production modules. The oil production module uses a heater
treater which burns natural gas. In the gas production module,
there are three process heaters used. They all combust natural
gas.
Crushing and Screening
Crushing and screening operations are significant
contributors to particulate emissions. These operations are
used in four modules: (1) coal strip mining, (2) coal room and
pillar mining, (3) oil shale strip mining, and (4) oil shale
room and pillar mining.
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Conveying and Loading of 'Coal and Oil Shale
The mining of coal and oil. shale and the transporta-
tion of coal involves extensive materials handling operations.
Much of the particulate emissions, due to these operations
are considered fugitive dust.losses and are difficult to
quantify. Fugitive losses will be addressed la.t.er in a separate
section. However, where the coal or oil shale is moved by
conveyors and where coal is loaded through a tipple, particulate
emissions can be estimated using EPA emission factors. The
modules where materials conveying and loading are used are (1) the
coal strip mining module (both conveying and loading). (2) the
coal room and pillar mining module (both conveying and loading),
(3) the oil shale strip mining module (conveying only), (4) the
oil shale room and pillar mining module (conveying only), (5) the
coal barge transportation module (loading only), and (6) the coal
rail transportation module (loading only).
Coal Thermal Drver
Both coal mining modules have a coal dryer as part
of their preparation plants. These dryers emit significant
amounts of particulates, which are primarily due to the flul.d-
izing action in the bed of coal being dried.
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Refuse Pile Burning
A solid waste stream is discharged from the coal pre-
paration plants in both of the coal mining modules and is dis-
posed of off site. This waste stream consists of dirt, clay,
rocks, coal, slate, etc. These solids are dumped in a large
refuse pile which may burn.. The products of this combustion
contain significant amounts of particulates.
5.1.2 Control Methods for Particulate Emissions
In this section potential particulate control methods
for the specific sources outlined in the previous section are
identified. Alternative methods for control will also be
discussed and where the information is available, they will be
compared on the basis of (1) the degree of control achievable,
(2) the energy and raw materials required, (3) secondary pol-
lution resulting from the control used, and (4) the capital
and operating costs of the control method.
Diesel-Fueled Engines
Particulate matter emitted by diesel engines consists
primarily of carbon and hydrocarbon aerosols resulting from
incomplete combustion of the fuel. Small amounts of additional
particulate emissions come from aerosols in the vent gases
of the two-stroke-cycle diesel engine (from air box drains)
and from crankcase oil going through the combustion process
unburned.
Federal regulations implemented in 1970 limit
smoke from new diesel engines. The regulations establish a
maximum intensity of smoke emission (measured by reduction in
light transmission) under conditions of severe engine loading.
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No control devices are believed to be needed to reduce the
smoke emissions from diesel engines to meet the established
standards (NA-029). All new engines since. 1970 have been
adjusted by the engine manufacturer to a conservative fuel
rate and power output to insure they meet the regulations.
Even though no control devices are used as such on
diesel engines, several methods can be employed to insure the
lowest possible particulate emissions. As vehicle mileage
increases, proper fuel system adjustment, maintenance at
appropriate intervals, use of the specified type of fuel, and
good operating techniques can maintain low levels of visible
emissions, particularly with respect to particulate carbon.
Boilers and Process Heaters
The boilers and process heaters used in the modules
of this report are fired with either fuel oil or natural gas.
Neither of these sources when properly maintained emit particu*
lates at a rate which would exceed Federal regulations. For
this reason, no particulate control device systems have been
adapted to oil or gas fired heaters or boilers.
However, in keeping the particulate emissions that
do result from them as low as possible, good practices must
be observed. Although improper practices are frequently the
cause of visible particulate emissions, insufficient informa-
tion exists to permit numerical evaluation of their effect on
emission levels (NA-029).
One method of good practice is proper design and
application of the boiler or process heater. These combustion
systems must be properly selected to meet load requirements,
and its individual components should be compatible to avoid
excessive emissions of particulate matter.
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Consideration must be given to load characteristics
when selecting a combustion system. The combustion system should
be able to supply energy at a change in rate consistent with the
demands of the facility without deviation from design limits.
Another technique that should be observed is proper
installation. Properly installed equipment will promote clean,
efficient operation of stationary combustion sources. Compre-
hensive installation instructions and plans are a prerequisite
for proper installation. The designer of the entire combustion
system and the manufacturers of the system's components are
responsible for providing such plans and instructions. Equip-
ment should be installed only by qualified personnel, and all
work should be inspected for quality.
Through proper operation and good maintenance, reduc-
tions in particulate emissions from stationary combustion can be
achieved. Stationary combustion units should be operated within
their design limits at all times and according to the recommen-
dations of either the manufacturer or another authority on
proper operational practices. Combustion units and system
components should be kept in good repair to conform with design
specifications. Sensitive monitoring systems are helpful in
indicating needed combustion system repair.
Another method of control for reducing particulates
from boilers and process heaters is energy substitution. The
particulate emission characteristics of fuels used in combustion
processes may differ widely. Therefore, some measure of control
may be effected by substituting among the various fuels. This
technique has special value for control of many small sources
when the cost of effective gas cleaning would be excessive.
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Of the two boilers used in the modules in Section 3.0,
both are oil-fired. For the boiler on board the oil tanker, the
only feasible energy substitution would be.to use a nuclear
reactor to generate the steam necessary to power the ship.
However, due to the large cost of such a system, nuclear power
is unlikely to be used aboard oil tankers. The other oil-fired
boiler is the one used in the oil production module as a steam
generator for secondary oil recovery. This steam generator could
easily be switched over to burning natural gas or the natural
gas condensate which is produced by the well. Such a change
could reduce particulate emissions by as much as 4070 (NA-029) .
The process heaters used in the natural gas production
module burn natural gas. No alternative energy source which
would emit less particulates could be substituted for the natural
gas.
Crushing and Screening Operations
The crushing and screening of coal and oil shale in
the four mining modules creates a potential particulate emission
problem if left uncontrolled. There are several control tech-
niques currently in commerical use which reduce these emissions.
Those controls which are most often used are (1) gravity collec-
tors (enclosxjres), (2) water sprays with or without chemical
stabilizers, (3) wet scrubbers, (4) mechanical collectors, and
(5) fabric filters.
The gravity collector is simply an enclosure con-
structed around the crusher and screening device which gives
the coarse dust particles a longer time to settle out. Water
sprays wet the coal or oil shale before the material enters
the crushing and screening operations suppressing the dust
-204-
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before it is emitted to the air. When the control system is a
wet scrubber, mechanical collector, or fabric filter, an en-
closure must be built around the crusher and screener. A fan
is then located so that it draws the particulate-laden air from
within the enclosure and blows it into the particular collection
device being used. Clean air is discharged from a vent on the
control system.
Table 5.1-1 compares these alternative control methods
in terms of the degree of control achievable, energy and raw
materials required, and secondary pollution resulting from the
control units. It should be noted that the fabric filter
possesses the potential for reducing the particulate emissions
from crushing and screening to near zero discharge.
Conveying and Loading
During the conveying of coal and oil shale and during
the loading of coal onto unit trains for shipment, a potential
particulate emission problem exists. More specifically, the
points of dust discharge for conveying is at the tail pulley,
where oil shale or coal is received from prior equipment, and
at the head pulley where the material is discharged. For the
loading operation, the point of particulate discharge is at
the bottom of the loading chute where the coal free-falls into
the unit train hopper car.
Providing enclosures around these transfer points is
the first step to be taken towards effective dust control (MO-114).
A well-designed enclosure can be defined as a housing which
surrounds the operation and contains, at least to a large degree,
all dust dispersion actions. For the conveying transfer points,
this would consist of a metal housing with rubber skirting
fitted to the conveyor belt openings. The rubber curtain is
-205-
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TABLE 5.1-:
N3
O
PARTICULATE CONTROLS FOR
Control Method Percent 'Control
Enclosure 60-80
Mechanical Collector 85-95
Water Spray 50
Water Spray with 90
Chemical Wetting
Agent
Wet Scrubber 95+
Fabric Filter 99+
CRUSHING AND SCREENING OPERATIONS
Pressure Drop Secondary
inches HgO Pollution
Recovered
Dust
Disposal
Problem
3.5-5.0 Recovered
Dust
Disposal
Problem
Water /So lid
Slurry
Water /Solid
Slurry
5.0-15.0 Water/Solid
Slurry
2.5-3.5 Recovered
Dust
Disposal
Problem
Inst-.alled Cost
$/cfm
very small
0.35-1.05
Variable
Variable
0.75-1.50
0.75-1.50
(1)
Source: (BA-210)
-------
an effective way to contain dust emissions; and the bottom edge
of it should be cut to conform to the cross-sectional profile
of the material conveyed on the belt. Although it is not
common practice to enclose the loading equipment used at points
where coal is transfered to unit trains, it would not be dif-
ficult to accomplish this. Heavy curtains could enclose the unit
car being loaded, with the roof of the enclosure being the base
of the loading tipple.
The next step in effective dust control is to remove
the particulate-laden air from the enclosures and pass it through
a control device such as a mechanical collector, wet scrubber,
or baghouse. A fan would provide the power to move the air to
the control system via dusts. A comparison of these three control
methods can be seen in Table 5.1-1. The control device used would
probably also service other parts of the preparation plant as
well. An air duct from each enclosure would simply vent into
a larger line which would lead to the control unit being used.
The fabric filter provides the greatest control for the dust
from conveying and loading operations with a near zero particulate
discharge potential.
Coal Refuse Pile Burning
Burning coal refuse banks are a very significant source
of particulate emissions to the atmosphere. Although they were
once considered inevitable consequences of coal mining, modern
control techniques have reduced their occurrence to a minimum.
The pollutants emitted include, besides particulates, SOa, NO ,
a
HC, and CO. The controls mentioned in this section for particulate
emissions are also the controls which would be utilized for re-
ducing emissions of any of the remaining four pollutants. For
this reason, this discussion will be presented only once in the
pollution control section, but will be applicable to the control
of the other four pollutants.
-207-
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The coal preparation plant from the room and pillar
coal mining module disposes of its refuse material in a pile.
The two basic methods of controlling burning coal refuse piles
are (1) methods for extinguishing combustion and (2) methods
for preventing combustion from occurring in the first place.
Refuse from the preparation plant for the strip mine will be
reclaimed along with the overburden.
In 1968 the Bureau of Mines completed a project which
was a step towards developing a low cost procedure for quenching
and removing burning coal refuse (MC-096). This control method
involved dislodging the hot refuse with water cannons and removal
with a bulldozer. The estimated cost for this technique was
$0.66 per cubic yard. Another procedure tested at this time
was using water cannons to cool the refuse material. Water
sprinklers sprayed over the test site reduce surface tempera-
tures to permit movement of rubber-tired vehicles over the
project site. A bulldozer equipped with a ripper and a tractor-
scrapper tore up and disposed of the quenched refuse at an
adjacent strip mine area. The cost of this particular method
was estimated at $0.44 per cubic yard removed.
Other known techniques which were tested by HEW
demonstration projects include:
1) sealing or capping to prevent air
circulation through burning refuse
banks by using various chemicals and
compound such as polyurethane foam,
several types of plastic material, and
waste dust from cement plants,
2) injection into the banks through
drill holes of a mixture of sludge,
"yellow boy", which is produced
during the neutralization of acid
mine/water with limestone,
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3) drill hole injection of a mixture
of vermiculite, limestone, and
sodium bicarbonate into the refuse
pile, and
4) the use of explosives to fracture fused
refuse material to facilitate the infil-
tration and percolation of water through
the hot cores.
To prevent refuse bank fires, a number of guidelines
should be followed. First, proper attention must be directed
to the selection and preparation of the refuse pile site. The
best location for coal refuse disposal is flat terrain, which
facilitates the movement of equipment. In hilly or mountainous
regions coal waste disposal should be conducted in valley
bottoms or ravines, since these areas are generally more access-
ible. The disposal site should be close to an adequate source of
non-combustible solid materials which can be sandwiched between
layers of coal refuse. Also, the sides of the disposal site
should be covered with a non-combustible material and compacted
to eliminate the inflow of air. Materials that may be considered
include clay, shale, coal sludge fines, fly ash, and fines or
wastes from plants such as cement, gypsum, and ceramic and
glacial loess. Another important consideration in site selection
and preparation for a refuse bank is whether or not coal seams
or other highly carbonaceous zones are known to crop out. If
such a condition exists, an adequate inert seal between the
waste and the outcropping resources is needed. Also, the site
should be graded to assure proper drainage away from the site,
and watercourses should be diverted around or run through
conduits beneath the disposal site.
-209-
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The final consideration for the disposal of coal
waste is proper refuse pile design. The best approach to ac-
complishing this is spreading the waste materials in horizontal
layers and compacting the material to increase its strength.
This technique will prevent slides on slumps of the refuse.
Besides using proper disposal techniques to control
refuse bank fires, an alternative method of disposal could be
used. The backfilling of abandoned underground mine tunnels
with reject material is a technique that has found some ap-
plication in the coal industry. If the mine is properly
sealed, this disposal method eliminates any potential refuse
burning. It also reduces the possibility of surface subsidence.
Coal Thermal Dryers
The coal preparation plants of the two coal mining
modules include thermal dryers which are used to dry coal which
has been mechanically cleaned. These fluidized-bed dryers are
the source of the greatest particulate emissions within the
preparation plants.
*.
Controls used by the coal industry to reduce par-
ticulate emissions from the dryers include mechanical collectors,
water sprays, and wet scrubbers. The mechanical collectors,
usually cyclones, are used primarily for product recovery since
a large amount of coal is carried up with the hot gases from
the dryer bed. From the cyclones, the air stream is passed
through either a water spray chamber or a medium energy wet
scrubber. Baghouses are not used due to the danger of explo-
sion of the coal dust.
-210-
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Table 5.1-2 compares the controls which are used
commercially on coal thermal dryers.
Besides using these control devices, the particulate
emissions can be reduced by another control method - a process
change. In 1972 only 197o of the coal mechanically cleaned was
thermally dried (Minerals Yearbook, 1972). Alternative methods
of drying coal use air as the drying medium. By using this
type of process, particulate emissions from coal drying could
be reduced.
-211-
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TABLE 5.1-2
PARTICULATE EMISSION CONTROLS FOR COAL THERMAL DRYERS
Pressure Drop Secondary Installed Cost
Control Method Percent Control inches H., 0 Pollution $/cfm
Cyclones 20-85 3.5-5.0 None 0.35-1.05
Water Sprays 95 4.5-6.0 Water/Solid 0.45-1.30
Following Cyclones Slurry
Wet Scrubber 99-99.9 8.5-20.0 Water/Solid 1.10-2.55
Following Cyclones Slurry
-------
5.2 S02 Control Systems
There are a number of sources of SOz emissions within
the modules of Section 3.0. Of these sources, however, only two
have SO2 controls commercially available and being used. These
two emission points are in Glaus sulfur recovery plants, one in
the natural gas production module, the other in the oil shale in-
situ production module. Emissions from other modules are relatively
small, and generally come from multiple and diverse sources, such as
diesel exhausts from mobile equipment. In the following section
the controls commercially available for Glaus plants will be
presented. The other S02 emissions are discussed in the sub-
sequent section.
SOC Controls for Glaus Sulfur Recovery Units
A Glaus sulfur recovery unit is designed to convert
sulfur compounds (HgS, CS3 , COS, and mercaptans) that have
been removed from a process stream by an amine treating unit
or similar system into elemental sulfur. However, most Glaus
plants have a removal efficiency of 90 to 96%. The gases
(mostly Hg S) that pass through the unit unconverted are usually
incinerated to S0g since it is a less hazardous compound. For
sulfur plants without controls, this SO, is discharged to the
c
atmosphere.
Several processes are commercially available for
treating this tail gas before incineration (RA-119). Some of
these units recover sulfur as a product, others recycle recovered
sulfur compounds back to the Glaus unit. Table 5.2-1 compares
six of these processes on the basis of (1) sulfur removal ability,
(2) secondary pollution, (3) product produced, and (4) installed
cost.
-213-
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i
N3
Process
Shell Glaus
Off Gas
Treating (SCOT)
Wellman-Lord
Sulfreen
IFP
Clean Air
TABLE 5.2-1
PROCESSES FOR GLAUS TAIL GAS TREATMENT
Removal
96%
Removal to
100 ppm
75%
Removal to
500-1000 ppm
Removal to
<250 ppm
Secondary
Pollution Product
None
None
None
None
None
None
None
Sulfur
Sulfur
Sulfur
Installed Cost, $'s
For a 100 Long Tons per Day
Capacity Glaus Plant
630,000 - 900,000
800,000
320,000 - 570,000
450,000 - 800,000
480,000 - 800,000
Beavon
Removal to
<250 ppm
SO
None
Sulfur
700,000 - 1,000,000
SOURCE: RA-119
-------
Other S02 Emissions
Besides the S02 emissions from Glaus plants, all but
one of the modules (gas pipeline transportation) of Section
3.0 release S0g to the atmosphere. These emissions result
from the combustion of fuel which contains a small amount of
sulfur.
At present there are no processes commercially avail-
able or in the developmental stage which are designed to remove
S02 from the flue gas of small sources such as those found in
the modules of this report. Some degree of sulfur dioxide
control, though, can be accomplished by either substituting a
lower sulfur fuel, switching to electrical power, or making a
process change. Those processes which could control their S0_
3
emissions by substituting a lower sulfur fuel are the ones
which burn fuel oil or coal. The following list identifies
these specific sources, the modules they belong to, and the
type of fuel burned.
In both the strip and room and pillar
mining modules for coal and oil shale
. diesel fueled trucks and bulldozers
are used. SOa emissions could be
reduced by burning a lower surfur
diesel fuel.
• Thermal dryers are used in both the coal
strip mining and the room and pillar mining
modules. These dryers combust coal
as a source of heat for drying the wet
coal. A lower sulfur coal could reduce
SO2 emissions.
-215-
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In the oil production module and in the
crude oil transportation module, fuel
oil is burned in boilers. Lower sulfur
fuel oil in both cases would reduce SO
emissions. Also, it may be possible for
the steam generator boiler in the oil
production module to switch to casing
head gas as a source of fuel.
In the transportation modules, diesel
fuel is burned in locomotives, towboats,
and oil pipeline booster stations. For
each source, S0g emissions could be
reduced by the use of a lower sulfur
diesel fuel.
Besides controlling S0p emissions by fuel substitu-
tion, switching to electrical power offers a complete elimina-
tion of S0g discharges. Those processes which could be switched
to electrical power are: the diesel powered pump used in the
water flood system of the oil production module and the oil
pipeline booster stations. Electric powered oil booster stations
are quite common. Approximately 7070 of crude oil pipeline
booster stations are powered electrically (BA-234).
Process change is another method of SOj emission control
With this approach, a processing alternative which emits less S02
can be substituted for one which emits a greater amount. This
technique is applicable to coal dryers. The thermal dryers used
on the two coal mining modules could be changed to dryers which
use air as the drying medium. Thus, the S02 emissions could be
eliminated by such a switch.
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5.3 Hydrocarbon Control Systems
Within the modules of Section 3.0 are a number of
hydrocarbon emission1 sources. These emission points can be
divided into three categories: (1) emissions from the combus-
tion of a fuel, (2) emissions from evaporation of a volatile
liquid hydrocarbon, and (3) fugitive emissions from miscella-
neous process leaks. Control systems applicable to the first
two categories will be discussed in this section, while controls
for the fugitive losses will be addressed in Section 5.6.
Controls for Combustion Sources
The type of hydrocarbon controls to be used on combus-
tion sources depend upon the particular kind of combustion device.
These combustion sources are characterized as those which are
fired externally, such as boilers and process heaters, and those
which utilize internal combustion, such as diesel-fired engines.
Of the externally-fired equipment, there are two types
of boilers: one used in the oil production module for generating
steam, the other in the crude oil tanker transportation module used
as the ship's power plant. Also there are three types of process
heaters: thermal dryers in each of the two coal production
modules, the heater treaters in the oil production module, and
heaters providing heat to regenerate glycol and amine solutions
in the gas production plant modules.
Hydrocarbon emissions from externally fired equipment
can be reduced or eliminated by essentially three techniques:
improved operating practices, fuel substitution, and process
change (NA-032).
-217-
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Good operating practice is the most practical tech-
nique for reducing hydrocarbon emissions from these sources.
Even the best equipment will perform poorly if improperly ap-
plied, installed, operated, or maintained. Hydrocarbon emissions
are directly related to the three common combustion parameters
of time, temperature, and turbulence. A high degree of fuel
and air turbulence will greatly reduce hydrocarbon emissions,
increase combustion efficiency, and reduce fuel consumption.
Stationary combustion units (including the oil tanker
boiler system) should be operated within their design limits
at all times and according to the recommendations of the man-
ufacturer in order to achieve a high degree of combustion ef-
ficiency. Combustion units and components should be kept in
good repair to meet design specifications. Flue gas monitoring
systems such as oxygen and smoke recorders are helpful in indi-
cating that the furnace is being operated properly and that
emissions are being held to a minimum.
Fuel substitution offers another method of controlling
emissions of hydrocarbons. Emissions from coal thermal dryers
can be reduced by fuel substitution. A switch from coal to fuel
oil or gas could reduce organic emissions from these dryers.
This reduction is, in part, affected by the better mixing and
firing characteristics of a liquid or gaseous fuel as compared
to those of a solid fuel.
The process change approach offers another method of
reducing hydrocarbon emissions. There are three emission sources
which, through a process change, could eliminate the need for
fuel combustion. These are the thermal dryers used in the two
coal mining modules and the heater treater used in the oil
production module. For the thermal dryers, instead of using
heat as a means of drying the wet coal, air could be used.
-218-
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Air drying techniques are used in many coal drying applications
in the United States which require no fuel combustion. As a
substitute for the heater treaters, there are three other
commercially available processes available for separating crude
oil and water emulsions. These alternatives are: (1) chemical
destabilization, (2) electrical coalescence, and (3) gravitational
settling. Since none of these units require heat input, hydro-
carbon emissions due to combustion are eliminated.
Besides the hydrocarbon emissions from externally-
fired equipment, there are also hydrocarbon emissions from
internal combustion diesel engines. See the discussion on
particulate control systems in Section 5.1 for a list of modules
using diesel fueled equipment.
Methods of controlling hydrocarbon emissions from
diesel equipment include good practice techniques. As vehicle
mileage increases, proper fuel system adjustment is most import-
ant. Also, maintenance at appropriate intervals and the use of
the specified type of fuel aid in reducing hydrocarbon emissions.
Diesel fuel modification offers another method for decreasing
hydrocarbon emissions. A major cause of hydrocarbon emissions
from diesel engines is incomplete combustion of the dispersed
fuel droplets, sometimes manifested as white smoke. The diesel
fuel characteristic normally related to white smoke is the cetane
number. Smoking tends,vto decrease with increasing cetane numbers.
The addition of cetane improvers, such as isopropyl nitrate,
tend to suppress white smoke and to reduce hydrocarbon emissions
(NA-031).
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Hydrocarbon Controls for Non-Combustion Sources
There are several quantifiable sources of hydrocarbon
losses from within the modules described in Section 3.0 which
are not due to fuel combustion; These losses are due. to evap-
oration of a volatile hydrocarbon during storage or loading
operations. The sources of these emissions are:
crude oil storage tanks located on
site at the oil well (oil production
module),
condensate recovery tanks, one located
at the gas well site and the other at
the gas processing plant (natural gas
production module),
crude oil tanker storage compartments
(crude oil tanker transportation module),
and
railroad crude oil tank car (crude oil
rail transportation module).
The controls available for reducing hydrocarbon losses
from crude oil and natural gas condensate storage tanks include
floating roofs or internal floating covers and vapor recovery
units. Floating roofs can reduce breathing losses approximately
807o compared to a fixed roof tank. Installation of a vapor
recovery unit, though expensive, can control emissions from a
fixed roof tank by as much as 95% (EN-071).
Tanker emission controls consist of venting vapor
expansions to an on-board vapor recovery system which reliquefies
the vapors. Pressure/vacuum valves can also be applied to tanker
-220-
-------
compartments for minimizing the quantity of vapors processed in
the vapor recovery unit.
Hydrocarbon evaporation losses from crude oil rail
cars while underway are very small. However, during loading
and unloading operations a potential hydrocarbon emission
problem exists. This is also true for the tanker module. A
significant portion of this problem can be eliminated by using
bottom loading techniques when filling rail cars instead of the
top or splash loading method. Bottom loading is an inherent
technique for tankers. Besides the bottom loading technique,
hydrocarbon emissions can be further reduced by installing a
vapor collection device manifolded into a vapor recovery unit.
Assuming a vapor collection efficiency of 95% and a 95% efficient
vapor recovery unit, emissions can be reduced by 9070 over an
uncontrolled bottom loading system.
-221-
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5.4 Nitrogen Oxides Control Systems
The formation and release of NO occurs with any process
A,
which utilizes combustion. There are numerous sources of this
pollutant within the modules described in Section 3.0. In fact,
every module except the coal slurry pipeline has one or more
sources discharging NO .
X
Various approaches have been developed, and others are
under development for controlling emissions of NO from combustion
*v
processes. This discussion is divided into two categories -
controls for external combustion sources and controls for internal
combustion sources.
Commercially Demonstrated NO Controls for External
Combustion Sources •
NO controls for external combustion systems include
X
combustion operating modification, combustion equipment design
modifications, flue gas treatment, fuel substitution, and
process modifications (NA-005).
The formation of NO in an external combustion system
X
is affected by the flame temperature, the amount of oxygen avail-
able to combine with the nitrogen, and the residence time of
exhaust gases within the firing chamber. High flame temperatures,
large excess air quantities, ancl short residence times of exhaust
emissions in the combustion chamber enhance the formation of NO .
A.
Combustion operating and equipment design modifications are made
with the intent of reducing the excess air in combustion, reducing
peak gas temperatures, and lengthening the residence time of
flue gases in the combustion chamber.
-222-
-------
Two-stage combustion in oil- and gas-fired boilers
has reduced NO emissions by 30 to 50 percent (NA-005). Low-
X
excess-air operation has reduced NO emissions from these boilers
X
by 30 to 60 percent, depending upon the percentage of excess
air, the design of the boiler, and the type of firing. Also,
by changing the firing of boilers from front wall or opposed
firing to tangential firing, NO has been reduced from 30 to
X
40 percent. A modified two-stage combustion technique, combined
with low-excess-air firing has reduced the stack-gas NO con-
X
centration in the flue gas by almost 90% (NA-005).
Proper burner location and spacing also aids in
reducing NO emissions. Arrangements which lower the flame
temperature and radiate heat more evenly have been the most
effective.
The combustion modifications discussed above are more
applicable in the case of a large external combustion source
such as a utility boiler. They represent the most effective
controls which could be applied to a large boiler such as the one
used on board the oil tanker module. However, there are serious
obstacles to the practical use of these control techniques for
the relatively small process heaters, boilers, and dryers used
in the rest of the modules. The specific combustion modifica-
tions considered most promising (low-excess-air, flue gas
recirculation, and two-stage combustion), all require additional
equipment and operating control and are expensive. Generally,
the smaller the combustion unit the more the control will cost.
-223-
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A partial reduction in NO emissions can be realized
X
by converting from coal to other fuels. This control method
could be used on the coal-fired thermal dryers. A fuel oil
could be burned in the place of coal.
Another method which can be utilized to reduce NO
x
emissions from certain sources is through making a change
from a process which requires fuel combustion to one which
accomplishes the job without the need for fuel. Such an option is
available to the thermal drying of coal and to the oil-water
separators at oil well sites. In place of a coal fired thermal
dryer, systems which utilize air as a drying medium could be
used. And, in place of gas fired heater treaters for breaking
the oil-water emulsions from oil wells, either chemical
destabilization, electrical coalescence, or gravitational settling
could be used. Since none of the process changes mentioned
require fuel combustion, NO emissions could be eliminated with
X
their use.
Controls for NO Emissions from Internal Combustion
^—•••••••^^M^^^B_^BMM«a>WB^K__2£^'H^BHH^^H^^^^^HMHBB^~>~a^MMHBMB*MIBlBH>^H^B^HH>l*HB^^^M*HB"M"M>>a>BII*HM^HMM>
Engines
There are two types of internal combustion engines
found in the modules described in Section 3.0. These are engines
fired by either diesel fuel or natural gas. The diesel engines
serve a variety of functions within the modules. The gas engines
are used to drive compressors for the transport of natural gas.
Several techniques are available for controlling NO
X
emissions from internal combustion, diesel-fired engines. These
involve combustion chamber design, the use of special fuel type,
and variation of compression ratio (NA-031).
-224-
-------
Combustion chamber modifications which have been found
to reduce NO emissions have involved design of the precombustion
X
chamber, the turbulence chamber, and the use of "energy cells."
Energy cells provide controlled combustion to prevent high peak
pressures and rough operation.
There are indications that by increasing the fuel's API
gravity a decrease in NO emissions occurs in diesel engines.
X
NO production decreases about 25 percent when the gravity of the
fuel is increased from 30.9 to 42.8 API. Thus, it appears
possible to modify NO emissions by tailoring fuel properties.
Also, there are indications that chemically bound nitrogen in
fuel may play an important part in NO emissions. If so, burn-
ing low-nitrogen fuels could be an effective method of controlling
NO from both internal and external combustion sources. The use
of such special fuels can add considerably to fuel costs, however.
The use of variable compression ratio diesel engines
tends to maintain a preset peak combustion pressure in the
combustion chamber. This may be a means of avoiding the exces-
sively severe cycles which occur frequently in conventional diesel
engines, and which are the cause of a disproportionate part of
the NO emissions from. These engines were first developed for
the military.
Switching from diesel power to electrical power offers
a means of completely eliminating NO from those sources where
such a change is feasible. Within the process modules, there
are two such sources. One, within the oil production module, is
a diesel engine used to drive the water flood system pump; the
other, within the oil pipeline transportation module, is a diesel
engine used to drive the line pumps in the booster stations. In
both cases, electrical power could be substituted for diesel
power.
-225-
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5.5 Carbon Monoxide Control Systems
Carbon monoxide is formed when carbonaceous fuels are
burned with insufficient oxygen for the formation of carbon
f
dioxide. It is also formed from C02.at high temperatures under
chemically reducing conditions. There are numerous sources of
CO within the modules described in Section 3.0. From each
process which burns a fuel, except possibly the natural gas
fueled engines, some carbon monoxide is emitted. These combust-
ion points are listed in Section 5.1. CO controls for external
combustion sources and internal combustion engines are discussed
in the following paragraphs.
CO Controls for External Combustion Sources
The most practical technique for reduction of CO
emissions from external combustion sources is simply good
practice. This involves proper design, installation, operation,
and maintenance of the combustion equipment and auxiliary systems
(NA-004). Good practice guidelines are published by the fuel
industry, equipment manufacturers, engineering associations, and
government agencies. Combustion units should be operated within
their design limits and according to the recommendations of the
manufacturer. Combustion units and components should be kept in
•
good repair to continue to meet design specifications. Sensitive
CO monitoring systems are helpful in indicating the need for
combustion system maintenance.
Proper fuel-air ratio adjustment is of major importance
for reduction of CO emissions from stationary combustion sources.
Flue gases from the best designed combustion unit may contain
substantial concentrations of carbon monoxide if insufficient
air is provided for combustion. Carbon monoxide emissions can
-226-
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also increase when excessive air is used. This can cool combustion
temperatures below the point where optimum oxidation of fuel and
CO would occur.
In the design of a combustion system, CO emissions can
be minimized by (1) a high combustion temperature, (2) intimate
contacting of fuel, oxygen, and combustion gases, (3) sufficient
reaction time, and (4) low effluent temperature. Another impor-
tant step in the combustion system design is making an accurate
estimate of the load on the system. Firing in excess of design
rates is perhaps the greatest cause of excessive CO emissions.
from external combustion systems.
Generally, automatic (as opposed to manually operated)
combustion control of the fuel-air ratio offers the potential of
increased efficiency, lower CO emissions, and lower operating
costs. Combustion control equipment is primarily concerned with
two functional aspects, namely, adjustment of the fuel supply
with variation of load demand, and correction and control of the
fuel-air ratio corresponding to the fuel supply.
Fuel substitution offers another method of controlling
emissions of carbon monoxide. The thermal dryers used on the
coal preparation plants of the two coal mining modules could be
switched from coal to fuel oil or natural gas. This would
reduce carbon monoxide emissions from these sources primarily
because of the better mixing and firing characteristics of the
liquid or gaseous fuels.
Elimination of combustion sources always reduces CO
emissions. There are two previously described processing
alternatives in which fuel combustion is eliminated. Thermal
dryers used in the coal mining modules can be replaced by air
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tables, and the heater treater used in the oil production module
can be replaced by any of three commercially available alterna-
tives for breaking crude oil-water emulsions which do not require
the use of heat. These are: (1> chemical destabilization,
(2) electrical coalescence, and (3) gravitational settling.
CO Controls for Internal Combustion Engines
The exhaust gases from the diesel-fueled engines used
in the modules described in Section 3.0 contain varying amounts
of carbon monoxide depending on the condition of the engine.
(See the discussion on particulate control systems, Section 5.1,
for a list of those modules which have diesel-fueled engines.)
Carbon monoxide emissions from diesel equipment are
controlled most effectively through good practice. As vehicle
mileage increases, proper fuel system adjustment is most import-
ant. Also, maintenance at appropriate intervals and the use of
the specified type of fuel are important in maintaining carbon
monoxide emissions at the lowest practical level (NA-031).
Carbon monoxide emissions from diesel engines, when
operating within their normal design limits, with excess air and
with a relatively high combustion temperature, are inherently
low. Thus, by keeping the engine in proper tune, carbon monoxide
emissions can be minimized.
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5.6 Fugitive Emissions Control
Particulates and hydrocarbons are two of the major
fugitive emissions. Approaches for controlling these emissions
are discussed in this section.
Particulate Fugitive Emission Controls
The sources of particulate fugitive losses in the
modules relating to the mining, processing, and transporting of
coal and oil shale include:
vehicle travel over unpaved roads and
areas within the oil shale strip mining
pits and within the oil shale room and
pillar mine,
the blasting operations which are used
to remove the overburden in the coal
and oil shale strip mines, and also to
fragment the oil shale for extraction
from the underground oil shale mine,
the handling of overburden, extracted
coal and oil shale, and refuse material
which comes from the screening and
sizing of oil shale and from the coal
preparation plants, and
the transportation of coal via unit trains
and barges.
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The travel of trucks, bulldozers, and other mining equip-
ment over unpaved roads and the areas around coal and oil shale
mines creates a potential fugitive emission.problem. The most
common control and easiest one applied is the watering down of
dusty surfaces. Regular watering of these areas can reduce emis-
sions by 30 to 70%, depending on the extent of surface use (PE-120)
In addition to emissions from vehicle travel over
unpaved areas, blasting operations contribute to the fugitive
particulate problem in the coal and oil shale extraction modules.
Blasting is used to aid in the removal of overburden from coal
and oil shale and also for fragmenting the oil shale in the
room and pillar mine before extraction. Techniques for control-
ling particulates from blasting operations include spraying water
or water with: chemical wetting agents over the area to be blasted
and infusing water by pressure'into the material being blasted.
The applicability of water infusion is limited primarily to
coal seams with high porosity and with few large-sized cracks.
Large amounts of materials are mined, hauled, and
processed within the coal and oil shale mining modules. These
operations are the source of significant fugitive dust losses.
Water spraying with or without chemical wetting agents is the
best method for controlling dust from these sources.
Coal or oil shale storage piles around mines are poten-
tial fugitive dust sources. A dust control efficiency of 50%
can be assumed for watering of these storage piles. Manufacturers
of continuous chemical spray systems for use in dry materials
handling and storage operations have claimed dust removal
efficiencies as high as 90 percent (PE-120).
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Another source of fugitive particulate emissions is
from the transportation of coal via unit train and barge. Some
windage losses of coal dust occur in coal movements by these
two methods. Techniques available for control include wetting
of the coal, chemical spraying of the coal, and special loading
where larger pieces of coal comprise the top layer in a hopper
car or barge. Control efficiencies for these methods are esti-
mated to be 30% for layering, 50% for water spraying, and 90%
for spraying with a chemical wetting agent.
Hydrocarbon Fugitive Emission Controls
The potential hydrocarbon fugitive emission sources
include:
the underground room and pillar coal
mine,
the producing wells used in the coal and
oil shale in-situ recovery processes,
the oil production well operations, and
the production, transportation, and
processing of natural gas.
Methane has been a problem in United States coal mines
for as long as underground mining has been practiced. Elimina-
tion of this fugitive hydrocarbon problem from below-ground mines
is of utmost importance because of the fire and explosion hazard
it presents. Presently, high ventilation rates through mine shafts
are being maintained as a means of controlling dangerous buildups
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of methane. However, ventilation does not eliminate or control
the amount of methane lost to the atmosphere.
One method of methane control which appears promising
is the removal of methane before the mining operation b'egins.
This is accomplished by drilling vertical boreholes from the
surface into the coal seam at various spots and recovering the
natural gas. Other methods available include the use of hori-
zontal holes in a coal seam to infuse an active face area with
water and thus divert the flow of methane, the use of long
horizontal holes to dewater and degasify a section prior to
mining, and hydraulic fracturing of coal to increase its permea-
bility, thus increasing methane flow through the coal to a
vertical or horizontal degasification hole (ZA-044).
The production of oil and gas from underground reser-
voirs, coal and oil shale in-situ operations, the transportation
of oil, and the transportation and processing of natural gas are
potential areas of fugitive hydrocarbon emission problems.
Sources of these fugitive losses include wastewater separators,
high-pressure gas-condensate separators, gas-oil separators,
pump and compressor seals, relief valves, pipeline valves and
corroded pipe flanges (MI-146).
Hydrocarbon emissions from wastewater separators may
be minimized by (1) sealing the oil/water mixture from the
atmosphere, (2) venting the recovered vapor to a vapor recovery
unit, and (3) providing floating covers over the separator.
The major fugitive hydrocarbon losses in high-pressure
gas-condensate separators are those associated with relief and
small volume gas venting systems. Relief systems consist not
only of the primary relief valves, but also discharge piping
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systems, liquid knockout drums, and a means of disposing of
relieved gas through flares or vapor recovery units.
Methods available for controlling fugitive losses from
pump and compressor seals include converting packed seals to
mechanical seals and/or installation of double seals. Losses
from around pipeline valves may be reduced by regular mainten-
ance of their stuffing boxes. Also, chatter in check, valves
can be minimized by sizing them to be fully open in normal-
operation, thus preventing excessive wear on moving parts.
Properly monitored inhibition programs can be an
effective technique for reducing corrosion problems of pipes
and flanges. Regular ultrasonic and/or radiographic inspections
should be made of piping and valves to determine wall thickness
losses. The results of such an engineering study should result
when warranted, in revisions to equipment specifications or
pressure ratings, where the inspected equipment is judged a
potential source of fugitive emissions. Design practices current-
ly used to control corrosion in piping include cathodic protection,
internal and external coatings of steel pipe, and proper selection
of pipe material.
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6.0 POTENTIAL PRODUCTION PROBLEMS
In the production of coal, oil, and gas, due consider-
ation must be given to potential environmental effects and to
associated problems. This section reviews the potential sources
of pollutants and major constituents of the contaminants 'and
their effects on receiving media. The availability of primary
resources is discussed briefly. These resources include energy
sources (electric power, diesel oil, and natural gas) and water
required for production operations. Federal, state and local
laws concerning emissions and water availability are also
discussed.
6.1 Coal Production
Coal production operations affect the quality of air,
water and land in the surrounding areas. This section presents
a discussion of the problems of airborne and waterborne emissions
associated with coal production. In addition, energy sources
(electric power and diesel fuel) and water requirements which
may impose some constraints on coal production are discussed.
6.1.1 Underground Mining Operations
Underground mining pertains to mining techniques which
employ tunnels and shafts to reach the coal deposits to be
extracted.
Airborne Emissions
The underground environment is contaminated with air-
borne matter consisting chiefly of coal dust and methane gas.
Coal dust is formed by the release of the dust trapped in
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fractures in the coal. It is also released during the fragmen-
tation process and in the handling and transportation of coal.
The coal dust, upon release, normally is suspended in the
methane contaminated air. This situation causes a visibility
problem and a potential explosion risk.
Methane is present in the coal, either compressed in
the fractures or absorbed into the coal. The rate of methane
release is dependent upon the speed of advance of a heading and
the degree of fragmentation. Underground operations do not in
general affect the air quality of the external environment.
Waterborne Emissions
Waterborne contaminants such as acids, dissolved solids,
and suspended solids are released from underground mining
operations. Acid mine water is formed as a result of water
seeping into the underground mine through the pyrite-bearing
strata. Water seepage is initiated by the disturbance of the
strata. The quantity of seepage is governed by such factors as
the degree of subsidence, surface topography, type of strata,
and annual rainfall. Normally, the acid mine water is pumped
out of the mine.
The discharge of mine water to the environment is
regulated by Federal, state, and local laws. Thus, the mine
water must be treated prior to release, and must comply with
acidity-alkalinity standards such as those set forth by the
various states (EN-219).
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Energy and Water Requirements
Electric power is the primary energy source for under-
ground mining operations. On the average, power consumed is 18
kwh per ton of coal produced: Power is normally delivered by
high-voltage (14 kv or higher) power transmission lines to the
larger underground coal mining operations. Power transmission
is a problem for mines not near generating stations. Water
required for controlling coal dust emissions is minimal.
6.1.2 Surface Mining Operations
Surface mining involves the removal of overlaying
materials, such as topsoil arid rock, to gain access to the coal
deposits, two methods generally employed are strip mining and
auger mining. The choice of mining method depends on terrain,
seam depth and thickness, deposit size, local geology, and other
factors.
Airborne Emissions
Potential sources of airborne emissions from surface
mining include dust and other materials emitted during the
fragmentation process and blasting operations, major combustion
products released by the diesel oil fueled equipment used in
mining operations, and dust from mines and waste piles. In some
surface mining operations waste piles are burned, releasing
products of combustion and other unburned materials into the
atmosphere.
Air emissions from surface mining operations fall under
the category of area emissions. The assessment of the impact
of these emissions requires field measurements and some computational
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analyses using atmospheric dispersion models with topography
effects to determine the maximum concentrations in affected
areas. These computed maximum concentrations can be compared
with the Federal, state, and local ambient air quality standards.
Waterborne Emissions
Potential pollutants of streams and underground water
supplies from coal surface mining operations include sulfuric
acid, iron, silt and trace metals such as arsenic, copper, lead
manganese, and zinc. For example, in the Appalachian surface
mining regions, it has been observed that the siltation from
the mined areas is around 1,000 times higher than the unmined
areas. Control of these potential pollutants will be essential
in future coal resource developments.
Energy and Water Requirements
Energy for surface mining operations is supplied in
the form of electric power and diesel oil. Average energy
requirements are about 14 kwh of electricity and 0.20 gallons
of diesel oil per ton of coal produced. High voltage power
accessibility may be a problem in remote areas. Water supply
in not a problem for most mining sites.
6.1.3 Coal Preparation
Raw coal contains sulfur compounds, dirt, clay, rock,
shale, and ash. Coal quality can be improved by mechanical
cleaning, which, in effect, removes coal impurities, reduces
sulfur and ash contents, and ultimately increases the Btu
content per pound of clean coal. This can be achieved by cleaning
either by a dry method, by a wet method, or by a combination of
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the two. Details of these methods are presented in Section
2.1.
During coal cleaning some contaminants may be released
to the environment. This section presents the potential
environmental effects and problems associated with coal clean-
ing at a coal preparation plant. Included among these problems
are airborne and waterborne emissions, energy and water require-
ments, and the significance of existing laws, regulations,
and guidelines.
Airborne Emissions
Pulsating air columns and thermal dryers are the
major sources of airborne emissions from coal cleaning operations,
From pulsating air columns (the dry process method), particulates
are the only significant airborne emissions. Approximately
three pounds of particulates per ton of coal feed are released
from these units to the environment. Thermal dryers release
both particulates and combustion products. Air pollution regu-
lations require that these.emissions be controlled. For example,
proposed EPA standards for particulate emissions state as
follows:
"Particulate matter from thermal driers
must not be more than 0.070 grams per dry
standard cubic meter (0.031 grain per
dry standard cubic foot), with less than
30 percent opacity; while particulate
matter from pneumatic (dry) coal cleaning
equipment must not be more than 0.040
gram per dry standard cubic meter (0.018
grain per dry standard cubic foot), with
less than 20 percent opacity."
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Coal preparation plants also produce refuse piles
consisting mainly of sulfur rich coal. Improper disposal of
the refuse pile may initiate low-temperature oxidation of the
coal with an accompanying increase in temperature within the pile.
Ultimately, this can result in the ignition of the refuse pile
from which undesirable gases such as SOai NO , and hydrocarbons
J\
can be emitted.
Waterborne Emissions
The contaminants in the process water from wet coal
cleaning consist of suspended solids, which are chiefly fine
clay and coal, and dissolved solids, which may contain iron,
aluminum, calcium, magnesium, sodium, and potassium. Water
effluents may also contain surface-active organic compounds
such as alcohols or kerosene, which are added in some coal
cleaning plants to enhance frothability in the process. Water
contaminants in refuse pile runoff are sulfuric acid, sulfates,
manganese, and iron.
Energy and Water Requirements
Energy required for coal preparation plants is supplied
as electrical energy and diesel oil. Electricity is the main
energy source. It is consumed at the rate of 3.7 kwh per ton
of coal cleaned. Electricity can be generated by in-plant
process boilers or it can be delivered via transmission lines.
Transmission lines are a problem for remote plant sites. A coal
preparation plant producing 10,000 tons of cleaned coal per day
needs about 580,000 gallons per day of make-up water for wet
cleaning operations. Water supply for such purposes may be a
problem in siting large coal preparation plants, especially in
the more arid sections of the nation.
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In general, the Mississippi River divides the relatively
humid east coast from the more arid western United States. Of
course, some western areas (notably the northwest) are also
humid, but by and large, the wes-tern central states are in a
relatively arid region. Figure 6.1-1 shows the relative water
abundance or deficit across the United States (US-083). Water
abundance is defined as a rainfall rate greater than the evapor-
ation rate, and water deficit is just the opposite. Figure 6.1-2
gives a general impression of the sizes and locations of major
rivers in the United States. This figure indicates that the
western central states do not have an overabundance of large
river water supplies.
There are other data that indicate this same relative
trend toward possible water shortages and the necessity to
carefully scrutinize water availability for energy development.
Production capabilities are presently being considered at rates
that would exceed the reliable natural water supplies at the
facility sites.
Another potential problem relates to water laws and
regulations. Recent reports (FE-076) indicate that the availa-
bility of water in any area is governed partly by Federal actions
but more importantly by physical limitations and by state and
local prerogatives. The four factors determining availability
are:
(1) Runoff. Some regions have inadequate rainfall
and runoff to meet the demands of all water
users.
(2) Institutional Factors. Federal and state laws,
interstate compacts, and international treaties
govern the allocation of water in many areas.
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I
KJ
-O
'"'' * '••••••'•••••-••
mmmm
ATER SURPLUS OR
INCHES
i20 TO >80
WffiSS 0 TO 20
S$: 0 TO -20
T0<-40
FIGURE 6.1-1 RELATIVE WATER SURPLUS OH DEFICIENCY IN THE UNITED STATES
-------
to
Flows of Large Rivers
FIGURE 6.1-2 LARGE RIVERS OF THE UNITED STATES
-------
(3) Environmental Considerations. The Federal Water
Pollution Control Act Amendments regulating
thermal pollution, sedimentation and acid run-
off from strip mining, increases in salinity,
salt water intrusion, and coastal water quality
strongly affect water availability.
(4) Capital Investment and Repayment. Construction
of water supply projects for energy activities
will be affected by debt limitations and success
or failure of bond issues.
Factor number 2 is of greatest consequence to this discussion.
The major constraints to water use in many regions of the United
States are administrative in nature. There are legal agreements
on water availability among the Federal government, the indi-
vidual states, and the river basin authorities. For examples,
summaries of the Law of River Compacts, State Water Laws, and
Federal Water Laws are presented in Appendix 6-1.
6.2 Oil and Gas Production
The three major operations in both the offshore and
the onshore production of oil and gas are exploration, drilling,
and production. Environmental problems associated with drilling
and production operations are discussed in this section.
6.2.1 Drilling Operations
Problems during routine drilling operations include
ambient air and effluent pollution and supply of energy and water,
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Airborne Emissions
The chief sources of air emissions are blowouts
and well-testing operations. Blowouts release to the atmosphere
considerable quantities of hydrocarbon liquids and gases in
addition to hydrogen sulfide and salt water. In addition, the
evaporation of spilled oil in wastewater contributes to the
hydrocarbon emissions. Of course the rate of evaporation is
dependent on the composition of the oil and prevailing meteor-
ological conditions. The gas or oil produced during well-testing
is normally burned. The products of combustion during this time
are released to the environment. This practice has been banned
by numerous states.
Waterborne Emissions
During drilling operations, blowouts and spills
are the major sources of water pollution. A blowout is recog-
nized as the greatest threat of hydrocarbon pollution in off-
shore waters during drilling.
Energy and Water Requirements
Energy required for drilling oil and gas wells varies
with rig size, type of formation drilled, well depth, and
the time on well. The forms of energy used in drilling wells
are diesel oil and natural gas. Diesel oil is normally used in
internal combustion engines for drilling crude oil wells. Gas
development wells usually employ gas-fueled engines.
Diesel oil and natural gas used in drilling wells
have been estimated to vary from 900 to 1,800 gallons of diesel
oil per day and from 150,000 to 300,000 cubic feet of natural
gas per day, respectively (FE-084).
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The water consumed in well drilling is approximately
17.3 gallons of water per barrel of oil produced, or the equiva-
lent of 3.05 gallons of water per million Btu's produced (FE-076).
For example, an oil well that can produce about 100,000 barrels
of crude oil per day using secondary and tertiary recovery methods
can consume as much as 1.7 million gallons of water per day.
The availability of such substantial quantities of water from
other regions for the development of oil wells can be a major
problem, especially in areas where water is not abundant.
6.2.2 Production Phase
Potential releases to the environment can occur during
routine production operations, during stimulation efforts from
acidizing, and from accidents.
Airborne Emissions
Air emissions related to oil or gas production
are released through venting or burning of vapors and liquid
waste materials. These emissions consist mainly of combustion
products, products of incomplete combustion, hydrogen sulfide,
and sulfur dioxide. The quantity of pollutants emitted varies
with the capacity of the producing facility. Examples of oil
and gas producing facilities are described in Sections 2.3 and
2.4, and their air emissions are given in Tables 3.3-1 and
3.4-1.
The environmental impacts.of the air emissions can be
estimated by computing the maximum concentration of the various
pollutants for meteorological conditions that may exist at the
area at various times through the use of mathematical diffusion
models.
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Waterborne Emissions
Potential sources of waterborne emissions include
wastewaters, saltwater brines, blowouts, well stimulation, and
sand production.
Wastewaters. Oil pumped from the reservoir is
accompanied by some amount of water. The oil is passed through
separation and treating facilities to remove this water. The
present state of treating facilities is not 100% efficient,
however, and small amounts of oil are entrained and dissolved
in the wastewater discharged to the environment. The oil removal
efficiency of the treating facilities is dependent on the
percentage of water in the crude stream, the physical character-
istics of the oil, and the oil throughput. Current Outer
Continental Shelf (OCS) regulations permit an average of 50 ppm
oil in discharged wastewaters.
Saltwater Brines. As oil production progresses
and the oil fields begin to play out, considerable quantities
of saltwater are produced along with the oil. The proper disposal
of the saltwater is a major concern in the oil production industry
because of its potential environmental effects on land and fresh-
water areas adjacent to oil wells. Saltwater may be permitted to
be discharged in saline bays, estuaries, and offshore by state
regulatory agencies. Sub-surface disposal, either for the purpose
of improved oil recovery or for disposal only, has to meet strin-
gent state regulations.
Blowouts. Blowouts occasionally occur in produc-
ing oil and gas wells. Liquid hydrocarbons and saltwater from
these blowouts are the major contaminants to water bodies.
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Well Stimulation. Well stimulation treatment is
practiced in the United States to improve productivity. There
are two methods used in stimulating a well, namely hydraulic
fracturing and acidizing, which involves pumping acid into a
carbonate or sand formation. The latter technique presents a
potential pollution risk, since it involves pumping several
hundred gallons of hydrochloric acid, organic acids or hydro-
fluoric acid into the producing formation. Upon completion of
the treatment, the well is returned to production status and
the spent acid, which is neutralized by saltwater, is separated
from the crude oil and disposed of along with saltwater produced
from the well.
Sand Production. Production of oil can be
hindered by the influx of formation sand into the wellbore. All
techniques of controlling sand influx require that all of the
sand be cleaned from the wellbore after the well "stands up" and
goes off production. Normally, the sand is oil saturated, thus
it must be cleaned or in the case of offshore production, be
transported ashore to save the offshore waters from a potential
pollution risk.
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Appendix 6-1
MAJOR WATER LAWS
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Law of River Compacts
These compacts are generally made within a river basin
agency and have a direct effect on the member states of that agency
The compacts exist to mediate the problems associated with
allocation of interstate water and the administration of water
rights. Because of these problems and existing or impending
litigation, several affected States have entered into interstate
compacts or requested court apportionment of the affected waters
for the river systems.
The Federal Constitution provides that no State shall
enter into any agreement or compact with another State, or with
a foreign power, without the consent of Congress. Approval by
Congress is required once the compact is ratified by the several
States and usually provides for a Federal representative serving
and reporting on the negotiations.
Upper Missouri River Basin
The interstate compacts which are applicable to the
Fort Union region are the Belle Fourche River Compact and Yellow-
stone River Compact.
"The Belle Fourche River Compact between Wyoming and
South Dakota was approved by the Act of February 26, 1944. Under
this compact water right priorities theretofore established in
one State were to be recognized in the other. Of the remaining
unappropriated water, 90 percent is to be allocated to South
Dakota and 10 percent to Wyoming. Diversions and impoundments
of water in one State for use in the other State are authorized
where State appropriation laws are observed.
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The Yellowstone River Compact among Wyoming, Montana,
and North Dakota was approved by the Act of October 30, 1951.
It divides Yellowstone River Basin Surplus waters (1) in the
Clarks Fork, 60 percent to Wyoming and 40 percent to Montana;
(2) in the Big Horn River, 80 percent to Wyoming and 20 percent
to Montana; (3) in the Tongue River, 40 percent to Wyoming and
60 percent to Montana; and (4) in the Powder River, 42 percent
to Wyoming and 58 percent to Montana. The compact provides
that the three signature States will not singly or jointly take
actions which adversely affect Indian water rights to those
.waters of the Yellowstone River or its tributaties. Diversions
and impoundments in one State for use in another State are
authorized where State appropriation laws are observed. Diver-
sions out of the Yellowstone Basin require the unanimous consent
of all of the compacting States" (NO-055).
Upper and Lower Colorado River Basins
"The Colorado River is perhaps the most regulated river
in the United States, and its utilization is such that very
little usable water now discharges from its mouth into the Gulf
\
of California. The cornerstone is the Colorado River Compact
of 1922, which the seven Basin states negotiated pursuant to the
Act of August 19, 1921 (42 Stat. 171). This Compact divides
the Colorado River Basin into two parts; i.e., the Upper Basin
and the Lower Basin, separated at a point on the river near the
Utah/Arizona border known as Lee Ferry. Article III(a) apportions
to each basin in perpetuity 7.5 m.a.f. of water per year. Article
III(c) provides that any future Mexican water rights, recognized
by the United States, are to be supplied as provided in the Compact
Article III(d) obligates the Upper Basin not to deplete the flow
at Lee Ferry below an aggregate of 75 m.a.f. for any period of 10
consecutive years reckoned in continuing progressive series. In
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1948 the Upper Basin States entered into a compact to divide the
water of the Upper Basin, Article lll(a) apportions among the
States of Arizona, Colorado, New Mexico, Utah, and Wyoming the
Colorado River Compact water:
(1) Arizona, 50,000 a.L:.-
(2) Colorado, New Mexico, Utah, and Wyoming, after
deduction of Arizona's 50,000 acre-feet: Colorado, 51.75 percent,
Ne.w Mexico, 11.25 percent, Utah, 23 percent, and Wyoming, 14
percent.
Article III(b)3 provides that no state shall exceed
its apportioned use in any year when such use deprives another
state of its water during that year. Curtailment in use of
water apportioned is to be determined by the Commission. The
Commission is to determine and allocate losses of water as a
result of reservoir storage. The Upper Colorado River Commission
is created as an interstate administrative agency and its duties
are defined by Article VIII of the Compact. The Compact is not
to interfere with the right or poxi/er of any state to regulate
within its boundaries the appropriation, use, and control of
water apportioned to such state. The failure of any state to
use water shall not constitute a relinquishment or a forfeiture
of the right to use that water. Article XIX provides that the
obligation of the United States to the Indian tribes, the Mexican
Treaty or any rights of the United States to acquire waters in
the Upper Colorado River System are not to be affected" (US-168).
State Water Laws
In all parts of the country, water laws are largely
based on the Riparian Doctrine, the Appropriation Doctrine, or
a combination of both. A riparian right to withdraw water is
based on the ownership of land next to a surface-water body.
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The right is independent of the use or non-use of the water. An
appropriation right is based upon the beneficial use of.the
vv/ater. In other words, the first to appropriate and use the water
has a priority over others who come along and appropriate at a
later time. An appropriation right is independent of the location
of the land with respect to the water.
Figure A-l shows that all states roughly east of the
95th meridian follow the Riparian Doctrine exclusively, with the
exception of Mississippi and Florida. This eastern half of the
country coincides with the area of water surplus shown on Figure
6.1.1. In this humid region, the Riparian Doctrine requires a
land owner to allow the stream to flow by or through his land
in its natural state. Thus, in its strict sense, the right does
not allow for the consumptive use of the water except for small
domestic needs. When irrigation becomes necessary in a riparian
state, the courts modify the doctrine to allow reasonable use in
relation to neighboring users. No riparian user can take all
the water of a. stream and allow none to flow down to his neighbor.
This contrasts sharply with the appropriator's right in other
parts of the country to 'consume all that he needs. The Mountain
States follow .the Appropriation Doctrine exclusively; other states
recognize both doctrines. In those states that recognize both,
the relative importance of each doctrine varies considerably.
In addition to riparian and appropriation rights, there
is a third kind of right based on need. Some examples of this
type are Indian water rights, Federal Reserve rights, and, in
some cases, municipal rights. These rights will be discussed
later.
"In all states, water laws relating to ground waters
generally are based on either the Riparian Doctrine or the
Appropriation Doctrine. The Eastern States generally use the
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FIGURE A-l
SURFACE-WATER LAWS
DOCTRINES RECOGNIZED
:::::::.-;:::: APPROPRIATION
BOTH APPROPRIATION
AND RIPARIAN
-------
English common-law version of the Riparian Doctrine, which
gives absolute ownership of ground water to the land owner.
Fifteen states modify this version and apply the American rule
of ,'reasonable use1, which restricts the landowner's rights in
relation to others. California goes; one step further in the
modification of the Riparian Doctrine with its doctrine of
'correlative rights'. Here, the landowner's use must not only
be reasonable, but must be correlated with the uses of others
during times of shortage. When the supply is limited, use is
restricted to the lands directly overlying the common supply.11
The applicable ground water laws in the United States are shown
on Figure A-2.
"While the Appropriation Doctrine seems to function
easily for surface-water supplies in the arid states, it runs
into some difficulty when it is applied to ground water. The
main reason for this is that ground water is a hidden resource,
whose occurrence and movement are poorly understood by most
people.
Many states, in recent years, have begun to expand their
control and regulation of ground-water use, and this has resulted
in the creation of many special rules and regulations. Some of
these apply to methods of well construction, monitoring of changes
in ground-water levels and ground-water quality, periodic sub-
mission of data on ground-water use, and preventive measures to
minimize contamination and pollution" (GE-058).
Federal Water Laws
The Federal Government was given limited powers relating
to water resource development which are either expressly delegated
or can be reasonably implied from the Constitution. There are a
-256-
-------
FIGURE A-2
GROUND-WATER LAWS
m
*>s>
DOCTRINES RECOGNIZEO
APPROPRIATION
COMMON LAW RIPARIAN
REASONABLE USE
H+H- CORRELATIVE RIGHTS
-------
number of Federal laws that specifically effect the basinr, undiT
consi-deradion. Some of the more important laws are:
Indian Water Rights .
Under a variety of treaties, acts, and executive orders
enacted around the turn of the century, numerous Indian reservations
were created in the central western states.
"Responsibility for the administration of Indian lands
and waters on these reservations rests with the Bureau of Indian
Affairs; however, the rights to the lands and water actually
are vested with the Indians or tribes. The Indians of each
reservation appear to have some legal claim to the use of the
waters located on or flowing through or along its boundaries.
Such rights are read from the treaties and agreements between
the Indian tribes and the United States which have been approved
by acts of Congress or formalized by Executive Orders. The Indian
people claim a right to these waters free from State regulation
and with a priority at least as early as the date the reservation
was recognized or established. The Indian water right priority
is not conditioned on use and may be exercised at any time. The
Indian right can be quantified by fixing the amounts of water needed
to serve the purpose or purposes for which the reservation was
established. (See Winters v. United States, 207 U.S. 564 (1903);
Conrad Investment Co. v. U.S. 161 Fed 829 (9th cir. 1908);
U.S. v. Walker River Irrigation District 104 Fed 334 (9th cir.
1939); U.S. v. Ahtanum Irrigation District 235 Fed 321 (9th cir.
1956); and in closing, Arizona v. California 373; 546-600 (1963).
Thus if the purpose were to promote an agricultural economy, as
has been the case generally, the quantity of water reserved would
be the amount needed to serve the practically irrigable acreage
on the reservation. It also has been urged on behalf of the
Indians that since the purpose of the Indian reservation is to
-258-
-------
provide an economic base for the Indian people residing thereon,
it must follow Chat; the Indian water right is a right to use
the available reservation waters for any beneficial use including
irrigation, livestock, domestic, power, recreation, industrial
and municipal purposes. Nevertheless, several State water
administrators continue to urge that the Indians are entitled
only to that water for which proper application under State
procedures has been made.
"The irrigation of Indian lands was authorized by the
General Allotment Act of February 8, 1887, which also provided
that the Secretary of the Interior should make a just and equal
distribution of the available water among the Indians. Later
the Act of April 4, 1910, made specific provision for irrigation
developments on Indian reservations, and special authorizations
have been provided by Congress for many individual projects.
The right to use Indian water for nonirrigation purposes has
not been litigated or judically determined" (NO-055).
Hexican Wat er Tre a t y
"In the Mexican Water Treaty of 1944, Mexico is guaran-
teed an annual quantity of 1,500,000 a.f. of water from any and
all sources. The water is to be delivered in the limitrophe
section of the river near the international boundary" (NO-055).
Boulder Canyon Acts
The Boulder Canyon Project Act of December 21, 1928
approved the Colorado River compact of 1922 and provided for the
construction of Hoover Dam and the All American Canal in the
Lower Colorado Basin.
The Boulder Canyon Project Adjustment Act of July 19,
1940 (54 Stat. 774), among other things, provided funds J:oi:
-259-
-------
planning for the use of water .in Liu- status of the Upper
Colorado Basin.
Other Acts of Interest:
An excellent review of other Federal laws that effect
the central western energy states is found in the Water Work Group
Report of the Northern Great Plains Resource Program, pgs 29-42
(NO-055). These laws are broken down into the basic areas of
interest in water resource development, including:
(1) Irrigation,
(2) Power,
(3) Navigation,
(4) Municipal and Industrial Water Supply,
(5) Flood Control,
(6) Watershed Protection and Flood Prevention,
(7) Outdoor Recreation, Fish and Wildlife,
(8) Environment,
(9) Water. Quality, and
(10) Planning.
More detailed discussions of legal water-use constraints are also
available in several of the other references cited in the
bibliography (US-168, NA-190, NA-176).
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7.0 AREAS FOR RESEARCH AND DEVELOPMENT
The evaluation of the environmental aspects of the
production and transportation of coal, oil shale, crude oil, and
natural gas leads to the identification of several areas of
research and development needs. These are itemized below.
Ambient Air Quality
The following areas of research are suggested relative
to ambient measurement, the modelling of ambient concentrations,
and the effects and fate of ambient pollutants.
Fugitive particulate emissions, especially
from strip-mined coal and oil shale mining,
are potentially a significant problem but
are presently inia'dequately quantified.
Improved methods for quantifying emissions
from both area sources and mobile sources
are needed. This likely will require im-
proved terrain-dependent models combined
with real-time meteorological input, and an
improved siting rationale for monitors.
Automated particulate analyzers which can
measure short-term particulate averages are .
needed. Some beta particle detectors of this
type are being made available, however they
are almost prohibitatively expensive as a
replacement for Hi-Vol samplers. A possible
approach to this problem might be to
separate the collection and analysis parts,
i.e., have one beta particle analyzer support
many field collection devices.
-261-
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There is a real need for an automated
field hydrocarbon monitor which will pro-
vide a detailed breakdown of the hydrocarbon
species. This would provide an excellent
clue to the sources', . and thus greatly simplify
the control of such emissions. Fugitive
hydrocarbon emissions are a serious problem
as has been discussed earlier. Given
information on species and ratios between
various species, along with compositions of
the various process streams, "fingerprinting"
techniques could be developed to greatly
localize the source of fugitive emissions.
.Better methods of tracing pollutants in the
atmosphere are needed. With a wide number of
easily detectable tracers, the contributions
of many local sources to the air nuality in
an area could be determined, and thus more
easily allow optimum control strategies to
be developed.
:
An air monitoring rationale is needed. This
is with regard to questions on how many moni-
toring stations should be used, how should
they be sited, how they should be moved
seasonally, and so forth. It is presently
difficult to compare results from various
networks due to different bases used in the
original network design.
There is a definite need for improvement in
calibration systems and the long-term stability
of calibration standards. In addition, the
drift rates, mean time between failure, and
temperature sensitivity of most automated
instruments are subject to improvement.
-262-
-------
These needs are related to the need for
better prediction from diffusion models.
The data obtained in identifying sources
with ambient concentrations is needed to
"tune" sophisticated models, including
terrain-dependent models. The "tuned"
models in turn would be of great value in
establishing air monitoring network designs.
Additional data is also needed regarding
the fate of pollutants in the environment,
and their long term effects on plant and
animal life. In particular, the effects of
hydrocarbons and NO , separately and jointly,
X
need to be better understood. If additional
information could be obtained regarding the
role of various hydrocarbon species or
classes of hydrocarbon species in the formation
of photochemical smog, more realistic ambient
air hydrocarbon standards could be developed.
This would allow the expenditures for controls
to be channeled to the most effective areas.
Air Emissions
The following is a list of the areas which appear to
need further research and development for the improvement of
the control of certain emission sources within the industries
of the modules described in Section 3.0.
• Diesel engine manufacturers have been engaged
in research on the reduction of nitrogen oxides,
hydrocarbons, and particulates from stationary
and mobile diesel engines. Continuation and
expansion of the following research and develop-
ment programs appear useful in reducing emissions of
-263-
-------
these pollutants : (1) development
of inhibitors to NO formation that could
A.
be introduced into the combustion process
through a fuel additive, (2) engine refinements
such as derating.engine output, variable com-
pression ratio, valve and/or injection modifi-
cation, and use of precombustion chambers
and turbulence chambers, and (3) reduction of
peak combustion temperature by means of
introduction of an inert material such as ex-
haust gas or water.
Reduction of NO emissions from stationary
x
natural gas fueled engines could be accom-
.plished with two-stage combustion. Further
investigation into the use of the precombus-
tion chamber which provides a type of two-
stage combustion is needed. Also, more
work is needed in improving the water
injection systems for gas engines. Improvp.H
flue gas recirculation systems are needed.
Examination of the application of combus-
tion modification techniques which would
be helpful in controlling NO emissions
X
from coal-fired thermal dryers is needed.
More study is needed on the cost-effect-
iveness of combustion modifications for
process heaters. For the smaller size
process heaters a technological break-
through is required which would provide a
novel type of combustion mechanism which
will emit NO at lower levels. Applica-
X
tion of fluid bed combustion of natural
gas is one possibility that could be
investigated.
-264-
-------
The emission of methane and dust from
underground mining operations is an oper-
ating hazard. It is also an environ-
mental problem for the mining industry.
Ventilation is the current control
method for these emissions. More
reliable methods for control of these
emissions are needed, however. Some
areas of research could be (1) a series of
investigations on the use of horizontal
and vertical holes to remove methane from
virgin coal and (2) the use of water infusion
to block methane flow at active face areas. .
Both methods potentially would allow
ventilation air rates to be reduced.
Dust generated by these high air rates
could accordingly be reduced.
Currently there exists no technology for the
removal of H2S from gas systems at low pres-
sure and with low H2S concentrations such as
those from the in-situ production of oil
shale. A process is needed which can effi-
ciently remove this dangerous component from
such gas systems. These gas systems also
contain low concentrations of hydrocarbons.
Incinerating or venting such large volumes
of low Btu gas (approximately 30 Btu/cu ft)
is often uneconomical or undesirable
environmentally. Some means of removing
these hydrocarbons is needed.
-265-
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Water Monitoring
There is a need for automated field analyzers to
inspect all critical effluent parameters for these modules.
Reliable automated analyzers would greatly reduce manpower
requirements in collecting required data. Also needed are auto-
mated data acquisition systems to indicate trends in data, to
indicate where regulations have been exceeded, and to provide
summary reports of collected data.
Water Effluent Control
The provisions of the Clean Water Act will require
zero discharge or zero impact of certain industrial facilities
in future years. Development work is needed to determine the
applicability of such technologies as ion exchange, membrane
separation processes, and forced evaporation processes to
effluent streams and in-process streams to obtain maximum and
cost effective water reuse.
Solid Wastes
Large volumes of solid wastes are generated in coal
and oil shale mining operations. The chemical composition of
typical solid wastes should be examined in detail to determine
the content of hazardous or potentially hazardous species. The
solubility of these species should be determined, and the long-
term chemical stability-solubility of these materials in a
landfill environment should be studied, including backfill in
mined areas.
The movement and attenuation of any soluble hazardous
species in various types of soils should be examined. Also
-266-
-------
the long-term stability in the landfill environment of liners
for disposal sites should be examined.
Hazardous Chemicals
A comprehensive and cost effective sampling and ana-
lytical strategy is needed for gaseous, liquid, and solid
effluents. The objective of this effort would be to provide a
means of detecting potentially hazardous materials in these
effluents. Field testing to verify these strategies will also
be needed.
Cost Impacts
Studies are needed to indicate trends in plant costs
as functions of increased emissions controls and improved fuel
economy. Because of increasing energy costs, the trends in new
plant designs are moving toward greater fuel utilization. This
has the secondary effects of reducing total gaseous, liquid,
and solid effluents and total cooling water requirements.
While energy conservation is in itself a desirable
feature, concurrent cost savings can in some cases cover the
expense of added control equipment. Engineering studies of
these various cost alternatives are needed.
-267-
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REFERENCES
AD-021 Advances in Pipelining. Proceedings, Session 10, 19th
Canadian Chemical Engineering Conference, Edmonton^
Alberta, October 1969, Ottawa. Ontario. Canadian Chemical
Engineering Society.
AM-115 American Waterways Operators, Inc., Big Load Afloat.
U.S. Domestic Water Transportation Resources, Washington,
D.C. (1973).
AU-006 Aude, T. C., et al., "Slurry Piping Systems: Trends..."
Chem. Eng. 15. 74-90 (1971).
AU-019 Aude, T. C., T. L. Thompson, and E. J. Wasp, "Economics
of Slurry Pipeline Systems," Presented at the Hydro-
transport 3, Colorado School of Mines, Golden, CO
(May 1974).
BA-210 "Basic Technology," Chem. Eng. Deskbook Issue 27 April
1970, 165.
BA-224 Battelle-Columbus Laboratories, Topical Report on
Energy Requirements for the Movement of Intercity
Freight, Columbus. Ohio (1972).
BA-233 Bain, A. G. and S. T. Bonnington, The Hydraulic Trans-
port of Solids by Pipeline, Internat'l. Series of
Monographs in Mechanical Engineering, Vol. 5, Pergamon,
NY (1970).
BA-234 Battelle-Columbus and Pacific Northwest Labs., Environ-
mental Considerations in Future Energy Growth, Con-
tract No. 68-01-0470, Columbus, OH (1973).
CH-182 Chilingar, George V. and Carrol M. Beeson, Surface
Operations in Petroleum Production, NY, American
Elsevier (1969).
CO-129 Council on Environmental Quality, Energy and the
Environment; Electric Power, Washington, D.C. (1973).
CO-168 Coalgate, Jerry L., David J. Akers, and Russell W.
Frum, Gob Pile Stabilization, Reclamation, Utilization,
Interim Report for period:February 1972 - May 1973,
Morgantown, West Virginia, Coal Research Bureau,
School of Mines, West Virginia, University (1973).
CO-175 Colony Development Operation, Atlantic Richfield Co.,
Operator, An Environmental Impact Analysis for a Shale
Oil Complex at Parachute Creek, Colorado, Vol. 1,
Part 1 (1974).
-269-
-------
REFERENCES (Cont.)
CO-197 Coal Pipeline Act of 1974, 93rd Congress, 2nd Session,
Report No. 93-1072, Washington, D.C., GPO (1974).
CO-244 "Coal-Slurry Pipelines May Aid Energy Race," Chem.
Eng. 81 (14) (1974).
DE-148 "Degasification of Coal Beds - A Commercial Source of
Pipeline Gas," AGA Monthly 56 (1), 4 (1974).
DU-061 Durand, R.,"Basic Relationships of the Transportation
of Solids in Pipes - Experimental Research," Proc.
Minnesota International Hydraulic Convention 1953.
EN-071 Environmental Protection Agency, Compilation of Air
Pollutant Emission Factors, 2nd ecf. with supplements,
AP-42, Research Triangle Park, NC (1973).
EN-096 Environmental Protection Agency, Processes, Procedures,
and Methods to Control. EPA-430/9-73-011, EPA, Washing-
ton, D.C. (1973).:
EN-204 Engineering-Sciences, Inc., Air Quality Assessment of
the Oil Shale Development Program in the Piceance
Creek Basin, McLean. VA (1974).
EN-219 Environmental Protection Agency, "State Standards for
Acidity Alkalinity" (Issued August 1972), Env. Reporter,
State Water Laws, Vol. 1 (1973).
EN-220 Environmental Protection Agency, Office of Air Quality
Planning and Standards, Background Information for
Standards of Performance: Coal Preparation Plants, 2
vols. - Vol. I, Proposed Standards; Vol. 7~, Summary
of Test Data, EPA, Research Triangle Park, NC (1974).
FE-076 Federal Energy Administration, Project Independence
Report. Washington, D.C. (1974).
FE-084 Federal Power Commission, National Gas Survey, 5 vols.
Vol. 1, FPC Report; Vol. 2, Supply Task Force Reports;
Vol. 3, Transmission Task' Force Reports; Vol. 4,
Distribution Task Force Reports; Vol. 5, Special
Reports, Washington, D.C. (1973).
FR-121 Frick, Thomas C. and R. William Taylor, eds., Petroleum
Production Handbook. 2 vols., McGraw-Hill, NY (1962).
-270-
-------
REFERENCES (Cont.)
GA-104 Galland, J. M. and T. F. Edgar, Analysis and Modeling
of Underground Coal Gasification Systems, Energy
Systems Labs. Rept. ESL-13. Univ. of Texas, Dept. of
Chemical Engineering, Austin, TX (1973).
GE-050 General Electric Co., Transportation Systems Div. ,
Application of Diesel - Electric Locomotives, Erie, PA
(1974).
GE-058 Geraghty, James J., et al., Water Atlas of the United
States, Water Information Center, Port Washington,
NY (1973).
GL-038 Glover, Thomas C., Unit Train Transportation of Coal:
Technology and Description of Nine Representative
Operations, BuMines, Washington, D.C. (1970).
GO-055 Govier, G. W. and K, Aziz, The Flow of Complex Mixtures
in Pipes. Van Nostrand, NY (1972).
HA-246 Hale, Dean, "Artie Energy Holds Great Promise,"
Pipeline Gas J. 1974 (July).
HI-083 Hittman Associates, Inc., Environmental Impacts, Ef-
ficiency, and Cost of Energy Supplied by Emerging Tech-
nologies, Draft report on Task 5, low Btu gasification
of coal and Task 6, high Btu gasification of coal,
Columbia, MD (February 1974).
HI-097 Hill, Robert W., "Dust Control With Collectors on
Continuous Miners," Mining Cong. J. 60 (7), 46 (1974).
HO-172 Holm, L. W., "Residual Oil-Can we Recover it Economically?"
Petroleum Engr.. 45 (13), 17 (1973).
HU-088 Huneke, John M., Statement to Committee on Interior
and Insular Affairs, U.S. Senate on S.2652 (Title IV)
ammendment, (11 June 1974).
IN-056 R. C. Barras, "Instrumentation for Monitoring Air
Quality," ASTM Special Technical Publication 555 (1974).
KA-124 Katz, Donald L., et al., Evaluation of Coal Conversion
Processes to Provide Clean Fuels, EPRI 206-0-0. Final
Report, Univ. of Michigan, College of Engineering,
Ann Arbor, Michigan (1974).
-271-
-------
REFERENCES (Cont.)
KA-134 Katz, L., et al., "Transmission to Market," Handbook
of Natural Gas Engineering. McGraw, NY (19597.
LO-084 "Longest Slurry Pipeline Passes Tests," Elec. World 15
February 1971.
MC-096 McNay, Lewis M., Coal Refuse Fires, An Environmental
Hazard, BuMines, Washington, D.C.(1971).
MI-146 Million, Charles L., "Conoco Technology Curbs Pro-
duction Pollution," Petroleum Engr. 4_5 (9), (1973).
MO-103 Montfort, J. G., "Black Mesa Coal Slurry Line is
Economic and Technical Success," Pipeline Ind. 1972
(March).
MO-114 Morrison, Joseph N., Jr., "Controlling Dust Emissions
at Belt Conveyor Transfer Points," Trans. Soc. Mining
Engrs. AIME 250, 47 (1971).
MO-126 Montfort, J. G., "Black Mesa System Proves Coal
Slurry Technology," Pipe Line Ind. 1974 (May).
MS-001 MSA Research Corporation, Hydrocarbon Pollutant
Systems Study, Vol. 1, Stationary Sources, Effects,
and Control, Evans City, PA (1972).
NA-004 National Air Pollution Control Techniques Advisory
Committee, Control Techniques for Carbon Monoxide
Emissions from Stationary Sources, NAPCA Pub. No. AP-65,
iMarch 1970).
NA-005 National Air Pollution Control Techniques Advisory
Committee, Control Techniques for Nitrogen Oxide
Emissions from Stationary Sources, NAPCA Pub. No. AP-67
(March 1970).
NA-029 National Air Pollution Control Administration, Control
Techniques for Particulate Air Pollutants, NAPCA Pub.
No. AP-51 (January 1969T
NA-031 National Air Pollution Control Administration, Control
Techniques for Carbon Monoxide. Nitrogen Oxide and Hydro-
carbon Emissions from Mobile Sources, HEW. Public
Health Service, NAPCA Pub. No. AP-66 (March 1970).
-272-
-------
REFERENCES (Cont.)
NA-032 National Air Pollution Control Administration,
Control Techniques for Hydrocarbon and Organic Solvent ro-
Emissions from Stationary Sources. Washington. D.C.
(1970).
NA-113 J. S. Nader, "Development in Sampling and Analysis,
Instrumentation for Stationary Sources," Journal of
the Air Pollution Control Association, Vol. 23, No. 7,
p. 587 (1973).
NA-176 National Petroleum Council, U. S. Energy Outlook, A
Report of the National Petroleum Councils Committee on
U. S. Energy Outlook, Washington, D.C., 1972.
NA-190 National Petroleum Council, U. S. Energy Outlook: Water
Availability. Washington, B.C., 1973.
NG-002 "NG/SNG Handbook," Hydrocarbon Processing 50 (4),
93-122 (1971).
NI-036 Nielson, George F., ed., 1974 Keystone Coal Industry
Manual. Mining Publications, McGraw-Hill, NY (1974).
NO-055 Northern Great Plains, Water Work Group, Report,
U.S. Bureau of Reclamation, Helena, Montana (1974).
PE-097 Petroleum Extension Service, Univ. of Texas, and
Pipeline Contractors Assoc., A Primer of Pipeline
Construction. 2nd ed., Austin, TX (1966).
PE-098 Petroleum Extension Service, Univ. of Texas,
Oil Pipeline Construction and Maintenance, Vol. 2_,
2nd Ed.,Series on Oil Pipeline Transportation
Practicing, Austin, TX (1973).
PE-120 PEDCO-Environmental Specialists, Inc., Investigation
of Fugitive Dust—Sources, Emissions ancf Control,
Contract No. 68-02-0044, Task Order 9, Cincinnati, OH
(1973).
PI-044 Pipeline Engineer International, Slurry Pipelines (1969).
PR-052 Process Research, Inc., Industrial Planning and Research,
Screening Report. Crude Oil and Natural Gas Production
Processes^Final Report, Contract No. 68-02-0242,:
Cincinnati, OH (1972).
-273-
-------
REFERENCES (Cont.)
PR-075 Pratt and Whitney Aircraft, Aeronautical Vest-Pocket
Handbook, 10th ed., 1964.
RA-119 Radian Corporation, A Program to Investigate Various
Factors in Refinery Siting.Final Report, Austin, Tx.,
1974.
RI-063 Rice, Richard A., "System Energy as a Factor in Con-
sidering Future Transportation," Presented at the ASME
Winter Annual Mtg., NY (1970).
SC-194 Schmidt, R. A. and W. C. Stoneman, A Study of Surface
Coal Mining in West Virginia, Final Report, SRI Project
1293, Stanford Research Inst., Menlo Park, CA (1972).
SK-024 Skelland, A.- H. P., Non-Newtonian Flow and Heat Transfer.
Wiley, NY (1967).
ST-166 Stefanko, Robert R. V. Ramani, and Michael R. Ferko,
AnAnalysis of Strip Mining Methods and Equipment
Selection, OCR R & D 61. Int. Rept. 7, Contract No.
14-01-0001-390, Pennsylvania State Univ., College
of Earth and Mineral Sciences (1973).
ST-188 Steppanoff, Alexey J., Gravity Flow of Bulk Solids and
Transportation of Solids in Suspension. Wiley, NY (1969).
ST-204 Stillwagon, R. E., "Economic Aspects of Electrically
Driven Compressor Stations for Natural Gas Pipelines,"
Presented at the IEEE Pet. Chem. Ind. Conf., 20th
Annual,Houston, TX, (September 1973).
TE-172 Temple, R. W. and R. N. DiNapoli, "Ethane and LPG
Recovery in LNG Plants," Hydrocarbon Proc. 49(4), 89
(1970).
TR-024 "Traditional Hazards Bought at Gas Plants." Oil Week
15 November 1971. 36.
TR-049 TRW Systems Group, Underground Coal Mining in the
United States, Research and Development ProgramsT
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US-083 U.S. Dept. of the Interior, River of Life. Water: The
Environmental Challenge, Conservation Yearbook No.67
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REFERENCES (Cont.)
US-093 U.S. Department of the Interior, Final Environmental
Statement for the Prototype Oil Shale Leasing Program,
6 Vols., Washington, D.C. (1973).
US-124 U.S. Dept. of Commerce, Maritime Administration,
Maritime Administration Tanker Construction Program,
Final Environmental Impact Statement, Washington, D.C.,
EIS-AA-73-0725-F.
US-144 U.S. Bureau of Mines, Minerals Yearbook 1972. Vol. 1.
Metals, Minerals and Fuels.Washington, D.C., 1974.
US-168 U.S. Dept. of the Interior, Water for Energy Manage-
ment Team, Report on Water for Energy in .the Upper
Colorado River Basin (1974).
VA-093 Van Norman, Jerry L., "New Ideas Are Evolving in
Compressor Station Piping Design," Pipeline Gas J. 1972
26 (November 1972).
WA-043 Wasp, Edward J., Terry L. Thompson, and T. C, Aude,
"Initial Economic Evaluation of Slurry Pipeline Systems,"
Proc. ASCE, Transportation Eng. J. 97 (TE 2), 271-9
(1971^.
WA-125 Wasp, E. J,, et al,, "Deposition Velocities, Transition
Velocities, and Spatial Distribution of Solids in Slurry
Pipelines," Presented at the First International Conf.
on Hydraulic Transport of Solids in Pipes, Cranfield, .
Bedford, England (September 1970).
WA-126 Wasp, E. J,, T, L, Thompson, and T, C, Aude, "Slurry
Pipeline Economics and Application," Paper K3,
Proceedings. First Internat' 1., Conference on Hydraulic
Transport of Solids in Pipes, September 1970, British
Hydromechanics Research Assoc., Cranfield, Bedford,
Eng. (1971).
WA-140 Wasp. E. J., T. L. Thompson, and T. C. Aude, "Pipeline
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WA-153 Wasp, E. J. and R, H, Derammelaere, "International
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-275-
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REFERENCES (Cont.)
WE-134 "Wet In Situ Combustion Aids Recovery of Oil, AICHE
Told," Oil Gas J. (3 April 1972)..
WH-036 Whittle, T. C., Private Communication, General Electric
Co., Transportation;Systems Div. (11 September 1974).
ZA-044 Zabetakis, M. G. , Methane Control in U.S. Coal Hines-
An Overview, Pittsburgh Mining and Safety Research
Center, Bureau of Mines, Pittsburgh, PA.
ZI-014 Zimmerman, R. E., "Economics of Coal Desulfurization,"
CEP 62 (10), 61 (1966).
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CONVERSION FACTORS
The references used in developing this report generally
stated flows, capacities, weights, etc. in English measurement
units. The following table can be used to convert these measure-
ments to metric units.
To Convert From
Ib
bbl
lb/103 bbl
scf
ton
gal
lb/103 gal
Ib/ton
Btu/bbl
ton
Btu
To
kg
1
kg/103l
Nm3
MT
1
kg/103l
kg/MT
kcal/1
kg
kcal
Multiply By
0.454
159.0
.002855
0.0283
0.9072
3.785
0.1199
0.5004
1.585
907.2
0.252
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TECHNICAL REPORT DATA
t'Plcasc read Instructions on tlii! reverse before completing)
1. REPORT NO.
3PA-6?0/2-76-064
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Atmospheric Pollution Potential from Fossil Fuel
Resource Extraction, On-Site Processing, and
Transportation
5. REPORT DATE
March 1976
6. PERFORMING ORGANIZATION CODE
' AUTHOR(S)E.C.Cavanaugh, G.M.Clancy, J.D.Colley,
P.S.Dzierlenga, V.M.Felix, D.C.Jones, and
T. P. Nelson
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
P.O. Box 9948
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADD-042
11. CONTRACT/GRANT NO.
68-02-1319, Task 19
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 1-12/75
14. SPONSORING AGENCY CODE
EPA-ORD
is. SUPPLEMENTARY NOTES project officer for this report is L.Lorenzi, Jr. , Mail Drop 61,
Ext 2851.
. ABSTRACT
The repO1;t describes the processes and operations employed for the pro-
duction, on-site processing, and transportation of coal, oil, oil shale, and gas.
Typical processing sequences are represented by modules. For each module,
identification and quantification of potential atmospheric emissions is achieved
through the use of existing information. A review o? emission source monitoring
methods, as well as a study of possible source control methods, is presented.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATi Field/Croup
Air Pollution
Fossil Fuels
Extraction
Processing
Transportation
Monitors
Air Pollution Control
Stationary Sources
Resource Extraction
13B
21D,08G
07A,13H
15E
14B
18. DISTRIBUTION STATEMENT
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
294
Unlimited
?0 SFCURITY n flSS iTliis
Unclassified
•>•>. PRICE
EPA Form 2220-1 (9-73)
-279-
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