EPA-908/4-77-010B
Emissions
From Synthetic Fuels
Production Facilities
VOLUME II
REPORT
U.S. Environmental Protection Agency
Region Mill
Derwr, Colorado
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DCN# 77-100-092-01
EMISSIONS FROM SYNTHETIC FUEL
PRODUCTION FACILITIES
VOLUME II
September 1977
Prepared for:
Environmental Protection Agency
Region VIII
Denver, Colorado
By:
J. D. Colley, W. A. Gathman, M. L. Owen
Radian Corporation
Austin, Texas
TS-6a
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FOREWORD
The two volumes comprising this document present a
study of emissions from synthetic fuel production facilities,
performed under EPA Contract No. 68-01-3535. The synthetic
fuel production facilities include oil shale and coal extrac-
tion, oil shale processing, and coal gasification.
The report presents the best available information.
Most of the data for the TOSCO II oil shale process have been
previously published and represents widely accepted estimates
for the process. Accepted published data for the Union Oil
and Paraho oil shale processes are not presently available.
The emissions from these processes were estimated in this re-
port based upon similar processes and developer information.
Accepted data for the Lurgi coal gasification process have
been previously published. As more information on these pro-
cesses is released, the contents of this report will be updated
or subsequent reports will be prepared to present this data.
This work was conducted under the direction of
Mr. Terry L. Thoem, Project Officer, Environmental Protection
Agency, Region VIII, Denver, Colorado. This study is comple-
mented by another Radian study, "Atmospheric Pollution Poten-
tial from Fossil Fuel Resource Extraction, On-Site Processing,
and Transportation", EPA-600/2-76-064. The fuel resources
considered in that report are coal, oil shale, oil, and gas.
11
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TABLE OF CONTENTS
Page
1.0 INTRODUCTION 1
2.0 OIL SHALE PROCESSING 3
2.1 Oil Shale Extraction 3
2.1.1 Oil Shale Surface Mining 5
2.1.1.1 Module Basis 8
2.1.1.2 Module Description 8
2.1.1.3 Module Emissions 11
2.1.2 Underground Room-and-Pillar Oil 15
Shale Mining
2.1.2.1 Module Basis 18
2.1.2.2 Module Description 18
2.1.2.3 Module Emissions 21
2.1.3 Oil Shale Sizing Operations 22
2.1.3.1 Module Basis 24
2.1.3.2 Module Description 25
2.1.3.3 Module Emissions 27
2.2 Shale Oil Processing 29
2.2.1 TOSCO Process 38
2.2.1.1 Module Basis 43
2.2.1.2 Module Descriptions 43
2.2.1.3 Module Emissions 50
2.2.2 Paraho Process 57
2.2.2.1 Module Basis 59
2.2.2.2 Module Description 59
2.2.2.3 Module Emissions 63
2.2.3 Union Oil Process 68
2.2.3.1 Module Basis 72
2.2.3.2 Module Description 72
2.2.3.3 Module Emissions 77
2.2.4 Trace Element and Organic Emissions
From Oil Shale Processing 81
111
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TABLE OF CONTENTS (Cont'd)
Page
2.2.4.1 Trace Elements 82
2.2.4.2 Trace Organics 91
3 .0 COAL GASIFICATION PROCESSING 101
3 .1 Coal Surface- Mining 101
3.1.1 Module Basis 105
3.1.2 Module Description 105
3.1.3 Module Emissions 108
3.2 Coal Gasification 112
3.2.1 High-Btu Lurgi Gasification 113
3.2.1.1 Module Basis 120
3.2.1.2 Module Description 121
3.2.1.3 Module Emissions 125
3.2.2 Low- and Medium-Btu Gasification ... 131
3.2.2.1 Module Basis 132
3.2.2.2 Module Descriptions 132
3.2.2.3 Module Emissions 132
3.2.3 Trace Element and Organic Emissions
from Coal Gasification 135
3.2.3.1 Trace Elements 135
3.2.3.2 Trace Organics 148
4.0 PROCESS WATER SYSTEMS 160
4.1 TOSCO II Process Water System 160
4.1.1 Inlet Water 162
4.1.2 Plant Water Stream Characterization. 163
4.1.3 Potential Problems 169
4.2 Lurgi Process Water System 171
4.2.1 Inlet Water 173
4.2.2 Process Water Stream Characteriza-
tion 175
4.2.3 Potential Problems 178
iv
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TABLE OF CONTENTS (Cont'd)
Page
4.3 Summary 180
BIBLIOGRAPHY 182
APPENDIX 190
1.0 INTRODUCTION 191
2. 0 RADIAN EQUILIBRIUM PROGRAM 192
3.0 RADIAN AQUEOUS INORGANIC EQUILIBRIUM
PROGRAM 198
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LIST OF FIGURES
Page
Figure 2.1-1 Steps Involved in Oil Shale Surface Mining- 7
Figure 2.1-2 Shale Sizing Operations 23
Figure 2.2-1 TOSCO II Retorting Procedure 39
Figure 2.2-2 Upgrading and By-Product Recovery Facilities 42
Figure 2.2-3 TOSCO II Shale Oil Module 46
Figure 2.2-4 The Paraho Retort Process 58
Figure 2.2-5 Union Retort B Flow Diagram 69
Figure 2.2-6 Union Oil Shale Oil Module 75
Figure 2.2-7 IGT Hygas Process for Electrothermal
Gasification, Showing Pretreatment, Hydro-
gasification, and Electrothermal Stages 85
Figure 2.2-8 Hypothetical Structural Model of Green River
Oil Shale Kerogen 92
Figure 3.1-1 Steps Involved in Area Stripping Operation- 106
Figure 3.2-1 General Flow Diagram of Lurgi High-Btu
Gasification 114
Figure 3.2-2 The Lurgi Gasifier 116
Figure 3.2-3 Overall Lurgi Flow Diagram 123
Figure 3.2-4 Disposition of Streams from the Rectisol
Unit 127
Figure -3.2-5 General Flow Diagram of Lurgi Low- or
Medium-Btu Gasification 133
Figure 3.2-6 Comparison of Environments in a Boiler and
a Coal Gasifier 137
Figure 3.2-7 IGT Hygas Process for Electrothermal
Gasification, Showing Pretreatment, Hydro-
gasification, and Electrothermal Stages 142
Figure 4.1-1 Major Water Streams for the TOSCO II
Process 161
Figure 4.1-2 Cooling System for the TOSCO II Process 165
.Figure 4.1-3 Relationship Between Slowdown Rate and
Cycles of Concentration 167
Figure 4.1-4 Calcium Sulfate Scaling Profile for the
Colony Cooling Tower 170
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LIST OF FIGURES (Cont'd)
Figure 4.2-1 Major Water Streams for a Lurgi Coal
Gasification Plant 172
Figure 4.2-2 Flow Rates for a Lurgi Water System 177
Figure 4.2-3 Calcium Sulfate Scaling Profile for
the Lurgi Cooling Tower 179
vii
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LIST OF TABLES
PAGE
Table 2.1-1,
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
2.1-2.
2.1-3.
2.1-4.
2.1-5.
2.1-6.
2.1-7.
2.1-8.
2.1-9.
2.2-1.
2.2-2.
2.2-3,
2.2-4,
2.2-5
2.2-6
2.2-7
2.2-8
Typical Consumption of Oil Shale
Sections Averaging 25 Gallons of
Oil Per Ton in the Mahogany Zone
of Colorado and Utah
Summary of Environmental Impact
from Surface Mining of Oil Shale -
Daily Energy Requirements for Oil
Shale Surface Mining
Atmospheric Emissions from Oil
Shale Surface Mining
Summary of Environmental Impact
from Room-and-Pillar Mining of
Oil Shale
Daily Energy Requirements for
Oil Shale Underground Mining
Atmospheric Emissions from
Underground Oil Shale Mining
Summary of Environmental Impact
from Oil Shale Sizing
Atmospheric Emissions from
Oil Shale Sizing
Characteristics of Crude Shale Oils
Characteristics and Yields of
Untreated Retort Gases
Characteristics of Upgraded
Shale Oils
Summary of Environmental Impact
from TOSCO II Retorting and Upgrading
Module
Preliminary Fuel Balance for
Commercial Shale Oil Complex
TOSCO II Shale Oil Module (7950 m3/day)
Air Emissions and Stack Parameters
Summary of Environmental Impact from
Paraho Retorting and Upgrading Module -•
Paraho Shale Oil Module (7950 m3/day)
Air Emissions and Stack Parameters
4
9
10
12
19
20
22
25
28
35
37
38
44
47
51
60
65
Vlll
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LIST OF TABLES
(Continued)
PAGE
Table 2.2-9. Summary of Environmental Impact from
Union Oil Retorting and Upgrading
Module -^ 73
Table 2.2-10. Union Oil Shale Oil Module (7950 m3/day)
Air Emissions and Stack Parameters 78
Table 2.2-11. Elemental Concentration of
Green River Oil Shale 82
Table 2.2-12. Trace Elements Concentration of a Coal
Gasifier Calculated on a Raw Coal Basis 86
Table 2.2-13. Fate of Trace Elements in Oil Shale
and Similar Processes 89
Table 2.2-14. Chemical Analysis of Kergoen 91
Table 2.2-15. Toxic and Hazardous Substances Likely
to be Emitted by Industrial Boilers 94
Table 2.2-16. Principal Compounds Obtained from
Coal Tar 95
Table 2.2-17. Compounds Obtained from Coal Tar 95
Table 2.2-18. POM Compounds Identified in Benzene
Extract of Carbonaceous Shale Coke from
Green River Oil Shale 98
Table 2.2-19. BaP Content of Process Shale and
Common Materials 99
Table 2.2-20. Benz(a)pyrene Concentrations in
Oil Shale Related Materials 99
Table 2.2-21. BaP Content of Petroleum Products 100
Table 3.1-1. Summary of Environmental Impact
From Coal Strip Mining 105
Table 3.1-2. Daily Energy Requirements for
Western Coal Surface Mining 108
Table 3.1-3. Atmospheric Emissions from Coal
Surface Mining 109
Table 3.1-4. Atmospheric Emissions from
Diesel-Power Equipment 111
Table 3.2-1. Synthesis Gas Composition for an
Oxygen Blown Lurgi Gasifier 118
IX
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LIST OF TABLES
(Continued)
PAGE
Table 3.2-2. Summary of Environmental Impact from
Lurgi High-Btu Coal Gasification 121
Table 3.2.3. Gasification Coal Analyses 121
Table 3.2.4. Composition of the SNG Product from
Design Basis Lurgi Plant 122
Table 3.2-5. Process Atmospheric Emissions from
High-Btu Lurgi Coal Gasification 126
Table 3.2-6. By-Product Storage Emission Losses 129
Table 3.2-7. Pump Seal Emissions 129
Table 3.2-8. Fugitive Emissions from Valves 130
Table 3.2-9. Summary of Environmental Impact
from Low-Btu Lurgi Gasification 134
Table 3.2-10. Summary of Environmental Impact
from Medium-Btu Lurgi Gasification 134
Table 3.2-11. Trace Element Concentration in
Typical Western Coal 136
Table 3.2-12. Fate of Selected Trace Elements
in Lurgi Gasifier 140
Table 3.2-13. Trace Element Concentration of Char
Calculated on Raw Coal Basis 143
Table 3.2-14. Trace Elements in Condensate from an
Illinois No. 6 Gasification Test 144
Table 3.2-15. Trace Element Emissions from a
Coal Gasification Plant 145
Table 3.2-16. Volatility of Trace Elements in Coal -- 146
Table 3.2-17. Toxic and Hazardous Substances Likely
to be Emitted by Industrial Boilers 150
Table 3.2-18. Principal Compounds Obtained from
Coal Tar 151
Table 3.2-19. Compounds Obtained from Coal Tar 151
Table 3.2-20. Benzpyrene Analysis Coal Tar from
Coke Oven 152
Table 3.2-21. Compounds Tentatively Identified in
Waste Effluent of Coal Gasification
Pilot Plant 153
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LIST OF TABLES
(Continued)
PAGE
Table 3.2-22. Components in Synthane Gasifier
Gas, ppm 154
Table 3.2-23. Mass Spectrometric Analyses of the
Benzene-Soluble Tar from the Synthane
Process 155
Table 3.2-24. Byproduct Water Analysis from Synthane
Gasification of Various Coals 156
Table 4.1-1. Colorado River Composition 163
Table 4.1-2. Oil Shale Cooling System Flowrates 166
Table 4.2-1. North Platte River Composition - Winter 173
Table 4.2-2. Deep Well Water Composition 174
Table 4.2-3. Treated Makeup to Water System 175
xi
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1.0 INTRODUCTION
In this volume of the report, process descriptions of
the synthetic fuels processes are presented along with detailed
discussions of the analytical procedures used to define indivi-
dual modules and to identify their emissions. Descriptions are
given for both the resource extraction processes and the synthe-
tic fuel conversion processes. Also included in the report are
qualitative discussions of trace element and organic emissions
and effluents. In addition, the water systems are analyzed for
potential problems in achieving "zero discharge" of water efflu-
ents .
The information presented in this document is organ-
ized into three sections. Oil shale processing is discussed
first in Section 2.0. Oil shale extraction modules are presen-
ted for surface mining and underground room-and-pillar mining.
A module for oil shale sizing is also included. Then oil shale
retorting- and upgrading modules are discussed. The types of
oil shale processes studied are the TOSCO II process, the Para-
ho process and the Union Oil process .
In Section 3.0 coal gasification processing is dis-
cussed. Included are a coal strip mining module and Lurgi coal
gasification modules for the production of low-, medium-, and
high-Btu gas.
All of the synthetic fuels process facilities are
designing for "zero discharge" of water effluents. Section 4.0
examines the proposed water systems for the TOSCO II process
and the Lurgi process for potential problems in achieving zero
discharge as well as the potential advantages and disadvantages
of treatment of water effluents to a quality which may be dis-
charged.
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Module Basis
Module sizes for the synthetic fuels processes were
selected to represent typical sizes anticipated for a commercial
facility. These module sizes also allow the processes to be
compared on an energy output basis.
Air emissions, water effluents, energy recovery, and
process requirements for water, manpower, and ancillary energy
are discussed for each of the modules.
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2.0 OIL SHALE PROCESSING
This section of the report presents a description of
oil shale surface and room-and-pillar mining along with retorting
technologies of the TOSCO II, Paraho, and Union Oil processes.
Process modules are defined and emissions from the modules are
assessed.
2.1 Oil Shale Extraction
Oil shale deposits in the Colorado River Valley of the
Rocky Mountains are considered to be the richest deposits of oil
shale in the world. These deposits represent a resource of an
estimated two trillion barrels of oil. While development of an
oil shale industry in the U.S. has been considered in the past,
the discoveries of crude oil in Pennsylvania and later in Texas
made oil shale extraction uneconomical (UN-025). Outside the
U.S., oil shale has been commercially mined and processed into
liquid fuels for many years, usually in areas where domestic
supply of crude oil was limited and imports were insufficient.
Oil shale is a marlstone-type inorganic material con-
taining an organic polymer known as kerogen. Kerogen is only
slightly soluble in conventional organic solvents. When heated,
however, the kerogen decomposes to yield hydrocarbon gases and
liquids. These hydrocarbon products can be processed and refined
in much the same manner as petroleum. Typical organic and mine-
ral content for oil shale containing 25 gallons of oil per ton
of shale is given in Table 2.1-1.
There are two major options considered for oil shale
development: 1) mining followed by surface processing of the
oil shale and shale oil, and 2) in situ (in place) processing.
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Development of either method is expected to proceed in a modular
fashion. A full scale commercial size plant is not expected to
be in operation prior to the middle or late 1980's.
TABLE 2.1-1. TYPICAL CONSUMPTION OF OIL SHALE SECTIONS
AVERAGING 25 GALLONS OF OIL PER TON IN THE
MAHOGANY ZONE OF COLORADO AND UTAH
Weight-percent
Organic Matter:
Content of raw shale 13.8
Ultimate composition:
Carbon 80.5
Hydrogen 10.3
Nitrogen 2.4
Sulfur 1.0
Oxygen 5.8
Total 100.0
Mineral Matter:
Content of raw shale 86.2
Estimated mineral constituents:
Carbonates; principally dolomite 48
Feldspars 21
Quartz 13
Clays, principally illite 13
Analcite 4
Pyrite 1_
Total 100
Source: US-093
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Most high quality oil shale lies below a thick layer
of overburden containing little or no kerogen. Underground min-
ing techniques will primarily be used to extract these resources.
There are some areas, however, where oil shale lies close enough
to the surface to permit surface mining.
2.1.1 Oil Shale Surface Mining
Because oil shale zones can be very thick, the typical
surface oil shale mine will be an open pit type mine.
Factors affecting the suitability of shale oil surface
mining are the amount of overburden that must be removed in order
to mine the shale and the availability of a disposal area for the
overburden. In comparison with underground mining, surface min-
ing has several economic advantages--surface mining is capable
of oil extraction at a lower cost and less manpower is required
(HI-083). Also, a greater resource extraction per unit land area
is achievable. In addition, surface mining is inherently safer.
The main disadvantage is a high land impact since all of the spent
shale and solid waste must initially be disposed on the surface.
Only after many years may mine back filling commence.
Overburden at potential surface mining sites ranges
from 30-250 meters (100-800 feet) in depth, averaging approxi-
mately 140 meters (450 feet). Due to the required mine depth,
several bench levels must be provided to develop sufficient work-
ing forces to meet production rates. An average mine slope of
45° with a working slope of 35° is typical (US-093). Overburden
and shale are 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
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and screening facilities may be located at the upgrading plant
site. Major processing steps associated with a surface mining
operation are shown in Figure 2.1-1.
Emission sources associated with the surface mining
facilities include excavation blasting, road dust from trans-
portation of oil shale and overburden, combustion emissions
from diesel-powered equipment, primary and secondary crushing
operations, and wind blown dust. Primary control for fugitive
dust is by water spraying with or without the use of dust sup-
pressants. Particulates generated in the crushing operations
may be reduced by wet scrubbers or fabric filters.
Water resulting from mine drainage and shale pile
runoff is routed to evaporation-containment ponds. This water
may be used for road dust control, shale pile wetting, and par-
ticulate control systems. If the mine is close to the upgrading
facilities, the mine water may be clarified and used as makeup
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 due to leaching. Another
potential demand for mine water is the reclamation operation.
A major environmental 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. Processed 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 back filling begin.
This is expected to be a long time period: up to 30 years.
Since solid waste cannot be disposed of underground, the land
impact associated with surface mining is higher than with roorr-
and-pillar mining.
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OVERBURDEN
REMOVAL
w
SHALE
EXTRACTION
CRUSHING
AND
GRINDING
SHALE
STORAGE
PRODUCT
SHALE
SOLIDS DISPOSA
AND
BACKFILLING
SPENT
SHALE
FROM
RETORT
REVEGETATION
FIGURE 2.1-1 STEPS INVOLVED IN OIL SHALE SURFACE MINING
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A land reclamation/revegetation operation should be
part of a surface mining operation; however, reclamation pro-
cedures are still in conceptual and developmental stages. Rec-
lamation requirements in terms of cost, equipment, time, and
water have not yet been accurately established nor has a success-
ful operation been demonstrated on a commercial basis.
2.1.1.1 Module Basis
The oil shale surface mining module is based upon an
operation capable of supplying sufficient amounts of run-of-mine
oil shale for a shale oil retorting/upgrading facility producing
7950 m3/day (50,000 bbl/day) of shale oil having an average oil
quality of 125 £/MT (30 gal/ton). The mine produces approxi-
mately 59,900 MT/day (66,000 TPD). This production equals the
demand of the processing plant, assuming that the plant would
operate at approximately 90 percent capacity on a yearly basis.
Table 2.1-2 contains estimates of the environmental impact of
surface oil shale mining.
2.1.1.2 Module Description
This section contains discussions on the processing
steps, flow rates, energy requirements, energy recovery ratio,
and water requirements of the surface mining operation.
Processing Steps
The steps involved in the extraction of oil shale by
the surface mining technique include topsoil removal and stor-
age; overburden drilling, blasting, and removal; and oil shale
drilling, blasting, and extraction. These steps resemble those
for coal surface mining, however, the pit is much deeper for oil
8
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shale surface mining. For this module the average overburden
thickness is approximately 137 meters (450 feet). The shale
is mined by a quarry-like operation due to the nature of the
mine pit area.
TABLE 2.1-2.
SUMMARY OF ENVIRONMENTAL IMPACT FROM
SURFACE MINING OF OIL SHALE
Basis: 59,900 MT/day of oil shale extracted (66,000 TPD)
Air (kg/day)
Particulates
S02
NOX
XX
HC
CO
Water Effluents
Thermal
Solid Wastes (MT/day)
Ancillary Energy (kcal/hr)
Energy Recovery Ratio
31,010
2,640
35,990
4,170
21,590
0
Neg
65,000*
1.7 x 108
0.971
*Solid waste is confined to overburden,
addressed in oil shale processing.
Flow Rates
Spent shale is
The mine facilities extract 59,900 MT/day (66,000 TPD)
of raw oil shale. This shale is hauled to the primary crusher
located within the pit. For a mine producing this amount of
raw oil shale, Hittman reports that approximately 65,000 MT/day
(72,000 TPD) of overburden is removed (HI-083).
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Energy Requirements
The energy requirements were calculated by scaling up
the numbers used in the Hittman report (HI-083) so that they
represent the size of this module. The revised numbers are
presented in Table 2.1-3.
TABLE 2.1-3.
DAILY ENERGY REQUIREMENTS FOR
OIL SHALE SURFACE MINING
Operation
Mining
Hauling
Reclamation
TOTAL =
Electricity
(kWh)
11.80 x 10s
11.80 x 10s
Diesel Fuel*
U)
300,615
65,656
2,810
369,081
Total
(kcal)
3.61 x 109
.57 x 109
0.03 x 10 9
4.21 x 109
*8630 kcal/liter
Energy Recovery R.atio
The energy recovery ratio for this module was deter-
mined by dividing the total heating value of the oil shale ex-
tracted (59,900 MT/day or 1.46 x 10u kcal/day) by the sum of
this number and the above module energy requirement (4.21 x
109 kcal). The result gives an energy recovery ratio .of 0.971
for oil shale surface mining.
Water Requirements
The water requirements for the surface mining module
for dust or particulate control is supplied by water collected
10
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in excavated areas. Excess water may be routed to an evapora-
tion pond. The variable climate of the areas underlain by oil
shale and lack of conclusive data based on actual revegetation
of an appropriate scale of these areas make it difficult to
predict the amounts of water needed for reclamation.
2.1.1.3 Module Emissions
The air, water, and solid emissions from oil shale
surface mining are presented in this section. These emissions
are based upon the module extraction rate of 59,900 MT/day.
Primary sources of information for this section of the module
include the Environmental Assessment for a Proposed Coal Gasi-
fication Project (WY-007) by Wyoming Coal Gas Co. and Rochelle
Coal Co. prepared by SERNCO and the Draft Environmental State-
ment for the El Paso Coal Gasification Project (US-112).
Air Emissions
Major sources of air emissions found within oil shale
surface mining include:
wind erosion
topsoil removal and storage losses
drilling overburden and oil shale
blasting of overburden
blasting of oil shale
overburden excavation and loading
11
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• mining roads
diesel equipment
Table 2.1-4 presents the atmospheric emission esti-
mates for this module. The estimates do not include the effect
of control measures beyond basic requirements. The basic re-
quirements assumed include hard surfacing major mine access
roads, periodic water spraying of secondary roads as conditions
require, and--reclaimed mine area contouring to promote vegeta-
tion. The effect of these control techniques on the above emis-
emissions is highly variable and cannot be estimated.
TABLE 2.1-4. ATMOSPHERIC EMISSIONS FROM
OIL SHALE SURFACE MINING
Basis: 59,900 MT/day (66,000 TPD) oil shale mined
Operation
Wind erosion
Part
45
Emissions (kg /day)
S02 NOX BC
CO
Topsoil removal and
storage losses
Drilling
Blasting of overburden
Blasting of oil shale
Overburden excavation
Mining roads
Diesel equipment
TOTAL =
6
102
757
93
2445
1300
290
5038
640 8700 1000 5200
640 8700 1000 5200
12
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Wind erosion results in the discharge of particulates
from the exposed mine areas. Using a wind erosion equation de-
veloped by PEDCo-Environmental, an emission factor of 0.60 MT/
acre-yr is calculated. Assuming 28 acres per year are disturbed,
approximately 45 kg/day (100 Ib/day) of particulates are emitted
(CO-352, US-093).
Topsoil removal and its storage is the first operation
in overburden excavation. SERNCO estimated that topsoil removal
discharges roughly 76 kg/acre-yr of topsoil disturbed. This
amounts to around 6 kg/day (13 Ib/day) of dust emitted to the
air from this operation, assuming 28 acres per year are disturbed
due to mine development (US-093).
Blast hole preparation by drilling releases noticeable
amounts of particulates during overburden removal. Adjusting
the number given by SERNCO for overburden drilling emissions to
an estimate which reflects the materials removal rate in this
module, it is estimated that 102 kg/day (227 Ib/day) of particu-
lates are emitted.
The blasting of the overburden discharges significant
quantities of dirt and dust into the air, however, this operation
occurs only periodically- Adjusting the estimates by SERNCO for
overburden blasting, roughly 757 kg/day (1677 Ib/day) of parti-
culates less than lOy in diameter are discharged to the atmos-
phere. This number is based on the assumption that the large
diameter particles settle out in the immediate vicinity of the
mine.
Following blasting, the overburden is loaded for removal
from the pit area. This phase of mining is the largest single
source of particulates in the extraction operation. SERNCO es-
timated that approximately 0.035 kg of dust is emitted per metric
13
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ton of overburden removed. Assuming a daily removal rate of
64,450 MT/day, the resulting emissions will be about 2260 kg/
day (4980 Ib/day).
The fragmenting of the oil shale by blasting periodi-
cally releases some dust to the air. Assuming the same amount
of dust is emitted for the blasting of the oil shale as for coal
(0.0016 kg/MT of material mined), then 93 kg/day (206 Ib/day)
of dust are emitted (WY-007).
The diesel-powered vehicles operating in the pit emit
significant quantities of pollutants. The equipment consumes
approximately 82,000 liters/day (21,600 gal/day) of diesel fuel
(adjusted value obtained from Hittman Report) (HI-083). The
emissions were determined by applying EPA emission factors for
heavy duty diesel engines (EN-071).
Hauling the extracted shale and overburden on mine
roads results in the dispersion of dust from both payloads and
road surfaces. Adjusting emission estimates reported by SERNCO
for coal mine road dust gives a total particulate discharge rate
of roughly 1300 kg/day (2900 Ib/day) for the hauling of the oil
shale and overburden.
Water Emissions
All mine water is collected and used for dust or par-
ticulate control with any excess being routed to an evaporation
pond. Therefore, no liquid effluent streams are anticipated.
Since no water is discharged, no thermal impact is expected.
In later years, water accumulation from spent shale
backfilling and supplemental irrigation from reclamation activi-
ties could infiltrate through faults and cracks into underground
14
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aquifers. The exact impact of the infiltrating water on an aqui-
fer would depend upon local geological conditions.
Solid Wastes
For a surface mine producing 59,900 MT/day of raw
shale, approximately 64,450 MT/day (70,900 TPD) of overburden
must be disposed (HI-083). This quantity represents the solid
waste generated by this module.
2.1.2 Underground Room-and-Pillar Oil Shale Mining
Most actual experience in oil shale mining involves
underground mining. The Bureau of Mines has demonstrated the
feasibility of room-and-pillar mining for oil shale at its
facility near Rifle, Colorado.
Entry to a room-and-pillar mine may be by horizontal
adit or by shaft. Early work was done on adit entry because
this is the less expensive method. It will be necessary to use
shaft entry on most of the high-quality shale reserves. Entries
to a production zone, though larger than those found in coal
mines, have been dug using conventional drilling, blasting, and
loading equipment and techniques. In a commercial-scale mine,
moles and other advanced cutting machines might be used. All
portions of the mining cycle of drilling, charging, blasting,
wetting of rock piles, loading, hauling, scaling, and roof bolt-
ing will be going on concurrently in various areas of the mine
except that blasting will occur during shift changes. At no
time will personnel be allowed in the immediate area of the
blasting.
The room-and-pillar mine offers an efficient proven
method for mining hard materials deep underground. The rooms
15
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and pillars will be on the order of 18 meters (60 feet) square
with about 18 meters (60 feet) spacing and the floor-to-ceiling
clearance will be about 18 to 24 meters (60 to 80 feet). The
mining can be done in two levels. First, the upper 9 meters
(30 feet) or so are removed; then deeper cuts are made in sel-
ected areas. When the mine is in full operation, extraction
proceeds on both levels at the same time.
Rotary drills prepare holes for blast charges which
fragment a part of the oil shale zone. Water and wetting agents
can be applied at the drill for dust control. Detonation of ex-
plosives produces quantities of carbon monoxide, nitrogen oxides,
and dust. Some of the dust will be carried away by ventilation
air. After fragmentation, the shale is loaded onto a large truck
or conveyor by a front-end loader and moved to a crushing facility,
Water will be added to the broken rock prior to and during loading
and conveying to minimize dust. This wetting operation is one of
the major consumers of water in the mining operation. Water appli-
cation will be minimized to reduce runoff from the pile of broken
rock.
Roof support must be provided for the rooms excavated.
The system most frequently used involves drilling holes in the
roof and inserting bolts equipped with either expansion heads or
other fastening systems. Roof bolts generate compressive stres-
ses to strengthen the roof, and they permit excavating larger
rooms than would otherwise be possible.
The mine ventilation system will draw air into the
mine from the mine entry and distribute it to the work areas.
The mine ventilation requirements are 3 m3/min (100 cfm) of air
per diesel horsepower.
16
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Water resulting from surface mine drainage and shale
pile runoff is also routed to evaporation/containment ponds.
Potential uses for this water have been discussed in the oil
shale surface mining section (2.1.1).
Although the extracted material is almost entirely oil
shale, the oil content of the oil shale may vary considerably. A
mining zone contains layers of varying quality. Generally, a zone
consists of a thick sequence of layers with an average yield of 30+
gallons of oil per ton of shale. Large layers of lower yield oil
shale are treated as overburden, but ordinarily no attempt is made
to separate material within a zone into high- and low-quality
shale.
Leaving pillars in place to support the roof signifi-
cantly decreases the portion of the oil shale that can be mined.
About 60 percent of the oil shale, in place is recovered in room-
and-pillar mines.
A major problem associated with oil shale extraction
involves solids waste handling and ultimate disposal of the spent
shale. Shale increases in size by about 12 vol. 70 during proces-
sing (US-093). Processed shale may be back-filled in an under-
ground mine, substantially reducing the impact of the surface
disposal problem. During the first three years of production,
all processed shale would be disposed on the surface. After
this time period sufficient underground space would be available
for partial disposal (US-093). This is a major environmental ad-
vantage of underground over surface mining. The exact amount of
back-fill depends on the type of spent shale, degree of compac-
tion, moisture content, and mine volume used. Currently, only
one oil shale mining plan calls for mine back-filling.
17
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Spent shale may be returned to the mine by trucks,
conveyors, or a slurry pipeline. If slurried, the slurry water
has to be collected in the mine and returned to the surface.
If a portion of the spent shale cannot be accommodated under-
ground or if none of it is back-filled, it must be contained on
the surface. Land must be available for disposal of both the
overburden from the mine opening and the spent shale.
Surface disposal of solid waste may be achieved by
containment (box canyons) and/or isolation (mesas), followed by
reclamation. Land reclamation and revegetation is a necessity
for reducing the land impact of the shale oil industry. Proce-
dures required to properly restore and revegetate the land have
not been adequately demonstrated. Total cost, time, and water
requirements have not been accurately established.
2.1.2.1 Module Basis
t
The oil shale underground room-and-pillar mining mod-
ule is based upon an operation capable of supplying sufficient
quantities of raw oil shale to support a shale oil retorting/
upgrading facility producing 7950 m3/day (50,000 bbl/day) of
shale oil. The mine produces approximately 59,900 MT/day (66,000
TPD) of oil shale having an average oil quality of 125 2,/MT (30
gal/ton). This production equals the demand of the processing
plant, assuming that the plant would operate at approximately
90 percent capacity on a yearly basis. Table 2.1-5 presents a
summary of the environmental impact of the oil shale underground
mining model.
2.1.2.2 Module Description
This section contains discussions concerning the pro-
cessing steps, flow rates, energy requirements, energy recovery
ratio, and water requirements of the underground mining operation.
18
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TABLE 2.1-5. SUMMARY OF ENVIRONMENTAL IMPACT FROM
ROOM-AND-PILLAR MINING OF OIL SHALE
Basis: 59,900 MT/day of oil shale extracted (66.000 TPD)
Air (kg/day)
Particulates 665
NOX 2945
HC 590
CO 5180
S02 Neg
Water Effluents 0
Thermal (kcal/hr) Neg
Solid Wastes Neg ^s
Water Requirements (5,/min) 1430
Ancillary Energy (kcal/hr) 9.2 x 106
Energy Recovery Ratio 0.998
Processing Steps
The mining will proceed by the conventional mining
cycle of drilling, charging, blasting, wetting of rock piles,
loading, hauling, scaling, and roof bolting. All phases of the
cycle will be taking place concurrently in various areas of the
mine, except that blasting will occur during shift changes when
personnel will not be in the immediate area.
Flow Rates
The mine extracts an average of 59,900 MT/day (66,000
TPD) of raw oil shale. This shale is hauled by truck to the
primary crusher located on the mine floor.
19
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Energy Requirements
The energy requirements were calculated by scaling
up the numbers used in the Hittman report (HI-083) so that
they represent the size of this module. The revised numbers
are presented in Table 2.1-6.
TABLE 2.1-6. DAILY ENERGY REQUIREMENTS FOR
OIL SHALE UNDERGROUND MINING
Operation
Mining
Hauling
Total
Energy Required
(kcal)
91.9
129.2
221.1
x 106
x 10s
x 106
Energy Recovery Ratio
The energy recovery ratio for this module was deter-
mined by dividing the total heating value of the oil shale ex-
tracted (59,900 MT/day or 1.46 x 10u kcal/day) by the sum of
this number and the above module energy requirement (2.211 x 108
kcal/day). The result gives an energy recovery ratio of 0.998
for the underground extraction of oil shale.
Water Requirements
The water requirements for this module consist only
of the water required for dust control. It will be used for
wetting down blasted shale, mine roads, and drilling dust
suppression. The Draft Environmental Impact Statement by the
20
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Colony Development Operation estimates that 1430 liters per
minute (380 gpm) of water are needed for this control (US-291).
2.1.2.3 Module Emissions
This section reviews the air, water, and solids emis-
sions expected from the underground mining of oil shale. These
emissions are based upon the module extraction rate of 59,900
MT/day (66,000 TPD) of raw shale. The primary source of infor-
mation for this section was the Draft EIS by the Colony Develop-
ment Operation in Colorado (US-291).
Air Emissions
There are two sources of atmospheric pollutants from
the underground mining of oil shale. The first source is the
diesel exhaust fumes generated by mobile mine equipment. Cata-
lytic scrubbers mounted on the equipment remove essentially 10070
of the S02 emitted. The other source is the various mining acti-
vities which discharge fugitive dust to the mine air. Approxi-
mately 10 to 15 kg/hr (22-33 Ib/hr) enters the mine atmosphere
from drilling, hauling, and loading and is drawn into the venti-
lation system. For three 1-hour periods each day, during blast-
ing, an estimated 100 to 150 kg/hr (220-330 Ib/hr) of particulates
will enter the mine atmosphere. Reported particulate emission
rates are based on an average rate of 28 kg/hr. No particulate
control devices are placed on the mine vent. Total emission rates
from the mine ventilation system are listed in Table 2.1-7.
Water Emissions
All mine water is collected and used for dust control
with any excess being routed to an evaporation pond. For this
reason, no water thermal discharges are shown for this module.
21
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TABLE 2.1-7. ATMOSPHERIC EMISSIONS FROM UNDERGROUND
OIL SHALE MINING
Basis: 59,900 MT/day (66,000 TPD) Oil Shale Mined
Pollutant
Particulates
Hydrocarbons
NOX
CO
SO 2
Emission Rate
665
590
2945
5180
Neg
(kg/ day)
Source: US-291
Solid Wastes
Negligible solid wastes are created as a direct result
of mine operation since no overburden is removed. The spent
shale which is disposed of in the mine is assumed to be a solid
waste emission from the retorting plant and not the mine.
2.1.3 Oil Shale Sizing Operations
Much of the mined oil shale will require crushing and
sizing prior to retorting. Sizing operations performed on oil
shale may include primary, secondary, and tertiary crushing;
screening; and briquetting. The required size of the crushed
oil shale depends on the specific retorting process being used.
The TOSCO II retort requires that the shale be ground to less
than 1.2 cm while the Union and Paraho retorts can accomodate
ore up to 8.5 cm. Typical operations in a shale sizing facility
are shown in Figure 2.1-2.
In order to minimize costs of transporting the raw
shale, the crushers are located close to the blasting operation,
22
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Receiving hopper
Primary crushing
From mine £
2750 tph
Vibratory feeder
crusher Secondary crushing
2740 tph,
-10.5 in.
Vibratory feeder
Tertiary crushing
2730 tph, -4.5 in.
From tertiary/
crusher /
Double deck
screen
Vibratory feeder
Grizzly bar screen
.Crusher
To storage
To retorting plant
f 110 tph, -3/16 in.
/*
2605 tph
f
. hopper
2720 tph,
-3P in.
Vibratory feeder''
/
/ i
' x / '
Vibratory feeder / \/10b '
i tph »fTo retorting
Briquetting / '"Briquettes > plsnt
-—^ ' ' 2720 tph
Screening plant
Briquetting plant
Mixer
Source: US-093
FIGURE 2.1-2 SHALE SIZING OPERATIONS
-------
usually within the room-and-pillar mine or in the surface mining
pit. From the primary crushers the shale is conveyed to secon-
dary and tertiary crushers outside the mine or pit. The remain-
ing sizing operations may be performed either at the mine site
or at the retorting site.
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. If the retort can-
not accept fine particles the fines are separated from the shale
by a screening process and compacted and formed into briquettes
suitable for routing to the retort along with the other shale
feedstock or are discarded.
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.
2.1.3.1 Module Basis
This module is based upon an operation capable of
sizing enough shale to supply a retorting plant producing
7950 m3/day (50,000 bbl/day) of crude shale oil. This requires
the operation to handle 59,900 Ml/day (66,000 TPD) of oil shale
having an average oil quality of 125 5,/MT (30 gal/ton). A sum-
mary of the environmental impact from oil shale sizing is pre-
sented in Table 2.1-8. This module represents a typical sizing
operation for a TOSCO II retorting plant.
24
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2.1.3.2 Module Description
This section contains discussions concerning the pro-
cessing steps, flowrates, energy requirements, energy recovery
ratio, and water requirements of the sizing operation-
TABLE 2.1-8. SUMMARY OF ENVIRONMENTAL IMPACT
FROM OIL SHALE SIZING
Basis: 59,900 MT/day of oil shale sized
Air Emissions kg/day
Particulates 731
Water Effluents 0
Thermal (kcal/hr) Neg.
Solid Waste Neg.*
Water Requirements Neg.
Ancillary Energy (kcal/hr) 16.0 x 106
Energy Recovery Ratio 0.997
*Solid wastes will be negligible for the TOSCO II process, but for
Paraho and Union processes, the fines will have to be disposed or
consumed by briquetting or by using a combination of retorts,
such as TOSCO II, that can consume the fines. If the fines are
disposed, they will be produced at a rate of 3000 MT/day (MC-238).
Processing Steps
The steps involved in the sizing of the mined oil shale
are primary, secondary, and tertiary crushing and screening. The
primary crushing will be done at the mine. Final crushing will be-
performed near the retorting and upgrading facility.
The crushing operation is designed to maintain a con-
tinuous feed to the retort. This objective will be accomplished
in part by maintaining a storage pile of coarse ore and a storage
25
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bin of fine ore. No storage facility for run-of-mine ore will
be needed. The mine haulage operation is entirely dependent on
the operation of the primary crusher. Should a breakdown occur
in the primary crusher or the conveyor to the coarse ore storage,
haulage from the mine will be interrupted. To avoid shutdown of
the retorting and upgrading facilities, sufficient storage of
coarse ore will be maintained to allow uninterrupted operation of
the downstream processing facilities for about one month. If the
final crusher breaks down, the amount of stored fine ore will be
enough to operate the retort for approximately 5 hours.
Flow Rates
The capacity of the primary crusher and the conveyor to
the coarse ore stockpile will be 4285 MT/hr (4750 tons/hr). Be-
cause of the periodic nature of the mining and primary crushing
operations, the coarse ore storage will provide surge capability
to maintain a uniform feed rate to the final crusher in addition
to providing an emergency supply in case of interruption in the
supply of coarse ore from the mine and primary crusher. Normally,
the coarse ore from the primary crusher will be fed directly to
the final crusher at a rate of 2685-2885 MT/hr (2950-3250 tons
per hour). During periods when the coarse ore production exceeds
the feed requirements of the final crusher, the excess will be
diverted to coarse ore storage. A coarse ore reclaim system will
be provided to maintain a uniform feed rate to the final crusher.
Ten crushers in the final crushing facility will produce minus
1.27 cm (0.5 in) shale on a continuous basis at a rate of 2685-
2885 MT/hr for feeding to the retort.
Energy Requirements
All crushing and conveying equipment will be driven
electrically and consume about 445,000 kWh daily (382.4 x 106
kcal/day) (US-291).
26
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Energy Recovery Ratio
The energy recovery ratio for this module was deter-
mined by dividing the total heating value of the oil shale sized
(59,900 MT/day or 1.46 x 10u kcal/day) by the sum of this num-
ber and the above module energy requirements (382.A x 106 kcal/
day). The result gives an energy recovery ratio of 0.997 for
the sizing of oil shale.
Water Requirements
The water requirements for this module will be negli-
gible if primary dust control is accomplished by the use of bag
filters. If wet scrubbers or dust suppression sprays are used
the requirement will increase slightly.
2.1.3.3 Module Emissions
This section reviews the emissions and effluents ex-
pected from an oil shale sizing operation. The major impact
will be to the air quality, while little or no water or solid
impact is anticipated. The primary source of information for
this section was the Draft EIS by the Colony Development Oper-
ation in Colorado (US-291).
Air Emissions
The major sources of atmospheric emissions from oil
shale sizing operations include the crushing and screening
facilities, belt conveyor transfer points, and the fine ore
storage silo. Table 2.1-9 summarizes the emissions from these
areas.
27
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TABLE 2.1-9. ATMOSPHERIC EMISSIONS FROM OIL SHALE SIZING
Source
Particulate Emission Rate
(kg/day)
Primary Ore Crusher
Portal Transfer Point
Feed Bin Transfer Point
Reclaim Transfer Point
Fine Ore Crusher
Fine Ore Storage
93
12
70
70
431
55
All crushing and screening facilities will be controlled
by thp use of fabric filters, with an assumed collection effici-
ency of 99 percent. The stack emissions from the filter vents
used on the primary crusher and screener will be discharged at
the rate of 3.62 kg/hr of particulates according to the Colony
Development's EIS (US-291). The fine ore crushing facility will
also be controlled by the use of fabric filters. The reported
particulate emissions from the fine ore crusher will be 16.6 kg/
hr according to Colony.
Coarse ore from the primary crusher located in the mine
is discharged to an inclined conveyor system for transport to the
coarse ore storage site or the final crushing plant, where secon-
dary and tertiary crushing occurs. Emissions from, the three trans-
fer points along the enclosed conveyor are 5.9 kg/hr of particu-
lates, as seen in Table 2.1-9.
Prior to being fed to the retorts, the sized shale is
stored in one of three large storage silos which serve as surge
capacity- Particulate emissions from the storage silos are con-
trolled with fabric filters. Particulates are emitted at the
rate of 2.1 kg/hr from the filter stacks according to Colony.
28
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Water Emissions
There are no process water requirements or water efflu-
ents from oil shale sizing operations. Thermal discharges are
therefore non-existent. Dust suppresion sprays may be used, as an
alternative, at transfer points.
Solid Wastes
Minimal solid wastes are generated from oil shale sizing
operations for the TOSCO process, but for Union and Paraho pro-
cesses the fines will have to be disposed or consumed by briquetting
or using a combination of retorts, such as TOSCO, that can consume
the fines. If the fines are disposed, they will be produced at
a rate of 3000 MT/day (3300 TPD) (MC-238).
2.2 Shale Oil Processing
There are two stages involved in the processing of oil
shale. First, the oil shale is heated to form hydrocarbon gases
and liquids by pyrolysis or retorting. The shale oil is pro-
duced by simply providing thermal energy to cleave enough bonds
in the kerogen matrix to allow the cracked products to be volatil-
ized and later condensed as oil. In the second stage, the shale
oil is upgraded for transportation and for subsequent use in
refineries or by consumers.
This report concentrates on three processes, the TOSCO II
process, the Paraho (indirect mode) process, and the Union Oil
Retort B process. These three processes represent different
approaches to oil shale processing and have been tested to varying
degrees in demonstration facilities. This report does not intend
to imply that these or any other oil shale processes are more or
less technologically or environmentally feasible.
29
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As yet, no commercial-sized facilities have been con-
structed. Colony Development Operation has prepared an environ-
mental impact analysis (CO-175) for a 7950 m3/day (50,000 bbl/
day) shale oil production facility using the TOSCO II oil shale
retort. A more recent environmental impact statement for the
proposed oil shale facility by Colony has been published by the
Department of Interior (US-291). Since no detailed emission infor-
mation such as an EIS has been prepared for the Paraho or Union
Oil processes , the process representatives were contacted to
obtain emission rates. Gaps in emission data occur since the
processes are still in early stages of development. Available
information is mainly concerned with EPA criteria pollutants,
SO , NO , CO, particulates and total hydrocarbons. Little infor-
X X
mation is available concerning emission rates of specific trace
elements and organics; however, studies are currently underway
or are in the planning stages. Due to the lack of information,
this report presents qualitative rather than quantitative dis-
cussions of trace elements and organics.
A general discussion of oil shale processing, given
below, is followed by detailed descriptions of three individual
processes and their modules.
Retorting (Pyrolysis) Techniques
Shale oil retorting may be grouped into two broad
categories:
those which mine and then retort the shale
i-
above ground (ex situ), and
those which retort the shale in place
underground (in situ).
30
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This report discusses only ex situ processes. Ex situ processes
make use of more familiar technology and consequently are more
advanced. The intriguing advantage of in situ processing is that
the massive solids handling and disposal problems associated with
ex situ processes may be avoided.
Ex situ processes require a retort, solids handling
facilities, and shale oil upgrading facilities. Of these processes,
only the retorting represents new technology that must be devel-
oped. The shale oil upgrading can be accomplished using conven-
tional petroleum refining techniques, although research is being
conducted in several areas of the upgrading facilities specific-
ally related to shale oil processing requirements.
Current ex situ processes incorporate either solid-
solid or solid-gas heat transfer. The TOSCO II process utilizes
solid-solid heat transfer in the form of hot ceramic balls to
supply heat to the oil shale. The ceramic balls are heated intern-
ally and then mixed with the raw shale in the retort. After
retorting, the ceramic balls must be separated for recycle from
the spent shale. Other processes use sand or spent shale part-
icles. Ex situ processes which involve gas-solid transfer either
use internal gas combustion or external heat generation. The
Paraho (direct mode) and Union Retort A processes use internal
gas combustion by injecting air directly into the retort. The
heat liberated by the combustion of fuel gas and carbon residue
provides the required retorting temperatures. The Paraho (indirect
mode) and Union Retort B processes use external heat generation
from external heaters to provide a high temperature recycle gas
which is routed to the retort. The recycle gas raises the shale
to the retorting temperature of approximately 480°C (900°F).
Combustion does not occur in the retort as it does' with internal
gas combustion processes.
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Upgrading Techniques
Many common features exist in the various shale oil
processes. These common features result from the fact that cer-
tain basic processing steps must be performed to obtain a market-
able hydrocarbon product from oil shale. These steps include
retorting, oil recovery and fractionation, gas recovery and treat-
ing, sulfur recovery, cracking heavy fractions, hydrotreating
hydrocarbon fractions, ammonia separation, and water treating.
Different shale oil processes use the same established technology
for all operations except the retorting step. Although the
effluent stream from retort types differ, the same upgrading
processes can be used.
A typical shale oil upgrading sequence is as follows:
1) Effluent from the retort is cooled, allowing
separation of light gases overhead and removal
of water by use of knockout drums. The crude
shale oil is routed to a fractionator for product
separation. A typical fractionator separates
the feed stream into gas, sour water, naphthas
or light oil, and a heavy bottoms oil. A
series of parallel operations follows the
fractionation as product streams are upgraded
and by-products recovered.
2) All gas streams produced in oil shale refining
are routed to a gas recovery and treating unit.
In this unit, heavy hydrocarbons (C5 ) are
recovered and returned to the light oil stream
32
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from the fractionator for processing. The gas
is treated in an amine or other similar unit for
removal of hydrogen sulfide and carbon dioxide.
The clean gas may then be routed to boilers for
power generation or to a methane/steam reformer
for hydrogen generation. The acid gas is strip-
ped from the amine and routed to a sulfur
recovery unit.
3) The sulfur recovery unit normally consists of
a Glaus plant working in conjunction with a
tail gas treating unit. This unit should be
capable of 99% sulfur recovery (HI-083). If
the hydrogen sulfide concentration in the Glaus
feed is maintained at 40 vol. "L or higher, a
three-stage Glaus plant should recover approxi-
mately 95% of the equivalent sulfur in the
charge. The gas stream containing approximately
5% of the original sulfur is routed to a tail
gas treating unit. Performances of tail gas
treating units vary; however, approximately
957o of the remaining sulfur should be removed.
Some tail gas units reduce sulfur to the level
of 250 ppm SO2 in the effluent gas stream.
4) Light distillate from the fractionator requires
hydrotreating to remove impurities and to improve
pour point and viscosity. Since hydrogen is
required, a hydrogen generation unit is normally
located on site. Hydrogen may be produced from
plant fuel gas and steam in a conventional steam
reforming process. Hydrotreated oil is routed
to product tankage. Sour gas from the hydro-
treater is routed to the gas recovery facilities.
33
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5) Fractionator bottoms are routed to a delayed
coker for recovery of additional oil by
thermal cracking. Oil from the delayed coker
is routed to a gas oil hydrotreater. Gas
produced from the thermal cracking is routed
to the gas recovery facilities. A large
percentate of the charge to the delayed
coker is produced as coke. This coke may
be either marketed as a by-product or used
for process heat.
6) An ammonia separation unit is used to remove
the ammonia from the hydrotreater wash water.
The water is first stripped of any light hydro-
carbons which are routed to the gas treating
facilities. The ammonia is then removed by
an ammonia stripper and compressed to form
Iqiuid ammonia.
7) Water treating facilities are necessary to
all shale oil processing units. Careful
water management and coordinated water-
treating facilities are required to reduce
makeup water requirements and to prevent
water pollution. Maximum reuse is antici-
pated if a goal of zero wastewater discharge
is to be obtained. Water-treating facili-
ties include mechanical draft cooling towers,
strippers to remove NHs and HaS, API separa-
tors, biological treating facilities, and
containment/evaporation ponds.
34
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Characteristics of Plant Streams
The retort is the heart of the shale oil process.
Most of the differences that exist between processes are a
result of the retorting procedure. Specific retort require-
ments dictate how fine the ore must be crushed. The TOSCO
retort requires ore ground to less than 1 cm (0.5 in.) while
the Union and Paraho retorts can receive ore up to 9 cm (3.5 in.)
in diameter. Operating conditions of the different retorts
vary- This affects the product streams. A comparison of
the effluent oil from three retorts is shown in Table 2.2-1.
TABLE 2.2-1.
CHARACTERISTICS
OF CRUDE SHALE OILS
Retorting Process
Internal Combustion Indirectly Heated
Gravity, °API
Sulfur, wt. %
Nitrogen, wt. %
Pour Point, °F
Viscosity, SUS
Union Retort A
20.7
0.77
2.01
90
223 @ 100°F
TOSCO1 Paraho (indirect mode)
28.0 21.7
0.80
1.70
75 65
120 @ 100°F 68 @ 130°F
1 Unpublished information submitted by Colony Development Operation
indicates TOSCO crude shale oil may have gravity as low as 21° API
and sulfur content of 0.75 wt. %.
Source: US-093
Gases produced in shale oil processes vary significantly,
depending on the type of retort. Gases from internal combustion
retorts such as Paraho (direct mode) and Union Retort A are diluted
with combustion products and the inert components of air. As a
result, the gas has a low heating value, 900 kcal/Nm3 (100 Btu/scf),
and would be uneconomical to transport a significant distance.
Gas from retorts which use indirect heating, such as TOSCO II,
Paraho (indirect mode) and Union Retort B, is composed only of
35
-------
undiluted products from the kerogen and has a substantially higher
heating value, 8000 kcal/Nm3 (900 Btu/scf).
The sulfur generated in the retorting step is also
dependent upon the type of retorting process used. Retorts using
indirect heating, such as TOSCO II, liberate sulfur as H2S. H2S
is then treated by a gas recovery and treating unit and sent to a
sulfur recovery plant where it is recovered as sulfur. Internal
combustion retorts also liberate H2S. A large portion of the
uncondensable gases is returned to the retort as combustion gas
where H2S is ignited to form S02. However, since shale rock is
mainly dolomite limestone, much of the S02 is absorbed by the
rock and removed with the spent shale. A comparison of gases
from internal combustion and indirect heat retorts is shown in
Table 2.2-2.
Physical properties and quality of the spent shale
also change with the retort. The amount of carbonaceous material
remaining on the shale is inversely proportional to the retort
temperature. The shale from a low-temperature TOSCO retort
contains 5-670 carbonaceous material while the shale from higher
temperature retorts have very little residual carbon remaining.
Retorts operating at intermediate temperatures, such as the
Paraho (indirect mode) retort, and Union Retort B, usually pro-
duce shales containing about 370 carbonaceous material.
Regardless of the retort types, all processes can use
cracking and hydrotreating processes to upgrade the retort oil
to distillate fuel quality. Properties of an upgraded shale oil
are shown in Table 2.2-3.
36
-------
TABLE 2.2-2. CHARACTERISTICS AND YIELDS OF
UNTREATED RETORT GASES
Type of Retorting Process
Internal
Composition, vol. °/0
Nitrogen1
Carbon Monoxide
Carbon Dioxide
Hydrogen Sulfide
Hydrogen
Hydro carbons
2
60.1
4.7
29.7
0.1
2.2
3.2
Combustion Indirectly Heated
2
62.1
2.3
24.5
0.1
5.7
5.3
As
Produced
--
4.0
23.6
4.7
24.8
42.9
After Desul-
furization
--
4.2
24.8
(0.02)
26.0
45.0
Gross Heating Value,
Btu/scf 83 100 775 815
Molecular Weight 32 30 25 24.7
Yield, scf/bbl oil 20,560 10,900 923 880
Includes oxygen of less than 1.0 volume percent.
2First analysis reflects relatively high-temperature retorting
in comparison with second, promoting higher yield of carbon
oxides from shale carbonate and relatively high yield of total
gas.
Oil from the retort.
Source: US-093
37
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TABLE 2.2-3. CHARACTERISTICS OF UPGRADED SHALE OILS
Gravity °API 46.2
Sulfur wt. % 0.005
Nitrogen wt. % 0.035
Pour Point °F <50.
Viscosity, SUS at 100°F 40.
Source: RA-R-215
2.2.1 TOSCO Process
The TOSCO II process features a rotary-type retort
which employs ceramic balls to supply the retorting heat by
solid-solid heat transfer. A simple flow diagram of the TOSCO
retorting step is shown in Figure 2.2-1. Crushed raw shale feed
of minus 0.5 inches in size is fed from a surge hopper to a raw
shale preheater. The incoming shale is preheated in a fluidized
bed to approximately 260°C(500°F) by combining with incoming hot
flue gas from the ceramic ball heater. The preheater effluent is
routed to a separator in which the shale is settled from the flue
gas. Following shale separation, the cooler flue gas, which has
been incinerated within the preheat system to reduce trace hydro-
carbons, is passed through a high-energy venturi to remove shale
dust before being vented to the atmosphere at a temperature of
50-55°C (125-130°F).
Preheated raw shale from the cyclone separators is
routed to the rotary drum retort. High-alumina content ceramic
balls of one-half inch diameter are combined with the raw shale
in the retort. The balls have been heated to approximately 650°C
(1200°F) in a furnace fired by product fuel gas. Retort tempera-
ture is maintained at 480°C (900°F) with about two tons of
38
-------
vo
-200 WESH
SPCNT SHALE
TO DISPOSAL
FIGURE 2.2-1 TOSCO II RETORTING PROCEDURE
-------
ceramic balls required to heat one ton of shale. An internal
pressure of .35 kg/cm3 (5 psig) is maintained to prevent the
entrance of air. The rotating retort is essentially a ball
mill: As the kerogen decomposes, the shale oil loses strength
and is pulverized by the ceramic balls. Approximately 5-670 car-
bonaceous material remains on the shale. An advantage of using
indirect heating rather than direct gas combustion is that the
fuel gas produced is not diluted by combustion products and con-
sequently has a higher heating value. Approximately 150 Nm3
of flue gas per cubic meter of product oil (900 scf/bbl) with a
heating value of 8000 kcal/Nm3 (900 Btu/scf) is produced from the
retort.
Retort products are routed to an accumulator where the
solids are passed over a trommel screen to separate the balls from
the spent shale. The ceramic balls are recycled to the vertical
ball heater by means of a bucket elevator. They are preheated by
flue gas coming from the steam superheater. This gas stream also
removes shale dust. Emissions are controlled by a wet scrubber.
In the ball heater, fuel gas is combusted to heat the balls to
650°C (1200°F).
The spent shale is cooled in a rotating drum steam
generator. After cooling, the processed shale is moisturized to
approximately 14 percent moisture content in a rotating drum
moisturizer. Steam and shale dust produced during the moisturizing
step are routed through a venturi scrubber to remove the dust
before discharging to the atmosphere. Following moisturizing,
the spent shale is conveyed to a disposal site. Dust collected
from the various venturi scrubbers is also routed off-site with
the processed shale.
40
-------
Hydrocarbon vapors are routed overhead from the accumu-
lator to a distillation tower. The retort products are normally
separated into gas, sour water, naphtha, gas oil and bottom oil
streams. A series of parallel operations follows the fractiona-
tion as product streams are upgraded and by-products recovered.
A flow diagram of the shale oil upgrading procedure is
shown in Figure 2.2-2. Units include gas recovery and treating
facilities, naphtha and gas oil hydrotreaters, delayed coker,
hydrogen generation unit, water treating facilities, sulfur re-
covery unit, ammonia separation unit, and steam and electric power
generation facilities. Gas from the accumulator is routed to gas
recovery and treating and then recycled to the ball heater for
combustion or sent to the hydrogen generation unit. The naphtha
is normally .stabilized and then hydrotreated. The gas oil streams
are also hydrotreated. Bottoms oil from the fractionator is
thermally cracked by use of a delayed coker to recover additional
oil and produce a coke by-product. All H2S-rich gas streams are
routed to the sulfur recovery unit. Wash water from the hydro-
treaters is stripped at an ammonia separation unit. Water removed
from gas streams is routed to a foul water stripper to remove
ammonia and hydrogen sulfide. The stripped water is used for
moisturizing spent shale.
Air emission sources for this process are the preheat
system, steam superheaters, moisturizing system, process heaters,
sulfur recovery unit, crushing and conveying, and power genera-
tion. Hydrocarbon storage and fugitive hydrocarbon losses are
also included.
41
-------
C1,S/>H)
N)
C«'l rod »LAHt futL
full CAI Ida COMFICI
LfS IPCCML M00JCI TO JTO«A«t
SUirun PIODUCT TO IIOSACt
TC STOHltC
o.i. >KOU;T tc STG<«ojucr r« ttstm
MOCCS9CD ««»LC TO OltF3»L
FIGURE 2.2-2 UPGRADING AND BY-PRODUCT RECOVERY FACILITIES
-------
2.2.1.1 Module Basis
Estimates of the emissions are based on an oil shale
processing plant producing 7950 m3/day (50,000 bbl/day) of
primary liquid fuels. For an oil shale facility, the primary
fuels include naphtha, distillate oil and/or a residual oil.
The 7950 m3/day module was selected since it is the commercial
sized facility used for most planning purposes. A feed rate
of approximately 59,870 MT/day (66,000 TPD) of raw shale is
charged to the retorts. A summary of emissions from an oil
shale plant is presented in Table 2.2-4.
2.2.1.2 Module Descriptions
The oil shale processing module for the TOSCO process
is comprised of the retorting and shale oil upgrading steps.
Raw shale extraction and crushing are not included in this mod-
ule. The primary fuels from this module are naphtha and fuel
oil. The TOSCO II plant at Parachute Creek, Colorado, is designed
for raw shale feed of 59,870 MT/day (66,000 TPD). A typical oil
shale will contain approximately 12 wt % kerogen or about 146
liters of oil per metric ton of oil shale (35 gal/ton). The
resulting primary fuels production will be about 7950 m3/day
(50,000 bbl/day). This represents the anticipated size of a
typical oil shale facility associated with an underground mine.
Surface mines are anticipated to be capable of supplying shale
for a 15,900 m3/day (100,000 bbl/day) or larger facility.
Processing Steps
The major processing steps for the oil shale module are
the following:
1) Retorting,
2) Gas recovery and treating,
43
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TABLE 2.2-4. SUMMARY OF ENVIRONMENTAL IMPACT FROM
TOSCO II RETORTING AND UPGRADING MODULE
Basis: 7950 m3/day Primary Fuels Plant
Air (kg/day)
Particulates 7,842
S02 3,077
NOX 16,935
HC 10,607
CO 676
Water (kg/day)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (kcal/hr) Negligible
Solid Wastes (MT/day) 49,380
Water Requirements (5,/min) 18,263
Energy Recovery Ratio 0.806
Ancillary Energy (kcal/hr) 214 x 10s
Manpower Requirements 503 - 625
(personnel)
Sources: BA-368, CO-175, HI-083, US-093, US-291
44
-------
3) Sulfur recovery,
4) Delayed coking,
5) Hydrogen generation,
6) Naphtha hydrotreating
7) Gas oil hydrotreating, and
8) Ammonia separation.
The processing sequence is shown in Figure 2.2-3. In
addition to these processing units, support facilities such as
utility boilers and water treating facilities are included.
Flow Rates
Module flow rates for oil shale processing are taken
from the Colony EIS (CO-175). These rates are as follows:
Raw Shale to Retort - 59,870 MT/day (66,000 TPD)
Spent Shale - 49,380 MT/day (54,430 TPD)
Low Sulfur Fuel Oil - 7,470 m3/day (47,000 bbl/day)
Liquefied Petroleum - 690 m3/day (4330 bbl/day)
Gas
Ammonia - 122 MT/day (135 TPD)
Sulfur - 157 MT/day (173 TPD)
Coke - 726 MT/day (800 TPD)
Energy Requirements
Energy requirements for this module are given by Colony
for the proposed TOSCO II Parachute Creek plant. These heat re-
quirements and fuel mix are shown in Table 2.2-5. The module
heat requirements and fuel mix are based on "Mode I" operation.
45
-------
RAW
SHALE
RETORT
PRODUCT
SEPARATION
SPENT SHALE
GAS TREATING
&
RECOVERY
TO PLANT
FUEL
TO GAS
TREATING
COKER
COKE
SULFUR
RECOVERY
HYDROGEN
UNIT
TO GAS
TREATING
NAPHTHA
UPS
TO GAS
TREATING
4
GAS OIL
HDS
SULFUR
-»- HYDROGEN
NAPHTHA
TO PLANT FUEL
-»- GAS OIL
FIGURE 2.2-3 TOSCO II SHALE OIL MODULE
-------
TABLE 2.2-5.
PRELIMINARY FUEL BALANCE FOR
COMMERCIAL SHALE OIL COMPLEX
MM BTU/HR
Mode I (3)
Source (2)
Mode II (4)
Fuel Gas Fuel Oil Cu Liquid Fuel Gas Fuel Oil C* Liquid
Pyrolysis and Oil Recovery Unit
Preheat Systems (6) 708 755
Steam Superheaters (6)
Hydrogen Unit
Reforming Furnaces (2) 632
Gas Oil Hydrogenation Unit
Reactor Heaters (2)
Reboiler Heater
Naphtha Hydrogenation Unit
Reactor Heater 10
Sulfur Recovery Unit
Sulfur Plants (2) and Common 10
Tail Gas Plant
Delayed Coker Unit 88
Utilities
Boilers (2) 93_
Totals 1448 848
384
144
330
632
945
307
120
47
40
55
48
11
10
96
615
1079
150
1150
475
(1) It should be emphasized that while estimates of total fuel consumption are subject to only minor
revisions, the allocation of fuels to various sources is quite preliminary, and is not only subject
to substantial revision, but will be variable during plant operations.
(2) Where multiple sources are indicated, consumption is for all sources.
(3) Complex is expected to operate in "Mode I" approximately two-thirds of the time.
(4) Complex is expected to operate in "Mode II" approximately one-third of the time.
Source: CO-175
47
-------
Ancillary energy requirements for the oil shale module
are 85,000 kW for the 66,000 TPD TOSCO II operation. Assuming
357o generating efficiency and discounting electrical requirements
for mining and crushing, the ancillary energy required is 214 x 105
kcal/hr (850 x 10s Btu/hr).
The heating values of the fuels are as follows:
Retort gas - 7,253 kcal/Nm3 (815 Btu/scf)
C,* Liquid - 11,767 kcal/kg (21,200 Btu/lb)
Distillate Fuel - 9.5 x 106 kcal/A (6 x 106 Btu/bbl)
Coke - 77,710 kcal/kg (14,400 Btu/lb).
Energy Recovery Ratio
An important consideration for synthetic fuels process-
ing is the efficiency of the conversion from the raw fuel source
to a usable fuel. The energy recovery ratio is used as an indi-
cation of this efficiency. It is defined as the ratio of the
heating value of all the products to the heating value of all the
inputs to the module. The heating value of the products includes
the net liquid and gas fuels produced along with the coke pro-
duced. Sulfur and ammonia are not included. The input heating
value includes the gross heating value of the raw shale and the
ancillary electrical inputs. The raw shale gross heating value
is approximately 2090 kcal/kg (3765 Btu/lb). The energy recovery
ratio for the TOSCO II module is calculated as 0.620.
48
-------
Water Requirements
Water demands of the oil shale industry cannot be
accurately defined due to the uncertainty of water requirements
for revegetation. Water requirements for this module are based
on TOSCO II estimates (CO-175). The water requirements for
revegetation are expected to range from 265 &/min (70 gpm) during
early development to 2650 £/min (700 gpm) after 12 years. The
module water requirements are as follows:
Makeup to Water Treatment - 11,563 £/min (3055 gpm)
for Cooling Tower and Boiler
Feed Water Makeup
Makeup to Pyrolysis Unit - 3,104 £/min (820 gpm)
for Moisturizer and Scrubber
losses and Processed Shale
Moisturizing
Dust Control for - 946 fc/min (250 gpm)
Processed Shale
Water for Revegetation - 2,650 £/min (700 gpm)
Total 18,263 £/min (4825 gpm)
Manpower Requirements
The manpower requirements for the oil shale complex are
estimated by Colony (CO-175). The personnel requirements estimated
for a commercial oil shale complex are given below:
Administrative 46
By-Products Terminal 8
Processing Area 368 - 470
Disposal Area 73 - 93
Guards 8
503 - 625
49
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The manpower estimates do not include personnel at the mining
facilities. The manpower requirements are assumed to be the
same for all the oil shale modules.
2.2.1.3 Module Emissions
The multimedia emissions for oil shale processing are
discussed in this section. The EPA criteria pollutants are
quantified along with water and solid1 effluents. The emissions
of trace elements and trace organics from oil shale processing
are discussed in Section 2.2.4.
Air Emissions
The air emissions in this module result from combustion
of fuels, shale moisturizing, sulfur recovery, storage, and mis-
cellaneous hydrocarbon emissions. A summary of module air emis-
sions is presented in Table 2.2-6. This summary represents the
most recent update of TOSCO II emissions by Colony Development as
presented by Battelle (BA-368). It should be noted that these
emission rates differ in some cases from those reported by Colony
in the earlier EIA for the plant at Parachute Creek, Colorado.
In general, these changes represent the evolution in the plant
design.
For example, the revised S02 emissions are considerably
lower than originally estimated. This is attributed to. two factors
New Sources Performance Standards were
lowered for H2S in process fuel gas from
an anticipated 35 grains H2S/100 scf to
10 grains/100 scf, which required approp-
riate design revisions. This would pro-
vide a central efficiency of about 99.67o
50
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TABLE 2.2-6. TOSCO II SHALE OIL MODULE (7950 m3/day) AIR EMISSIONS AND STACK PARAMETERS
Ui
/
,.
A.
B.
C.
i.
>.
A.
II.
4.
5.
it.
V.
8.
0.
Snurcu
Pyrnlysls & Oil
Itccovcry Unit
rri'lm.il System
(6 units)
Steaii Siiperhrutrrs
(« units)
Shiilc Moisturizing
(6 units)
llyilrof.uii Unit
(4 1 unt4CU:j)
Car; Ull Hydroftonnt Ion
Kvactor lleatur
(i null!))
K.-bullur ll.-.ilvr
N.iChtlin llytlrop.cnut Ion
DolnyeJ Cuhfir
III Illty Hollers
('1 mills)
Sulfur Rtfcnvury
lluflnlnii Misc.
StornKU
•KII'AI.
Kulsulona (kv./dnv) Stack Paroneters
Total Vulaclty Height Temp. Radius
1'iii tlfuljlca SO, OriiJiilm CO NO, a/sac11 «. °C n. RuCrri-ni-es
2.649 555 2,9/iS A', 7 14.123 IS. 8 94.6 S3 1.42 BA-368
2. 354 1,032 2 31 1.2)4 14.2 94.6 63 .69 BA-368
2,649 .... 1^.2 94.6- 84 .69 HA-3AB
124 297 17 107 895 15.2 24.4 227 .88 I1A-36S
4 10 1 4 29 10.7 22.9 4S2 .38 UA-368
)7 41 2 16 122 11.0 45. 8 371 .88 BA-368
2 4 1 2 5 7.3 22.9 427 .38 HA-368
12 30 2 11 92 4.6 S3. 4 177 1.14 BA-J68
31 78 4 28 235 7.6 16.8 204 1.07 BA-368
1,010 - - 9.2 64.0 149 1.22 BA-368
7,370 1.5 KA-K-211
?62 - - 15.2 - - RA R-215
7,842 3,()7/ 10,607 676 16,935
-------
for SO2 emissions resulting from process
fuel gas combustion. In addition, removal
efficiencies in the gas treating section
for trace organic sulfur compounds, such
as mercaptans, were revised.
Pilot plant data indicates that the preheat
section of the Tosco II process can remove
SO2 from flue gas at about 9570 efficiency,
by the contact of S02 with shale dust.
This was not taken into account in earlier
estimates.
In addition, new nitrogen oxide (NO ) emission rates
X
are considerably lower than previously estimated. Original
estimates assumed that all of the relatively high organic nitrogen
content of shale oil was converted to NO during combustion in
addition to normal NOX emissions by fixation. Current estimates
assume considerably less NO formation which is more in line with
X
experimental and published data.
Finally, particulate emissions from the preheat system
are reported to be higher than previously indicated. However,
this is mostly due to the fact that the new rates reflect total
particulates. Total particulates include condensible hydrocarbons
as well as solids. Only about half of the reported particulates
for the preheat systems are solids.
The air emissions from the module result from several
general sources. These sources include fuel combustion, pre-
heating, shale moisturizing, sulfur recovery, petroleum storage,
and miscellaneous sources. These sources are discussed below.
52
-------
Fuel Combustion
Emissions from the combustion of fuels result from the
following sources (CO-175):
Pyrolysis or Retorting Unit
Hydrogen Unit
Gas Oil Hydrotreating Unit
Naphtha Hydrotreating Unit
Delayed Coking Unit
Utility Boilers
The type of fuel combusted at the individual sources
is determined from the TOSCO II fuel mix (see Table 2.2-
Radian used updated emission estimates (BA-368) for these emission
sources. In general, these emission rates agree reasonably well
with EPA emission factors for combustion sources.
Preheating
Use of flue gas streams for raw shale and circulat-
ing ball preheating require additional particulate removal from
the flue gas after preheating. Venturi wet scrubbers are used
to remove the particulates. It is estimated by mass balance cal-
culations that the Venturi wet scrubber will remove 99.8 percent
of the raw shale dust from the flue gas leaving the preheat system
and 95.8 percent of the spent shale dust from the flue gas from
the steam superheaters leaving the ball circulation system (CO-175)
Shale Moisturizing
The only emissions from the spent shale moisturizing
operation are particulates. The emission rates are taken from the
53
-------
updated estimates (BA-368). It is estimated by mass balance
calculations that Venturi wet scrubbers will remove 93.0 percent
of the spent shale dust. The emission factor for controlled partic-
ulate is 0.25 gr/ACF.
Sulfur Recovery
Sulfur dioxide is considered to be the only emission
from the sulfur recovery facilities. Sulfur recovery facilities
consist of a Glaus plant and a tail gas treating unit. Updated
emission rates (BA-368) are presented. It is estimated by mass
balance calculations that the sulfur recovery facilities will
recover 99.770 of sulfur as elemental sulfur. This corresponds
to 95 percent sulfur recovery in both the Glaus plant and tail
gas treating unit.
Petroleum Storage
The following assumptions based on literature, data
and experience are formulated to calculate the hydrocarbon emis-
sions from petroleum storage.
1) All product storage is in floating
roof tanks.
2) Storage capacity is 10 days (HI-083).
3) Combined hydrocarbon product is
equivalent to a crude oil.
Using petroleum storage emission factors for storing crude oil in
floating roof tanks (0.029 Ib/day - 103 gal) hydrocarbon emissions
from storage are calculated to be 3.03 g/sec (23.9 Ib/hr).
54
-------
Floating roof tanks will provide approximately 90-95% control of
hydrocarbon emissions from storage. These emissions are assumed
to occur at a height of 15.2 m (50 feet).
Miscellaneous Sources
There can be numerous miscellaneous hydrocarbon emis-
sions in the shale oil upgrading facilities which escape from
sources such as valve stems, flanges, loading racks, equipment
leaks, pump seals, sumps, and API separators. These losses are
discussed in Radian's Refinery Siting Report (RA-119). Based on
literature data, Radian found that the miscellaneous hydro-
carbon emissions amount to about 0.1 wt. % of refinery capacity
for a new well-designed, well-maintained refinery. This value
of 0.1 wt. % is used to determine miscellaneous emissions from
the shale oil up-grading facilities. Upgrading capacity is con-
sidered to be the feed to the distillation tower (50,000 bbl/day).
Crude shale oil from the TOSCO II retort is approximately 21°
API (US-093). Hydrocarbon emissions from miscellaneous sources
are calculated to be 85.3 g/sec (676 Ib/hr). The composition of
these hydrocarbons can be expected to be a composite of all
volatile intermediate and refined products. The emissions are
assumed to occur at a height of 1.5 m (5 feet).
Water Effluents
Water effluents are nonexistent since the module is
assumed to operate with zero discharge (HI-083). Any water blow-
down streams are routed to containment/evaporation ponds. This
wastewater blowdown stream should be high in dissolved solids
with some suspended solids and organics. A large amount of water
is used on the spent shale pile. The potential exits for runoff
55
-------
from the spent shale pile to leach contaminates from the spent
shale. The use and maintenance of a lined catchment basin and
containment structure (embankment) will solve this problem.
It has been estimated that, regardless of the quan-
tities of water applied to the surface of the processed shale
embankment, infiltration will be limited to the upper two to
three feet of the embankment. Runoff water which is to be reused
for processed shale disposal should remain in the embankment and
is not likely to re-enter surface or subsurface water systems
(US-291). This is true as long as the embankments are maintained
but may be a problem if the embankments are abandoned.
Thermal Discharge
Thermal discharge to water bodies is zero since no
water is discharged from the module.
Solid Wastes
Solid wastes are determined from the amount of spent
shale in a typical shale oil process (US-093). This value is
49,380 MT/day (54.430 TPD) of spent shale for a 59,870 MT/day
(66,000 tons/day) raw shale process. The geometric mean size of
the retorted shale from the TOSCO process is 0.007 cm (.003 in.)
with a maximum size of 0.476 cm (0.19 in.) and a minimum size of
0.00077 cm (0.0003 in.) (US-093).
Other solid wastes will be disposed of in the spent
shale pile such as water softener sludge and spent catalyst, but
these quantities will be very small in comparison to the spent
56
-------
shale. However, the impact may be significant depending on the
catalyst and its toxic components if it is disposed in a small
area of the embankment and the embankment partially fails.
2.2.2 Paraho Process
The Paraho retort has the capability of using either
direct gas combustion (direct mode) or externally heated recycle
gas (indirect mode) to achieve the required 480°C (900°F)
retorting temperature (PF-003). Publicity releases indicate
that recent tests using externally heated recycle gas were
considered by Paraho developers to be very successful. This
report assesses the Paraho process with externally heated
recycle gas,
A vertical retort is used. Coarsely ground shale oil
ranging from 1-9 cm (3/8" to 3-1/2") in size is introduced at
the top and flows bv gravity downward through the retort.
Heated recycle gas (or combustion air and recycle gas for direct
fired operation) is introduced at several points in the retort,
flowing upward countercurrent to the shale. Retorting tempera-
tures reach a maximum of 620-650°C (1150-1200°F). Spent shale
is removed from the bottom of the retort. Shale oil vapors
leave overhead, passing through an electrostatic precipitator
and then to a gas recovery unit. A portion of the noncondensible
gas is heated and returned to the retort as recycle gas with the
remainder treated for sulfur removal and used in the plant for
process fuel. Fuel gas produced by indirect heating usually
has a heating value around 7230 kcal/Nm3 (800 Btu/scf). The
Paraho retort is shown in Figure 2.2-4. Upgrading facilities
are assumed to be similar to the TOSCO II process.
57
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SHALE ROCK
SHALE VAPORS
TO OIL
RECOVERY UNIT
OIL/GAS
SEPARATOR
HEATED
RECYCLE
GAS
COOL
RECYCLE
GAS
RETORTED SHALE TO
DISPOSAL BEDS
r
RECYCLE
HEATER
PLANT
FUEL GAS
_L
GAS
RECOVERY
L.
RECYCLE
GAS
BLOWER
SULFUR
PLANT
SULFUR
FIGURE 2.2-4. THE PARAHO RETORT PROCESS
58
-------
2.2.2.1 Module Basis
Estimates of the emissions are based on an oil shale
processing plant producing 7950 m3/day (50,000 bbl/day) of pri-
mary liquid fuels. A feed rate of approximately 59,870 MT/day
(66,000 TPD) of raw shale is charged to the retorts. A summary
of emissions from a Paraho oil shale plant is presented in
Table 2.2-7.
2.2.2.2 Module Description
The oil shale processing module for the Paraho process
is comprised of the retorting and shale oil upgrading steps. Raw
shale extraction and crushing are not included in this module.
The primary fuels from this module are naphtha and fuel oil. The
Paraho module processes 59,870 MT/day (66,000 tons/day) of raw
shale. The raw shale is assumed to contain approximately 30 gal-
lons of oil per ton of oil shale. The resulting primary fuels
production will be about 7950 m3/day (50,000 bbl/day).
Processing Steps
The major processing steps for the Paraho oil shale
module are the following:
1) Retorting,
2) Gas recovery and treating,
3) Sulfur recovery,
4) Delayed coking,
5) Hydrogen generation
6) Naphtha hydrotreating,
7) Gas oil hydrotreating, and
8) Ammonia separation.
59
-------
TABLE 2.2-7. SUMMARY OF ENVIRONMENTAL IMPACT FROM
PARAHO RETORTING AND UPGRADING MODULE
Basis: 7950 m3/day Primary Fuels Plant
Air (kg/day)
Particulates 1,178
S02 2,734
NOX 13,785
HC 7,924
CO 593
Water (kg/day)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (kcal/hr) Negligible
Solid Wastes (MT/day) 49,380
Water Requirements (&/min) 20,386
Energy Recovery Ratio NA
Ancillary Energy (kcal/hr) NA
Manpower Requirements 503 - 625
(personnel)
NA = Not Available
60
-------
The processing sequence is the same as that for the
TOSCO II process in Section 2.2.1.2, Figure 2.2-3. In addition
to these processing units, support facilities such as utility
boilers and water treating facilities are included.
Flow Rates
Module flow rate's for the Paraho process are assumed to
be very nearly the same as those for the TOSCO II process since
both modules assume the same quality raw oil shale and both modules
are assumed to operate by indirect heating. The TOSCO II process
flow rates are repeated below for the Paraho process.
Raw Shale to Retort 59,870 MT/day (66,000 TPD)
Spent Shale 49,380 MT/day (54,430 TPD)
Low Sulfur Fuel Oil 7,470 m3/day (47,000 bbl/day)
Liquefied Petroleum 690 m3/day (4,330 bbl/day)
Gas
Ammonia 122 MT/day (135 TPD)
Sulfur 157 MT/day (173 TPD)
Coke 726 MT/day (800 TPD)
Energy Requirements1
Energy requirements for the Paraho module are different
than those for the TOSCO II module. The retorting energy require-
ment can be calculated from the following equation (AT-051):
AH0 = A + BT + CT2 + DT3 + ET4 + FT2G
o
Decent information presented by Paraho Development Corporation
indicates that the retorting heat requirements may be less than
that calculated here (MC-238).
61
-------
where AHS = enthalpy above 77°F in Btu per'pound of shale; T =
temperature, °F; G = modified Fischer assay, gallons per ton; A =
-52.1723; B = 0.555857; C = -1.15991 x 10"3; D = 1.68010 x 10'5;
E = -8.15335 x 10~10; and F = 4.11319 x 10"6. Assuming a retort
temperature of 1150°F for the Paraho process, AHg = 345.5 Btu/lb or
191.5 kcal/kg. This same equation applied to the TOSCO II retort
temperature of 900°F gives AHS = 299.4 Btu/lb or 166.2 kcal/kg.
When the value for AHg for the Paraho retort is applied to a 7950
m3/day facility, 507.8 x 10s kcal/hr (2015 x 10s Btu/hr) are required.
Consequently, the heat requirements for the Paraho retorting are
somewhat higher than that for the TOSCO process.
Ancillary energy requirements for the Paraho process
should be lower than those for the TOSCO II process. The Paraho
process does not require as much energy for solids handling
since raw shale preheating and ceramic ball handling steps are
eliminated in the Paraho process. Specific values for the
reduced ancillary energy requirements are not available.
Energy Recovery Ratio l
As discussed earlier the energy recovery ratio indicates
the efficiency of fuel conversion from the raw fuel source. An
accurate assessment of the Paraho process energy recovery ratio
could not be made because of the lack of available data. However,
the energy recovery ratio for the Paraho process may be similar to
that of the TOSCO process since the higher retorting heat require-
ments for the Paraho process tend to be offset by the lower ancil-
lary energy requirements.
1 Recent information presented by Paraho Development Corporation
indicates that the energy recovery ratio"for the Paraho process
is 0.611 (MC-238).
62
-------
Water Requirements
Water demands for the Paraho process were obtained from
Paraho Development Corporation (MC-238). Reported water require-
ments were for a facility that produced more synthetic crude than
the module considered in this report; so their estimates are
adjusted accordingly.
Makeup to Pyrolysis Unit None
Cooling Tower Makeup 10,541 £/min (2,785 gpm)
Solid Residue Disposal 6,756 £/min (1,785 gpm)
Shale Oil Upgrading 3,089 Jl/min ( 816 gpm)
Total 20,386 fc/min (5,386 gpm)
DEI claims that water requirements for solid residue
disposal can be reduced and that shale oil upgrading water require-
ments can be reduced by upgrading outside the retorting area.
Manpower Requirements
Refer to the manpower requirements for the TOSCO module,
Section 2.2.1.2.
2.2.2.3 Module Emissions
The multimedia emissions for the Paraho process are
discussed in this section. The EPA criteria pollutants are
quantified along with water and solid effluents. The emissions
of trace elements and trace organics from oil shale processing
are discussed in Section 2.2.4.
63
-------
Air Emissions
The air emissions in this module result from the com-
bustion of fuels, sulfur recovery, storage, and miscellaneous
hydrocarbon emissions. A summary of the module air emissions
is presented in Table 2.2-8. This summary assumes that the
Paraho process can operate in a similar mode to the TOSCO II
process when Paraho uses indirect heating of recycle gas.
The air emissions result from several general sources.
These sources are discussed separately in Section 2.2.1.3 and
should apply here, except for,.fuel combustion and preheating.
Fuel Combustion
Emissions from the combustion of fuels result from
the following sources:
Pyrolysis or Retorting Unit
Hydrogen Unit
Gas Oil Hydrotreating Unit
Naphtha Hydrotreating Unit
Delayed Coking Unit
Utility Boilers
The modes of operation and, therefore, the combustion
emissions for the Paraho process (indirect mode) and the TOSCO
II process should be very similar. This is because the heat
requirements, the product slate and, consequently, the available
fuels are very similar.
Some differences, however, arise in the retorting steps
Because of these differences, the Paraho process emissions for
64
-------
TABLE 2.2-8.
Ul
PARAHO SHALE OIL MODULE (7950 m3/day)
AIR EMISSIONS AND STACK PARAMETERS
Emissions (kg/day)
Source Particulates
1.
2.
3.
4.
5.
6.
7.
8.
1'yrolysis 6. Oil
Recovery Unit
Hydrogen Unit
(4 furnaces)
Cas Oil Hydrogenation
A. Reactor lleater
(2 units)
11. Reboller Heater
Naphtha Hydrogenation
Delayed Coker
Utility Boilers
(2 units)
Sulfur Recovery
Refining Misc.
9. Storage
TOTAL
988
124
4
17
2
12
31
--
--
--
1.178
SO 2
1 , 244
297
10
41
4
30
78
1,030
--
--
2.734
Total
Orgunics
265
17
1
2
1
2
4
--
7.370
--
7 , 924
CO N0x
425 12,407
107 895
4 29
16 122
2 5
11 92
28 235
..
._
.-
593 13.785
Rate
NmJ/sec
635.0
85.1
3.7
12.1
1.4
12.7
32.5
29.1
--
Stuck Parameters
Height Temperature
m "C
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
1.5
15.2
N/A
N/A
N/A
N/A
N/A
N/A
H/A
N/A
--
Radius
m
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
._
Reference
EN-071
BA-368
BA-368
BA-368
BA-368
BA-368
BA-368
BA-368
RA-R-215
RA-R-215
H/A - Not available. See Table 2.2-6 for these values presented for the TOSCO II process.
-------
pyrolysis were estimated by Radian. The estimate was made by
assuming that the same fuels are available to the Paraho process
as to the TOSCO II process and then applying emission factors
for an industrial heater from AP-42 (EN-071). Exceptions to
AP-42 arise for S02 and NOX. For gas combustion, S02 was
calculated based on 230 Mg/Nm3 (0.10 gr/scf) of dry H2S in the
fuel gas. Sulfur was assumed to be 0.25 wt % for fuel oil. NO..
^x
emissions from fuel oil combustion was assumed to be 2.16 g NOX/106
cal (1.2 Ib NOX/105 Btu). The S02 adjustments conform to new source
performance standards (NSPS) for refineries and Colorado regula-
tions. The NOX adjustments are derived from TOSCO II data for a
high nitrogen content fuel.
Preheating
Another difference between the Paraho process and TOSCO
II process is that particulate emissions from the Paraho retorting
will be significantly less since raw shale preheating, as well
as ball circulating and spent shale moisturizing steps are elim-
inated in the Paraho process. Consequently, particulate control
for Paraho retorting is not required.
Water Effluents
Water effluents are nonexistent since the module is
assumed to operate with zero discharge (HI-083). Any water blow-
down streams are routed to containment/evaporation ponds. This
wastewater blowdown stream should be high in dissolved solids
with some suspended solids and organics. Impermeable catchment
basins and containment structures (embankments) should solve
problems associated with runoff from spent shale piles that could
potentially discharge leachates to surface or ground waters.
Leachates from the processed shale pile to surface and groundwater
66
-------
systems are a potential problem. However', studies indicate
that water contamination due to percolation-type leaching will
be negligible and that surface leaching will not pose critical
problems (US-093). This is true as long as the embankments are
maintained but could be a problem if the embankments are abandoned,
Thermal
Thermal discharge to water bodies is zero since no
water is discharged from the module.
Solid Wastes
Solid wastes are determined from the amount of spent
shale in a typical shale oil process (US-093). This value is
49,380 MT/day (54,430 TPD) of spent shale for 59,870 MT/day
(66,000 TPD) raw shale process. The spent shale should be
approximately the same size as the charged shale, 1-9 cm
(3/8 to 3-1/2 in.). Some of the shale will be crushed as the
shale moves downward through the retort and the resulting fines
will be entrained in the product gas stream.
Other solid wastes will be disposed of in the spent
shale pile such as water softener sludge and spent catalyst, but
these quantities will be very small in comparison to the spent
shale. However, the impact may be significant depending on the
catalyst and its toxic components if it is disposed in a small
area of the embankment and the embankment partially fails.
67
-------
2.2.3 Union Oil Process
In the Union Oil process, oil shale is pumped upward
through an expanding cone by a reciprocating piston. A counter-
current stream of hot gas heats the rising bed of shale to the
necessary retorting temperature. Retorting takes place near the
top of the retort. Oil that is liberated from the shale is
carried downward by the gas and gravity toward the cooler shale.
This process design reduces agglomeration of the oil shale and
the product oil (HO-379).
Union has developed several variations of this basic
retorting concept. Retort A, developed in the early 1940's,
uses internal combustion to supply heat for retorting. A once
through flow of air is heated by the combustion of carbonaceous
deposits on the retort shale at the top of the retort. Retort B
was developed to produce a higher quality product than Retort A.
Retort B uses indirect heat. Recycled product gas is heated in-
directly in a furnace to about 510-540°C (950-1000°F). The furnace
is fueled by make gas, upgraded product gas, which has a heating
value of about 7000 kcal/Nm3 (800 Btu/scf) (HO-379).
An auxiliary process, SGR (Steam Gas Recirculation), has
also been examined by Union. Processed shale from Retort B contains
a nominal 4 wt. % carbonaceous deposit. In SGR, the hot processed
shale is sent to a separate vessel where the carbonaceous deposit
is removed by reacting with steam and air to produce low-Btu gas
or with steam and oxygen to produce high-Btu gas. Marginal eco-
nomics has stopped further work on this process (HO-379). Present
plans are to use the Retort B design for development (CL-115).
Further discussion in this section is directed at Retort B.
The retorting system using Retort B is presented in
Figure 2.2-5. The following description is taken from a report
published by the Union Oil Company (HO-379).
68
-------
MAKEUP WATER
A
i n n
M i ii
111 11
u UL
OIL-WATER
SEPARATOR
RECYCLE GAS
HEATER
VENTURI
SCRUBBER
LIGHT-ENDS
OIL
RETORT MAKE GAS TO
GAS TREATING
C.W.
RETORTED SHALE TO
DISPOSAL
Source: HO-379
RUNDOWN OIL PRODUCT
FIGURE 2.2-5 UNION RETORT B FLOW DIAGRAM
-------
Oil shale from the feed bin flows through
two...chutes to the solids pump. Shale oil
product acts as a hydraulic seal in the feed
chutes to maintain the retort pressure. The
solids pump is mounted on a movable carriage
...(and) consists of two piston and cylinder
assemblies which alternately feed shale to
the retort.
The shale is retorted as it rises through
the retort cone. (Heat is supplied by a
countercurrent flow of hot recycle gas:) As
the retorted shale rises above the upper
cone lip it forms a freestanding pile....
A rake rotates above...the freestanding
pile to break up any agglomerates that may
form.
The space above the cone is enclosed by the
dome. The (processed) shale slides down
chutes and through the dome wall at the
(processed) shale outlets. Hot recycle
gas is introduced into the space between the
(processed) shale pile and the dome. It
flows downward into the rising shale to
provide the heat required for retorting....
The bulk of the liquid product trickles
down through the cool, incoming shale and
the balance, in the form of a mist, is
carried from the retort by the (cooled)
gases. The gas and liquid are separated
from the shale in the lower slotted wall
section of the retort cone.
The shale particles which fall through the
slots into the disengaging section are re-
cycled to the feed chutes. The retorted
shale is conveyed in pipes to one of the two
retorted shale cooling vessels. As shown in
Figure (2.2-5), a level of shale is maintained
above the level of water in the quench vessel!
A drag-chain conveyor removes the cooled
shale from under the water level. A water
level is maintained in the conveyor to seal
the retort from the atmosphere. Generated
steam is condensed and returned to the
cooling vessel. The cooled and (moistened)
processed shale is sent to disposal.
70
-------
Gases from the disengaging section are scrubbed
and cooled in a venturi scrubber. Agglomerated
mist plus light ends and water produced by cooling
are sent to an oil-water separator. The oil is
recycled to the retort through the oil shale
feed line and the water is sent to the water seal
after stripping to remove ammonia. The scrubbed
gas is divided into a make stream and a recycle
stream. The recycle stream is compressed and
heated prior to injection into the top of the
retort.
The make gas is processed by compression and
scrubbing to remove heavy ends and hydrogen
sulfide. Oil is used to scrub out the heavy
hydrocarbons and Stretford solution is used
to remove hydrogen sulfide. The sweetened
make gas is used as plant fuel.
The liquid product from the retort is treated
sequentially to remove solids, arsenic and
light ends. Solids removal is accomplished
by two stages of water washing. The shale fines
are collected in the water phase which is re-
cycled to the water seal.
The liquid product contains 50 ppm of chemically
combined arsenic. (The arsenic concentration
is) reduced to about 2 ppm in a proprietary
Union Oil process. (The process uses) an
absorbent which picks up arsenic to about 80
percent of its weight. About 50 tons of spent
absorbent will be placed in the retorted shale
disposal-, area per year. . The dearsenited shale
oil is sent to a stripping column for stabili-
zation and sweetening prior to upgrading.
Make gas production from the retort will exceed
plant fuel requirements. To avoid flaring the
excess, the system will be balanced by absorbing
the heavy ends of the make gas into the oil
product. This will be accomplished by varying
the operating conditions of the stripping column
and a related debutanizer.
Upgrading facilities are assumed to be similar to the
TOSCO II process.
71
-------
2.2.3.1 Module Basis
Estimates of the emissions are based on an oil shale
processing plant producing 7950 m3/day (50,000 bbl/day) of pri-
mary liquid fuels. Specific data for the Union Oil Retort B
process was supplied by Union (CL-115) for oil shale containing
142 £/MT (34 gallons/ton). This results in a raw shale require-
ment of 58,300 MT/day (64,300 TPD), which is slightly lower than
the requirement for the TOSCO II and Paraho modules. A summary
of the emissions from a Union Oil shale plant is presented in
Table 2.2-9.
2.2.3.2 Module Description
The oil shale module for the Union Oil process is com-
prised of the retorting and shale oil upgrading steps. Raw shale
extraction and crushing are not included in this module. The
Union Oil module processes 58,300 MT/day (64,300 TPD) of raw shale.
The raw shale is assumed to contain approximately 142 liters of
oil per metric ton of oil shale (34 gallons/ton). The resulting
primary fuels production will be about 7950 m3/day (50,000 bbl/day)
Processing Steps
The main processing steps involved with the shale oil
module are as follows:
1) retorting,
2) gas recovery and treating,
3) sulfur recovery,
4) delayed coking,
5) hydrogen generation,
6) naphtha hydrotreating,
72
-------
TABLE 2.2-9. SUMMARY OF ENVIRONMENTAL IMPACT FROM
UNION OIL RETORTING AND UPGRADING MODULE
(Basis: 7950 m3/day Primary Fuels Plant)
Air (kg/day)
Particulates 873
S02 1,988
N0x 8,166
HC 7,984
CO 883
Water (kg/day)
Suspended Solids 0
Dissolved Solids 0
Organic Material 0
Thermal (kcal/hr) Negligible
Solid Wastes (MT/day) 48,500
Water Requirements (S,/min) 9,840
Energy Recovery Ratio NA
Ancillary Energy (kcal/hr) NA
Manpower Requirements 503 - 625
(personnel)
NA = Not available
73
-------
7) gas oil hydrotreating,
8) ammonia separation unit
The processing sequence is shown in Figure 2.2-6. In addition
to these processing units, support facilities such as utility
boilers and water treating facilities are also included.
Flow Rates
Module flow rates for Union Oil shale oil processing
were provided by Union (CL-115). These rates are as follows:
Raw Shale to Retort 58,300 MT/day (64,300 TPD)
Spent Shale 48,500 MT/day (53,500 TPD)
Shale Oil Produced - Net C5+ 7,950 m3/day
(50,000 bbl/day)
Sulfur 51 MT/day (56 TPD)
Retort Fuel Gas Produced and 1.64 x 106 Nm3/day
Consumed - C,~ (5?>9 x IQ* scf/day)
No estimates were made for ammonia or coke production
rates, but they should be similar to the TOSCO II module in Sec-
tion 2.2.1.2.
Energy Requirements
Energy requirements for Union Retort B are estimated
from Union data (CL-115) for the retorting complex alone. Union
reports that all of the fuel gas produced at the retort will be
consumed in retorting. This amounts to an energy requirement of
438 x 10s kcal/hr (1737 x 10s Btu/hr). This is slightly more
than the energy requirements estimated for TOSCO II process.
Ancillary energy requirements for the Union Oil process
are not available. However, the retort charging operation, using
74
-------
RAW
SHALE
Ln
RETORT
i
SPENT
SHALE
&
^ TREAT
RECO<
\s
ING &
i/ERY
PRODUCT
SEPARATION
TO GAS
TREATING
f
™ COK.L
i
R
\
i
vr
•—-
v^-
SULFUR
RECOVERY
HYDROGEN
UNIT
t
NAPHTHA
HPS
TO GAS
TREATING
t
GAS OIL
HDS
TO PLAI
f .
!•*
SULFUR
HYDROGEN
NAPHTHA
GAS OIL
COKE
FIGURE 2.2-6 UNION OIL SHALE OIL MODULE
-------
a solids pump, is expected to use much greater quantities of
energy than a gravity feed retort (CO-320).
The heating values of the fuels are as follows (CL-115):
Retort Gas 6500 kcal/Nms (720 Btu/scf)
Distillate Fuel 9.5 x 106 kcal/£ (6 x 10s Btu/bbl)
Energy Recovery Ratio
As discussed earlier, the energy recovery ratio is
an indication of the efficiency of conversion from the raw fuel
source. An accurate assessment of the energy recovery ratio
for the Union Oil process could not be made because of the lack
of a*r ; 1able data.
Water Requirements
Water requirements have been estimated by Union (CL-115)
for Retort B to be 9840 £/min (2600 gpm). This includes retorting,
cooling, gas treatment, deasher, scrubber, processed shale mois-
turizing and disposal. However, it does not include upgrading
and revegetation. The water requirements for Union's Retort B
is expected to be similar to TOSCO and Paraho requirements when
upgrading and revegetation are included.
Manpower Requirements
The manpower requirements for the Union Oil process are
assumed to be the same as those for the TOSCO II process, Section
2.2.1.2.
76
-------
2.2.3.3 Module Emissions
The multimedia emissions for the Union Oil process
are discussed in this section. The EPA criteria pollutants
are quantified along with water and solid effluents. The emis-
sions of trace elements and trace organics from oil shale pro-
cessing are discussed in Section 2.2.4.
Air Emissions
The air emissions in this module result from the com-
bustion of fuels, sulfur recovery, storage, and miscellaenous
hydrocarbon emissions. A summary of the module air emissions
is presented in Table 2.2-10. This summary presents emissions
directly associated with the module operations required to pro-
duce the shale oil. The emissions for the pyrolysis and oil
recovery unit were provided by Union (CL-115). No data were
available from Union on the upgrading facilities; however, oper-
ations were assumed to be similar to the TOSCO II process. The
resulting emissions should be the same.
The air emissions result from several general sources.
These sources are discussed individually in Section 2.2.1.3. All
except for fuel combustion and sulfur recovery should apply here.
Fuel Combustion
Emissions from the combustion of fuels result from
the following sources:
Pyrolysis or Retorting Unit
Hydrogen Unit
Gas Oil Hydrotreating Unit
77
-------
TABLE 2.2-10.
oo
UNION OIL SHALE OIL MODULE (7950 m3/day)
AIR EMISSIONS AND STACK PARAMETERS
Emissions (kg/day)
1.
2.
3.
4.
5.
6.
7.
8.
9.
Source
Pyrolysis & Oil
Recovery Unit
Hydrogen Unit
(4 furnaces)
Gas Oil llydrogenation
A. Reactor Heater
(2 units)
11. Rcboiler Heater
Naphtha Hydrogenatlon
Delayed Coker
Utility Boilers
(2 unity)
Sulfur Recovery
Refining Misc.
Storage
TOTAL
Particulates
683
12'.
4
17
2
12
31
--
--
--
873
S02
1.528
297
10
41
4
30
78
--
--
--
1.988
Total
Organics
325
1.7
1
2
1
2
4
--
7.370
262
7 , 98'.
CO NO,.
715 6.788
107 895
4 29
16 122
2 5
11 92
28 235
--
-.-
..
883 8.166
Rate
Nm'/sec
N/A
130. 7
2.1
6.5
0.7
9.1
20. 7
N/A
--
Stack Parameters
Height
m
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
1.5
15.2
Temperature
°C
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
--
Radius
m
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
--
Reference
HO-379
CL-115
EN-071
EN-071
EN-071
EN-071
EN-071
EN-071
Radian
RA-R-215
RA-R-215
N/A - Hot available. .See Table 2.2-5 for these values presented for the TOSCO II process.
-------
Naphtha Hydrotreating Unit
Delayed Coking Unit
Utility Boilers
The air emissions for the pyrolysis or retorting unit
are based upon data provided by Union (CL-115) obtained from their
pilot plant operations. The emissions result primarily from the
combustion of retort fuel gas for heating of recycle gas to the
retort. The retorting operations for Union and Paraho processes
are similar since they both are assumed to use indirect heating
with recycle gas. The primary difference is that Union plans on
using only reheat gas for retorting while it is assumed that
Paraho is using both retort gas and fuel oil. This will account
for some of the differences in retorting emission rates, especially
the lower NOX rate for the Union Retort B.
The upgrading emissions for Union are assumed to be the
same as those for TOSCO II. Union reports that they can increase
their fuel gas production by changing retort condidtions. It is
assumed that they will do this to produce the necessary fuel gas
for upgrading heat requirements.
Sulfur Recovery
Union reports that no emissions will be produced at
the sulfur recovery unit. Sulfur dioxide is usually considered
to be the only emission from the sulfur recovery facilities.
However, Union reports that the tail gas from their sulfur re-
covery unit will be combusted and the S02 emissions are accounted
for under the pyrolysis and oil recovery unit source.
Union plans on using a Stretford unit for sulfur re-
covery which should provide a sulfur recovery efficiency of
greater than 99 percent.
79
-------
Water Effluents
Water effluents are nonexistent since the module is
assumed to operate with zero discharge (HI-083). Any water blow-
down streams are routed to containment/evaporation ponds. This
wastewater blowdown stream should be high in dissolved solids
with some suspended solids and organics. Impermeable catchment
basins and containment structures (embankments) should solve
problems associated with runoff from spent shale piles that could
potentially discharge leachates to surface or ground waters.
Leachates from the processed shale pile to surface and ground
water systems are a potential problem. However, studies indicate
that water contamination due to percolation-type leaching will
be negligible and that surface leaching will not pose critical
problems (US-093). This is true as long as the embankment is
maintained but may be a problem if the embankment is abandoned.
Thermal
Thermal discharge to water bodies is zero since no water
is discharged from the module.
Solid Wastes
Solid wastes are determined from the amount of spent
shale in a typical shale oil process (US-093) . This value is
48,500 Ml/day (53,500 TPD) of spent shale for a 58,300 NT/day
(64,300 TPD) raw shale process. The quantity of solid waste
for the Union Oil module is less than for the TOSCO II and Paraho
modules. This conclusion is solely dependent on the assumption
that the Union Oil module uses a higher grade of oil shale. (This
assumption is made to correspond with the data supplied by Union
(CL-115))- Data is not available on the size of the spent.shale.
80
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Spent shale should be roughly the same size as charged shale.
The spent shale for the Union Oil process, therefore, should be
relatively large in size due to the large size of the charged
shale.
Other solid wastes, such as water softener sludge and
spent catalyst, will be disposed of in the spent shale site.
The quantities of these wastes will be very small in comparison
to the spent shale. However, depending on the catalyst and its
toxic components, an environmental impact may be significant if
the catalyst is disposed of in a small area of the embankment
and the embankment partially fails.
2.2.4 Trace Element and Organic Emissions From Oil Shale
Processing
Trace elements can be emitted to the environment when
oil shale is converted to a synthetic crude oil. Raw oil shale
contains trace elements in the form of mineral inclusions or
organic complexes. These elements can become part of the emis-
sions and effluents to the environment during oil shale process-
i
ing, product combustion, or processed oil shale disposal.
Trace organic emissions can also result from oil shale
processing. Various organic species are created when kerogen
is decomposed in the oil shale retort. These organics can then
be emitted during the processing steps or with the disposed pro-
cessed oil shale.
There is very little information available in the
literature concerning trace emissions of elements or organics.
Programs are currently underway which are designed to specify
the trace emissions from oil shale processing. However, this
81
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information is not presently available. This section discusses
some of the factors influencing trace emissions from oil shale
processing. Available information on oil shale processing and
other related processes is used to predict the fate of trace
elements and organics during oil shale processing. The discussion
is intended to provide only a qualitative description.
2.2.4.1 Trace Elements
Trace elements present in processed Green River oil
shale are presented in Table 2.2-11. The same trace elements
TABLE 2.2-11. ELEMENTAL CONCENTRATION OF GREEN RIVER OIL SHALE
Element
Concentration
(wt. ppm)
Element
Concentration
(wt. ppm)
Element
*Quantity in ( ) is water soluble.
Source: CO-175
Concentration
(wt. ppm)
Li
Be
B
F
CI
Sc
Ti
V
Cr
Mn
Co
Ni
Cu
Zn
Ga
Ge
As*
Se
Br
' Rb
Sr
Y
850
35
140
1,700
72
2.4
570
29
49
34
39
11
15
13
2.2
0.40
7.2 (0.11)
0.08
0.01
29
69
1.2
Zr
Nb
Mo
Ru
Rh
Pd
Ag
Cd
In
Sn
Sb
Te
I
Cs
Ba
La
Ce
Pr
Nd
Sm
Eu
9.3
3.4
4.9
< 0.1
< 0.1
< 0.1
< 0.01
0.14
Standard
0.11
0.39
< 0.1
< 0.01
1.2
32
1.4
1.6
0.25
1.2
0.44
0.12
Gd
Tb
Dy
Ho
Er
Yb
Lu
Hf
Ta
W
Re
Os
Ir
Pt
Au
Hg
TI
Pb
Bi
Th
U
0.40
0.07
0.40
0.07
0.27
0.25
< 0.1
< 0.1
0.04
0.42
< 0.1
< 0.1
< 0.1
< 0.1
< 0.1
< 0.1
0.14
10.
0.36
0.77
0.99
82
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are found in the raw oil shale although the concentrations may be
different. Very little data on the fate of trace elements in oil
shale processing facilities has been published. Atlantic-Richfield
has identified 29 elements in a typical Green River shale oil
(BU-172).
Experimental Studies of the Fate of Trace Elements
in Similar Processes
Recently, attention has been focused on trace element
emissions from coal-fired power plants. Coal also contains trace
elements that are emitted when the coal is combusted. Certain
limited analogies can be drawn between the coal-fired power plant
and oil shale processing. Basically, these analogies are:
both systems handle organic material bound
in a matrix with mineral matter, and
both systems operate at elevated temperatures.
However, this analogy has its limitations. The physical
and structural similarities between coal and oil shale are limited.
The oil shale retorts operate at lower temperatures than the coal-
fired boiler. The coal fed to a power plant encounters an oxidiz-
ing atmosphere with the coal combustion products existing in
either gas or solid phase; the oil shale fed to a retort encoun-
ters a reducing atmosphere. When the Paraho process uses internal
combustion, the oil shale is subjected to a reducing atmosphere
that contains localized areas of excess oxygen.
In a study of the fate of trace elements in a coal-fired
boiler, Radian identified the following elements as being enriched
in flue gas (SC-338):
83
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sulfur lead chromium
mercury molybdenum copper
chlorine nickel cobalt
antimony boron uranium
fluorine zinc arsenic
selenium cadmium silver
The following elements exit the stack in the same
proportions as in the ash. These include:
barium aluminum manganese
beryllium calcium magnesium
vanadium iron titanium
Based on semiquantitative surveys, tin and germanium
are also enriched in the flue gas.
A coal gasifier also has similarities to the oil shale
retort. This analogy has most of the similarities and limitations
applied to the coal-fired power plant analogy. An additional
similarity is that in a gasifier, the coal first encounters a
reducing atmosphere and then an oxidizing atmosphere. Gasifiers,
however, usually operate at higher pressures than oil shale re-
torts.
Little work has been published concerning the fate of
trace elements in coal gasification systems. Attari (AT-042) has
reported some data in connection with the IGT HYGAS pilot plant.-
The purpose of this work was to measure the concentrations of 11
trace elements found in the solid streams entering and leaving
each of the three stages of the HYGAS pilot plant. The HYGAS
gasifier section is shown in Figure 2.2-7.
84
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PRETREATER
HYOROGAS1FIERJ
ra* hydrogen-rich gas
PIPELINE GAS
63 aim
THANATION
residual char
PURIFICATION
carbon dioxide, liquid aromatics,
sulfur, ammonia
to power generation
GASIFIER
spent char to
power generation
1000 °c
74atm
FIGURE 2.2-7.
IGT HYGAS PROCESS FOR ELECTROTHERMAL
GASIFICATION, SHOWING PRETREATMENT,
HYDROGASIFICATION, AND ELECTROTHERMAL
STAGES
85
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Because the pilot plant was not operational during the
period when the analytical work was performed, coal and char sam-
ples accumulated over several years of bench-scale research were
used in the analysis. The emphasis of the project was placed on
trace element analytical methods since sampling and operating
criteria of the pilot plant were not involved. The relative
amounts of the trace elements found in the overhead gas and the
spent char from the electrothermal gasifier are presented in
Table 2.2-12. The amount of each element assumed to be in the
overhead gas was calculated by difference. It can be seen from
these data that most of the Hg, Se, As, Te, Pb and Cd which
entered the gasifier in the coal feed, apparently left the gas-
ifier in the vapor phase. Most of the Sb, V, Ni, Be and Cr
remained in the solid phase. However, due to the conditions
under which the work was done, the accuracy of the data is in
doubt. An indication of trends in the volatility of the trace
elements in a gasifier are the best that can be expected from
this data.
TABLE 2.2-12. TRACE ELEMENTS CONCENTRATION OF A COAL GASIFIER
CALCULATED ON A RAW COAL BASIS
Trace
Element
Hg
Se
As
Te
Pb
Cd
Sb
V
Ni
Be
Cr
Gas
Overhead
«>
96
74
65
64
63
62
33
30
24
18
0
Spent Char
Bottom
(%)
4
26
35
36
37
38
67
70
76
82
100
*The T4 of the trace element in the overhead gas was calculated
by difference since only solid analysis was done.
Source: AT-042
86
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Estimation of the Fate of Trace Elements in the
TOSCO II Retort
The fate of trace elements in oil shale can be estimated
in the TOSCO II retort. Radian has developed a computer program
that estimates the composition of a system at chemical equilibrium.
The Radian Equilibrium Program is capable of estimating the equi-
librium composition of various systems based on the composition
of material going into the system and the temperature and pressure
of the system. The program is based on the thermodynamic principle
that chemical equilibrium is reached when the free energy of the
system is minimized. However, there are certain assumptions that
limit the validity of the program when it is applied to oil shale
systems. These assumptions and their implications are discussed
below:
There are no rate calculations performed in
the program. The real system may not actually
be at equilibrium, but the program assumes
that it is. Discrepancies between the cal-
culated composition of the system and the
real composition of the system can result.
Composition of the kerogen in the raw shale
was available (CO-175), but the concentrations
of the trace elements was only available for
the processed shale (CO-175) (see Table 2.2-11).
One source (US-291) states that: "processed
shale contains essentially all of the metallic
elements found in raw shale." However, the
relative concentrations of the trace elements
should change as the more volatile elements
become depleted in the processed shale.
Nevertheless, qualitative trends of the fate
87
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of trace elements can be estimated from the
processed shale composition. These calcu-
lations cannot be considered quantitative.
The program assumes that all the chemical
species are available for reaction. In
reality, some of the trace elements may be
trapped in the mineral structure. These
elements will not contribute to the pre-
dicted reactions. This is another reason
that the calculations must be considered
qualitative, rather than quantitative.
The results of the Radian Equilibrium Program indicate
that the following species tend to be enriched in varying degrees
in the gas phase of the TOSCO II oil shale retort C-the program
printout is included in the Appendix).
selenium boron arsenic
cadmium germanium lead
mercury antimony tin
The program also indicates that the following trace
elements tend to remain with the processed shale:
beryllium copper nickel
cobalt manganese uranium
chromium molybdenum zinc
barium
The remaining trace elements in the processed shale
listed in Table 2.2-11 are not considered by the equilibrium
program.
88
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Data Analysis
The fate of the trace elements in the similar processes
is compared to the calculated trends for oil shale processing in
Table 2.2-13. All of the trace elements predicted to be volatile
in oil shale retorting are also volatile in coal-fired boilers
and coal gasification. The nonvolatile elements predicted for
oil shale retorting that are also nonvolatile in coal-fired
boilers are Be, Mh, and Ba. In coal gasification, Be has a low
fraction in the vapor phase (18%), all of which may be the result
of analytical error.
TABLE 2.2-13.
FATE OF TRACE ELEMENTS IN OIL
SHALE AND SIMILAR PROCESSES
Trace
Element
Be
Se
Cd
Hg
As
Pb
B
Co
Cr
Cu
Ge
Mn
Mo
Ni
Sb
Sn
U
Zn
Ba
Oil Shale Retorting
(Radian Equilibrium Program)
N/V
V
V
V
V
V
V
N/V
N/V
N/V
V
N/V
N/V
N/V
V
V
N/V
N/V
N/V
Coal-Fired Boiler
(Radian Data)
N/V
V
V
V
V
V
V
V
V
V
V
N/V
V
V
V
V
V
V
N/V
Coal Gasifier
(IGT HYGAS)
V (187.)
V (74%)
V (62%)
V (96%)
V (65%)
V (63%)
-
-
N/V (0%)
-
-
-
-
V (24%)
V (33%)
-
-
-
V = volatile trace elements
N/V = nonvolatile trace elements
89
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Elements which are predicted nonvolatile in oil shale
retorting but volatile in a coal-fired boiler are Co, Cr, Cu, Mo,
Ni, U, and Zn. Of this group, Cr is nonvolatile in coal gasifi-
cation and Ni is only partially vaporized (24%), all of which may
also be due to analytical error. No comparisons with coal gasi-
fication could be made with Co, Cu, Mo, U and Zn. However, the
trend is that elements predicted to be nonvolatile in oil shale
retorting also have little or no volatility in a coal gasifier.
The comparisons indicate that the Radian Equilibrium
Program predictions for trace elements are reasonable. In addi-
tion, analysis of the shale oil by Atlantic-Richfield (BU-172)
indicates that arsenic is present in high levels in the synthetic
crude. This corresponds with the computer predictions for oil
shale processing.
Ultimate Fate of Trace Elements
The volatile trace elements in oil shale will be present
in the crude synthetic oil. Many of the elements must be reduced
in concentration before the crude is refined. Two general ap-
proaches to upgrade raw shale oil are coking and hydrotreating.
The trace elements can be concentrated in the primary
fractionation tower bottoms and then fed to a coker where the
trace elements are again concentrated in the heavy ends from the
coker and on the coke. Arsenic is an exception (BU-172). It
cannot be concentrated in a fractionation tower, since it is
distributed throughout the entire boiling range. Alternative
dearsenation steps are being developed such as irradiation with
ultraviolet light and treatment with metal oxides.
The trace elements that remain in the processed shale
may be leached by rainfall or snowmelt from shale disposal sites.
90
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Precautions must be taken to prevent drainage from oil shale
disposal sites from entering water sources near the site.
2.2.4.2 Trace Organics
Kerogen is the organic polymer contained in oil shale
When heated, kerogen decomposes to yield hydrocarbon gases and
liquids. These hydrocarbon products can be processed and re-
fined in much the same manner as petroleum.
A hypothetical structural model of Green River oil
shale kerogen is presented in Figure 2.2-8 (SC-257). From this
'model it can be seen that five and six carbon rings are basic
structures in the kerogen matrix. Also present are disulfides,
ethers, and esters. No organic nitrogen compounds are shown
although nitrogen is present in rather large quantities. The
chemical analysis of kerogen is presented in Table 2.2-14.
TABLE 2.2-14. CHEMICAL ANALYSIS OF KEROGEN
Organic Component,
Component Weight Percent
Carbon 80.52 ± 0.40
Hydrogen 10.30 ± 0.08
Nitrogen 2.39 ± 0.10
Sulfur 1.04 ± 0.08
Oxygen 5.75 ± 0.49
Source: CO-175
Very little information is available concerning the
specific components that exist in shale oil. The location and
type of oil shale probably affects the composition of the shale
oil, since the composition of other fossil fuels, such as crude
91
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Ni
S —S —
— o —
*°
-c - o-
D
O
E
I
C
BRIDGES
MONOMERS
The left are the monomers of the multipolymer, kerogen. I, represents isoprenods; T, terpenoids;
and C, carotenoids. Bridges can be disulfide (D), ether (0), ester (E), isoprenoid (I), and caro-
tenoid (C) linkages. The entrapped molecules in the matrix of the network are not bonded.
FIGURE 2.2-8 HYPOTHETICAL STRUCTURAL MODEL OF GREEN RIVER OIL SHALE KEROGEN
-------
oil, coal, and natural gas, are dependent upon their location
and origin. The type of retort used probably also affects the
composition since retorts operate at different temperatures with
heat supplied by different mechanisms.
Experimental Studies of the Fate of Trace Organics
in Shale Oil Processing
Analogous coal processes which produce organic compounds
are coal gasification, liquefaction, coking, and combustion in
coal-fired boilers. Very little is known at present on the com-
position of organics from gasification and liquefaction processes.
Battelle (BA-261) reported forty-two toxic and hazardous
organic substances likely to be emitted by industrial boilers
(see Table 2.2-15). The organic compounds are listed in order
of their decreasing health hazard. The first twelve compounds
are all potent carcinogens. This rating is intended only as a
guide since a direct comparison of the potency of the various
hazardous materials is not always possible.
In a coke plant, cyclic and polycyclic organic matter
present in coke oven emissions will be found in the fraction which
has been defined as tar. The principal compounds obtained from
coal tar as presented by (RO-153) and (MO-125) are given in Tables
2.2-16 and 2.2-17, respectively. Several of the more widely
accepted carcinogens are species of benzpyrene. Data resulting
from the above samples clearly indicated the presence of benz(c)
phenathrene (potent carcinogen), benz(a)anthracene (carcinogen),
a benzfluoranthene isomer (possible carcinogen), benz(a)pyrene
(potent carcinogen) and/or benz(e)pyrene, and cholanthrene
(carcinogen).
93
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TABLE 2.2-15.
TOXIC AND HAZARDOUS SUBSTANCES LIKELY
TO BE EMITTED BY INDUSTRIAL BOILERS
Organic Materials
7,12-Dimethylbenz(a)anthracene
3-methylcholanthrene
Dibenz(a,h)anthracene
Benz(c)phenanthrene
Benz(a)pyrene
Dibenz(a,h)pyrene
Dibenz(a,i)pyrene
Dibenz(c,g)carbazole
4-Aminobipheny1
Benzidine
1-Naphthylamine
4-Nitrobiphenyl
PhenyIhydraz ine
Methyl-phenyIhydraz ine
Dibenz(a,j)acridine
Dibenz(a,h)acridine
Cholanthrene
Dibenz(a,j)anthracene
Dibenz(a,g)fluorene
Indeno(l,2,3-cd)pyrene
Dibenzo(a,1)pyrene
Benz(a)anthracene
Chrysene
Dibenz(a,c)fluorene
Dibenz(a,h)fluorene
Dibenz(a,i)carbazole
Benz(a)carbazole
Dibenz(c,h)acridine
Picene
Dibenz(a,g)carbazole
Benzoquino1ine
Pyridine
Acridine
Aniline
Benz(j)fluoranthene
Benz(b)fluoranthene
Dibenz(a)anthracene
Dibenz(a,c)anthracene
Phenol
Benzthiophenes
Dibenzthiophenes
Thiophene
Sourer: BA-261
94
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TABLE 2.2-16. PRINCIPAL COMPOUNDS OBTAINED FROM COAL TAR
Hydrocarbons
Nitrogen Compounds
Oxygen Compounds
Naphthalenes
Acenaphthene
Fluorene
Anthracene
Phananthrene
Chrysene
Pyrene
Fluoranthene
Pyridines
Quinoline
Carbazole
Acridine
Picoline
Phenols
Cresols
Xylenol
Naphthols
Source: RO-153
TABLE 2.2-17. COMPOUNDS OBTAINED FROM COAL TAR
Benzene
Toluene
Xylenes
Phenols
Cresols
Naphthalenes
Anthracene
Phenanthrene
Thiophrene
Thiophene
Pynole
Pyridine
Quinoline
Source: MO- 125
-------
The structure of the functional groups in oil shale is
similar to that of coal: Both fossil fuels contain groups of six
carbon rings fused together. Decomposition of the kerogen in oil
shale could result in the production of polycyclic organics as in
the coal processes discussed above. Some of these polycyclic or-
ganics may be carcinogenic.
The processing of shale oil also has many similarities
to crude petroleum refining processes. Indeed, many refinery
processes are likely to be used in commercial oil shale processing,
It is likely that many of the compounds present in crude oil are
also present in shale oil.
Crude oil composition has been studied for many years
and analysis is still being done on crude oil fractions. Crude
oil contains many organics, some of which are quite toxic in
higher concentrations than those usually found in crude oil.
Likewise, it is probable that organics in shale oil exist in
concentrations below toxic levels. More studies on shale oil
composition and toxicity should be conducted to adequately assess
the health effects of the components.
Shale oil retorting produces a processed shale contain-
ing residual carbonaceous material. The previous discussion has
established the possible production of polycyclic organics in
oil shale processing. Polycyclic organics have a low volatility.
If produced in the process, they will most likely remain with the
carbonaceous material on the processed shale.
Studies have been conducted to determine if there is
carcinogenic potential in processed shale. These investigations
compare the polycyclic organic content in samples of soil, water,
vegetation, and air from pristine areas to samples of carbonaceous
96
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processed shale from various retorting processes. The samples
were analyzed for polynuclear aromatic hydrocarbons (PAH), in-
cluding those of known carcinogenic properties such as 3,4-benz(a)
pyrene.
Preliminary results of these comparisons (SC-257)
indicate that the content of benz(a)pyrene (BaP) in benzene ex-
tracts of carbonaceous oil shale is about one order of magnitude
higher than that in extracts of soil and/or plant material from
the pristine environment. Preliminary data also indicates that
saline water from leached carbonaceous shale may be at least
three to four orders of magnitude higher in PAH content than
ground or surface water from pristine areas. It can be concluded
that polycyclic organics can be leached from carbonaceous pro-
cessed shale in the presence of inorganic salts (SC-257). A
conclusion of the potential levels of leached PAH has yet to be
reached.
The spent shale from high temperature retorts is almost
completely free of carbonaceous material. Retorts operating at
intermediate temperatures, such as the Paraho process, and lower
temperatures, as in the TOSCO II process and Union Retort B, pro-
duce a processed shale containing residual organic carbon. These
carbonaceous spent shales may contain aza-azarines in addition to
PAH (SC-257). Table 2.2-18 lists some compounds identified in
carbonaceous spent shale along with the compounds' potential car-
cinogenicity (SC-239).
Presently, oil shale facilities are planning to design
for "zero discharge" of water runoff from processed shale disposal
sites. It remains to be seen whether the amount of PAH with car-
cinogenic properties will constitute a serious hazard to the en-
vironment. Additional data is needed along with more experimental
studies to determine the impact of the PAH on the environment.
97
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In addition, the effect of atmospheric oxidation of carbonaceous
material on exposed processed oil shale needs to be studied.
TABLE 2.2-18. POM* COMPOUNDS IDENTIFIED IN BENZENE EXTRACT OF
CARBONACEOUS SHALE COKE FROM GREEN RIVER OIL SHALE
Potential
Name of Compound Carcinogenicity
Phenanthrene
Fluoranthene
Pyrene
Anth anthrene (dibenzo(cdjk)pyrene)
Benz(a)anthracene (1,3-Benzanthracene) +
Benz(a)pyrene +-H-
7,12-Dimenthyl(a)anthracene I I I I
Perylene
Acridine
Dibenz(a,j)acridine (1,2-
7,8-dibenzacridine) ++
Phenanthridine ?
Carbazole
*POM = polynuclear organic matter
+ = high carcinogenic potential
- = low carcinogenic potential
Source: SC-239
BaP Concentrations in Oil Shale Processing Products
Analytical work indicates that processed shale from
the TOSCO II process contains less than 40 parts per billion (ppb)
of BaP (CO-615). Analysis also shows that the PAH compounds
found in processed shale are present in raw shale. Table 2.2-19
presents the BaP content of many common materials found in the
environment for comparison (CO-615).
98
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TABLE 2.2-19. BaP CONTENT OF PROCESSED SHALE AND COMMON MATERIALS
Material BaP (ppb)
Coconut Oil 43.7
Peanut Oil 1.9
Oysters (Norfolk, Va.) 10 to 20
Forest Soil 4 to 8
Farm Field near Moscow 79
Oak Leaves 300 max.
Processed Shale (Colony) 38
Source: CO-615
The BaP content of shale oil is considerably higher
than that of processed shale. The BaP concentrations in materials
from the TOSCO II process are presented in Table 2.2-20. The
concentrations of BaP are given for raw oil shale, processed shale,
crude shale oil, hydrotreated shale oil, and shale oil coke
(CO-615). Table 2.2-21 shows the BaP content of shale oil com-
pared to other oils (CO-615).
TABLE 2.2-20. BENZ(a)PYRENE CONCENTRATIONS IN
OIL SHALE RELATED MATERIALS
Material Concentration (ppb)
Raw Oil Shale 15*
Processed Oil Shale 30*
Crude Shale Oil 3,130*
Hydrotreated Shale Oil 690
Shale Oil Coke 129
*Samples analyzed at TOSCO and Eppley Laboratories
Source: CO-615
99
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TABLE 2.2-21. BaP CONTENT OF PETROLEUM PRODUCTS
Petroleum Products BaP (ppb)
Libyan Crude Oil 1,320
Cracked Residuum (API Sample 59) 50,000
Cracked Sidestream (API Sample 2) 2,000
West Texas Paraffin Distillate 3,000
Asphalt 10,000 to 100,000
Raw Shale Oil (Colorado) 3,200
Hydrotreated Shale Oil (0.25% N) 800
Source: CO-615
100
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3.0 COAL GASIFICATION PROCESSING
This section of the report presents a description of
coal surface (strip) mining and coal gasification. The Lurgi
process is described for production of low-, medium-, and high-
Btu gas. Process modules are defined and the impact of the mod-
ules is assessed.
3.1 Coal Surface Mining
Coal is one of the most significant of the western
energy resources. Proven reserves of coal amount to almost 122
billion metric tons in the western states alone, and total U.S.
coal consumption in 1973 was near 0.5 billion metric tons (RA-150)
Most experts believe that if the U.S. is to reach or
even approach energy self-sufficiency, the vast coal reserves in
the western states must be utilized. The coal found there is
characteristically low in sulfur, ash, and Btu content and lies
close to the surface in thick seams. It is expected that sur-
face or strip mining techniques will be employed for extracting
these reserves. The objective of this section is to provide a
description of the processes involved in the surface mining of
coal.
Coal Extraction
A surface mine is first opened by making a cut on the
thinner overburden side of the coal seam (commonly called the
crop line). The valuable topsoil removed from over the coal
seam is stored until it can be replaced in areas being reclaimed.
The topsoil is usually removed by self-loading scrapers.
101
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After removal and storage of the topsoil, the over-
burden is prepared for removal. This preparation involves the
forming of a smooth working surface called a bench with the
stripping machine and bulldozers. The bench matches the width
of the pit being dug so the moving vehicles and machinery will
have a clear area for moving about.
Upon completion of the bench, a predetermined pattern
of holes extending down to near the top of the coal seam are
drilled. These blast holes are drilled in a pattern which de-
pends upon the composition and thickness of the overburden. The
blast holes themselves are 25 to 40 cm (10 to 15 inches) in di-
ameter. The cuttings from these holes are removed by compressed
air, collected by a cyclone dust collection system built into
the drills, and deposited on the ground near the hole. After
placement of the explosive, the cuttings are used to backfill
the hole.
Following the drilling the holes are charged with ex-
plosives. The size of the charge injected depends upon the
materials encountered in the overburden, the locations of the
various strata to be blasted, the spacing of the adjacent holes,
and the total depth of overburden.
When the charges have been set and all equipment moved
to a safe location, the holes are connected for detonation by a
detonating fuse and/or electric blasting caps. A delay connector
insures proper detonation. It provides the best fregmentation
of the coal with minimal vibration and dust generation.
Once the overburden has been blasted, it is ready for
removal. Long-reach electric- or diesel-powered draglines are
commonly used as the overburden removal tool. Alternatively, a
102
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mine may use diesel powered shovels. The dragline positions
itself on the bench for removal of the overburden. It then pro-
ceeds parallel with and down toward the coal seam. Simultane-
ously, the dragline and bulldozers are constructing a bench to
replace the one being removed. The cycle continues until the
overburden thickness reaches an economic or physical limit.
After overburden removal, the surface of the coal seam
is cleaned of any material left with a bulldozer. Should the
coal need to be fractured prior to loading, a grid of blast holes
is drilled into the seam. Charges are detonated and fracture the
coal in planes, allowing easy digging and loading with minimal
coal dust emissions.
The loading of the cleaned and possibly fractured coal
is the next step in surface mining. Loading is often accomplished
with a large electrically-powered shovel. An articulated front
end loader is used for support and clean-up work. Typically, the
coal is loaded directly into large off-highway-type trucks. These
trucks usually discharge their load directly into hoppers which
.feed via conveyors directly to the crushing and sizing plant.
Coal Sizing
Coal preparation facilities are designed to provide
properly sized coal to the plant gasifier. Preparation operations
also generate coal fines which cannot be fed into the Lurgi gasi-
fier and are consequently sold, gasified in a small Lurgi gasifier
to produce plant fuel, or burned in the plant boilers. A number
of facilities are included in the preparation operation. These
are run-of-mine coal unloading, primary crushing, primary screen-
ing, secondary crushing and screening, coal storage, reclaiming,
coal fines cleaning, and associated belt conveyors.
103
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The run-of-mine coal is usually hauled by truck, con-
veyor, or rail to hoppers which feed into the coal preparation
area. Here the coal is crushed and screened to a minus 5 cm
product. Oversize coal goes to a secondary crusher where it is
reduced to a minus 5 cm product. Crushing and screening oper-
ations can be performed either at the mine site or at the gasi-
fier plant site.
The sized coal from the primary and secondary crushing
operations is next loaded on a belt conveyor. This conveyor
transports the coal to storage stock piles.
Coal from the stock piles is transported by covered
conveyors to active storage bins. These bins are designed for
two or more days' storage capacity and serve primarily as surge
capacity. Active storage bins are covered and equipped with
dust collectors.
In preparation for emergencies a large supply of coal
is set aside in dead storage. This coal pile is prepared on an
impermeable base. As a guard against wind and water erosion and
the resulting pollution, dead storage piles may be sprayed with
asphalt or polymer crusting agents (BU-087, FA-084. MA-294).
From the storage bins, the coal is transported to a
screening arrangement which sorts the coal into three sizes:
1) minus 5 cm to 1 cm,
2) minus 1 cm to 2 mm, and
3) smaller than 2 mm (fines).
The first two categories are fed separately into the Lurgi gasi-
fier while the coal fines are cleaned for use in the plant boilers
Excess fines go to sales or gasification.
104
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3.1.1 Module Basis
The coal strip mining module is based upon an operation
capable of supplying sufficient amounts of sized coal for a high-
Btu Lurgi coal gasification complex producing 8.2 x 10s Nm3/day
of SNG (288 MMscfd). The required output for the module is 25,600
metric tons/day of coal (28,000 TPD). A summary of the environ-
mental impact from the mining and sizing operations is presented
in Table 3.1-1.
TABLE 3.1-1. SUMMARY OF ENVIRONMENTAL IMPACT
FROM COAL STRIP MINING
Basis: 25,600 MT/day (28,000 TPD) of coal
Air (kg/day)
Particulates 3794
S02 83
NOX 1125
HC 130
CO 676
Water Effluents 0
Thermal neg
Solid Wastes (MT/yr) 15.6 x 10s
Ancillary Energy (kcal/hr) 1.84 x 107
Energy Recovery Ratio 0.997
3.1.2 Module Description
The basic steps involved in area stripping operations
are shown in Figure 3.1-1.
105
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TOPSOIL
REMOVAL
o
cr>
OVERBURDEN
REMOVAL
OVERBURDEN
REPLACEMENT
GRADING AND
TOPSOIL
REPLACEMENT
COAL
EXTRACTION
MINE
DRAINAGE
CRUSHING
AND
GRINDING
WASTE
WATER
TREATMENT
T
COAL
STORAGE
PRODUCT
COAL
COAL PILE
RUNOFF
RECLAIMED
WATER
REVEGETATION
FIGURE 3.1-1 STEPS INVOLVED IN AREA STRIPPING OPERATION
-------
Topsoil and overburden are first removed and placed in
separate storage areas. After the exposed coal seam is mined,
overburden and topsoil are replaced and reclamation activities
begin. In an established strip mine, mining and reclamation
activities take place on a simultaneous, continuous basis.
In addition to the mine site operations just mentioned,
major facilities found at a typical strip mine include haulage
roads, run-off water collection and treatment facilities, and a
crushing and sizing plant. In this study, the mining module is
assumed to include all the steps necessary to prepare coal for
subsequent processing in a Lurgi gasification complex.
Flow Rates
Coal facilities in the mine and sizing area handle an
average of 25,680 Mr/day (28,250 TPD) of sized coal. During the
crushing and screening operations coal fines are formed and sep-
arated at the rate of approximately 9,000 MT/day (9900 TPD)
(WY-007). These fines are cleaned and sold. The total amount
of coal mined daily is therefore about 34.680 metric tons
(38,150 TPD).
Energy Requirements
The energy requirements for this module are summarized
on Table 3.1-2. The numbers were derived from a Hittman Associates
report (HI-083). The estimates are based on a hypothetical sur-
face mine in the Powder River Basin.
107
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TABLE 3.1-2.
DAILY ENERGY REQUIREMENTS FOR
WESTERN COAL SURFACE MINING
Operation Electricity
(kWh)
Mining 0.63 x 10 5
Hauling
Crushing 1.20 x 10 5
Reclamation
Total 1.83 x 10s
Diesel Fuel
a)
16,039
3,503
5,730
150
25,422
Total
(kcal)
2.2 x 108
.3 x 10®
1.9 x 108
.02 x 108
4.42 x 108
Energy Recovery Ratio
The energy recovery ratio for this module was determined
by dividing the total heating value of the coal produced (34,680
metric tons/day or 1.67 x 1011 kcal/day) by the sum of this number
and the module energy requirement. The energy recovery ratio for
this module is 0.997-
Water Requirements
•
The only process water requirements for the mining mod-
ule consist of the water used for dust control in the sizing
operations and along haulage roads. El Paso Natural Gas estimates
that about 6.54 x 106 I/day (1200 gpm) of water is needed for a
mine this size (US-112).
3.1.3
Module Emissions
This section presents the environmental impacts of coal
surface mining. Air, water, and solids emissions are discussed
and estimated using information from the Environmental Assessment
(WY-007) for the Wyoming Coal Gas and Rochelle Coal Company coal
gasification project.
108
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Air Emissions
Major sources of air emissions found within a typical
strip mining operation include:
extraction operations,
coal sizing,
ash handling, and
reclamation.
Table 3.1-3 presents the atmospheric emission estimates
for this module. The use of emission control equipment was not
assumed in calculating these estimates.
TABLE 3.1-3. ATMOSPHERIC EMISSIONS FROM COAL SURFACE MINING
Basis: 34,680 MT/day (38,
Wind erosion
Overburden excavation
Ash handling and disposal
Blasting of overburden
Mining roads
Blasting of coal
Drilling
Topsoil removal and storage
losses
Coal crushing, screening, loading,
sizing, and conveying
T^T OGP *I onii "i "nniPTif"
UXCOC J_ *— *i LL -L^/lllC-llL.
Total
150 TPD) coal mined
Emissions (kg/day)
Part S02 N0x HC
190
1500
500
374
320
40
50
25
750
45 83 1125 130
3794 83 1125 130
CO
676
676
109
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Extraction Operation
The dust generated from the various extraction activ-
ities is the major atmospheric emitter in this module. SERNCO
reports that approximately 120 acres per year for a typical oper-
ation are disturbed due to surface mining operations (WY-007).
Blast hole preparation by drilling releases noticeable
amounts of particulates. For a surface mine producing similar
rates of coal as this module, SERNCO (WY-007) estimates that up
to 50 kg/day (110 Ib/day) of particulates are discharged from
the drilling of blast holes. The blasting of the overburden in-
jects a considerable amount of dirt and dust into the atmosphere,
but this operation occurs only periodically. SERNCO estimates
that blasting emits 374 kg/day (824 Ib/day) of particulates less
than lOy in diameter. Larger diameter particules are assumed to
settle out in the immediate vicinity of the mine.
The fugitive dust emitted during the removal of the
overburden is the main source of particulates in a coal surface
mine. For this phase of mining, SERNCO estimates that roughly
0.035 kg of dust is discharged per metric ton of overburden
moved. Assuming 15.6 x 10s MT per year of overburden is removed
(WY-007), this results in particulate emissions of approximately
1500 kg/day (3000 Ib/day). Some dust is also released in the
shooting of the coal. SERNCO estimates these emissions to be
about 40 kg/day. Another source of fugitive dust is wind erosion.
Based on an equation developed by PEDCo-Environmental for esti-
mating these losses, a daily emission of 190 kg (420 Ib) of par-
ticulates is calculated (CO-352).
Hauling the coal on mine roads will result in the dis-
persion of dust from both payloads and road surfaces. SERNCO
110
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estimates that 320 kg/day (705 Ib/day) of participates result
from coal hauling.
The removal of topsoil and its storage prior to mining
is another source of dust in this module. It is estimated by
SERNCO that this operation discharges 25 kg/day (55 Ib/day) of
dust to the atmosphere. Wetting of the topsoil to reduce emis-
sions is not planned.
The diesel-powered equipment constitute a major source
of emissions. This equipment consumes approximately 25,400 liters
of fuel (6,700 gal) each day according to Table 3.1-2. The total
estimated daily emissions from all equipment for this module is
summarized in Table 3.1-4. The emission factors used were for
heavy-duty diesel vehicles (EN-071).
TABLE 3.1-4. ATMOSPHERIC EMISSIONS FROM DIESEL-POWERED EQUIPMENT
Pollutant
Particulates
SOa1
NOX
HC
CO
Emission Rate
37
83
1125
130
676
(kg/ day)
1 Based on average sulfur content for diesel fuel of 0.2 percent.
Coal Sizing
The crushing, sizing, screening, and conveying activ-
ities result in the discharge of a moderate amount of dust. From
these operations greater emissions may occur during the dry. hot,
summer months. SERNCO estimates that 0.025 kg of dust are emitted
per metric ton of coal crushed, screened, sized, and conveyed
111
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(WY-00/). Therefore, approximately 750 kg/day (1650 Ib/day) of
particulates are emitted from this module. These operations will
be covered to aid in reducing dust emissions. No other controls
are planned.
Ash Handling
The short-haul transportation of gasifier ash from the
plant back to the, mine generates a small amount of fugitive dust.
These emissions are minimal since the ash is wet. SERNCO esti-
mates that this operation results in particulate emissions of
500 kg/day (1100 Ib/day). Since the material is hauled wet, no
dust controls are planned.
Liquid Effluents
All mine drainage and surface run-off is assumed to
be collected, treated, and used to satisfy mine site water de-
mands (dust suppression). Therefore, no liquid effluent streams
are anticipated. Since no water effluents are assumed, thermal
discharges are negligible.
Solid Wastes
The mine overburden must be disposed of at a rate of
15. 6 x 10s MT per year. This quantity represents the solid
waste generation rate of this module.
3.2 Coal Gasification
The gasification of coal to form a low-, medium-, or
high-Btu synthetic gas is one means of supplying the demand for
natural gas. Many coal gasification projects have been proposed
with several scheduled to begin construction in the near future.
112
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Technology has been available since the mid-1800's for
the production of a low-Btu gas from coal. The process studied
in this report was successfully proven on a pilot scale in 1930.
A. Cr. Saechsische Werke built this pilot plant at Hirschfelds,
Germany. Werke's process was the forerunner of the Lurgi pro-
cess which was developed by Lurgi Mineraloltechnik, GmbH, a West
German company. This is still the only commercially successful
high-pressure technique for producing a low-Btu gas from coal.
As of 1974, sixteen plants have applied this technology (US-112).
These plants have produced town gas or low-Btu gas. Almost sixty
grades of coal, including coke, anthracite, semi-anthracite,
bituminous and subbituminous coals, coking coals, lignite, and
peat have been successfully processed.
Currently no commercial scale facility exists which
produces high-Btu gas. A number of methanation pilot plants and
a demonstration plant in Scotland, though, have produced a high-
Btu gas from Lurgi synthesis gas.
The objective of this section is to provide a descrip-
tion of the processes of producing low-, medium-, and high-Btu
synthetic gas using Lurgi technology. A discussion of the high-
Btu Lurgi gasification process is followed by a discussion of
the low- and medium-Btu Lurgi gasification processes.
3.2.1 High-Btu Lurgi Gasification
High-Btu coal gasification produces a synthetic natural
gas (SNG) with a heating value of 8400 to 8900 kcal/Nm3 (950 to
1000 Btu/scf). Figure 3.2-1 shows a simplified flow diagram of
the major steps in Lurgi high-Btu gasification. The following
paragraphs provide a brief description of the process steps.
113
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OXYGEN
COAL
GASIFICATION
SHIFT
CONVERSION
GAS
COOLING
GAS
PURIFICATION
METHANATION
T
GAS
DEHYDRATION AND
COMPRESSION
STEAM
SNG
FIGURE 3.2-1
GENERAL FLOW DIAGRAM OF
LURGI HIGH-BTU GASIFICATION
114
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Gasification
Figure 3.2-2 shows a diagram of the Lurgi gasifier.
Coal is fed intermittently into the gasifier via a coal pressure
lock. As the coal travels slowly downward, it contacts a hot
rising stream of synthesis gas and is heated to 370 to 590°C
(698 - 1094°F). This heating causes the coal to be successively
dried, devolatilized, and gasified. Coal undergoes devolatili-
zation according to Equation 3-1:
Coal + Heat -»• C + CHi, + Organics (3-1)
The devolatilized coal reacts further with the rising hot syn-
thesis gas in the gasification zone of the gasifier according
to Equations 3-2 and 3-3:
C + 2H2 £ CiU + Heat (3-2)
C + H20 + Heat £ CO + H2 (3-3)
The synthesis gas also undergoes reactions according to Equations
3-4 and 3-5:
CO + H20 Z C02 + H2 -I- Heat (3-4)
CO + 3H2 £ OU + H20 + Heat ' (3-5)
From the gasification zone, unreacted coal descends to
the combustion zone. Here, steam and pure oxygen injected at the
bottom of the gasifier react with coal according to Equations 3-3
and 3-6, supplying the heat to the gasifier as well as the syn-
thesis gas required in the gasification and devolatilization
zones:
115
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FF.ED COAL
COAL PREHEAT a
DEVOLATILIZATION
ZONE
SCRUBBING COOLER
GASIFICATION
ZONE
COAL
DISTRIBUTOR
ASH QUENCH V/ATER
COMBUSTION
ZONE
STEAM + OXYGEN
ASH
ZONE
ASH
QUENCH
CHAMBER
Source: TJS-112
\
ASH
FIGURE 3.2-2 THE LURGI GASIFIER
116
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C + H20 + Heat ? CO + H2 (3-3)
C + %02 * CO + Heat (3-6)
A revolving ash grate at the bottom of the combustion
zone supports the coal bed and also distributes the steam and
oxygen or air fed to the gasifier. The grate also allows for
removal of ash. The ash exits the gasifier via lock hoppers and
is water quenched. It is then sent to a dewatering area. Steam
is used to pressurize the ash lock hoppers so that no gases will
be emitted to the atmosphere when the ash is released from the
locks.
A raw synthesis gas (see Table 3.2-1) composed mainly
of CO, C02, H2, CHit and steam (also N2 if the low-Btu gasification
scheme is used) is removed from the top of the gasification zone.
The gas is scrubbed with water to remove entrained particulates
and to condense heavy hydrocarbons.
Shift Conversion
In the high-Btu scheme the raw gas which leaves the
gasification section is split into two approximately equal streams,
one feeding into the gas cooling area and the other directed to
the shift conversion area. The primary function of the shift
conversion operation is to adjust the H2/CO mole ratio of the
mixed gas stream to 3.5 to 1 to optimize the methanation step.
The shift conversion is accomplished in a catalytic, adiabatic
water gas shift reactor via Equation 3-7:
CO + H20 ? C02 + H + Heat (3-7)
The operating conditions and catalyst are desijned to allow this
conversion to take place in the presence of heavy hydrocarbons,
tar oils, sulfur comp.ounds, and naphtha.
117
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TABLE 3.2-1. SYNTHESIS GAS COMPOSITION FOR AN
OXYGEN BLOWN LURGI GASIFIER
Component Volume Percent (Dry Basis)
C02 28.4
H2S 0.5
CO 19.9
H2 38.7
N2 + Air 10.3
OU 0.3
r is n i
\j 2n if U . J-
C2H6 . 0.6
C3H5
0.2
iH,
Source: US-349
Gas Cooling
The gas is cooled by generating low-pressure steam in
a waste heat recovery unit. The crude gas is cooled once more
in air or water heat exchangers to about 32°C. The synthesis gas
is now at a low enough temperature to be processed in the purifi-
cation section.
Gas Purification
Depending upon the sulfur content of the coal fed to
the gasifier, a certain amount of H2S and other sulfur compounds
will be present in the synthesis gas. These compounds must be
removed to acceptable levels prior to the fuels end use. The C02
present may also be removed, depending upon the specific situation,
118
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The purification step usually consists of a Rectisol
unit to remove sulfur compounds and C02, if desired, from the
synthesis gas stream. It is usually followed by a Glaus or
Stretford unit to recover the sulfur compounds as elemental
sulfur.
Methanation
The methanation step is designed to convert the medium-
Btu synthesis gas from the gas purification section to a high-Btu
gas by Equations 3-5 and 3-8:
CO + 3H2 t CIU + H20 + Heat (3-5)
C02 + 4H2 t OU + 2H20 + Heat (3-8)
If ethylene is present it is hydrogenated to ethane and then the
ethane is hydrocracked to methane according to Equations 3-9 and
3-10:
\
C2IU + H2 t C2H6 (3-9)
C2H6 + H2 * 2CH., (3-10)
All of these reactions are promoted by a nickel catalyst
designed specifically for methanation. In this stage the methane
content of the gas is increased from around 15 percent to about
93 percent and, correspondingly, the heating value from around
3800 kcal/Nm3 (430 Btu/scf) to 8400 kcal/Nm3 (950 Btu/scf) (US-112)
Gas Compression and Dehydration
Following methanation the synthesis gas is compressed
to a predetermined pressure. Then it is cooled in air and/or water
119
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heat exchangers and dehydrated. Dehydration is usually accom-
plished by one of the many common wet or dry systems. A typical
unit may be a glycol dehydration system which uses triethylene
glycol (TEG) as the drying agent.
Auxiliary Systems for Gasification Plant
In addition to the gas cleaning equipment just described,
other facilities including a primary water treatment unit, an am-
monia still, coal and by-product storage facilities, process steam
and power generation facilities, and an oxygen plant are required
for unit operations.
3.2.1.1 Module Basis
i
The high-Btu coal gasification module is based upon a
facility capable of producing 7.1 x 10s Nm3/day (250 x 10s scfd)
of SNG with a heating value of 8,746 kcal/Nm3 (983 Btu/scf).
This size was selected since it corresponds to the capacity of
the proposed WESCO Lurgi coal gasification complex to be con-
structed in the four-corners area of New Mexico. It is consid-
ered to be typical of the commercial plants to be constructed.
Extensive information is available on this process, including
heat and material balances and emission estimates. To produce
7.1 x 10s Nm3/day of SNG the plant will process about 22,560
metric tons/day (24,820 TPD) of coal. A summary of emissions
from the gasification plant is presented in Table 3.2-2. Emis-
sions of trace elements and trace organics is discussed in
Section 3.2.3.
120
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TABLE 3.2-2. SUMMARY OF ENVIRONMENTAL IMPACT FROM
LURGI HIGH-BTU COAL GASIFICATION
Basis: 7.1 x 10s Nm3/day of Synthetic Natural Gas
Air (kg/day)
S02 10,970
NOX 17,930
HC 210
NH 45
Particulate 790
Water (kg/day) 0
Thermal (kcal/hr) Neg.
Solid Waste (MT/day) 5,940
Water Requirements (fc/min) 20,100
Energy Recovery Ratio 0.69
Manpower Requirements (personnel) 600
Ancillary Energy (kcal/day) 1.44 x 109
3.2.1.2 Module Description
The Lurgi high-Btu processing module consists of the
gasifier, gas cleanup units, sections for upgrading the gas heat-
ing content, related auxiliary systems, steam production, and
by-product recovery and storage. The coal feedstock for the
module is a subbituminous coal with an analysis as shown in
Table 3.2-3. The composition of the product gas is shown in
Table 3.2-4.
TABLE 3.2-3. GASIFICATION COAL ANALYSES
Component
Ash
H20
Sulfur
Wt %
22.79
12.00
0.74
Heating Value = 4622 kcal/kg (8325 Btu/lb)
Source: US-349
121
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TABLE 3.2-4. COMPOSITION OF THE SNG PRODUCT
FROM DESIGN BASIS LURGI PLANT
Component
C1U
CO 2
CO
H2
N2. + Air
Total
Vol. %
96.84
0.50
0.06
1.45
1.15
100.00
Heating Value = 8746 kcal/Nm (983 Stu/scf)
Source: US-349
Processing Steps
The basic processing steps of the Lurgi coal gasifica-
tion process are shown in Figure 3.2-3. Sized coal is reacted
with steam and oxygen in the gas production area, producing a
raw synthesis gas. This gas then undergoes 1) shift conversion
to produce the proper H2:CO ratio for the methanation reactor,
2) cooling, 3) purification, 4) methanation and 5) dehydration
and compression. The auxiliary or by-product recovery areas
provide the facilities with water treatment, auxiliary power
generation, process heat dissipation and by-product recovery
and storage.
Flow Rates
The module flow rates have been taken from the Final
EIS on the WESCO coal gasification plant. The rates for the
major process streams are:
122
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NJ
SCMMATIC FLOW DH&KAM OF COAL GASIFICATION PLANT
ftau Mint
ru n smxtti
tn. to iroi*Gt
Source: US-349
FIGURE 3.2-3 OVERALL LURGI FLOW DIAGRAM
-------
Coal to Gasifier - 22,560 MT/day (24,820 TPD)
Gasifier Ash - 5,940 MT/day (6,534 TPD)
Synthetic Natural
Gas to Pipeline - 7.1 x 106 Nm3/day (250 MMscfd)
Crude Phenols - 93 MT/day (102 TPD)
Tar Oils - 686 MT/day (755 TPD)
Tar - 675 MT/day (743 TPD)
Ammonia - 185 MT/day (204 TPD)
Naphtha - 286 MT/day (315 TPD)
Sulfur - 184 MT/day (202 TPD)
Energy Requirements
The Lurgi coal gasification process requires auxiliary
ener"""- in the form of electricity and steam. To provide this
energy, coal is used to fire steam boilers. The energy require-
ments for the major plant users are:
Boiler Plant - 817.2 x 10s kcal/hr (3237 MMBtu/hr)
Electric Power - 60.1 x 10s kcal/hr (239 MMBtu/hr)
Steam Superheater
Fuel Oil - 81.4 x 106 kcal/hr (323 MMBtu/hr)
Energy Recovery Ratio
The energy recovery ratio is a means of measuring the
raw energy to product efficiency for a particular process. In
the synthetic fuels processing industry this measure is an im-
portant consideration since it provides a basis for comparison
of different types of processes. The energy recovery ratio is
defined as the ratio of the heating value of all the primary prod-
ucts to the heating value of the feedstock and fuel input to the
module. For this module the primary product is the SNG with a
heating value of 8746 kcal/Nm3. The average heating value of the
124
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feedstock is 4622 kcal/kg. The energy recovery ratio for the
Lurgi high-Btu gasification module is 0.69 (US-349).
Water Requirements
The water requirements for this module are based upon
the WESCO coal gasification plant. They estimate a water require-
ment of 20,100 liters/min (5309 gpm).
3.2.1.3 Module Emissions
This section contains multimedia emission estimates
from the Final Environmental Statement for the WESCO Coal Gasi-
fication Project (US-349). Trace element and trace organic emis-
sions are discussed separately in Section 3.2.3.
Air Emissions
Atmosphere emissions from the Lurgi facility result
from process and fugitive emission sources.
Process Emissions
Process sources include the coal lock hopper, steam
boiler, steam superheater, gas liquor expansion gas, gas liquor
vent gas, shift catalyst regeneration, Rectisol vent gas, Glaus
sulfur plant, and Stretford plant. Table 3.2-5 contains the
WESCO EIS emission estimates for the process sources (US-349).
Emissions from the coal lock occur during the decom-
pression cycle and the loading of the lock with coal. The gas
is vented to the atmosphere after particulate removal. The con-
trol efficiency of the particulate removal device is unknown.
125
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TABLE 3.2-5. PROCESS ATMOSPHERIC EMISSIONS FROM HIGH-BTU LURGI COAL GASIFICATION
N>
Source Stack Diameter (m)
Coal lock 2.73
Rectisol Vent gas
Steam boilers
Steam superheater
Glaus sulfur plant 5.15
!
Stretford plant
Gas liquor expansion
Cus liquor vent gas
Recovered hydrocarbons
TOTAL
Emissions for Total Stacks (kg/day)
Stack Height (m) No. of Stacks S02 N0x HC Particulates
60.61 1 744 1,056 10.824 24
1,848
5,832 15,816 — - 744
360 1.056 --- 24
90.90 1 1,320
168 ---
336
168
192
10,968 17,928 10.824 792
-------
Particulate emissions from the steam boiler are con-
trolled by electrostatic precipitators in combination with wet
scrubbers (US-349). Typical control efficiencies for this com-
bination is greater than 99 percent. After particulate removal,
the flue gases are combined with those from the steam superheater
and vented to the atmosphere via the large ninety meter (300 ft)
stack. The vented vapors from the gas liquor expansion and gas
liquor vent, shift catalyst regeneration, Rectisol unit, Glaus
sulfur plant, and Stretford plant are incinerated in the plant
steam boiler and combined with the flue gases from the boiler and
superheater and sent to the large stack. Incineration controls
virtually 100 percent of the hydrocarbon and carbon monoxide
emissions.
Figure 3.2-4 is a simplified diagram showing the dis-
position of the streams originating from the Rectisol Unit. The
rich HaS stream goes to the Glaus sulfur plant. The lean H2S
stream is routed to the Stretford Plant. The C02 off-gas vent
is sent to the plant boilers for incineration since it contains
from 1 to 3 percent hydrocarbons. Incineration in the boilers
should reduce the hydrocarbon emissions from this source by 100
percent.
Rich H2S Stream
to Glaus Plant
Lean H2S Stream
to Stretford Plant
Synthesis
Gas
C02 Offgas Vent
Rectisol Unit
Synthesis
Gas
FIGURE 3.2-4 DISPOSITION OF STREAMS FROM THE RECTISOL UNIT
127
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Intermittent emissions orginate from the local vent
and the plant flare. These emissions occur during startup or
emergency conditions. WESCO estimates emissions from the local
vent to be 1.8 MT/yr of S02 and 1.0 MT/yr of hydrocarbons. From
the flare, WESCO estimates 4.7 MT/yr of S02 are emitted.
Fugitive Atmospheric Emissions
Fugitive air emissions from the Lurgi gasification
process arise from equipment leaks such as pump seals, valves,
and flanges. Emissions from storage facilities are included.
High pressures encountered in many of the processing operations
of the Lurgi process enhance fugitive leaks from equipment. It
is assumed that fugitive emission losses are minimized by use of
the best available control techniques, including mechanical seals
on pumps and vapor recovery systems on storage facilities. In
addition, it is assumed that good maintenance practices are em-
ployed to help minimize equipment leaks.
By-product storage losses are calculated using the
method outlined in API Bulletin No. 2523 (AM-030) and information
in Compilation of Air Pollutant Emission Factors (EN-071). Vapor
recovery systems with a 95% recovery efficiency are assumed to be
employed for emission control on the by-product hydrocarbon and
ammonia storage vessels. Table 3.2-6 lists the results of the
storage emissions calculations.
Estimates of the fugitive emissions from valves and
pump seals are calculated from an emission factor of 0.23 kg/day
for these pieces of equipment when used in refinery services
(DA-069). Pump seal emission factors were doubled if the pump
handled high-pressure streams and halved if they handled water/
hydrocarbon streams. Table 3.2-7 lists-the adjusted pump seal
128
-------
emission factors, the number of pumps for each type of service,
and the pump seal emissions. All pumps are assumed to use mechan-
ical seals. Table 3.2-8 lists the valve emission factors, the
estimated number of valves and the valve emissions.
TABLE 3.2-6. BY-PRODUCT STORAGE EMISSION LOSSES
Naphtha Tar Oil Tar
Phenols
Ammonia
Total losses
(kg/day) 769
Total losses employing
vapor recovery
(kg/day) 38.5
745
20.3
493
13.4
90
2.4
1730*
45.3*
*Emission rate based on vapors being 96%
TABLE 3.2-7. PUMP SEAL EMISSIONS
Type of Stream
Handled by Pump
Number of
Pumps
Emission Factor,
kg/day
Air Emission,
kg/day
Water/Hydrocar-
bon Stream (low
pressure)
Hydrocarbon
Strean (low
pressure)
or
Water Hydrocar-
bon Stream
(high pressure)
Gaseous Stream
(high pressure)
TOTAL
18
48
48
12
0.05
0.10
0.10
0.20
0.9
4.8
4.8
2.4
12.9
129
-------
TABLE 3.2-8. FUGITIVE EMISSIONS FROM VALVES
Type of Service in Number of Emission Factor, Air Emission,
Which Valve in Used Valves kg/day kg/day
Gaseous 930 0.100 93
Liquid 1360 0.022 30
TOTAL 123
The composition of the fugitive emissions from valves
and pump seals is a mixture of the various hydrocarbon streams
found in the Lurgi plant. The discussion in Section 3.2.3 de-
scribes the compounds that may be present in the Lurgi process
and are potential fugitive emissions.
Liquid Effluents
The Lurgi coal gasification process is designed to
operate with "zero liquid discharge." All potential liquid
effluents are either treated for reuse within the process or
sent to evaporation ponds for disposal. Plant runoff is col-
lected in a storm water pond and then treated in the normal waste-
water treating system. Thus, no liquid effluents are discharged
from the boundary limits of the conversion facility.
Solid Wastes
Solid wastes from the Lurgi coal gasification plant
consist of 1) gasifier ash, and 2) lime softener sludge.
The coal fed to the gasifiers contains 22.79 weight
percent ash. Since all of this ash is removed from the gasifiers
130
-------
and sent to ash quenching, approximately 247,500 kg/hr of ash is
produced based on a coal rate to the gasifiers of 22,560 MT/day.
The gasifier ash contains a major portion of the trace
elements present in the coal feedstock. In addition, trace or-
ganics could be present in the ash effluent. The existence and
composition of these pollutants in the gasifier ash are discussed
in Section 3.2.3.
Approximately 230 kg/hr of CaCOs is produced in the
lime softener. These solids are transported in slurry form to
the ash quenching area where they are combined and disposed of
with the gasifier ash. The total solid waste to disposal is
247,700 kg/hr (511,400 Ib/hr).
3.2.2 Low- and Medium-Btu Gasification
The gasification of coal by the Lurgi process to pro-
duce either a low- or medium-Btu gas is an alternative to high-
Btu gasification. Low-Btu fuel gas has a heating value of
1330-2660 kcal/Nm3 (150-300 Btu/scf) and can be used as fuel in
either a conventional boiler or a combined cycle generating plant.
Medium-Btu gas has a heating value of 2660-4000 kcal/Nm3 (300-
450 Btu/scf). It can be used as a chemical feedstock or as fuel
in a conventional boiler or a combined cycle power generating
plant.
Low- and medium-Btu Lurgi gasification differ only in
the source of oxygen for the gasifier. The medium-Btu scheme
requires a 98%+ oxygen stream to the gasifier supplied by a cry-
ogenic oxygen plant while the low-Btu complex operates with an
air-blown gasifier as its source of 02. The nitrogen which en-
ters the low-Btu gasifier in the air dilutes the synthesis gas,
resulting in a lower heating value for the product.
131
-------
Figure 3.2-5 shows a simplified flow diagram of low-
and medium-Btu gasification. The primary difference between the
high-Btu process and the low- and medium-Btu processes is the
synthesis gas upgrading stages. Shift conversion and methana-
tion reactors are not present in low- or medium-Btu plants. The
remaining processes are discussed in Section 3.2.1.
3.2.2.1 Module Basis
The two modules are based on an output equivalent to
the high-Btu module on a Btu/day basis. The output from the high-
Btu module is 6.2 x 1010 kcal/day (2.45 x 10ll Btu/day) based on
a product gas with a heating value of 8746 kcal/Nm3 (983 Btu/scf).
The heating value for the low-Btu product gas is 1785 kcal/Nm3
(200 Btu/scf) and for the medium-Btu product gas is 4080 kcal/Nm3
(450 Btu/scf). The product flow rates are adjusted to these num-
bers. Therefore, the low-Btu module produces 34.5 x 10s Nm3/day
(1.22 x 109 scfd) and the medium-Btu module produces 15.4 x 10s
Nm3/day (5.44 x 108 scfd).
Summaries of emissions for low- and high-Btu gasifica-
tion plants are presented in Tables 3.2-9 and 3.2-10.
3.2.2.2 Module Descriptions
Separate descriptions are not provided since the low-
and medium-Btu modules are similar to the high-Btu module des-
cribed in Section 3.2.1.2.
3.2.2.3 Module Emissions
The emissions are calculated using the Wesco Final EIS.
Emissions should be similar to the emissions discussed for high-
Btu gasification in Section 3.2.1.3. However, more stringent
132
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STEAM
COAL
AIR or OXYGEN
y r
GASIFICATION
GAS
COOLING
GAS
PURIFICATION
GAS COMPRESSION
AND DEHYDRATION
LOW- or MEDIUM-BTU
SYNTHETIC GAS
FIGURE 3.2-5. GENERAL FLOW DIAGRAM OF LURGI
LOW- OR MEDIUM-BTU GASIFICATION
133
-------
TABLE 3.2-9. SUMMARY OF ENVIRONMENTAL IMPACT
FROM LOW-BTU LURGI GASIFICATION
Basis: 34.5 x 10s Nm3/day of gas (1,220 MMscfd)
Air (kg/day)
S02 10,100
N0x 17,930
HC 210
NH3 40
Particulates 792
Water (kg/day) 0
Thermal (kcal/hr) Neg
Solid Waste (MT/day) 5,470
Water Requirements ( £/min) 18,400
Ancillary Energy (kcal/day) 1.67 x 109
Energy Recovery Ratio .758
Manpower Requirements (personnel) 600
TABLE 3.2-10. SUMMARY OF ENVIRONMENTAL IMPACT
FROM MEDIUM-BTU LURGI GASIFICATION
Basis: 15.4 x 10s Nm3/day of gas (544 MMscfd)
Air (kg/day)
S02 9,740
NOX 17,930
HC 210
NH3 40
Particulates 792
Water 0
Thermal (kcal/hr) Neg
Solid Waste (MT/day) 5,280
Water Requirements (£/min) 17,900
Ancillary Energy (kcal/day) 1.62 x 109
Energy Recovery Ratio .784
Manpower Requirements (personnel) 600
134
-------
sulfur removal must be performed in the low-Btu Rectisol unit
due to nitrogen dilution of the product gas. This accounts for
differences in SOa emission rates.
3.2.3 Trace Element and Organic Emissions from Coal
Gasification
Available data concerning the formation and fate of
trace organics and elements in coal gasification processes is very
limited. However, limited analogies can be drawn between the gas-
ification process and the conventional coking and coal combustion
processes to give insight into the identification, quantification,
and ultimate fate of trace compounds produced in the gasification
process. The following sections discuss these analogies and pre-
sent some of the available literature data.
3.2.3.1 Trace Elements
Elements present in concentrations of 0.1% (1,000 ppm)
.or less are usually referred to as trace elements. The main
source of the trace elements found in coal is the mineral matter
associated with living plant tissues. Table 3.2-11 lists the
trace element analysis of a typical western coal.
Little information is available on the fate of trace
elements in a coal gasification plant. An analogy, however, can
be drawn between coal gasification and coal combustion. Basic-
ally the same trace elements will be in the coals fed to both
systems. Also, the gasification system includes a section in
which the coal passes through an oxidizing atmosphere similar
to that present in a boiler. However, this analogy has its lim-
itations .
135
-------
TABLE 3.2-11. TRACE ELEMENT CONCENTRATION
IN TYPICAL WESTERN COAL
Element
Antimony
Arsenic
Bismuth
Boron
Bromine
Cadmium
Fluorine
Gallium
Germanium
Lead
Mercury
Nickel
Selenium
Zinc .
ppm by weight
0.3
0.1
0.0
60.0
0.4
0.2
200.0
0.5
0.1
1.4
0.2
3.0
0.1
1.1
- 1.2
- 3.0
- 0.2
- 150.0
- 18.0
- 0.4
- 780.0
- 8.0
- 0.5
- 4.0
- 0.3
- 30.0
- 0.2
- 27.0
Source: US-112
As shown in Figure 3.2-6, coal fed into a power plant
boiler encounters only an oxidizing atmosphere. Coal combustion
products exist in either the gas or solid phase. In the gasi-
fier, the coal first encounters a reducing atmosphere. Part of
the coal is vaporized and leaves the system while the char which
remains enters the combustion zone at the bottom of the gasifier.
In this oxidizing atmosphere, the char is combusted with oxygen
in the presence of steam. This produces a gas mixture containing
hydrogen which is fed to the top section of the gasifier. Be-
cause trace elements in a Lurgi gasifier first encounter a reduc-
ing atmosphere, then an oxidizing atmosphere (with possible recy-
cle through the reducing atmosphere), it is difficult to predict
the distributions of specific trace elements among the Lurgi gas-
ifier effluent streams.
136
-------
COAL
t
i
OXIDIZING
ATMOSPHERE
COAL -
H2 RICH
RAW GAS
STEAM
02
->
r->
^
r
REDUCING
ATMOSPHERE
1
OXIDIZING
ATMOSPHERE
RAW
- SYNTHESIS
GAS
t
ASH
SPENT CHAR (ASH)
BOILER
COAL GASIFIER
FIGURE 3.2-6. COMPARISON OF ENVIRONMENTS IN A
BOILER AND A COAL GASIFIER
137
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Experimental Studies of the Fate of Trace Elements in
Coal Processing Systems
Kaakinen, Jordan, and West (KA-121) determined the con-
centrations of 17 trace elements and total mass flow rates for
all inlet and outlet streams of a pulverized coal-fired power
plant. The goal of this effort was the calculation of a trace
element material balance around the power plant. Aluminum, iron,
rubidium, strontium, yttrium, and niobium concentrations in all
outlet ash streams (fly ash and bottom ash) were reported to
be essentially unchanged from inlet concentrations. Copper,
zinc, arsenic, molybdenum, antimony, lead, and the radioisotopes
lead - 210 and polonium - 210 were found in progressively higher
concentrations in fly ash fractions collected in a downstream
direction from the firebox. These trace elements were in their
lowest concentrations in the bottom ash. The bulk of the inlet
concentrations of the trace elements found in both of these groups
were retained in the solid samples. The inability to account for
the inlet concentration of mercury and selenium in solid and li-
quid samples suggests that portions of these two elements exis-
ted as vapors and/or very fine aerosols in flue gas which passed
through the sampling equipment. Also, the enrichment of certain
trace elements in successive fly ash fractions collected in the
downstream direction is probably due to volatilization of these
elements or their compounds in the furnace and their subsequent
condensation or adsorption onto suspended fly ash particles.
Natusch, Wallace, and Evans (NA-149) likewise report that the
trace elements arsenic, antimony, cadmium, lead, selenium, and
thallium probably volatilize in the furnace and recondense on
small ash particles as the flue gas cools.
A Radian report (RA-R-219) characterizes trace element
emissions from three coal-fired electric generating stations. A
material balance approach was used for a quantitative examination
138
-------
of twenty-seven elements. The results indicate that the trace
elements can be classified into two general groups: 1) those
preferentially emitted with the flue gas, and 2) those uniformly
distributed in the ash. The elements included in this study in-
clude the following:
aluminum arsenic beryllium ~~ cadmium
antimony barium boron calcium
chlorine iron mercury sulfur
chromium lead molybdenum titanium
cobalt magnesium nickel uranium
copper manganese selenium vanadium
fluorine mercury silver zinc
Enrichment in the flue gas at all three stations was
indicated for:
sulfur lead chromium
mercury molybdenum copper
chlorine nickel cobalt
antimony boron uranium
fluorine zinc arsenic
selenium cadmium silver
The remainder of the twenty-seven elements were found to exit
the stack in the same proportion as they exit with the ash.
These were:
barium aluminum manganese
beryllium calcium magnesium
vanadium iron titanium
Another Radian study used the Radian Equilibrium Pro-
gram to predict the fate of trace elements in a Lurgi gasifier.
139
-------
The program is described in Section 2.2.4.1. and in the Appendix.
The following trace elements were selected for consideration on
the basis of both their presence in typical coals and interest
as potential pollutants: As, Be, Se, Cd, Hg, Pb, B, Co, Cr, Cu,
Ge, Mn, Mo, Ni, P, Sb, Sn, V. Zn, Ba, U. Table 3.2-12 presents
the results of the study.
TABLE 3.2-12.
FATE OF SELECTED TRACE ELEMENTS
IN LURGI GASIFIER
Element
As
Be
Se
Cd
Hg
Pb
B
Co
Cr
Cu
Ge
Mn
Mo
Ni
P
Sb
Sn
V
Zn
Ba
U
wt . ppm
in Feed Coal
14.0
1.6
2.1
2.5
0.2
35.0
102.0
9.6
13.8
15.0
6.9
49.0
7.5
21.0
71.0
1.3
4.8
33.0
272.0
130.0
1.3
600°K
V
NV
V
NV
V
V
V
NV
NV
NV
NV
NV
NV
NV
V
V
NV
NV
NV
NV
NV
866°K
V
NV
V
V
V
V
V
NV
NV
NV
V
NV
NV
NV
V
V
NV
NV
NV
NV
NV
V - Volatile
NV - Non volatile
140
-------
Attari (AT-042) has reported data on coal gasification
systems in connection with the IGT HYGAS pilot plant. The pur-
pose of this work was to measure the concentration of eleven
trace elements found in the solid streams entering and leaving
each of the three stages of the HYGAS pilot plant. The HYGAS
gasifier section is shown in Figure 3.2-7.
Because the pilot plant was not operational during the
period when the analytical work was performed, coal and char
samples accumulated over several years of bench-scale research
were used in the analysis. The emphasis of the project was
placed on trace element analytical methods since sampling and
operating criteria of the pilot plant were not involved. The
relative amounts of the trace elements found in the overhead
gas and the spent char from the electrothermal gasifier are
presented in Table 3.2-13. The amount of each element in the
overhead gas was assumed to be the remainder unaccounted for in
the spent char. It can be seen from these data that most of the
Hg, Se, As, Te, Pb and Cd which entered the gasifier in the coal
feed, apparently left the gasifier in the vapor phase. Most of
the Sb, V, Nu, Be and Cr remained in the solid phase.
Some research has indicated that trace elements might
also be found in the aqueous streams of a coal gasification sys-
tem. Shown in Table 3.2-14 are Bureau of Mines data on trace
elements which were detected in condensate from a laboratory
Synthane gasifier.
The Northern Great Plains Resources Program Atmospheric
Aspects Work Group published a report in 1974 which contains an
estimation of the trace element emissions for a 7.1 x 10s Nm3/day
(250 MM scfd) gasification plant whose feedstock was an Eastern
coal (NO-098). Table 3.2-15 presents the results. These estimates
originate from an EIS done in 1973 by Rhodes for coal gasification.
141
-------
fuel 03$
HYDROGAS1FIEB
74 a |raj/
tresidual char
raafbydrogen-ficligas
PIPELINE GAS
63 aim
METHANATION
IGAS PORIFICAFION
arbon dioxide. liquid aromalics,
sulfur .ammonia
GASIFIER
spent char to
power generation
1000 DC
74atm
FIGURE 3.2-7.
IGT HYGAS PROCESS FOR ELECTROTHERMAL
GASIFICATION, SHOWING PRETREATMENT,
HYDROGASIFICATION, AND ELECTROTHERMAL
STAGES
142
-------
TABLE 3.2-13. TRACE ELEMENT CONCENTRATION OF CHAR
CALCULATED ON RAW COAL BASIS
Trace
Element
Hg
Se
As
Te
Pb
Cd
Sb
V
Ni
Be
Cr
Gas*
Overhead
(I)
96
74
65
64
63
62
33
30
24
18
0
Spent Char
Bottom
(%)
4
26
35
36
37
33
67
70
76
82
100
*The % of the trace element in the overhead gas was calculated
by the difference since only a solid analysis was done.
Source: AT-042
143
-------
TABLE 3.2-14.
TRACE ELEMENTS IN CONDENSATE FROM AN
ILLINOIS NO. 6 GASIFICATION TEST
Ppm:
Calcium
Iron
Magnesium
Aluminum
Ppb:
Selenium
Potassium
Barium
Phosphorus
Zinc
Manganese
Germanium
Arsenic
Nickel
Strontium
Tin
Copper
Columbim
Chromium
Vanadium
Cobalt
No. 1
4.4
2.6
1.5
0.8
401
117
109
82
44
36
32
44
23
33
25
16
7
4
4
1
No. 2 Average (by weight)
3.6
2.9
1.8
0.7
323
204
155
92
83
38
61
28
34
24
26
20
5
8
2
2
4
3
2
0.8
360
160
130
90
60
40
40
30
30
30
20
20
6
6
3
2
Source: FO-026
144
-------
TABLE 3.2-15. TRACE ELEMENT EMISSIONS FROM
A COAL GASIFICATION PLANT
Basis: 7.1 x 10s Nm3/day
Element
Arsenic
Bromine
Cadmium
Chromium
Cobalt
Copper
Flourine
(Jallium
Lead
Manganese
Mercury
Nickel
Selenium
Vanadium
Emissions (kg/day)
0.14
0.15
0.01
0.17
0.06
0.15
1.01
0.04
0.10
0.54
0.002
0.15
0.02
0.25
The above data clearly indicate the loss of certain
trace elements during gasification. However, no conclusion as
to the final disposition of all of the trace elements leaving
the gasifier is possible. Also, the chemical forms in which the
trace elements occurred were not examined in any of the streams.
Data Analysis
Based on the recent studies of trace elements in a
coal-fired power plant (KA-121) and in a coal gasification system
(AT-042), only limited conclusions can be made about the ultimate
145
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fate of trace elements in a Lurgi gasification plant. The HYGAS
data cannot necessarily be related to the Lurgi gasification sys-
tem. Furthermore, the samples analyzed (solids only) were from
bench-scale work, and, therefore, may not be representative of
commercial scale operation. Nevertheless, it is obvious from
these studies that certain trace elements have a tendency to
volatilize while others have a tendency to remain in the ash or
spent char.
Data on the volatility of trace elements in coal as
reported by Ruch, Gluskoter, and Shimp (RU-039) are given in
Table 3.2-16. Results of the low-temperature (150°C) ash testing
show that only Hg (up to 90 percent), Br (100 percent), and Sb
(up to 50 percent) are volatilized. F was not tested but was
assumed to be volatilized completely. Results of the high temp-
erature (300 to 700°C) ash testing show that only Mo (33 percent)
and V (up to 25 percent) are volatilized.
TABLE 3.2-16. VOLATILITY OF TRACE ELEMENTS IN COAL
Low-temperature ash
Retained (> 95%) Lost
Ga
Se
As
Zn
Ni
Co
Be
Cu
Pb
V
Mn
Cr
Cd
Hg (up to 90%)
Br (100%)
Sb (up to 50%)
F (untested but
presumed lost)
High-temperature ash
Retained* Lost
Zn
Ni
Co
Cu
Pb
B
Cd
Mn
Cr
Be
Ge
Sn
Se
Mo (33%)
V (possibly up
to 25%)
(untested but
presumed retained)
* No significant losses observed in coal ash from 300 to 700°C or between
results from whole coal and low-temperature ash or high-temperature ash
(^450°C).
Source: RU-039
146
-------
Analysis using the Radian Equilibrium Program predicted
that the following trace elements would volatilize in a Lurgi
gasifier:
As, Se, Hg, P, Sb, Pb, B
The following elements were predicted to not volatilize,
thus leaving the gasifier in the char and ash:
Be, Co, Cr, Cu, Mn, Mo, Ni, Sn, V, Zn, Ba, U
The program also predicted that Cd and Ge would be nonvolatile at
a gasifier temperature of 600°K but would volatilize at 866°K.
There seems to be some agreement in the studies that
portions of the Hg and Se exist as vapors and/or fine aerosols in
the gas stream. The gasification data also indicates that As, Te,
Pb, and Cd volatilize to some degree and that a portion of these
trace elements will leave the gasifier in the overhead gas stream
(see Table 3.2-13). The power plant study concludes that Ce, Zn,
As, Pb, Mo, and Sb will be at least partially volatilized in a
furnace and then condensed or adsorbed onto suspended fly ash
particles.
Trace elements reported to remain in the spent char in
a gasifier were Sb, V, Ni, Be, and Cr (see Table 3.2-13). In the
power plant study, Al, Fe, Rb, Sr, Y, and Nb concentrations were
reported to be constant in all outlet ash streams. This implies
that they were not volatilized during combustion.
The Northern Great Plains report stresses the preliminary
nature of the estimates shown in Table 3.2-15. They are based upon
a limited amount of data. NGP claims that actual emissions may
vary by an order of magnitude or more.
147
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3.2.3.2 Trace Organics
There are two major sources of organic materials from
coal processing: those originally present in the coal which are
released through volatilization and those formed by chemical re-
action in the gasifier and associated equipment. Much information
is known about the identity of individual components in coals. A
significant amount of work has also been performed to define the
products from coal pyrolysis or thermolysis. However, each coal
has an individual genesis and a correspondingly unique composition.
As a result the available data cannot be generalized and applied
for all cases. It must be evaluated in terms of the coal compo-
sition and the process (reaction and operating conditions) in-
volved.
Although the molecular composition pattern in coal can-
not be specified precisely, a number of organic functional groups
are present. A similar functional group pattern is probably pres-
ent in the plant effluents. In processes which gasify coal at
intermediate temperatures, the gasifier output may also contain
all of the products commonly associated with pyrolysis, carboni-
zation, and coking of coals in addition to the oxygenated products
associated with partial combustion. It is unlikely that gasifica-
tion conditions will result in complete conversion of all organic
components to gas. The possibility exists, therefore, that traces
of many organic compounds (functional groups) will be found in the
plant effluent streams (RA-144).
Experimental Studies of the Fate of Trace Organics
in Coal Processing Systems
Due to the lack of information concerning compositions
of streams from a gasification plant, data on emissions from
148
-------
processes such as boilers and coke ovens, which have been
characterized in more detail, were examined
Battelle (BA-261) reports forty-two toxic and hazardous
organic substances likely to be emitted by industrial boilers
(see Table 3.2-17). The organic compounds are listed in order
of their decreasing health hazard. The first twelve compounds
are all potent carcinogens. This rating is intended only as a
guide since a direct comparison of the potency of the various
hazardous materials is not always possible.
In the coke plant, cyclic and polycyclic organic matter
present in coke oven emissions will be found primarily in the
particulate fraction which has been defined as tar. The principal
compounds obtained from coal tar as presented by (RO-153) and
(MO-125) are given in Tables 3.2-18 and 3.2-19, respectively.
Several of the more widely accepted carcinogens are species of
benzpyrene. To characterize the presence of this general group,
benzpyrene analyses were performed on the coal tar from a number
of coke oven samples (BE-236). Results indicate that benzpyrene
is present in concentrations ranging from less than 260 ppm to
18,000 ppm (Table 3.2-20). The combination of mass spectra and
chromatographic data resulting from the above samples clearly
indicates the presence of benz(c)phenanthrene (potent carcinogen),
benz(a)anthracene (carcinogen), a benzfluoranthene isomer (possible
carcinogen), benz(a)pyrene (potent carcinogen) and/or benz(e)pyrene,
and cholanthrene (carcinogen).
As stated,, previously, the coal gasifier output may con-
tain all of the products commonly associated with pyrolysis, car-
bonization, and coking of coals in addition to the oxygenated
products associated with partial combustion. Various heavier
organic compounds present may be classified as tar, including
149
-------
TABLE 3.2-17.
TOXIC AND HAZARDOUS SUBSTANCES LIKELY
TO BE EMITTED BY INDUSTRIAL BOILERS
Organic Materials
7,12-Dimethylbenz(a)anthracene
3-methylcholanthrene
Dibenz(a,h)anthracene
Benz(c)phenanthrene
Benz(a)pyrene
Dibenz(a,h)pyrene
Dibenz(a,i)pyrene
Dibenz(c,g)carbazole
4-Aminobiphenyl
Benzidine
1-Naphthylamine
4-Nitrobiphenyl
Phenylhydrazine
Methyl-phenylhydrazine
Dibenz(a,j)acridine
Dibenz(a,h)acridine
Cholanthrene
Dibenz(a,j)anthracene
Dibenz(a,g)fluorene
Indeno(1,2,3-cd)pyrene
Dibenzo(a,1)pyrene
Benz(a)anthracene
Chrysene
Dibenz(a,c)fluorene
Dibenz(a,h)fluorene
Dibenz(a,i)carbazole
Benz(a)carbazole
Dibenz(c,h)acridine
Picene
Dibenz(a,g)carbazole
Benzoquinoline
Pyridine
Acridine
Aniline
Benz(j)fluoranthene
Benz(b)fluoranthene
Dibenz(a)anthracene
Dibenz(a,c)anthracene
Phenol
Benzthiophenes
Dibenzthiophenes
Thiophene
Source: BA-261
150
-------
phenols and cresols, pyridines, anilenes, dihydric phenols
(catechols), intermediate and high-boiling aromatics (naphthalenes),
saturates, olefins, and thiophenes. Another group of organic com-
pounds might be designated light oil and/or naphtha, including
benzene-toluene-xylene (B-T-X), naphthalene, thiophene and con-
densable light hydrocarbons and carbon disulfide.
TABLE 3.2-18. PRINCIPAL COMPOUNDS OBTAINED FROM COAL TAR
Hydrocarbons Nitrogen Compounds Oxygen Compounds
Naphthalenes
Acenaphthene
Fluorene
Anthracene
Phananthrene
Chrysene
Pyrene
Fluoranthene
Pyridines
Quinoline
Carbazole
Acridine
Picoline
Phenols
Cresols
Xylenol
Naphthols
Source: RO-153
TABLE 3.2-19. COMPOUNDS OBTAINED FROM COAL TAR
Benzene Phenanthrene
Toluene Thiophrene
Xylenes Thiophene
Phenols Pyrole
Cresols Pyridine
Naphthalenes Quinoline
."* •• '
Anthracene
Source: MO-125
151
-------
TABLE 3.2-20. BENZPYRENE ANALYSIS COAL TAR FROM COKE OVEN
Ul
Test
Number
7
8
8A
8A
9
10
10
11
11
19
20
21
21
21
23
Location
1
2
3
3
1
6
4
4
5
1
2
3
3
3
2
Sample
Number
1045
1060
1066
1067
1095
1102
1105
1111
1114
1208
1213
1222
1223
1229
1241
Total Benzpyrene
(UK)
30
70
100
B.D.L.
B.D.L.
30
B.D.L.
B.D.L.
B.D.L.
B.D.L.
B.D.L.
22,000
520
B.D.L.
220
Benzpyrene Concentration*
(ppm)
510
1,000
560
<260
<630
560
<1,300
-------
In a study of the effluent from an experimental coal
gasification plant, certain organic components were extracted and
tentatively identified (Table 3.2-21). The particular distribu-
tion of organic compounds which might be present in raw gasifier
gas will depend on the composition of the feed coal and on the
operating conditions of the gasifier. The range of sulfur and
B-T-X components which might be expected from the Synthane Pro-
cess, another gasification process, are given in Table 3,2-22
for six coal feeds (FO-026, KA-142).
TABLE 3.2-21. COMPOUNDS TENTATIVELY IDENTIFIED IN WASTE EFFLUENT
OF COAL GASIFICATION PILOT PLANT
Restructured Gas
Chromatograph Peak Best Match Second Best Match
1 Phenol Phenol
2 jj-Cresol in-Cresol
3 m-Cresol £-Cresol
4 2,5-Dimethylphenol 2,6-Dimethylphenol
5 3,4-Dimethylphenol 3,4-Dimethylphenol
6 2.4-Dimethylphenol 3,4-Dimethylphenol
7 a-Naphthol 1,2-Dihydroxy-
1,2-Dihydronaphthalene
Source: MC-130
Separation equipment is provided in the Lurgi gasifica-
tion plant to remove condensable matter. Tars which might separate
from such condensate have been partially characterized for the
Synthane Process (Table 3.3-23). Similarly, aqueous condensate
from Synthane raw gas has been analyzed and compared with coke-
plant weak ammonia liquor (Table 3.3-24). These analyses of Syn-
thane streams should qualitatively parallel the Lurgi gasifier
streams since both operate at approximately the same temperature.
153
-------
TABLE 3.2-22. COMPONENTS IN SYNTHANE GASIFIER GAS, ppra
Ul
H2S
COS
Thiophene
Methyl thiophene
Dimethyl thiophene
Benzene
Toluene
'C8 aromatics
S02
CS2
Methyl mercaptan
Illinois
No. 6
Coal
9,800
150
31
10
10
3AO
94
24
10
10
60
Illinois
Char
186
2
.4
,4
.5
10
3
2
1
__
.1
Wyoming
Subbi-
tuminous
Coal
2,480
32
10
__
__
434
59
27
6
--
.4
Western
Kentucky
Coal
2,530
119
5
__
--
100
22
4
2
--
33
North
Dakota
Lignite
1,750
65
13
__
11
1,727
167
73
10
--
10
Pitts-
burgh
Seam
Coal
860
11
42
7
6
1,050
185
27
10
--
8
Source: FO-026,.KA-142
-------
TABLE 3.2-23.
MASS SPECTROMETRIC ANALYSES OF THE BENZENE-SOLUBLE
TAR FROM THE SYNTHANE PROCESS (UNITS: VOLUME PERCENT)
Ul
Ul
Run HP-1
Structural type No. 92, ,
(includes alkyl Illinois
•derivatives) No. 6 coal
Benzenes
Indenes
Indanes "'
Naphthalenes
Fluorenes
Acenaphthenes
3-ring aromatics
Phenylnaphthalenes
4-ring pericondensed
4-ring catacondensed
Phenols
Naphthols
Indanols
Acenaphthenols
Phenanthrols
Dibenzofurans
Dibenzothiophenes
Benzonaphthothiophenes
N-heterocyclics 3
Average molecular
weight
2.1
28.6
1.9
11.6
9.6
13.5
13.8
9.8
7.2
4.0
2.8
(2)
.9
--
2.7
6.3
3.5
1.7
(10.8)
212
Run HPL
No. 94,
lignite
4.1
1.5
3.5
19.0
7.2
12.0
10.5
3.5
3.5
1.4
13.7
9.7
1.7
2.5
—
5.2
1.0
--
(3.8)
173
Run HPM No. Ill,
Montana
subbituminous
coal
3,9
2.6
4.9
15.3
9.7
11.1
9.0
6.4
4.9
3.0
5.5
9.6
1.5
4.6
.9
5.6
1.5
--
(5,3)
230
Run HP -11 8
No. 118, *
Pittsburgh
seam coal
1.9
26.1
2.1
16.5
10.7
15.8
14.8
7.6
7.6
4.1
3.0
(2)
.7
2.0
—
4.7
2.4
--
(8.8)
202
Spectra indicate traces of 5-ring aromatics.
2
Includes any naphthol present (not resolved in these spectra)
o
Data on N-free basis since isotope corrections were estimated
Source: FO-026, KA-142
-------
TABLE 3.2-24.
Ul
0\
BYPRODUCT WATER ANALYSIS FROM SYNTHANE GASIFICATION
OF VARIOUS COALS [mg/& (Except pH)]
PH
Suspended Solids
Phenol
COD
Thiocyanate
Cyanide
NH3
Chloride
Carbonate
i
Bicarbonate
Total sulfur
Coke
plant
9
50
2,000
7,000
1,000
100
5,000
--
— —
--
--
Illinois
No. 6
coal
8.6
600
2,600
15,000
152
0.6
'8,100
500
26,000
211,000
31,400
Wyoming
subbitumi-
nous Illinois
coal char
8.7
140
6,000
43,000
23
0.23
9,520
--•
_ _
--
--
7.9
24
200
1,700
21
0.1
2,500
31
- _
--
--
North
Dakota
lignite
9.2
64
6,600
38,000
22
0.1
7,200
--
_ -
--
--
Western
Kentucky
coal
8.9
55
3,700
19,000
200
0.5
10,000
--
_ _
--
--
Pittsburgh
seam
coal
9.3
23
1,700
19,000
188
0.6
11,000
--
_ _
_-
--
X85 percent free NH3
2Not from same analysis.
3S= = 400
SOT = 300
SO; = 1,400
S203 = 1,000
Source: FO-026, KA-142
-------
Data Analysis
Due to the lack of available information, the best
conclusions as to the ultimate fate of trace organics in a coal
gasification plant must be estimates based on the composition of
the coal, processing conditions, and data on actual emissions from
a few processes such as boilers or coke ovens which have been
characterized in more detail.
The direct bearing of the initial coal composition on
possible effluents from a gasification plant is difficult to assess
However, it is expected that the coal function groups will be
maintained to a certain extent. The following types of potential
polluting compounds may be present in the Lurgi plant effluents
to a greater or lesser degree. The listing is intended to be
illustrative, not comprehensive (AN-062, BL-040).
Hydrocarbons Oxygen-Containing
Benzene Aromatic Acids
Toluene Phenols
Xylenes Fatty Acids
Polycyclic Aromatics Esters
Naphthalenes Ethers
Anthracenes Quinones
Pyrenes Cresols
Heterocycles (esters,
lactones)
Sulfur-Containing Nitrogen-Containing
Thiols Heterocycles (pyridines,
Heterocycles pyrroles, indoles,
quinolines, carbazoles)
157
-------
As previously stated, certain analogies can be drawn
between coal combustion and coal gasification processes. However,
conclusions drawn from an industrial boiler study should be ap-
plied to gasification plants only when the conditions of combus-
tion are the same. Research on hazardous emissions from industrial
boilers (BA-261) indicates that carcinogenic trace hydrocarbons
are likely to be emitted. It is not possible to estimate the con-
centration of each of the components in the stack gas since only
benz(a)pyrene has been studied in any detail (HA-011).
Analogies can also be made between coke ovens and coal
gasifiers. Comparison of Tables 3.2-18, 3.2-19, and 3.2-23 re-
veals that several classes of organic compounds are present in
the tar from both a coke oven and a gasifier. Coke ovens also
operate in the same temperature range as some gasification pro-
cesses, although at a much lower pressure. The results of the
study of coke oven emissions indicate the presence of organic
compounds widely accepted as carcinogens in relatively heavy con-
centrations in the tar. It is likely that some of these hazardous
hydrocarbons are also present in gasifier tar.
Sampling and analyses of bench-scale Synthane gasifier
effluents indicate trace organics present in the gasifier gas, the
tar, and the by-product water streams. However, even these efflu-
ent streams are reported to be only representative of those that
will be obtained from a commercial operation. The applicability
of this data to a commercial operation has not been proyen.
Based on solubility data, certain groups of trace or-
ganics will be expected to be almost totally in the organic pro-
cess streams while others might be in the aqueous streams as well.
Indenes, indanes, naphthalenes, fluorenes, acenaphthenes, and
naphthols and dibenzofurans are insoluble in water and should
158
-------
remain almost totally within the organic streams. Benzenes,
N-heterocyclics, phenols, and catechols are soluble in water and
might, therefore, be in both aqueous and organic streams. Organics
that are in the aqueous stream even in trace amounts could be con-
centrated and emitted from the Lurgi cooling water system.
159
-------
4.0 PROCESS WATER SYSTEMS
This section of the report presents a detailed discussion
of the water systems for the TOSCO II oil shale retorting process
and the Lurgi coal gasification process. The discussion centers
on the water system requirements and potential problem areas that
can arise as these processes attempt to operate with zero dis-
charge of water effluents.
The major water streams of interest are characterized
according to flowrate and approximate compositions. Based on this
information, individual system processes will be analyzed to
evaluate problem areas. Examples of process problems include
CaC03 and CaSO^ scaling, and NH3 and H2S odor problems.
4.1 TOSCO II Process Water System
The Colony Development Operation plans to construct an
underground oil shale mine and a TOSCO II oil shale plant consist-
ing of retorting and upgrading facilities. The plant site will
be located north of Grand Valley, Colorado, on Colony's Dow West
oil shale field. The water system for the plant is discussed in
this section.
Figure 4.1-1 is a schematic of the major process water
streams. Because the Colony water system is designed to operate
at zero discharge, all of the process water is eventually evapor-
ated or consumed in moisturizing processed shale for disposal.
The plant water systems cascade the water streams from
one process step to the next. In this manner, the best quality
water is used in the process steps in which it is required. Blow-
down streams from these processes are sent to processing steps
160
-------
LIME
CHEMICAL ADDITION
COLORADO RIVER
OR GROUND WATER
SEDIMENTATION
PONDS
CLARIFIER
CONDENSATE
COOLING SYSTEM
DLOWDOWN
PROCESS
STEAM
SYSTEM
H2 PLANT
CONSUMPTION
EVAPORATION + DRIFT
EVAPORATION
PYROLYSIS PROCESS
SHALE PILE
RUNOFF
RESERVOIR
RAW SHALE
FIGURE 4.1-1 MAJOR WATER STREAMS FOR THE TOSCO II PROCESS
-------
which can use poorer quality water. Processed shale disposal,
which can accommodate the lowest quality water, is the final con-
sumer of process waste waters.
Colony has presented the water systems for their TOSCO
II plant (CO-175). As shown in previous sections, the heart of
the oil shale plant is the pyrolysis and oil recovery unit. The
water systems associated with the pyrolysis unit will be examined
to identify areas with potential water problems.
4.1.1 Inlet Water
The quality of the water supply has a significant impact
on the plant water systems. The plant must be designed to accom-
odate the inlet water characteristics to avoid equipment scaling
and fouling.
The species given in Table 4.1-1 constitute the great
majority of the ionic species in Colorado River water, which will
be used in the Colony plant. Additional species (e.g., iron,
phosphate, boron, silicates, etc.) are also present, but exist in
such comparatively small quantities that they have little effect
on the system chemistry.
The raw river water entering the overall Colony water
system will be treated with lime to reduce the concentration of
calcium. Of this treated water, part will be used as a makeup
stream to the cooling system, and the remainder will be used as
process water.
Lime treatment of the river water will precipiate CaCOs-
For the Colony system's lime treatment step it was assumed that
the calcium concentration could be reduced to 26 mg/S, in a lime
162
-------
treatment vessel of conventional capacity and retention time,
I [ [ [
giving a total Ca , Mg hardness of 42.5 mg/£.
TABLE 4.1-1. COLORADO RIVER COMPOSITION
Ca^
MG"^
Na+
HCOl
col
soT
Cl"
NO I
PH
Temperature
70
16
110
158
0
135
150
0
8
2
mg/fc
.5 mg/£
mg/£
mg/Jl
mg/Jl
mg/Jl
mg/H
.28 mg/&
.0
.25°C
* Near DeBegue, Colorado
** August 1973 - September 1974 Average
4.1.2 Plant Water Stream Characterization
The major plant streams of interest are examined in
this section.
Process Water
Because the Colony water system is designed to operate
at zero discharge, all of the process water from retorting is
eventually evaporated or consumed in moisturizing processed shale
for disposal. Foul process water will be sent to a distillation
cleaning process to remove NH3 and H2S before treating the pro-
cessed shale. However, some residual NH3 and H2S will remain in
the water after treatment.
163
-------
Cooling Water
The Colony project's cooling system is composed of a
multiple-cell induced-draft cooling tower and a network of piping
over the entire processing area. A schematic of this system is
given in Figure 4.1-2.
Fresh water must be continually supplied to the cooling
system to make up for water lost during processing in the cooling
tower. Evaporation occurring in the cooling tower concentrates
the impurity species in the makeup water. Chemical additives may
be introduced into the system to control the chemical character-
istics of the cooling water. A purge from the cooling water re-
cycle stream must also be maintained to remove impurity species
at a rate sufficent to prevent scaling and fouling of the equip-
ment.
Windage or drift from cooling towers carries dissolved
impurity species from the recycle water loop along with the water
droplets entrained in air. This reduces the required rate of
liquid purge or blowdown, since it is a purge stream in itself.
The drift rate is normally a function of the recycle water rate.
The relationship between the cooling water concentration factor
(CF), the evaporation rate (E), the drift rate (D), and the blow-
down rate (B) is given below:
TV = E+B+D f, TIN
L* B+D ^ ;
The concentration factor, or number of cycles of concentration,
can also be expressed as the concentration of a given dissolved
species in the cooling water recycle divided by the concentration
of that species in the makeup water.
164
-------
CHEMICAL .ADDITION
MAKEUP
Oi
COOLING TOWERS
EVAPORATION DRIFT
HEAT EXCHANGES
SLOWDOWN
FIGURE 4.1-2 COOLING SYSTEM FOR THE TOSCO II PROCESS
-------
Using the above formula and the proposed Colony cooling
system flowrates (given in Table 4.1-2), the cooling system is
found to operate at 4.7 cycles of concentration. This value is
based on the assumption that the drift will be about 0.1 percent
of the recirculating water, a typical approximation made for
induced-draft wet cooling towers.
TABLE 4.1-2. OIL SHALE COOLING SYSTEM FLOWRATES
Evaporation and drift 1,530 gpm
Slowdown 370 gpm
Makeup 1,900 gpm
Recirculation Water 36,000 gpm
It is often desirable to reduce the blowdown stream from
a cooling tower to minimize the waste water effluent from the
cooling system. For a given evaporative cooling load, the blow-
down rate is a function of the number of cycles of concentration
of the cooling water. The relationship between blowdown rate and
water concentration for the Colony cooling system is given in
Figure 4.1-3.
A reduction in blowdown rate is generally achieved by
increasing the cycles of concentration to the point at which cal-
cium sulfate reaches saturation. Beyond this point, precipitation
of calcium sulfate occurs.
It is common for acid (usually sulfuric acid) to be
added to the recirculating water stream of a cooling cycle for pH
control. The pH must be maintained low enough to prevent precipi-
tation of calcium carbonate. Other chemicals are also usually
added to the cooling water to inhibit biological degradation of
the cooling towers and corrosion of the piping network.
166
-------
400 --
300--
3
-------
The Radian Equilibrium Program was used to model the
effects of concentrating the recycled cooling water. This was
accomplished by determining the equilibrium compositions of dis-
solved species in the cooling water at 5, 10, and 20 cycles of
concentration. The concentrations of all species except COT were
increased by these concentration factors. The COT ion is not
affected by the concentration process in the same manner as the
other ions because CO 3 is found to closely approach equilibrium
with the C02 in the air during evaporation in the cooling tower.
Therefore, a computer option was used that allowed the CO 3 ion
to attain equilibrium in relation to the atmospheric partial
pressure of C02.
The results of the equilibrium computer runs are listed
in the Appendix. The most important results relate to the concen
tration of CaSOif'2H20 (calcium sulfate dihydrate) , the chemical
species most likely to scale under the Colony cooling system's
operating conditions. The tendency toward forming scale is re-
flected in the value of CaSO^'2EzO relative saturation, which is
defined by Equation 4.1-2.
RSCaSO,.2H20 - C+ 0 (4-1-2)
where a_. -H-, acn=, and au n are the chemical activities of the
ri2u
calcium ion, sulfate ion, and H 0, respectively, and K,, ^ ^H o
is the solubility product constant for calcium sulfate dihydrate.
Precipitation can theoretically occur for any relative saturation
greater than 1.0. However, in practice nucleation and scaling are
found to require relative saturations of 1.2 to 1.4 in order to
occur.
The tendency of Colony's cooling system to form calcium
sulfate scale with increasing cycles of concentration is shown
168
-------
graphically in Figure 4.1-4. As the graph shows, the system's
operating condition of 4.7 cycles of concentration corresponds
to a CaSOit-2H20 relative saturation of about 0.15. Therefore,
the cooling system is well removed from experiencing any problems
with calcium sulfate scaling and, in fact, can afford to operate
at higher cycles of concentration with higher relative saturations
This would permit a reduction in the flowrate of makeup water to
the cooling system and a corresponding reduction in the blowdown.
rate. This analysis indicates that there will be a large margin
of safety to maintain zero discharge if water system problems
occur.
4.1.3 Potential Problems
Problems associated with the system may arise from
species in the foul process water and the possibility of scaling
during moisturization of processed shale.
Although foul water will be sent to a distillation to
remove NH3 and H2S, some residual NH3 and H2S will remain in the
water after treatment. This treated water will be used to
moisturize the processed shale. Since large quantities of
moisturized shale will be disposed of, there is the possibility
of HaS and NHa odor problems in the disposal area. Phenols,
amines, and organic acids will also be in the process water used
to moisturize shale. Some of these compounds may contribute to
an odor problem.
During the mositurization of the shale, dissolution of
inorganic species (such as CaO and MgO) may lead to scaling on
the walls of the rotating drum moisturizer. The severity of this
problem will depend on the composition of the shale, the compo-
sition of the process water, and the dissolution kinetics.
169
-------
10 16 20
CYCLES OF CONCENTRATION
FIGURE 4.1-4 CALCIUM SULFATE SCALING PROFILE FOR THE COLONY COOLING TOWER
-------
4.2 Lurgi Process Water System
The water system for a future Lurgi coal gasification
plant is discussed in this section. The plant will be built as
a joint venture of the Rochelle Coal Company and the Wyoming Coal
Gas Company. The proposed plant site is the Powder River Basin
of northeast Wyoming. Water supplies are relatively scarce in
this area; and, as a result, water recycle is heavily stressed
in the design of the plant facilities.
The plant's water stream network, shown in Figure 4.2-1,
is relatively complex. In order to limit the use of raw water
makeup to the plant, the water effluent streams from the gas cool-
ing and gas cleaning processes are recycled for use as boiler feed
water and cooling water. Both of these effluent streams are
initially sent to a liquid-liquid extraction process, Lurgi?s
Phenosolvan process, to clean them of phenolic compounds. The
gas cleaning liquor, designated the "minor" Phenosolvan effluent,
is a stream rich in high-boiling organics, fatty acids, ammonia,
coal dust and dissolved solids. The "major" Phenosolvan effluent
is a wastewater stream from the gas cooling process and is rich
in NHs, H2S, and low-boiling organics.
The proposed Wyoming plant will operate under one of
two modes of recycle operation. The base case treats a majority
of the major Phenosolvan effluent to cooling water quality for
use as makeup to the cooling system. The rest of the major Pheno-
solvan effluent and all of the minor Phenosolvan effluent will be
treated to boiler feedwater quality under this recycle mode. If
boiler feedwater quality cannot be achieved, an alternate recycle
mode will be to use all of the Phenosolvan effluent in the cooling
system and redesign the cooling system to maintain zero discharge.
171
-------
NJ
FINAL CONCENTRATE
TO ASH DISPOSAL
STEAM AND
POWER GENERATION
SYNTHETIC PIPELINE
GAS PRODUCTION
BRINE
EVAPORATOR
EVAPORATION AND
DEMORALIZATION
MINOR PHENOSOLVAN
MAJOR PHENOSOLVAN
CONCENTRATE
MULTI STAGE
FLASH EVAPORATION
AND OZONATION
COOLING SYSTEM
DLOWDOWNS
EVAPORATION
AND DRIFT
RAW WATER
SOFTENING
AND FILTERING
RAW WATER
FIGURE 4.2-1 MAJOR WATER STREAMS FOR A LURGI COAL GASIFICATION PLANT
-------
A basic feature of the water system which makes zero
discharge operation feasible is the brine evaporation process.
In this process the various blowdown or purge streams of high
saline content can be treated to produce a distillate for use as
boiler feedwater and a concentrated brine to be discharged to
the ash sluicing system. The brine can be evaporated to almost
any degree of concentration, making it possible to reclaim all
of the process water, excepting that which is needed to moisturize
the ash for disposal.
4.2.1 Inlet Water
A coal gasification plant can relay on two sources of
water for makeup to its water system: river water and groundwater
from nearby deep wells. The well water could be required if the
gasification plant's water rights for diversion of river water
will not guarantee a sufficient water supply during low-flow river
conditions.
River water quality experiences some seasonal variation,
with the winter quality being generally poorer. A typical winter
analysis for the North Platte River is given in Table 4.2-1.
TABLE 4.2-1. NORTH PLATTE RIVER COMPOSITION - WINTER
61.9 mg/X,
Mg"1"1" 21.5 mg/X,
Na+ 48.5 mg/X,
HCOl 159.5 mg/l
SO^ 193. mg/X,
Cl" 14.4 mg/X,
Temperature 4.35°C
173
-------
Groundwater is generally alkaline but is variable in
quality. A representative composition for water coming from the
deep wells is given in Table 4.2-2.
TABLE 4.2-2. DEEP WELL WATER COMPOSITION
179 mg/fc
Mg" 35
Na+ 310
HC03" 197 mg/fc
SO*" 1080. mg/5,
Cl" 6.8 mg/Jl
pH 8.2
Temperature 11 °C
Source: WY-007
The Wyoming plant's water system is designed to accom-
modate inlet water varying in quality from 600 to 1200 ppm total
dissolved solids. Taking a weighted average of the river water
composition and the groundwater composition, a composite inlet
stream can be determined having a total dissolved solids value of
1200 ppm. When this composite stream is softened with lime and
soda ash, the resultant stream entering the water system has
a composition given in Table 4.2-3. This stream is then evapor-
ated to produce high-quality boiler feedwater and a concentrate
stream.
174
-------
TABLE 4.2-3. TREATED MAKEUP TO WATER SYSTEM
35 mg/fc
15 mg/A
Na+ 194 mg/fc
HCOl 5.3 mg/fc
SOI 686 mg/5,
Cl" 10.18 mg/fc
Temperature 4.35'
pH adjusted to 7.1
:o
4.2.2 Process Water Stream Characterization
The Wyoming plant's water system was not well-defined
with respect to compositions and flowrates in its Environmental
Impact Statement. The lack of specificity can be attributed to
the unknown character of the major and minor Phenosolvan streams,
especially the minor stream. The amount of dissolution of dust
in this stream will be a function of the quality of the water
entering the gas cleaning process, the type of coal, and the pro-
cess operating conditions. In order to give an accurate descrip-
tion of the water system flowrates and compositions, samples will
need to be taken of the actual process in operation. However, it
is possible to make a reasonable approximation by using the
following assumptions:
1) Based on Radian in-house data for aqueous
dissolution of fly ash from coal, the
minor (dusty liquor) Phenosolvan effluent
stream will pick up around 3000 ppm of
inorganic species. Much of it will be
175
-------
2) The lime treatment process will discharge
its underflow at about 10% solids.
3) Treated boiler feedwater will have
about 0.5 ppm dissolved solids.
4) Purge from the boiler water treatment
will be on the order of 5% of the inlet
flow.
5) Cooling tower drift will be about
0.1% of recirculating flow.
6) Inlet water composition will be
1200 ppm total dissolved solids.
7) The brine concentrator concentrates
to virtual dryness. (The water for
ash sluicing mainly comes from raw
water input).
8) Flash evaporation produces a water
of about 10 ppm TDS.
Based on these assumptions, the estimated flows and
compositions of the major water streams are given in Figure 4.2-2.
The most questionable of these assumptions is necessarily the one
pertaining to the composition of the minor Phenosolvan effluent.
The nature of the particular species making up its total dissolved
solids value will have a major effect on determining whether the
minor Phenosolvan effluent can be treated to boiler feedwater
quality.
176
-------
SYNTHETIC PIPELINE
GAS PRODUCTION
2950 GPM
1770 GPM
920 PPM
FINAL CONCENTRATE
TO ASH DISPOSAL
4950 LB/HR SALTS
STEAM AND
POWER GENERATION
7865
0.5
25 GPM
BRINE
EVAPORATOR
GPM
PPM
4855 GPM
10 PPM
EVAPORATION AND
DEMINERALIZATION
MINOR PHENOSOLVAN
MAJOR PHENOSOLVAN
1180 GPM
920 PPM
CONCENTRATE
1100 GPM
3000 PPM
MULTI STAGE
FLASH EVAPORATION
AND OZONATION
/T\ 4380 GPM
10 PPM
3170 GPM 940 PPM
COOLING SYSTEM
160 GPM
2% SOLIDS
SLOWDOWNS
1520 GPM
»>-
EVAPORATION
AND DRIFT
RAW WATER
SOFTENING
AND FILTERING
0,_ r_..
552°00 PPM
60 GPM
SOLIDS
RAW WATER
3230 GPM
1200 PPM
FIGURE 4.2-2 FLOW RATES FOR A LURGI WATER SYSTEM
(Concentration - ppm total dissolved solids inorganic species)
-------
Based on the above assumptions, the cooling tower system
operates at about 6 cycles of concentration. The tendency for
calcium sulfate scaling in the Lurgi cooling towers is presented
in Figure 4.2-3. This figure indicates that the cooling system is
operating in a range that should be free from calcium sulfate
scaling. However, the cycles can be increased only to about 9
before scaling would be a problem. This means that there is not
a large margin of safety to maintain zero discharge if water sys-
tem problems should occur. However, slipstream treatment to re-
duce excessive calcium concentrations in the recirculating cooling
tower water may help alleviate unforeseen problems.
4.2.3 Potential Problems
The potential water system problem areas involve the
Phenosolvan effluent streams, the system blowdown streams, and
the ash sluicing line.
The minor Phenosolvan stream may be susceptible to
or CaCOs scaling, depending on the composition of the inlet water
to the gas cleaning process and the amount of dissolution of the
dust picked up during the cleaning process. Also, both Phenosolvan
effluents have organic species in them which could cause problems
with filming or foaming in the evaporators and the cooling towers.
In addition, the Phenosolvan effluent streams will have residual
phenolic compounds, NHs , and H2S; all of which can create toxicity
and odor problems.
The blowdown or purge streams sent to the brine evapor-
ator, some of which may be in slurry form, present the typical
problem associated with piping concentrated streams: There is
the possibility of scaling on the pipe walls due to dissolution
178
-------
VO
1.2
1.1
1.0
0.0
0.0
0.7
0.6
0.5
0.4
0.3
0.2
0.1
345
CYCLES OF CONCENTRATION
FIGURE 4.2-3 CALCIUM SULFATE SCALING PROFILE FOR THE LURGI COOLING TOWER
-------
of solid species and subsequent reprecipitation. CaSOi* scaling
will be the major danger due to the high SO., concentration in the
I I
raw water inlet and the chance of picking up Ca in the minor
Phenosolvan effluent. If all of the blowdown streams are collected
in a common vessel prior to being fed into the brine concentration
system, there will be a special danger of CaSOi* scaling because
I i
of the high Ca concentration in the lime treatment effluent and
the high SO 4. concentrations in the boiler feedwater blowdown and
the cooling tower blowdown.
Problems that may occur with the ash sluicing also in-
volve scaling. The ash might be expected to have a substantial
amount of CaO. If the CaO is present in a form that can readily
dissolve, there is a possibility of forming CaCOs scale, Mg(OH)2
scale and/or CaSOi* scale, depending on the composition of the
sluice water, pH, and the kinetics of dissolution.
4.3 Summary
Based on the analysis of a representative oil shale
project's water system, there appears to be no major problems
confronting the application of their proposed water reuse strat-
egies. They will mainly need to guard against scaling in their
shale moisturization process. They will also need to clean their
foul process water sufficiently to remove NH3, H2S, and phenols
before using it to moisturize spent shale.
A Lurgi water system appears to have greater dangers of
running into problems as a result of its relative complexity. Po-
tential exists for scaling in the piping for the minor Phenosolvan
stream (the gas cleaning effluent liquor), in the piping and ves-
180
-------
sels used to feed the various process blowdowns to the brine con-
centration system, and in the ash sluicing system. Whether or
not these problems occur will depend on the specific nature of the
coal used and the actual flow conditions, such as retention times
for vessels and lines. In addition, odor problems may also arise
from absorbed NH3, H2S, and phenols in the ash sluice liquor.
181
-------
BIBLIOGRAPHY
AM-030 American Conference of Government Industrial Hygienists,
Documentation of the Threshold Limit Values for Sub-
stances in Workroom Air. 3rd ed. Cincinnati, Ohio,
1971.
AN-062 Angelkova, G. A., Compt. Rend. 13 (1) , 63-6 (1960)
AT-042 Attari, A., Fate of Trace Constituents of Coal During
Gasification. PB 223 001, EPA 650/2-73-004. Final
Report, Chicago, Illinois, Inst. of Gas Technology,
1973.
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Toxic and Hazardous Emissions Control Needs, Final Re-
port, Contract No. 68-02-1323, Task 8, Columbus, Ohio,
Battelle, Columbus Labs., 1974.
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of Airborne Pollutants Emanating from a Proposed Shale
Oil Production Plant, Supplemental Report, Richland,
Wash., Battelle, Pacific Northwest Labs., April 1975.
BE-236 Bee, R. W., et al., Coke Oven Charging Emission
Control Test Program, Final Report, Vol. 1. EPA 650/
2-74-062, Contract No. 68-02-0650. McLean, Va., Mitre
Corp., 1974.
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-------
BIBLIOGRAPHY
(Cont'd)
BL-040 Blom, L. , L. Edelhausen, and D. W. Van Krevelen
"Chemical Structure and Properties of Coal. XVIII.
Oxygen Groups in Coal and Related Products", Fuel 36.
135-53 (1957).
BU-087 Burns and Roe, Inc., Steam Electric Power Plants.
Development Document for Effluent Limitation Guidelines
and Standards of Performance. Draft. N.Y., 1973.
BU-172 Burger, E. D., -et al., "Prerefining of Shale Oil",
Presented at the Symposium on Refining of Synthetic
Crudes, Division of Petroleum Chemistry, Inc., 170th
National ACS Meeting, Chicago, Illinois, August, 1975.
CL-115 Cloninger, James S., Private Communication, Union Oil
Company of California, Grand Junction, CO, 24 Nov.,
1976.
CO-175 Colony Development Operation, Atlantic Richfield Co.,
Operator, An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Vol. 1,
Pt. 1. Plant„ Complex and Service Corridor-, 1974.
CO-320 Conkle, Nick, Vernon Elizey, and Keshava Murthy,
Environmental Considerations for Oil Shale Development,
Final Report. EPA-650/2-74-099, Contract 68-02-323, „
Task 7. Columbus, Ohio, Battelle-Columbus Labs.
I !
CO-352 Cowherd, Chatten, Jr., et al., Development of Emission
Factors for Fugitive Dust Sources, Final Repo'rt. EPA-
450/3-74-037, Contract No. 68-02-0619. Kansas City,
Mo., Midwest Research Inst., June 1974.
183
-------
BIBLIOGRAPHY
(Cont'd)
CO-615 Coomes, R. Merril, "Health Effects of Oil Shale
Processing", Presented at the 9th Oil Shale Symposium,
Colorado School of Mines, Golden, CO, April, 1976.
DA-069 Danielspn, John A., Comp. and Ed., Air Pollution
Engineering Manual, 2nd Ed., AP-40, Research Triangle
Park, N.C., EPA, Office of Air and Water Programs,
1973.
EL-052 El Paso Natural Gas Co., Application of El Paso Natural
Gas Co. for a Certificate of Public Convenience and
Necessity. Docket No. CP73-131. El Paso, Texas, 1973.
EN-071 Environmental Protection Agency, Compilation of Air
Pollutant Emission Factors, 2nd Ed. AP-42, Research
Triangle Park, N.C., 1973.
FA-084 Farnsworth, J. Frank, D. Michael Mitsak, and J. F.
Kamody, "Clean Envrionment with K-T Process", Presented
at the EPA Meeting, Environmental Aspects of Fuel
Conversion Technology, St. Louis, MO, May, 1974.
FO-026 Forney, Albert J., et al., Analyses of Tars, Chars,
Gases, and Water Found in Effluents from the Synthane
Process. Technical Progress Rept. 76. Pittsburgh, Pa.,
Pittsburgh Energy Research Center, 1974.
184
-------
BIBLIOGRAPHY
(Cont'd)
HA-011 Hangebrauck, R. P., et al., Sources of Polynuclear
Hydrocarbons in the Atmosphere. 999-AP-33, Public
Health Service, 1967.
HI-083 Hittman Associates, Inc. ,__ Environmental Impacts,
Efficiency, and Cost of Energy Supplied by Emerging
Technologies, Phase 2, Draft Final Report, Tasks 1-11,
HIT-573, Contract No. EQC 308, Columbia, MD., 1974.
HO-379 Hopkins, John M., et al., "Development of Union Oil
Company Upflow Retorting Technology", Presented at
AIChE 81st National Meeting, Kansas City, MO, April,
1976.
KA-121 Kaakinen, John W., Roger M. Jorden, and Ronald E. West,
"Trace Element Study in a Pulverized-Coal-Fired Power
Plant", Paper 74-8. Presented at the 67th Annual
APCA Mtg., Denver, Colorado, June 1974.
KA-142 Kalfadelis, C. D. and E. M. Magee, Evaluation of
Pollution Control in Fossil Fuel Conversion Processes;
Gasification Section 1: Synthane Process, Final Report,
EPA 650/2-74-009b. Linden, N.J., Esso Research and
Engineering Co., 1974.
MA-294 Magee, E. M., C. E. Jahnig, and H. Shaw, Evaluation of
Pollution Control in Fossil Fuel Conversion Processes;
Gasification; Section 1: Koppers-Totzek Process.
PB 231 675, EPA/2-74-009a. Linden, N.J., Esso Research
& Engineering Co., 1974.
185
-------
BIBLIOGRAPHY
(Cont'd)
MC-130 McGuire, J.M. , A. L, Alford, and M. H. Carter, Organic
Pollutant Identification Utilizing Mass Spectrometry.
EPA-R2-73-234. Athens, Georgia, Southeast Environmental
Research Lab., EPA, 1973.
MC-238 McKee, J. M. and S. K. Kunchal, "Energy and Water Re-
quirements for an Oil Shale Plant Based on the Paraho
Processes", Presented at the Ninth Oil Shale Symposium,
Colorado School of Mines, Golden, Colorado, April 1976.
MO-125 Morrison, Robert Thornton and Robert N. Boyd, Organic
Chemistry, 2nd ed., Boston, Mass., Allyn & Bacon, 1966.
NA-149 Natusch, D. F. S., J. R. Wallace, & C. A. Evans, Jr.,
"Toxic Trace Elements: Preferential Concentration in
Respirable Particles", Science 183 (Jan. 18), 202
(1974).
NO-098 Northern Great Plains Resources Program, Atmospheric
Aspects Work Group, Discussion Draft. Denver, Colorado,
December 1974.
PF-003 Pforzheimer, H., "Paraho-New Prospects for Oil Shale",
CEP 70 (9), 62 (1974).
RA-R-119 Radian Corporation, A Program to Investigate Various
Factors in Refinery Siting, Final Report, Austin, Texas,
1974.
186
-------
BIBLIOGRAPHY
(Cont'd.)
RA-R-215 Radian Corporation, A Western Regional Energy Develop-
ment Study, Final Report, 4 Vols., Radian Project No.
100-064, Austin, Texas, August 1975.
RA-144 Radian Corporation, Technical and Cost Proposal for
the Selection and Development of Procedures to Assure
the Environmental Acceptability of Coal Utilizing Pro-
cesses. Proposal No. 484-101-73. Austin, Texas,
1973.
RA-150 Radian Corporation, A Western Regional Energy Develop-
ment Study. Final Report, Austin, Texas, August 1975.
RA-R-219 Radian Corporation, Coal-fired Power Plant Trace Element
Study, 4 vols., Austin, Texas, Radian Corporation,
Sept. 1975.
RO-153 Roberts, John D. and Marjorie C. Caserio, Basic Princi-
ples of Organic Chemistry, New York, W. A. Benjamin,
1965
RU-039 Ruch, R. R., H. J. Gluskoter, and N. F. Shimp, Occur-
rence and Distribution of Potentially Volatile Trace
Elements in Coal, Final Report. EPA 650/2-74-054,
Environmental Geology Notes #72. Urbana, Illinois,
Illinois State Geological Survey, 1974.
SC-239 Schmidt-Collerus, Josef J., The Disposal and Environ-
mental Effects of Carbonaceous Solid Wastes from Com-
mercial Oil Shale Operations, Denver, Colorado,
University of Denver, Denver Research Inst., January,
1974.
187
-------
BIBLIOGRAPHY
(Cont'd.)
SC-257 Schmidt-Collerus, J. J., Francis Bonomo, and C. H.
Prien, "Polycondensed aromatic compounds (PCA) and
carcinogens in the shale ash of carbonaceous spent
shale from retorting of oil shale of the Green River
formation," Amer. Chem. Div. Fuel Chem., Preprints 19
(2), 115-122 (1974).
SC-291 Scott Research Laboratories, Inc. Coal Preparation
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Coal Company, Vansant, Virginia, Contract No. 68-02-0233
Plumsteadville, PA., October, 1972.
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Stations, Summary, Contract No. 68-01-2663, Austin,
Texas, Radian Corporation, July, 1975.
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Norman, OK, May, 1975.
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San Juan County, N.M. , Draft Environmental Statement,
DES-74-77, 1974.
188
-------
BIBLIOGRAPHY
(Cont'd.)
US-291 U.S. Bureau of Land Management, Proposed Development
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DES-75-62. Appendix I: See KL-062. Washington, 1975.
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Counties, Wyoming, October, 1974.
189
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APPENDIX
-------
1.0 INTRODUCTION
Descriptions of the computer models used in this study
are presented in the Appendix. The computer models discussed are
the Radian Equilibrium Program which considers the gas phase
composition of chemical systems and the Radian Aqueous Inorganic
Equilibrium Program which considers the aqueous chemistry of
plant water systems.
The Radian Equilibrium Program was used to evaluate the
trace element distributions in the synthetic fuels processes.
The Radian Aqueous Inorganic Equilibrium Program was used to
assess the water management strategies in the plant water systems
for potential scaling problems. The computer printouts for the
two equilibrium programs are also presented.
191
-------
2.0 RADIAN EQUILIBRIUM PROGRAM
The Radian Equilibrium Program is a computerized model
that has the capability to predict the chemical equilibrium of
systems composed of a single, ideal gas phase and several pure
condensed phases. The basic computation yields the equilibrium
composition and enthalpy for a given temperature and pressure.
Optionally, the final temperature may be computed for adiabatic
operation.
The technique used involves minimization of the total
free energy of the system. The free energy of the^system is
written in terms of the standard-state free energies, the
activity coefficients, if any, and the number of moles of each
chemical species. The total free energy is then minimized
according to the basic criterion for equilibrium.
The program is written in a generalized manner to
allow for a flexible number of specified elements, condensed
phases, and species. Up to ten elements, ten active condensed
phases and four-hundred species can be considered.
192
-------
TOSCO II Oil Shale Trace Element Analysis
193
-------
SHALE OTL TRACE SPECIES
vo
TEMP B 755, OEG K PS l.o ATM
ELEMENT GM-ATC1MS TMPijT P'nF .MT 1 AL (PT ) «AlAMCF FKPM.iP
C B 6.71CIM -1.197V ,77!>-V>>i
H B 1 '•' , J '/• 3 v» -H.^OI'VJ . 3fl-t/*i
0 B . 17
S » ,3591* -13.922 My , ?< ? P. - 0 7
INITIAL ENTHALPY, H IN KCAL/K^ B tk)yi
FINAL ENTHALPY, H IM KCAL/KG » -lft2.4S
CHANGE IN ENTHALPY, OFLTA H a -1«2.4S
TOTAL MOLES OF GAS B 3. 52^77
EQUILIBRIUM *PLE FRACTION GASES
CH4 ,4(?7l7+"ffl CP j)4?ft4-W2 N?
Sf(G) ,7832n-3W CH2 ,°5?75>-P|3 H?fJ
CH3SH .76J13-no C2"4 ,!9(S30-f7 C2rifi
C2H2 ,79231-13 C?M? » .25124-?) C302
a .12685-W4 CS2
B .65PI91-35 C3H
B .P8355-05
B .35628-0)7
• .fl22a9-l_l_
• ,29R4fl-(«9
CONDENSED PHASES,MOLES/MOLE .GAS
C(GR) « 1.43302
TRACE ELEMENT OJSIRIRUT
SPECIFS, PERCENT
BE WT PPM IM FUEL « 35,
HEOCS)
HtCL (G)
BECL2CL)
BE(OH)2(G)
BE.S04
SE WT PPM IN FUEL »
•e (G)
r,n-ATOM*l ,FH B******** PCT GAS s ,w PI
3? PE (S) e .KB PEO(R)
(G) B ,9191 PE404 fG)
(G) » '.24-23 IECL;
PfcS(S) * 'fV>V BE OH
B >Pl «E3S?(S)
GM-AT0^4*1 ,F:
^6 StH2
PCT GA3
PI
8E2C
.92-22
• , 17-««7
-------
SECO
SE2 CG)
SEC fG)
CO WT PPM I'-i FHfeL »
Cnru)
C05CS)
Ci>CL3(S)
CU(CH3)2
HG WT PPM T'J FUEL =
HG(G)
HGCL CG)
MGH (G)
A3 WT PPM IN FUEL •
ASCG)
. ASO(G)
ASMCG)
PB WT PPM IN FUEL •«
S PB CG)
Cn P9P REO
PHCCL)
Ph(CL)4
PMC03 (C)
B HT PPM IN FUEL «
* CG)
BH303 (G)
B02 (G)
B2CL4 tG)
02Hf> (G)
P2H3 CD
Bh3 CG)
BH CG)
BCL2 CG)
BF CG)
PHF2 CG)
BF3 CG)
CO WT PPH IN FUEL »
rOCL CG)
3
C
8
.
S
C
s
C
.
8
C
8
7.
s
8
r
If.
s
8
8
S
a
14P.
B
B
I
B
B
a
B
B
B
C
B
*
39,
B
. •»*-•> i Sf:'» nn
.{jo.**, «5KCCH3)2
,«w-12
1 A;, O'-ATH"*) .Pf> a I
.'<•*•! MI rnn(S)
,<*7 + f>2 CliTLftn
.v." n.:C'.lH)2CG)
./?-i? rnro3
jl-.H Gi4-ATQ"* ) .Eft »
.\l-*w^ wf;n(R)
.1*. «S MG(CL)?(L)
.2P-1 1
26-t1 G^-ATQi*! ,F6 a OP"
,«'/-P!fi 4J>?CG)
,3?-(/ti A5CL3(G)
.b?-CM
WP!^. GM-ATO"*! .F.6 s 4P"
.6P+MB (P»)9
.I/IM PbO?(S)
,rt4-M»i Pii(CL)2CS)
.12-28 PHH-
,i^ci» PBSH4
a^n Gh-ATO'** 1 .Ff> B***
.(•>M H (S)
.tf« RHD2 CG)'
,pni «S IG)
,?lfl fl2(f)H)4 fS)
,!*n H20 (G)
,(?f! P*N (S)
. i". P R H ? ( G)
.IIM nci.3 CG)
.Vif MUCL CG)
,^e* POF crn
.4K-3H ROHF? (G)
.1P+P3 B2F4 (G)
,anK Grt-ATOM*i.e6 B^SI
,17-16 COCL2CS)
a . J v - t 1
= .2N-Mh
,W37b PCT GAS
a .0"
= .53-02
= ,3«-(*»i
- >ri,i.
,41*3 PCT GAS'
a .14-13
= . HP
.PIS17 PCT GAS
r ,1*-9l.(> PI
P80CG)
PH304 (S)
PrtCCl )?CG)
PK(CH314
a li^W.ffl PI
B2H3 (G)
RfJ CG)
P2 CG)
R2COH)4 fG5
f>2n? tr,)
HH CG)
PC^H)2 CG)
KCL2H (G)
BCL fG)
RF2 CG)
BOF2 CU)
M3F3P3 CG)
* .Pi PI
COCU2 (G)
Z
8
e
a
a
a
E
a
•
a
8
B
a
•
a
8
B
•
•
a
8
a
a
B
8
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8
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•
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8
.1H-19
,20-^d
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3.0 RADIAN AQUEOUS INORGANIC EQUILIBRIUM PROGRAM
The Radian Aqueous Inorganic Equilibrium Program is a
computerized model that provides the capability to predict
aqueous process chemistry. The program provides this capability
based upon the specification of nine key species commonly present
in plant water systems. These key species are: CaO, MgO, Na20,
S02, S03, C02, N205, HC1, and H20.
Numerous chemical equilibria for the system are analysed.
There are 44 dissociation-type equations, 11 solubility product
relations, and 8 gas solubility equations. Equilibrium relation-
ships are expressed as activities using products of individual
molalities and activity coefficients. The activity coefficients
are -related with ionic strengths to account for solution non-
ideality. Deviations from ideality can be quite significant in
water systems, especially when water is recycled and reused.
The program can be applied to water management systems
to predict the scaling potential for such species as calcium
sulfate dihydrate, calcium carbonate and magnesium hydroxide.
Radian laboratory experiments and pilot plant tests indicate
that the scaling potential of a chemical species can be correlated
with the relative saturation of that species in a solution. The
aqueous inorganic equilibrium program will predict these relation-
ships.
198
-------
Water Analyses for the TOSCO II and Lurgi Systems
199
-------
Colony Water System - 5 cycles of concentration
18 JUN 76
INPUT SPECIES (MOLES)
H20
CAO
MSO
NA20
« 5,55062+31
* 3.26000-03
« 3,39353-03
» 1,20003-32
PC02 • 3,33008-04 ATM.
AQUEOUS SOLUTION
COHPONENT
H*
H20
H2C03
HC03-
HS04-
CA*»
CAOH*
CAHC03*
CAC03
CAS04
MG+ +
MGOH*
HGHC03*
HGC03
HGS04
NA*
NAOH
NAHC03
NAC03-
NAS04-
QH-
Ct-
C03—
S04--
COHPQNENT
CA(OH)2(S)
CAC03C5)
CASOI(S)
HG(OH)2CS)
HGC03CS)
HOLALITY
1,598-07
2,139-05
5,337-05
2.096-08
3|271-1?
1,053-06
1.2S1-H8
5,532-04
2,855-03
4,979-09
2|l35-08
5, 371-04
2.372-02
5,516-11
8,623-07
1,303-03
2,733-84
1,250-08
2,329-02
1,732-08
5,653-03
MOLALITY
0,000
0,000
0,003
0,000
0,000
HCL
C02
N203
N20S
S02
S03
EQUILIBRIA
ACTIVITY
1,374-07
2,156-05
4.434-05
1,701-08
1,315-03
2,716-10
8,744-07
1.271-H8
5.577-U4
1,441-03
4,134-09
4,999-07
2.152-08
5,415-04
1,990-02
5,561-11
8,693-07
1,082-08
2,267-04
1,038-08
1,917.'02
8,245-99
2.527-0
ACTIVITY PR
1,417-1
1,044*1
3,318-0
1.553-1
1.182-1
•TEMPERATURE
2.32303-82
0.00093
2.240 OEG. C,
C02 « 7.73589-05 MOLES
0.03080
7)02500-03
ACTIVITY COEFFICIENT
8,599-01
9t«
8,307-01
8, 304-B1
4.862-01
8,304-01
8,304-01
1,008*00
1.PU8+0U
5.048-01
8.304-05
8,304-01
1,008*00
1,008*00
8.391-01
1,008*00
1,008*90
8.304-01
8,304-01
8,3*4-01
8.265-01
4,761-01
4,465-0>
1,673-14
7,720-04
1,619-01
9.103-99
2.989-07
PH • 6.8621
MOLECULAR HATER • 1,00021*00 KGS.
IONIC STRENGTH • 4.60632-02 RES, E.H, • •2,701-08
200
-------
Colony Water System - 10 cycles of concentration
18 JUN 76 18126149.996
TEMPERATURE
INPUT SPECIES (IDLES)
2.240 OEG, C,
H20 « 5.55362+01
CAO * 6,52090-03
HGO • 0.78703-03
NA20 « 2.40009-02
HCL
C02
N203
N20S
502
303
3.0333W
1,43503-02
PC02 • 3,3(5046-04 ATM.
AQUEOUS SOLUTION EQUILIBRIA
OMPONENT
H +
H2Q
H2C03
HC03-
HS04-
CAOH +
CAHC03*
CAC03
CAS04
HG+ +
MGOH +
MGHC03+
MGCU3
HGS04
NA>
NAOH
NAHC03
NAC03-
HAS04-
OH-
CL-
C03-- .
MOLALITY
8,908-08
2.121-05
l,03i)-04
1,763-08
5,222-03
1,008-09
3,245-06
6,751-08
1,294-03
5,499-03
1.567-08
1,894-05
1.168-07
1,283*03
4,717-02
1,912-10
2. 988-00
8,751-08
8,014*04
2,483-08
4,638*02
7,154-08
ACTIVITY
7,485-38
2, 154-35
8,130-05
1,394-38
7|985. 18
2,571-06
6,8bB-08
1,315-03
2,360-03
1,241-08
1,531-06
1,166-07
1.303-33
3,790-02
3|336*06
6.933-08
6,349-04
1,934-08
ACTIVITY COEFF
8,403-01
9,981-01
7J892-01
7,922-31
7|922-0l
7.922-01
1,016+03
1,816+00
4.291-01
7,922-01
1 ,OlS+«3
1,016+00
8,035-01
1,016+00
l,fll6+3U
7,922-01
7,922-01
7.922*81
7,826*01
3,679.01
304 —
COMPQNENT
CA(OH)2(S)
CAC03(S)
CAS04(S3
HG(OH)2(3)
MGC03CS)
C02
l,B67r02
MOLALITY
0,000
0,000
a,000
a.aoa
0,0(13
3.716-B3 3,484-01
ACTIVITY PRODUCT RELATIVE SATURATION
7,642-19
5,852-11
7,837-05
8,550-19
6,465-11
9,321*14
4.166-03
3,811-01
5.011-08
1,639-06
* 1,32747-04 HOLES
MOLECULAR WATER • 1,00042+00 XGS,
PH • 7,1258 IONIC STRENGTH • 9,00008-32 RES, E.N, « -fl.425-08
201
-------
Colony Water System- 20 cycles of concentration
18 JUN 76
18:26(44,786
INPUT SPECIES (10UE5)
TEMPERA'URE 2.240 DEC, C,
H20 a 5,
CAO « 1,
M30 • 1,
NA20 * 4,
55P62+01
35743-32
80000-02
PC02 > 3,33000-04 ATX.
AQUEOUS SOLUTION
COMPONENT
H +
H20
H2C03
HC03-
HS04-
CA + +
CAOH +
CAHC03+
CAC03
CAS04
HG++
HGOH+
MGHCOJ+
HGC03
HGS04
NA+
NAOH
NAHC03
NAC03-
OH-
CU-
C03—
SQ4 —
COMPONENT
CACOHJ2CS5
CAC03CS)
CAS04(S)
MG(OK)2(S)
MGC03CS)
HOLALITY
5,039-08
2,085-05
1,943-04
1,444-38
1,017-92
3,006-09
3J377-07
2,834-03
1,065-02
4,797-08
5I997-07
2,905-03
9,368-02
6,361-10
9,943-06
5.512-H7
2,225-03
4,472-08
9,272-02
2,866-07
2,089-02
MOLALITY
0.0559
3,0(10
0,009
8,003
HCL
CQ2
N203
N205
302
303
EQUILIBRIA
ACTIVITY
4.2M-H8
2,153-05
1,446-04
1.JI93-08
3,37
-------
Lurgi System - raw water
21 JUN 76
11130:22,939
TEMPERATURE
INPUT SPECIES (HOLES)
4.34k) DEC. C,
H20 « 5,55f«2+01
CAO • 8,733^3-04
MGO • 6.17300-04
NA20 » 5,84pfl3-03
HCL * 2,87330-04
C02 3 t).
N205 « i
502 - I
S03 • 7.1420H-03
PC02 • 3.33032-04 ATM.
AQUEOUS SOLUTION EQUILIBRIA
COMPONENT
H +
H20
H2C03
HC03-
HS04-
CAt*
CAflH*
CAHC03+
CAC03
CASO'l
HGOH +
HGHC03+
MGC03
MGSU4
MA +
NAOH
MAHC03
NAC03-
NAS04-
OH-
CL-
C03--
2,016-815
8.749-05
1,773-38
6,408-04
1.9H-1&
5.H06-07
1,184-08
2,320-04
1,994-89
1,9?3-U7
1.355-08
1,526-04
1,148-02
5,934-11
7.533-07
2,044-08
1,938-04
2,525-08
2,870-04
4,555-08
ACTIVITY
7,931-08
2,5)23-05
7,628-05
1,544-08
3,739^04
1,664-10
4,359-07
2J329-04
2,765-04
1,736-09
1.S75-C.7
1,361-08
1,531-04
1,3^6-02
5,956-11
7,563-07
1,688-04
2,199-08
2,495-34
2,632-08
ACTIVITY COEFFICIENT
8,87l-fl
9,997-Jil
8.718-01
8.707-C1
5,834-01
8,737-01
8,707-Vl
1,004*^0
5,956-Cl
8.737-H1
6.7«)7-Hl
8,7-63-01
1.01)4+04
8,7»J7-01
6,707-»l
8,787-Bl
8,695-01
5,778-01
S04— 6.564-03
COMPONENT HQLALITY
0,000
0,830
e.eoa
C02 « 1.J9186-04 HOLES
MOLECULAR MATER * 1.02000+00
PH * 7.1007 IONIC STRENGTH • 2,13643-32
CA(OH)2(S)
CAC03CS)
CASU4CS)
HG(OH)2(S)
HUC03CS)
3.665-03 5,583-01
ACTIVITY PRODUCT RELATIVE SATURATION
1.8*7-19
9.HJ9-12
1,369-06
1,337-19
7,265-12
2,2k)8-14
7.785I-P4
6,5ll-?2
8.P77-09
1,951-07
RES, E.N. « 4.657-09
203
-------
Lurgi System - 5 cycles of concentration
21 JJN 76
:J9:26.i
INPUT SPECIES MOLES)
TEMPERATURE 4,340 OEG. C,
PC02 » 3
COMPONENT
H*
H20
H2C03
MC03-
HS04-
CA + *
CAOH*
CAHC03+
CAC03
CAS04
MG* +
HGOH*
MGHC03*
MGC03
HGS04
NA*
NAOH
NAHCOJ
NAC03-
NAS04-
OH-
CL-
C03 —
H20 « 5,55062*01
CAO • 4.36653-03
NA20 « 2,90003-02
,33004-04 ATM.
AQUEOUS SOLUTION
MOLALITY
2,137-07
1,986-05
4,313-05
1,219-07
2,631-03
2,581-10
6.762-07
6,309-09
1,898-03
2,801-09
2,703-07
7,516-09
1,187-03
5,540-02
1,137-10
1,444-06
1.948-08
2,592-03
1.237-08
1,435-03
1,377-08
HCL
CU2
N205
S02
303
EOUILI83IA
ACTIVITY
1,791-07
2,321-05
3,374-05
9,587-08
1..B31-H3
2,329-10
5.317-07
6,419-09
1.766*03
7,931-04
2.2*13-09
2.125-07
7,648-09
1,208-03
4,423-02
li469-«6
1. 531-08
2,038-03
9.726-09
1,113-03
5,156-09
« 1.43500-03
* 3!s7103-d2
ACTIVITY COEFFICIENT
8,378-01
9,985-Hl
1 ,018*00
7,323-01
7,863-01
3. 919-0J
7.863-01
7.863-01
l)018»00
4.179-01
7,863-01
7.863-01
l|018*00
7,9-78-01
1,018+00
7 1863-01
7,863-01
7,863-01
7.7S4-01
3,746-01
S04--
COMPONENT
CA(OH)2(S)
CAC03(S)
CAS04(5)
MG(OH)2(S)
HGC03CS]
3.019-32
10LALITY
0,000
0,000
0,00a
1,008.02 3,337-01
ACTIVITY PRODUCT RELATIVE SATURATION
9,752-22
5,315-12
1,036.05
7,502-20
4,059-12
1,191-14
4.203-04
,925-01
,533-09
1,090-07
0,000
C02 • 6,54303-25 HOLES
MOLECULAR MATER • 1.02001*00 *GS.
PH « 6.747B IONIC STRENGTH • 9.91832-02 RES. E.N, > -2,515-08
204
-------
Lurgi System ~ 8 cycles of concentration
22 J'JN 7*
UM7J24.63S
INPUT SPECIES
H20 = 5.55062+31
CAO » 6,y«643-H3
MSO = 4,93l>?a-HJ
NA20 s 4.(>
pco2 * 3.J3B16-34 AT*.
H +
H20
H2C03
HCU3-
H504-
CAOM+
CAHcnj
CACQ3
HG+ +
KGOH +
KGC03
HGS04
NAOH
N4HC03
MAC03-
MASQ4-
OH-
CL-
C03--
SOLUTION
HOLALITY
1.965-e5
l.MZ-04
6.454-P9
4,045-03
8.657-lia
2.939-83
2,B96-03
9,759-09
9.416-H7
6,221-38
2,039-03
8,629-02
4,305-10
5,467-36
1,901-07
5,251-4)3
3,155-08
3,0<*3-03
9,867-ifi8
TEMPERATURE
HCL * .
C02 s 4.2205)3
N203 « i
N205 * 1
502 t (
S33 = 5.71363-32
4,34!9 OEG, C,
ACTIVITY
7,23(5-08
2,ni<»-«5
8.344-35
l,3a9-*3
6,759-13
l,77t-M6
1.B83-H3
7,
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