600
ASSESSMENT OF SOLID WASTE CHARACTERISTICS AND
CONTROL TECHNOLOGY FOR OIL SHALE RETORTING ;
by
Ashok K. Agarwal
Monsanto Company
1515 Nicholas Road
Dayton, Ohio 45418
Contract No. EPA 68-01-6487
Project Officer
Edward R. Bates ]
Hazardous Waste Engineering Research Laboratory-
Cincinnati, Ohio 45268
March 1986
Air and Energy Engineering Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
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NOTICE
The information in this document: has been funded wholly or in
part by the United States Environmental Protection Agency under
Contract 68-01-6487 to Monsanto Company. It has been subject
to the Agency's peer and administrative review, and it has been
approved for publication as an EPA>document.
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FOREWORD
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When energy and material resources are extracted, processed,
converted, and used, the related pollutional impapts on our
environment and even on our health often require that new and
increasingly more efficient pollution control methods be used.
The Air and Energy Engineering Research Laboratory, Research
TriailOle PaT~l? . asc'l e1"C in HOTT-OT /-vr\-iT-i/-r =si->^ ^^w./->»-.r-i4--v--,-t-T -^-^ ~.-.,, __j
I me Air and Energy Engineering Research Laboratory, Research
Triangle Park, assists in developing and demonstrating new and
improved methodologies that will meet these needs i both effi-
ciently and economically. .
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Frank Princiotta i
Director :
Air and Energy Engineering Research Laboratory
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ABSTRACT
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This report is a comprehensive study of the characteristics of •
solid and liquid wastes produced from various oil shale process- H
ing technologies, and control methods for environmentally safe
disposal of solid wastes. It also includes the results from an m
experimental study to construct liners and covers for proper ||
disposal of spent shales. In addition the auto ignition potential
of raw and spent shales has been evaluated. «
Considerable effort is currently being directed to commercializa- •
tion of processes to produce liquid fuels from oil shale deposits
in the United States. When financing uncertainties are resolved, •
construction of large-scale plants could begin. The retorting of |
oil shale produces large quantities of solid wastes. These wastes
include raw mined oil shale (which does not contain enough kerogen «
for economical recovery), spent oil shale (mineral matter from |
which the kerogen has been thermally removed by retorting), over-
burden material (which must be removed before the shale can be
mined), shale fines from processing operations (e.g., dust •
collected in fabric filters) and process wastes (e.g., spent •
catalysts, wastewater treatment sludges).
Oil shale deposits in the eastern and western parts of the United f|
States, their geological subdivisions, their locations, tonnage,
and their physical and chemical characteristics have been _
described. The solid and liquid wastes generated from the various •
oil shale technologies have been compiled. Amounts of solid and
liquid wastes generated and their composition depend, among other
things, on the particular technology used and on the type of shale •
processed. Some of the wastes may also be site specific. Avail- •
able field and laboratory leachate data are also presented.
If only one-half of the planned production comes on line, it would |
eventually amount to approximately 600,000 barrels per day of
shale oil. This would lead to approximately 740,000 tons/day or _
270 million tons per year of retorted oil shale, along with lesser •
quantities of other solid wastes, which will require environmen- "
tally safe disposal. If not properly managed, these high volume
wastes are capable of producing leachates that could contaminate •
the water supply for millions of people. Surface disposal sites •
covering many square miles in area and hundreds of feet in depth
would do extensive property damage and threaten lives should •
they ever suffer sudden mass failure. An experimental program |
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was undertaken to establish the best combination of spent shale
with materials readily available at the disposal site to construct
liners and covers for the spent shale disposal. i
Also in this report available information has been pompiled in
order to evaluate the auto ignition potential of raw and spent
shales from various oil shale processes. The results indicate
that raw shale fines have a potential for spontaneous ignition
similar to bituminous coals while such potential for retorted
shales appear to be less. Hence, there is a potential jthat if oil
shale disposal sites are not properly designed they i could auto
ignite. It appears probably that control technology employed by
the coal industry can be modified and applied toi oil shale
disposal sites to mitigate this hazard. j
Control technologies to prevent serious adverse impacts from dis-
posal of billions of tons of oil shale wastes have bejsn proposed
but their application to oil shale waste materials oh the scale
required for commercial plants has not been demonstrate^. Further-
more, to be effective, these control technologies must be applied
to highly technical and integrated disposal designs that are site
and process specific. There is no current experience an disposal
of wastes of similar composition or of volumes approaching that
which will result from the oil shale industry. i
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CONTENTS
Foreword
Abstract
Figures
Tables.
Acknowledgment xxii
1. Introduction ; .
1.1 Sources and volumes of solid waste, including
an overview of the oil shale industry . . .
1 i
1.2 Potential dangers to human health and the ',
environment from the disposal and reuse of
the wastes. 5
1.3 Present/proposed disposal approaches. . . i . 17
1.4 Conclusions and additional research needed i. . 21
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2. Characteristics Of U.S. Oil Shale !. 23
2.1 Introduction ' . 23
2.2 Location j . 23
2.3 Geology . 1 . 28
2.4 Composition ; . 41
2.5 Physical properties . 52
3. Solid Wastes and Their Characteristics for •
Oil Shale Retorting Processes . 69
3.1 Lurgi-Ruhrgas oil shale retorting ....;. 69
3.2 TOSCO II oil shale retorting, j . 85
3.3 Paraho direct heating mode oil shale i
retorting J . . 105
3.4 Paraho indirect heating mode oil shale
retorting .: . 127
3.5 Occidental modified in situ oil shale j
retorting j . 135
3.6 T? oil shale retorting .; . 151
3.7 Hytort oil shale retorting. j . 155
3.8 Geokinetics horizontal in situ oil shale i
retorting : . 164
3.9 Superior circular grate oil shale retorting . 168
3.10 Union Oil A oil shale retorting 177
3.11 Union Oil B oil shale retorting i. 182
3.12 Union Oil SGR oil shale retorting ;. 191
3.13 Chevron STB oil shale retorting :. 202
3.14 Allis-Chalmers oil shale retorting . . . . ;. 210
3.15 Dravo oil shale retorting i. 216
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CONTENTS (continued)
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4. Environmental Control Technologies ....... . 219
4.1 Environmental impacts ........... . 219
4.2 Disposal alternatives ......... ... 222
4.3 Control technologies ............ 227
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References ............ ........... • 255
Appendix ............. ............ A~!
A. Auto-oxidation potential of raw and spent shale
and the suggested design of piles to avoid the •
auto-ignition of shales. . . .......... A-l gj
B. Use of spent oil shale as a liner material at
spent shale disposal sites ........... B-i _
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FIGURES
Number
2.2-1 Principal United States oil shale deposits. .1 . 24
2.2-2 Green River formation oil shales-Utah, !
Colorado, and Wyoming ] . 25
2.2-3 Distribution of upper Devonian and lower |
Mississippian Black Shales in the Eastern
United States | 27
2.3-1 Schematic North-South cross section of Piceanjse
Creek showing relationship of oil shale >l
bearing members of the Green River formation
and surrounding strata j 32
2.3-2 Schematic cross section of Uinta Basin showing
relationship of oil shale bearing Green River
formation with surrounding strata .....;. 34
2.3-3 Schematic cross section showing relationship of
Green River formation with surrounding strata 37
2.3-4 Oil yield of Tipton shale member. ..... .:. 38
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2.3-5 Oil yield of Wilkins peak member 39
2.3-6 oil yield of Laney shale member ' . 40
2.4-1 Organic matter content of Green River oil i
shales . 44
2.5-1 Specific gravity and oil yield of Colorado oil
shales 54
2.5-2 Compressive strength of oil shales 60
2.5-3 Compressive strength-versus Fischer assay of''
Colorado oil shale, Anvil Points Mine . . . i. 62
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3.1-1 Lurgi-Ruhrgas oil shale retorting process . .I. 70
3.1-2 Lurgi-Ruhrgas Process operations and
waste streams 72
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Number
39 — 1
. .& — X
3.2-2
3.3-1
30_0
. O £•
3.4-1
3.5-1
3.5-2
•3 fi-l
*J * U JL
3.7-1
3.7-2
O O *|
3.8-2
3.9-1
3Q — 9
. ;? <£
3.9-3
31 0—1
• X U X
3.11-1
3.11-2
3.12-1
3.13-1
FIGURES (continued)
Process block flow diagram for sand wash
Schematic of Paraho direct heating
Paraho indirect mode process flow diagram . . .
Schematic of the Occidental modified in situ
Occidental MIS retorting, oil/water separation
Diagram of IGT oil shale gasification process
Hytort commercial plant conceptual design . . .
Electrical conductivity breakthrough curve
for Leachate from Geokinetics spent shale . .
Superior retorting process retort showing
movement of charge through various zones. . .
Superior process flow diagram and major waste
Flow diagram for retort! system in Union oil
Block flow diagram for Union oil Retort B
Diagram of Union Oil SGR-3 retorting process. .
Process flow scheme of Chevron STB retort . . .
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Page
86
88
106
107
128
136
137
152
156
158
163
167
170
171
172
178
183
185
192
203
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FIGURES (continued)
Number
3.13-2 Block flow diagram of Chevron semiworks oil !
shale plant '. 206
3.14-1 Allis-Chalmers oil shale process flowsheet. . . 213
3.14-2 Allis-Chalmers oil shale retorting and combustion
process development unit flow schematic .... 214
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3.15-1 Dravo retorting process . , . 216
3.15-2 Dravo pilot plant flowsheet schematic .-..].. 218
4.3-1 Surface hydrology control technologies. .. . 1 . 228
4.3-2 Runon diversion costs 1 231
4.3-3 Runoff collection costs [ 233
4.3-4 Runoff/leachate pond costs : 235
4.3-5 Runoff/leachate pond liner costs 236
4.3-6 Subsurface hydrology control technologies . j . 237
4.3-7 Liner costs j 240
4.3-8 Leachate collection costs -. ! 242
4.3-9 Groundwater collection costs ! . ' 244
4.3-10 Surface stabilization technologies j 245
4.3-11 Dust control costs ; 248
4.3-12 Reclamation and revegetation costs ! . 250
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Number
1 1-1
JL. * J. JL
1 1 — 9
J. * J."*j£
1 1 — ^
J. * JL *>
1.1-4
1.2-1
1.2-2
1.2-3
1.2-4
1.2-5
1.2-6
1.2-7
1.2-8
1.3-1
2.2-1
TABLES
; Page
Antrrnx n matp Solid Waste Relationships 6
Major Waste Produced Over a Period of 20 Years
(TOSCO II 47,000 bbl/day plant with upgrading) 7
Summary of Results from Differential Scanning
Calorimetry and Nonadiabatic Oxygen
Chemical Properties of Union B Retorted Shale . 9
Estimated Composition of Process Water for
P(=t"OT~"t"(=f^ ^Vial*3 Pool "i ncr/Wp't'T'i ncr ...... 10
RCRA Testing of Simulated Shale Plant Wastes
Chemical Composition of Leachates from Union B
Retorted Shale Leachates by Leaching Method
(ma/L) 13
Raw Mined Oil Shales Leachates (Maximum
Estimated Quantities of Some Major Constituents
Leachable from Oil Shale (Assuming
Permeability and Water Availability are not
Key Features of Solid Waste Disposal Approaches 18
Total In-Place Shale Oil Resources of the
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TABLES (continued)
Number
! Page
2.4-1 Mineral Content bf Green River Oil Shale !
Versus Grade. , 41
2.4-2 Average Mineral Composition of Mahogany Zone1
Shale, Colorado and Utah j 41
2.4-3 Fischer Assay Data of the Inorganic Mineral '
Portions of 16 Samples of Green River Oil
Shale Ranging From 10.5 To 75.0 gal/ton Oil
Shale ......... !
42
2.4-4 Chemical Composition of the Inorganic Portiori
of Various Grades of Green River Oil Shale '
and of The Spent Shale Products ; 43
2.4-5 Typical Mineralogical Composition of Devoniari
Black Shale ! 43
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2.4-6 Probable Composition of Mahogany-Zone Organic
Matter . .' . 45
2.4-7 Elemental Composition of New Albany Shale ;
Organic Matter : 45
2.4-8 Approximate Carbon/Hydrogen Ratios in Various
Organic Materials 45
2.4-9 Authigenic Sodium Minerals In The Green River'
Formation j 48
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2.4-10 Average Distribution of Sulfur and Nitrogen In
Oil Shale ! . .: . 50
2.4-11 Distribution of Sulfur and Nitrogen in ;
Colorado Oil Shale 50
2.4-12 Levels of Trace Elements in Green River Oil I
Shale , ^ 51
2.5-1 Visual Features of Green River Oil Shale. . .I. 53
2.5-2 Weight (Inplace) and Weight (Broken) for Green
River Oil Shale' :. 55
2.5-3 Porosities of Raw and Thermally Treated Oil '
Shales (Percent of Bulk Volumes) ;. 57
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TABLES (continued) "
Number Z^ge ffi
2.5-4 Shear Strengths of Lean Oil Shale Specimens
from Roof Material of USBM Experimental Mine n
(Anvil Points). 58 p
2.5-5 Compressive Strengths of Raw and Thermally-
Treated Oil Shales (Kilograms Per Square •
Centimeter) 59 ™
2.5-6 Compressive Strength of Green River Oil Shale en
Samples Cut Perpendicular to Bedding (Samples H
from USBM Experimental Mine, Anvil Points,
Colorado) 61 _
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2.5-7 Summary of the Range of Concentrations in m
Leachate Samples. . . j 63
2.5-8 Comparison of Trace Element Concentrations from B
Raw Mined Shale with those from Soils and
Previously Exposed Shales 64 am
2.5-9 Mean Values for Major Ion Composition of C-a
Leachate 65
2.5-10 Mean Values for Major Ion Composition of C-b •
Leachate 65
2.5-11 Mean Values of Trace Element Concentrations of |
C-a Leachate ; 67
2.5-12 Mean Values of Trace Element Concentrations of J|
C-b Leachate 67
2.5-13 Maximum Observed Concentrations in Raw Shale •
Leachates 68 V
3.1-1 Inventory of Streams to be Disposed of as «
Solid Waste in the Lurgi-Ruhrgas Process. . . 75 g
3.1-2 Physical Properties of Lurgi Processed Shale. . 77
3.1-3 Summary of Hydraulic Conductivity Measurements •
for Various Compaction and Loadings for Lurgi
Retorted Shale. 78 •
3.1-4 Water Holding Capacity of Lurgi Processed
Shales at Various Pressures and Bulk m
Densities 78 I
xiv
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TABLES (continued) ;
Number | Paqe
3.1-5 Composition of Lurgi Processed Moisturized i
Shale . ................. : 79
3.1-6 Inorganic Analysis of the Lurgi '< •
Processed Shale .......... ..... 79
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3.1-7 Major Ion Composition of Column Leachate-Lurgi
Retorted Shale .............. j go
3.1-8 Concentration of Selected Trace Elements in i
Column Leachate of Lurgi Retorted Shale . J . 81
3.1-9 Concentrations in ASTM Water Shake Test i
Extracts - Lurgi Spent Shales ......... 82
3.1-10 Concentrations in RCRA Test Extracts - Lurgi !
Spent Shales ................ j . 33
3.1-11 Leachable Mass as Indicated by the ASTM ;
Proposed Water Shake Test for Lurgi Spent i
Shales - mg/g . .............. j 34
3.1-1.2 Leachable Mass as Indicated by the RCRA I
Extraction Test for Lurgi Spent Shales - mg/g 84
3.2-1 Summary of Solid Wastes Generated at Sand Wash
Processing Facility ............ j go
3.2-2 Major Waste Produced Over a Period of 20 Years
for TOSCO II 47,000 bbl/day Plant with
Upgrading
3.2-3 Physical Properties of TOSCO II Processed Shale 92
3.2-4 Sieve Analysis of TOSCO II Spent Oil Shale !
Residue .................. ! 92
3.2-5 Hydraulic Conductivity Measurements of TOSCO II
Retorted Shale ............... : 93
3.2-6 Water Holding Capacity of TOSCO II Processed !
Shales at Various Pressures and Bulk ',
Densities ................. i 93
3.2-7 Reported Analysis of TOSCO II Processed Shale! - 94
3.2-8 Selected Elemental Concentrations in Raw and '
Retorted TOSCO II Oil Shales ........ i. 94
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Number
1
TABLES (continued) **
B
Page
3.2-9 Some Polycyclic Aromatic:Hydrocarbons that have
been Detected in the Benzene Extract of TOSCO m
II Spent Shales • • 95 |j
3.2-10 Approximate Composition of TOSCO II Combined
Process Wastewater (50,000 bbl/day upgraded •
shale oil production) 96 •
3.2-11 Organic Content of Gas Condensate (Foul Water) ffl
For TOSCO II 97 V
3.2-12 Composition of Foul Water for TOSCO II 97 _
3.2-13 Inorganic Species in TOSCO II Foul Water. ... 98 •
3.2-14 Concentrations in ASTM Water Shake and RCRA •
Extracts - TOSCO II Spent Shales 99 m
3.2-15 Leachable Mass as Indicated by RCRA and ASTM m
Water Shake Extraction Test for TOSCO II (
Spent Shales 100
3.2-16 Effluent Concentrations - (TOSCO II) Spent I
Shales. Constant Rate Injection into a *
Dry Column 1°1
3.2-17 Levels of Trace Elements Measured in Runoff and 1
Leachates from Field Test Plots of TOSCO II
Retorted Shale (ppm). : 102 «
3.2-18 Inorganic Composition of TOSCO II Leachates
Produced During Laboratory and Field
Lysimeter Studies (mg/L) 103 •
3.3-1 Paraho Direct Solid Wastes: Types and
Quantities • HO m
3.3-2 Paraho Direct Retorted Shale Characteristics. . Ill
3.3-3 Paraho Direct Retorted Shale Major Elements •
3.3-4 Paraho Direct Retorted Shale Trace Elements A
(ppm) 1]-3 •
3.3-5 Paraho Direct Product Water Bulk
Properties (wt. %). . ............ H5
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TABLES (continued)
Number
3.3-6 Paraho Direct Product Water Major Species/Gross
Salinity (ppm)
3.3-7 Paraho Direct Product Water Trace
Elements (ppm)
3.3-8 Compounds Identified in Paraho Direct Oil
Shale Wastewaters
116
118
3.3-9 Paraho Direct Recycle Gas Line Drain (ppm). .! . 121
3.3-10 Concentrations in RCRA and Water Shake Test I
Extracts - Paraho Direct Spent Shales . . ., . 122
3.3-11 Leachable Mass as Indicated by the ASTM |
Proposed Water Shake Extraction Test for i
Paraho Direct Spent Shales - mg/g ..... ; . 123
3.3-12 Column Leaching Effluent Concentrations for i
Paraho Direct Spent Shales ........ ',. 124
3.3-13 Inorganic Composition of Paraho Direct Spent ;
Shale Leachates Produced During Field •
Lysimeter Studies, (mg/L) ......... ; . 125
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3.4-1 . Paraho Indirect Retorted Shale Characteristics 130
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3.4-2 Paraho Indirect Retorted Shale Chemical ;
Composition ........... ..... | 131
3.4-3 Composition of Paraho Indirect Spent Oil Shales 132
3.4-4 Paraho Indirect Process Water Composition . . j . 133
3.4-5 Inorganic Analysis of Condensate Streams from'
the Paraho Indirect Process ........ ; . 134
3.4-6 Composition of Batch Generated Leachate from !
Paraho Indirect Retorted Shale ....... j . 135
3.5-1 Inventory of Solid and Liquid Waste Streams ;
for Occidental MIS Process ......... \ . 140
3.5-2 Compositions of Solid and Waste Streams for !
Occidental MIS Process ........... j . 141
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3.5-3 Composition of MIS Occidental Processed Shale! . 142
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TABLES (continued) •"
Number
'' ..... " ' '
3.5-4 Boron and Fluoride in Oxy Retort 3E Spent Shale 142
3.5-5 Mineralogical Analyses for Selected Samples of ||
Oxy Retort 3E Spent Shale Core ........ 142
3.5-6 Analysis of Core Samples^ from Oxy Retort 3E I
Preliminary Data. . . ......... ... 143 *
3.5-7 Oxy Retort 6 Steam Boiler Blowdown Collected -
March 6, 1979 (in ppm except as noted). . . . 144
3.5-8 Compounds Identified in Occidental Oil Shale g
Retort Wastewaters. . ............ 145 B
3.5-9 Oxy Retort 6 Product Water Analysis Results . . 147
3.5-10 Concentrations of Dissolved Species in the v
Leachate from Occidental MIS Processed Shale. 148
3.5-11 Concentration Range of Macro Ions Found in the g
First Fraction of Leachates from Occidental
MIS Retorted Shale. . , ............ 148 —
3.5-12 Inorganic Composition of Leachates from ™
Occidental's Retort 3E, Logan Wash, Colorado
(mg/L) ........ ............ 149 M
3.7-1 Water Holding Capacity of Hytrot Processed
Shales at Various Pressures and Bulk
Densities ...... ............ 159
3.7-2 Concentrations in ASTM Water Shake and RCRA
Tests Extracts - Hytort Spent Shales ..... 160 •
3.7-3 Leachable Mass from Hytort Shale as Indicated
by the ASTM Proposed Water Shake Test and
RCRA Extraction Test - mg/g ......... 161
3.8-1 Inorganic Composition of Leachates from
Geokinetics Spent Shale (mg/L) ........ 164
3,8-2 Major Ion Composition of Effluent (Geokinetics
6) ...................... 165
3.8-3 Concentration (mg/L) of Trace Elements for
Selected Pore Volumes (Geokinetics 6) .... 166 m
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TABLES (continued) j
Number I Page
3.9-1 General Water Quality Parameters of Superior!
Oil Shale Process Water j . 173
3.9-2 Inorganic Composition of Superior Leachate i
Produced by the ASTM Test Method D3987. . .' . 174
3.9-3 The Effect of Coproducted Retort Waters on tne
Quality of Superior Leachates from Spent
Shales j . 175
3.9-4 Effect of Distilled Water, and Time on the !
Leachate Quality of Moistened, Compacted
Superior Spent Shales ! . 175
3.9-5 Concentration of Metals in Leachates from '••
Superior Retorted Shales '', . 175
3.10-1 Physical Properties of Union A Spent Shale. .: . 180
3.10-2 Chemical Properties of Union A Retorted Shale . 180
3.10-3 Analysis of Leachate Obtained in Laboratory '
Tests of Union A Raw and Retorted Shale . .! . 181
3.10-4 Inorganic Composition of Leachates from Union| A
Spent Shale • . isi
3.11-1 Inventory of Streams to be Disposed of as :
Solid Wastes in Union B Process [ . 186
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3.11-2 Physical Properties of Union B Spent Shale. .! . 187
]
3.11-3 Chemical Properties of Union B Retorted Shale! . 187
3.11-4 Estimated Composition of Union B Process Water
In the Active Basin and the Reuse Water Sump. 188
3.11-5 Inorganic Composition of Leachates from UnioniB
Spent Shale, mg/L j . 189
3.11-6 RCRA Testing Of Simulated Union B Oil Shale :
Plant Wastes ; . 190
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3.12-1 Physical Properties of Union SGR Spent Shale.i . 193
3.12-2 Particle Size, pH, and Electrical Conductivity
of Spent Oil Shales Produced by Union SGR
Retorting Process . 193
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TABLES (continued)
Number Page •
3.12-3 Chemical Properties of Union SGR Retorted Shale 194
3.12-4 Amounts and Quality of Surface Runoff from ff
Union SGR Decarbonized Shale Lysimeter Study. 195
3.12-5 Water Quality of Percolate from Union SGR •
Decarbonized Shale Lysimeters 196
3.12-6 Analysis of Spring Snowmelt Runoff and •
Percolate from Union SGR Decarbonized •
Shale Lysimeter Study. April 21, 1976. . . . 197
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3.12-7 Analysis of Runoff and Percolate Samples
Collected August 5, 1976 from Union SGR
Decarbonized Shale Lysimeter Study 198
3.12-8 Analysis of Spring Snowmelt Runoff and
Percolate from Union SGR Decarbonized
Shale Lysimeter Study.' April 21, 1976. . . . 199 jfl
3.12-9 Analysis of Runoff and Percolate Samples
Collected August 30, 1977 from Union SGR
Decarbonized Shale Lysimeter Study 200
3.12-10 Analysis of Spring Snowmelt Runoff and
Percolate from Union SGR Decarbonize
Shale Lysimeter Study. May 3, 1978 201
Percolate from Union SGR Decarbonized •
•
Chevron STB Retort. ... .......... 205 J§
3.13-1 Nominal Process Operating Conditions for the
Chevron STB Retort. ...
3.13-2 Preliminary Results: Chevron STB Pilot Plant «
Spent Shale Properties ............ 208 9
3.13-3 Chevron STB Spent Shale : Leach Test Results. . . 209
3.14-1 Allis-Chalmers Western Shale Tests ..... . . 215 •
Technologies 229 ||
4.3-1 Key Features of Surface Hydrology Control
Technologies ..... .........
4.3-2 Key Features of Subsurface Hydrology Control —
Technologies ..... ............ 238 •
4.3-3 Key Features of Surface Stabilization
Technologies ..... ; ............ 246 0
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TABLES (continued)
Number
4.3-4 Engineering Costs and Timing of Solid Waste
Management Activities for a 47,000 bbl/day
Facility (Thousands of Dollars) . . . . j . 252
A-! Description of Samples Tested by RTI. . . . J . A-7
A-2 Mean Heat Capacity of Coal and Shale
Materials Based on Initial Sample
Weight (J/G, -325 Mesh) i . A-7
A~3 Exothermic Onset Temperature in Oxidation •
of Coal, Oil Shale and Retorted Oil Shale
(2°C/minute heating ramp, -325 Mesh) A-9
A-4 Magnitude of Exothermic Reaction of Coal, oil|
Shale and Retorted Oil Shale (2°C/minute i
heating ramp, -325 Mesh) \ . A-10
A-5 Spontaneous Combustion Index and Calculation i
Parameters of Materials Subjected to l
Nonadiabatic Test (Tested Dry) ; . A-12
!
A-6 Summary of Results From Differential Scanning
Calorimetry and Nonadiabatic Oxygen i
Absorption Testing ! A-16
A-7 Effect of Compaction in Reducing the Volume !
of Air Entering or Leaving a Coal Mass in
Response to Barometric Pressure Change. . .•- . A-18
xxx
-------
ACKNOWLEDGMENT
1
I
I
I
This study and the preparation of this report has involved «
participation of professionals from Monsanto and independent •
consultants. Dr. Shib C. Chattoraj's work in developing this m
report is very much appreciated. The contributions of Dr. Arthur
D. Snyder and Mr. Duane R. Day are acknowledged. Also Mr. Robert H
N. Heistand provided valuable review comments. The liner study m
was performed by Denver Research Institute.
The project is deeply indebted to the EPA Project Officer,
Mr. Edward R. Bates for his continuing advice and guidance
during the course of this effort. ;
XXI1
1
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SECTION 1
INTRODUCTION
1.1 SOURCES AND VOLUMES OF SOLID WASTE, INCLUDING !
AN OVERVIEW OF THE OIL SHALE INDUSTRY j
1985 makes the start of the commercial U.S. oil shale industry
with the first commercial plant (Union Oil's 10,000 bbl/day Long
Ridge facility) coming on line. Many additional and often much
larger plants are scheduled to start production between 1987 and
1994 with many of the early plants being subsidized by jthe Federal
Government through the U.S. Synthetic Fuels Corp; (Tables 1.1-1
and 1.1-2). If only one half of the planned production comes on
line, it would eventually amount to approximately 600,000 barrels
per day of shale oil. Assuming an average shale grade of 30 gal/
ton and that 88% of the raw shale retorted will remain as spent
shale to be disposed, then about 740,000 tons/day or i270 million
tons per year of retorted oil shale, along with lesser quantities
of other solid wastes, will require environmentally safe disposal.
In addition to retorted oil shale other solid wastes produced will
include waste overburden, raw shale fines, shale oil coke, API
separator sludges, wastewater treatment sludges, elemental sulfur
or sulfur containing wastes from air pollution control equipment,
and spent catalysts which may contain highly toxic substances such
as arsenic. . ;
!
I
The types and quantities of solid wastes that will be produced
from proposed oil shale facilities are not well defiited at this
time. Detailed information prepared as supplements to' the Uintah
Basin Synfuel Development FEIS [BLM, 1983], lists the types and
quantities of solid wastes estimated for the Sand Wash and
Paraho-Ute projects [TOSCO, 1982; Paraho, 1982].
Although these projects are quite different in that they employ
different retorting technologies, mine different grades of shale
at different rates, produce differing amounts and types of final
products, and, at times, employ differing control technologies,
the rates of solid wastes can be compared when examined on a
common basis [Heistand, September 1984]. The common !bases used
are mined shale (tons of wastes per thousand tons of mined shale,
T/MT) and hydrotreated oil (tons of waste per million barrels
of., oil, T/MMBbl). i
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-------
Factors were determined on the basis of shale minied and oil
produced for sixteen solid wastes, grouped into two Categories,
as shown in Table 1.1-3 [Heistand, September 1984]. '
Using the factors presented in Table 1.1-3, it is possible to
calculate probable rates of various solid wastes produced based
upon projected mining rates and product oil production for the
above-ground oil shale retorting facilities. :
A surface retorting plant, such as a TOSCO II processing facility,
will be a source of large quanitities of plant wastes' which will
require disposal. Table 1.1-4 indicates the makeup of the waste
material that will be discarded .from a small TOSCO II plant over a
period of 20 years. !
1.2 POTENTIAL DANGERS TO HUMAN HEALTH AND THE ENVIRONMENT
FROM THE DISPOSAL AND REUSE OF THE WASTES i
Although oil shale facilities will produce huge volumes of solid
wastes, the potential for reuse of the wastes is small. Some
wastes such as spent catalysts could potentially be reclaimed and
recycled back into the process. Elemental sulfur, remojved by some
air pollution control technologies, has a limited market poten-
tial; however it remains to be demonstrated on a commercial scale
that there are no trace impurities that would constrain its use.
It is expected that hazardous wastes such as spent catalysts and
some sludges will be disposed in licensed hazardous wa|ste facili-
ties. However, one catalyst unique to shale oil upgrading is of
particular concern. The arsenic guard bed catalyst will contain
20% or more arsenic. No facilities exist to reprocess, this spent
catalyst and environmentally safe disposal may be difficult to
achieve. Other than the arsenic guard bed catalyst,: the major
unique dangers to health or the environment posed by oil shale
facilities may be from the long term effects of on site disposal
of millions of tons of retorted oil shale, raw oil shale waste,
and other process wastes. Principal concerns in thisiregard may
be summarized as follows: ;
1. A.uto oxidation/auto ignition may be a serious ;problem if
disposal of raw shale fines and/or carbonaceous spent shales
are not done in a manner to minimize this risk. !
i
2. High inorganic salt loading and possibly organics in leach-
ates from raw shale fines or spent shale could potentially
have significant impacts on groundwater supplies in the area
and on surface waters that supply millions of people (Color-
ado River). A related issue is to what extent should process
wastewaters be treated prior to codisposal with the retorted
shale. Codisposal of spent catalysts and treatment sludges
may also significantly impact the nature of leachates from
disposal sites. ]
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TABLE 1.1-3. APPROXIMATE SOLID WASTE RELATIONSHIPS
Type of waste
Mined shale
basis,
T/MT
Hydrotreated
oil basis,
T/MMBbl
Ma j or
Retorted shale
fRaw fines, dust, subore
Off-spec sulfur
Oily particles
WWT sludge
Scrap and garbage
834.5
784.4
58.8
1.3
0.49
0.14
0.10
Catalysts and other wastes
Methanator
Reformer
Hydro treater (HDN, HDS) •
Lo-temp CO shift
Alumina
DEA sludge '
API sep. btms. i
API float
Hi-temp CO shift (FeCr)
Arsenic guard bed 1
27.76
0.48
1.10
17.22
2.29
5.04
0.95
24.44
2.12
1.26
36.31
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aThese factors will give values which may range +100%
to -£
Based on solids content.
Source: Heistand, September 1984.
3. Infiltration of moisture into disposal sites from precipita-
tion or from surface or groundwater intrusion could lead to
sudden pile failure. Such failure could cause extensive
property damage, threaten lives, and contaminate the drinking
water supply for millions of people.
Auto-Oxidation/Auto-Ignition
Auto oxidation leading to auto ignition of some coals and coal
wastes has been known to be a problem for many years. Some coal
wastes piles in the east are believed to haye ignited in this
manner while the phenomenon is fairly common with western lignite
coals. Since raw oil shales and some retorted oil shales possess
carbonaceous material and are capable of being ignited, EPA has
recently conducted several tests to assess the potential for
auto-ignition of raw oil shale fines and retorted oil shales. The
results indicate that raw shale fines have a potential similar to
bituminous coals while retorted shales appear to be less reactive
(Table 1.2-1). Hence there is a potential that if oil shale
1
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TABLE 1.1-4.
MAJOR WASTE PRODUCED OVER A PERIOD OF
(TOSCO II 47,000 bbl/day plant with
20 YEARS
upgrading)
Stream description
Raw shale runoff and leachate
Raw shale sludge - preheat system
Processed shale sludge - ball elutriator
.Processed shale sludge - moisturizer
Processed shale
Stripped foul water
Compression condensate - Wellman-Lord Unit
Cokeb
Stripped sour water purge stream
Revegetation water
Dust suppression water
Boiler blowdown
Boiler feedwater treatment concentrate
Cooling tower blowdown
Storm runoff
Processed shale leachate
Spent catalysts
Treated sanitary water
Sanitary water treatment sludge
Service and fire water runoff
Source water clarifier sludge
Trash, construction debris, etc.
TOTAL
Mater
Quantity, as a
106 tons total ^
N.D.a
11.31
0.85
0.57
350.84
18.49
ial quantity
percent of
tfaste quantity
N.D.
2.27
0.17
0.11
70.43
3.71
1.73 0.35
5.26
1.06
0.75 0.15
14.59 2.93
9.70 1.95
11-04 2.22
4.81 0.97
60.31 12.11
4.34 0.87
N.D. N.D.
0.005 0.001
0.55 0.11
N.D. ' N.D.
0.63 0.13
2.37 0.48
N.D. ' N.D.
498.15 99.93
N.D. - Not determined. i
Most of the coke can be sold as a by-product. [
Source: EPA 600/8-83-003, April 1983 i
i
disposal sites are not properly designed they could iauto-ignite
producing huge quanities of pollutants such as S02, NQ , H2S, C02
and hydrocarbons. Such combustion could impair pile^ stability
leading to failure of the disposal pile and/or substantially
accelerate the leaching process. Since oil shale disposal sites
will occupy several square miles and be hundreds of feet thick,
there is no known method for extinguishing combustion should it
get started. Hence, the key to controlling ignition must be the
design and incorporation of appropriate controls when tlhe disposal
site is constructed. It appears probably that control1 technology
employed by the coal industry can be modified and applied to oil
shale disposal sites to mitigate this hazard. :
-------
TABLE 1.2-1. SUMMARY OF RESULTS FROM DIFFERENTIAL
DIFFERENTIAL SCANNING CALORIMETRY AND
NONADIABATIC OXYGEN ABSORPTION TESTING
-—e
Paraho Retorted Shale 300 480 0.27
TOSCO II Retorted Shale 306 560 1.4
Union Shale Mixture 321 860 4.6
Hytort Retorted Shale 357 1,340 3.8
I
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Onset, Exotherm, Nonadiabatic test
Materal °C J/g S index
Wyoming Subbituminous Coal 190 10,900 165 I
Western Kentucky #9 Bituminous Coal 193 13,800 60
Utah Raw Shale (66 GPT) 211 8,320 86 ™
C-a Raw Shale 226 920 5.6 A
Utah Raw Shale (28 GPT) 227 2,990 44
Pocahontas #3 Bituminous Coal 230 15,700 42 B
1
I
Lurgi Retorted Shale - M3 0.00 11
Lower onset temperature means more reactive. A
Higher S index means more reactive. ™
Test in dry air, particle size: -325 mesh. m
wo exotherm observed to 550°C. H
Source: EPA 600/2-84-153, 1984.
Leaching ||
The composition of retorted oil shales vary principally in re- —
sponse to the properties of the raw shale feed and the retorting B
process. The composition of any leachates from retorted shale *»
disposal sites will vary depending upon the properties of the re-
torted shale, and other wastes codiposed with the retorted shale, ||
such as wastewaters for cooling/wetting and treatment sludges. fl
Anticipated composition for Union B retorted shale is provided in
Table 1.2-2, process water for cooling and wetting the shale in an
Table 1.2-3, and properties of Unisulf solution, Unisulf sulfur •
byproduct, and moistened retorted shale are provided in Table
1.2-4. Some leaching test results on Union B retorted shale are
I
8
I
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TABLE 1.2-2. CHEMICAL PROPERTIES OF UNION B RETORTED SHALE
Components5 Weight, %
I
Major elements as oxides ;
SiO2 31.5 ;
CaO 19.6 :
MgO 5.7 |
A1203 6.9
i
Fe20 2.8 ;
Na20 2.2 !
K20 1.6 !
S03 1.9 |
i
P20§ • 0.4 |
Other properties '
Mineral CO2 22.9 |
i
Organic C 4.3 ;
Nitrogen, Kjeldahl 0.2 i
Free silica (quartz) 8.0 i
pH of slurry 8.7 '•
aAnalyses determined by heating sample to ;
950°C for pH measurement. Analyses by
Union Research Department. |
Source: Battelle PNL 3830, 1981 !
-------
TABLE 1.2-3. ESTIMATED3 COMPOSITION OF PROCESS WATER
FOR RETORTED SHALE COOLING/WETTING
Parameter
Alkalinity (as CaC03 )
Carbonate ( as CO3 )
Bicarbonate ( as HC03 )
Chemical oxygen demand
Total organic carbon
Total dissolved solids
Total solids
Hardness (as CaCO3 )
Ammonia
Sulfides (as H2S)
Phenols
Cyanide (CN) - [
Oil and grease
Sulfate
Sodium
Arsenic :
Chromium '•
pH units '
Reuse
water sump,
mg/L
2,000
400
1,700
5,500
1,350
2,600
3,100
900
35
100
125
20
1,300
500
1,500
6.5
0.5
8-10
aThese values are maximum design case
levels based on preliminary bench-scale
tests and engineering1 calculations.
Source: Union Oil Company,
10 ;
January 1984.
1
1
1
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TABLE 1.2-4.
RCRA TESTING OF SIMULATED SHALE
PLANT WASTES (UNION B PROCESS)
Unisulf
sulfur
Moistened
retorted shale
plus fines5
Ignitability
Causes fire through friction No
Oxidation 0°F
Corrosivity
a) pH
b) Steel corrosion (in/yr)
Reactivity
Yield gases, vapors or flames
when exposed to water No
Yields H2S or HCN when
exposed to pH 2 buffer No
Reacts explosively
a) When subjected to burner
flame No
b) When under heated
confinement No
HP Toxicity, mq/L
No
0°F
No
No
No
No
noistened with simulated process water.
Source: Union Oil Company, January 1984.
Maximum
allowed
12.5
0.25
Minimum
allowed
2.0
Arsenic
Barium
Cadmium
Lead
Mercury
Selenium
Silver
<0.01
0.2
<0.01
<0.05
0.002
<0.0005
<0.02
0.07
<2.7
<0.01
<0.05
<0.0005
<0.0005
<0.02
5.0
100.0
1.0
5.0
0.2
1.0
5.0
11
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TABLE
Compound
Ag
Al
As
B
Ba
Be
Ca
Cd
Cl
CN
Co
Cr
Cu
F
Fe
HC03
Hg
K
Li
Mg
Mn
Mo
Na
Ni
NH3-N
N03-N
Oil and grease
Pb
Phenols
PO4
Se
Si
SO4
Sr
IDS
TOG
Zn
pH, units
Source : Union
'
1.2-5. CHEMICAL COMPOSITION
FROM UNION
Union Oil
Company
1982c
<0.3 - 0.12
0.005 - 0.022
0.22 - 17.0
0.09 - 0.11
<0.05
46 - 460
<0.01 - 0.03
7 - 120
0.003 - 0.009
<0.03 - 0.05
0.003 - 0.012
<0.02 - 0.2
5.6 - 11.4
<0.5 - 6.5
92 - 257
<0.0005 - 0.001
4.6 - 48
0.1 - 0.6
29 - 1,400
0.2 - 6.7
0.8 - 4.0
11 - 4,800
<0.02 - 0.12
<1 - 4
<10 - 100
<2 - 5
0.05 - 0.5
<0.001 - 0.0086
<200
<0.005 - 0.018
1-4
115 - 19,100
1.1 - 7.6
327 - 25,000
0-31
0.04 - 0.26
7.5 - 7.9
B RETORTED
S teams -
Rogers
• 1976
'
! 0.066
' 8
0.03
• -
17
<0.02
210
<0.005
0.01
-
_
-
2,370
-
14
50
27
5,040
—
2.4
2.0
25
! <0.2
<0.005
—
—
-
7,090
—
16,000
240
-
7.6
OF LE ACHATES
SHALE
Cleave
et al.
1979
<0.009
<0.001
0.97
<0.078
-
243
0.016
7.0
-
<0.011
<0 . Oil
—
<0.025
172
-
7.4
58
<0.007
109
—
—
—
0.009
—
<0.001
-
878
—
1.518
11.3
0.025
8.33
(mg/L)
Woodward-
Clyde
1975
<0.009
<0.05 - 0.27
—
—
-
-
69 - 424
8-91
-
_
-
-
<0.05 - 20
4-32
-
3-85
5-55
mm
45 - 750
—
2-5
31 - 111
—
—
-
0.5 - 4
230 - 2,400
—
410 - 4,860
-
3.1 - 6.9
Oil Company, Januairy 1984.
12
!
1
I
1
I
1
1
1
1.
1
1
PPI
1
1
1
I"
f
1
-------
TABLE 1.2-6. RETORTED SHALE LEACHATES BY !
LEACHING METHOD (mg/L)
Shale
Paraho
TOSCO II
Lurgi
Paraho -
Several
Example
Source :
Parameter
pore volume
pH
EC ()jS/cm at 25°C)
HC03
C03
S04
Cl
F
Mg
Na
Ca
K
PH
EC (pS/cm at 25°C)
HC03
C03
S04
Cl
F
Mg
Na
Ca
K
PH
EC ((jS/cm at 25°C)
HC03
C03
S04
Cl
F
Mg
Na
Ca
K
0.198; TOSCO II - 1.03
Lurgi shales have been
provided is Lurgi shale
Field
9.57
21.100
-
-
12,350
526
11.9
7.7
5,591
421
834
8.9
10,000
-
-
30,270
-
13
156
10,270
463
110
_
-
-
-
-
-
-
-
-
-
~
; Lurgi -
RCRA
9.27
4,600
2,723
217
226
29
-
484
37
724
6.5
7.72
5,710
3,325
-
229
22
-
81
131
1,872
3.9
8.67
5,650
2,940
59
880
19
-
430
55
1,479
11
0.621.
ASTM
12.05
2,800
5
236
536
7
13.5
0.5
145
266
31
8.69
2,650
191
-
1,130
10
20.2
35
545
31
8
11.85
4,270
6.9
210
2,290
17
6.3
0.4
275
713
64
Column
initial
11.55!
9,230
15.3;
232|
3,840:
49 1
21:
1.6!
1,500
610;
140;
9.24^
35,080 ;
619 :
46 '
25,000
178 |
27 ,
628 ;
10,095 -
545 .
89 ;
12.24 i
59,500 ;
10.5 ;
775
34,000 ,
2,250 |
26.4 1
3.5 :
18,770 :
535 |
1,464 :
i
Column3
12.35
6,250
4.8
463
2,045
14
11.4
1.7
285
670
38
9.21
5,180
188
13
2,470
13
29.5
60
945
83
11
11.93
4,250
7
203
2,070
15
7.6
0.3
325
575
150
i
tested and results differ slightly.
provided by Rio Blanco Oil Shale.
EPA-600/D-84-036, March 1984.
13
i
i
f
i
-------
TABLE
Species
HC03
C03
TDS
F
Cl
P04
N03
S04
Zn
Fe
Co
Li
NH3
B
Cd
Be
Mg
P
Si
Mo
Mn
Ni
Na
Cu
Al
Ca
Ba
K
Cr
Sr
Pb
Ag
Se
As
Hg
1.2-7. RAW MINED
(MAXIMUM
Concentration ,
mg/L
579
5.68
72,660
113
366
0.28
2,564
45,900
0.597
2.02
1.17
0.339
2.55
1.97
0.168
0.300
12,830
7.0
13.2
1.5
2.34
1.12
2,030
0.073
5.28
505
0.822
16.4
0.290
15.4
1.036
0.012
0.007
0.013
0.007
0.003
i
OIL SHALES LEACHATES
OBSERVED CONCENTRATIONS )
Locationa
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
C-b, 20 ft
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
: C-a, 15 ft
C-b, 10 ft
C-a, 5 ft
C-b, 15 ft
C-a, 15 ft
C-b, 10 ft
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
C-b, 10 ft
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
; C-b, 10 ft
C-a, 5 ft
; C-a, 15 ft
! C-b, 10 ft
'• C-a, 15 ft
C-a, 15 ft
I C-a, 15 ft
; C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
C-a, 15 ft
C-b, 20 ft
C-b, 20 ft
Date
9/21/82
7/19/82
8/16/82
7/26/82
7/01/82
2/25/82
7/26/82
5/10/82
8/16/82
8/11/82
8/23/82
7/26/82
8/30/82
7/26/82
7/26/82
7/06/82
9/06/82
8/04/82
6/02/82
7/06/82
6/02/82
6/02/82
8/02/82
7/06/82
7/01/82
3/22/82
9/23/82
7/19/82
6/02/82
7/19/82
8/11/82
3/17/82
4/12/82
7/01/82
8/04/82
2/25/82
1
1
1
1
1
•
•1
.
•«r
a5, 10, 15, and 20 foot deep Lysimeters on Federal lease
tracts Ca and Cb.
Source: EPA-600/D-84-228, 1984.
14 i
1
I
f
1
-------
I
provided in Table 1.2-5 while results on several other retorted
shales (all without codisposed wastes) are presented in Table
1.2-6. Some raw mined oil shales have been leached (under field
conditions and the results are in Table 1.2-7. j
A significant volume of data such as that above exists.; This data
indicates that even if raw and retorted shale wastes are not de-
fined as hazardous, the leachates from these wastes are high in
dissolved salts as well as other contaminents and could seriously
impact surface or groundwater supplies, provided (Significant
amounts of leachate are produced. The amount of leachate produced
will depend to large extent on site specific characteristics and
the disposal controls employed. Since billions of tons of retort-
ed oil shale may eventially be produced, the cummulatiye impact on
water quality could be very great. Table 1.2-8 indicates the quan-
tity of some constituents leachable from oil shale pastes. As
previously discussed a 600,000 bbl/day oil shale industry would
produce about 270 million tons/per year of retorted Shale, which
would accumulate to nearly 8 billion tons after 30 years of opera-
tion. Such a quantity of waste will possess the potential for
leaching hugh quanitities of contaminents. For example assuming
8 billion tons of TOSCO II retorted shale, then 58 million tons of
sulfate are leachable along with 100 million tons of total dis-
solved solids and lessor amounts of many other contaminents._ The
key to preventing serious environmental impact does\ not lie in
preventing the leaching (since erosion of the disposal sites and
leaching will eventually occur) but rather in employing controls
to assure that the rate of release of contaminents is,slow enough
to be accomodated without substantial environmental damage. These
controls must be designed and built into the disposal sites from
the beginning since the huge size of the disposal sites will make
any retrofit operations extremely expensive and likely;impossible.
Mass Failure !
Retorted oil shale disposal sites will be the largest;solid waste
disposal sites ever constructed. A typical 50,000 bbl/day surface
retorting plant will produce about 450 million cubic feet/year of
solid waste, which over an operating plant life of 30;years would
cover an area of about 3.5 square miles to a depth Of 150 feet-
[EPA 600/2-80-205a, 1980]. Most disposals will be head of hollow
or cross canyon fills, miles in length and hundreds of feet deep.
Mass failure of one of these fills could have major impacts caus-
ing extensive property damage and threatening lives, j Failure of
one of several disposal piles proposed could destroy downstream
reservoirs, shale oil upgrading, storage, and loading; facilities,
and deposit millions of tons of leachable retorted shale in the
Colorado River. j
The most likely cause of a disposal pile failure would be satura-
tion of the waste pile and/or liquefaction of the ipile bottom
leading to slippage. Moisture contributing to this problem could
15
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come from codisposed wastewaters, precipitation and infiltration,
groundwater intrusion into the pile, or surface streams routed
over or through the disposal site. The principal approach to
prevent these problems is therefore to control the Movement of
moisture into or through the disposal pile. To accomplish this
requires the incorporation of a number of control technologies
into a complex site and material specific design. Although the
basic technologies to be employed are well known (i.;e., drains,
liners, covers, earth fill dams, benching) their construction on
the scale required and application to oil shale wastes have never
been demonstrated. I
i
1.3 PRESENT/PROPOSED DISPOSAL APPROACHES I
Due to the high volumes of solid wastes produced by all oil shale
facility, the environmentally safe disposal of these jwastes must
be engineered on a site and process specific basis. The slate of
solid wastes to be disposed and their chemical nature will vary in
response to the nature of the raw shale feed, the particular re-
torting process employed, the specific plant design including pol-
lution control technologies, and whether raw shale oil as upgraded
on site. The design of the solid waste disposal site! as well as
the selection and application of appropriate control technologies
must be tailored to accomodate not only the quantities and nature
of the wastes but also the characteristics of the specific dis-
posal site. Alternative disposal practices and contrdl technolo-
gies are generally well known. All have been proposed or consid-
ered by one developer or another though no developer has yet pro-
posed a plan incorporating all the control features that might be
desired into a specific design for solid waste disposal.
Disposal Approaches '
t-A |
!
The following discussion applies to the basic methods for handling
solid wastes produced by a surface retorting process. The key
features of each approach are summarized in Table 1.3-1. A
discussion of the control technologies applicable1 to these
disposal alternatives is presented. |
Landfills
A landfill basically entails placing the waste material as a com-
pacted fill in a suitable location. The wastes from the process-
ing facility are transported to the disposal site by conveyors or
trucks and then hauled to the active portion of the landfill.
Preferably, the solid wastes are then laid down in lifts of 9-18
inches and compacted to a suitable in-place denisity. The
compacted fill may be built with a proper slope to i a vertical
height of 40-50 feet and then flattened, or benched, to provide a
passageway for the disposal equipment and to facilitate runoff
collection. The overall landfill can be constructed gradually in
this fashion, using a multiple-bench arrangement. '<
17
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Depending upon the geography of the disposal site, the landfill
may be built on a level or nearly level surface, in the head of a
valley, or across a valley. The applicable control technologies
will vary somewhat with site topography but still will jbe designed
to protect the surface and subsurface waters. Applicable control
technologies include runon and runoff catchment ponds, 'embankments
and diversion systems, liners and cover, and revegetation. Provi-
sion for structural stability of the fill is also a major
consideration. !
I
A surface landfill of some type will need to be included in most
oil shale developments. This results from the shale undergoing a
volume expansion upon mining, crushing, and processing,1 which pre-
cludes all of the shale being returned to the mine. j
Underground Mine Backfill ;
11 * • ' • " _ i
In this disposal approach, the waste material is placed in the in-
active portion of the underground mine (e.g., a room-and-pillar
mine), while production continues in other parts of the mine. This
approach is attractive from several viewpoints. By returning
the wastes to the mine, the size of a surface landfill would be
greatly reduced. The potential for mine subsidence would be di-
minished. Backfilling the mine may enhance resource recovery by
increasing the amount of shale that can be mined safely. Disad-
vantages include possible release of volatiles underground in the
workplace and possible groundwater contamination. j
The major considerations in backfilling involve developing logis-
tics for carrying out simultaneous mining and disposal operations
while providing protection for workers and the groundwater. For
fine processed shales, like the TOSCO II, hydraulic or slurry
backfilling may be practical. However, additional water, above
the moistening needs, would be required and a drainage collection
system would be needed. The wastes may be transported :to the mine
by conveyors or trucks, then compacted in place, but the space
limitations reduce the practicability of this approach. Alterna-
tively, the wastes may be backfilled pneumatically, but this ap-
proach may be difficult to implement at the scale required.
A study on the above backfilling techniques has been conducted for
the wastes from the Colony project [Dravo Corp., 1975]. The re-
sults indicate that, while theoretically 80% of the wastes could
be returned to the mine, only 60% of the wastes can 'actually be
placed in the mine during the project life due to a time lag of
5-10 years between the mining and backfilling operations. It was
concluded that none of the placement techniques wer^ developed
sufficiently to be applied on a large scale.
19
-------
I
Impacts of Disposal Alternatives gn the Use of Oil Shale and •
Other Natural Resources
t'
proaucea oy an on snaie lacinty, these wastes must be disposed
on or close to the plant site. In the case of open pit mines, m
such as the one proposed for federal lease tract Ca, huge amounts B
of overburden and subgrade oil shale will also require disposal. 9
These wastes could be disposed entirely on the surface as piles or
canyon fills or could partially be returned to the mine. Either B
way the leaching potential of these wastes must be carefully con- m
trolled or leachates will seriously impair the quality and use of
surface and groundwater supplies. Depending upon the specific «
placement of these wastes they could also impair future access to V
other oil shale resources. Returning some of the retorted oil
shale to an underground mine would be expensive and technically
difficult but could actually increase the potential for resource JB
recovery by facilitating mining of the support pillars. "
Potential Utilization of Oil Shale Solid Waste •
Oil shale solid wastes having some potential for utilization in-
elude retorted oil shale, raw shale fines, spent catalysts, ele- m
mental sulfur and biological treatment sludges. Retorted oil U
shales, particularly decarbonized shales, have some limited poten- *
tial for utilization on site. Decarbonized western oil shales
posses a significant capacity to cement similar to low grade com- fft
mercial cement. Hence a very limited amount of retorted shale may V
be used locally as a low grade cement substitute. Raw shale
rejects and fines, from mining and raw shale preparation, could be m
processed in specially designed retorts or possibly formed into I
bricketts and processed in the regular plant facilities. Spent
catalysts could potentially be reclaimed and reused in the upgrad- m
ing process, though facilities to reclaim them do not presently •
exist. Some air pollution control technologies remove elemental "*
sulfur which, if not contaminated by impurities, should have at
least a limited market for agricultural use. Biological treatment A
sludges may be useful on site as soil conditioners for m
revegetation if they do not contain significant quantities of harmful
contaminents. However, even if all the above wastes are utilized at
to the maximum extent possible, it will not make a significant •
impact on the amount of solid waste to be disposed. ~
20 :
I
1
I
I
-------
1.4 CONCLUSIONS AND ADDITIONAL RESEARCH NEEDED i
i
i
Conclusions '
1. The oil shale industry will produce unprecedented volumes of
solid waste mostly consisting of retorted oil shales, raw oil
shale fines, overburden and subgrade ore, codisppsed waste-
water, and much smaller quantities of known hazardous wastes.
Although the known hazardous wastes will be sent 'to licensed
disposal or recycling facilities, the high volume solid wastes
will be disposed on or close to the plant site. If not prop-
erly managed these high volume wastes are capable of producing
leachates that could contaminate the water supply for millions
of people. Some of the waste may also pose the hazard of auto
ignition unless proper controls are employed. Surface disposal
sites covering square miles in area and hundreds; of feet in
thickness would do extensive property damage and threaten lives
should they ever suffer sudden mass failure. j
2. Control technologies to prevent serious adverse impacts from
disposal of billion of tons of oil shale wastes have been
proposed but their application to oil shale waste materials
and on the scale required has not been demonstrated. Further,
to be effective, these technologies, must be applied in highly
technical and integrated disposal designs that are site and
process specific. There is no current experience in disposal
of wastes of similar composition or of volumes 'approaching
that which will result from the oil shale industry.!
Additional Research Needed |
a. Solid wastes (including codisposed wastewaters) from oil
shale facilities need to be characterized.
I
b. The effects from codisposal of liquid and solid wastes
need to be determined. Related question is to what ex-
tent should wastewater be treated prior to i codisposal
with retorted shale. , i
c. Effective means of controlling moisture movemejit into and
from retorted shale disposal site to achieve mass
stability and minimize leachate need to be developed and
demonstrated. Included are liners and covers made from
retorted shale, drains installed above and below liners,
use of vegetation to reduce infiltration, arid means of
relocating surface drainage in filled canyons.;
d. The nature and quantity of leachate produced from dis-
posal sites employing state-of-the-art technology needs
to be determined.
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e. A best management practices design manual needs to be m
developed to guide developers and permitters in the
selection of appropriate control technologies and the W
integration of these technologies into complex site and m
process specific disposal designs.
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SECTION 2
CHARACTERISTICS OF U.S. OIL SHALE
2.1 INTRODUCTION
This section describes the location, geology,
the physicochemical properties of oil shale
United States.
resources
Oil shale is commonly defined as a fine-grained
containing organic matter (known as kerogen) that is
insoluble in petroleum solvents, but that yields
quantities of liquid oil, gases, and residual
pyrolysis [Culbertson et al., 1973].
2.2 LOCATION
composition
, and
in the
sedimentary
rock
essentially
substantial
carbon upon
The principal United States oil shale deposits are presented in
Figure 2.2-1 [Duncan et al., 1965]. These deposits occur in four
general locations; (a) the Tertiary period (Eocene) deposits of
the Green River Formation in Colorado, Utah, and Wyoming; (b) the
late Devonian and early Mississippian period marine shales of the
central and eastern United States, stretching from Michigan and
Pennsylvania southward through Indiana and Kentucky to Texas;
(c) the early Cretaceous and upper Triassic marine, shales in
Alaska; and (d) the small Tertiary shale deposits £>f Montana,
Nevada, Idaho, and California [EPA-600/2-80-205a, 1980].
It has been estimated that an equivalent of seven trillion barrels
(bbl) of oil are contained in the U.S. reserves of shale oil, but
not all of these deposits are sufficiently rich in organic matter
to be considered commercially attractive. Estimates place total
known U.S. oil shale resources for oil shales yielding 10 gal of
oil per ton of shale at well over 2 trillion bbl [Duncan et al.,
1965]. The Green River Formation oil shales in Colorado, Utah,
and Wyoming account for an estimated 90 percent of \ this total
resource and are therefore regarded as being the most important
commercially. I
The Devonian Marine black shales of the central and eastern United
States are estimated to contain at least 400 billion bbl of equiva-
lent oil. While they have not received as much commercial interest
as the Green River Shales, there are commercial projects proposed
23
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EXPl.ANATION
Tertiary d»ponltn
<3repn River Formation
In Colorado, Utah, and
Wyomuiu; Monlen>y
Formation, California;
middle Torllary deposits
In Montana. Black srean
are known high-grade de-
posit.-!
Mer.oswlc deposits
Marine shale In Alaska
Permian deposits
J'hosphorla Formation,
Montana
Devonian and Mls.sln.slpplan
df>pi)nlts (resource ontl-
mati>s Included for
hanli'trod areas only).
Boundary dashed where
concealed or where
location Is uncertain
Figure 2.2-1. Principal United States Oil Shale Deposits.
Source: Duncan et al., 1965
for their development. The Institute of Gas Technology has demon-
strated that retorting in the presence of hydrogen (hydroretortina)
can increase the oil yield of the Eastern Devonian Shales, by a
?*£ °f 2'-5 CTarman et al- 1967]. The Alaskan marine shales
anj. .the Tertiary shales of California and elsewhere have received
iF~ attention to date and are not considered to be commercially
attractive. J
2-2.1 Green River Formation Oil Shale
As shown in Figure 2.2-2, the oil shale deposits of the Green
River Formation occur in a 16/988 mi2 area in northwestern
Colorado, northeastern Utah, and southwestern Wyoming. The richer
oil shales, those of highest commercial interest, are generally
more centrally located in the four depositional basins: Piceance
Creek basin, Colorado; Uinta basin, Utah; and the Green River and
Washakie basins of Wyoming. The Piceance Creek basin of Colorado
contains the thickest and richest; oil shale deposits within the
United States, and accordingly, the greatest interest related to
commercial development has been directed to that area.
Table 2.2-1 presents the total in-place shale oil resources of the
Green River Formation. Total identified shale oil resources in
place, which average 15 gal/ton or more in strata up to 2,000 ft
thick, are estimated to be 179 billion tons in Colorado's Piceance
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COLORADO
Area of 25 gal. /Ion or richer
oil shole 10 ft or more thick
MESA
GRAND MESA
KEY,MAP
>•—«T WYOMING""!
Area of
Map
I !
UT«H I COLORADO 1_
25 i 50
SCALE, MILES
100
Figure 2.2-2. Green River Formation Oil Shales-Utah,1 Colorado,
and Wyoming. Source: Baughman, 1978 I
TABLE 2.2-1. TOTAL IN-PLACE SHALE OIL RESOURCES
OF THE GREEN RIVER FORMATION
Type of shale (yield/ tonne)
62.6 L/ tonne
(15 gal/ ton)
or more
Location
Colorado
Utah
Wyoming
TOTAL
Billions
of
tonnes
163.2
43.7
43.7
250.6
Billions
of
equivalent
barrels
of oil
1,200
321
321
1,842
104. 3. L/ tonne
(25 gal/ton)
or more
Billions
of
tonnes
82.6
8.7
8.2
99.5
Billions
of
equivalent
barrels
of oil
607
64
60
731
125.2 L/ tonne
(30 gal/ ton)
lor more
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Billions
of
tonnes
48.3 i
6.8 :
1.8 i
56.9 i
i
Billions
of
equivalent
barrles
of oil
355
50
13
418
In beds at least 10 ft thick.
Source: Ash, 1964.
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Creek Basin, 48 billion tons in Utah's Uinta Basin, and 48 billion T
tons in the combined Green River, Washakie, and Sand Wash basins
of Wyoming. The three-state total is thus 1,842 billion bbl. The jt
total in-place resource is not presently recoverable, but it is •
estimated by the U.S. Geological Survey (USGS) that approximately
80 percent of the known shale that yields 25 gal/ton or more, or •
some 88 billion tons of shale oil are suitably located and of I
adequate thickness to be reasonably regarded as the potentially
recoverable resource base. If 50 percent of the 25 gal/ton or m
more resource could be recovered, it would be large enough to •
produce 2 million bbl/day, or over one-fourth the present daily *
imports, for more than 400 years. Table 2.2-1 shows that 80 to 85
percent of the in-place, 25- to 30-gal/ton oil shale resource are •
in Colorado's Piceance Creek Basin, with the remainder divided |
between Utah's Uinta Basin and Wyoming.
2.2.2 Devonian-Mississippian Black Shales n
The black marine shales of the Deyonian/Mississippian periods are
located in the Eastern and Central States. These shales, part of •
an original shallow inland sea, occur over an area of more than B
400,000 mi2 in Ohio, Kentucky,; Tennessee, Indiana, Michigan,
Alabama, and extend as far southwest as Oklahoma and Texas. As •
shown in Figure 2.2-3 black shale deposits also occur in the I
northern great plains and extend into Canada.
The Devonian shales are lean by western shale standards, with an I
average Fisher assay of only 10 gal/ton; however, the carbon con- *
tent of Devonian shales is typically about 14 percent, or approxi-
mately the same as Green River shale assaying 30 gal/ton. The ft
difference in Fischer assay is due to the higher carbon to avail- m
able hydrogen weight ratio of thei10 gal/ton Devonian shale (11-2
to 1) as compared with the 30 gal/ton Green River shale (7.2 to f»
1). If, however, the 10 gal/ton Devonian shale is retorted in the •
presence of hydrogen (i.e., hydroretorted), oil yield can be
increased to 25 gal/ton, according to research conducted by the _>
Institute of Gas Technology (IGT) [Tarman et al., 1977]. •
The higher oil yields possible with hydroretorting can, of course,
have an influence on defining the Devonian shale resource base. fl
The USGS estimate of equivalent oil in place in Devonian shales is 9
400 billion bbl, without considering the effect of hydrogen in
retorting. With hydroretorting, this value could easily increase »
to 1 trillion bbl, or 250 percent of the conventional Fischer •
assay. •
The Institute of Gas Technology has surveyed the three-principal tf
Devonian shale basins (Appalachian, Illinois, and Michigan) and p
estimated that some 423 billion bbl of oil could be recovered from
the 6,200 mi2 of outcrops and relatively shallow deposits in these m
basins alone if hydroretorting were employed. Their criteria for jj
a recoverable resource required that a shale deposit have an
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Figure 2.2-3.
Distribution of Upper Devonian and Lower
Mississippian Black Shales in the Eastern
United States. Source: Baughman, 1978
organic content of more than 10 percent by weight, a unit rock
thickness of at least 10 ft, an overburden thickness oJF less than
200 ft, and a stripping ratio of less than 2.5 to 1. i The study
assumed hydroretprting yields of 85 percent of the organic carbon
present, and strip mining at 90 percent recovery of in-place shale.
2.2.3 Other Shale Deposits , ,
i
Among other U.S. shale deposits are the thin strata of carbona-
ceous shales associated with coal beds, particularly iti the Appa-
lachian coal region. It is estimated that perhaps 60 billion bbl
of equivalent oil may be present there in high grade shales assay-
ing from 25 to 100 gal/ton. In California, the Mioqene marine
shales are believed to constitute a 70-billion bbl resource in
shales varying from 5 to 25 gal/ton. In southwestern Montana,
beds of Permian black shale, ranging from 5 to 15 gal/ton, may
total up to 10 billion bbl of equivalent oil in place. As with the
Appalachian coal shales, however, neither the Alaskan, California,
nor the Montana shale are considered to be of near-term:commercial
importance [Duncan et al., 1965]. :
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2.3 GEOLOGY
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The geology of United States oil shales varies with the location fl
of each occurrence. The geologic factors which are similar from ™
deposit to deposit are related to the modes of origin for oil
shales. The origin of oil shale involved the deposition of organ- H
ic remains from quiescent organic-rich waters. The maintenance of H
reducing conditions during and after deposition and before indur-
ation was required to prevent oxidation of deposited organic mat- _.
ter. The similarities in geology appear to end at this point, as I
evidenced by the wide differences in the mineralogical composition *•
of the inorganic fraction of oil shale and the variance of the
properties of kerogen (altered organic material) from deposit to •
deposit. |
Oil shale interest to date has concentrated on the Green River •
Formation deposits and more recently the Devonian-Mississippian I
black shale deposits. For this reason, discussions of the geology ^
of these two major deposits are presented.
2.3.1 Green River Formation •
The Green River Formation oil shales were deposited 50 to 60 mil- •
lion years ago in two large Eocene-age lakes. Lake Uinta occupied H
the northwest part of Colorado and the northeast part of Utah.
Lake Gosiute occupied the southwest portion of Wyoming. During «
different periods of deposition of the Green River Formation the •
two lakes were probably connected in the area of northwest Colo- m
rado and southwest Wyoming near the east end of the Uinta Mountain
Uplift. ; M
Located within each of these ancifent lake complexes were individ-
ual depositional basins. Fluctuations in lake levels caused by m
tectonic and climatic changes resulted in alternating deposition g
of oil shales, saline minerals, fluvial sediments, fresh water
facies, and mud-flat type deposits. Figure 2.2-2, discussed u
previously, shows the individual depositonal basins. The thicker, 9
richer oil shales are generally located at the depositional ™
centers of these basins.
2.3.1.1 Piceance Creek Basin, Colorado p
The Piceance Creek basin is a large asymmetric structural downwarp «
[Doimell, 1961]. The axis of the basin trends northwest to south- •
west with the western and southern flanks gently sloping into the
basin. The northern and eastern flanks slope much more steeply
into the basin. The basin is bordered on the northwest and north •
by the Rangely-Skull Creek-White River anticlinal trends; on the m
east by the White River Uplift; on the southeast and south by the
Elk and West Elk Mountains and Gunnison Uplift; and along the west
by the Douglas Creek arch [Murray et al., 1964]. Numerous small
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anticlines and synclines are found within the basin; faulting
(graben) systems are associated with some of the more pronounced
structural trends. I
Strata exposed in and around the margins of the basin range in age
from late Cretaceous to early Tertiary [Donnell, 1961]. The
oldest rocks are the late Cretaceous Mesaverde Group which is
composed of sandstones, shales, and some coal beds. Fossil content
indicates that deposition occurred near standlinesj in fresh,
brackish, and marine environments. The Mesaverde j rocks are
generally more resistant to erosion and form a series of prominent
benches which outcrop continuously around the southern ;and eastern
margin of the basin. Overlying the late Cretaceous is the Paleocene
series consisting of the Ohio Creek Conglomerate and; an unnamed
unit, composed of feldspathic sandstones, shales, and thin coal
beds, which is considered a Fort Union Formation equivalent. The
Wasatch Formation of early Eocene overlies the Paleocene rocks and
consists of thick sequences of lenticular sandstones and vari-
colored shales with some coal beds. Fossil evidencfe indicates
that) the Wasatch was deposited in a terrestrial fluvial environ-
ment,. The Wasatch Formation, being less resistive to erosion than
overlying and underlying strata, forms lowland areas between the
cuestas of the more resistive adjacent rocks. The Green Riyer
Formation, containing the oil shales of the Piceance Greek basin,
is generally thought of as overlying the Wasatch Formation. How-
ever,, upper tongues of the Wasatch Formation are time equivalent
to some Green River depositional sequences which represents either
fluyial depositional encroachment into the lacustrine !Green River
environment or regression of the Green River lacustrine environ-
ment,. Similarly, the fluvial (stream-bed) Uinta Formation inter-
tongues, but generally overlies, the lacustrine j (lake-bed)
deposits of the Green River Formation. The Green River Formation
in Piceance Creek basin has been divided into three main members
based on lithology, but locally a fourth clastic facies is present.
Each of the members is discussed in ascending order with emphasis
on the Parachute Creek Member, the main oil shale be'aring unit.
The Douglas Creek Member, basal member of the Green River Forma-
tion,, is composed of sandstones, shales, and limestones that con-
formably overlie the varicolored shale and sandstone units of the
Wasatch Formation. This member has been recognized only in the
southern, western, and central parts of the basin. Injthe eastern
part of the basin, aclastic facies replaces the Douglas Creek Mem-
ber. To the northwest, the Douglas Creek Member coalesces with
shales of the overlying Garden Gulch Member. Resistant strata of
the Douglas Creek Member form a series of light brpwn benches
along the base of the Green River Formation escarpmentJ
The Garden Gulch Member, overlying the Douglas Creek Member along
the basin margins, is composed of dark, finely laminated illite
shales and marlstone, some of which contain kerogen. With the ex-
ception of the eastern part of the basin, where equivalent sandy
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Garden Gulch outcrops as gray steep slopes between the white
cliffs of the Parachute Creek Member and the brown and buff {•
benches of the Douglas Creek Member. ffl
Problems with the correlation of the Garden Gulch and Douglas «
Creek Members, as they were previously described at type sections M
on the flank of the basin, to central basin deposits as they "
are presently mapped has been discussed [Roehler, 1974]. The
two members at the type sections have been described as being •
"...largely chronologic and lithologic equivalents." Others do •
not differentiate the two members because they are partly time-
equivalent. The thickness of the Garden Gulch-Douglas Creek •
(undifferentiated fresh water unit) in the more central portion •
of the basin is reported to be at least 1,000 feet. Two easily
discernible geologic markers in the subsurface, found on resis- _
tivity logs, exist in the vicinity of the Garden Gulch-Douglas •
Creek unit. Both markers exhibit an extremely low resistivity. P
The uppermost marker, the Blue marker, is considered the contact
between the clay (illite) shales of the Garden Gulch and the •
dolomitic marlstones of the overlying Parachute Creek Member. I
The lowermost marker, the Orange marker, has been described by
some as the contact between the Garden Gulch and Douglas Creek m
Members [Roehler, 1974]. •
A clastic facies equivalent to the Douglas Creek, Garden Gulch,
and( lower portion of Parachute Creek Members are assigned to the •
Anvil Points Member. This member is composed of sandstones, •
shales, marlstones, siltstones, and limestones. The Anvil Points
Member has been described along outcrops from the Parachute Creek •
valley around the eastern rim, to a little north of the headwaters 1
of Piceance Creek. The absence of the Anvil Points Member in the
Piceance Creek gas field indicates that the member is confined to H
the southeast and eastern parts of the basin. The maximum known B
thickness is 1,870 feet in the upper Piceance Creek area. The An- *
vil Points Member appears as a series of benches and cliffs below
the cliffs of the Parachute Creek Member. It interfingers with •
the overlying Parachute Creek Member and the underlying Wasatch I
Formation with both the upper and lower contacts conformable and
gradational. «
The Parachute Creek Member which overlies the Douglas Creek-Garden
Gulch_unit is of most interest because it contains the majority of _
the oil shale resources in the Piceance Creek basin. Although the I
term oil shale is used extensively, the lithology generally con- •
sists of kerogenetic dolomitic marlstone and differs considerably
from the true illite shales of the!underlying Garden Gulch Member. •
Weathering of the resistant Parachute Creek Member has produced p
precipitous and often spectacular1 escarpments around the rim of
the basin. The thickness of the Parachute Creek Member varies «
from over 2,000 feet in the north central part of the basin to I
about 500 feet along the margins. ' *
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The most consistently rich and laterally persistent oil! shale zone
in the basin is designated the Mahogany ledge on putcrop and
Mahogany zone in the subsurface [Bradley, 1931]. Figiire 2.3-1, a
schematic cross section, shows the relative position of the
Mahogany zone as well as other members and zones within the Green
River Formation. The very resistant-to-weathering nature of the
Mahogany zone is due to its high kerogen content and! results in
vertical to near-vertical outcrops. The Mahogany zone is bounded
on the top and bottom by relatively thin barren zones' termed the
'A' and 'B' grooves, respectively. These barren zones are less
resistant to erosion, forming slopes on outcrops that resemble
grooves, hence their designation. In the subsurface both the 'A'
and ''B' grooves produce distinct lows on resistivity >. logs. The
thickness of the Mahogany zone ranges from approximately 100 feet
near the margins of the basin to about 200 feet in the north cen-
tral part of the basin. Generally, the grade of oil shale in the
Mahogany zone exceeds 20 gallons per ton with the richest sequence
comprising approximately 130 feet of 30 gallon per [ton shale.
I
Above the Mahogany zone there generally is 300 to 500 feet of
leaner oil shale. This sequence is thickest in the southern part
of the basin. Due to interfingering with the overlying Unita
Formation in the northern part of the basin, the upper sequence
thins to less than 300 feet. !
A sequence of oil shale below the Mahogany zone extends from the
top of the Blue marker to the base of the 'B1 groove. In the
southeastern part of the basin this lower oil shale sequence is
interfingered with, and in some instances replaced by; the Anvil
Points Member. In the extreme northwest part of the basin the
lower oil shale sequence is absent and the Mahogany zone and over-
lying oil shale rests conformably on the Garden Gulch Member
(Donnell, 1961). Elsewhere, the thickness of the lower oil shale
sequence ranges from a minimum of 20 feet in the southwest to over
1,300 feet in the north-central part of the basin. iToward the
central portion of the basin the lower sequence ofj oil shale
thickens due to the increased lacustrine type deposition,
resulting in significant accumulations of dolomitic marlstones,
organic material, and saline minerals. The saline' minerals,
depending on the particular mineral, have been fotmd finely
disseminated within the oil shale, as individual spherical crystal
growths or rosettes and as bedded layers and zones. j
The lower oil shale zone was subdivided into a series of alternat-
ing lean and rich zones [Cashion and Donnell, 1974] j The rich
zones were designated R-4, R-5, R-6, etc. This designation and
correlation was based on oil shale grade from the Modified Fischer
Assay or apparent grade from geophysical logs. The^ lower oil
shale sequence can also be subdivided into two zones, leached and
unleached, on the basis of removal by dissolution or leaching of
saline minerals, mainly consisting of minerals such as nahcolite
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»ooo'-
•000'-
700O%-
6000 -
5000'-
4000'-
3OOO'-
SOUTH
A1
9000'
Greovt
Groovt
- 8000'
GRE EN RIVER
F )RMATION
- TOOO'
GREEN f
RIVER <
FORMATION L
Wbsotch
Formation
- 6000'
- 5000'
- 4000
L 3000
Figure 2.3-1. Schematic North-South Cross Section of Piceance
Creek Showing Relationship of Oil Shale Bearing
Members of the Green River Formation and
Surrounding Strata.
Source: Baughman, 1978
and halite in the upper portions of the-saline section. Although
leaching is not confined to any one area of the basin, the effects
of leaching are most pronounced in the central part of the basin
where there was maximum saline deposition. An unleached or saline
zone is found below the leached zone in the central portion of the
basin. This zone contains potentially recoverable deposits of
nahcolite and dawsonite. From these two minerals, soda ash and
alumina can be produced. The thickness of the unleached saline
zone in the central part of the basin ranges from about 500 to
over 1,000 feet.
The interface of the leached and unleached zone, somewhat poorly
defined, is termed the dissolution surface. In reality, it is
probably a dissolution zone, as numerous cores have shown nahco-
lite to be present above the dissolution surface while vugs and
cavities are found below. At best, any designated dissolution
surface is an approximation.
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The leached zone is characterized by cavities, vugs, and collapsed
breccia. The thickness of the leached zone toward the central
part of the basin varies from about 400 to 1,100 feet. Leached
zone thickness is greater around the margins of the major saline
deposition. Leaching of the saline minerals has upgraded the oil
shale value within the leached zone by removing inorganic saline
minerals which would have had the effect of diluting the percent-
age of organic material. Leaching has also produced higher po-
rosity and permeability by removing evaporites thus producing an
aquifer while reducing bulk strength of the rock. j
Overlying the Green River Formation is the Uinta Formation, which
includes sandstones and siltstones which were formerly designated
as the Evacuation Creek Member of the Green River Formation. With
the exception of a few local unconformities described by Donnell
(1961), these formations represent a continuous depositional
sequence. The outcrop of the Uinta Formation forms! a buff to
rusty brown colored rounded cap receding from the white cliffs of
the Parachute Creek Member. :
The maximum thickness of the Uinta Formation is unknown because
the top has been removed by erosion; however, from: subsurface
information, it is known to exceed 1,200 feet. Because of inter-
tonguing with the Parachute Creek Member, the lower boundary
varies from location to location. i
2.3.1.2 Uinta Basin, Utah ;
The Uinta basin is sharply asymmetrical, the axis of which lies in
the northern portion of the basin trending east-west and parallel
to the Uinta Mountain uplift which borders the basin to the north
The Wasatch Mountains border the basin to the west and the Douglas
Creek Arch borders the basin on the East. The southern flank of
the basin is bordered by the San Rafael Swell, the Salt Creek
Anticline, and the Uncomphagre Uplift. Over 13,000 feet of sedi-
ments were deposited in the basin center during the Epcene time.
Eocene strata of the Uinta basin belong to the Wasatch Green
River, and Uinta Formations, consisting of rocks deposited in
fluvial and lacustrine type environments. The thickest and
richest oil shales of the Uinta basin are found in the east
central portion of the basin, as indicated on Figure 2.3-2.
The Wasatch Formation, the basal Eocene strata, is composed of
fluvial sandstones, shales, mudstones, and siltstones. The
Wasatch rocks vary in color from red and purple to browns and
light grays. The formation is divided into two parts, the main
body of the Wasatch and the Renegade tongue which intertongue with
the overlying Green River Formation.
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The Green River Formation is divided into three members in the
Uinta basin: the basal Douglas Creek Member; and the overlying
Garden Gulch Member, and the uppermost Parachute Creek Member.
Figure 2.3-2 is a schematic cross section illustrating the Eocene
stratigraphy of the Uinta basin. ;
Index
Map
V'//////:,-'//.'.-/.Uinta format ion •/;/////////'.y'-V/V.;=b^==7?ciastic •'" •="-
Mahogany Zone
Lacustrine Facies
Green River Formation
Clastic Facies
Green River Formation
Figure 2.3-2.
Schematic Cross Section of Uinta Basin Showing
Relationship of Oil Shale Bearing Green River
Formation With Surrounding Strata.
Source: Baughman, 1978
The Douglas Creek Member is compqsed of shale, siltstone, sand-
stone, and oolitic, algal, and ostracodal limestones. Locally,
the Douglas Creek Member contains a few oil shale beds. The
member conformably intertongues with fluvial sediments of the
Wasatch Renegade Member. The maximum thickness of the member is
1,180 feet [Cashion, 1967].
The Garden Gulch Member outcrop is distinctly different from the
Douglas Creek Member outcrop, a$ the Garden Gulch forms gray
slopes which contrast with the brown ledge-forming sediments of
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the Douglas Creek" Member. The member is chiefly fcomposed of
marlstones, oil shales, and siltstones. The Garden Gulch Member
is thickest along the eastern outcrop of the Green River Formation
of the Uinta basin/ Westerly, the Garden Gulch thickens, while
the overlying Parachute Creek and underlying Douglas Creek members
thicken basinward. The maximum thickness of the Garden Gulch
Member is 230 feet [Cashion, 1967]. ;
The Parachute Creek Member of the Green River Formation contains
the oil shales of significant interest in the Uinta ^basin. The
member is composed mostly of kerogenetic marlstone (:oil shale),
barren marlstone, sandstone, siltstone, and tuff. The oil shales
are for the most part finely laminated or varved. Individual beds
within the Parachute Creek Member are well known for their lateral
extent and relative continuity. Many of the mappable units of the
Piceance Creek basin oil shales are also recognized and mappable
in the Uinta basin. The thickest and richest sequence of oil
shale in the Uinta basin is found in the laterally persistent Ma-
hogany ledge, termed Mahogany zone in the subsurface.! Oil shale
also exists above and below the Mahogany zone, but is somewhat
leaner in grade. The maximum thickness of the Mahogany zone in
Utah is about 100 feet. The Parachute Creek Member is about 750
feet thick in the east central portion of the basin but thickens
to the north and west toward the synclinal axis of1 the basin.
Evidence of a saline zone exists in the upper one-third of the
member, where crystal cavities thought to have once contained the
mineral nahcolite have been observed. The leaching of the nahco-
lite by groundwater has given the appearance on verticjal outcrops
that swallows have nested there, thus giving rise to the name
"birds nest zone" [Cashion, 1967]. The upper section of the
Parachute Creek Member containing the "birds nest zone'" was named
Evacuation Creek Member [Bradley, 1931 and Cashion, 1967]. How-
ever, the nomenclature has since been revised to place those
sediments within the Parachute Creek Member [Cashion et al.,
1974]. The lacustrine sediments of the Parachute Creek member
intertongue with the overlying fluvial sediments of the Uinta
Formation. ;
Overlying the Green River Formation is the Uinta Formation, which
consists of approximately 1,750 feet of sandstones and claystones.
Colors range from brown and greenish gray in the lower section to
browns and reds, in the upper section [Cashion, 1967]. The Uinta
Formation covers most of the east central portion of the Uinta
basin where the thicker and richer oil shales are found.
2-3.1.3 Green River and Washakie Basins, Wyoming ;
Ancient Lake Gosiute covered a large portion of southwestern
Wyoming. The large lake was bordered to the north bys the Sweet-
water Uplift, the Wind River Uplift, and the Gros Ventre Uplift.
To the west, the lake was bordered by highlands created by the
Absaroka Thrust, the Uinta Arch, and the White River Uplift. The
35
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Park Range and Rawlins Uplift border the lake to the east. The •
oil shales of primary interest in Wyoming are located in the Green
River and Washakie basins, which are contained within the areal H
extent of ancient Lake Gosiute. Other smaller basins within the H
extent of Lake Gosiute also contain oil shale but they are thin
and lean in comparison to those of the Washakie and Green River tm
basins. The other basins are the Fossil basin. Great Divide •
basin, and the Sand Wash basin, the latter extending into North-
western Colorado. The Washakie and Green River basins are now
separated by the Rock Springs Uplift, similar to the separation II
of the Uinta basin and Piceance Creek basins by the Douglas Creek •
Arch.
The stratigraphy of the sediments containing the oil shales in |
Wyoming is similar to that containing oil shales in Colorado and
Utah. The Wasatch Formation underlies the oil shale bearing Green «
River Formation. The Wasatch in Wyoming, as in Colorado and Utah, •
consists predominently of fluvial varicolored brown and gray sand- m
stones, siltstones, shales, and mudstones. Upper Wasatch sedi-
ments intertongue with the overlying Green River Formation. The •
Green River Formation has been divided into four basic members, in B
ascending order: Luman Tongue, Tipton Shale, Wilkins Peak, and
the Laney Shale Member. The fluvial Bridger Formation overlies m
and intertongues with the Green River Formation. Figure 2.3-3 is y
a schematic section, showing the general east-west stratigraphic
relationship of the rocks deposited during Eocene time in the
Green River and Washakie basins. I
Each of the members of the Green River Formation represents wide-
spread deposition of lacustrine facies of ancient Lake Gosiute. •
The Luman Tongue contains only lean oil shales. The Tipton Member H
contains oil shales considerably richer than those of the Luman in
the Green River basin. «
The Wilkins Peak Member consists mostly of marlstones, siltstones, ™
saline deposits, and oil shale. The saline section of the Wilkins
Peak Member contains bedded deposits of the mineral trona, from H
which soda ash is produced. The trona is presently being mined •
and processed. This saline section of the Wilkins Peak member
correlates time-wise with the saline section of the lower Para- •
chute Creek Member in the Piceance Creek basin [Roehler, 1974]. g
The oil shales of the Wilkins Peak Member, although relatively
rich, are thin and separated by lean or barren marlstones. The —
Wilkins Peak Member grades laterally to gray-green marlstones •
and is eventually replaced in section by fluvial tongues of the •
Wasatch Formation.
The uppermost member of the Greeii River Formation in Wyoming is I
the Laney Member. The widespread>distribution of the Laney indi-
cates that Lake Gosiute was most; extensive during Laney deposi- m
tion. Oil shales of the Laney Member in the eastern part of the ||
Washakie basin represent the thickest and richest oil shale
36
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deposit, in Wyoming. The section of oil shale varies from about
150 to 500 feet in thickness [Roehler, 1973]. The oil shales of
the Laney Member in the Green River basin are not as thick as
those of the Washakie basin. The lacustrine Laney Member inter-
tongues with the overlying fluvial Bridger Formation.
Figures 2.3-4, 2.3-5, and 2.3-6 show the areal distribution of the
richer oil shale beds of the Green River basin [Culbertson, 1968].
Accompanying histograms indicate the grade of oil shale within
the Tipton, Wilkins Peak, and Laiiey Members of the Green River
Formation.
0 10 20 Tw
10 20 30
Oil yield in gallons per ton——
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Figure 2.3-4.
Oil Yield of Tipton Shale Member.
Source: Baughman, 1978
2.3.2 Devonian And Mississippian
Until quite recntly there has been only limited research on the
black shales of the East and Midwest because of the emphasis on
the richer and thicker oil shales of the Green River Formation.
The term "black shale" refers to dark (principally black or dark
gray) shale deposits which owe their dark color to their organic
content and which were generally deposited under marine conditions.
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Oil yield in gallons per ton
Figure 2.3-5. Oil Yield of Wilkins Peak Member.
Source: Baughman, 1978
*T v, +?'2^' 1re£ernred to previously, indicates the areas under
which the black shale of Devonian and Mississippian are known and
inferred to exist. Total land area indicated is nearly 400 000
square miles. The crosshatched areas contain the black shales
area bounded by the dashed line indicates where the location of
the black shales are uncertain or where it is concealed (i p
buried) [Duncan et al., 1965]. I '"
As may be noted, these black shales are widely distributed between
the Rocky Mountains and the Appalachian Mountains, with the prin-
cipal known resources contained in zones five or more; feet thick
and correlatable in Arkansas, Illinois, Indiana, Kentubky, Michi-
gan, Ohio, Oklahoma, Tennessee, and Texas [Conant et al., 1961].
Depending upon the location, various formation names! have been
applied to the black shales of the upper Devonian\ and lower
Mississippian. They include the Chattanooga, Antrim, New Albany,
196 1 Mountain Glen, Woodford, and the Lodgepole [Conant et al.,
Figure 2.2-3 illustrates the depositional conditions existing
during the Devonian and Mississippian. The figure also shows the
different names applied to the "black shales" deposited durina
this time [Conant et al., 1961]. !
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20 MILES
GREEN
RIVER
BASIN
Fo«t
Fwt
300
250 -
200
300
0 10 20 0 10 20 30 40
Oil yield in gallons per ton —
Figure 2.3-6.
Oil Yield of Laney Shale Member.
Source: Baughman, 1978
Basically, the area of deposition was in the Paleozoic Appalachian
Sea, which covered the Appalachian, Ohio, and Michigan basins.
Circulation of marine water carrying abundant mineral organic mat-
ter was enhanced by outlets from the Appalachian Sea via the St.
Lawrence seaway and by a southern opening into the Mexico Mediter-
ranean. Under sediment loading, the basins continued to subside,
and correspondingly more sediments were deposited, compressing and
forcing the black shales deeper into their respective basins.
Such conditions existed until the end of the Paleozoic when the
entire eastern part of the continent was emergent [Conant et al.,
1961]. :
The black shales of the Devonian and Mississippian, in contrast
to the oil shales of the Green River Formation, are true shales
composed dominantly of the micaceous clay illite.
Other important minerals associated with the black shales include
phosphate and uranium minerals, with uranium ranging in concentra-
tion from 0.001 to 0.008 weight percent. These minerals are found
in the Chattanooga formation.
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2.4 COMPOSITION
2.4.1 Minerals
The proportions of inorganic and organic minerals in oil shale
vary with the grade of shale. Typical values are shown in
Table 2.4-1 [Stanfield, 1951]. Typical of the minerals present in
Green River oil shale of commercial grade is the listing presented
in Table 2.4-2 [Smith et al., 1978]. ;
TABLE 2.4-1. MINERAL CONTENT OF GREEN RIVER OIL SHALE| VERSUS GRADE
Fischer Assay, gallon oil/ton
Inorganic minerals, wt., %
Organic minerals, wt. , %
Oil Shale
10.5
92.2
7.8
100.0
26.7
84.0
16.0
100.0
3613
so:i
19:9
100.0
57.1
67.0
33.0
100.0
Source: Stanfield, 1951
TABLE 2.4-2. AVERAGE MINERAL COMPOSITION OF MAHOGANY
ZONE SHALE, COLORADO AND UTAH
Composition
,„• weight
Mineral Chemical formula
Dolomite
Calcite
Quartz
Illite
Albite
K feldspar
Pyrite
Analcime
(Mg,Fe)Ca(C03)2
CaC03
Si02
KAl2(AlSi3)Ol0(OH)2
NaAlSi308
KAlSi308
FeS2
NaAlSiO4 • 25H20
TOTAL
32
16
15
1'9
10
6
1
r-
100
Source: Smith et al., 1978 i
The chemical analyses of the inorganic mineral portions; of 16 sam-
ples of Green River oil shale varying in grade from 10.5 to 75.0
gallons per ton were reported [Stanfield, 1951]. The minimum,
maximum, and average values are shown in Table 2L4-3. The
variation of inorganic chemical composition with shale grade is
shown in Table 2.4-4, along with the inorganic chemical
composition of the spent shale.
41
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TABLE 2.4-3. FISCHER ASSAY DATA OF THE INORGANIC MINERAL
PORTIONS OF 16 SAMPLES OF GREEN RIVER OIL
SHALE RANGING FROM 10.5 to 75.0 gal/ton
OIL SHALE
Assay data, %
Minimum Maximum Average
Si02
Fe2C>3
A1203
CaO
MgO
S03
Na20 :
K20 I
Sub Total
Mineral C(>2 in raw shale
Mineral C02 in spent shale calculated to
raw shale
Mineral C02 in raw shale that was volatilized
by the assay
9.9
9.7
0.0
40.9
4.3
9.5
21.2
8.7
2.6
2.7
3.4
25.7
25.6
10.2
17.4
17.0
2.3
Source: Stanfield, 1961
Particle size measurements showed that 99.4 percent of the
inorganic constituents of the Green River oil shales are smaller
than 44 microns (325 mesh sieve), about 80 percent are smaller
than 10 microns, and about 10 percent are smaller than 0.5 micron
[Tisot, 1963]. Table 2.3-5 presents the typical mineralogical
composition of Devonian black shale [Bates et al., 1957].
2.4.2 Kerogen
Kerogen is that portion of the organic material in oil shale that
is insoluble in ordinary solvents for petroleum and that, upon the
application of heat, yields gas, oil, bitumen, and organic residue
(mainly fixed carbon). Bitumen, a benzene-soluble material gen-
erally comprises a small part of the total organic matter in oil
shale. The term kerogen is often used, however, to denote the
total organic material in oil shale.
Kerogen appears black in color to the unaided eye. Under the
microscope, thick sections of kerogen appear yellow in color, with
a minor portion appearing brown or black. It has no well defined
structure, appearing as stringers; masses, and irregular granules
all intermixed with the inorganic minerals in the rock.
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TABLE 2.4-4. CHEMICAL COMPOSITION OF THE INORGANIC PORTION OF
VARIOUS GRADES OF GREEN RIVER OIL SHALE AND OF
THE SPENT SHALE PRODUCTS !
Chemical
constituent
Raw shale
Si02, percent
Fe203
A1203
CaO
MgO
S03
Na20
K20
Spent shale
Si02
Fe203
A1203
CaO
MgO
Very low-
grade shale
(10.5 gal/ ton)
40.9
4.3
9.4
11.0
5.4
0.1
1.8
3.4
53.27
5.64
12.28
14.82
7.00
Medium
grade shale
(26.7 gal/ ton)
26.1
2.6
6.5
17.5
5.3
0.6
2.6
1.0
41.90
4.10
10.53
28.11
8.53
High-grade
shale
(36.3 gal/ ton)
25.5
2.9
6.3
14.2
5.6
1.2
2.7
1.9
42.36
4.74
10.46
23.54
9.30
• Very high-
i grade shale
(61.8 qal/ton)
'• 26.4
3.1
! 7.0
' 8.3
4.5
! 1.4
i
1.9
: 1.0
49.19
5.87
; 13.13
• 15.40
i 8.35
Source;: Stanfield, 1961
TABLE 2.4-5. TYPICAL MINERALOGICAL COMPOSITION
OF DEVONIAN BLACK SHALE
Mineral
Composition
weight
percent
Quartz
Feldspar
Illite + minor kaolinite and
muscovite
Carbon
Total organic matter
Pyrite and marcasite
Chlorite
Iron oxides
Tourmaline, zircon, and apatite
22
9 :
i
31 ;
13.6
16 - 22
11
2
2
i ;
Source: Bates et al., 1957
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The organic matter content of oil shale increases with the grade
of shale. Reported values are plotted on Figure 2.4-1 to show the
range in organic content of shales varying from 10 to 75 gallons
per ton in grade, as determined by the Modified Fischer Assay.
DATA SOURCES •
• USBM R I No 4825
o USBM I C. No 62!6
x USBM R I No 4744
SHALE GRADE, GAL. OIL/TON
(PER MODIFIED 'FISCHER ASSAY)
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Figure 2.4-1.
Organic matter content of Green River Oil Shales.
Source: Baughman, j 1978
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2•4,2.1 Composition of Keroqen
Ultimate
The ultimate composition of the organic material in ten samples of
™e£V°f Mahogany zone oil shale from Colorado and Utah have been
s§r?k^ CSAlth/ 19613*>T£f similaritY among the compositions'was
Srf11?11!?' t average of the ultimate compositions of the samples
was taken to represent the typical composition of : the organic
matter of Mahogany zone oil shales of the Green River Formation?
This average composition is shown in Table 2.4-6. ; "»i.J.on.
TABLE 2.4-6. PROBABLE COMPOSITION OF MAHOGANY-ZONE ORGANIC MATTER
Component
Average amount of
component, wt. %
of organic matter
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
C/H ratio
80.52
10.30
2.39
1.04
5.75
1.42
Source: Smith, 1961
WaS P.er.formed °n New Albany shale
-. . — -. —.. -.—,«.**_^ WAA^-U^ |_oinxL.ii 3.HQ
composition determined from this investigation
-L dXy «LC ^ • ~t"~ / »
TABLE 2.4-7.
ELEMENTAL COMPOSITION OF NEW ALBANY
SHALE ORGANIC MATTER
Component
Average
(weight % organic matter)
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
82.0
7.4
2.3
2.0
6.3
Source: Smith and Young, 1967
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Carbon-hydrogen Ratio Comparisons •
The approximate ratio of carbon to hydrogen (C/H) in the organic «
matter from both Green River and New Albany oil shale is compared g)
to the C/H ratio of various other organic materials in Table
2.4-8. «
TABLE 2.4-8. APPROXIMATE CARBON/HYDROGEN RATIOS •
IN VARIOUS ORGANIC MATERIALS
Material C/H ratio
I
Conventional petroleum
Athabasca bitumen
Green River Kerogen ,
New Albany Organic Matter
Gilsonite
Lignitic coal
Low volatile bituminous
coal
Anthracitic coal
6.2 - 7
7.5
7.8
11.1
8.3
12.1
19.4
35.1
.5
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Source: Baughman, 1978 H
Particle Bonding ; «
Tests on surface area led to the! conclusion that perhaps only a •
small amount of the organic matter is either directly or
chemically bonded to the inorganic mineral constituents. Green •
River Formation kerogen can be found either partly or entirely 11
encasing the inorganic mineral constituents of oil shale [Tisot,
1963]. Despite this conclusion^ bonding between kerogen and m
inorganic matter is such that kerogen has never been isolated in ]|
pure form by either mechanical or chemical separatory processes.
Chemical Formula H
Based on the' elemental analysis of kerogen from Green River oil
shale the following empirical formula was developed for the •
material: C6H9 8N0 18S0.o400.56 fstanfield, 1951]. This formula fl
is in substantial agreement , with that reported later:
CoisHasoOiaNsS [Vanderborgh, 1974]. The latter formula indicates «
a molecular weight of approximately 3200. It should be noted that |
these formulas are based only on the elemental analysis of
samples, and they are not necessarily applicable for use in
generallized correlations relating molecular weight to thermal or •
physical properties. H
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2-4.2.2 Specific Gravity
2.4.3 Saline Minerals i
i
The Tertiary-age sedimentary Green River Formation oil shal<=
very complex material. In addition to its orglnic matte? con
of
in addition to
5
and
e
mineral and
•
°f 4°° tO 35°° fee
in a 1400 uare mile area
Another 36 billion tons of mixed trona and halite are
r^o1/ ASdS °f
part of the area. Occurrences of the mineral
^
Eie Nation"
47
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TABLE 2.4-9.
Mineral name
Carbonates
Trona
Eitelite b
Dawsonite ^
Burbankite
Shortite3 ,
Pirssonite
Gaylussite
Norsethite
(New Unnamed)
Nahcolite
Thermonatrite
Carb ona t e-pho sphate s
Bradleyite
Carbonate-chlorides
Northupite
Silicates
Albite
Analcite
Sepiolite
Loughlinite .
Labuntsovite
Acmite ,
Elpidite
Magnesioriebeckite
(crocidolite), etc.
Feldspar
Borosilicates
Re e dme r gne r i te
Searlesite
Leucosphenite
Halides
Neighborite
Cryolite
Halite
AUTHIGENIC SODIUM MINERALS IN
THE GREEN RIVER FORMATION
Chemical formula
Na2C03-NaHC03-2H20
Na2Mg(C03)2
Na3Al(C03)3-2Al(OH)3
Na2(Ca, Si, Ba, Ca)4(C03)s
Na2Ca2(C03)'3
Na2Ca(C03)2-2H20
Na2Ca(C03)2-5H20
BaMg(C03)2 (Check formula, no sodium shown)
3NaHC03 -Na2C03
NaHC03 ;
Na2C03-H20
Na3P04»MgC03
Na2C03«MgC03-NaCl
NaAlSi308
NaAlSi206-H20
H6Mg8Si1203o(OH)1o-8H20 (Check formula, no
sodium shown)
Na2Mg3Si6Ol6-8H20
(K, Ba, Na, Ca, Mn) (Ti, Nb) (Si, Al)2(0, OH)7H20
Na20'Fe203;4Si02
Na2ZrSi60!5*3H20
Na2(Mg, Fe}3(Fe, Al)2Si8022(OH)2
Variable composition
NaBSi308
NaBSi206-H20
CaBaNa3BTi3Si9029
NaMgF3
Na3AlF6
NaCl
aUnique to Green River Formation
Known elsewhere only in
Source: Jaffe, 1962
igneous or metamorphic rocks.
48 '
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Organic acids of high molecular weight have been found in
dark-colored trona mineral brines from wells drilled in the
Eden-Farson area, approximately 40 miles north of Rock Springs
Wyoming. Both the dissolved trona and the dissolved organic
matter are contained in the Green River Formation.
Nahcolite occurrences are common in Colorado and Utah oil shales
but are not noted in Wyoming shales. In Colorado's Piceance Creek
/™Si™ bedded ^posits of the water soluble sodium salt nahcolite
(NaHC03) were discovered from examination of core samples drilled
in.1964 on Marathon Oil Company property in the north^central por-
tion of the basin. Subsequent drilling disclosed three principal
bedded units of nahcolite which occur at depth in a thickness from
°ne t? nine feet. Nahcolite in disseminated form has 'even greater
distribution. Reserves of approximately 130 million tons of
?SS? per s
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TABLE 2.4-10. AVERAGE DISTRIBUTION OF SULFUR AND NITROGEN IN
OIL SHALE
Weight
percent
Remarks
Type of sulfur compound ;
Sulfide sulfur 67
Organic sulfur 33
Sulfate sulfur Trace
Type of nitrogen compound
Organic 100
As pyrite and marcasite,
FeS2
As CaS04, FeS04 and MgS04
No inorganic nitrogen found
Source: Stanfield, 1951
in various grades of oil shale were reported in the Annual Report
of the Secretary of the Interior' for 1949, Part II. These data
appear in Table 2.4-11.
TABLE 2.4-11.
DISTRIBUTION OF SULFUR AND NITROGEN IN COLORADO
OIL SHALE
Oil yield of shale,
gallons per ton
Total sulfur,
weight' percent
Total nitrogen,
weight percent
10.5
26.7
36.3
57.1
61.8
75.0
0.62
0;.56
0.73
1.96
1.99
1>86
0.28
0.54
0.44
0.66
Annual Report of the Seceretary of the Interior: Part II,
1949
2.4.5 Moisture
There is no consistent relationship between field moisture of oil
shale and oil yield from shale. Typical values for field moisture
varied from 0.38 to 2.93 percent [Stanfield, 1951].
A method for determining the moisture content of oil shale is pre-
sented in U.S. Bureau of Mines Report of Investigations No. 4477,
which deals with the modified Fischer Assay method.
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2-4.6 Trace Elements
are
A fi
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1
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Recent studies have confirmed the magnitude of the mercury content •
shown in Table 2.4-13L [Donnell, 1977]. Using flameless atomic ab-
sorption, an oil shale sample, which had previously been found to M
contain 4.0 ppm mercury, (USGS in 1959) was found to actually con- (}
tain 0.35 ppm. Additional samples were tested an no relationship
between oil content and mercury was apparent. It has been shown -g
that the majority of the mercury present in oil shale ends up in ||
the gaseous Fischer Assay products.
2.5 PHYSICAL PROPERTIES I
2.5.1 Visual Features
The visual features of six specimens of Green River oil shale, Q
selected so as to range in grade: from 10 gallons per ton to 75
gallons per ton, are presented as Table 2.5-1 [Stanfield, 1951]. ft
Shale of most interest would assay in the 15 to 30 gallon per ton |
range.
The color of fragments of Green River oil shale varies with the •
richness or organic content of the material. Rich shale appears 0
dark in color due to the relative abundance of dark-colored
organic matter (kerogen) present. The inorganic materials pre- .
sent, such as clays, carbonates, iand silica, are generally light g
colored. Some rich shale is also light brown in color.
Easily visible in Green River oil shale are repetitive thin lami- •
nations, called varves. Each varve consists of thin bands, one »
light and one dark in color. These are minute seasonal pairs of
lamina which average between 20 and 30 microns in thickness, a m
micron representing 1/1000 of a millimeter. The mineral dolomite g
predominates in the layer made darker in color by higher organic
matter content. The mode of formation of the varves has been ™
described [Smith, 1968]. In overall effect, the varves present a •
woodgrained effect, a feature which probably has a bearing on the *-
naming of a persistently rich zone of oil shale as the "Mahogany"
I
zone .
The Green River oil shale often separates along bedding planes to
form slab-like fragments. When broken across bedding planes, the «
fracture is generally conchoidal. The laminated structure of oil g
shale has an important effect on measured physical properties of
the rock, depending upon whether the direction of the examination
is parallel with or perpendicular to the laminations. Lean shale •
has relatively uniform properties ;in both directions. m
2.5.2 Specific Gravity tt
There exists a relationship between the organic (kerogen) content
of oil shale and the specific gravity of oil shale. Since the or- .
ganic component of oil shale has , a specific gravity of about 1.1 g
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W
Ss
tO
rH
O
OS
J>
IH
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o
o
CO
W
£Zk
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Observed
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W
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longated
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w
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and loop
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and since the mineral components of oil shale have specific grav-
ities ranging from 2.2 (for anaicime) to 5.0 (for pyrite), an
increase in the organic content of an oil shale causes a decrease
in specific gravity of the oil shale.
The graph presented as Figure 2.5-1 displays average values for
oil shale samples from the Anvil Points area in Colorado
[Smith, 1956].
I
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100 r
80
70
60
50
40
30
UJ
>•
6
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to
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K
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t 20
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10
Reference :
Industrie! ond Engineering Chemistry
Vol 48 Wo. 3 fp 441-444 1956
14
i.5
1.6
1.7
1.8
1.9 2.0 2.1 2.2 2.3 2.4
SPECIFIC GRAVITY, 60/60° F
2.5 2.6 2.7 2.8
2.9
I
Figure 2.5-1.
Specific Gravity and Oil Yield of Colorado
Oil Shales. Source: Smith, 1956 (Reprinted
with permission from I.&E.C. Copyright
American Chemical Society.)
A basic equation for the relationship between organic content and
oil shale density was developed |[ Smith, 1969]. The equation is:
DADB
A(DB-DA) -f
54
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-------
DT = Shale density j
A = Weight fraction of organic matter
B = Weight fraction of mineral matter ;
A = Average density of organic fraction,
(g/cm3) ;
B = Average density of mineral fraction,
(g/cm3)
Plotted values agree closely with those shown on Figure 2 5-1
when values in the range of natural occurrence in oil: shales are
assigned to DR(2.7 g/crn^ ) and DA(1.05 g/cm3). ,
Taking the specific gravity/organic content correlation one step
lurther, an empirical relationship between specific gravity and
01i>A m gallons per ton, as determined by the Fischer Assay
method was also developed [Smith, 1956]. This relationship is
expressed by: i c
Y = 31.563 X2-205.998 X + 326.624 j
I
Where Y = oil yield in gallons per ton ;
X = specific gravity of Green River
oil shale at 60/60 °F.
In another study an equation relating the oil yield of New Albany
™ deVel°*ed ^mith etal., 1964].
Y = 93.482 - 34.355 X
Where Y = oil yield in gallons per ton <
X = specific gravity of New Albany oil shale
The calculated relationships between grade, specific gravity,
weight (in place) and weight (broken 38 percent voids) for typical
Green River formation oil shale are presented in Table 2^5-2.
2-5.3 Porosity and Permeability !
The porosity of Green River oil shale before and after heating has
been reported [Dinneen, 1972]. The data were obtained on samp] es
ranging in grade from 1.0 to 60 gallons per ton. These shales
were heated under controlled conditions to 950 °F to remove the or-
ganic matter and further heated to 1500°F to decompose the mineral
carbonates. During the thermal treatment, the oil shale samples
were in a stress-free environment. Table 2.5-3 presents the mea-
surable porosities of the raw and treated oil shale samples
55
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• •••••
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TABLE 2.5-3. POROSITIES OF RAW AND THERMALLY TREATED
OIL SHALES (PERCENT OF BULK VOLUMES)
Oil yield,
liters per
metric ton
4.2
27.1
56.3
1104.3
125.2
164.8
244 . 1
Measurable
porosity of
raw oil shale
10.54
5.53
0.57
0.30
0.14
0.16
0.13
Porosity after
heating to
510°C (950°F)
13.36
14.70
19.09
30.41
36.34
45.35
61.16
Porosity after
heating to
816°C (1500°F)
1 24.83
20.89
; 32.03
.. 53.85
i 51.90
62.91
70.69
Source: Dinneen, 1972 i
The mineral matrices of the oil shales yielding less than about
9.6 gallons of oil per ton did not undergo noticeable structural
breakdown upon heating to 950°F. For richer shales,! the struc-
tural breakdown becomes more noticeable as the grade of shale in-
creases, so that for shales yielding more than 30 gallons per ton,
there is extensive fracturing and swelling. ;
The effect of heat, stress, and time on permeability of test
columns of Green River oil shale samples of various !grades were
determined [Tisot et al., 1971]. As compressive strain increased
with time, the columns' pre-geometry, porosity, and permeability
were concurrently undergoing change. Permeability was expressed
as the amount of nitrogen (STP) which passed through the column of
fragments (in cubic inches per square inch of cross-seqtional area
per minute). 'i
2.5.4 Mechanical Properties :
2.5.4.1 Shear Strength
Shear strengths of lean oil shale samples cut from the roof mater-
ial in the experimental underground oil shale mine of the U.S.
Bureeiu of Mines at Anvil Points, Colorado, are presented in
Table 2.5-4 [Agapito, 1972].
i
2.5.4.2 Compressive Strength i
[
The compressive strengths of core samples of Green River oil shale
before and after thermal treatment have been reported [Dinneen,
1968 and 1972], The untreated samples displayed high Gompressive
strength values that were about the same, whether determined per-
pendicular to or parallel to the bedding planes of !the shale.
57
-------
1
1
TABLE 2.5-4. SHEAR STRENGTHS OF LEAN OIL SHALE SPECIMENS FROM ROOF
MATERIAL OF USBM EXPERIMENTAL MINE (ANVIL POINTS) •
Direction ofShear\Standard
shearing force to strength, \ Number of deviation •
the bedding planes Ib/sq. in. samples tested (percent) •
Perpendicular 3,490 5 4.9 •
Perpendicular 4,640 5 3.1 J§
Parallel 1,770 5 . 10.5
Perpendicular 3,560 . 5 5.1 «.
Perpendicular 3,145 5 6.0 •
Parallel 890 5 8.3 *
Perpendicular 3,205 5 5.2
Parallel 920 5 9.1 •
Source: Agapito, 1972 w
After heating to 950°F, the lean shales retained high compressive
strength values in both horizontal and vertical planes, indicating _
a high degree of inorganic cementation between the mineral parti- I
cles comprising each lamina and between adjacent laminae. Dinneen "*
showed the compressive strength of rich shale is quite low after
removal of the organic matter. Decomposition of the mineral car- •
bonates at 1500°F apparently does not greatly affect the compres- p
sive strength. The results are presented in Table 2.5-5,
expressed in metric system units [Dinneen, 1968 and 1972]. sa
English system unit may be derived from Figure 2.5-2. |
A rather comprehensive report on the compressive strength of roof
and mine support pillar specimens cut perpendicular to bedding •
Planes was prepared [Agapito, 1972]. The specimens were obtained »
in the room-and-piliar system underground shale mine of Mobil Oil
Company, near Anvil Points, Colorado. The data are summarized in •
Table 2.5-6. H
That the compressive strength of \ oil shale varies with the grade «
of the shale is presented in Figure 2.5-3 [Sellers, 1971]. •
2.5.4.3 Hardness
u
For two Green River core samples tested, the hardness of the II
horizontal core was 61 (scleroscope hardness number) and.for the
vertical core was 55 [Matzick et al., 1956]. m
2.5.5 Leachate Quality and Quantity
The modified in-situ method of oil shale retorting and the various •
surface methods require that quantities of raw (unretorted) shale •
58
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100
RAW SHALE
V
\ HEATED SHALE
\
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OIL YIELD;, 6AL./TON
60
Figure 2.5-2. Compressive Strength of Oil Shales.
Source: Dinneen, 1968 and 1972
be mined from shafts and drifts that provide access to the re-
torts. Raw shale is also mined to provide a void space into which
the shale in the retort expands upo;n rubblization by blasting. The
mined shale may be stored on the ground surface for a period of at
least a few years and possibly even permanently. Underground
mining and surface retorting will also require large storage piles
of raw, mined shale for retort feed material. In addition lean
shale and rejected raw shale fines may be permanently disposed.
The placement of the raw mined shale on the surface places it in
an t environment with which it is no longer in geochemical
equilibrium. Subsequent precipitation on the pile creates the
potential for the release of leachate containing a variety of
chemicals into percolating waters -at elevated levels relative to
the base line conditions.
A^econnaisance study of leachate quality from raw mined oil shale
with emphasis on shale from Federal lease tracts C-a and C-b has
been reported [EPA-600/7-80-181, ; 1980]. The study employed
laboratory leaching columns containing a variety of samples of raw
shale and soils which were obtained from the Piceance Basin of
Colorado. The purpose of extending the study to selected soil
samples was to provide a background and perspective from which to
view raw shale leachate properties.t Included were four raw
60
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TABLE; 2.5-6.
COMPRESSIVE STRENGTH OF GREEN RIVER OIL SHALE SAMPLES
CUT PERPENDICULAR TO BEDDING (SAMPLES FRtiM USBM
EXPERIMENTAL MINE, ANVIL POINTS, COLORADO)
Distance from
Mahoqany marker,
feet
31.6 above
21. 5-26. 8 above
20 above
18 . 5 above
10 above
4.2 above
2.5 below
4.5 below
7 below
10 below
12 . 5 below
14 below
14.6 below
15.5 below
17 below
17.5 below
18.5 below
20 below
20.5 below
23 below
23 below
26.6 below
27 below
31 below
33 below
37 below
39.5 below
46.5 below
Bed
designation
Roof
do
do
A
B
C
D
D
D
D
E
E
E
F
F
F
F
G
G
G
G
G
G
H
H
H
H
I
Number of
specimens
tested
2
2
3
1
2
1
1
2
2
1
1
3
5
3
1
1
8
1
1
2
2
2
3
3
1
1
2
2
Compressive
strength,
psi
15,380
14,890
12,430
17,100
1!5,000
17,100
19,000
12,650
11,730
10,700
12,520
;8,280
7,350
11,910
12,080
9,190
'8,160
14,480
14,470
10,250
,8,600
14,090
12,960
18,560
13,600
3J5,390
17,280
12,700
Designations refer to arbitrarily-designated groups of
minesable beds, lettered A through I. j
Source: Agapito, 1972
shales, two soils, one sample of naturally leached 'outcropping
shale, and one sample of naturally retorted shale from a surface
fire of unknown age. ,
Leaching was conducted by passing deionized water through columns
of each material. Both saturated and unsaturated testis were con-
ducteid. Samples of the effluents were collected and s'ubjected to
chemical analyses. The ranges of concentration variation observed
61
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CURVE IS FROM EQUATION
= J5;760-957A + 9.72A2
-2B9A (H/W) Whirl H/W= I 825
FISCHER ASSAY, GALLONS PER TON
Figure 2.5-3.
Compressive Strength versus Fischer Assay
of Colorado Oil Shale, Anvil Points Mine.
Source: Sellers, 1971
Table 2 5 7 fS"ttweac5 °f^ ^ Aerials tested are presented in
sSiSc: ;5~Zi ^ /aS f°U?d "^ the leachate contained dissolved
™°Jids at elevated concentrations relative to the background. The
mauor contributors to the dissolved solids content are caicium
magnesium, sodium, bicarbonate, chloride and sulfate. I compa™-
iS Table f I £lemS£ concentrations in the leachates is presented
tL7™i™£: i • ^.concentrations of four elements of potential
o?™C?*°gafal significance: Al, B, F, and Zn were found to be
significantly greater in the leachates from some of the mined
snaies than in the corresponding samples from the previously ex-
bv th^^1^18; iThe levels of a11 other trace elements produSd
«£M 3 6d .shales were comparable to those observed from the
soils and previously exposed shales.
. maximum observed concentrations of various
h -, dra:nk:Ln9 water criteria, it was concluded that
even the worst leachate from the columns did not exceed 100 times
drinking water standards for measured parameters ^ However thJ
maximum concentrations of Cr, F, Fe, Hg, Mn, NOa Pb? IS!!' TDS
and Zn were found to exceed drinking water criteria.
As a result of the laboratory study [EPA-600/7-80-
The mean concentrations of the major ionic species found in the
^aC^eSnfr0mT tlfeC-a and C-b tracts are Presented in Table 2.5-9
and 2.5-10. In the case of the C-a tract, the leachate from the
62
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raw shale was highly saline with a mean concentration of dissolved
solids of 29,500 mg/L for the 5 ft. depth pile and 60,220 mg/L for
the 15 ft. depth pile. These waters were found to be a magnesium- •
sulfate type, with these two constituents accounting for 87% of •
the total equivalent weight of the dissolved solids. The pH
ranged from 6.9 to 7.9 throughout the study. " •
m
In the case of the C-b tract the ,quantity of dissolved solids in
the leachate was lower; averaging 6,850 mg/L and the pH ranged m
from 7.4 to 8.4. The composition of the C-b leachate is dominated ffl
by sodium and sulfate, rather than magnesium and sulfate exhibited ™
in the C-a leachate. In both cases it appeared that the calcium
concentration was controlled by the solubility of calcium sulfate. it
The mean values of trace element concentrations in the C-a and C-b
tract leachates are presented in \ Tables 2.5-11 and 2.5-12. The m
data are averaged over two years of sampling for various pile |J
depths. The concentrations of fluoride observed in the field
generated leachates were similar to those measured in the previous fc
laboratory column leaching study [EPA-600/7-80-181, 1980], even •
though the shale samples differed. The concentrations of zinc, *»
boron, and aluminum found in the field study were significantly
less than the maximum values observed in the laboratory column tt
studies (compare Tables 2.5-11 and 2.5-12 with Table 2.5-8). The B
differences may be due to the difference in materials used in the
two studies. The maximum values of the species analyzed in the *•
field study are presented in Table 2.5-13. Although the •
concentrations of many trace elements were sometimes observed to
be greater than various recommended maxima for particular uses
(e.g., drinking water), the large concentrations of the common m
species is more likely to be the significant quality m
characteristic of these leachates.
The cumulative volume of leachate per unit area measured over £
nearly three years at the C-a tract ranged from 6.26 to 13.72 cm
per year. These volumes represent 7 and 16 percent, respectively, «
of the incident precipitation over the same time period. The lar- •
ger value is believed to be more representative of the actual *
leachate volume generated in the pile. The cumulative volume of
leachate at the C-b tract ranged from 11.52 to 17.02 cm per year. jR
These volumes represent 12 and 17 percent, respectively, of the m
incident precipitation over the same time period. Leachate vol-
umes of these magnitudes are believed to be larger than the natur- M
al recharge rates on undisturbed lands receiving similar volumes g
of precipitation. The raw shale piles were formed from mine-run
size material and remained unvegetated. Therefore, infiltration ^
capacity was high and both evapotranspiration and direct runoff •
capacity were low. •
66
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67
-------
TABLE 2.5-13. MAXIMUM OBSERVED CONCENTRATIONS
IN RAW SHALE LEACHATES
Concentration,
Species
HC03
C03
TDS
F
Cl
P04
N03
S04
Zn
Fe
Co
Li
NH3
B
Cd
Be
Mg
P
Si
Mo
Mn
Ni
Na
Cu
Al
Ca
Ba
K
Cr
Sr
Pb
Ag
Ti
Se
As
Hg
Source :
mg/L
579
5
72,660
113
366
0
2,564
45,900
0
2
1
0
2
I
0
0
12,830
7
13
1
2
1
2,030
0
5
505
0
16
0
15
1
0
0
0
0
0
.68
.28
.597
.02
.17
.339
.55
.97
.168
.300
.0
.2
.5
.34 ;
.12
.073
.28
.822
.4
.290
.4
.036 ;
.012
.007
.013
.007
.003 1
EPA-600/D-84-143 ,
68
Location
C-a,
C-a,
C-a,
C-a,
C-a,
C-b,
C-a,
C-a,
C-a,
C-a,
C-a,
C-b,
w"" a. /
C-b,
C-a,
C-b,
C-a,
C-a,
C-a,
C-b,
C-a,
C-a,
C-a,
C-b,
C-a,
C-a,
C-b,
V*™" Q. f
C-a,
C-a,
C-a,
C-a,
C-a,
C-a,
C-b,
C-b,
1984
15
15
15
15
15
20
15
15
15
15
15
10
5
15
15
10
15
15
15
10
15
15
15
10
5
15
10
15
15
15
15
15
15
15
20
20
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
ft
Date
9/21/82
7/19/82
8/16/82
7/26/82
7/01/82
2/25/82
7/26/82
5/10/82
8/16/82
8/11/82
8/23/82
7/26/82
8/30/82
7/26/82
7/26/82
7/06/82
9/06/82
8/04/82
6/02/82
7/06/82
6/02/82
6/02/82
8/02/82
7/06/82
7/01/82
3/22/82
9/23/82
7/19/82
6/02/82
7/19/82
8/11/82
3/17/82
4/12/82
7/01/82
8/04/82
2/25/82
1
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SECTION 3 ;
SOLID WASTES AND THEIR CHARACTERISTICS :
FOR OIL SHALE RETORTING PROCESSES .
3.1 LURGI-RUHRGAS OIL SHALE RETORTING j
3.1.1 Retorting Operation i
A schematic for the Lurgi retorting process [EPA-600/8-83-005,
1983] is shown in Figure 3.1-1. Initial crushing !in the pit
reduces the size of the run-of-mine shale to minus 8 inches.
Secondary and tertiary crushing further reduce the shale size to
minus 1/4 to 1/3 inches. The crushed oil shale is fed through a
feed hopper to a double screw mixer, where four to eight times its
weight of a hot (1,200-1,300°F) circulating heat carrier, such as
sand or processed shale from the collecting bin, is thoroughly
mixed in, thus heating the entire mixture to approximately
950-1,000°F within a few seconds. At this temperature, pyrolysis
of the kerogen in the oil shale occurs, resulting in the
production of retort gas, shale oil vapor and water vapor.
!
The circulating heat carrier and the partially retorted shale are
then dropped from the screw mixer into the surge vessel, where
residual oil components are distilled off. The mixture of heat
carrier and retorted shale residue is passed to the lower section
of the lift pipe, where combustion air (preheated to 450-900°F) is
introduced, raising the mixture pneumatically to the collecting
bin. Essentially all available organic carbon contained in the
retorted shale residue is burned in the lift pipe. Supplemental
fuel may be added to the bottom of the lift pipe to i sustain the
combustion of the organic residue when processing ; leaner oil
shales. Also, at the high lift pipe temperature, \ a moderate
amount of carbonate decomposition occurs in the processed shale.
At the top of the lift pipe, the hot, burned shale is separated
from the flue gases in the collecting bin. Fines arejcarried out
of the collecting bin with the flue gas stream. The coarse-
grained shale residue accumulates in the lower section of the
collecting bin and flows continuously to the mixer. Partial
removal of the solids to prevent accumulation in the collecting
bin may be required if the fines carry-over is not I sufficient.
The combustion air supplied to the lift pipe is preheated by
counter-current heat exchange with the flue gas stream in the
preheat section of the waste heat boiler. The calcined minerals
69
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in the burned shale combine with the sulfur dioxide \produced by
combustion of the organic sulfur to form calcium arid magnesium
sulfites and sulfates. ;
The pyrolysis products stream containing shale fines is withdrawn
at the end of the screw mixer and passed through two ^series-con-
nected cyclones to a product recovery section. The fines are
separated in these cyclones and returned to the recycle system.
The vapor stream then passes through a sequence of three scrubb-
ing coolers (not shown). The first scrubbing cooler removes dust
from the gas stream by condensation of heavier oil fractions. A
dusty heavy oil is obtained at this point. In the next scrubbing
cooler, further condensation of the oil takes place at a temper-
ature above the dew point of water to produce a water-free middle
oil. Final cooling of the gas produces an aqueous gas condensate
and a light oil fraction. The light oil is separated from the
condensate or gas liquor in an oil/water separator, finally, the
gas is scrubbed with a lean oil in the naphtha scrubber to recover
naphtha and noncondensable gases, as deemed desirable. \
i
The flue gas stream in the lift pipe is dedusted in a cyclone
after leaving the collecting bin; the dust is routed to the pro-
cessed shale mixer. The gas stream is then routed through a heat
exchcinger for preheating of combustion air, a waste heat boiler to
produce process steam, another cyclone, and a humidifier or flue
gas conditioner. Additional dust removed by the waste :heat boiler
and cyclone are routed to the processed shale mixer. The flue gas
stream is cooled somewhat and conditioned in the humidifier by
adding steam generated during processed shale quenching. After
humiclifi cation and cooling, residual dust is removed fr|om the flue '
gas stream using an electrostatic precipitator and discharged into
a processed shale quencher/moisturizer where more water is added
to cool the solids. The processed shale residue, cooled to ~200°F,
is moisturized to a suitable moisture content and discarded as
open pit backfill. j
3.1.2 Solid Wastes i
i
A block flow diagram for the basic processing and pollution con-
trol system for the Lurgi process is presented in Figure 3.1-2.
In the retort off-gas discharge system, the flue gas and entrained
processed shale particles are separated from each other via a
series of cyclones, waste heat recovery system, humidifier, etc.
The flue gas is then passed through an electrostatic precipitator
to remove the residual particulates and is eventually vented to
the atmosphere. The processed shale particulates separated along
these steps is sent to the processed shale mixer for quenching and
proper moisturizing before final disposal. !
The retort gas is cleaned for marketing. The gas is ; first com-
pressed to remove much of the moisture and ammonia, theri subjected
71
-------
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to treatment by diethanolamine and triethylene glycoli, which re-
move the acidic components and the residual moisture,!respective-
ly, from the compressed gas. The clean, dry gas is then sent to
the pipeline. A small amount of spent amines are generated in
this process, which are disposed with the processed shale. How-
ever, the spent amine is less than 1% of the processed|shale mass.
The acid gas obtained from the diethanolamine regeneration is
treated by the Stretford process, which converts the; H^S in the
gas to elemental sulfur. The clean gas is then vented to the
atmosphere. Spent Stretford liquor could be reclaimed on site or
sent off site for reclamation.
The gas liquor from the oil and gas recovery section is subjected
to oil/water separation, but it still contains dissolved ammonia
and sulfur compounds and its direct discharge or use may also cre-
ate pollution. Therefore, the ammonia and dissolved volatile com-
pounds from the liquor are removed by an ammonia recovery process.
The treated water is then used for processed shale moisturizing.
Overall water management activities consist of satisfying the pro-
cess steam and cooling water needs, as well as efficient manage-
ment of the aqueous waste effluents. Properly treated mine water
is .used as the boiler feedwater to produce the steam in the Lurgi
waste heat recovery boiler. Treated mine water is also used as
cooling water, process makeup water, cooling tower makeup water,
etc. Minor wastes generated from the water treatments are equal-
ized in a holding pond and then used for processed shale moistur-
izing.
Table 3.1-1 summarizes the final waste streams and the iintermediate
streams which make-up the final waste streams. These streams were
identified in Figure 3.1-2. The subgrade ore, overburden, and
processed shale (streams 2, 3, and 29) constitute the majority of
the wastes (greater than 97% of solid wastes). Several waste-
waters, such as equalization pond discharge, treated sanitary
wastewater, clarified mine water, and oil/water separator dis-
charge, are used to moisturize the processed shale. j
Table 3.1-1 also describes the general composition of these
streeims and component mass flow rate. Of the If inal -waste
streeims, the processed shale represents more than 50% of the
total volume. The components of concern and the composition
of the solid waste streams show that for all the waste streams
the leachable salts are of primary concern. The water for dust
control and revegetation (streams 90 and 91) has a isignificant
solids concentration which may contribute to salt leaching or met-
als leaching. Also of concern are the organics in the processed
shale (generated from both the unburned hydrocarbons in the pro-
cessed shale as well as from the moisturizing water (stream 73),
and the sludges to be added to the solid waste pile. 1
73
-------
1
I
Sanitary wastewater treatment and aerated pond sludges although *
not determined, can be estimated to be 0.5 Ib/hr based on 18 gpm
influent rate, a typical TSS concentration of 250 mg/L, and a •
treatment efficiency of 75%. Thus, at 0.5 Ib/hr these sludges If
are of insignificant weight compared to the processed shale rates.
However, the solids from sanitary wastewater treatment and sludges
may pose special health risks and should not be dismissed lightly.
1
The rate of spent amine is difficult to estimate as the influent _
rate of rich amine and efficiency of the amine regenerator are •
unnerta in. ™
uncertain.
3.1.3 Characteristics of Solid Wastes
I
Tables 3.1-2 to 3.1-6 provide additional information on the com-
position of the processed moisturized shale (stream 29). The •*
nominal feed size of the particles associated with the Lurgi •
retorting process is less then 0.6 cm. As seen in Tables 3.1-2 ™
and 3.1-3, properly moistened and compacted processed shale has
low permeability; therefore, actual field leaching may not be
represented by laboratory column leaching experiments. The results
of column leaching and various other experiments performed on the
processed shale are given in Tables 3.1-7 to 3.1-12. Some soluble
elements are reported as their oxides.
74
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-------
TABLE 3.1-3. SUMMARY OF HYDRAULIC CONDUCTIVITY MEASUREMENTS
FOR VARIOUS COMPACTION AND LOADINGS FOR LURGI
RETORTED SHALE
Material
Water
wt. %
Density,
g/cm3
Permeability, cm/s at various loadings
; 50 psi 100 psi 200 psi
LURGI-RG-r
LURGI-ULG-I
LURGI-RBa'b
a,b
26.6
10.4
dry
dry
1.41
1.33
1.81
1.22
1.0 x 10"6
3.0 x 10~^
8.3 x 10"5
1.2 x 10~^
6.5 x 10~?
1.9 x 10"^
6.5 x 10~?
2.0 x 10"^
Leaching columns.
Various source samples.
Source: EPA-600/D-84-228, 1984
TABLE 3.1-4.
WATER HOLDING CAPACITY OF LURGI PROCESSED SHALES
AT VARIOUS PRESSURES AND BULK DENSITIES
Sample
14.7 psi
(1 bar)
44.1 psi
(3 bar)
Pressure
73.5 psi
(5 bar)
147 psi
(10 bar)
200 psi
(13.6 bar)
No compaction
Lurgi 27.5
Packed to a
BDD=1.30 g/cc
Lurgi ash 62.4
BDb=1.45 g/cc
Lurgi ash 60.2
BDb=1.60 g/cc
Lurgi ash 47.2
Lurgi 20.7
27.6
62.3
58.7
46.3
20.2
26.9
62.2
56.6
45.8
19.8
25.3
62.0
55.5
44.4
19.8
15.5
61.7
55.2
43.7
19.0
aTable entries are moisture contents (w) expressed on a weight %
basis: weight of water per unit weight of dry solids.
v\
BD= bulk density. •
Source: EPA-600/D-84-228, 1984
78
I
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I
1
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i
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1
1
1
I
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1
-------
TABLE 3.1-5. COMPOSITION OF LURGI PROCESSED MOISTURIZED SHALE
Weight
Component percent
Retorted shale
(moisturized) 100.00
Moisture 18 . 70
Oxygen (organic) 0.02
Nitrogen (organic) 0.08
Carbon (organic) 0.25
Sulfur (total) 0.93
Source: EPA-600/8-83-005, 1983
Mass flow, Flow,
10s Ib/hr 103 Ib-moles/hr
9,733
1,820 101.1
2 0.1
8 0.6
24 2.0
91 2.8
TABLE 3.1-6. INORGANIC ANALYSIS OF LURGI THE PROCESSED SHALE
Component
Silicon dioxide
Iron oxides
Aluminum oxide
Calcium oxide
Magnesium oxide
Sulfate
Sodium oxide
Potassium oxide
Carbonate
Chloride
Loss on ignition
Weight
percent
46.00
4.40
12.70
22.40
4.80
3.80
3.20
2.70
4.40
0.08
4.60
Source: EPA-600/8-83-005, 1983
79
-------
TABLE 3.1-7. MAJOR ION COMPOSITION OF COLUMN
LEACHATE-LURGI RETORTED SHALE
Vt
L
0.020
0.058
0.092
0.186
0.236
0.292
0.350
0.378
0.452
0.535
0.590
0.652
0.737
0.860
1.06
mg/L
Ca
575
560
540
520
530
540
560
570
580
600
590
590
600
610
590
Mg
0.3
0.2
0.4
0.6
0.7
0.7
0.8
0.7
0.7
0.7
0.6
0.7
0.7
0.7
0.8
Average
Source :
vt
L
Na
11970
11270
10590
5410
3150
1660
1000
795
600
575
535
405
530
385
365
K
950
760
830
300
220
160
120
110
110
100
110
100
110
80
120
TCf^
-•"— .j
permeability =
Cl
1360
1300
1150
450
230
131
75
65
45
: 48
39
30
; 41
26
23
f
"K = 8
HC03
136
67
57
29
25
26
26
22
21
21
20
18
23
20
20
.3 x K
CO3
393
351
328
208
149
123
101
111
105
118
90
93
105
136
137
3~^ cm/s
S04
23900
23400
21900
12600
5590
5450
3890
3480
3180
3110
3040
2760
3180
2770
2750
1
1
1
1
PH
10
11
11
11
11
11
10
11
11
11
11
11
11
11
11
.83
.09
.13
.22
.15
.05
.96
.07
.08
.12
.02
.07
.02
.21
.20
= pore volume
EPA-600/D-84-228,
1984
80
1
1
I
^v
1
1
1
1
Ir
t
1
mm
1
1
I
1
-------
TABLE 3.1-8. CONCENTRATION OF SELECTED TRACE
ELEMENTS IN COLUMN LEACHATE OF
LURGI RETORTED SHALE
vt
L
0.020
0.058,
0.092
0.186
0.236
0.292
0.350
0.378
0.452
0.535
0.590
0 . 652
0.737
0.860
1.06
F
21.0
22.7
17.5
8.2
4.4
8.6
7.9
10.1
6.1
6.3
4.5
5.4
4.1
4.8
4.4
Average
17-1-
B
1.01
0.77
0.66
0.41
0.33
0.24
0.16
0.14
0.10
0.10
0.16
0.12
0.10
0.09
0.22
Si
20
11
15
11
11
11
8
8
8
8
5
9
9
9
8
Key
permeability =
mg/L
Mo
11
11
10
5.1
3.7
2.4
1.9
1.9
1.6
1.6
1.0
1.5
1.7
1.3
1.2
K = 8.3
Mn
0.037
0.023
0.022
0.018
0.017
0.019
0.015
0.013
0.013
0.010
0.016
0.024
0.019
0.012
0.015
x 10~?
' Al
29
23
18
i 5.8
4.6
' 3.8
J3.3
3.2
,2.9
2.8
1.5
!2.7
'2.9
12.5
2.3
cm/s |
Sr
7.8
7.9
16
6.9
8.4
13
13
15
16
17
19
19
19
17
22
|p = pore volume
Source :
EPA-600/D-84-228, 1984
81
-------
TABLE 3.1-9.
CONCENTRATIONS IN ASTM WATER SHAKE
TEST EXTRACTS - LURGI SPENT SHALES
Parameter
PH
EC
ALK
H2C03
HC03
C03
TDS
F
Cl
P04
N03
S04
Zn
Fe
Co
Li
V
NH3
B
Cd
Be
Mg
P
Si
Mo
Mn
Ni
Na
Cu
Al
Ca
Ba
K
Cr
Sr
Pb
Ag
Ti
Se
As
Hg
Units
—
|jmhos/cm @ 25°
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
RG-Ia
11.43
3660
192
0.001
9.6
110.7
3700
2.0
; 23.7
0.62
8.7
2545
0.001
0.018
<0.005
0.371
0.053
8.4
0.173
<0.001
' <0.0005
0.6
0.22
5.5
<0.05
0.008
<0.005
324
<0.001
0.60
750
0.115
43
0.100
14
0.012
<0.001
<0.005
<0.020
0.016
<0.001
ULG-Ia
11.49
2650
160
0.001
7.0
92.5
2140
3.8
10.9
<0.1
1.7
1301
0.007
<0.005
<0.005
0.616
0.059
6.2
0.005
<0.001
<0.0005
0.5
0.20
3.4
<0.05
0.006
<0.005
180
0.003
<0.02
402
0.130
34
<0.005
13
<0.01
0.005
<0.005
<0.020
<0.01
0.001
RBS
11.85
4270
355
0.001
6.9
209.6
3350
6.34
17.1
0.5
2.52
2291
<0.001
<0.005
<0.005
0.887
0.082
-
0.096
<0.001
<0.0037
0.4
0.5
5.4
<0.05
0.029
<0.005
275
0.002
<0.02
713
0.157
64
0.095
20
<0.01
0.008
<0.005
<0.020
<0.01
<0.001
Various source samples.
Source: EPA-600/D-84-228, 1984
1
1
82
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1
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1
i
f
1
I
I
I
f
I
1
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TABLE 3.1-10.
CONCENTRATIONS IN RCRA TEST EXTRACTS
LURGI SPENT SHALES
Parameter
pH
EC
ALK
H2COa
HC03
C03
TDS
Cl
P04
NOS
S04
Zn
Fe
Co
Li
V
NH3
B
Cd
Be
Mq
P"
Si
Mo
Mn -
Ni
Na
Cu
Al
Ca
Ba
K
Cr
Sr
Pb
Ag
Ti
Se
As
Hg
Units
^
pmhos/cm @ 25°
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
RG-Ia
8.06
4150
1612
37.8
1948
9.5
5690
7.1
<0.01
1.53
684
0.138
<0.005
<0.005
0.173
0.008
3.28
0.520
0.004
<0.0005
290
0.4
0.6
<0.05
0.110
0.012
43
0.032
<0.02
964
0.130
3.2
<0.005
8.9
<0.01
0.002
<0.005
<0.02
0.019
<0.001
ULG-Ia
i
7.99
4236
2188
59.7
2646
11.1
6520
6.4
<0.01
0.48
420
0.082
<0.005
< 0.005
0.135
0.006
1.08
0.270
0.003,
0.0016
269
0.7
7.0!
<0.05
0.410
0.075
28
0.017-
<0.02!
1280;
0.350;
5.0
<0.005:
13,
<0.01|
<0.002;
<0.005!
0.0201
0.020:
0.001;
RBa
8.67
5650
2505
14.1
2937
58.7
8520
18.9
<0.01
0.53
880
0.010
<0.005
<0.005
0.304
0.008
1.98
1.470
0.002
0.0026
430
0.7
7.9
<0.05
0.090
<0.005
55
0.009
<0.02
1479
0.180
11.0
<0.005
13
<0.01
<0.002
< 0,005
<0.02
0..047
<0..001
Various source samples.
Source: EPA-600/D-84-228, 1984
83
-------
TABLE 3.1-11.
LEACHABLE MASS AS INDICATED BY THE ASTM PROPOSED
WATER SHAKE TEST FOR LURGI SPENT SHALES - mg/g
Parameter
RG-I
ULG-I
RBC
Na
Ca
Mg
S04
Cl
F
B
Mo
Al
TDS
1
3
0
10
0
0
0
0
0
14
.296
.00
.002
.18
.095
.008
.0007
.004
.002
.80
0
1
0
5
0
0
0
0
8
.720
.608
.002
.204
.044
.015
-
.002
.006
.560
0
0
0
0
^
-
.0008
—
-
-
.0002
.010
.008
~
I
I
I
t
I
I
aVarious source samples.
Source: EPA-600/D--84-228, 1984
TABLE 3.1-12.
LEACHABLE MASS AS INDICATED BY THE RCRA EXTRACTION
TEST FOR LURGI SPENT SHALES - mg/g
Parameter
RG-I
ULG-I
RBC
Na
Ca
Mg
S04
Cl
B
Mo
Al
TDS
0.860
19.28
5.80
13.68
0.142
0.010
0.016
0.050
H3.8 ;
0.560
25.60
5.38
8.40
0.128
0.005
0.008
0.038
130.4
1.100
29.58
8.60
1.760
0.378
0.029
0.020
0.038
170.4.
Various source samples.
Source: EPA-600/D-84-228, 1984
84
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3.2 TOSCO II OIL SHALE RETORTING i
3.2.. 1 Retorting Operation ;
Figure 3.2-1 shows a conceptual flow diagram of the TOSCO II
retorting process [EPA-600/8-83-003, April 1983]. The process is
indirectly heated and employs a solid-to-solid heat exchange
(between hot ceramic balls and raw shale) as a means for providing
the heat of retorting. The integral parts of the TOSCO II
retorting system are: retort and accumulator; product
±rac:tionator; processed shale removal system; ceramic ball system-
and raw shale preheat system. ;
The TOSCO II retort is a slightly inclined, rotating drum to which
raw shale, minus 1/2-inch size, preheated to approximately 500°F
is fed. Ceramic balls, at 1.5 times the shale mass flow rate, and
previously heated to about 1,300°F, are also added toj the retort.
The rotating, mixing action results in pulverization: of the raw
shale. Heat transfer from the ceramic balls raises the shale
temperature to approximately 900°F, and pyrolysis, or retorting,
of the kerogen in .the shale occurs. The pyrolysis vapors and the
mixture of balls and pyrolyzed shale are then taken to an
accumulator vessel. This accumulator consists of ia rotating
perforated screen or trommel which retains the balls; but allows
t]2e Pulveri2ed shale to Pass through, thus affording k separation
o± the two. The pyrolysis vapors are removed from the vapor dome
at the top of the accumulator and sent to a fractionator for oil
recovery, while the ceramic balls are sent for recycling and the
processed shale is eventually sent for disposal. ;
In the oil recovery section (not shown in Figure 3.2-1), the pyro-
lysis vapors are separated by the fractionator into gas, naphtha
oil, gas oil, bottom oil, and gas condensate, or foul water. Each
stream is sent to its respective processing unit for' appropriate
treatment. ; '
Processed shale dust, contained with the ceramic balls as they
emerge from the accumulator, is removed by hot flue gas from the
steam superheater. The particulate matter is subsequently con-
verted to a sludge in the venturi wet scrubber and sent to the
disposal area. The clean flue gas is emitted to the atmosphere
through the scrubber stack. The clean ceramic balls are then
transported by a bucket elevator to the ball heater if or heating
and recycling back to the retort. In the ball heater, treated
fuel gas and shale oil are burned by atomizing the fuels with air
in a vertical combustion chamber at the top of the vessel. Hot
flue gas thus generated passes downward, concurrently with the
balls, thereby heating them. The flue gas is separated from the
balls in the gas disengagers and the hot balls are returned to the
retort.
85
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The hot processed shale from the accumulator is taken to a rotat-
ing drum steam generator/cooler where it is cooled to about 300°F
by indirect heat transfer to the feedwater to generate some
process steam. The cooled processed shale is then taken to
a^2 5er rotatln9 drum and processed shale moisturizing water is
added. Steam incidentally produced during the moisturizing oper-
ation entrains some processed shale dust which is removed in"the
venturi wet scrubber; the steam, along with a little; participate
matter, is released to the atmosphere through the scrubber stack
The processed shale, cooled to below 200°F is moisturized to
approximately 14% water by weight (to aid compaction and dust
control) and then transported to the disposal area. !
The disengaged hot flue gas is used to preheat the rawi shale feed
thereby recovering most of the waste heat. The preheating system
consists of a series of three lift pipes (or preheat zones), a
thermal oxidizer (incinerator), cyclones and wet scrubbers. The
flue gas is introduced at the bottom of the last lift1 pipe (first
preheat zone), where the raw shale stream from the -second lift
pipe (second preheat zone) is also received. The solids are lift-
ed pneumatically and heat transfer from the gas to the shale oc-
curs. The preheated shale is accumulated in a collecting bin at
the top of the lift pipe and sent to the retort. Residual dust in
the flue gas is separated by a cyclone and added to the feed going
to the retort. \
Since the flue gas temperature is at its highest when introduced
to the last lift pipe (first preheat zone), it partially retorts
the very fine shale, which results in hydrocarbon vapor release
into the flue gas. Therefore, the flue gas is introduced to a
thermal oxidizer (located between the first and second preheat
zones) to burn the hydrocarbons so that the hydrocarbon emission
to the atmosphere is not excessive. Some shale oil, !C4 liquids
and air are also added to the oxidizer to sustain combustion. The
resulting flue gas is cooled, and then introduced to the bottom of
the other two lift pipes. At this point, the temperature of the
flue gas is low enough so that the extent of retorting!of the fine
shale is less than in the first preheat zone. Hydrocarbons
released in these two lift pipes are emitted with the flue gas,
without incineration.
The flow diagram for a complete plant complex, emphasizing the
waste streams produced, is presented in Figure 3.2-2 [TOSCO, 1982].
Production-scale mining, of the oil shale is accomplished by con-
ventional underground room-and-pillar mining.
The acid gases (H^S, CO^ ) in the retort gas and hydrotreated flue
gas are separated.by absorption in a diethanolamine solution as a
pretreatment step. The treated sweet gas is eventually separated
into C4 liquids, LPG, and C-4 and lighter process gas. Sulfur from
the acid gases is recovered by the Claus/Wellman-Lord processes.
87
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A tail gas stream containing a small amount of sulfut dioxide is
eventually emitted from the Wellman-Lord unit. An acidic conden-
sate is also obtained from the Wellman-Lord unit; it is neutral-
ized with alkali and then sent for disposal.
The naphtha and gas oils are hydrotreated to produce upgraded syn-
crude. An ammoniacal wash water is produced from the hydrogena-
tion and subjected to an ammonia recovery process. ; This latter
process produces a sulfurous overhead which is sent to the Glaus
Plant for recovery of sulfur. The hydrotreatment operations con-
sume process gas, thereby generating flue gases. >The ammonia
plant does not burn any fuels. The bottoms oil is coked to yield
a gaseous overhead, naphtha oil, and gas oil which are sent to
their respective units for treatment, and a coke residue which is
disposed of with the processed shale or marketed. A small amount
of aqueous condensate is also produced and sent to the foul water
stripper. A gas-fired furnace is used for heating the, feed to the
coke drums. The flue gas from the furnace is emitted to the atmos-
phere. Hydrogen for the oil hydrotreating is generated by steam
reforming, using the treated process gas (C2 and lighter fraction).
The reforming furnaces burn fuel and generate a flue emission.
Carbon dioxide, generated as a result of reforming, is separated
from the hydrogen and is also released to the atmosphere.
The foul water condensed from the pyrolysis vapors is steam strip-
ped to remove volatile matter which is sent to the Glaus plant for
recovery of sulfur. Ammonia in the stripper overheads is conver-
ted to elemental nitrogen during incineration in the Glaus pro-
cess. The stripped water is used in processed shale moisturizing.
3.2.2 Solid Wastes |
i
Large quantities of solid waste materials will be generated over
the life of a TOSCO Plant. Solid wastes are summarized in Tables
3.2-1 [TOSCO, May 1982] and 3.2-2 [EPA-600/8-83-003, April 1983].
3.2.3 Characteristics of Solid Wastes \
Various data on TOSCO II processed shales are presented in Tables
3.2-3 to 3.2-9. Table 3.2-10 presents the composition !of TOSCO II
combined process wastewater (retort water and other wastewaters).
m^™s 3-2~1:L to 3.2-13 depicts chemical composition data on the
TOSCO ii foul water. Lab leachate data on retorted shale are
shown in Tables 3.2-14 to 3.2-16. Tables 3.2-17 and 3J2-18 depict
field leachate data for the TOSCO II retorted shale. !
89
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TABLE 3.2-1.
SUMMARY OF SOLID WASTES ESTIMATED FOR THE
TOSCO SAND WASH PROCESSING FACILITY
Waste material
Sanitary refuse
Construction debris
TOTAL
Source
Sanitary landfill
Surface mine and plant site
Surface mine and plant site
Estimated
quantity,
ton/yr
3,000
2,500
5,500
Estimated
volume ,
cubic
yards/yr
8,500
7,000
15,500
Potential hazardous wastes
Spent catalysts
Spent HDN catalyst
Guard bed catalyst
(proprietary solids)
Spent HDS catalyst
Spent ZnS catalyst
Spent FE-CR catalyst
Spent Cu-Zn catalyst
Spent reforming catalyst
Spent methanation catalyst
Spent alumina catalyst
Spent sludge (DEA
filtration)
TOTAL
Others
Separator sludge
Tank bottom sludge
Plant debris
TOTAL
Upgrading units
Upgrading units
Hydrogen unit
(hydrodesulfurizer)
Hydrogen unit
(ZnO guard bed reactor)
Hydrogen unit
(high temp Ishift converter)
Hydrogen unit
(low temp shift converter)
Hydrogen unit
(reformers)
Hydrogen unit
(methanation)
Sulfur unit
Gas recovery
API separator
Water treatment area
Mine and plant site
305
570
18.3
6.7
14.2
33.7
12.8
5.4
80
14.25
1,070.4
500
2,000
50
2,550
500
900
35.9
17.9
25.4
54.4
19.8
8.4
100
12.6
1,674.4
720
2,400
200
3,320
NOTE: This table does not list sedimentjproduced by treatment of the raw water
since the sediment may be suitable for reclamation and will be combined
with the spent shale in the spent shale moisturization procedure.
Source: TOSCO, May 1982
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90
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TABLE 3.2-2.
MAJOR WASTE PRODUCED OVER A PERIOD OF 20 YEARS
FOR TOSCO II 47,000 bbl/day PLANT WITH UPGRADING
Stream description
Quantity,
tons
Material quantity
as a percent of
total waste quantity
Raw shale runoff and leachate N.D.a
Raw shale sludge - preheat system 11.31
Processed shale sludge - Ball 0.85
elutriator
Processed shale sludge - 0.57
moisturizer
Processed shale 350.84
Stripped foul water 18.49
Compression condensate - 1.73
Wellman-Lord unit
Coke 5.26
Stripped sour water purge stream 0.75
Revegetation water 14.59
Dust suppression water 9.70
Boiler blowdown 11.04
Boiler feedwater treatment 4.81
concentrate
Cooling tower blowdown 60.31
Storm runoff 4.34
Processed shale leachate N.D.
Spent catalysts 0.005
Treated sanitary water 0.55
Sanitary water treatment sludge N.D.
Service and fire water runoff 0.63
Source water clarifier sludge 2.37
Trash, construction debris, etc. N.D.
TOTAL 498.15
Ni.D.
2.27
0.17
0.11
7Q.43
3.71
0.35
| "
1.06
0.15
2.93
1.95
2.22
0.97
12.11
0.87
N:D.
6.001
0.11
NiD.
6.13
Q. 48
N;D.
99.93
N.D. - not determined.
May be a marketable by-product.
Source: EPA-600/8-83-003, April 1983
91
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TABLE 3.2-3. PHYSICAL PROPERTIES OF TOSCO II PROCESSED SHALE
Parameter
Geometric mean size
Geometric standard deviation
Permeability
Bulk density
Solids density
Porosity
Maximum size
Minimum size
Unit
cm
—
cm2
g/cc
g/cc
-
cm
cm
_jQuantity
0.007
3.27
2.5 x 10"10
1.30
2.59
0.47
<0.476
>0. 00077
Source:
EPA-600/8-83-003, 1983
TABLE 3.2-4.
SIEVE ANALYSIS OF TOSCO II
SPENT OIL SHALE RESIDUE
Sieve
U.S. standard
No. 8
No. 16
No. 30
No. 50
No. 120
No. 200
Hydrometer
Summation
Opening, Weight retained Percent
mm in grams retained
2.38
1.19
0.595
0.297
0.125
0.074
0.0461
0.0346
0.0336
0.0268
0.0157
0.0077
0
567
390
588
1,170
784
1,134
1,125
2,043
2,882
287
69
11,038
0.00
5.14
3.53
15.33
10.60
7.10
10.28
10.20
18.50
26.10
2.60
0.62
100.00
Cumulative
percent
finer
100.00
94.86
91.33
86.00
75.40
68.30
58.02
47.82
29.32
3.22
0.62
0.00
Source: Margheim, May 1975
92
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TABLE 3.2-5. HYDRAULIC CONDUCTIVITY MEASUREMENTS
OF TOSCO II RETORTED SHALE
Moisture, Density,
Material wt. % g/cm3
TOSCO II
20.8
11.0
11.4
TOSCO IIa Dry
Permeability at various loadings"
50 psi 100 psi ' 200 psi
1.56
1.39
1.29
1.46
6.8 x
5.6 x
6.7 x
2.8 x
6.2 x 10~6
4.6 x 10~§
4.0 x 10~§
5.6 x 10'
3.9 x 10'
2.5 x 10"
Leaching columns. • \
\
Source: EPA-600/D-84-228, 1984
TABLE 3.2-6. WATER HOLDING CAPACITY3 OF TOSCO II PROCESSED
SHALES AT VARIOUS PRESSURES AND BULK DENSITIES
Sample
Pressure
14.7 psi 44.1 psi 73.5 psi 147 psi
(1 bar) (3 bar) (5 bar) (10 bar)
200 psi
(13.6 bar)
No compaction
Packed to a
BDD=1.30 g/cc
BDb=1.45 g/cc
BDb=1.60 g/cc
48.0
42.2
36.0
34.6
45.8
42.0
33.8
33.5
45.9
41.9
32.9
32.1
43.8
41.6
32.1
30.8
44.7
41.4
30.5
30.5
Table entries are moisture contents (w) expressed on a! weight 7
basis: weight of water per unit weight of dry solids.!
DBD = bulk density. i
Source: EPA-600/D-84-228, 1984 i
93
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TABLE 3.2-7. REPORTED ANALYSIS OF TOSCO II PROCESSED SHALEa
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Weight
Component percent «
Hydrogen (organic) 0^44 ™
Oxygen (organic) NR
Nitrogen (organic) 0.35 H
Carbon (organic) 4.49 •
Sulfur (total) 0.76
Na20 8.68
K20 3.28
CaO , 15.80
MgO 5.31
A1203 6.80
Si02 33.00
Fe2O3 2.52
C02 20.92 •
Loss on ignition H
at 900°C 27.60
aDry basis.
NR - not r
Source: EPA-600/D-84-228, 1984
NR - not reported.
TABLE 3.2-8. SELECTED ELEMENTAL CONCENTRATIONS IN
RAW AND RETORTED TOSCO II OIL SHALES •
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Source: Wildung and Zachara, 198:0.
I
Weight, %
Raw shale Retorted
Org C
C
H
N
S
Ca
K
Mg
Na
Si
Al
Fe
_
_
_
_
_
9.
1.
2.
1.
13.
3.
1.
8
25
6
43
0
4
89
5.
—
—
-
—
11.
1.
3.
1.
16.
4.
2.
shale
5
3
50
9
74
0
2
45
F
Sr
Ba
Mn
B
As
Cu
Cr
Pb
Ni
Zn
Mo
Se
Cd
PPM
Raw shale Retorted
1,020
640
1,310
271
110
70
48
36
30
29
72
28
4.1
1.05
1,490
780
1,580
334
146
82
62
42
41
34
105
36
4
0
shale
.9
.98
94
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TABLE 3.2-9. SOME POLYCYCLIC AROMATIC HYDROCARBONS :THAT HAVE
BEEN DETECTED IN THE BENZENE EXTRACT OF TOSCO
II SPENT SHALES ;
Compound ppb (W/W)
Benzo(a)pyrene (BaP) 28-55 >
Alkyl I (BaP) _ \
Alkyl II (BaP) _ I
Benzo(ghi)fluoranthene _ j
Benzo(e)pyrene 18-29
Perylene 3_g >
Benzo(ghi)perylene 12-24 '
Anthanthrene 3_5 ; -
Pyrene 58-1021
Fluoranthene 21-23
Benz (a) anthracene. 27-45
Triphenylene 13-34 ;
Penanthrene !
7,12-DimethyIbenz(a)anthracene - !
i
3-Methy1cho1anthrene
Coronene 5 i
Chrysene 30_35 ;
Source: Fox, July 1983
95
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•
1
1
TABLE 3.2-10. APPROXIMATE COMPOSITION OF TOSCO II COMBINED
PROCESS WASTEWATER (50,000 bb I/day upgraded fl
shale oil production)
i
Component
Ca+2
Mg+2
Na"1"1
NH4+1
Zn+2
As*5
Cr+6
C03~2
HCOs"1
S04~2
S203"2
P04"3
Cl
CN"1
Phenols
Amines
Organic acids
Neutral oils
TOTALS (rounded)
NOTE: In addition
(less than 1
Cu, Ni, Co,
Concentration ; in water (mg/L
added to spent shale
280
:iOO
670
16
5
0.015-0.3
2
j 360
100
850
90
5
570
5
315
410
1
1,330
960
6,100
to above, elements present in
mg/L) are Pb, ;Ce, Ag, Mo, Zr,
Fe, Mn, V, Ti, K, P, Al, F, B,
Source: DRI No. 5269, April 1980
96
•B
xxy/ ^
1
32
204 |
1
1.8 •
0.0045-0.09 •
0.45
109 |
32 I
261 I
1
1.8
175 1
1.81
127 g
409
295 |
n
1,870
^«w^ ^~v^— . —
Sr, Kb, Br, Se,
Li |
1
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TABLE 3.2-11.
ORGANIC CONTENT OF GAS CONDENSATE
(FOUL WATER) FOR TOSCO II ;
Component
Acids
Phenols
Bases
Neutrals
TOTAL
TOC
Concentration ,
mg/L
1,710
510
680
1,424
4,324
3,160
Mass % of
organics
39
12 •
16 !
33 !
100 1
73
Source: EPA-600/8-83-003, April 1983
TABLE 3.2-12. COMPOSITION OF FOUL WATER FOR TOSCO II
Component
NH3
H2S
C02
Organic acids
Organic phenols
Organic bases
Organic neutrals
HgO
TOTAL
a
Amount in
raw shale'
Ib/ton
0.28
0.036
0.34
0.155
0.046
0.062
0.129
—
a Foul water Coker wash,
flow water flow
Ib/hr (opm) Ib/hr (qpm)
770
99 386
935 - .
426
127
170
355
213,300 (426) 36,050 (72^
216,182 36,436
Total fpul water
Ib/hr (gpm) ma/T,
770i
485:
935j
426'
mi
170;
355 j
249,350: (498)
252,618
3,088
1,945
3,749
1,710
c -i n
ftRO
1,424
Pilot plant data obtained from Metcalf & Eddy Engineers, Octoberi1975.
Estimated from material balances based on data from Colony Development
Operation, 1974, and Whitcombe and Vawter, March 1975. '
Source EPA-600/8-83-003, April 1983 ;
97
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TABLE 3.2-13. INORGANIC SPECIES IN TOSCO II FOUL WATER
Component
Concentration ,
mg/L
Ca
„„
Mg
Na
K
++
5
0.4
C03
Cl"
CN
Si
Other components
5
0.3
12
1.3
Range, mg/L
Fe
B ;
Ce, Ag, Sr, Rb, Br, Se, As,
Zn, Cu, Ni, Mn, Ti, P, Al
Pb, Ba, Mo, Zr, Co, Cr, Li
0.1-1.0
0.01-0.1
0.001-0.01
Source: EPA-600/8-83-003, April 1983
98
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TABLE 3.2-14.
CONCENTRATIONS IN ASTM WATER SHAKE AND RCRA
EXTRACTS - TOSCO II SPENT SHALES ;
Parameter
p.H
EC
ALK
H2COS
HC03
C03
TDS
F
Cl
P04
N0a
S04
Zll
T™* j«*.
Fe
Co
Li
NH3
B
Cd
Be
Mg
P"
Si.
Mo
Mn
Ni
Na
Cu
y. -1
Al
Ca
Ba
K
Cr
Sr
Pb
Ag
TL
Se
As
Hg
Units
)—
p mhos/cm @ 25°
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
ASTM
4:1
8.69
2650
164
0.88
191
4.0
1970
20.2
9.8
<0.03
16.0
1130
0.020
0.018
<0.005
0.079
0.007
0.644
2.500
<0.001
<0.0005
35
0.18
0.8
1.56
0.053
<0.005
545
<0.001
2.15
31
0.117
8
0.025
0.53
<0.010
<0.001
0.006
<0.020
0.018
<0.001
20:1
9.0l!
740
96 i
0.24:
107
4.7 i
510
7.5
1.9
<0.03 i
19.5 !
238 i
<0.005 l
<0.005
<0.005 !
0.039 i
<0.002
0.067
0.530
-------
TABLE 3.2-15. LEACHABLE MASS AS INDICATED BY RCRA AND
ASTM WATER SHAKE SHAKE EXTRACTION TEST
FOR TOSCO II SPENT SHALES - mg/g
Parameter
Na
Ca
Mg
S04
Cl
F
B
Mo
Al
TDS
RCRA
2.620
37.44
1.620
4.580
0.444
'•*>
10.013
0.010
.0.054
163 . 6
ASTM
2.18
0.124
0.140
4.52
0.039
0.081
0.010
0.006
0.009
7.88
Source: EPA-600/D-84-228, 1984
100
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TABLE 3.2-16.
EFFLUENT CONCENTRATIONS - (TOSCO II) SPENT SHALES
CONSTANT RATE INJECTION INTO A DRY COLUMN
vt
L
0.020
0.050
0.100
0.121
0.264
0.287
0.308
0.333
0.355
0.375
0.397
0.418
0.440
0.464
0.488
0.511
0.534
0.556
0.579
0.629
0.965
1.030
1.120
1.191
1.886
2.013
2.25
Ca
545
540
520
505
495
425
410
455
435
395
415
380
345
352
320
330
300
275
265
252
120
83
90
72
26
14
13
Na
10,095
10,060
10,540
10,570
10,520
9,815
9,355
9,440
8,590
7,965
7,420
6,705
5,770
5,490
4,885
4,185
3,744
3,425
3,075
2,605
1,280
945
1,060
715
485
375
420
Cl
mg/L
178
172
176
167
154
163
152
139
133
114
100
92
84
74
61
54
49
45
32
29
19
13
16
12
7
6
7
S04
25,000
25,200
27,400
26,700
26,800
26,800
25,500
24,100
23,400
21,500
20,500
17,000
15,900
14,400
13,500
12,100
11,200
10,300
9,400
7,920
3,210
2,470
2,820
1,820
1,010
660
840
F !
27.0
29.0 !
30.0
30.2 !
39.2
36.3
34.0 :
23.2
28.4
15.9 :
17.2 i
37.8 :
32.6 ;
33.3 !
17.7 '
17.7
18.2 i
19.7 ;
18.3 -
19.1
29.2
29.5 :
29.1
30.5 :
33.5 ;
38.5 :
31.1 ;
i
pH
9.24
9.28
9.29
9.39
9.37
9.31
9.34
9.28
9.30
9.27
9.29
9.26
9.21
9.17
9.25
9.21
9.20
9.13
9.20
9.20
9.10
9.21
9.24
9.27
9.35
9.38
9.25
K = 2.8 x 10
vt ,
^— = pore volume
cm/s
Source: EPA-600/D-84-228, 1984
101
-------
TABLE 3.2-17.
LEVELS OF TRACE ELEMENTS MEASURED IN
RUNOFF AND LEACHATES FROM FIELD TEST
PLOTS OF TOSCO II RETORTED SHALE (ppm)
Runoff from
typical rain
storms
First leachate
from sloping
section of plot
Source: EPA-600/8-83-003, 1983
First leachate
from deepest
portion of bed
Be
Hg
~-—^y
Cd
Sb
Se
Mo
Co
Ni
Pb
As
Cr
Cu
Zr
B
Zn
Li
V
Mn
F
Ba
Fe
0.00002-0.00007
_
_
0.004-0.007
0.03-0.09
0.01
0.05
0.009
0.005-0.008
0.01-0.07
0.02
0.001
_
0.01-0.09
0.02-0.2
0.003
0.004
0.02-3
0.02-0.04
0.09-0.6
0.0006
0.0005
0.006
0.001-0.003
0.002-2
3-74
0.01
0.05-0.02
0.004
0.02
0.004-0.009
0.06-0.2
0.001
0.02-0.9
1
0.007-0.076
0.003-0.006
0.06-0.2
; 2-17
0.06-0.1
0.6-2
—
0.0003
0.003
0.002
2
5-74
0.001-0.04
0.2-0.6
0.003
0.08-0.2
0.004
0.06-0.2
0.003
0.02
1-3
0.07-0.8
0.004-0.1
0.06-0.5
0.006-12
0.1
1-3
102
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TABLE 3.2-18.
INORGANIC COMPOSITION OF TOSCO II LEACHATFS
DURING LABORATORY AND FIELD L?S MTER
g/L)
Al
As
Ba
Br
Ca
Cd
Cl
Co
Cr
DOC
EC ((Jmhos/cm)
F
Fe
HC03
Hg
K
Li
Mg
Mn
Mn
11U
M =
Na
Ni
NH4
NOo
N03
Oil and grease
Pb
Rb
S
Sediment
Se
Q-i
WJ.
S04
Sn
Sr
IDS
TOC
U
V
Zn
pH (units)
Bulk density, g/cm3
Solid-to-liquid ratio
Contact time
No. of replicates
Batch
(Runnells
and
Eammaili,
1981)
7.6
<0.2
5.2
<0.02
1.6
<0.02
22
<0.02
<0.01
0.03
96
76
<0.01
<0.05
8
"0.4
0.01
3.2
815
<0.02
2
3
<0.5
<0 . 1
<:L
"*
530
<0.3
0.12
625
<0.15
0.07
2185
<0.5
0.12
<0.01
9.9
0.4 g/mL 1.
17 days 17
2 4
Ldlxadlory studl£ >—
Batch
{Runnells
and
Eanmaili,
1981)
20
0.6
11.5
0.017
1.0
<0.02
52
<0.02
<0.01
<0.01
155
<0.02
<0.06
"10.6
0.2
<0.3
0.01
6.3
1865
<0.02
<2
"3
<0.5
<0 . 1
3
—
1300
<0.3
1.4
1700
<0.18
0.05
5480
<0.5
0.61
<0.01
10.3
0 g/mL
days
Column first
pore volume
(Stollenwerk,
1980 )a
<
6.02
10
1.3
470
230
0.12
0.08
73
~
26
0.24
390
77
1700
0.42
3.9
4700
<0.04
7.7
<0.2
0.1
~
<0.03
0.18
0.18
0.02
6.5
15,700
<0.06
9.8
<0.03
8.0
1.15
2.8 g/mL
46 days
4
Blender ;
(Marqheim 1975)
_
114
7.6
-
,-
1750 !
;
20 :
32 ;
27
165
5.6 •
•"
— i
_
,
_ '
,
™* ,
i
730 ;
'
1262 |
~ |
8.4
0.1 g/mL '
5 min. '
i !
(continued)
103
-------
TABLE 3.2-18 (continued)
Field Ivsimeter studies
Al
As
B
Ba
Br
Ca
Cd
Cl
Co
Cr
Cu
DOC
EC (jjmhos/cm)
Fe
HC03
Hg
"3
K
Li
Hg
Hn
Ho
Na
Ki
NH4
K03
N02
Oil and grease
Pb
P04
Kb
s
Sediment
Se
Si
S04
MW^
sn
Sr
TDS
TOC
U
V
Zn
pH (units)
Bulk density, g/cm3
Solid-to-liquid ratio
Contact time
No. of replicates
Runoff
(Margheim,
1975)
-
_
-
.
10-232
-
—
-
-
-
88-1415
-
20-25
-
<0. 06-16
-
_
>
0.2b
243-4518
2-10
o~oib b
0.01-0.09
7.4-8.15
1.36
0.79
20 min-48 hrs
Percolation
(Metcalf
and Eddy,
1975)
0.09-2
0.02-0.2
0.02-0.9
0.01-0.1
' 0.1-0.7
420-550
0.003-0.006
0.001-0.07
0.003-0.009
0.06-0.2
™
5.2-18
-------
3.3 PARAHO DIRECT HEATING MODE OIL SHALE RETORTING
3.3.1 Retorting Operation I
The Paraho retort was developed by modifying the USBM vertical
kiln technology [Shih, 1979]]. In demonstration runs at Anvil
Points, Colorado, the Paraho direct mode was used to produce more
than 100,0000 barrels of shale oil for the U.S. Navy. It was
refined to products meeting all specifications. i
A schematic diagram of the Paraho direct mode is presented in
Figure 3.3-1. The crushed shale, flowing downward, is contacted
with a countercurrent stream of hot gases having sufficient heat
content to pryolyze the kerogen in the shale. The oil is carried
out of the top of the retort as a stable mist with the1 gas stream,
and the retorted shale is removed from the bottom of the retort
through a hydraulically-operated grate. The process is continuous.
Raw oil shale, crushed to a 1/4 to 3 in. size, is spread evenly
across the top of the shale bed in the retort where it; is preheated
by the rising hot gases. Raw shale fines, less than a/4 in. are
screened from the retort feed to avoid lowering the bed porosity
and increasing the resistance to the countercurrent gas flow. The
shale moves downward by gravity through the mist formation and
preheating zone into the retorting zone where the temperature is
increased to retorting temperatures to produce gas, oil, and coke.
This residue of coke, or char, about 4.5 per cent by weight of
organic carbon, remains on the shale. As the shale continues
downward into the combustion zone, much of the heat used for
direct mode retorting is supplied by the combustion iof the coke
residue. Air, used for combustion, is mixed with recycle gas to
control flame temperatures and assure even gas distribution.
This air-gas mixture is introduced at several levels ;in the com-
bustion zone. Additional recycle gas is introduced;through the
bottom grate to cool the shale as it passes throughithe cooling
zone. The retorted shale leaves the retort at approximatley 300°F.
The hot gases are cooled by the incoming shale in the mist
formation zone to approximately 145°F to produce a stable oil mist.
The oil mist is separated from the offgas by oil mist separators
(coalescers) and an electrostatic precipitator. The oil yield
from the Paraho direct mode is about 93 percent of Fischer assay.
Part of the oil-free gas is recycled to the retdrt and the
remainder is available as plant fuel. !
3.3.2 Solid Waste \
The process operations for the Paraho direct mode process are
presented in Figure 3.3-2. This figure shows the block-flow dia-
gram for commercial-scale operations designed for the Paraho-Ute
project in Utah [Paraho, June 1982]. Raw shale mining, crushing,
screening, and stockpiling will generate dusts that will be
controlled by a variety of control devices. The raw shale dust,
105
-------
1
1
PRODUCT I
GAS
RAW SHALE
A
/
^ RETOF
MIST FORMATION ZONE
J
RETORTING ZONE
I TOP
COMBUSTION D'STRIBUT
ZONE
1 ' MID
i k DISTRIBUT
RPTCJHTCn CMAI C
nc iwn i cu OFIMI.C
COOLING ZONE
V
\ ,
y
\ ^
0 hi- GAS OIL/GAS £") *"
'T SEPARATORS ^^
1 RECYCLE GAS
PRODUCT OIL BLOWER
^ ! TOP DILUTION GAS \
TOP AIR
MID DILUTION GAS 1
OR jk
MID
AIR ** r^i AIR
AIR BLOWER
^ BOTTOM COOLING GAS 1
/
1
i
RECYCLE
, MS 1
I
I
1
1
. RETORTED SHALE •
1
Figure 3.3-1. Schematic of Paraho direct heating mode process.
Source :
DOE/EV-0086, June. 1980 1
1
1
1
106 •
-------
to
u
o
*!
g CS
g cb
o e^
o TTI
o d)
43 C
fl3 0
M *~>
(0 '
6
ca* I
V rt
en to
..
0) (1)
M O
£j M
&> 3
•H O
fa W
107
-------
I
1
collected by these devices will be disposed as a solid in the raw »
shalS fines storage area. Future plans call for the utilization
of these raw shale fines for their energy value The total raw |
shal? rejects (fines plus dust) will be about 7,500 tons per day. fl]
The Paraho direct mode retorting operation, designed to Produce «,
42?300 barrels of hydrotreated shale oil per day, will produce |
about 52,000 tons of retorted shale per day. This represents by
far, the largest solid waste stream. The retorted shale will be
disposed in an above-ground site designed to minimize water •
infiltration, runoff, and percolation. The retorted shale will be •
Sansferred from the retort to the disposal area using covered
conveyors, an enclosed silo, and covered bottom dump trucks. The H
bulk of tlie shale will be spread in 8 to 10 in. layers, wetted to |
about 10% by weight on the surface for dust control, and subjected
to light compaction. v flj
Additional water will be used to construct special water- imperious
liners and, in case of emergencies, to control excessive tempera-
tures This water, used for retorted shale dust control, liner |
construction, and emergency temperature control, will consist of a H
mixture of treated process water and river water. Water usage tor
both raw shale fines storage and retorted shale disposal will be m
about 925 gal. per minute. H
The crude shale oil, obtained from the oil recovery system, is
dewatered and subjected to on-site hydrotreating to produce a •
pipeline quality, marketable product. This hydrotreating and its W»
auxiliary processes produce a variety of spent catalysts which
constitute potential solid wastes. •
The product gas, hydrotreater off gas, and wastewater _ off gas are
subjected to ammonia and sulfur irecovery prior to being used as «
plant fuel. Sulfur recovery, will produce additional solid ||
wastes .
Sour water from oil recovery, hydrotreating, ammonia plant •
and Stretford units is treated in a wastewater treater. B
This treatment will produce additional solid wastes.
Finally, solid wastes will be generated from normal construction, §
scrap, and sanitary wastes.
The amounts of these solid waste streams and their characteristics |
have been compiled in Table 3.3-1. Although these, wastes are
presented as average annual rates, most of these materials are not
processed on a daily basis. Detailed characterization data are |
™
not available.
108
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feedstocks on offsite reclamation plants. The hazardous wastes
will be transported to an approved offsite hazardous waste
disposal area. :
The dusts (raw shale, retorted shale, surficial soils,' overburden,
and unit operations) produced from the Paraho-Ute facility will be
about 250 tons per day [Paraho, 1982]. i
i
3 .3.. 3 Characteristics of Solid Wastes I
The retorted shale produced by the Paraho direct mode operations
has been subjected to extensive characterization studies. These
retorted shale physical and chemical characteristics :are compiled
Tables 3.3-2 to 3.3-4. Detailed physical properties are available
in the literature. Due to the varied research operations
performed during most of these characterization studies, along
with variations of these studies, these data exhibit wide
variations and inevitable uncertainty. '
Since all of the water produced during the retorting and auxiliary
operations will be treated and used for dust control >(co-disposed
with the retorted shale), the characteristics of these process
waters are listed in Tables 3.3-4 to 3.3-9. At the present time,
there have been two types of process water that have been studied:
the product water (Tables 3.3-4 to 3.3-8), co-produced with the
crude shale oil and separated from oil tank bottoms; gas
condensate, (Table 3.3-9) water condensed from the iproduct gas
after oil-water separation. The data in Table 3.3-9 contain
uncertainties about the operation and may not depict actual
commercial operations. '
Tables 3.3-10 and 3.3-11 present leachate data from the RCRA and
ASTM water shake tests. Table 3.3-12 presents data from laboratory
tests in which certain pore volumes of water were passed through
a column of shale. Finally Table 3.3-13 summarizes field data
obtained from field lysimeter studies. i
It should be noted that various investigators have studied
characteristics of solid wastes for Paraho Direct process.
Only selected data are presented in the above mentioned
Tables 3.3-2 to 3.3-13.
109
-------
TABLE 3.3-1. PARAHO DIRECT SOLID WASTES:
(42,300 barrel per day plant)
Quantity & design
Solids waste case rates
Construction debris 16,000 cu yd (first
and garbage 3 years)
Raw shale fines 7,385 TPSD (max)
Retorted shale 52,235 TPSD
Wastewater treatment 2,468 TPSD (wet
sludge basis, 0.6% solids)
Sulfur, crystalline 95 TPSD
cake
Scrap and garbage 4.6 T/D
Oil filter particles 64 TPSD (50% oil)
ZnO catalyst 250 cu ft/6 mo
Lo-temp CO shift 2,600 cu ft/2 yr
catalyst
Methanator catalyst 600 cu ft/2 yr
Reformer catalyst 1,500 cu ft/2 yr
Hydrotreater catalyst (Confidential)
(ICR-106)
API separator bottoms 0.9 T/D
Air floatation unit 0.09 T/D
float
High- temp CO shift 1,750 cu ft/2 yr
catalyst
Arsenic guard bed 9,600 cu ft/6 mo
catalyst
aEstimated solids
•u
Construction only.
GNot a waste; feeds taken for future use.
^Not a waste; feeds taken for reclamation.
eOff-site disposal, EPA-approved site.
TYPES AND QUANTITIES
Thousand tons/yeara
5.3b
2,450°
17,250
4.8
31.4
1.6
21. ld
18.8;;
488°
^
25d
0 .3
0.03
32. 8e
_
720
1
1
1
Ov
1
*
1
1
I
1
1
n
.
•
Source: Paraho , June 1982 and Heistand, 1984. V
i
110
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TABLE 3.3-2. PARAHO DIRECT RETORTED SHALE CHARACTERISTICS
A.
Size Classification
'
Unified Soil Classification System !
B.
C.
.D.
Designation
Cobble
Gravel
Sand
Silt
Clay
Density
Compactive effort
ft.-lb/cu. ft.
Light, 6,200
Std. Proctor, 12,375
Heavy, 56,250
Strength
Days curing
28
60
Permeability
Compactive effort
ft.-lb/cu. ft.
Light, 6,200
Heavy, 56,250
Size, mm Weight percent
+38.1 ! 3.9
4.76 - 38.1 ; 51.8
0.074 - 4.76 ! 21.7
0.005 - 0.074 ! 20.7
-0.005 ; 1.9
i
Water Added ;
Density, Ib/cu. ft.
None Optimum, 22 wt._%
86 88
90 93
96 9!8
i
i
Compressive strength, psi
19ti
200
;
Permeability, ft/yr
Loading No | Optimum
psi water i water
50 40 6.3
100 27 1.3
200 18 i 0.8
50 35 ; 1.0
100 30 i 0.6
200 23 0.1
Source: Holtz, 1976.
Ill
-------
TABLE 3.3-3. PARAHO DIRECT RETORTED SHALE
MAJOR ELEMENTS (wt. %)
Elements
WCC
BNW1
CSM
BNW2
Battelle Paraho DRI
Aluminum 1.27 4.7 4.6 4.83
Calcium 11.5 13.4 12.0 13.4 13.3
Carbon, min. 4.95 3.73 4.42
Carbon, org. 1.86 2.39 2.31
Iron 2.03 2.45 2.31 2.56 2.40
Magnesium 4.22 4.21 4.47 4.32
Nitrogen 0.58 0.22 0.3
Potassium 0.6 1.82 1.85 1.86
Silicon 16.1 17.7 18.0 13.2
Sodium 1.48 2.24 2.36 2.19
Sulfur .. 0.48 0.77 0.8
Titanium 0.22 0.22
NOTES AND SOURCES:
WCC [Holtz, 1976]
BNW1 - weighted means, August 1977 [DOE/EV-0086, June 1980]
CSM - means, August-September 1977 [DOE/EV-0086, June 1980]
BNW2 - weighted means, November 1977 [DOE/EV-0086, June 1980]
Battelle [Battelle PNL 3830]
Paraho - means, 1977-1978 [DOE/EV-0086, June 1980]
DRI [DRI, June 1977]
112
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TABLE 3.3-4. PARAHO DIRECT RETORTED SHALE
TRACE ELEMENTS (ppm)
Elements A B C D E F
Antimony 2.8 2.9 0.7
Arsenic 59 60 44 21 59 30
Barium 625 586 737 800
Beryllium - - - 2
Boron 120 190 96 52 107 65
Bromine 0.8
-------
TABLE 3.3-4 (continued)
Elements
Manganese
Mercury
Molybdenum
Nickel
Niobium
Rubidium
Samarium
Scandium
Selenium
Strontium
Tantalum
Terbium
Thorium
Uranium
Ytterbium
Zinc
Zirconium
A
416
0.03
33
34
10.3
85
4.1
7.1
2.9
832
0.7
0.4
7.0
5.2
16
85
70
B CD E F G
332 411 600 396
0.02 0.07 0.04 0.06
43 33 12 31 16 28
35 35 38 32
7.0 7.0
97 87
3.6
7.0
1.6 3.3 0.3 3.3 0.5 2.0
935 877 800
7.5 :
1
14 15
68 71 16 82
68 71 42
NOTES AND SOURCES:
A - BNW, weighted means, August 1977 [DOE/EV-0086, June 1980]
B - CSM, means, August-September 1977 [DOE/EV-0086, June 1980]
C - BNW, weighted means, November 1977 [DOE/EV-0086, June 1980]
D - TRW, May 1977
E - Battelle PNL 3830 ;
F - DRI, June 1977
G - Stollenwork and Rumell, 1981
114
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TABLE 3.3-5.
PARAHO DIRECT PRODUCT WATER'
BULK PROPERTIES (wt. %)
Date
5/77
6/77
7/77
8/77
8/77
9/77
9/77
10/77
11/77
11/77
12/77
1/78
2/78
4/78
5/78
6/78
6/78
7/78
7/78
8/78
8/78
9/78
Other
H2S,
TOC,
a
Lab
PAR
PAR
PAR
BNW
PAR
PAR
CSM
PAR
BNW
PAR
PAR
PAR
PAR
PAR
PAR
CSM
PAR
CSM
PAR
PAR
BNW
PAR
C
5
.1
4.3
4
2.
3.
4.
4.
4.
2.
3.
5.
4.
7.
5.
4.
6.
8.
1
4
0
5
6
3
4
6
4
0
4
9
8
1
1
3
2
3
2
2
3
2
2
2
2
3
1
3
6
3
4
N
.7
.9
.1
.2
.1
.0
.9
.8
.6
.4
.0
.7
.8
.1
.9
.4
5.6
S
3
.5
4.3
5.
3.9 -
3.
1
• 5.1
5
2.7
3.
8
2.2 - 4.8
4.4
4.
4.
3.
3.
5.
2.8 -
4.
2.7 -
4.
4.
6.
5
4
9
1
7
3.1
3
2.9
3
4
5
Mm
3
CO? Alkalinity t>H
.0
3,4 1
1
2.7 !
4
3.
4
4.
3.
4.
3.
0.
4.
?
2.
3 .
3.
1.
1
o
5
9
4
5
8
7
8.8 - 8.9
8.5 - 8.6
ft R
2.6 - 7 . 8i 8.6 - 9.1
2
5 2.9 - 3.7
2
0
0
species :
<10 ppm
1.4-4.4
; so4,
Wt. %;
0.02-1
Cl, 1
.08 wt
.3-2.8
wt!
NH3, 1.4-3.6 w
8.5 - 8.9
8 fi
'r— %;
Product water - water CO-produced with oil in the gas-oil
separator.
Source: DOE/EV-0086, June 1980.
115
-------
nr
p»
^•x
K
n
*3
w
a
to
to
CO
o
^
CO
W
r-H
o
W
CO
o
rf»
*g
jy]
H
1
H
0
1
PH
B
ptj
p*i
M
Q
O
gj
S
PH
*
vo
1
CO
•
CO
a
H
w
4->
§
0
0
rrj
CO W
rH > T3
re r-H -H
4-> O i-H
O (Q O
H W W
•rH
-a
•rH
CO
11 *
0
CO
m
j*5
•g
0)
re
o
!_;
0
r—
0)
L)
i.
C
CO
CO vD
in VD
CM CM
co co
-S-
o
a>
r^ ^-i
^*
cr>
rH
rH
CO
O
0
0
in
in
rH
CM
CM
CO
O
O
in
«
CO
ro
CM
rH
V
PH
CO
D-
1
">}*
O
i-H
is i
vD
rH
0
ro
VD
co
rH
O
CO
VO
*3*
CO
O
ro
o
rH
V
CM
CO
r~
i
rH
O
VO
.-&
^ u
U 0)
H PM
rH
CO
i-H
O
O
ro
CO
rH
CO
•5"
(U
.1
4-)
rj
0
u
'***'
116
1
I
I
1
B
1
I
I
I
I
I
I
I
I
I
I
I
I
-------
•T3
(U
•H
•8
o
u
1
m
CO
§
M
«
. 4-
0
c
c.
T3
<1) V
rH > -C
U
S-4
g
cn
0)
Q
! -A
1 -H-H
; ^ C/3 t^ CO rfi CO Ixi t , [ t
MpnS WfeS (-HOHSx ! t^.
C? C? v1 S
O O O O (U
£- rH
» C- CO rH
rH
°^ O~> •* rH O
1-1 <-i r- m CM co co
V csj
CO
CO CM rH o CO
"* «* «* CO rH
rH rH ^
^M CO
V V ^
o
1
111 s s
r- t- i> co
777 ^
in v£ r- fj,
rH rH rH CO rH
' ' ' r- i
"-J rH rH 1 CM
rH rH i — | CT» i — 1
O
CO
T~H
1
VJD
CO
O
O
1
(a
o
Q
ii
u
S-,
3
o
to
117
-------
TABLE 3.3-7. PARAHO DIRECT PRODUCT WATER TRACE ELEMENTS (ppm)
6/77
PARa
Sb
As 9.0
Ba <0.5
B 30
Cd 0.3
CN 8.8
Cr
Cu 0.2
F 3.8
Pb <0 . 1
Li
Mn
Hg
Mo 3
Ni
Se <1
Ag <0.2
Sr
Th
Zn 1.0
Sources:
aDOE/EV-0086
8/77 9/77
BNW GE-T
3.1- 22.2
6.9
0.8 0.4
43 13
0.5- 2.6
0.9
1.4- 43
10.0
<0.4 0.4
0.04
0.1-
0.3
1.5- 7.9
11.0
0.2- 1.5
1.1
, June 1980.
11/77 12/77
BNWa GSRI
4.9- 6
18.2
<3 0.3
16- 0.2
43
<0.2
0.5-
11.8
16- 0.8
36
<0.3 0.3
'
0.005
o.i- ; 0.3
0.5
3.9- 0.2
8.3
<0.2
0.1- 0.5
8.5
1/78 , DRIC ang
PARa Jackson Jackson
1
9 1.5- 0.01
9.0 (5.1)
<0.5 0.1
40 0.1- 3
3.6
0.1 0.1 0.5
1.6
0.14 (0.1)
2.5
0.1 6
3.5 0.1
0.4- 1
2.9
0.2
<0.01
0.7 <0.1- 0.1
0.5
0.1-
0.4
0.4- 0.1
4.4 (0.8)
0.4 <0.1
<0.1-
0.8
0.1-
1.7
0.6 (2.0)
1
1
1
1
I
1
1
1
fl
H
1
1
1
1
I
I
1
Jackson & Jackon, 1982.
CDRI, June,
1977.
118
1
1
-------
TABLE 3.3-8. COMPOUNDS IDENTIFIED IN PARAHO
DIRECT OIL SHALE WAS.TEWATERS3 I
__________^ I
Compounds
Total Organic ;
Carbon (ppm) 41,900 \
Toluene
Phenol |
o-Cresol l
m-Cresol
p-Cresol '
C2-Phenol i
C3-Phenol '
2,6-Dimethylphenol !
3,5-Dimethylphenol i
Methoxyphenol
Naphthalene ;
2-Methylnaphthalene '
C2-Naphthalene
. 2-Methylpyridine x i
4-Methylpyridine x
2,3-Dimethylpyridine •,
2,4-Dimethylpyridine x i
2,5-Dimethylpyridine x :
2,6-Dimethylpyridine x ;
2-Ethylpyridine ;
C2-Pyridines x ;
2,4,6-Trimethylpyridine x '•.
C3-Pyridines x
4-(n-propyl)pyridine •
C4-Pyridines x ;
4-(3-pentyl)pyridine x I
C5-Pyridines x i
Aniline x
3-Methylaniline :
N-methy1aniline x ;
N,N-dimethylaniline x ;
N-ethylaniline x i
2,4-Diethylaniline x ;
N,N-diethy1aniline x :
Quinoline x |
Isoguinoline x '
(continued)
119
-------
1
I
I
TABLE 3.3-8 (continued)
Compounds fl
2-Methylquinoline x
3-Methylquinoline x «
7-Methylquinoline x U
2,4-Dimethylquinoline x m
2, 6-Dimethylquinoline
2,7-Dimethylquinoline x •
Trimethylquinoline •
Acridine x
1
aCompounds marked with "X" were
identified in each sample.
Those not marked are not •
necessarily absent. P
Source: Engineering Science,
June 1983
120
I
I
1
I
I
1
I
I
I
I
-------
TABLE 3.3-9. PARAHO DIRECT RECYCLE GAS LINE DRAIN* (ppm)
m
1
w
1"
1
.
1
1
^
1
1
I
•
1
m
I
1
Analyses
Aluminum
Arsenic
Barium
Boron
Cadmium
Calcium
Chromium
Copper
Iron
Lead
Magnesium
Mercury
Molybdenum
Potassium
Selenium
Silver
Sodium
Silicon
Zinc
Alkalinity as CaCOs
Carbonates
. Carbon, total
Carbon, organic
Chemical oxygen demand
Chloride
Cyanide
Fluoride
Hydrogen, total
Nitrogen, total
Nitrogen , ammonia
Nitrogen, nitrate
PH
Phenol
Phosphate , total
, Total suspended solids.
Total dissolved solids
Sulfur, sulfate
Sulfur, sulfide
Sulfur, total
After oil separation.
CE -TEMPO
9-09-77
10.3
<0.1
13.7
<0.03
0.2
1.5
0.2
29.5
2.4
1.8
27.6
0.1
1.6
8.9
1540
GSRI
12-13-77
0.2
0.9
0.1
<0.02
<0.01
4
0.02
0.9
2
0.04
1
4.8 ppb
0.04
0.1
<0.01
3
0.6
0.5
-0.07
Values reported are for TDS after vacuum evaporation
and after evaporation at 180°C, respectively.
Source: DOE/EV-0086, June
1980
121
PAR ;
1-04-78
i
-------
I
TABLE 3.3-10,
CONCENTRATIONS IN RCRA AND WATER SHAKE TEST
EXTRACTS - PARAHO DIRECT SPENT SHALES
Parameter
pH
EC
ALK
H2C03
HC03
C03
TDS
F
Cl
P04
N03
S04
Zn
Fe
Co
Li
V
NH3
B
Cd
Be
Mg
P
Si
Mo
Mn
Ni
Na
Cu
Al
Ca
Ba
K
Cr
Sr
Pb
Ag
Ti
Se
As
Hg
Units
mm
|jmhos/cm @ 25°
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
RCRA
9.27
4600
2593
3.5
2723
217
6220
-
28.8
<0.05
1.75
220
<0.001
0.020
0.044
0.503
0.018
0.161
0.333
<0.001
<0.0005
484
0.49
4.0
<0.05
0.016
<0.05
37
0.019
3.0
724
0.915
6.5
<0.10
8.4
<0.010
<0.002
<0.005
< 0.020
0.010
<0.001
ASTM
12.05
2800
398
<0.001
5.0
236
1425
13.5
7.2
<0.1
3.5
536
0.0003
<0.005
<0.005
0.944
0.035
2.2
0.513
<0.001
<0.0005
0.5
0.3
2.3
<0.05
0.002
<0.005
145
0.002
<0.02
266
0.157
31
<0.005
5.0
<0.01
0.003
<0.005
<0.020
<0.01
<0.001
Source: EPA-600/D-84-228, 1984
122
1
1
I
I
I
1
1
1
1
I
I
I
I
I
I
I
-------
TABLE 3.3-11.
LEACHABLE MASS AS INDICATED BY THE ASTM
PROPOSED WATER SHAKE EXTRACTION TEST FOR
PARAHO DIRECT SPENT SHALES - mg/gI
Parameter
Na
Ca
Mg
S04
Cl
F
B
Mo
Al
TDS
Paraho
0.580
1.064
0.002
2.144
0.029
0.054
0.002
0.003
0.005
5.700
Source: EPA-600/D-84-228, 1984
123
-------
TABLE 3.3-12.
COLUMN LEACHING EFFLUENT CONCENTRATIONS
FOR PARAHO DIRECT SPENT SHALES
vt
L
0.022
0.032
0.047
0.070
0.088
0.105
0.128
0.151
0.167
0.178
0.190
0.202
0.220
0.244
0.263
0.275
0.294
0.312
0.353
0.367
0.412
0.423
0.473
0.483
0.606
0.644
0.726
0.836
0.918
1.642
1.978
2.177
Ca
610
605
610
625
625
640
660
635
635
610
650
605
635
670
660
670
680
620
685
665
700
655
715
710
700
730
660
680
670
560
380
390
Na
1,500
1,445
1,385
1,305
1,280
1,165
1,095
1005
955
965
935
895
875
830
785
780
760
705
640
595
565
525
490
460
430
370
340
305
285
140
100
105
Cl
mg/L
49
47
47
42
39
35
33
31
3d
27
26
26
23
24
27
32
30
23
25
24
26
21
17
19
18
14
16
13
14
9
6
6
S04
3,840
3,805
3,735
3,695
3,525
3,485
3,320
3,270
3,180
3,185
3,175
3,085
3,060
3,065
2,975
2,930
2,890
2,890
2,815
2,605
2,615
2,530
2,500
2,395
2,390
2,290
2,205
2,105
2,045
1,500
1,000
860
F
21.0
22.2
21.9
22.0
22.6
21.0
21.0
21.5
22.0
20.4
20.9
21.4
21.1
21.8
21.8
22.5
21.9
21.6
14.2
12.4
14.4
14.5
12.7
12.8
12.5
11.5
12.4
11.4
11.4
10.2
8.1
8.3
PH
11.55
11.60
11.66
11.73
11.78
11.81
11.86
11.89
11.91
11.83
11.94
11.95
11.99
12.02
12.01
12.03
12.06
11.96
12.06
12.10
12.13
12.07
12.14
12.17
12.21
12.24
12.27
12.31
12.35
12.46
12.57
12.60
Source:
EPA-600/D-84-228, 1984
K = 4.6 x 10~4 cm/s
vt = pore volume.
L
124
I
I
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1
1
1
1
1
1
I
I
I
I
I
I
I
-------
TABLE 3.3-13.
INORGANIC COMPOSITION OF
i
i
l
i
PARAHO DIRECT
SPENT SHALE LEACHATES PRODUCED DURING
Al
As
B
Ba
Br
Ca
Cd
Cl
C03
Cr
Cu
DOC
EC, (.imhos/cm
F
Fe
HC03
K
Li
Mg
Mn
Mo
Na
Ni
NH4
N03
N02
Pb
P04
FIELD LYSIMETER STUDIES,
Lysimeter3 Percolate
Colorado Shale
(Garland
et al., 1979)
0,0005 - 0.1
0.007 - 0.08
0.5 - 3
0.03 - 0.55
M
,140 - 530
—
70 - 2,200
_
<0.001 - 0.02
<0.001 - 0.07
<2 - 400
'8,000 - 30,000
3-13
<0.01 - 0.3
1
320 - 1,230
6 - 20
0.2 - 140
<0.01 - 0.075
1.2 - 9.5
1,500 - 10,400
<0.005 - 0.04
<1 - 11
<0.1 - 6
0.001 - 4
_
-
125
(mg/L) ,
Lysimeter3 Runoff
Colorado Shale
; (Kilkelly
et al., 1981)
i '
,
1
7-10
i <4
i
1
; _ •
i
.70 - 170
\ _
!
18 - 50
i 4 _ 5
: 3 - 14
i
_
1 ~
2-5
;
i
;
I
; (continued)
i
i
i
-------
TABLE 3.3-13 (continued)
Lysimeter Percolate
Colorado Shale
(Garland
et al., 1979)
Lysimeter Runoff
Colorado Shale
(Kilkelly
et al., 1981)
1
I
I
I
1
Rb
Se
Si
S04
Sn
Sr
TDS
TOG
U
V
Zn
pH
0.0005
i 5
3,000
<0
! 4
2
<0.0003
0.1
0.005
6.9
» —
- 0.04
-16
- 20,000 5-14
.04
-13
- -
- 429
- 0.003
- 0.45
- 1.1
- 11.5
Bulk density, g/cm3
Solid-to-liquid ratio, g/mL
Contact time, min
Particle size, dso
Number of replicates
1.55
NA
aAnvil Points lysimet'er, high elevation site. Runoff values are for spring
snowmelt. The first reported value for runoff is from spent shale with
20-cm soil cover and the second value is for runoff from preleached, bare
spent shale.
Source: Fox, July 1983
126
I
I
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1
I
1
f
I
I
1
I
I
I
-------
3.4 PARAHO INDIRECT HEATING MODE OIL SHALE RETORTING!
3.4.1 Retorting Operation
in?ir? Ct m-°de of 0Peration is basically ' the same as
.
equipment. In the indirect mode, the air blower! are
^16 is eliminated
i -
The principal zones within the retort are essentially! the same a^
d 1
Because of changes in the nature and flows of the recycle eras the
^r" fE-e%h°f ^ th,S °f fgas and retorted shale Yare Sm4wha?
^?^er .for the. ^direct mode. Both the retorted shale and the
offgas temperatures average approximately 300°F.
rHT-^M- mn* ind^ect "L0^6 J138. not been tested as extensively as the
direct mode. Thus, the indirect mode data are auite limited -mrf
since the Paraho retort had not been operated for extensive^ Se?l
iods of time, much of the samples and data that have bet£obtained
expensive e^What- .uns,ta^le start-up or shutdown ?ondi?ions No
extensive engineering designs have been made for a commercial-size
facility using Paraho indirect mode retorting technology^
3.4.2 Solid Wastes ;
Although no block-flow diagram is available for the Paraho indi-
n?S^22 ?oPr0<^SS' th,e Odla9.ram Provided for the Paraho :direct mode
£oreUraeteFs19pUfrepro?eLe-dn Ulll^ ^er^d^st^
-------
RAW
SHALE
A
MIST
FORMATION
AND
PREHEATING
RETORTING
ZONE
HEATING
RESIDUE
COOLING
AND
GAS
PREHEATING
•^ jf.
V /
RESIDUE
Figure 3.4-1.
1
I
1
1
OIL MIST R
SEPARATORS U
~yw i ,
T W
\ *-OIL
OIL ; r- |
— STACK -\
"* i rAo tLliCIHOSIAIIC— ' H
T X'SpArro PRFC-IPITATOR •
HtATcn H
< „ _' i»,..-—- n(r^*vr*i c r*f\f
- . ( •* ] '' Rl OU/FR H
^ i - x_>^ - •
I
1'
-• ... rnni PP _^— . __
•" V^UUl_C.r\ n*
1
Paraho indirect mode process flow diagram. •
Source: EPA-600/7-79-075, 1979.
1
1
1
128 |
-------
As there is no information available for other solid wastes
produced by a facility based upon Paraho indirect mode technology,
a general estimate of these wastes is available from information
based upon the Paraho direct mode process (see Table 3.3-] in
Section 3.3.2). i
The product gas will experience the biggest single change between
the Paraho indirect mode and the Paraho direct mode processes.
The offgas volume decrease is largely offset by increases in con-
centrations. Thus, the overall energy (MBtu/hr),< the sulfur
production, ammonia production and the estimated rates for
catalysts, sludges, non-marketable byproducts, and 'other solid
wastes will be essentially the same. ;
3.4.3 Characteristics- of Solid Wastes !
Except for retorted shale, the characteristics of Parjaho indirect
process solid wastes should be quite similar to Paraho direct
process solid wastes. Available characterization datk for Paraho
indirect retorted shale are presented in Tables 3.4-il to 3.4-3.
Available information regarding process water characteristics
produced from the Paraho indirect mode technology is presented in
Tables 3.4-4 and 3.4-5. The limited amount of data Ion leachate
characteristics produced from experiments using retorted shale
produced by the Paraho indirect mode is presented in Table 3.4-6.
129
-------
TABLE 3.4-1.
A. Size Classification
PARAHO INDIRECT RETORTED
SHALE CHARACTERISTICS3
Unified Soil Classification System
Designation
Cobble
Gravel
Sand
Silt
Clay
B. Density
Compactive effort
ft.-lb/cu. ft.
Light, 6,200
Std. Proctor, 12,375
Heavy, 56,250
C . Strength
Days curing
28
60
120
D. Permeability
Compactive effort
ft.-lb/cu. ft.
Light, 6,200
Heavy, 56,250
ja
aHoltz, 1976.
Size, mm Weight percent
+38.1
4.76 - 38.1 52.4
0.074 - 4.76 , 31.9
0.005 - 0.074 13.3
-0.005 2.4
Water Added
Density, Ib/cu. ft.
None Optimum, 22 wt. %
89.0 93.9
94.4 98.8/99.2
102.1 105.8
Compressive strength, psi
11.8
15.3
10.8
Permeability, ft/yr
Loading No Optimum
psi water water
50 71
100 52
200 . 30
50 2 -
100 2.5
200 2.4
130
1
1
1
1
1
1
1
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TABLE 3.4-2. PARAHO INDIRECT RETORTED SHALE
CHEMICAL COMPOSITION '[
Major componenta
Ash
Min C02
Organic C
Si
Al
Fe
Ca
Mg
S
Na
K
Trace components
Be
Hg
Cd
Sb
Se
Mo
Co
Ni
Pb
As
Cr
Cu
Zr
B
Zn
V
Mn
F
Concentration, wt. %
79.4, 79.1 '
18.1 !
1.8
10.8 :
4.2 •
1.9
10.9 :
3.9
0.7 :
1.7 i
2.0 i
Concentration, ppm:
0.7 '
0.03 i
^ '
0.8
0.2 ;
10
16 :
14 i
11
18 ;
66
26
62 :
18
21
88
272
450
aWCC (Holtz), 1976
bTRW, 1977.
131
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TABLE 3.4-3.
COMPOSITION OF PARAHO INDIRECT
SPENT OIL SHALES
Component
Weight, %
Si02
CaO
MgO
A1203
Fe2O3
Na20
K2O
S03
Mineral C02
Organic C
Inorganic C
23.1
15.3
6.5
8.0
2.7
2.3
2.4
0.7
18.1
1.84
4.95
Texture
pH
silty gravel
10.9
Source: EPA-600/2-80-205a,
1980
132
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TABLE 3.4-4. PARAHO INDIRECT PROCESS WATER COMPOSITION
Element
Lead
Mercury
Cesium
Barium
Molybdenum
Strontium
Bromine
Selenium
Arsenic
Gallium
Zinc
Copper
Nickel
Cobalt
Germanium
Iron
Manganese
Chromium
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Boron
Lithium
Mg/mL
0.2
<0.01
0.01
2.0
0.1
3.0
0.009
0.1
1.0
<0.02
0.4
0.2
0.2
<0.04
<0.05
5.0
0.3
0.3
0.03
0.3
<0.05
>10
>10
2.0
>10
5.0
>10
0.8
>10
>10
7
5.0
1.0
Source: EPA-600/2-80-205a,
1980
133
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I
„. .. „
FROM THE PARAHO INDIRECT PROCESS
Parameter mg/L
I
Cations: H
Calcium 39.16 I
Magnesium <0.1
Sodium 0.29 m
Potassium 0.18 I
Ammonium, NH4 13,440-calc.
Anions: I
Carbonates 3,030-calc. •
Bicarbonates 6,280-calc.
Sulfate 1.65 H
Sulfide 390 I
Chloride TR
Fluoride 0.10 H
Nitrate 1.0 •
Nitrite <0.002 •
Nutrients: ffi
NH3-N 16,800-calc. H
Phosphate, total 0.75
Gross parameters: I
BOD 4,850
COD 17,100 _
TOC 9,800-36,900 •
TIC 1,600 •
Oil and grease 33.3
Solids, total 429 •
Solids, upon H
evaporation 406
Total alkalinity 12,900 M
Hardness 98-calc. I
Phenols 42
pH 9.5 •
Source: EPA-600/2-80-205a, 1980 •
I
134
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TABLE 3.4-6.
COMPOSITION OF BATCH GENERATED LEACHATE
FROM PARAHO INDIRECT RETORTED SHALE
Element
Al
Ca
Fe
K
Mg
Si
Na
S04
C03
HC03
Cl
PH
mg/L
<0.03
4.3
0.04
3.3
1.8
8.5
65
25
1.4
<0.1
44
10.9
Source: Holtz, 1976
135
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3.5 OCCIDENTAL MODIFIED IN SITU OIL SHALE RETORTING
3.5.1 Retorting Operation
The recovery of shale oil by the Occidental modified in situ (MIS)
process involves the underground- pyrolysis of large chambers of
rubblized shale [Fox, July 1983]. These chambers are constructed
by mining out about 20% of the volume of the retort and blasting
the balance so that the entire chamber is filled with fractured
rock. A commercial-sized retort will measure about 333 ft by
166 ft in cross section and 400 ft high. Oil is recovered from
such a retort, shown in Figure 3.5-1, by initiating combustion at
the top of the retort with an external fuel supply and propagating
the^ reaction zone, which consists of a pyrolysis zone and a
trailing combustion zone, down the bed of rubblized with input
gas. The volatile hydrocarbons condense in the cool region at the
bottom of the retort and are pumped to the surface.
INPUT GAS
Overburden
EXIT GAS
Pillar =
,V BURNED OUT ZONE •"..•• =
ii COMBUSTION ZONE
. * •• s * .,v f '.., '..•'.
'-••*.:'"PYROLYSi'10N E|f
.•;. CONDENSATION ZONE" .' =
OIL
0 500 1000
Temperature (°C)
XBL 612-623!
Figure 3.5-1. Schematic of the Occidental modified
in situ retorting process.
Source: Fox, July 1983.
Occidental has tested eight experimental retorts at Logan Wash,
Colorado. Leaching studies have been conducted on materials from
Retort 3. Retort 3 was operated between February and July of
1975 in air-recycle gas mode. Yield was around 60% Fischer Assay.
This retort was cored in December 1978, and the spent shales have
been characterized and subjected to leaching studies.
Figure 3.5-2 presents a conceptual illustration of a rubblized MIS
retort [EPA-600/8-83-004, 1983]. In the operation of an MIS
retort, air and steam (streams 37 and 70) are admitted at the top
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through several openings which connect the retort air level to the
top of the rubblized shale. The steam is produced from process
waters, using kettle evaporators and Lurgi waste heat recovery B
boilers. Steam promotes the water/gas reaction and provides a •
means of controlling the combustion zone temperature. Retort
start-up is accomplished through introduction of hot inert gas. •
When the temperature of the broken rock at the top of the retort g|
is high enough, air is introduced to initiate combustion.
An operating retort contains four major zones. In the first, or •
preheat zone, the air/steam feed gas is preheated through contact m
with hot processed shale. The heated gas then reaches a combus-
tion zone where oxygen is consumed by burning residual carbon in B
the processed shale. Below the combustion zone is the retorting B
zone where hot combustion gases heat the raw shale rubble to ap-
proximately 900°F, and the retorting process commences. During m
retorting, the kerogen is pyrolyzed to produce gas, oil and oil g
vapor, and solid residue with residual carbon. The shale oil
moves downward by gravity and precedes the advancing combustion
front by six to ten feet. In the final zone, the combustion and •
retorting gases are cooled as they flow downward, condensing most •
of the vaporized oil. During the early stages of the burn, when
the rock is still cool, some water is also condensed. H
Oil, water, and retort gas exit the bottom of the MIS retort and
undergo separation in a three-phase separation sump located under- «
ground. Heavy oils (stream 39) obtained from this sump are pumped •
to storage. The retort water (stream 41) is also pumped to the
surface and steam stripped to remove volatile compounds. The
overhead vapors (stream 43) are sent to the Phosam-W unit, while •
the stripped water is used in the production of low-quality steam H
to be injected back into the MIS retorts. The retort gas mixture
(stream 38) consists of light hydrocarbons from shale pyrolysis, n
carbon dioxide and water vapor from the combustion of carbonaceous ||
residue, water vapor from steam injection, carbon dioxide from the
decomposition of inorganic carbonate (primarily dolomite and cal- _.
cite), and nitrogen from the combustion air. In addition, the gas B
contains ammonia and sulfur-bearing gaseous products such as H2S "
and COS. The gases are drawn to the surface by large blowers and
fed to an absorption/cooling oil recovery unit. •
3.5.2 Solid Wastes
Table 3.5-1 presents an inventory of solid and liquid waste Q
streams. From a commercial size development with 229 retorts
operating simultaneously, each 120 ft x 120 ft x 250 ft and
containing oil shale with an average Fischer assay of 15 gpt, the B
Occidental modified in-situ process will generate among other •
products the following: Mined rock - 56,685 tons per calender
day; Wastewater - 1,458 gpm [EPA-6'00/7-79-075, 1979]. B
I
138
I
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3.5.3 Characteristics of Solid Wastes !
Compositions of solid and liquid waste streams are shown in
Table 3.5-2. Available data on spent shale are presented in
Tables 3.5-3 and 3.5-4. Analytical data on core samples are given
in Tables 3.5-5 and 3.5-6. Data on steam boiler blowdown and
wastewaters are shown in Tables 3.5-7 to 3.5-9. Finally, various
leachate data are presented in Tables 3.5-10 to 3.5-12.
139
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