United States
Environmental Protection
Office of
Research and
Industrial Environmental Research
Cincinnati, Ohio 45268
July 1977
            Research and Development
            Program Report


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:

      1.  Environmental Health Effects Research
      2  Environmental Protection Technology
      3.  Ecological Research
      4  Environmental Monitoring
      5.  Socioeconomic Environmental Studies
      6.  Scientific and Technical Assessment Reports (STAR)
      7.  Interagency Energy-Environment Research and Development
      8.  "Special" Reports
      9.  Miscellaneous Reports

This report has been assigned to the  INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research  and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of. and development of. control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service. Springfield. Virginia 22161.

                                            July 1977


         K. W. Crawford, C. H. Prien
  L. B. Baboolal, C. C. Sh1h, and A. A. Lee

   TRW Environmental Engineering Division
       Redondo Beach, California 90278


          Denver Research Institute
           Denver, Colorado 80210
             Contract 68-02-1881
               Project Officer

            Thomas J. Powers III
Energy Systems Environmental Control Division
Industrial Environmental Research Laboratory
           Cincinnati, Ohio 45268
           CINCINNATI, OHIO 45268

     This report has been reviewed  by the  Industrial  Environmental  Research
Laboratory, U.S. Environmental  Protection  Agency,  Cincinnati,  Ohio, and ap-
proved for publication.   Approval does not signify that the contents neces-
sarily reflect the views  and  policies of the  U.S.  Environmental  Protection
Agency, nor does mention  of trade names  or commercial  products constitute
endorsement or recommendations  for  use.

     When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on our
health often require that new and increasingly more efficient pollution con-
trol methods be used.  The Industrial Environmental Research Laboratory -
Cincinnati (lERL-Ci) assists in developing and demonstrating new and improved
methodologies that will meet these needs both efficiently and economically.

     The material presented in this report summarizes the status of oil shale
technologies and development activities, the nature and sources of pollution
from oil shale development and their potential impacts on the physical envi-
ronment.  This information has been collected from related on-going industrial
and government activities to provide a consolidated data source for planners
and researchers concerned with oil shale development, to identify data and
research gaps so that priorities for subsequent efforts in this area can be
defined, and to establish the baseline material from which later environ-
mental assessments can be made and related pollution control methods can be
developed.  Further information can be obtained from the Energy Systems Envi-
ronmental Control Division, lERL-Cincinnati.
                                      David G. Stephan
                        Industrial Environmental Research Laboratory


     This Preliminary Environmental Assessment has been assembled from a wide
variety of governmental  and industrial  data sources,  including the Detailed
Development Plans filed  by federal  lease tract developers  as recently as June
1976.  This document reviews potential  environmental  impacts that could result
from direct or indirect  discharge of air, water,  and  solid wastes, and some
of the environmental control technology which  has been  developed or proposed.
Secondary pollution effects, such as those stemming from population influx,
are not considered.  The primary purpose of this  document  is the identifica-
tion of important environmental  research areas in oil shale technology, and
for setting research priorities.

     Chapter 1 is an introduction and summary  of  the  Preliminary Environmental
Assessment (PEA).  Chapter 2 presents a brief  review  of oil  shale extraction
and retorting technologies.   The discussion includes  the history, technology,
development plans, and environmental  programs  of  the  major contenders for
commercial development.   Chapter 3 reviews the sources  and nature of pollution
from shale oil operations including the pollutant inventories presented by the
various developers for air,  liquid and  solid waste emissions.  Chapter 4 des-
cribes the baseline environmental  conditions and  discusses potential  environ-
mental impacts of the various technologies and developments.   Chapter 5 is a
brief review of shale oil  upgrading and refining  experiences to date, and of
waste streams and hazards associated with refining and  handling of shale oil.
Chapter 6 is a summary of monitoring projects  and studies  which have been or
are being conducted in the Piceance and Uinta  Basins, and  which are relevant
to oil shale development.

     This report was submitted in partial  fulfillment of Contract 68-02-1881
by TRW Environmental Engineering Division under the sponsorship of the U.S.
Environmental Protection Agency.   This  report  covers  the period of June 1,
1975 through June 1, 1976, and work is  continuing toward the final  project
report "Assessment of the Environmental Impacts from  Oil Shale Development"
to be published in mid-1977.


TABLES 	   x

      2.1    The Extraction and Preparation of Oil Shale for Retorting.  .   7
          2.1.1   History	   7
          2.1.2   Underground Room and Pillar Mining 	  10
          2.1.3   Open Pft Mining	14
          2.1.4   Mining for In-Situ Retorting 	  19
          2.1.5   Advanced Mining Methods   	  19
          2.1.6   Storage, Transport and Crushing of Oil Shale 	  22
      2.2   Surface Retorting Technologies and Development Plans ....  24
          2.2.1   TOSCO I! Retorttng Process 	  24
          2.2.2   The Paraho Processes	27
          2.2.3   The Union Oil Process	33
          2.2.4   Superior Oil Process 	  36
          2.2.5   Lurgf-Ruhrgas Process  	  40
      2.3   Commercial Development Plans Employing In^Situ Technology  .  41
          2.3.1   The Occidental  Modified In-Situ Process  	  41
          2.3.2   Western Oil Shale Corporation (WESTCO) 	  46
          2.3.3   Geokinetics, Inc	46
          2.3.4   ERDA In-Situ Research, Development and Demonstration
                  Project	46

      2.4   Federal Oil Shale Lease Tracts 	   46
          2.4.1   Tract C-a - Rio Blanco Oil  Shale Project (RBOSP)  ...   48
          2.4.2   Tract C-b - Roxana	   52.
          2.4.3   Tracts U-a/U-b - White River Shale Project (WRSP).  .  .   53
          2.4.4   Federal In-Situ Lease Tract Nominations  	   55
      3.1   Atmospheric Emissions  	   60
          3.1.1   A Comparison of Retorting Processes for Potential
                  Emissions	   62
          3.1.2   Process Emissions Inventories  	   67
          3.1.3   Fugitive Emissions Inventories 	   73
      3.2   Water Requirements and Wastewater Processing 	   76
          3.2.1   Water Requirement Estimates for Oil Shale Development    76
          3.2.2   Sources and Nature of Wastewater 	   78
          3.2.3   Specific Process Wastewaters 	   80
          3.2.4   Process Wastewater Treatment 	   83
      3.3   Solid Wastes Associated with Oil  Shale Extraction and
            Processing	   86
          3.3.1   Raw Shale Fines	   86
          3.3.2   Retorted Shales	   87
          3.3.3   Other Shale Derived Solid Wastes 	   91
          3.3.4   Non-Shale Solid Wastes 	   91
          3.3.5   Inventory of Solid Wastes  	   93
      4.1   Air Quality Impacts of Oil  Shale  Extraction and Processing  .   99
          4.1.1   Baseline Characterization of Meteorology and Air
                  Quality	   99
          4.1.2   Review of Model Application to Oil  Shale Related
                  Emissions in Colorado and Utah	103
          4.1.3   Assessment of Models and Model Concepts Applied to Oil
                  Shale Emissions	108
          4.1.4   Comparison of Modeling Results 	  109

     4.2    Impacts on Water Quality and Hydrology  	   113
         4.2.1   Existing Surface Water Quality and Flow   	   113
        Upper  Colorado River  Basin  	   113
        Piceance Creek Basin  	   113
        Uinta  Basin   	   116
         4.2.2   Existing Ground Water Quality and Yields  	   117
        Piceance Creek Basin  	   117
        Uinta  Basin   	   122
         4.2.3   Effects of Water Withdrawal by Oil  Shale  Development
                 on  the White and Colorado  Rivers  	   122
         4.2.4   Effects of Development on  Local Surface and
                 Groundwater	   124
      4.3   Potential Impacts Associated with  Solid Waste Disposal ...  131
          4.3.1   Solid Waste Disposal Plans for Oil  Shale Development .  131
          4.3.2   Potential Hazards and Pollution  Problems 	  140
          4.3.3   Experience in Establishing Vegetative Cover on Retort
                  Shale Piles	141
      5.1   Upgrading and Refining of  Shale Oil  	148
          5.1.1   Upgrading Plans for  Oil  Shale Developments 	  148
          5.1.2   Experiences in Oil Shale Refining	148
      5.2   Waste Streams and Hazards  Associated with Refining and
            Handling of Shale Oil  	  153
          5.2.1   Waste Streams	153
          5.2.2   Carcinogenic Properties of Crude Shale Oils and
                  Refined Products 	  153
      5.3   Emissions from the Combustion of Shale Oil  Products  ....  157
      6.1   Monitoring and Environmental  Studies by Private Industry,
            Universities, and certain  Government Agencies  	  160
      6.2   Environmental  Programs of  the Federal   Prototype Oil Shale
            Leasing Program  	  160
          6.2.1   Geotechnical  Data Gathering  	  167
          6.2.2   Environmental  Baseline Programs  	  168
          6.2.3   Continuous Monitoring Programs 	  170

6.3   Comments on Monitoring Programs  	  170
    6.3.1   Air Quality and Meteorological Monitoring  	  171
    6.3.2   Surface and Ground Water Monitoring  	  171
    6.3.3   Solid Wastes	171
    6.3.4   Revegetation	172

2-1   Locations of Potential Oil Shale Developments - Piceance
      Basin, Colorado 	     8
2-2   Locations of Potential Oil Shale Developments - Uinta Basin, Utah   9
2-3   Perspective Drawing of Oil Shale Room and Pillar Mining ....    11
2-4   Vee-Cut Blasting Pattern for Underground Oil Shale Mining ...    13
2-5   Typical Bench Blasting Pattern Viewed from Above - Tract C-a  .    15
2-6   Cross Section of Typical Bench Blasting Pattern Viewed from the
      Side	    16
2-7   Typical Bench Development Viewed from Above - Tract C-a ....    17
2-8   30-Year Pit Cross Section - Tract C-a 	    18
2-9   Schematic of Occidental Modified In-Situ Mining Method  ....    20
2-10  Oil Shale Feed Preparation Schematic	    21
2-11  Schematic of the TOSCO II Retorting Process 	    25
2-12  Schematic of Paraho Direct Mode 	    29
2-13  Schematic of Paraho Indirect Mode 	    30
2-14  Side View of Union B Retort	    31
2-15  Flow Diagram for Union B Retorting Process  	    34
2-16  Top View of Superior Retort	    37
2-17  Cross Section View of the Superior Retort 	    38
2-18  Schematic of the Occidental Modified In-Situ Process  	    43
2-19  Flame Front Movement in the Occidental Modified In-Situ Process    44

4-1   Location of Selected Stream Gaging Stations and Oil Shale
      Developments  	   115
4-2   Aerial View of Colony Development Operation Disposal Site -
      Davis Gulch	   132
4-3   Tract C-a Conceptual Phase I Solid Waste Disposal Plan  ....   134
4-4   Tract C-a Conceptual Phase II Solid Waste Disposal Plan ....   135
4-5   Schematic of Union Oil Company Retorted Shale Disposal Plan for
      Operations at Parachute Creek Site	   136
4-6   Backfilling of Mined Out Shale Zone with Processed Shale -
      Superior Oil Company  	   139


2-1    Results of Federal Oil Shale Lease Offerings 	   47
2-2    Tract C-a - Rio Blanco Oil Shale Project Summary	   49
2-3    Tract C-b - Roxana Oil Shale Project Summary 	   51
2-4    Tracts U-a/U-b - White River Shale Project Summary 	   54

3-1    The Sources and Nature of Atmospheric Emissions from Oil Shale
       Extraction and Processing  	   61
3-2    Comparison of Total Sulfur in Raw Retort Gases 	   63
3-3    Comparison of TOSCO II Emissions Inventories (8000 m3/day)
       (50,000 bbls/day)	   69
3-4    Lease Tract C-a Phase II Emissions Inventory (56,000 bbls/day)  .   70
3-5    Lease Tracts U-a/U-b Emissions Inventory (50,000 bbls/day) ...   71
3-6    Union B Fuel Gas Combustion Emissions	   72
3-7    Summary of Air Pollution Control Technology for Oil Shale
       Preparation and Retorting, and Shale Oil  Upgrading 	   74
3-8    Potential Fugitive Dust Emissions  	   75
3-9    Estimates of Process Water Requirements for Full  Scale Oil Shale
       Production (m3 of water needed per m3 of oil produced) 	   77
3-10   Water Consumption Requirements for Unit Processes Associated
       with Oil Shale Processing	   77
3-11   Approximate Composition of TOSCO II Combined Process Wastewater
       (8000 nr/day upgraded shale oil production)  	   81
3-12   Paraho (GCR) Process Wastewater Analysis 	   82
3-13   Approximate Composition and Flow Rates for Selected Wastewater
       Streams Lease Tracts U-a/U-b (Phase III, 8000 m3 upgraded shale
       oil/day)	   84

3-14   Ash Composition of Typical Retorted Oil Shales 	   88
3-15   Properties of Retorted Shales  	
3-16   Inorganic Ions Leachable from Freshly Retorted Shales (kgs/tonne)
       Based on Laboratory Tests  	   go
3-17   Levels of Benzo(a)pyrene (BaP) Reported in Selected Natural and
       Industrial Materials

3-18   Typical Composition of Shale Oil  Coke  .............    93
3-19   Major Solid Wastes from TOSCO II  Processing  ..........    95
3-20   Solid Wastes Generated During Construction and Operation of Shale
       Oil Facilities at Tracts U-a/U-b  - Phase IV  ..........    96

 4-1    Existing  Air Quality Data  Summary for Federal  Oil  Shale  Lease
       Tracts  .............................  102
 4-2    A Comparison of Air Pollutant Emissions  (kg per hour)  Used  in
       Modeling  Studies ........................  110
 4-3    Comparison of Modeling Results with Applicable Standards ....  112
 4-4    Water and Dissolved Solids Discharge at  Selected Stations in
       Upper Colorado River Basin ...................  114
 4-5    Summary of Piceance and Yellow Creek Streamflow Records   ....  116
 4-6    Summary of Roan and Parachute Creek Streamflow Records .....  117
 4-7    Maximum Values for Dissolved Constituents  of Surface Waters on
       and Around Federal  Oil  Shale Lease Tracts   ...........  118
 4-8    Mean Values for Dissolved  Constituents in  Ground Water on Federal
       Oil  Shale Lease Tracts C-a and C-b ...............  121

 5-1    Summary of Crude Shale Oil Properties  .............  150
 5-2    Summary of "On Site" Upgrading of Shale  Oil Planned at Develop-
       ment Sites ...........................  152
 5-3    Comparable Carcinogenic Potency of Complex Mixtures .......
6-1   Summary of Meteorology and Air Quality Monitoring and Studies.  .
6-2   Summary of Surface  and Ground Water Monitoring Activities   ...  152
6-3   Summary of Spent  Shale/Solid Waste Disposal  Projects  ......  164
6-4   Summary of Revegetation  Projects  ................  165

    1 Btu = 2.929 x 1(H kilowatt hour  (kWh)
    1 kcal = .397 Btu
    1 inch = 2.54 centimeter (cm)
    1 foot - 0.3048 meter (m)
    1 yard - 0.9144 meter (m)
    1 mile - 1.609 kilometer (km)
    1 pound = 0.4536 kilogram  (kg)
    1 ton (short)  = 9.072  x  Ifl2  kilogram  (kg)
    1 tonne = 1  metric ton (tonne)
    1 acre = 0.407 hectare (ha)
    1 acre = 4.047 x 1Q3 square meter  Cm2)
    1 square foot = 9.290 x 10"2  square meter  (m2)
    1 square mile =2.59 square kilometer  (km)2
    1 cubic foot = 2.832 x 10~2 cubic  meter  (m3)
    1 gallon = 3.785 x 10~3 cubic meter  (m3)
    1 barrel = 0.1590 cubic meter (m3) = 42  U.S.  gallons
    1 acre-foot = 1234 cubic meters
    1 cubic yard = .764 cubic meter  (m3)
Conversions especially important  in  this report:
       Shale oil1 m3 = 6.3 barrels  =0.93  tonnes  crude  shale oil
       Volumetric flow rates1  m3/sec  =  2120 ft3/min
       Emission factors1 lb/106 Btu =  .1145 kg/kcal
       Heating value890 kcal/m3 = 100 Btu/SCF
    0   Oil shale yield0.125 m3/tonne  =  30 gal/ton
       Water resources1234 m3  = 1 acre-foot

                        1.0  INTRODUCTION AND SUMMARY

     Commercial interest in the extraction and processing of oil shale has
been shown for several decades.  A viable oil shale industry has been "about
to start" several times in this century, but each time economic, technical,
political, or legal roadblocks have postponed actual development.  More re-
cently, the impetus to develop domestic energy sources has prompted many new
government and privately sponsored oil shale activities.  This apparent in-
creased interest in oil shale has also led to increased concern about envi-
ronmental impacts which might be associated with large scale extraction and
processing operations.

     The oil shale area of northwestern Colorado and northeastern Wyoming has
no large human population or industrial base at present, and thus air and
water quality are not unduly influenced by human activities.  Large-scale con-
struction and operation of oil shale facilities, however, will result in direct
atmospheric emissions, and wastewater and solid waste generation.  Further,
an influx of shale industry employees and support services population will
create numerous indirect impacts on air, water, and land resources.

     The Environmental Protection Agency is empowered to encourage and promote
the development of pollution control technology for industrial waste streams.
Such technology includes not only "add on" devices for minimizing emissions
and effluents, but also "in house" and management techniques for controlling
pollution or averting undesirable environmental effects of industrial activi-
ties.  To aid in defining the nedd and priorities for control of waste streams
associated with oil shale development, EPA has requested the preparation of
this preliminary environmental assessment.  Included are a summary of current
oil shale technologies and development activities, a review of the properties,
sources and quantities of wastes which may be generated by these technologies
and activities, a discussion of potential environmental impacts and hazards
resulting from oil shale development, and discussions of pollution control
technology and/or management practices which have been developed or are planned
for commercial operations.  Some of the current baseline environmental moni-
toring and control technology development projects are discussed and briefly
evaluated.  Indirect impacts resulting from population influx into the oil
shale region are not discussed in this report, although the relative importance
of such impacts should not be minimized.  The preliminary environmental assess-
ment will be updated in the final assessment report which will be submitted by
TRW/DRI to EPA in June of 1977.

     Several oil shale mining and retorting technologies are approaching the
commercial state of development.  Oil shale has been mined on a modest scale
for over three decades.  To date, however, mining has been underground and con-
fined to the southern end of the Piceance Basin, with adit access at the

Mahogany zone outcrop.  Current development plans for larger scale oil  shale
extraction call for both room and pillar mining and for open pit mining.  In-
dividual developers envision the mining of from 10,000 to over 100,000 tonnes
of oil shale per day.

     The private sector has developed both above-ground and in-situ retorting
technologies, and several companies plan to apply these technologies on pri-
vately owned oil shale lands in Colorado and Utah.   Similar technologies are
likely to be utilized on federally leased oil shale lands.   Crude or upgraded
shale oil production rates of 1200 to over 8000 mj (8000 to over 50,000 bbls)
per day are envisioned.  Aboveground retorting processes which have reached
the stage of industrial interest in the United States may be divided into three
classes based upon the way heat is supplied to the retorting process.  These
categories include retorts using (a) recycled hot solids (e.g., TOSCO II and
Lurgi-Ruhrgas,  (b) an internal  combustion zone within the retort (e.g., Paraho
Direct Mode, Superior Circular Grate), or (c) an external, fuel-fired furnace
or gasifier (Union Retort B, Paraho Indirect Mode).  The major U.S. retorting
processes which employ these various modes of heat transfer are individually
discussed in Chapter 2 of this report.  Although private developers such as
the Colony Development Operation, Union Oil Company, and the Paraho Group con-
sider their respective retorting technologies to be demonstrated at the pilot
and/or prototype stage,full scale commercial  operations are not currently
planned or such plans have been  postponed.  Among the reasons cited for the
cautious approach to commercial  development are the lack of a definite fed-
eral energy policy, uncertainties regarding both production costs and product
prices, questions about the ability to meet ambient air quality standards,
and the threat of environmental  litigation.

     Although in-situ extraction of shale oil has attracted research interest
for over 20 years, only recently has commercial interest emerged.  The Occi-
dental  Petroleum Corporation has developed a modified in-situ process and
claims  that commercial production is technically and economically possible.
Several other private interests, as well as the Laramie Energy Research Center
CERDA), are supporting or have proposed in-situ extraction projects.

     Chapter 2 includes a summary of the development plans for the federal
lease tracts in Colorado and Utah.  The developers of Tracts C-a, C-b, and U-a/
U-b have recently submitted Detailed Development Plans for their respective
tracts to the Area Oil Shale Supervisor (AOSS), as required by the lease stip-
ulations.  Each lessee has also, however, requested suspension of certain lease
conditions, including tract development requirements for the immediate future.
The Department of the Interior has recently granted all of these suspension
requests for a period of one year.

     In 1975 the Department of the Interior accepted nominations of tracts to
be leased for in-situ development.  Four of the tracts nominated by industry
were recommended by a special committee of the Oil  Shale Environmental Advisory
Panel.  The Secretary of the Interior has not acted to date on the recommenda-
tions.  An environmental impact statement is currently in preparation.

     Chapter 3 of the report is a summary of the types, sources, properties,
and quantities of wastes which may be generated during the extraction and

processing of oil shale.  Of the atmospheric emissions from oil shale process-
ing activities, the major source of S02 NOX, and CO is fuel combustion for
process heat.  S02 is also emitted in the tail gases of sulfur recovery opera-
tions.  The use of fuel oils in mobile equipment and in explosives results in
emissions of CO and NOx.  Hydrocarbons are present in both combustion emis-
sions and in product storage tank vapors.  Emissions of particulate matter
can result from blasting, raw and retorted shale handling and disposal, shale
dust in flue gases, fuel combustion, and site activities which generate fugi-
tive dust.

     Emissions of hazardous substances may occur during the extraction and
processing of oil shale.  Silica (quartz) may be present in dust derived from
oil shale and associated rocks and in fugitive dust.  Particulate emissions
from fuel combustion and fugitive dust from retorted shale handling and dis-
posal could contain small quantities of hazardous organic material and certain
trace metals.  Retorted shale may release ammonia, hydrogen sulfide, and vola-
tile organics during moisturizing and subsequent cooling.  Catalyst materials
may release metals to the atmosphere during regeneration, handling, or final

     The quantities of atmospheric emissions associated with shale processing
depend on the size of the operation, the type of mining and retorting tech-
nology employed, the extent of on-site upgrading, and the degree of emissions
control  practiced.  Emissions inventories for the Colony Development Operation
and for Tracts C-a, C-b, U-a/U-b are reported in Section 3.1.  Less complete
emissions data are presented for the proposed Union Oil Company and Occidental
Oil Company operations, and for fugitive dusts which may result from site use

     Water is a necessary resource for the development of an oil shale indus-
try.  Water would be used for cooling, dust control,  gas cleaning and pro-
cess emissions control, and for moisturizing retorted shale.  As much as 3.7
m3 of water is required for the production of 1 m3 of upgraded shale oil.
Unlike their counterparts in the petroleum, by-product coke, and related
industries, oil shale developers do not plan to discharge wastewater directly
to local surface water.  Rather, process waters would be reused for purposes
requiring progressively lower quality water within the plant, and finally
for moisturizing retorted shale.

     The sources and properties of process wastewaters are discussed in Sec-
tion 3.2.  Generally, the characteristics of these wastewaters are similar to
those encountered in petroleum refining - high dissolved and suspended solids,
and high chemical and biochemical oxygen demand.  Oil and grease, reduced
nitrogen and sulfur containing compounds, and organic compounds such as
phenolics and carboxylic acids are likely to be present in such waters.  Con-
stituents in wastewater applied to retorted shale may be an indirect source
of water pollution if mobilization occurs via erosion, runoff, or leaching
of a retorted shale disposal pile.

     The major solid wastes from oil shale processing are raw shale fines from
crushing and dust control, and the processed shale remaining after retorting.
In an integrated facility, these constitute more than 95 percent of the solids

requiring disposal.  The quantity and nature of other solids to be discarded
depend primarily upon the extent of upgrading of the crude shale oil  which
is carried out in conjunction with the retorting operations, and the  solid
wastes from auxiliary operations.  The latter might include shale coke from
delayed coking; spent catalysts from hydrotreating, sulfur recovery,  and
arsenic removal; lime and alum sludges from water treatment; spent activated
carbon and diatomaceous earth from oil or gas treatment.   The quantities of
these wastes which may be generated by various developments are tabulated in
Section 3.3.

     With many retorting technologies (e.g., TOSCO II and  Union B) an organic
residue remains on the oil  shale after retorting.   Other technologies  (e.g.,
Paraho Direct Mode) have been designed to burn most organic material  as part
of the retorting step.  Retorted shale exhibits cement-like properties if most
of the carbonaceous material has been burned off during retorting, and such
properties may be used to advantage in creating an impermeable disposal pile.
On the other hand, carbonaceous retorted shales do not generally exhibit such
cementing properties.  Inorganic constituents of both burned and carbonaceous
retorted shales are partially water soluble, and may be mobilized by  water
run-off or by percolation through a disposal pile.   Carbonaceous retorted
shales contain organic substances which may also present a hazard during hand-
ling and disposal, or may be present in fugitive dust or leachate waters from
disposal piles.

     Chapter 4 is a summary of the major potential  impacts which can  result
from oil shale development.  The scope of the chapter is limited to direct
and indirect impacts on air and water quality resulting from extraction and
processing activities.  Effects of increased human population (e.g.,  vehicle
traffic) and effects of development on biota are not considered.

     Several air quality modeling efforts have been undertaken to predict the
impact of process emissions on ambient air quality.  Section 4.1 reviews
these efforts, including those performed by the developers of the federal lease
tracts, for the adequacy of the data inputs and the models employed.   Currently,
most air quality levels in the oil shale region are well below the federal and
state ambient standards, with the exception of occasional  short term  particu-
late and oxidant levels.  Maximum ambient levels of sulfur dioxide and carbon
monoxide associated with individual oil shale operations are predicted to meet
state and federal standards.  However, suspended particulate and non-methane
hydrocarbon levels are predicted to exceed short term standards for signifi-
cant deterioration and maximum allowable increment increases.  Further, emis-
sions assumed in most of the modeling efforts have generally not accounted
for fugitive dust, secondary sources such as vehicular traffic, or transient

     Potential effects of extraction and processing activities on the quality
and flows of the surface and groundwater are discussed in  Section 4.2.  Exist-
ing water quality in the oil shale region varies geographically and seasonally.
Several streams and shallow aquifers provide water suitable for irrigation
purposes although water quality in lower oil shale aquifers in the Piceance
Basin and in the lower reaches of Piceance Creek exceeds the dissolved solids,

fluoride, or boron criteria for domestic or irrigation uses.  The only signi-
ficant quantity of water found on or near the Utah lease tracts (U-a/U-b) is
that in the White River.  Water quality in the White River is suitable for
irrigation use except during low flow in the summer.

     Withdrawal of good quality surface and groundwater from sources in the
upper Colorado Basin for consumptive use may result in increased salinity
levels in the lower Colorado River.  Conversely, consumptive withdrawal of
poor quality groundwater which might otherwise reach the upper Colorado River
or its tributaries may result in decreased salinity levels in the lower
Colorado River.  The exact impact of withdrawal on the Colorado River is not
known, but the estimated maximum increase in total dissolved solids at Imperial
Dam resulting from a 160,000 m3 (1,000,000 bbl) per day oil shale industry is
only about 15 mg/1, or 1.7% of the current value of TDS at that point.

     All of the major developers have indicated their intention to discharge
no wastewaters directly to surface streams.  All process waters would be re-
used and ultimately applied to retorted shale.  Effects of extraction and pro-
cessing activities on local hydrology and water quality are therefore likely
to be of an indirect or incidental nature.  Generally, the water pollution
implications of mine dewatering and of the creation of large retorted shale
disposal piles are not currently known, and perhaps cannot be known until
development occurs.  The site specific water pollution problems and proposed
water management programs of the Superior Oil Company, Occidental Oil Company,
and lessees of the federal tracts are summarized in Section 4.2.

     Section 4.3  is a summary of solid waste disposal plans for major oil
shale developments, and a review of physical hazards and intermedia pollutant
transfer potential of retorted shale disposal piles.  Most of the developers
propose to  use canyon sites for solid waste disposal, and plan to establish
stable slopes and water diversion features on the waste piles.  The surface
of the piles are  to be revegetated and retention structures to be built to
prevent contaminated waters from reaching surface or groundwater.

     In general,  retorted shale cannot be entirely returned to mined-out
areas as a disposal method since retorted shale occupies a greater volume
than the raw shale from which it was derived.  The Superior Oil Company, how-
ever, proposes to return all of the processed shale from its oil and mineral
extraction operations to the mined out zone.  In this case, the recovery of
sodium and aluminum minerals in addition to shale oil results in a processed
shale whose volume is less than that of the parent shale.

     The major potential problems for surface disposal of retorted shale are
(1) physical instability allowing mass movements;  (2) runoff and leaching of
retorted shale creating indirect water pollution; and (3) surface destabili-
zation allowing excessive wind and water erosion to occur.  These problems
or hazards and some experiences with small scale disposal pile stabilization
efforts (physical and vegetative) are reviewed in Sections 4.3.2 and 4.3.3.

     Shale derived oils have properties different from petroleum derived oils,
and different processing steps may be required to produce suitable petroleum

substitutes.  The composition and properties of shale oils which may influence
upgrading steps, refining waste streams, and combustion emissions are discussed
in Chapter 5.  A brief summary of two experiences in refining crude shale oil
is also included.  Section 5.2.2 is a review of epidemiological  studies,  ana-
lytical measurements, and bioassay tests which have  been aimed at determining
the carcinogenicity hazard associated with  human exposure to  crude and refined
shale oils.

     Chapter 6 is a summary of environmental monitoring projects and studies
which have been or are being conducted in the Piceance and Uinta Basins rele-
vant to oil shale development.  Such programs may be divided  into two general
categories:  (1) private and/or specialized projects and (2)  projects con-
nected with the Federal Prototype Oil Shale Leasing  Program.   The chapter in-
cludes a catalog of various monitoring activities, a narrative summary of the
monitoring programs of the lease tracts, and comments about monitoring pro-
grams, with focus on scope, quality, and the availability of  data and results
to interested parties.


     Several oil shale mining and retorting technologies are approaching the
state of economic feasibility.  The private sector has developed mining,
above-ground retorting and in-situ retorting technologies, and several com-
panies plan to apply these technologies on privately owned lands in Colorado
and Utah.  Similar technologies are likely to be applied on federally leased
oil shale lands.  This chapter is a brief review of oil shale extraction and
retorting technologies.  The discussion includes the history, technology,
development plans,  and some environmental programs of the major contenders
for commercial development at present.

     The locations of potential oil shale development sites in the Piceance
and Um'ta Basins of Colorado and Utah are shown in Figures 2-1 and 2-2.


     Oil shale has been mined on a modest scale for several decades.  To
date, however, mining has been underground and confined to the southern end
of the Piceance Basin with adit access at the Mahogany zone* outcrop.  Con-
siderable experience in room and pillar mining has been accumulated.

     Current development plans for larger scale oil shale extraction call
both for room and pillar mining and for open pit mining.  This section re-
views the history of oil shale mining, the status of mining technology at
present, planned research and development programs, and technology for pre-
paration of shale for retorting.

2.1.1  History  (1,2)

     Oil shale property was purchased as early as the 1920's for possible
development.  However, actual oil shale development efforts were not con-
ducted until the Bureau of Mines Shale Research Facility at Anvil Points
Colorado was established under the Synthetic Liquid Fuels Act of April 5,
1944.  The plant and underground mine were operated by the Bureau of Mines
during the period from 1944 through 1956.  Authority to lease the facility
was given to the Secretary of the Interior in 1956, and from 1964 through
1968 the facility was leased to the Colorado School of Mines Research Founda-
tion for purposes of improving retorting technology.
*The Mahogany zone is a rich interval of oil shale strata which extends
 throughout the Piceance and Unita geologic basins in Colorado and Utah.

                                               OUTCROP OF
                                               fAAHOGANY LEDGE
                                                      U.S. NAVAL
                                                       NO. 1 AND 3
                                              95W    94W    93W
Figure 2-1.   Locations of  Potential Oil  Shale Developments  -
              Piceance Basin,  Colorado

                        21       22
Figure 2-2.  Locations  of Potential  Oil Shale Developments
             Uinta  Basin, Utah

     Mobil  Oil Company acted from 1964 through 1968 as project manager for
a six company cooperative effort for improving oil  shale technology.  At
first this group operated the Anvil Points mine and in 1966 opened a new
mine in a 24 meter (78 ft) high ledge of the Mahogany zone which produced
453,600 tonnes (500,000 tons).   Union Oil Company operated a mine from 1955
through 1958 on their property located on the east fork of Parachute Creek.
This effort resulted in the mining of over 56,500 tonnes (70,000 tons) of
shale for Union's retort development activities.

     The Colony Development operation started with a prototype mining
effort in 1964 with the intent of eventually proceeding to a 59,892 tonne
(66,000 ton) per day production mine.  Operations were suspended in 1973.

     The objective of all  these efforts,  in addition to tfie production of shale
for testing various retorting processes, was to develop applicable methods
for mining the richer oil  shale of the Mahogany zone.  The total years of
effort devoted to the development of mining methods in shale have made avail-
able reliable systems of ore extraction, a necessary condition for the start
of a commercial shale oil  industry.

     The production systems expected to be used through 1985 are underground
room and pillar; open pit (a standard method); and the Occidental modified
in-situ method.  These mining methods are described below.

2.1.2  Underground Room and Pillar Mining  (1.2,3,4,17)

     Room and pillar mining is most commonly associated with relatively thin
tabular beds of coal  and potash.  The type of room and pillar mining associ-
ated with oil shale is more closely akin to that practiced in the lead-zinc
mines of Missouri and Kansas.  Once the mine opening has been developed,
the basic sequence is as follows (see Fig. 2-3):  a) drill, load and blast
the upper (approximately 1/2 the thickness mined) heading and ventilate the
area; b) bar down dangerous overhead rock;  c) muck the blasted oil shale;
d) scale the remainder of the loosened shale from the overhead and sides of
the ribs and pillars; e) install roof bolts to assure structural integrity
for safety in future operations.  Mobile units are diesel powered, and carry
air compressors for the rotary drills, water for drilling and dust suppres-
sion, and lighting systems for operational illumination.

     At some distance behind the initial  heading development, a similar
sequence is followed in the bench area; a) drill, load, blast and ventilate;
b) muck; c) scale the pillars and clean up the area for haulage.

     Drilling:  Rotary drilling jumbos have been developed which are totally
self-contained.  These units are capable of drilling the necessary 40 to 50,
6.6-12.7 cm (3-5 in) diameter holes rapidly enough to allow loading and
blasting a heading in one shift.

     Blasting:  Ammonium Nitrate/Fuel Oil (ANFO) mixtures of 95/5 composition
have proven to be an effective blasting agent for dry holes in oil shale when
properly primed.   Headings require 0.35 Kg of blasting agent per tonne of rock


Figure 2-3.  Perspective Drawing of Oil Shale Room and Pillar Mining

(0.7 Ib/ton).  Benches require less explosive - about .175 Kg/tonne (0.35
Ibs/ton) because of their easier blasting characteristics.

     Blasting in a wide heading is most economically accomplished using a Vee
cut  (the name is apparent from the view of Fig. 2-4).  Since there is only one
"free face" to blast to, and the remainder of the area is surrounded by rock
which resists movement, a Vee cut requires heavier loading and thus a higher
blasting agent factor.  In order to open up the blasted area, the shooting is
done sequentially from the "cut" holes outward to the "trimmer  holes.  Holes
may also be sequentially fired from the middle of the face upward and down-
ward, with the bottom row of "lifters" typically being the  ast fired.  This
allows  the muck to be thrown away from the face for easier loading.

     Bench blasting is similar to that associated with open pit mining and
will be described in Section  2.1.3.

     Ventilating:  Ventilation regulations require a minimum of 2.8 m3/min
of air flow (100 cfm) per diesel  horsepower.   After blasting there is a re-
quirement to reduce the NO/ level  in mine air below a Threshold Limit Value
(TLV) of 25 ppmv within an hour so that the next shift can work in a safe
atmosphere.   All  fumes and dust generated will  generally be rejected to the
outside atmosphere in a short period of time.

     Barring Down:   Before mucking and haulage, safety procedures normally
require men working on top of the muck pile to bar down loose rock from the
back to prevent rock falls during mucking.

     Mucking and Haulage:   The practice of room and pillar mining in Colorado
oil shale and in the midwestern lead-zinc district has led to the development
of diesel front end loaders of 19 m3 (25 cubic yards) capacity and diesel
trucks to 67 tonnes (75 tons) capacity.  All  diesel  engines are equipped with
scrubbers to meet mine toxic  gas emission requirements.   Haulage from the
mine is accomplished by trucks or conveyors through adit entry mines.  For
inclined shafts,  conveyors or skips will  be used depending on the angle of
incline.  Skips will  be required for operation from vertical  shafts.

     Roof Bolting and Scaling:   AS soon as the heading has been mucked out,
detailed scaling of the back* and installation of rock bolts is accomplished,
A pattern of installing rockbbolts on 1.8 m  (6 ft) centers has been estab-
lished  for present mines along with a general pattern of 18 m (60 ft) rooms
and 18  m (60 ft) pillars.  The length of rock bolts will depend upon the
thickness and competence of overlying strata.

     Shale mine pillars have  been instrumented and various surveys have been
made of their structural  competence.  Knowledge of the geological joint
system of the oil shale bed has a large influence on the ability to calculate
pillar size versus thickness  of overburden.  Thus, orientation of the mine
to take advantage of the geological  joint system is important.  But, since
the oil shale mines developed to date have been of small areal extent, the
effect of large scale underground excavation on pillars is unknown.

*The roof of a hard rock mine is normally referred to as the back.


                                                           "TRIMMER HOLES"
Ftgure 2-4.  Vee-Cut Blasting Pattern for Underground Oil Shale Mining

2.1.3  Open Pit Mining  (2,5,7)

     Open pit mining is not as complex as underground mining,  but the basic
steps are similar:  a) drill, load, and blast either the overburden or the
oil shale; b) load the material for transport to the retorting or disposal
area; c) scale the face for safety and repeat the cycle.

     Drilltng:  Drilling in open pit mines is normally accomplished with
large mobile drills, capable of drilling large diameter holes.  Bench height
and drill characteristics are usually chosen to obtain a drill with a mast
height sufficient to drill  a hole in one pass.   If achievement of the neces-
sary bench deoth requires the addition of lengths of drill  stem,  the opera-
tion would be slowed down.   Figure 2-5 shows a  view of a drilling pattern
planned for a large bench on Tract C-a (7).

     Blasting:  Because larger loading equipment can be used on surface than
is possible underground, the blasting pattern in a pit mine can be spread
out and large powder holes used, even though this may produce  larger blocks
of ore.  An average of 0.35 Ibs of ANFO blasting agent per  ton (.175  kg/tonne)
of material will likely be required, although the quantity  can be adjusted
as experience with the variations in the oil shale develops.   Figure 2-6
shows the cross section of a typical blasting pattern as envisioned for Tract
c~a (7).  The holes are drilled and loaded below the bench  level  to preserve
a level floor for subsequent operations.  Stemming in the top  of the hole
effectively contains the explosion to maximize useful effects.

     In open pit mining, detonating cord is normally used between holes and
down the holes to the primers.  Millisecond delay connectors are used between
sections of cord to sequentially initiate blasts from front to back and side
to side.  This improves fragmentation as well as minimizing shock to the
surrounding area.  Since the detonating cord is relatively  insensitive to
initial detonation, safety is improved.  Electrically initiated caps used  to
start the sequence do not have to be connected until  last.   If there are
thunderstorms and lightning in the area blasting can thus be delayed.

     Loading and Hauling:  Broken ore is loaded with large  shovels (usually
electrically powered) into trucks having capacities of up to 77 tonnes (85
ton).  Diesel powered front end loaders and bulldozers are  used for cleanup
in and around the loading areas.  Road graders and watering trucks are re-
quired to maintain haul roads since tire wear is one of the most expensive
operating costs associated with open pit mining.

     Frequently primary crushing of the ore is accomplished in the open pit,
followed fay haulage from the pit with either large diesel trucks.  Alterna-
tively ore may be transported by conveyor belt to the secondary crushing
storage pile.  Figure 2-7 shows a schematic plan of a loading  operation (7).

     Slope Stability:  Both the safety of the pit and economics of open pit
mining are highly dependent upon the steepness of the side  slopes which can
be maintained in the pit (see Figure 2-8 where the slope angle is45).
If the slope stability cannot be maintained at a fairly steep  angle, slides


                                                      ru v.wiw.'v


                          PD = Primary Detonating
                    Figure 2-5.  Typical  Bench Blasting Pattern Viewed from Above - Tract C-a  (7)


                   BENCH LEVEL
                                                        15 FT


     HOLE DIA.
    15 IN.
                    ^Primary Detonating
            Figure 2-6.  Cross Section of Typical Bench Blasting Pattern Viewed from the Side (7)

                                               90 FT      230 FT
                                               90 FT
                                        HAULAGE ROUTE TO PLANT SITE
                                        HAULAGE ROUTE  TO EXCAVATION SITE
Figure 2-7.  Typical Bench Development Viewed from Above - Tract C-a  (7)

              C  GENERALIZED
         WEST    pHASE H
                 PIT UMIT
                                -5 THRU R-2 ZONES	ORE
                                           LOWER AQUIFER
                            Figure 2-8.  30-Year Pit Cross
  Section -  Tract C-a (7)

hazardous to personnel may result.  If it is necessary to maintain the slope
at low angles to avoid slides, the amount of overburden which must be removed
compared to the amount of usable oil shale produced could make the operation
too expensive.

2.1.4  Mining for In-Situ Retorting  (8)

     A general discussion of in-situ retorting can be found in Section 2.3.
Of interest here is the Occidental modified in-situ operation near De Beque,
Colorado.  As described in Section 2.3, mining is performed at two levels.
The layer between these levels is drilled and blasted to form a room or
"chimney" filled with rubblized shale for retorting (Figure 2-9).  The chimneys
are planned to be about 95 meters high and 30 meters square.

     Since large cross-section chimneys are desirable from a resource recov-
ery point of view it is probably necessary to leave pillars in both the upper
and lower levels for safety during mining.  These pillars would be blasted
at the same time as the main column and form part of the rubblized column for
retorting.  Though a chimney would be partially filled with retorted shale,
the long span across the tops of a chimney would make subsidence more likely
than in the case of normal room and pillar mining.

2.1.5  Advanced Mining Methods

     The Bureau of Mines contracted with several companies for studies of
advanced mining methods (10).>  The contracts were with Cameron Engineers for
underground mining methods, Fennix and Scisson for modified in-situ methods,
and Sun Oil Company for single pass open pit mining methods.

     Cameron Engineers examined eight underground mining systems for mining
thick shale under heavy overburden (9).   Of  the eight systems examined, four
were considered acceptable.  In order of preference they were chamber and
pillar, sublevel stopfng with spent shale backfill, sublevel stoping with
full subsidence, and block caving to si usher drifts.

     Fennix and Scisson examined ten basic mining system possibilities and
selected four candidate rubblization techniques for modi tied in-situ retort-
ing based upon two mining systems, room and pillar and tunnel boring (11).
The rubblization techniques examined were raise boring,  vertical  drill  and
blast,  fan drill and blast, and horizontal ring drill  and blast.   System II
Room and Pillar, Vertical  Drill  and Blast, System IV Tunnel  Boring,  and
Horizontal  Ring Drill  and Blast were recommended to the  Bureau of Mines for
further study in the second phase of the contract.

     Sun Oil  Company examined a single pass open pit mine (5).  The most signi-
ficant aspect of their efforts was that their rock mechanics calculations  in-
dicated that an average 37 slope could be maintained in  the area considered.

Figure 2-9.   Schematic of Occidental Modified In-Situ Mining  Method

      In addition to the above contracted studies, the Bureau of Mines is dev-
eloping mining technology for the rich, deep oil shales and associated saline
minerals of the central Piceance Basin, Colorado (9). One corehole has been
drilled in this area, and a  second  hole, 1.8 m  in diameter, is planned to
gather additional  shaft sinking data  in FY  77.  Later plans call  for sinking
a  full sized  shaft (in FY 78) to develop full technical and economic data  for
shaft sinking through the saline aquifer system and  leached zone  strata UU).

2.1.6  Storage,  Transport and Crushing of Oil  Shale  (6.7,12)

     Figure 2-10 schematically represents a typical  oil  shale preparation
circuit.   The mined shale is fed from trucks or conveyors into a feed surge
control  hopper(s).   From the feed hopper(s) the ore is conveyed to grizzlies
above the primary crushers.   A grizzly serves the purpose of screening out
ore which will choke the entry to the primary crusher and is made of heavy
bar.  The oversize ore is broken on the grizzly (hydraulic picks are used
for this purpose) so that the retained rocks pass the bar screen.

     The primary crusher reduces the ore to a size which will  fit the entry
for the secondary crusher.  Primary-crushers to be used for oil shale are
generally the largest size comrnetscially available and are banked for two
reasons:   a)   the higher reliability of standard units and b) having several
units increases the overall  system reliability.   It is not efficient for a
crusher to produce 100% of a product which will  feed the next crushing stage
because too much undersize material will be produced which may slow the flow
through the following crusher).   Therefore, the primary crusher product is
screened and the oversize portion (10-20%) is returned to the primary crusher

      From  the primary crusher the  ore is moved  to  a  stockpile  by  covered con-
veyor.  The  surface storage required  for  reliable  feed  to  the  retorts  is a
minimum of a  30-day supply.   A  stacker-reclaimer is  used  for  stockpiling the
ore in windrows  and reclaiming  it  for feeding  the  secondary crushing  circuit.

     The secondary crushing circuit is a duplicate of the system described for
the primary crushing circuit, except that a grizzly is not required since the
ore is already sized to fit the input requirements  of the crushers.  The size
requirements and limitations may be found in the individual process descrip-
tions (see Section 2.2).

     Fine ore from the secondary crusher is stored in silos from which the
ore is moved by weight belt conveyors to the retorts.

     Particulate Emission Control:  Emissions and effluents from the various
operations are discussed in Section 3.  Particulate emissions from crushing
have predominant impact potential, and all  developers plan to control  dust
from the crushing operation by use of the best available technology.  Crusher
buildings are to be negatively pressurized, conveyor belts are to be covered,
suction hoods are  to be placed over appropriate points and all dust laden air


                               FEED HOPPER
                             PRIMARY CRUSHER
                            STACKER RECLAIMER
                               FEED HOPPER
is to be fed to bag house (fabric) filters.  The collected dust may be fed to
retorts which can use fine material or may be mixed with spent shale and
placed in the disposal area.  Stockpiles will be sprayed with bitumastic or
latex preparations to reduce wind blown dust.  A review of expected fugitive
dust emissions from these sources is also included in Section 3.


     Above ground retorting processes which have reached the stage of indus-
trial interest in the United States may be divided into three classes based
upon the manner heat is supplied to the retorting process.  These categories
include retorts using (a) recycled hot solids, (b) an internal combustion zone
within the retort, and (c) an external, fuel-fired furnace or gasifier.  Poten-
tially commercial U.S. retorting processes which employ these various modes
of heat transfer are individually discussed in the sections to follow.  Pro-
cesses are presented in the approximate order of their technical and commer-
cial advancement.

2.2.1  TOSCO II Retorting Process (Recycled Hot Solids)

     History (14):  TOSCO II is the process of The Oil  Shale Corporation.
Initial development work (from 1955 to 1966) was conducted under TOSCO
sponsorship by the University of Denver Research Institute, in a 22 tonne/
day (24 ton/day) pilot plant.  In 1964 the Corporation formed Colony Develop-
ment Operation, which included SOHIO, Cleveland Cliffs,  Atlantic Richfield,
and TOSCO.  (Later, Ashland Oil  and Shell  Oil  replaced SOHIO and Cliffs.)
A 909 tonne/day (1000 ton/day) semi-works  plant was constructed near Grand
Valley, Colorado, and operated until  1972.  The site included a room-and-
pillar mine which produced over one million tons of raw  shale, and a number
of test sites for the study of retorted shale disposal and site revegetation.

     This process is probably the closest  to immediate industrial  scale-up
to 8000 m3/day (50,000 bbl/day).  It has been dormant since 1974,  pending
initiation of a federal  synfuels participation program and completion of a
final Environmental  Impact Statement (EIS).

     Process Technology  (12,13,14,15):  Minus one-half inch crushed shale
(including fines) is preheated by direct contact  with hot flue gases from a
ball  heater (see Figure 2-11) used downstream in the process.  The preheated
shale is then fed to a horizontal, rotating retort, where it is heated to  480
C (900F) by mixing with small,  1.30 cm (1/2") hot ceramic balls.   Shale oil
vapors are removed, fractionated and condensed.  The cooled balls and retorted
(spent) shale are discharged from the retort, and screened to separate the
spent shale from the balls.  The spent shale is cooled in a rotating drum
steam generator, moistened to about 14% water content, and transported to  the
disposal site.   As discarded it normally contains about 4-5% residual carbon-
aceous matter.

     The cooled balls are sent to an external ball heater, reheated, and
recycled to the retort.   In a typical situation the ball to raw shale feed
ratio to the retort is about 2:1.  The ball heater can use an outside fuel,
a portion of retort off-gases, and/or even the carbonaceous residue on the
spent shale as a fuel source(s).

                  RAW SHALE

                                                HOT BALLS

                                         PREHEATED SHALE
                                                    FLUE GAS TO
                                                                                                PROCESSED SHALE
                                                                                                TO DISPOSAL
                         Figure 2-11.   Schematic of  the TOSCO  II Retorting  Process   (12)

     The crude shale oil is fractionated into gas,  naphtha,  gas  oil,  and
bottoms oil.  Subsequent hydrotreating and coking is  used  to upgrade  the
products to plant fuel gases and LPG, low sulfur fuel  oil, diesel  fuel,  plus
sulfur, ammonia, and petroleum coke byproducts.

     TOSCO has presented considerable detail  (",J3)  regarding proposed  pol-
lution control technologies to be utilized throughout its  Yar1^  operations
(mining, retorting, upgrading).  In the case  of the retorting plant,  a venturi
wet scrubber is to be used for dust control in the shale preheat system,
together with settling chambers and cyclones.  Hot flue gases in the preheat
system will be incinerated prior to discharge, in order to reduce trace
hydrocarbons.  Warm flue gas and a high energy venturi scrubber  will  remove
residual dust from the ball recirculation system.  A foul  water  stripper will
remove most of the NH3, H2S, and C02 gases from plant waters.  Plant fuel
gases will be treated to reduce the sulfur and nitrogen present, prior to
on-site use for heat generation.  HgS is recovered as elemental  sulfur in a
Claus Plant, tail gases are treated for trace SO? removal  in a Wellman-Lord
unit.  Arsenic is removed from the gas oil and naphtha prior to  hydrogenation
by a proprietary catalytic process.  Emissions from the moisturizing of spent
shale are  controlled bv a venturi wet scrubber.

     Development Plans  (13):  A full-scale commercial plant processing some
55,000 tonnes (61,000 tons) of raw shale per day for 20 years from a 1600
hectare (4,000 acre) underground mine has been designed, together with up-
grading facilities.  A plant site on upper Parachute Creek has been selected,
together with a 325 hectare (800 acre) disposal  site in adjacent Davis Gulch.
Two 230 kv powerlines may be built by Colorado Public Service Company to
service the plant.  Permit applications have been made for a 310 km (194
mile) long, 40 cm (16 inch) product pipeline to Lisbon Valley Station, Utah.
Access roads and a railroad spur are under construction.  A water contract
with the U.S. Bureau of Reclamation proposes to divert .35 cubic meters/sec
(12.5 ft3/sec) of water for the plant from the Colorado River at Grand Valley,

     Annual construction employment is expected to reach 2400 people in the
second year of construction.  Plant and mine direct employment is estimated
to stabilize at 1,000 when full-scale production is attained in  the fourth
year after project initiation, with an additional 1,000 people involved in
peripheral indirect employment.

     Recent estimates indicate a grand total investment of $960 million
(Sept. 1975 dollars), with a required selling price of $14.20/bbl at a 10%
discounted cash flow return on an all-equity investment.

     Use of TOSCO II Technology at Sites Other than Parachute Creek (Dow
Property):Some 5480 hectares  (14,700 acres) of Unitah County land held by
The Oil Shale Corporation has been consolidated into  the  "Sand Wash Unit"  (16)
The Corporation is committed to expend a minimum of $8.million  in predevelop-
ment costs on the site.  Room and pillar mining of 10-13m (30-40 ft) of  shale
at approximately 600 meters  (2000 feet) in depth is planned  and TOSCO II re-
torting is to be employed.


     TOSCO II retorting may be employed in varying degrees at Lease Tracts
C-b, C-a and U-a/U-b.

     Environmental Programs:  The Colony/TOSCO group has conducted a thorough
environmental assessment of its proposed plant.  A 20-volume Environmental
Impact Analysis for the Parachute Creek Development was published in 1974(13).
A formal BLM prepared Draft Environmental  Impact Statement was issued in Dec-
ember 1975(12).  Hearings were held in January 1976.  A final EIS is now being
prepared.  The production of 7500 m3/day (47,000 barrels) of fuel oil  per day
is contemplated.   Revegetation of the disposal area, as stated by Colony,
will be continued for as long as necessary to establish a compatible,  stable
vegetative cover.

2.2.2  The Paraho Processes (Gas Combustion and Hot Inert Gas Retorting)

     History  (14,17):  The Gas Combustion Retort was initially developed in
the U.S. Bureau of Mines at Anvil Points, Colorado in 1951, and reached a 136
tonne/day (150 ton/day) pilot plant-capacity at the conclusion of the Synthe-
tic Liquid Fuels.Program in 1955.  Between 1964 and 1966, a consortium of six
petroleum companies (Mobil, Humble, Pan American, Sinclair, Continental,
and Phillips) improved the process, attaining a capacity of 320 tonnes/day
(350 tons/day) at yields in excess of 85% of Fischer assay.  However,  the
studies of the consortium indicate that difficulties were encountered with
small shale sizes, high rates of gas and shale throughout, and bridging due
to rich shales.  The Paraho/Development Engineering, Inc. gas combustion
retort was designed to overcome such limitations.

     The Development Engineering, Inc., (DEI) kiln was invented by John B.
Jones (U.S. Patent No. 3,736,247), and initially used for calcining limestone
where it has attained a capacity of 636 tonnes/day (700 tons/day) in a 3.2
meter (10.5 ft) diameter design.  In May 1972 DEI leased the federal faci-
lities at Anvil Points, Colorado and launched a project to apply the DEI
kiln to oil shale retorting.  A consortium of 17 companies, known as the
Paraho Oil Shale Project was formed, and activities at Anvil  Points initiated
in late 1973.  A 1.4 meter (4.5 ft) diameter pilot kiln was built, followed
by a 2.6 meter (8.5 ft) inside diameter semi-works retort with a nominal
capacity of 410 tonnes/day (450 tons/day).  This latter retort has been
operated since 1974, producing 1590 m3 (10,000 barrels) of shale oil for
the Navy in a 56-day continuous run in March 1975.  Private financing  for
the project to date has been $9 million.

     It is planned to continue process development for the next 18 to  24
months under a proposed $6 million ERDA/Navy appropriation, while an Environ-
mental Impact Statement is prepared for construction of a full-scale 11,800
tonnes/day (13,000 ton/day) commercial module.

     Process Technology Gas Combustion or Direct Mode  (14,17,18):   The USBM
Gas Combustion Retort consisted of a vertical vessel fed from the top with  raw
shale, which moved downward by gravity through a top preheat zone, thence into
a retorted shale cooling zone.  Oil vapors from the retorting zone passed upward
through the preheat zone, where they condensed to a stable aerosol mist that
passed out with the retort gases and were recovered in mist collectors.


     Part of the gases released by retorting 700-900 KCAL/m  (80-100 Btu/
SCF) were recycled near the bottom of the retort, where they were heated
and passed upward into the combustion zone.  Here, new retort gas was in-
jected and the gases burned, together with a portion of the residual carbon
on the retorted shale to furnish the heat for the process.

     The Paraho/DEI retort employs the same four-zone configuration and
operating methods, but substantial improvements have been made in the design
of inlet and discharge mechanisms, and in recycle gas/air introduction to
the retort.  As a result the remainder of discussion of the gas combustion
method in this section will be restricted to the Paraho process.

     In the direct mode Paraho process (Fig. 2-12) minus 7.6 cm (3 in) plus
0.6 cm (1/4 in) shale is introduced into the top of the retort through a
rotating spreader, passes through the 4 zones previously described, and is
discharged through a special, hydraulically operated discharge grate, which
more uniformly controls solids flow rates.  Retort off-gases (approx. 900
kcal/m3 Or 100 Btu/SCF) are recycled to the retort at three points.  These
gases, together with combustion of a portion of the carbonaceous residue
on the spent shale, provide the heat for the process.  The retorted shale
containing a 2.3% carbonaceous residue, is discharged to disposal at approxi-
mately 150C (3000F).  Retort gases, oil mist, and vapors leave the top of
the retort at approximately 66<>C (1500F), and pass through a cyclone, wet
electrostatic.precipitator, and aerial  condenser to remove oil.  As pre-
viously noted, a portion of these gases are recycled to the retort.

     Process Technology:  The Paraho Indirect Mode Retorting Process (Hot
Inert Gas Retorting) (18):  The Paraho process may also 5e operated in the fn-
direct mode (Fig. 2-13), in which case no combustion is carried out in the
retort, per se.  The retort gases therefore have a high heating value 8000
kcal/nn (900 Btu/SCF).   A portion of these gases are used to heat a recycle
portion of same in an external furnace, and the latter are recycled to the
retort as a heat source.  The retorted shale has a carbon content of 4.5%.
A combination of direct and indirect operating modes may also be employed.

     The product shale oil has a 21 API gravity, with pour points of 32C
(900F, direct mode) or 190C (680F, indirect mode).  It may be upgraded by
conventional hydrotreatment to remove nitrogen and sulfur, and refined to
normal petroleum products.  No shale oil upgrading has been undertaken at
Anvil Points; all product oil is stored for transport elsewhere.

     Development Plans (32);  It is proposed by Paraho to construct a single,
full-size, 11,800 tonnes/day (13,000 tons/day) commercial modular retort
at Anvil Points, Colorado, on a site approximately one mile west of the
existing Paraho semi-works plant.  The present underground room-and- pillar
mining facilities will  be expanded eastward.  Raw shale will be passed
through a conveyor system to a 2 hectare (5 acre) retort plant area located
on the present mine road approximately 1.2 KM (3/4 mile) southwest of the
mine, at an elevation of approximately 2,100 meters (7,000 feet).  Retorted
shale will be conveyed to the disposal  area now being used for the current
Paraho operations.  Shale oil will be transported by rail or truck to a
refinery for processing.


                    OIL MIST


            \ GAS PREHEATING
            \     ZONE
                RETORTED SHALE
                                                         V PRECIPITATOR /
                                                     IRECYCLE GAS
                                           CRUDE SHALE OIL

                                 NET PRODUCT GAS
                                       AIR BLOWER
                   (GAS  ooreusTiGN RETORTING PROCESS (is)

               MIST FORMATION AND
                                                             CRUDE SHALE OIL
                       fRETORTED SHALE
              FIGURE 2-i3Soewnc OF PARAHO INDIRECT MODE
                        (HOT INERT GAS)  RETORTING OB)

                                                SHM.C nit
                                                Oil lltl
Figure  2-14.   Side View of Union  B Retort (36)

      Primary crushing  down  to  minus  25 cm  (10 inch) will be carried out in
 the  mine,  and the  raw  shale will  be  fed to a conveyor for transport to the
 retorting  site.  After secondary  crushing to approximately minus 8 cm (3
 inch)  the  oil  shale will  be fed to the top of the modular retort.  The full-
 size Paraho  retort will operate in the same manner as the present demonstra-
 tion pilot and semi-works retorts.   The full-size retort (13 meters, 42-foot
 diameter and 30 meter, 104  foot high vessel) is expected to have a maximum
 capacity of  approximately 11,800  tonnes/day (13,000 tons/day).

      Water requirements are to be met by expanding the current facilities,
 which include a supply line from  the Colorado River, and a small reservoir
 on the mesa  itself.  The  present  Public Service Co. of Colorado utility line
 will  be increased  in capacity  to  meet the anticipated 9000 KVA power needs.
 It is estimated that a project period of 3 to 4 years will be required to
 construct  the facilities  and demonstrate the retorting process.

      The cost of the modular project was calculated in early 1975 to be $76
 million (in  1975 dollars).  The present work force of 80 would be expanded
 to approximately 300.  A  temporary construction and mine development crew
 of 400 to  450 people for  about 18 months is anticipated.

     The original  funds for  the ParaHo  program were nearly  exhausted  in  April
1976, and the Anvil Point facilities  were  partially closed  down.   The Navy is
currently negotiating a contract with DEI  to  produce 16,000 m3 (100,000  bbls)
of shale oil  by 1978 for refining  and military  testing.   The  Paraho  project
thus  has a temporary reprieve.   Paraho  submitted a  request  for ERDA  funding
of a  50,000 bbl/day demonstration  plant at Anvil  Points  in  1975,  but the re-
quest ts awaiting  congressional action  on  synthetic fuels legislation.

      Commercial Use of Paraho  Technology:  Gulf and Standard of Indiana
 (Lease Tract C-a)  are  participants in the Paraho project and intend to use
 the  process  for part of the shale at Tract C-a (20). SOHIO,  Sun  and  Phillips
 also plan  to use the technology at the Utah lease tracts U-a and U-b except
 for  retorting fines (21).   Development plans at the lease tracts are reviewed
 in Section 2.4.

      Environmental Programs:   No  extensive environmental studies have as
 yet  been conducted on  the Paraho  process, pending further work on the pro-
 cess technology studies now in progress.  Some initial emission and efflu-
 ent  measurements have  been  conducted by Paraho and by TRW/DRI  (under current
 EPA  contract).  The results  are to be published  by  EPA  in 1977.

      Emission control  technologies for the Paraho processes  have not as yet
 been indicated, since  the basic technology is still under development.
 (Several retorted  shale disposal  methods are under  investigation).

      Retort  gases  and  condensate  waters are presently sent to  a  thermal
 oxidizer for incineration/evaporation.  It is expected that  pollution con-
 trols will be more fully  delineated, together with  the emissions and efflu-
 ents involved, as  further research proceeds during  the next  18-24 months.


     A Draft Environmental Impact Assessment statement was prepared by the
U.S. Bureau of Mines in May 1975.  Late in 1975, however, it was determined
by ERDA that a new, full Environmental Impact Statement would be required.
Its preparation and approval  may take an additional 9 to 13 months from the
present date.

2.2.3  The Union Oil Process (Retort B - Hot Inert Gas Retorting)

     History of Technology Development (14,17):  The Union Oil Company has been
involved in oil shale activities for several decades, beginning in the 1920's
with the purchase of 12,000 hectares (30,000 acres) of fee property contain-
ing oil shale resources.  The development of Union's oil shale retorting
technology was initiated in the early 1940's, and three variations of a ver-
tical kiln retorting process, with upward flow of shale and counter-current
downward flow of gases and liquids, have been developed.  These variations
are known as the Retort A, the Retort B, and the Steam Gas Recirculation
(SGR) processes.   The first concept, the Retort A process, has been carried
through 1.81 tonnes (2 tons) per day and 45.5 tonnes (50 tons) per day pilot
plants.  This was followed by the construction and operation of a large
demonstration plant in the late 1950's.  The demonstration plant was designed
for 317.5 tonnes (350 tons) per day capacity, but long-term operability was
demonstrated at rates of 635 to 907 tonnes (700 to 1,000 tons) per day, with
a peak rate of 1,089 tonnes (1,200 tons) per day.  Although the demonstration
of the Retort A process was extensive and successful, the Union Oil work,
except for a continuing low level research effort, was suspended because of
a plentiful supply of low-cost Middle East oil and natural gas at the time.
The two improved versions of the Union Oil process, the Retort B and the SGR
processes, were both developed in the 1970's in response to increasing
energy demands and shortage of fuel supplies.  Both the Retort B and the SGR
processes have been carried through pilot plant stage.  It is the Retort B
process that Union Oil now proposes to construct and demonstrate at the
9,072 tonnes (10,000 tons) per day rate, along with all necessary auxiliary
facilities.  The  SGR technology may be  employed  at  later stage  of development.

     Process Technology Summary  (17,22,36):  In the Retort B process, shov/n in
Figs. 2-14 and 2-15, crushed oil shale in the size range of 3  to  5 cm
(1/8 to 2 inches) flows through two feed chutes to a solids pump.  The solids
pump consists of two piston and cylinder assemblies which alternately feed
shale to the retort; the pump is mounted on a movable carriage and is com-
pletely enclosed within the feeder housing and immersed in oil.  As shale
is moved upward through the retort by the upstroke of the piston, it is met
by a stream of 510 to 538C (950 to lOOQOF) recycle gas from the recycle
gas heater flowing downward.  The rising oil shale bed is heated to retort-
ing temperature by countercurrent contact with the hot recycle gas, result-
ing in the evolution of shale oil vapor and make gas.  This mixture of shale
oil vapor and make gas is forced downward by the recycle gas, and cooled by
contact with the cold incoming shale in the lower section of the retort
cone.  In the disengaging section surrounding the lower cone, the liquid
level is controlled by withdrawing the oil product, and the recycle and make
gas is removed from the space above the liquid level.  As shown in Fig.
2-15, the make gas is first sent to a Venturi scrubber for cooling and heavy


                                                                   B   F
                                                                                          RETORTED SHALE TO
                                                                                          RUNDOWN OIL PRODUCT
                             Figure  2-15.   Flow Diagram  for Union B  Retorting  Process (36)

ends removed by oil scrubbing.  That portion of the 7109 kcal/m3 (800 Btu/SCF)
gas not recycled  is then processed by compression and oil scrubbing to remove
additional naphtha and heavy ends, followed by hydrogen sulfide removal 1n a
Stretford  unit.   The  sweetened make  gas 1s used  as  plant  fuel.
     The product oil withdrawn from the retort is treated sequentially for .
solids, arsenic, and light ends naphtha removal.  The solids removal is accom-
plished by two stages of water washing.  The shale fines are collected in the
water phase which is recycled to the water seal.  The water seal is a Union
Oil concept shown in Figure 2-15, in which a water level is maintained in a
conveyor system for retorted shale removal to seal the retort pressure from
atmosphere.  For arsenic removal, a proprietary Union Oil process employing
an adsorbent is utilized to reduce the arsenic content of the raw shale oil
from 50 ppm to 2 ppm.  The dearsenated shale oil is then sent to a stripping
column for stabilization prior to shipment.  The resulting crude shale oil
has a 22.7 API gravity, 60F pour point, 1.7% nitrogen and 0.81% sulfur
content, and low (1.75%) Conradson carbon residue.  At the present time,
Union Oil does not envision additional upgrading of the crude shale oil on-

     For the Retort B process, all the plant fuel requirements will be met
by the make gas produced.  The principal pollution control devices in the
Union Oil design include the Stretford process for hydrogen sulfide removal
from the retort make gas and oil/water separation and sour water stripping
for waste water treatment.  The treated waste water is used in the cooling
and moistening of the retorted shale to provide for dust control and proper

     Development Plans (23):  To further the development of the Retort B pro-
cess, Union Oil has proposed to the U.S. Energy Research and Development Ad-
ministration a cooperative $120 million venture to build a 9,070 tonnes
(10,000 tons) per day prototype plant capable of producing 1,240 IIH (7,800
barrels) of shale oil per day.  This prototype plant will be constructed on
Union Oil property located on Parachute Creek, north of Grand Valley, Colorado.
Union Oil owns a total of more than 12,000 hectares (30,000 acres) of fee
property containing about 0.32 billion m3 (2 billion barrels) of recoverable
shale oil in the rich Mahogany zone.

     The mining and the processing area for the demonstration plant will be
located on a bench on the north side of the East Fork of Parachute Creek.
The mine portal is designed to open on to a bench at the 2,100 m (7,000 ft)
elevation.  The conventional room and pillar method will be employed for
production mining, with rooms 18.3 m (60 feet) high by 18.3 m (60 ft) wide
and pillars having an 18.3 m (60 ft) square horizontal section.  For the
9,070 tonnes per day prototype plant, the water consumption rate is esti-
mated to be 81 m3/hr (355 gpm) and the power requirement to be 11,300 kw.
Unton Oil filed water right applications as early as 1959, and a conditional
decree has been awarded by the Colorado State Court to Union Oil for claimed
water rights of 200 m3/sec (118.5 ft3/sec or 85,770 acre-feet per year).

All electric power will be purchased from outside the plant and probably be
supplied by the Public Service Company of Colorado.

     For the prototype plant, 7,620 tonnes (8380 tons) per day (dry basis)
of retorted shale containing approximately 20 percent water will  be trans-
ported to a disposal area in the East Parachute Creek Canyon, where it will
be deposited in windrows proceeding up the south embankment. (See  Figure 4-5),

     Union Oil has estimated that 32 months will be required to design and
construct the prototype plant with all its auxiliary facilities.   The opera-
ting program to assess the technical, economical and environmental feasi-
bility of the Retort B process is scheduled for two years.  If the process
proves to be viable, two more retorts would be constructed at the prototype
site, bringing the total plant capacity to 27,200 tonnes (30,000 tons) of
oil shale feedrate per day.

     Environmental Programs:  Union has conducted studies of the various
environmental impacts to be encountered in a Retort B Prototype Plant.
Among the control  technologies to be employed are the following:

    Primary and secondary crushing will be done underground.  A dust suppres-
sion system will be used for dusts from both mining and crushing  operations.

   Because of the oil  seals and water quench used, the retort is  essentially
free of participate emissions.  The plant is totally water consumptive.  Any
process waters or run-off will be captured in the plant's collecting pond.

 t  It is not planned to flare excess make-gas, but rather to absorb heavy
ends into the oil  product.

 0  Retorted, wet spent shale (20% H20) will be conveyed to windrows at the
disposal site, and compacted to 1764 Kg/m3 (90 Ibs/ft3) density for stabil-
ity.  Outer slopes and the top of the piles will be revegetated.   A leachate
ditch will  be constructed to gather leachates from run-off, and discharge
these to the plant water supply pond.

     Union Oil is in the process of completing the environmental  impact
analysis (EIA).  Originally scheduled to be issued in May 1976, release of
the EIA has now been postponed indefinitely pending the outcome of synthetic
fuels commercialization legislation and ERDA's decision to participate
in the demonstration of the Union Retort B process at the 9,072 tonnes per
day capacity.

2.2.4  Superior Oil Process (Hot Gas Retorting, Combustion of Residual Car-
       bon) (24,25)

     History;  Superior Oil has owned some 2,600 hectares (6,500 acres) of
oil shale land in the northern Piceance Creek Basin for nearly 40 years.
In 1967 it began a drilling and geological evaluation program, and found
that the deeper shales on the property contained attractive quantities of
nahcolite (NaHO^) and dawsonite (NaAHOH^CO^) minerals, as well  as oil
shale.  A research program was therefore initiated to permit integrated


                                Figure  2-16.   Top View of Superior Retort (25)

                 SHAIE BED
               OPERATING FLOOD
Figure 2-17.   Cross Section View of the Superior  Retort (Courtesy of Arthur McKee & Co.)

 recovery  of these minerals  and  shale oil.   Included were investigations into
 the  development of a  circular grate retort.

     A small  laboratory  unit is being tested in Superior's Denver, Colorado
 facilities.   A  pilot  plant  unit of 9-18 tonnes/hour (10-20 tons/hr) capacity
 is currently under construction in Cleveland, Ohio, to be in operation in the
 fall of 1976.   If results are successful this will be followed by erection
 of a 18,000 tonnes/day (20,000  ton/day) full-scale commercial modular on
 Superior's  Piceance Creek Basin site.

     Meanwhile  Superior  has proposed to the Bureau of Land Management an ex-
 change of 1,000 hectares (2,500 acres) of Superior land for 680 hectares
 (1700 acres) of adjacent federal  land, in order to provide a more economi-
 cally mineable  tract  with uniform geologic  features.  The U.S.G.S. has
 recently  evaluated mineral  values of the lands in question and has indicated
 that Superior's land  has lower mineral values than the lands asked for in
 trade.  A decision by the Bureau  of Land Management on this land trade is
 still pending.

     Process Technology:  The Superior integrated process involves  underground
room and pillar mining at a depth of 600 meter (2000 feet); processed shale is
to be returned to the underground mine for disposal.  After primary crushing
underground, 80-95% of the nahcolite present will  be recovered mechanically
by secondary crushing to minus 7.5 cm (3 in), and screening to remove the

     The  dawsonitic shale from  NaHCOs recovery will be fed in 3 streams to
 a traveling circular  grate  retort (Figs. 2-16 and 2-17).  A commercial sized
 module is expected to be 56 meters (185 ft) in diameter, with a capacity of
 21,000 tonnes/day (23,000 tons/day).  The doughnut-shaped retort has five
 separately-divided sections, through which  the shale travels in sequence.
 These are a loading zone, retorting zone, residual carbon recovery zone,
 cooling zone, and unloading zone. Hot gases are drawn downward through the
 bed  of shale on the grate,  in the retorting zone, producing oil-laden vapors
 which are removed and the shale oil condensed.  The oil-denuded and cooled
 gas  stream  is next recycled to the cooling  zone, and drawn downward through
 the  spent shale to reduce temperature of the shale prior to discharge.  The
 cooled shale is fed to the  leaching plant for recovery of alumina (Al20a)
 and  soda  ash (Na2C03).

     During  retorting the dawsonite in the  retorted shale is converted to
 alumina and sodium carbonate.  These are processed in the leaching plant by
 dissolution  and subsequent  recovery of soda ash (NaHCOs) and aluminum hydrox-
 ide.  The A1(OH)3 is  calcined to  cell-grade alumina.

     The  spent  s&ale  (sodium-minerals and shale oil denuded) is sent to the
 underground  mine as a wet cake on the production conveyor during its return
 run.  No  revegetation of retorted shale will therefore be required.

     Development Plans:  As noted previously a 9-18 tonne (10-20 ton) travel-
 ing  grate pilot retort is to begin operation in Cleveland in the fall of
 1976.  If successful,  this will be followed by construction of a full-scale


~18,000 tonnes/day (20,000 ton/day) modular plant and mine on Superior's
2,600 hectare (6,500 acre) property in Colorado's northern Piceance Creek
Basin.  This scale-up is partially dependent on a proposed land exchange
with the federal government (24).

     Water requirements for the full-scale plant are to be satisfied by
utilizing the saline water in the "leached zone" aquifer directly above the
proposed mine.  Plant cooling waters will  be returned to the aquifer.  Power
requirements for mining and processing will be purchased off-site.   The cost
of the full-scale plant and its manpower requirements have not been esti-

     Environmental Programs;  Superior has not released detailed data on the
emissions and effluents to be expected from its process.  (Superior has
indicated that a portion of the nahcolite produced could be added to the
retort feed "for sulfur removal.")  It can be expected that, in addition to
control of normal shale oil plant emissions and effluents, control  of brines
and wastes from the leaching plant and associated mineral  recovery activi-
ties will be necessary.

     Superior is currently preparing an Environmental Impact Analysis of its
integrated process, but no release date has as yet been established.

2.2.5  Lurgi-Ruhrgas Process (Recycled Hot Solids) (17,26,27)

     History:  This process was developed jointly by two German firms,
Lurgi-Gesellschaft and A. G. Ruhrgas, in the 1950's for low-temperature coal
carbonization and for cracking saturated hydrocarbons to olefins.  Two lig-
nite carbonization units with a combined plant capacity of 1500 tonne/day
(1700 tons/day) began operation in Yugoslavia in 1963.  A small 14-23 tonne/
day (16-25 ton/day) plant in West Germany has been used to retort Colorado
oil shale, at a yield of 100 percent of Fischer assay.  The Lurgi Company
indicates that a retorting unit of 5000 tonnes/day is technically feasible.

     Process Technology:  In the L-R process, minus 1.3 cm (1/2 in) shale
is heated by contact with hot, finely-divided solids in a horizontal, cylin-
drical vessel with a screw conveyor-  The finely-divided heat carrier may be
sand or coarse shale ash.  The products are withdrawn from the top of the
mixer, dedusted, and condensed.  The spent shale and heat carrier pass into
a lift line, together with dust from dedusting.  Air is added and the carbon
is burned off the spent shale-heat carrier mixture.  Thus the carrier is
reheated and is recycled after dust removal.

     Because of the direct contact between shale solids and heat carrier, heat
transfer is rapid, leading to high-throughput retorts.  Care must be taken
to avoid readsorption of shale-oil vapors on the solids in order to prevent
loss of yield.  Patents cover related processes developed by a number of U.S.
companies which have examined this potentially attractive retorting method.

     Development Plans (28):  In late 1975 American Lurgi presented a proposal
to 14 major owners or leasees of oil shale land to elicit support for construc-
tion of a 4,000 tonne/day demonstration plant of the L-R process.  It was


estimated in the proposal that the plant could be operational 36 months
after project approval.  This proposal is apparently still active, but no
actual site Is indicated at present.

     Environmental Studies:  No specific environmental studies have been
published on the L-R process to date; although limited data are available
regarding certain emissions and effluents from the process in pilot scale.


     In-situ extraction of shale oil has attracted research interest for
many years.  Only recently, however, has commercial interest emerged.  Both
"true" and "modified" in-situ projects are included in the commercial pro-
jects discussed below.  The major emphasis in this section is placed on the
Occidental process since it is the most nearly commercial of the in-situ

2.3.1  The Occidental Modified In-Situ Process  (29,30,31,32)

     History of Technology Development:  Occidental Petroleum Corporation's
involvement in oil shale technology is a relatively recent development.  In
late 1972, Garrett Research and Development Company (now Occidental Research
and Development), a subsidiary of Occidental Petroleum Corporation, an-
nounced plans for the field testing of a modified in-situ shale oil recovery
scheme which is the subject of U.S. Patent 3,661,423.  The actual work began
in the summer of 1972 on the private property (known as the D. A. Shale, Inc.
property) at the head of Logan Wash outside of Debeaue, Colorado.  In the
ensuing months, three research retorts, each 9.1 m (30 ft) on a side and
21.9 m (72 ft) high, were prepared and ignited.

     At the end of 1974, the project was transferred to an operating branch
of the company, when Occidental Oil Shale, Inc., a subsidiary of the Occi-
dental Oil and Gas Production Division, was created.  Concurrently, a deci-
sion was made to initiate the development of a commercial size retort in the
commercial mine, located off the north side of Logan Wash about a quarter
mile below the head of a canyon.  The commercial mine is being developed at
a new location because there is insufficient room at the head of Logan Wash
(the research mine location) to permit a large mining operation, and be-
cause the research mine is located just below the Mahogany Ledge and too
high for the construction of commercial size retort columns.  The first
commercial size retort (Retort No. 4), with a 36.6 m (120 ft) by 36.6 m
(120 ft) cross section and 76.2 m (250 ft) height and containing 15 gpt
rubblized shale, was ignited from the top on December 10, 1975.  A total of
4,300 m3  (27,000 bbls) of oil has been recovered from the retort, and produc-
tion rates of about 80 m3 (500 bbls) per day have been realized.

     Process Technology Summary:  The modified in-situ process for shale oil
recovery consists of retorting a rubblized column of broken shale, formed by
expansion of the oil shale into a previously mined out void volume.  The
Occidental process involves three basic steps.   The first step is the mining


out of approximately  20% of the oil shale deposits (preferably low
grade shale or barren rock), either at the upper and/or lower level of the
shale layer.  This is followed by the drilling of vertical longholes from
the mined-out room into the shale layer, loading those holes with an ammo-
nium nitrate-fuel oil (ANFO) explosive, and detonating it with appropriate
time delays so that the broken shale will fill both the volume of the room
and the volume of the shale column before blasting.  Finally, connections
are made to both the top and bottom and retorting is carried out (Fig.2-18).

     Retorting is initiated by heating the top of the rubblized shale column
with the flame formed from compressed air and an external heat source, such
as propane or natural gas.  After several hours, the external heat source
is turned off, and the compressed air flow is maintained, utilizing the
carbonaceous residue in the retorted shale as fuel  to sustain combustion.
In this vertical retorting process, the hot gases from the combustion zone
move downwards to pyrolyze the kerogen in the shale below that zone, produc-
ing gases, water vapor, and shale oil mist which collects in the trenches
at the bottom of the rubblized column (Fig. 2-19).   The crude shale oil and
byproduct water are collected in a sump and pumped  to storage.

     The off-gas consists of products from shale pyrolysis, carbon dioxide
and water vapor from the combustion of carbonaceous residue, and carbon
dioxide from the decomposition of inorganic carbonates (primarily dolomite
and calcite).  Part of this off-gas is recirculated to control both the
oxygen level in the incoming air and the retorting  temperature.  The off-
gas has a heating value of approximately  580: kcal/m3 (65 Btu/SCF), and the
part of t&e off-gas not recycled is currently flared.

     Occidental envisions using the low Btu gas from a commercial retort for
generating electric power.  Turbines manufactured by Brown-Boveri of Switzer-
land will be investigated for this application.  According to Occidental's
estimate, only 20 to 25 percent of the electric power produced from the low-
Btu gas is required for operating the modified in-situ process.

     Occidental has not disclosed any information on the design of surface
oil and gas treatment plants.  The minimum treatment required for the crude
shale oil produced from the retorting process will  include phase separation
of the oil from the byproduct water and the stabilization of the oil product.
The waste-water effluent from the phase separator may be used for steam
generation after appropriate treatment.

     Retort water volume produced from the Occidental process is approxi-
mately equal to shale oil volume.  This quantity of water is approximately
equal to in-situ shale processing requirements.  It is not known whether
Occidental has investigated the treatment of the retort water for use in
oil shale development.

     The crude shale oil produced from the Occidental process has a specific
gravity of 0.904 (API gravity of 250), a pour point of 21<>C (70F), a sulfur
content of 0.71 weight percent and a nitrogen content of 1.50 weight percent.
The crude shale otl is also reportedly free of solids and may be potentially
usable as boiler fuel without upgrading.


                                      >.oJ",C-3,/jC&r 75ir&-1>
Figure 2-18.   Schematic  of the Occidental  Modified In-Situ  Process  (30j

                         AIR t RECYCLE GAS

                               rRETORTIMG AND VAPORIZATION
Figure 2-19    Flame Front Movement in the Occidental  Modified In-Situ Process

      Development Plans:   Occidental  has  invested over $30 million during
 the  last  five years  in the  development of the modified in-situ process.  A
 second  commercial  size retort  (Retort No. 5), similar in dimensions to
 Retort  No.  4, is now being  prepared.  If the process proves to be success-
 ful  at  the  current 79.5  m3/day (500  bbl/day) level, Occidental expects to
 attract sufficient support  for the construction of a 795 m3/day (5,000 BPD)
 demonstration mine and retort.   The  demonstration mine and retort would pro-
 vide the  necessary information on the technical and economic feasibility
 and  the environmental  acceptability  of advanced mining techniques and multi-
 ple  in-situ retorts.  After the successful demonstration of these concepts,
 Occidental  plans to  expand  the shale oil operations to commercial propor-
 tions,  without  the need  for federal  subsidies or loan guarantees.

      The  Occidental  in-situ experiments  have been conducted on private land
 controlled  by D. A.  Shale,  Inc., through a three-year lease and option agree-
 ment that has since  been extended.   The  D. A. Shale property contains rela-
 tively  low  grade shale (15  gpt) and  may  be marginal for commercial operation.
 Occidental  is seeking to enlarge its holdings of land underlain by higher
 grade oil shale and  has  nominated two tracts in Colorado under the Interior
 Department's Prototype Oil  Shale Leasing Program (Section 2.4).

      Environmental Studies  and Activities:  During  its in-situ experiments,
 Occidental  has  contracted Claremont  Engineering to  conduct ambient monitor-
 ing  of  gaseous  criteria  pollutants and stack monitoring of selected pollu-
 tants in  the retort  off-gas, such as S02, CO and H2S.  The daily averages
 of the  measured values of the  pollutants have been  reported to the State of
 Colorado  on a quarterly basis.  The  retort off-gas  is of special concern
 because of  the  large quantity  of gas involved, which eventually must be
 vented  to the atmosphere after burning  (either in turbines to  generate
 electric  power  or through simple incineration).

      A  water problem of special concern  is the contamination of naturally
 occurring groundwater infiltrating the underground  development of an oil
 shale zone.  At Occidental's present site, there is little or  no ground
 water (pump tests  have yielded less  than 2.3 m3/hr or 10 gpm) due to the
 geology of the  area.   According to Occidental, the mining scheme for the
 center  of Plceance basin  should be so designed to keep the aquifers isolated
 from  the target oil  shale below.  In this area, the access shaft to the oil
 shale zone should  also be lined (e.g., with cement) to prevent contamination
 of the  aquifer.   In  areas where there 1s saline water below and within the
target oil shale zone, Occidental believes that 1n most cases, it 1s possible
to either seal  off the area  or  to pump the water to the surface and relnject H
 1n the  same formation  downdlp.  A closely related area of concern, the potentii
for underground leaching  of  the spent shale, 1s also not considered by Occi-
dental to be a  significant problem.  Occidental envisions that leaching of the
 spent shale will be  limited  due to the large size of the shale pieces.  The
movement of the water will be slow and probably confined to the spent chimneys
The water quality  1n Roan Creek, Logan Wash and Dry Gulch 1s currently
monitored by Occidental.

      There  is no retorted or spent shale disposal problem associated with
 the  Occidental  process.   The rock mined  is not significantly different from


the naturally occurring material in the region and will be dumped into the
canyons near the oil shale mine.  A permit for increasing the size of its
mined waste disposal pile from 382,000 m3 (500,000 cubic yards) to 6,500,000
m3 (8.5 million cubic yards) was recently granted to Occidental by Garfield
County Commissioners on January 13, 1976.  The approval of this special per-
mit provides Occidental with sufficient mined rock (low grade shale) dis-
posal capacity to expand into the large demonstration phase.  The permit
was granted on the basis that the raw shale pile would not be found to de-
grade the water quality of the area.  A second stipulation of the permit is
that upon completion of the raw shale pile, Occidental will restore the
vegetative cover to a condition compatible with comparable natural talus
slopes in the vicinity.

     Occidental has developed a list of 48 activities for which environmental
effects and permits must be considered, and has assembled a team of seven
people to gather environmental baseline data.  The studies conducted include
a meteorological study, fauna and flora studies, the completed paleontolo-
gical and archaeological studies, ambient air and retort vent gas monitoring
studies, water quality monitoring studies, and others.  The EIA for the
development of the Occidental process is scheduled to be released in December

2.3.2  Western Oil Shale Corporation (WESTCO) (16)

     Western Oil Shale Corporation (WESTCO) initiated a project in 1975,
with a consortium of 10 companies, to design a modified in-situ project on
a site in the Uinta Basin.  Three underground vertical retorts ("chimneys")
are to be investigated, using special DuPont explosives.

2.3.3  Geokinetics. Inc.(16)

     Geokinetics has also begun field tests of its "true11 in-situ process
on a site some 15 miles south of federal lease Tracts U-a/U-b.  After
explosive fracturing, a horizontal fire flood is to be employed.

2.3.4  ERDA In-Situ Research, Development and Demonstration Project

     ERDA has issued a Program Opportunity Notice for in-situ proposals from
private interests.  Federal support is indicated through commercial demon-
stration.  ERDA is currently negotiating contracts with Occidental, Equity,
Geokinetics, and Talley-Frac.


     Late in 1973 the Department of the Interior prepared six oil shale pro-
totype lease offerings on federal land in Colorado, Utah and Wyoming (33).
TaSle 2-1 summarizes the high bids received for the offered tracts (34).
Recently requests for in-situ nominations have been solicited, since no bids
were received for the Wyoming tracts in 1973.  The locations of the four
active leases and the four preferred in-situ nominations are shown in Figures
2-1 and 2-2 (35).


Table 2-1.  Results of Federal 011 Shale Lease
            Offerings (34)
i Acres)
2073 %
2073 %
Resource Estimate
106m3 (106 bbls)
200 (1300)
116 (723)
53 (331)
43 (271)
57 (354)
57 (352)
High Bonus
Bid (106 $)
(Rio Blanco Oil Shale
Standard of Indiana
Gulf Oil Corp.)
(Atlantic Richfield
Ashland Oil
Shell Oil
The Oil Shale Corp.,
Sun Oil Co/Ph1H1ps
White River Shale Oil
(Sun, Phillips, Sohlo)

      The status of development plans  at  the  federal lease tracts is reviewed
 in this section.  The developers  of tracts C-a, C-b and U-a/U-b have submitted
 detailed development plans  to  the area oil shale supervisor.  The in-situ
 nominations have been made  and final  choice  for leasing awaits an Environmental
 Impact Statement (EIS).   In March of  1976 Roxana (Tract C-b) formally requested
 a  suspension of tract development requirements and a postponement of the 4th
 and 5th bonus payments as required by the lease.  RBOSP (Tract C-a) and WRSP
 (Tracts U-a/U-b) have submitted similar  suspension requests to the Department
 of the Interior in July  of  1976.   Althouoh the area oil shale supervisor
 (AOSS)  is currently reviewing  the Detailed Development Plans for each tract,
 the Secretary of the Interior  granted the suspension of development at C-a  and
 C-b in August 1976, and  at  U-a/U-b 1n October 1976.

 2.4.1  Tract C-a - Rio Blanco  Oil Shale  Project (RBOSP) (7)

      Project Description:    The Rio Blanco Oil Shale Project (Standard of
 Indiana and Gulf Oil  Corp.) has recently submitted a detailed development
 plan (DDP) to the area oil  shale  supervisor  (AOSS) in Grand Junction.  This
 plan envisions a phased  development of Tract C-a using open pit mining (Table
 2-2).  Mining will  commence at the northwest corner of the lease tract and
 will have disturbed less than  300 hectares (750 acres) at the end of Phase  I.
 Phase I will involve the construction and operation of two TOSCO II
 retorts, each capable of processing 9,700 tonnes (10,700 tons) of oil
 shale per day.  During 1982, total  crude shale oil production is planned at
 1,400 m3/day (9,000 bbU/day)  (see Table 2-2).  Phase  I processing opera-
 tions will Include a thermal cracking plant  and a  sulfur recovery plant.

      Phase I support systems include  water supply from ground water sources
 on the tract (5.3-9 m3/min  or  1400-2400  GPM), a power line from an existing
 230 KV line near the  White  River,  and an extension of the existing Ryan Bulch-
 C-a road to Rangeley.  Product oil  will  initially be pipelined to Rangeley,
 thence through an existing  AMOCO  pipeline to a refinery.  Peak manpower re-
 quirements during Phase  I is expected to be  about 700 employees.

      In addition to DDP  approval  by the AOSS, the Rio Blanco project requires
 several  government actions  before development can proceed.   Plans call for
 location of processing facilities and the retorted shale disposal area outside
 the tract (to the north).   An  amendment  to the Mineral Leasing Act of 1920 is
 apparently required to allow this use of off-tract federal  lands, and such
 legislation is now pending  in  the U.S. Congress (S.2413 and H.11163).  RBOSP
 also requires approval of rights-of-way  for  service corridors and State of
 Colorado support for  the proposed Rangeley access road.  Finally, RBOSP envi-
 sions its employees living  primarily  in  Rangeley, and has assisted the town
 in planning for growth.  Urban expansion will probably require access to sur-
 rounding federal  land; a mechanism for acquiring such land will be required.

      Phase II operations at C-a are envisioned to begin in 1985 and will employ
 both TOSCO and Paraho (gas  combustion) retorting.  Open pit mining will expand
 to about 108,000 tonnes/day (120,000  tons/day) to feed the retorts   Rio
 Blanco  plans to upgrade  crude  shale oil  at 8,960 m3/dav (56,000 bbls/day) by
 delayed coking,  and by hydrogenation  of  naphtha and gas oil distillation

                  Table 2-2.   Tract  C-a - Rio Blanco Oil  Shale  Project  Summary  (7)
   Ore Haulage
   Overburden Haulage



   Pipelineable Shale Oil
   Upgraded Shale Oil
   Ammonia (anhydrous)
   Moisturized Processed Shale


                                              PHASE I
                                                         PHASE II
      Stage 1
      Open Pit
    10,000 tonnes/day
     Belt Conveyor
       TOSCO II

   Thermal Cracking
                            stage 2
                           Open Pit
                         19,400 tonnes/day
                          Belt Conveyor
                            TOSCO II

                         Thermal  Cracking
         Open Pit
    108,000 tonnes/day
       Belt Conveyor
       Belt Conveyor

Combination of TOSCO II  & Gas
Delayed Coking & Hydrotreating
    Belt Conveyor
720 m3/day (4,500 BPSD) 1440 m3/day(9,OOOBPSD)

    11 tonnes/day          22 tonnes/day
                                                 8,930 ,i)2/day  (55,800 BPSD)
                                                      153 tonnes/day
                                                      210 tonnes/day
                                                      425 tonnes/day
   10,000 tonnes/day     20,000 tonnes/day         107,700 tonnes/day

1.76x10^3^(1,390 AFY) 3.5xlo6m3/yr(2,370  AFY)  12.7xlo6m3(10,000 AFY)

      17.7 MW                28.8 MW                    227 MW

      2 years
      3 years

                            2 years
                            3 years

        3 years
        20-30 years
Notes:    BPSD = bbls per stream day
         AFY  * acre-feet per year
         MW   = megawatts =10* watts

Hydrogen will be produced on site by partial  oxidation (gasification) of heavy
shale oil distillatiorr residue.  The operation is designed to consume
all gaseous products as plant fuel.  Elemental sulfur and ammonia will be
recovered as co-products from gaseous and liquid product streams.

      Phase II operations are expected to be supplied by "on tract"  ground
 and surface water.  Expansion beyond 8,960 m3/day (56,000 bbls/day) of shale
 oil will require additional water supplies and Rio Blanco has applied for an
 8.5 m3/sec (300 3/sec) water right on the White River.

      Environmental Programs:  Mining and shale preparation air pollution con-
 trol at Tract C-a will  include frequent watering at  the mine and on trans-
 port roads, enclosing and spraying raw and crushed shale  at transfer points,
 and using baghouse filters with induced-draft fans for crushing and
 screening operations.

      Process pollution  control  is to be accomplished by technology  similar
 to that described in the TOSCO II section (2.2.1).  Phase I operations
 will include a thermal  oxidizer to handle certain ammonia and sulfur contain-
 ing gas streams, excess fuel gas, and oil/water separator sludges.

      Phase II air pollution control  will include technology similar to that
 used in Phase I, with the combination of GCR and TOSCO II retorts supplying
 the operation with entirely gaseous  fuels.  Cleaned low and high Btu fuel
 gases generally present a lower emissions potential from process heaters
 than liquid fuels.  Hydrogen sulfide and ammonia removal  from in-plant fuels,
 the use of wet and dry  venturi  scrubbers, and incineration of trace hydrocarbons
 1n the TOSCO II preheat system are the major air pollution control  techniques.

      Water quality control at Tract C-a is based on a zero discharge concept.
 Rio Blanco plans to collect storm  and surface waters, mine waters, and pro-
 cess waters for in-plant use or for controlled evaporation.  The ultimate
 disposition of wastewater is evaporation, or entrapment as a permanent com-
 ponent of retorted shale.

      RBOSP plans to dispose of retorted shale, mine overburden, and other
 solid wastes (spent catalysts,  coke, lime sludge, spent zeolites) on a site
 called "84 Mesa," north of Tract C-a.   This  site is sufficient to accommodate
 waste for up to 30 years before backfilling  of the open pit .is planned.   Tests
 are currently underway to determine  the best revegetation techniques for the
 soil and overburden profile which would eventually "cap"  the retorted shale

      RBOSP is conducting a two-year baseline monitoring program to  define
 natural conditions at Tract C-a prior to oil shale development (part of
 lease stipulations).  Continued monitoring of meteorology, ambient  air and
 water quality, ground and surface water hydrology, soils and geology, ter-
 restrial and aquatic flora and fauna is planned through development stages
 of the project.  A more detailed description and evaluation of monitoring
 activities at C-a and other lease tracts is presented in Chapter VI of this


 2.4.2  Tract C-b (Roxana)  (6)

      Project Description:   Tract C-b is  a  joint  venture of Ashland Oil,  Inc.
 and Shell  Oil Company, known as the Roxana Shale Oil Company.  Atlantic
 Richfield  and The Oil  Shale Corp.  (TOSCO), originally partners in the C-b
 venture, have withdrawn from the project.   Roxana'* two remaining partners
 submitted  a detailed development plan to the Area Oil Shale Supervisor
 (AOSS)  in  February 1976.  The future of  the project is uncertain however,
 due to  ARCO and TOSCO withdrawal,  technical and  economic uncertainties about
 extraction of deep Mahogany Zone shale on  the  tract, and lack of a federal
 energy  policy.

      Table 2-3 summarizes  the Roxana project plans.  The C-b DDP envisions
 development mining (Phase  I)  for about 5 years in order to establish deep
 mining  technology and  define  geologfc and  hydrologic conditions on the tract.
 Coarse  ore would be stockpiled until  completion  of the Phase II construction
 of  surface retorting and upgrading  facilities.   Roxana plans to use TOSCO II
 technology (both Ashland and  Shell  are members of the Colony Group), and
 surface operations are expected to  be similar  to those planned by Colony for
 use at  the Parachute Creek property.

      Water produced during Phases  I and  II may  exceed project demand, and
 excess  waters will  be  directly discharged  if quality is adequate, and rein-
 jected  or  used for spray irrigation if water is  of poor quality.  Phase  III
processing operations  will  likely require  more water than can be obtained
from aquifers  on  the tract, and Roxana plans to  obtain additional water
 from  the Colorado River (perhaps in conjunction  with Colony development)'.

     A  product pipeline(s)  will  follow the water supply corridor south from
 the tract  via Parachute Creek to the Colorado  River.  An electric power
 corridor will  extend to the north and east to  connect with the White River

      Environmental  Programs:   During the mine  development and construction
 phases  at  C-b,  air pollution  sources will  mainly be fugitive dust, stationary
diesel  emissions,  and  vehicular emissions.  Dust control will be accomplished
 by watering,  by use of chemicals, and by minimizing exposed soil surfaces.

     Shale preparation and  retorting process emissions and effluents, and
 associated pollution control  technologies  at C-b are the same as those des-
 cribed  in  Section  2.2.1  of  this report (TOSCO  II process).  All process waste
water will  be  consumed 1n the moisturizing of retorted shale.

     Retorted  shale and other solid  wastes will  be disposed of on the east
 stde of Tract  C-b  in Sorgum Gulch (see Section 4.3).  During Phase I, a dam
will be constructed  below Sorgum Gulch for collection and storage of excess
mine water.  Later,  the  dam will serve to  retain any runoff from retorted
shale piles.  Colony's experience in  revegetating spent shale at Parachute
Creek will   be applied  at C-b.  As was the case with RBOSP, Roxana is conduc-
ting a two-year baseline environmental monitoring program as required by lease


                         Table 2-3.  Tract C-b - Roxana 011 Shale Project Summary  (6)
Ore Haulage
Processed Shale Haulage
Plpellneable Shale 011
Upgraded Shale 011
Moisturized Processed
Nine Development
(room & olllar)
3.5 x 10 total tonnes
To Storage via Belt Conveyer

Excess Hater Produced
5-10 MH
5 years
1 year
Development Mining
Stockpiling of Ore
Plant Construction
Plant Construction
Excess Water Produced
20 MH
4 years
1 year
Room and Pillar
60,000 tonnes/day
Belt Conveyor
Delayed coking,
8000 m3/day (50.000
175 tonnes/day
136 tonnes/day
727 tonnes/day
60,000 tonnes/day
Total Requirement
435m3/sec(12.3 CFS)
100 MH
20-30 years

2.4.3  Tracts U-a/U-b - White River Shale Project (WRSP) (21)

     Project Description

     The lessees Of Tract U-a (Phillips Petroleum, Sun Oil)  and U-b (Phillips,
Sun, SoBio) have proposed joint development of the two tracts, which adjoin
one another.  A Detailed Development Plan for the two tracts was submitted to
the Area Oil Shale Supervisor (AOSS) in April 1976.  Final  DDP approval  is
still pending.  In late 1976  WRSP requested a temporary suspension of
operations and further lease payments on both tracts.

     The project activities planned for the tracts are expected to occur in
four phases, as summarized in Table 2-4.  In Phase I a 335  meter (1100 ft)
deep access shaft for a subsequent room-and-pillar mine will first be estab-
lished near the center of the combined tracts, in order to permit testing of
the shale deposft.  Mining will be initiated some six months later.  Mine de-
velopment will continue, and extend throughout the following Phase II, with an
expansion of production from 1814 tonnes (2000 tons) to 9100 tonnes (10,000
tons) of raw shale per day.

     Phase II will be of 4 years duration, and will involve the construction
and operation of a single modular vertfcal retort with a throughput capacity
of up to 9100 tonnes of shale (10,000 tons) per day.  The retort design has
not yet been  selected, but could  be a  Paraho direct-heat design later
modified for  indirect heating, or another  available  verticle-type  retort.
At a retort feed rate of 6800 tonnes (7500 tons)  of coarse  shale per  day,
some 750 cubic meters (4700 barrels) of crude oil would be  produced daily.

     A commercial plant (Phase III), with a  first "train" projected capacity
of 72,500 tonnes (80,000 tons) per day, will  be constructed for start-up some
2*s years after the successful conclusion of  Phase II.  This will be followed
by start-up of a second commercial train of  the same capacity some 1% years
after the first, thus bringing total plant production  capacity to  an  ultimate
145,000 tonnes  (160,000 tons) per day.

     It is currently intended that the major portion  (85%)  of the  Phases  III
and  IV retorting will be carried  out in  vertical, gas-combustion type-, direct
and  tndtrect-mode retorts, but that t&e  15%  of crushing fines produced will  be
pyrolyzed in  TOSCO II-type retorts.  It  is expected  that all of the 15,800
cubic meters  (100,000 barrels) of shale  oil  produced  daily  at maximum scale-up
will be upgraded in facilities similar to  those to be  used  for  the Colony and
Tract C-b projects.

     During  Phases I and  II water for  the  White River Shale Project will  be
obtained from a 146,000 m3  (118,000 acre-ft) reservoir behind  a damon the
nearby White  River, to be constructed  by the State of Utah  and  the Ute Indians.
Whin commercial production is attained  (Phases III and IV)  water requirements
will range  from 13,000 acre-feet  (16,000,000 m3)  to  26,000  acre-feet
(32  000 000 m?) per^ year.  These  could also  be obtained from  the above-mentioned
multi-purpose reservoir, or alternatively,  by pumping  from  the Green  River
and  Flaming Gorge Reservoirs.


                    Table 2-4.  Tracts U-a/U-b - White River Shale Project Summary (21)

Ore Haulage
Pipelineable Shale Oil
Upgraded Shale Oil
Liquid Fuels
Moisturized Processed

Open Mine
(room and pillar)



3 megawatts
1 . 5 yrs .
1.5 yrs .

Development and
9,100 tonnes/day

Single Vertical
Gas Treating

750 M3/day
2.1 tonnes/ day
6,550 tonnes/day
(includes fines)
870 Iiters/m1n.
13.6 megawatts
3 yrs.
2.5 yrs.

Commercial Production
72,500 tonnes/day

Gas Combustion/
Hyd retreating
S, NH3 Recovery

8,000 M3/day
7,600 M3/day
75 tonnes/day
187 tonnes/day
1 ,240 M3/day
58,700 tonnes/day
17 M3/m1n.
100 megawatts
2 yrs.
20-30 yrs.

Commercial Productloi
145,000 tonnes/day

Gas Combustion/
S, NHs Recovery

16,000 M?/day
15,200 M3/day
150 tonnes/day
374 tonnes/day
2,480 M-Vday
117,400 tonnes/day
34 M3/m1n.
200 megawatts
2 yrs.
20-30 yrs.

     At full-scale production the Project is expected to be self-sufficient
in utilities and fuel requirements.  Modest quantities of shale oil  initially
produced will be transported to market by truck.  In the commercial  phases
(III, IV) the upgraded shale oil products will probably be sent by pipeline
northeast to Casper, Wyoming, and thence by conventional trans-continental
pipeline to refiners.

     Environmental Programs

     During all three operating phases of the White River Project, fugitive
dusts from mining and crushing are to be controlled by the use of water sprays,
baffled settling chambers,  and wet scrubbers.   Wet  scrubbers will also be  used
for partlculate emissions control during modular and  full-scale retorting.

     All of the shale oil produced daily at maximum scale-up will  be upgraded
in facilities similar to those used for the Colony Operation.  As  a  result,
some 3% of the wastes disposed will be spent catalysts, sludges, and arsenic-
laden solids from TOSCO II-type shale oil upgrading units.  These  wastes  will
be discarded with the retorted shale.  Waste disposal is expected  to be at
Tract U-a, in Southam Canyon, to the west of the plant area.  The  processed
shale pile will be built southward along the eastern half of the canyon,  to-
ward the southern limits of Tract U-a.  A retention dam at the northern end
of t&e canyon vrill prevent contamtnatton of the White River.  The  finished
processed shale disposal pile will be contoured to blend with the  natural ter-
rain, and revegetated.

     It ts projected that the 72,500 tonnes (80,000 tons) per day  and 145,000
tonnes (160,000 tons) per day commercial operations will collectively dispose
of a total of about 1,040 million metric tons (1,150 million tons) of processed
shale and plant wastes during the 20 plus years of contemplated full-scale
production.  This will result in a disposal pile in Southam Canyon of 727
million cubic meters (950 million cubic yards) volume, occupying some 366
hectares (900 acres), with an average depth of 61 meters (200 ft).  A two-year
baseline environmental monitoring program is proceeding at U-a/U-b.

2.4.4  Federal In-Situ Lease Tract Nominations (35)

     In April 1975, the Under Secretary of the Interior called for nomina-
tions of areas for leasing to be developed by in-situ technology.   Six
tracts in Colorado and three in Utah were nominated, and a tract selection
committee (composed of state personnel and Department of Interior  personnel)
recommencWtwo preferred and two alternate tracts.  The preferred sites are
shown in Figures 2-1  and 2-2 as "insitu #2" (Colorado) and "in-situ #8"  (Utah).
The alternate sites are "1n-situ #7," and  in-situ #9," in Utah.  Major
criteria for selecting the preferred sites were:

        Lack of conflicting mineral  leases (or absence of minerals
         associated with oil shale).

        Shale deposits likely to be available only or primarily by
         employing 1n-situ extraction methods.

        Absence of  ground water

     t   Socio-economic  factors  (e.g.,  local  towns  likely to be affected)

        Accessibility  (e.g.,  existing  roads)

        Environmental considerations

     The tract selection committee submitted its recommendations to OSEAP
in September 1975.  The Oil Shale Environmental Advisory Panel  reviewed the
selections and recommended four sites for consideration by the Assistant
Secretary of the Interior.  Final decision on which tracts to be leased
awaits preparation of an Environmental Impact Statement.


 1.  Crookston, R. B., "Mining Oil Shale," Society of Automotive Engineers
     (SAE), Seattle Washington, August 11-14, 1975.

 2.  Cummins, A. B., and Given, I. A., "Mining Engineering Handbook," Society
     of Mining Engineers of American Institute of Mining and Metallurgical
     Engineers, 1973.

 3.  Blasters Handbook, 6th Edition, E. I. DuPont De Nemours.

 4.  Langefurs, U., and Kihlstrom, B., "Rock Blasting, 2nd Edition,"  Wiley,

 5.  Banks, C. E., "Data Compilation for Study of Surface Mining of Oil  Shale,"
     9th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado,
     April 29-30, 1976.

 6.  Detailed Development Plan, Vols. I and II, Federal Oil Shale Lease  Tract
     C-b, submitted to Area Oil Shale Supervisor, February 1976.

 7.  Detailed Development Plan, Vols. I-V, Federal Oil Shale Lease Tract C-a
     (Rio Blanco Oil Shale Project), submitted to Area Oil Shale Supervisor,
     March 1976.

 8.  McCarthy, M. E., "The Status of Occidental Oil Shale Development,"  9th
     Oil Shale Symposium, Colorado School  of Mines, Golden, Colorado, April
     29-30, 1976.

 9.  Hoskins, W. N., "Technical and Economic Study of Candidate Underground
     Mining Systems for Deep, Thick Oil Shale Deposits," 9th Oil Shale Sympo-
     sium, Colorado School  of Mines, Golden, Colorado, April 29-30, 1976.

10.  Russell, P. L., "Bureau of Mines Oil  Shale Reserach," 9th Oil  Shale
     Symposium, Colorado School of Mines,  Golden, Colorado, April 29-30, 1976.

11.  Stone, R. B., "Technical and Economic Study of an Underground Mining,
     Rubblization and In Situ Retorting System for Deep Oil Shale Deposits,"
     9th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado,
     April 29-30, 1976.

12.  Colony Development Operation, Draft Environmental Impact Statement  (EIS),
     U.S. Department of the Interior, Bureau of Land Management, December, 1975.

13.  Colony Development Operation, An Environmental Impact Analysis for  a
     Shale Oil Complex at Parachute Creek, Colorado, Part I, 1974.

14.  Prien, C. H., "Current Oil Shale Technology:  A Summary," in Guide  Book
     to the Energy Resources of the Piceance Creek Basin Colorado.  Rocky
     Mountain Association of Geologists, 25th Field Conference, 1974.


15.  Whitcombe, J. A. and Vawter, G. R., "The TOSCO II Oil Shale Process,"
     Science and Technology of Oil Shale, Ann Arbor Science Publishers, 1976.

16.  Cameron Engineers, Synthetic Fuels Quarterly, March 1976, p. B-4.

17.  Sladek, T. A., "Recent Trends in Oil Shale - Part 2:  Mining and Shale
     Oil Extraction Processes," Mineral Industries Bulletin, Colorado School
     of Mines, Vol. 18, No. 1, January 1975.

18.  Jones, J. B., "The Paraho Oil Shale Retort," 9th Oil Shale Symposium,
     Colorado School of Mines, Golden Colorado, April  29-30, 1976.

19.  McKee, J. M. and Kunchal, S. K., "Energy and Water Requirements for an
     Oil Shale Plant Based on the Paraho Process," 9th Oil Shale Symposium,
     Colorado School of Mines, April 29-30, 1976.

20.  Op. Cit., 7, Vol. I.

21.  Detailed Development Plan, Federal Oil Shale Lease Tracts Ua and Ub
     (White River Shale Project), submitted to Area Oil Shale Supervisor,
     June 1975.

22.  Cameron Lngineers, Synthetic Fuels Quarterly, September 1974.

23.  Union Oil Company, data and information provided to TRW in response to
     technical inquiries, 1975.

24.  Superior Oil Company, Application for Consolidating Oil Shale Lands by
     Acreage Exchange #C-19958, Bureau of Land Management, U.S. Department
     of the Interior, Denver,  Colorado.

25.  Weichman, B., "Superior Process for the Development of Oil Shale and
     Associated Minerals," 7th Oil Shale Symposium, Colorado School  of Mines,
     Golden, Colorado, April  18-19,  1974.

26.  Schmalfeld, P., "The Use  of the Lurgi-Ruhrgas Process for the Distilla-
     tion of Oil Shale," Quarterly of the Colorado School of Mines,  Vol. 70
     (3), July 1975.

27.  Lurgi  Mineraloltechinek (GMBH), "Development of the Lurgi-Ruhrgas Retort
     for the Distillation of Oil  Shale," Frankfort (Main), October 1973.

28.  Chemical  Engineering. December 8, 1975, p. 81.

29.  Cameron Engineers, Synthetic Fuels Quarterly. June 1974.

30.  McCarthy, H. E., and Cha, C. Y., "Development of the modified in situ
     Oil Shale Process," 68th  AIChE Annual  Meeting, Los Angeles, California
     November 16-20, 1975.

31.  Ridley, R. D., Testimony on H.R. 9693 "Shale Oil  Development Corporation
     Act,"  Subcommittee on Energy, Committee on Science and Astronautics,
     House  of Representatives, Washington, D.C., May 14, 1974.

32.  Cameron Engineers, Synthetic Fuels Quarterly,  June  1975.

33.  Final Environmental Impact Statement for the Prototype  Oil  Shale  Leasing
     Program, Vol. I, Regional Impacts of Oil Shale Development, U.S.  Depart-
     ment of the Interior.

34.  Ash, H. 0., "Federal Oil Shale Leasing and Administration," op.cit.  14.

35.  Report by the Interagency In Situ Oil Shale Trace Selection Committee
     to the Assistant Secretary of the Interior, Lands and Water Resources,
     September 5, 1975.

36.  Hopkins, J. M. et.al.,  "Development of Union Oil Company Upflow Retorting
     Technology," 81st  National Meeting of the American Institute of Chemical
     Engineers, Kansas  City,  Missouri, April 11-14, 1976.


     The oil shale technologies and development activities reviewed in Chapter
2.0 are likely to be the major contributors to commercial shale oil
production in the near future.  Each technology and activity will  have asso-
ciated with it certain waste streams and environmental  problems. Thus  Chapter  3
is a discussion of characteristics of the major technologies which influence
the composition, properties, and quantities of wastes which may be generated
during future commercial operations.  The approximate inventories  of waste
quantities are presented where information 1s available.  Where appropriate,
a brief discussion of planned pollution control practices 1s Included.
Section 3.1 1s a review of the types, sources, and Inventories of
atmospheric emissions. Section 3.2 is a review of process water requirements,
wastewater characteristics, and wastewater treatment alternatives.  Section
3.3 includes a discussion of some important characteristics of raw and retort-
ed shales, an identification of non-shale solid wastes, and a summary  of the
approximate quantities of such wastes which would be associated with major
development activi ties.


     Atmospheric emissions can arise from several activities or operations
during oil shale processing.  A breakdown of the more important sources of
emissions is presented in Table 3-1.  The major source  of S02, NOX, and CO
is fuel combustion for process heat; S02 is also emitted in the tail gases
of sulfur recovery operations.  The use of fuel oils in mobile equipment and
in explosives will result in emissions of CO and NOX.  Hydrocarbons are pre-
sent in both combustion emissions and in product storage tank vapors.   Emis-
sions of particulate matter can result from  1) blasting,  2) raw and  spent
shale handling and disposal,  3) raw and spent shale dust in process gas
streams,  4) fuel combustion, and  5) site activities which generate fugitive

     Emissions of potentially hazardous substances may occur during the
extraction and processing of oil shale.  Silica  (quartz) may be present
in dust derived from oil shale and associated rocks and in fugitive dust.
Particulate emissions from fuel combustion and fugitive dust from spent shale
handling and disposal can contain polycyclic organic material (POM) and cer-
tain trace metals.  Gaseous ammonia,  hydrogen  sulflde, and  volatile organ1cs
may be released during moisturizing and subsequent  cooling  of  retorted shale.
*Fugitive Dust refers to particulate matter which is discharged to the atmo-
 sphere in an unconfined flow stream, generally as a result of mechanical
 disturbance of granular material exposed to air.

       Table  3-1.   The  Sources and Nature of Atmospheric  Emissions
                       from 011  Shale  Extraction and Processing
0 Oil Shale
 Raw Shale
and Utility
 Gas Cleaning
e Product
 Solid Waste
Emission Generating Activity
Nine equipment use
 Fuel use
Equipment use
 Tuel us'e
Ore Siprage
Shale Preheat
 Fuel use
 Shale dusts
Heat Carrier Reheating
 Fuel use
 Combustion of shale
organic material
Spent Shale Discharge
 Moisturizing or dry exit
Process heaters/furnaces
 Fuel use
Sulfur recovery and tall gas
Hydrogen production
 C02 removal
Fuel use
Tank evaporation
Equipment use
 Spent snaie transport
and spreading
 Coke, spent catalyst.
other wastes - transport
and spreading
Criteria Pollutants
dust*(D. CO, NOX, HC
PM*(2). CO. NOX. S02. HC
PM*(2). CO. NOX. S02. HC
PH*{1,2), CO. NOX. S02, HC
HC's Z
PM*(2). CO, MOX. S02. HC
PM*(2). CO, NOX. S02. HC
PM*{3). HC's
PH*(1), CO. NOX, S02. HC
PH*(2). CO, MOX. HC. S02
PH*(2). CO, NOX, S02, HC
Non-Criteria Pollutants
Kg. Pb salts, silica
trace elements
trace elements, trace
organ Ics
trace elements, trace
H2S, NH3, volatile and
trace organlcs
cs2. cos
trace organlcs
metals (N1, Cr. Fe. Ho).
trace organlcs
Suspended particulate matter Is the defined criteria pollutants:
   PH 1s broken down Into 3 general categories In this table.
   (1)  Raw shale and natural soil dusts
   (2)  Fuel combustion ash and sooty material
   (3)  Spent shale dust (Including dust from other solid wastes)

Catalyst materials may release participate tter containing trace metals to
the atmosphere during regeneration, handling, or final disposal.

     Section 3.1.1 below is a comparison of TOSCO II, Paraho,  and Union B
retorting processes for potential emissions of criteria and hazardous  pollu-
tants.  Section 3.1.2 reviews shale preparation, retorting, and upgrading
emissions inventories or estimates which have been prepared for oil  shale
developments.  Section 3.1.3 presents an estimate of fugitive  dust emissions
associated with the extraction of oil shale.

3.1.1  A Comparison of Retorting Processes for Potential Emissions

     Potentially commercial surface retorting technologies fall into three

                        Class                               Examples

  (1)  Externally heated recycle solids retorts    TOSCO II
  (2)  Gas combustion retorts (GCR)                Paraho Direct Mode
  (3)  Externally heated recycle gas retorts       Union B, Paraho Indirect

      Generally,  the retorting  operation itself does  not involve atmospheric
 emissions;  gaseous, liquid,  and solid  streams  leaving the  retort are  handled
 by downstream systems  before reaching  an atmospheric interface.   However,
 certain features  inherent  in the retorting  method  influence the nature and
 magnitude of emissions  from  other  sources in the associated shale oil  plant.
 The discussion below focuses on TOSCO  II, Paraho,  and Union B  technologies
 with emphasis on process stream composition and quantities.   Differences
 in potential  emissions  for criteria  pollutants (SOg, NOX,  particulates,  CO,
 and hydrocarbons)  and  hazardous substances  (polycyclic organic  material  and
 trace  elements)  are discussed.

      It should be  cautioned  that a comparison  of processes for  potential
 emissions  (and other wastes)-should  consider similar sized operations,  and
 appropriate  control  technologies applied to waste  streams.  Since processes
 such as TOSCO II  are more  advanced and more information is presently  avail-
 able for such processes, waste  streams are  more well  defined than those asso-
 ciated with  less  developed processes.   Conclusions reached in  this  section
 are not intended  to endorse  or  condemn a given process, but rather  to high-
 light  process features.

     Sulfur  Compounds:   Sulfur  in  raw  oil shale amounts to about 0.7% by
weight, approximately  1/3  associated with the  organic fraction; and 2/3 as
 pyrite (Fe2S) (1).   During kerogen pyrolysis,  about  40% of the organic sulfur
 in  shale appears  as t^S in the  produced gases, and the other 60% as heavier
sulfur compounds  in raw shale oil  and  in the spent shale carbonaceous residue.
Pyritic shale sulfur does  not decompose under  non-oxidizing retorting

       JV   retort produces about 187 M3 of net gas along with each cubic
  iL I S^de,n5alL01-i(1S40^Foper BBLK2,3).  The gas contains about 3-5
volume % H2S, and  the oil about 0.9 weight % total sulfur.  The sulfur is
partially  removed  from both  oil and gas before in-plant use or sale   Conse-
quently, S02 emissions from  plant fuel use depend upon both the fuel mix and
hejJfie!i ?f su]Jur removal  from gas and liquid products.  Finally, SO? can
be emitted in sulfur recovery plant tail gases, or in tail gases from
subsequent cleanup operations.
     A  gas combustion retort  (GCR) produces a significantly larger
                          (~2000 MW) (10,900 SCF/BBL) than a TOSCO II re-
of gas per volume of oil (*
tort (4,5). Sulfur in such retort gases amounts  to  about  O.U  by volume
(almost entirely as H2S).  The smaller total  quantity  of  sulfur in GCR re-
tort gas compared to TOSCO II gas may partially  reflect the  higher grade
of raw shale (and associated higher sulfur content)  which  has been used in
the TOSCO II retort than in the GCR retort.   Also,  the more  rapid pyrolysis
of kerogen and the shorter residence time of organic vapors  at retorting
temperatures in the TOSCO II retort may result in more complete conversion
of organic sulfur to H2S.  Table 3-2 shows a comparison of total sulfur in
TOSCO II and GCR retort gases.

    Table 3-2.   Comparison of Total  Sulfur in Raw Retort  Gases (2,3,5,6)
GCR (direct
mode Paraho)
Vni.imp M3 gas
Produced M3 oil
Sulfur in Gas
(Vol %)
0.1 - 0.2
Weight Sulfur (Kg) in
Gas per M3 of Oil
3 - 6
     In the combustion zone of a GCR, organic sulfur and pyrite are burned
along with the carbonaceous residue of retorted shale.  The oxides of sulfur
are apparently captured by the alkaline oxide/carbonate minerals remaining
in the shale* and are discharged from the retort as sulfite or sulfate salts
with burned shale (7,9).

     Externally heated recycle gas retorts (i.e., Union B) produce net gas
of composition similar to TOSCO II gas.  Sulfur content of raw shale oil  and
of the carbon residue associated with spent shale are also comparable (10,11).

     Actual S02 emissions associated with individual retorting processes  will
depend upon the degree of sulfur removal accomplished for in-plant fuels,
the extent of on-site shale oil processing, and the degree of control  applied
to sulfur recovery tail gases.

     Oxides of Nitrogen:   Combustion of any hydrocarbon fuel will produce
oxides of nitrogen when air containing elemental nitrogen is used as the
oxygen supply.  The extent of NOX formation from oxygen and nitrogen in air
during combustion is related primarily to flame temperature, residence time,
and air/fuel mixture.  In addition, organic nitrogen contained in fuel can


be  partially  oxidized  to  NO  and  N02, depending on the above variables and
the level  of  fuel  nitrogen.   Generally, gaseous fuels tend to emit lower
quantities of NOX  than liquid or solid fuels, given comparable combustion
conditions and fuel  nitrogen levels  (13).

     Most  retorting  processes require heat supplied by combustion of retort
gases,  shale  oil,  or carbonaceous residue remaining after pyrolysis of shale
organic material.  Nitrogen  in raw oil shale exists as a chemically bound
component  of  the kerogen matrix  (1). In TOSCO II retorting about 35% of the
original shale nitrogen in shale appears as the sum of ammonia in retort
gases and  organic  nitrogen in crude shale oil.  The remaining 65% is found
in  the  retorted shale  (with  carbonaceous residue) (2).  Combustion of raw
gas, crude shale oil,  or the spent shale carbonaceous residue may result in
a partial  conversion of the  bound N to NOX.

     In the GCR process the  residual carbonaceous material associated with
"retorted"  shale is  burned internally in the retort.  The recycle gas is
known to contain some  ammonia but very little NOX (5,6).  Mass balance calcula-
tions suggest  that the organic nitrogen entering the combustion zone of the
GCR is  partially converted to elemental nitrogen.  However, total ammonia 1n
GCR retort gas  and total nitrogen in GCR product oil per ton of Input shale
1s about the same as the totals  in TOSCO II gas and oil..

     A  TOSCO  II plant may present a larger NOX emissions potential than a
GCR plant, depending on the  quantity and nitrogen level of shale-derived
oil which  must be used to supplement gas for process heat.  Net TOSCO II
gas is  likely  to be of sufficient quantity to supply retorting process heat,
but not to  supply both retorting and on-site upgrading heat requirements,
and feedstock  for hydrogen production (2,3).  A GCR retort, on the other hand,
produces a large excess of low Btu gas over retorting heat requirements,
and such gas is available for supplying heat for upgrading processes (it is
doubtful,  however, that GCR  gas could be economically used as a feedstock
for hydrogen production) (14).

     Particulate Matter (2,3,7,9):  Generally, processes which require small
sized shale feed (e.g., TOSCO II) will have more uncontrolled particulate
emissions  during crushing and raw shale handling operations than processes
which require  large  feed (GCR-Paraho).  Also, the presence of small raw and
retorted shale  particles in  preheat and elutriator systems of a TOSCO II
plant_result in a greater particulate emissions control requirement than.
would be the case with a similar sized GCR retort.  Particulates result-
ing directly from fuel combustion for in-plant purposes are mainly a function
of fuel mix; the GCR retort  will produce an excess of fuel gas, a TOSCO II
operation may  have to  burn some  product oil for process purposes.  Moisturiz-
ing of  retorted TOSCO  II shale may require greater particulate emissions
control than  moisturizing  the larger sized GCR retorted  shale.

     The feed  to a retorting  plant always presents a particulate control pro-
blem.   Run-of-Mine raw shale commonly contains about five weight percent
of ore of  less  than 12.7 mm  (1/2 inch) size.  A sizable percentage of this
segment will become minuslOOy particulate as a result of primary crushing.

                ^ PPD   "n0"5 ^  PreS6nt mre f
  nn   of  ho f   Sc  ?lon  process'  re stora9e and handling and dis-
  posal  of the fine TOSCO  II  retorted shale are potential fugitive sources.
  dSSEn  rSSl! r"6-  ^ GC5 a?d Un1on will require proper handing and
  disposal  in  order to  minimize  fugitive emissions.

      Site use activities which may generate fugitive dust are generally not
  process  specific.   The use  of  open pit vs. underground mining will be the
  largest  factor determining  total  fugitive emissions associated with the ex-
  traction  of  oil  shale (15).

      Hydrocarbons  (HC's) and Carbon Monoxide (CO):  Emissions of HC's and CO
 occur curing  incomplete combustion of fuels in process heaters and in mobile
 equipment.  Hydrocarbons may also be vaporized during product storage.  Equip-
 ment use  and  evaporative hydrocarbon emissions are not expected to be process

      The  TOSCO II  retort may present a somewhat greater hydrocarbon emissions
  control requirement than direct mode Paraho or Union retorting since pre-
  heated TOSCO  flue  gases contain fresh kerogen derived vapors.  Incineration
  of these  gases can reduce hydrocarbon concentrations to less than 90 PPM (3).
  There may be  other hydrocarbon sources in Union or 6CR retorting that have not
  been quantified.

      The  largest source  of  CO  in  an oil shale operation is mobile equipment
  used for  mining and transport  (3,7). The quantity of such emissions is a
  function  of  mining method and  haul distances rather than retorting process.

      Polycyclic Organic  Matter (POM)*:  The pyrolysis of essentially any
  type of organic material produces a certain amount of POM, and oil shale
  kerogen  is no exception  (17).  Generally, POM compounds have a low volatility
  and will  be  associated with high  boiling liquid or solid products, or parti-
  culate matter.

      Although POM is  known  to  be  present in carbonaceous retorted shales, the
  biological availability  and potential hazard of such material is not accu-
  rately known  at present.  (See Section 3.3)

      Release  of POM to the  atmosphere during oil shale processing can occur
  via three major pathways:

      (1)   Handling and disposal of retorted shale - fugitive particulates
            and possible volatilization of hydrocarbons.

      (2)   Combustion  of shale  derived oils containing POM.

      (3)   Flue gases  containing entrained retorted shale particulates,
            along with  retort gas or spent shale coke combustion products.

*POM includes polycyclic aromatic hydrocarbons, their nitrogen and sulfur
 heterocyclic analogues, and their oxidized derivatives.


      TOSCO II  retorted shale is very fine and contains 4-5% carbonaceous
 residue.   Fugitive emissions may occur  during disposal of such shale, and the
 small  sized suspended particles are  those most  likely to penetrate into and
 be retained by the lung.   TOSCO II preheat  system and elutriator system flue
 gases  may contain suspended  raw and  spent shale particles of very small size
 even after controls.   The  use of product oil to supply process heat may con-
 tribute to POM emissions.

     Union B spent shale is  chemically  similar  to TOSCO II spent shale, but
 may present less  of POM emissions potential during handling and disposal due
 to the much larger average particle size.

     GCR  retorting involves  the  combustion of residual  shale carbonaceous
 material  internally,  and little  organic matter or carbon remains with the
 retorted  shale(s).  Consequently, POM is found  in much lower amounts in GCR
 retorted  shale  than in TOSCO II  retorted shale  (16).  Further, GCR retorted
 shale  consists  of pebble sized solids, and is likely to present a low fugi-
 tive emissions  potential.

      Trace Elements:   Green  River oil shale contains trace amounts of many
 elements.  However, for elements other  than Si, Fe, Al, Ca, Mg, Na, and K,
 the concentrations in oil  shale are  less than or comparable to those found
 in common sedimentary and  igneous rocks (18). In contrast, petroleum and coal
 contain greater quantities of metals  and other  trace elements than common

     Temperatures  and  redox conditions during retorting are not severe enough
 to volatilize most metalic and heavy elements.  With notable exceptions such
 as arsenic (As) and possibly antimony (Sb), most trace elements (e.g., nickel
 (Ni),  vanadium (V), Molybdenum  (Mo)) remain with the spent sha'le, or are
 found  as  components of raw and spent shale solids entrained in retort gases
 and in raw shale  oil.  Arsenic in raw shale apparently forms a range of
 volatiles,  oil  soluble compounds (perhaps organic arsines) during retorting,
 and appears  in  raw shale oil and all  condensible oil fractions (19).  If not
 removed during  upgrading, arsenic will be present in shale oil combustion

     Actual emissions of non-volatile trace elements will  be in approximate
proportion to raw  and retorted shale particulate emissions for an oil  shale
extraction and retorting operation.   SucEL emissions may not be different in
nature or magnitude from those associated with the extraction and processing
of other fuel and  non-fuel  minerals (coal, limestone, phosphate rock,  etc.).
Further, the dolomitic and/or alkaline nature of shale immobilizes many ele-
ments as relatively inert oxide, carbonate, or silicate salts.  Trace element
mass emission rates give no simple indication of bioavailability, chemical  re-
activity, or physical  properties.

     Metals  and their  compounds  are used as catalysts (Ni, Co, Mo, Cr, Fe,
 Zn) for hydrotreating, dearsentating, sulfur recovery, and trace sulfur re-
 moval  (2,3,7,8).  Emissions of particulate matter containing catalyst metals
 can occur either  during on-site  regeneration or during handling and disposal.
 Catalyst  use is,  of course,  not  unique  to shale oil processing, and much


information and experience in preventing hazardous  emissions  can  be  borrowed
from the petroleum and related industries.

3.1.2  Process Emissions Inventories

     Quantitative and semi-quantitative emissions information is  available for
several oil shale technologies and developments.  Emissions from process sour-
ces are generally known with more certainty than emissions from mobile equipment.
use, blasting, and fugitive sources.  Process inventories for the Colony Develop-
ment operation and lease tracts C-a, C-b, and U-a/U-b are presented and dis-
cussed below.  Less complete estimates of emissions are presented for the
Union and Occidental processes.

     Colony Development Operation - TOSCO II:  The basic information about
TOSCO II emissions is contained in the Colony Development Operation EIA (1973)
(2) and more recently in the Department of Interior's EIS for Colony (1975)
(3).  Other versions of TOSCO  II emissions can be found in SRI (1974) (9) and
FEA (1975) (15), although these are based upon data in the Colony EIA.  More
recently, detailed development plans (DDP's) for federal lease tracts Ca and
Cb have presented TOSCO II emissions estimates  (7,8).  The DDP's have relied
heavily upon Colony data similar to that found  in the 1975 EIS (3).

     Table 3-3 presents four versions of an emissions inventory for TOSCO II
retorting and on site upgrading of shale oil.   The first three are based upon
Colony  EIA data.  Plant emissions result mainly from fuel combustion, with the
preheat system being  the largest single source.  Colony had assumed a plant
fuel mix consisting of about 50% fuel gas, 21%  butane fuel, and 29% fuel oil
(2).  S02 and NOX emissions  reflect the sulfur  and nitrogen content of fuels,
especially the fuel oil.  Particulate emissions arise in flue gases both from
combustion processes  and from  the entrainment of raw and spent shale dust.
Also, large quantities of particulates  are generated during ore preparation.

     Colony  has  revised  the  TOSCO  II  emissions  inventory  in  the  1975  EIS (the
fourth inventory in Table  3-3).  Total  S02 emissions  are  dramatically reduced,
reflecting greater sulfur removal  plans for  in-plant  fuels.   Some  modification
of the original  fuel  mix may also  be  involved,  but Colony has not  revealed
the assumed  fuel  schedule (or fuel  sulfur contents).   Total  NOX  emissions  are
also  lower in Colony's EIS emissions  inventory.  It is  not known whether
greater nitrogen removal  from fuels or greater  combustion control  is  respon-
sible  for the NOX reductions.   Total  process particulate  emissions are about
the same  in  the 1973  inventory.

      Colony  has indicated that Claus  sulfur  plant tail  gas is to be handled
by a  Wellman-Lord unit for S02 removal.  S02 emissions  from the  sulfur recov-
ery operation are larger in  the 1975  inventory  than in the EIA inventory,
mainly reflecting an  increased H?S load on the  Claus  plant from  more exten-
 sive  sulfur  removal from shale oil  products.

      Colony  has estimated emissions resulting from mobile equipment use in
 underground mining, and dust generated during blasting operations.  Total
 carbon monoxide emissions from the mine are  much larger than from in-plant


operations.  NOv and particulate emissions from the mine constitute around
10* of the total for their respective inventories.

     Tract C-b Inventory (8):  The developers of tract C-b (Shell  and Ashland)
are partners in the Colony group, and propose to use TOSCO II  technology at
the tract.  The emissions inventory reported in the recent DDP for tract Cb
is essentially identical to that presented in the Colony 1975  EIS and shown
in Table 3-3.

     Tract C-a Inventory (7):  The leasees of tract C-a intend to use TOSCO II
retorting for 2/3 of the mined shale and GCR '(Paraho) retorting for the other
1/3 during Phase II operations.  Table 3-4 presents the emissions inventory
for C-a  phase II operation (8900 M3/day, 56,000 BBLS/day) as described in the
recent detailed development plan.  The emissions directly associated with
GCR retorting are those from the shale preheating furnace and  from spent
shale moisturizing.

     The integrated TOSCO/GCR retorting system for Tract C-a differs in
several ways from the Colony (TOSCO) system:

         GCR product gas is used to preheat shale for the TOSCO II
          retort - the  integrated system uses entirely gaseous fuels.

         Hydrogen for  upgrading is produced by partial oxidation of
          the 480C+ (900F+) shale oil distillate bottoms rather
          than by the reforming Light hydrocarbons.  Process energy
          (and associated emissions) for this operation is supplied
          by auxiliary  boilers.

         A  lower average grade of shale (.095 M3/tonne or 23 gal/ton)
          is extracted  and processed.  Total shale preparation emis-
          sions for the 8900 M3/day operation are therefore higher
          than for the  Colony operation (using  .146 M3/tonne or 35
          gal/ton shale).

     The overall shale  preparation and processing emissions associated with
the  tract  C-a  operation are comparable to Colony EIS emissions for S02.
Total NOX and particulate emissions are lower,  reflecting use of low nitrogen
plant fuels, better combustion control, and  more efficient particulate  col-
lection systems.

     Tracts  U-a/U-b (23):  The  White  River oil  shale project plans  to  develop
 tracts  U-a/U-b probably using  primarily Paraho type technology. Fines are to be
 handled using  TOSCO  II  technology in later phases of tract development.
 Table  3-5 presents an emissions  inventory for Phase III operations (8000 m3/
 day  or 50,000  bbls/day).  Total  NO  emissions are comparable  to  those for
 similar sized  operations at C-a  ana  C-b.   Total particulate,  SOg,  THC,  and
 CO emissions differ  somewhat  from those associated with other developments
 for  several  reasons  including:   (1)  the inclusion of mining,  mobile equipment,
 and  fugitive dust  emissions  in the U-a/U-b inventory, (2) a combination of

            Table  3-3.   Comparison/of TOSCO II Emissions Inventories (8000 m3/day) (50,000 bbls/day)
'' ' I'C >' I't (I)
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WOICUHHJ lOJlUO) l|qf||f 1M3.
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08'0 5S> 1 ^Z'O '8
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N90'0 5'*
oo'o 600-0 - tiro two '*
8IO'0 eiO'O - SIB'O I6>'0 t'S
HO'O 819-J - SZ'l Z'0 ' '
Mfo eofi cl
(IUO|fl|M >UMd|Kb*
 lltou) A X>tM
[fioi 4*14 jo
6uo>s JO w|j
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Table 3-4.   Lease Tract C-a  Phase  II Emissions  Inventory   (56,000  bbls/day)
Coker Heater
Gas Oil Heater
Gas Oil Furnace
Naphtha Heater
\\2 Production
Aux Boilers
Sulfur Plant
Glycol Reboller
(Hi-Gas Plant)
H-Plant CO?
GCR* Preheat
GCR Moisture
Process Total
Ore Prep

Y S0?

. 0.209

  Max 15 mln/day

      Ref.  7 at end of Chapter 3.
Primary Crush 0.130
Secondary Stock- 0.218
Primary Ore 0.142
Secondary Crush 0.647
Fine Ore Storage 0.125
Total 1.255

^Based on 2/3 TOSCO .
1 1/3 GCR
I 109,090 tonnes/day ]
Gas Oil
Raw Shale 011
Raw Napfcha
Raw Gas 011
Sponge Oil
H-plant Feed
Coker Tank
Tank .001
                                                                                          Assumes evaporative
                                                                                          component at all stored
                                                                                          products to have a
                                                                                          specific gravity of
                                                                                          0.84 (60/60F) or 7 IDS/

Table 3-5.  Lease Tracts U-a/U-b Emissions Inventory (50,000 bbls/day) (23)
Heat Input
Source 108KCAL/Day
Piriho Tjfjje Retorts
 Raw Shale Feed
e Retorted Shale
 Gas Heaters 12
TOSCO II Type Retorts
e Raw Shale Feed 0
e Preheat 22.8
e ElutHator 3.9
e Shale Moisturizer 0

Hydrogen Plant 44.1

Crude Shale Oil
Hydrotreater 11.9
Naphtha Hydrotreater 1.7
Utility Boilers
 Low BTU Gas 76.7
 Fuel Oil 45.3
Sulfur Plant
Process Total 21B

























Mining Operations
 Nine Fugitive Cost
 Mobile Equipment
Mine Total

e Coarse Ore Crusher
 Ore Transfer
e Storage
 Secondary Crusher
Ore Prep Total

Tank Storage

Processed Shale Disposal
e Transfer
 Traffic Dust
 Mind Erosion
Disposal Total

Heat Input














4 93


1 71

Direct and  Indirect Mode Paraho retorting, and TOSCO II retorting, (3) hydro-
treating of crude shale oil, and (4) the use of fuel oil in utility boilers.
A detailed  comparison of emission source contributions to the total inventor-
ies for U-a/U-b, C-a, and C-b has not been undertaken for the preparation of
this report.

     Union  B Process (20):  A complete emissions inventory for the Union B
process is  not available at present.  However, company personnel  indicate that
three major emissions sources will be present in the first generation Union B
plant at the Parachute Creek site:  (1) flue gas from the recycle gas heater,
(2) sulfur  plant tail gas, and (3) flue gas from the arsenic removal  preheater.
A normalized emissions inventory for a Union B plant cannot be directly com-
pared to an inventory from Colony or C-a, since Union does not envision on-site
upgrading during initial operation.

     Net product gas from the Union retort is expected to be similar in com-
position and heat value to TOSCO II retort gas.  After sulfur removal, Union
reports the following emissions from combustion of this gas:

            Table 3-6.  Union B Fuel Gas Combustion Emissions (20)
Plant Size
M3 oil /day
1260 (7920)
8000 (50,000)
Gas Firing Rate
1.9x105 (67x1 05)
12.2x105 (430x105)
S02 Emissions
0.33 (0.36)
2.08 (2.29)
NOX Emissions
1.0 (1.1)
6.2 (6.8)
     A Stretford unit will be used to remove HS from Union retort gases.
Off gas from the Stretford Unit will contain small amounts of sulfur com-
pounds (C$2, COS, HoS).  Union has not disclosed its estimate of such emis-
sions, but the quantity is likely to be small relative to fuel gas combus-
tion emissions.

     A small quantity of fuel gas is to be used in a heater in Union's
arsenic removal process.  The amount of fuel used (and emissions) is con-
sidered a proprietary part of the process.

     The Union B process features spent shale moisturizing and discharge
from the retort via a water seal.  Particulates associated with shale
moisturizing are collected in this process with the condensed steam.

     The Union B retort accepts a somewhat smaller sized raw shale as feed
than a GCR retort.  The quantity of uncontrolled particulate emissions from
shale preparation might be expected to be somewhere between that from a
comparably sized GCR and a TOSCO II operation.

     Superior Process:  The Superior process combines certain features of gas
combustion retorting (Paraho Direct Mode) and inert gas retorting (Paraho

Indirect Mode).  On-site use of low and high Btu gas for process and upgrad-
ing purposes will result in emission control requirements similar to those
for Paraho retorts.  Superior has not developed its process to the point of
being able to define such emissions to date.

     Occidental  (In-situ):  A modified in-situ operation and associated sur-
face plant would be expected to product uncontrolled emissions similar to
above ground retorting processes.  Mining is required and the associated
mobile equipment emissions and dust emissions would be similar to those
associated with  the mining for above ground retorting (on a unit mined
shale basis).

     Since the in-situ retort is operated in a gas combustion mode, large
quantities of low Btu gas (700 Kcal/M3 or  80 Btu/SCF) are commonly produced
during in-situ retorting (22). Occidental reports that such gas contains
around 0.6% total sulfur and some ammonia (21). The economic practicability
of removing hydrogen sulfide from the retort off-gas prior to combustion,
especially if electric power generation with the low-Btu gas proves to be
feasible, remains to be ascertained.  In a previous study for the Federal
Energy Administration conducted by TRW (15), the Quantity of vent gas released
to the atmosphere was estimated to be 625 M3/Sec (1,400,000 ft3/min) for a
5860 M3/day (36,800 BBLS/day) in-situ operation retorting .08 M3/tonne (18 gal/
ton) shale.  This is equivalent to a stack gas emission rate of 839 M3/sec
(1,777,000 actual ft3/min) at 95QC (2000F), and comparable in magnitude and
composition with the stack gas emitted from a 500 MW oil-fired electric power

     In-situ produced wastewaters will likely contain NH3 and H2S, which
could be released to the atmosphere if such waters were to be disposed of
by evaporation (i.e., in surface ponds).

     If product upgrading is performed on site, emissions will be associated
with such processing.  However, Occidental does not envision upgrading at
present.  A quantitative estimate of emissions associated with the Occidental
process will have to await the design of surface plant for handling product
oil, gas, and wastewaters.  Occidental has filed certain emissions data with
the State of Colorado, but this data is not currently public information.

     Summary of Air Pollution Control Technology:  Table 3-7 presents the
major sources of $03, particulate, NOX, hydrocarbons, and carbon monoxide
from the preparation and processing of oil shale to upgraded shale oil pro-
ducts.  The major proposed air pollution control equipment and/or techniques
to reduce these emissions are listed in the table, along with some comments
about the emissions inventories which have been presented and discussed above.

3.1.3  Fugitive Emissions Inventories

     Table 3-8 presents one estimate of fugitive emissions associated with
oil shale operations.  Uncontrolled fugitive particulates could constitute
a large fraction of a total  parttculate inventory at a development site.
Shale preparation and process partfculate emissions for a 8000 MJ (50,000 bbls)
per day) plant are about 5 to 10 tonnes/day (Tables 3-3 and 3-4), while


Table  3-7.    Summary of  Air  Pollution  Control  Technology  for Oil  Shale
                  Preparation and Retorting, and Shale Oil  Upgrading
                                                               Comnents About Emissions Inventories
 SO,  (and total sulfur)

Fuel Desulfurlzatlon

  An1ne/amon1a/H20 scrubbing

  Stretford sulfur removal/recovery

 fClaus sulfur removal/recovery

  Sulfur plant tall gas cleanup -
     Wei loan Lord

   Hydrotreatlng followed by off-gas
   HS and annonla removal
           Differences In S02 Inventories reflect:

              Fuel mix
           t   Degree of hydrotreatlng

              Efficiency of S removal from fuel  gas

              Sulfur plant tall  gas cleanup

           Recent Colony and CB  Inventories assume cleaner
           fuels than earlier Colony and SRI Inventories.
           Ca  and Union Inventories based on entirely gaseous
           plant fuels.

    Retort Feed

 ,  Shale Moisturizing
  Covered conveyors

  Water spray  at transfer points and
   at storage.

  Baghouses with Induced draft fans.

  Dry cyclones

  Venturl wet scrubbers

  Clean Fuels

  Venturl wet scrubber

  Hater seal (Union)
           Early Colony efficiency lower than SRI  assump-
           tions.  Recent Colony. Ca, Cb Inventories  1n
           approximate agreement (unit shale basis).
           Early Colony efficiency assumptions differ frar
           SRI.  Recent Colony Cb, Ca estimates are comparable
           on a unit shale basis.

           Fuel mix accounts for major Inventory differences.

           SRI assumes greater efficiency than Colony, Ca, Cb.
           TOSCO II generates more participates during mois-
                                        turizing than does
                                        claims no emissions
                            .% soufo
                                                                                                 water seat ,
  Gas Fuels

  Liquid Fuels
    Armenia  removal
  t  Hydrotreatlng/amnonla

     off gases
ival from
Early Colony EIS assumed high nitrogen shale oil
used as  plant fuel.  Recent Colony and Cb Inven-
tories assume low N fuels.  Ca and Union
Inventory based upon entirely gaseous fuels.
HC's and CO
                            Incineration of trace hydrocarbons
                            1n TOSCO  II preheat system
                                         All Inventories comparable for HC's.  Diesel
                                         equipment/mine vent rather than process sources
                                         contribute most CO.

                  Table 3-8.  Potential  Fugitive Dust Emissions3
Type of Mining Operation
Surface Mine (8000 M3 oil/dav)
Mine development
Overburden Disposal
Temporary Storage
Permanent Disposal Processed Shale
Surface Facilities (8 Kilometers of
unpaved road, VMT 80 Kilometers)
Haulage from Mine (3 Kilometers)

Underground Mine (8000 M3 oil /day)
Mine development
Permanent Disposal of processed shale
Surface Facilities (8 Kilometers of
unpaved roads; VMT 80 Kilometers)
True In-SituProcess1ngd(8000 M3 oil/day)
Surface Facilities (8 Kilometers
unpaved road; VMT 80 Kilometers)
Land Required



Emissions (Tonnes/Day)
Uncontrolled Controlled



 Amick, Robert, S., et al., Fugitive Dust Emission Inventory Techniques, paper
 number 74-58 presented at the Air Pollution Control Assoc. meeting in Denver,
 Colorado, June 1974.

 Emissions from overburden disposal will likely be much less for the oil shale
 industry.  Revegetation is planned for the disposal area.  This will minimize
 fugitive losses from this source.

Assuming an average of 80% control by applying various air pollution strategies
 to minimize particulate emissions.

dWithout mining to create void volume.  Emissions associated with a 8000
 M3/day modified in-situ operation would amount to about .06 - 0.1 tonnes/
 day (uncontrolled), depending on the extent of mining.

uncontrolled fugitive emissions could amount to 4 tonnes/day for a surface min-
ing operation.  As would be expected, underground mining presents less of a
fugitive dust problem than deep surface mining.  Estimated fugitive emissions
after control are comparable in magnitude to controlled participate emissions
from shale preparation 1n a TOSCO II operation.

      The emissions inventory for Phase III operations at tracts U-a/U-b in-
clude estimates of fugitive emissions from several sources.   Approximately 5
tonnes/day of dust are to be attributed to such sources for the 8000 m3 (50,000
bbls) per day operation (Table 3-5).


      Water is a necessary  resource for  the development of an oil  shale in-
 dustry.  Water is required for dust control  during  mining and  crushing, for
 gas cleaning and air pollution control, for cooling purposes,  and for mois-
 turizing of retorted shale.  Upgrading of crude shale oil,  on  site power
 generation, and revegetation of disturbed land and  retorted shale disposal
 areas will also consume large quantities of raw water.   The total  quantity
 of water necessary for each of these uses is dependent on the  development
 options chosen and on the ultimate  size of the oil  shale development.

      In recent years, increasingly  stringent wastewater discharge regulations
 have been promulgated by both the federal and state agencies.   Because of
 these regulations, the quality and  quantity of wastewater effluents and the
 frequency of waste disposal  may be  limited.   Most of the oil shale developers
 however, plan no direct discharges  to receiving streams.

      The following is a discussion  of water requirement estimates,  sources
 and nature of wastewaters, specific process wastewaters, and wastewater
 treatment options for the oil shale industry.

 3.2.1   Water Requirement Estimates  for Oil  Shale Development

      The water requirements per unit of net product will  necessarily depend
 on the type of mining,  retorting, and upgrading processes utilized.   In gen-
 eral ,  the in-situ methods are expected to require less water than convention-
 al mining and retorting.   Estimated water requirements for  an  integrated oil
 shale industry which have been prepared for various oil shale  developments
 are summarized 1n Table 3-9.

Table 3-9.
Estimates of Process Water Requirements for Full  Scale Oil
Production (m? of water needed per m3 of oil  produced) (3,
             Oil  Shale Development
         Tract C-a - Phase II
         Tract C-b - Phase III
         Tract U-a/U-b - Phase IV
         Colony Development Operation
         Union Oil Development Operation
                               Quantity Required
                               (m3 water/m3 oil
      Estimates have been made to categorize water consumption by unit  pro-
 cesses and operations within a shale oil  recovery operation.   Table 3-10is
 one such estimate of the water requirements by unit processes (4).

 Table 3-10. Water Consumption Requirements for Unit Processes Associated
             with Oil  Shale Processing


Mining and Crushing
Shale Oil Upgrading
Processed Shale Moisturizing
Power Generation
Sanitary Use
Associated Urban Development
Domestic Use
Domestic Power
Water Requirements
m3 water/m^ oil production

0.16 - 0.22
0.25 - 0.31
0.62 - 0.93
1.23 - 1.87
0.31 - 0.43
0 - 0.30
0.01 - 0.02
2.57 - 4.07
0.29 - 0.39
0.03 - 0.04
0.32 - 0.43
2.89 - 4.5
      More than 80% of the estimated water demand is attributable to the pro-
 cessing facilities.  Of the total process water, approximately 45-50% is con-
 sumed in moisturizing processed shale.  Shale oil upgrading accounts for
 about 25% of the total process water demand.  Power generation and retorting
 each consumes 10-15% of the water requirement for processing oil shale and
 shale oil.

3.2.2  Sources and Nature of Wastewater (1,3.7,8,9,12,14,22)

     Aqueous wastes from oil shale processing can be broadly categorized as
originating from direct or indirect sources.  Direct sources are wastewaters
generated from unit operations and/or processes, including (1)  wastewater
from retorting operations, (2) wastewater from upgrading operations, (3)
water from air emission control and gas cleaning systems, (4) cooling water
and boiler water blowdowns, (5) water treatment systems, (6) mine dewatering
wastewaters and (7) sanitary wastewaters.  Indirect sources include: (1)
leachate from retorted shale disposal areas, (2) runoff and erosion result-
ing from construction and site use activities, and (3) runoff from mining
and transport activities.  The following is a discussion of the characteris-
tics of the wastewaters from each of these sources.

     Wastewater from Retorting Operations:  Water is a direct product of oil
shale retorting, resulting from the pyrolysis of kerogen, the release of free
and inorganically bound water from raw shale, and the combustion of organic
material in shale.  From 4 to 30 liters of water (1-8 gallons)  are commonly
produced per ton of input shale feed to a surface retort, depending on the
retorting process and the composition of the shale processed (1,3,14).  In-
situ process demonstrations have reportedly produced even greater amounts of
water (22). Some water condenses with crude shale oil during separation of the
oil from retort gases.  This water can partially separate from crude shale
oil during storage, or can appear in aqueous waste streams of shale oil up-
grading operations.  Water remaining in retort gases after oil  separation
can be condensed during cooling or gas cleaning operations, or can appear in
the flue gas stream from retort gas combustion.  Water separated from crude
shale oil contains  mainly ammonia, carbonate and bicarbonate, sodium, sul-
fate, chloride, and dissolved or suspended organic compounds (phenolics,
amines, organic acids, hydrocarbons, mercaptans).  Smaller quantities of
calcium, magnesium, sulfides, and trace elements may also be present, along
with suspended shale fines.  Water condensed from retort gases contains
primarily ammonia and carbonates, with traces of organic substances and sul-
fur containing compounds.

     Process Water from Upgrading Operations;  The quality of the wastewaters
from an upgrading operation varies with the level of on-site upgrading or
refining utilized.  In general, a full scale refining operation may include
any of the following wastewater streams:  oily cooling water, process water,
and wash water.

     Oily cooling water includes all wastewater resulting from quenching,
vessel  cleanout, spills, coker blowdown and process steam condensation.
Process wastewater includes condensed steam from stripping operations, wash
water from process drum cleaning operations, wastewaters produced during
chemical reactions, and other in-process sources.  Spent caustic streams can
result from extraction of acidic contaminants.  Wastewaters from sources
such as ion exchange regeneration, in-plant storm water, hydraulic decoking
and once-through cooling are mostly oil free.

        The blending of wastewaters  from  a  full scale refining operation may
 produce a wastewater high in ammonia,  bicarbonates, sulfides, phenols, total
 dissolved solids, oil  and grease.   Such  waters may be characterized by high
 levels of Biochemical  Oxygen Demand (BOD)  and Chemical Oxygen Demand (COD).

     Water from Air Emission Control and  Gas Cleaning  Systems:   Included  in
this category is wastewater collected during retort gas cleaning,  tailgas
cleanup, and foul water stripping.  Major constituents in such waters are
shale dust particulates,  hydrocarbons, H2S, NH3, phenols, organic acids and
amines.  Other constituents  such as thiosulfate and thiocyanate may also
be present.

     Cooling Water and Boiler Water Slowdowns:   Cooling water is used in  re-
torting and oil upgrading to absorb heat  which  cannot  be  economically recov-
ered for use in the complex or absorbed by air  fan coolers.   Cooling water  is
generally circulated through a wet cooling tower system to  release this heat
to the atmosphere.  Because of evaporative losses, there  is  a constant build-
up of dissolved solids which requires a portion of this recirculated water
to be discharged as blowdown from the cooling water system.   Similarly a
fraction of the.boiler water must be discharged as blowdown  to minimize scal-
ing of boilers.  Both the cooling water and the boiler blowdown waters con-
tain a high concentration of dissolved solids,  and substances such as hexa-
valent chromium used for corrosion control.

     Raw  Water Treatment  System Wastewater:  Good quality water is needed to
supply  processing,  cooling  tower, steam  generation and other miscellaneous
process uses.  Wastes  from  water treatment  systems generally consist of
chemical  sludges, backwash  water from  filtration system and blowdown from
zeolite softening systems.   The largest  quantity  of waste is  lime  sludge
which  is  characterized  by high hardness  and dissolved salts content.

     Mine  Dewatering Wastewater:  Waters found in aquifers encountered dur-
ing mining must be  removed  by a dewatering  system.  Mine dewatering could
produce large  quantities  of low quality  water unless groundwater is prevented
from entering  the mine.   The quality and quantity of this water will vary
with location  and processing technique.  During a full scale operation, most
of this water  willbe  used  in wetting  and compacting retorted shale.  Major
constituents of mine water  are sodium, carbonate, bicarbonate, chlorides,
fluorides  and  boron.   Reinjection of this water into the aquifer may cause
increased  ground water  salinity.

     Sanitary  Wastewater:   Included in this category are wastewaters from
domestic  sewage,  kitchen, bathroom, laundry and toilet uses.  In addition
to the mineral and  organic  matter already present in the water  supply system,
human excrement,  paper, soap, dirt, food wastes and other substances are
added  to wastewater.   Because of the unstable organic matter and the enteric
microorganisms present, disposal of this wastewater without pretreatment is
objectionable  both  from the health, environmental, and esthetic point of
     Leachate  from  Retorted  Shale;  As discussed in the water requirement
section, approximately 45-50% of the water required for an oil shale plant


 is used  for moisturizing of retorted shale.  Much of this water requirement
 will be  supplied by mine water and process wastewaters.  Because of the large
 quantities of water utilized and the exposure of retorted shale to rain and
 snowfall, a source of indirect water pollution may occur via leaching or run
 off from retorted shale piles.  However, the bulk of the water applied to re-
 torted shale is expected to be held in capillarity or to be bound as simple
 hydrates.   The suspended and dissolved constituents of wastewaters applied
 to retorted shale are expected to be partially immobilized by physical adsorb-
 tion and/or chemical reaction with retorted shale.  Leaching experiments in
 the laboratory and with small plots indicate that inorganic salts - Na, Mg,
 S04, Cl~ may be leached from retorted shales.  Small quantities of organic
 substances and trace elements are also water soluble.  Leachates are further
 discussed in Section 3.3.

     Runoff and Erosion from Construction, Mining, Transport, and Site Use
Activities:  Construction, mining and site use activities may potentially
 result in increased sediment and dissolved solids loading in surface runoff
and receiving streams.   This indirect source of potential water pollution
 is not unique to oil shale extraction and processing, but may require care-
 ful control due to the magnitude of site activities.  Collection and impound-
ment of  runoff will  likely be necessary.

 3.2.3  Specific Process Wastewaters

     The following is a summary of the available process wastewater informa-
 tion.  Waste stream information for some processes are not yet available or
 are considered to be proprietary.

     TOSCO II Wastewater  (3,8):   Direct wastewater discharge from a TOSCO
 II retorting and upgrading operation is not anticipated.  All wastewater 1s to
be reused for in-plant processing and ultimately consumed in moisturizing
 retorted shale.  Plant process wastewaters will be collected, processed to
 reclaim  useful components, and combined for in-plant treatment before reuse.
The major process units that generate wastewater are:  (1) pyrolysis and oil
 recovery units - blowdown wastewater is produced from high energy venturi
wet scrubbers used to remove shale dust from the flue gas; (2) gas oil and
 naphtha hydrogenation units - sour water is produced by the washing opera-
 tion; (3) ammonia separation and sulfur recovery units - ammonia stripped
water and an acidic wastewater are generated; (4) delayed coking process
units - foul water is produced; (5) utility boilers - blowdown wastewater
is produced; and (6) Wellman-Lord unit - blowdown consisting of alkaline
sulfate/sulfi te wastewaters.

     Detailed quantitative characterization of the individual waste streams
has not been performed to date because these streams are combined, treated
in-plant and subsequently reused to exhaustion.  However, the combined pro-
cess waste stream has been approximately quantified by Colony and is repro-
duced in Table 3-11.  The major constituents present in the combined process
water are organic acids, neutral oils, amines and phenols, and mineral salts
such as sodium, calcium, and magnesium sulfates, chlorides and carbonates.
Data on the exact chemical composition of the organic acid, amine, and

Table 3-11.  Approximate Composition of TOSCO II  Combined  Process  Wastewater
             (8000 mJ/day upgraded shale oil  production) (3)

Organic Acids
Neutral Oils
TOTALS (Rounded)
Concentration in Water (mg/1)
Added to Spent Shale
.015 - 0.3
.0045 - .09
        In  addition  to  above, elements present in trace quantities  (less
        than  1 mg/1  are Pb, Ce, Ag, Mo, Zr, Sr, Rb, Br, Se, Cu, Ni, Co,
        Fe, Mn,  V, Ti,  K,  P, Al,  F. B, Li.

 neutral  oil  fractions  are not available.  High molecular weight organics be-
 longing  to the polycyclfc organic  materfal  (POM) class may also be present.
 Twenty-two trace elements have also  been  identified as constituents of com-*
 bined wastewater; none of these, however,  is present in quantities greater
 than 1 mg/1.

      GCR (Paraho Direct Mode) Wastewater:   Available information from the
 Paraho Demonstration Project indicates  that the major constituents present in
 process  water (condensed or separated from crude shale oil or retort gases)
 are ammonia,  carbonates  and bicarbonates,  organic acids,  and amines
 (1,5,6).  Table 3-12 is a summary  of the  major constituents present in the
 Paraho retort wastewater stream and  does  not reflect any downstream processing
 operations.   Because of the significant amounts of organic material present,
 the biochemical  oxygen demand (BOD)  and chemical oxygen demand (COD) are
 very high.

           Table 3-12.   Paraho (GCR)  Process Wastewater Analysis (1,5,6)
Ammonia nitrogen
Organic carbon
Organic nitrogen
Concentration Range (mg/1)

     Levels of approximately twenty metals have also been determined in
Paraho process waters (6),  Their concentrations are all  less  than 1  mg/1.
Upgrading of shale oil is not currently practiced at Anvil  Points, and little
is known about wastewaters which may be associated with  such  practices.

     Union Oil Retort B Process  (20):   The major wastewater  streams from
Union Oil's retorting process are:  (1)  water from make gas compression and
cooling, (2) water from ammonia absorption, (3) water from oil-water
separation, (4) water from first stage solids removal, and (5) water from
oil stripping.  According .to Union, these wastewater streams will be com-
bined, stored and reused for retorted shale cooling in the water seal after
oil water separation and some water stripping.  The total quantity of waste-
water generated for a 9000 tonnes/day (10,000 TPD) oil shale  plant is esti-
mated at 1.32 m3/min (350 gpm).  Because of the proprietary nature of the
Union process, quantitative  Information on waste  stream  composition  has
not been made available.  Limited information released by Union  personnel
indicates that the predominant Inorganic constituents present In their com-
bined process wastewater are sodium, calcium, and sulfate.  Some magnesium,
potassium,  and bicarbonate are also  present,  and  the total dissolved sol Ids
is estimated  at  10,000  ppm.  No  information  Is  available regarding  organic
constituents  or  trace elements.

     Lease Tracts:  The characteristics of process wastewater streams have
not been reported for Tracts C-a or C-b.  Because of the similarity in re-
torting operations between C-b and Colony (3,8), it is expected that C-b's
process wastewater will be comparable to that reported for Colony.   Tract
C-a will utilize 35% Paraho (GCR) retort process and 65% TOSCO II process
in its Phase II development.  Consequently process wastewater generated at
C-a will have a composition reflecting both TOSCO II and Paraho retorting.

     Developers of Tracts U-a and U-b in Utah plan to process oil  shale using
primarily Paraho retorts during Phase III.  Some of the reported characteris-
tics of process wastewaters associated with Phase III operations at U-a/U-b are
shown in Table 3-13 (23).

3.2.4  Process Wastewater Treatment

     Under current planning, most of the oil shale developers envision zero
discharge of their wastewaters.  Reasons for this commitment may be (1) the
relative scarcity of water in the western oil shale regions, which may en-
courage minimum intake and discharge of waters, (2) future pollution control
regulations for wastewater discharge which may be so stringent that cost for
discharge compliance may well exceed the cost of simple in-plant treatment and
subsequent reuse, and  (3) control technologies for in-plant treatment which
have been well developed by the oil refining industries can be applied to oil
shale processing without resorting to high cost research.  Consequently, it is
anticipated that most of the developments will employ treatment techniques
similar to those developed by the oil refining industries.  The final disposi-
tion of wastewater will be evaporation or incorporation Into retorted  shale.

      The  degree of treatment utilized will  necessarily depend  on the intended
 reuse of  the wastewater.   For the purpose of this discussion,  the  treatment
 techniques will  include both the in-plant and end-of-pipe treatment options.
 In-plant  controls  are designed primarily to reduce the volume  and  quantities
 of contaminants discharged in process wastewaters.   End-of-pipe controls,  on
 the other hand, are designed to treat the wastewaters after they have been

      In-plant treatment includes:  (1)  collection of all  process wastewaters
 and waters from leaks, drain outs, flushes, washdowns, and runoffs; (2)  pre-
 processing of certain waste streams to reclaim valuable constituents;  and  (3)
 combining of the various waste streams for solids settling and oil-water
 separation.   A typical  in-plant treatment system will  consist  of individual
 waste collection lines, ammonia stripping,  a sulfur recovery system for
 specific  process streams,  a combined waste holding pond,  a gravity API sep-
 arator,*a chemical  dosage  tank, a dissolved air flotation unit (DAF) and a
 final  holding pond for the treated wastewater.

      Wastewater from the foul  water system will  be stripped with steam to re-
 move dissolved hydrogen sulfide and ammonia.  Gases from the stripped overhead
 will be sent to the sulfur recovery plant and to the ammonia recovery system
 while the stripped water will  be pumped directly to a holding  tank or pond for
 later use in moisturizing  spent shale.
 *American Petroleum Institute  (recommended design)


Table 3
-13.  Approximate Composition and  Flow Rates  for Selected  Wastewater Streams  -  Lease Tracts'-
      U-a/U-b (Phase III,  8000 m3  Upgraded Shale Oil/Day)  (23)
Component or
Total Dissolved Solids
Suspended Solids
Chemical Oxygen Demand
Biochemical Oxygen Demand
Oil and Grease
Flow Rate
mg/1 as N
Waste Stream
Sour. Water
Stripper Oily
Bottoms Wastewater'
500-1500 100-2000
50-100 50-1000
80-1 50
17.7 4.1
Low- TDS

High TDS


     All oily wastewaters from processing, including gas condensates, oily
water wash-down from process pads, and process leaks will be collected in a
common sump.  Overflow from the sump will be conveyed to an API separator
system, consisting of a surge pond, an API separator, a chemical  dosage tank
and a DAF unit.  Separated oil will be returned to the raw oil  recovery plant
and any sludge collected will be removed periodically and returned to a re-
tort or burned in the thermal oxidizer.  Effluent from the API  separator will
flow to the chemical tank where it will be saturated with air by pressurizing
the tanks to 40 to 60 psig.  After about 1 minute retention, the wastewater
will be discharged through a flotation chamber where air will come out of
solution in minute bubbles.  The residual oil and particulates will be
carried to the surface by the bouyant force and will be skimmed and returned
to the raw oil recovery plant.  Processed effluent will then be sent to a
holding pond from which the wastewater will be used for moisturizing and
compacting spent shale.

     Sanitary wastewaters will be  collected and treated  in packaged treat-
ment units.  Effluent from the treatment  unit will be chlorinated and reused
as make-up water for certain processes.

     Mine dewatenng wastewater, runoffs,  and blowdowns  from cooling tower and
boilers will not be treated  in the conventional sense.   These wastewaters
will be centrally collected  for use  in dust suppression  and/or conveyed to
the holding tank or pond for wetting of  retorted  shale.

      End-of-pipe treatment includes: (1) additional  treatment  of the process
wastewater after in-plant treatment, (2) treatment of sanitary wastewater,
 (3)  demineralization  of mine dewatering  wastewater and boiler  and cooling
water  blowdown.  Process  units  utilizing end-of-pipe treatment may include  any
one or more of the  following:   biological  treatment units such as activated
sludge system,  biofiltration, or  aerated lagoons, demineralization units  such
as ion exchange  columns,  reverse  osmosis or distillation, and  soluble organics
removal  units  containing  activated carbon filtration.


      The  solid wastes  resulting  from oil shale processing present one of the
 major environmental  problems  associated with commercial development.  Shale
 derived solid wastes include  fines from crushing and conveying of the raw
 shale and the processed  (or retorted) shale remaining after retorting.  To-
 gether these constitute  most  of  the process solids requiring disposal.
 Other solids to  be discarded  depend primarily upon the extent of upgrading
 of the crude shale oil which  is  carried out in conjunction with the retort-
 ing operations,  and may  include  shale oil coke if experience shows that such
 material  is not  usable or marketable.  Certain non-shale wastes such as
 spent catalysts  may also be generated during the processing of shale oil.
 This  chapter deals with  the nature and sources of solid wastes from oil
 shale processing and presents data on the quantities of solid wastes ex-
 pected from the  various  oil shale processing operations.

 3.3.1  Raw Shale Fines

      The  primary sources of raw  shale fines are the crushing operations con-
 ducted on the as-mined shale, and dust from raw shale transport within the
 mine-plant complex.  The composition of the fines, of course, is essentially
 that  of the mined, raw shale and its contained organic matter.  A typical
 chemical  analysis of the organic matter would include the following (1):

                     wt %                     wt %

          Carbon     80.5           Sulfur      1.0
          Hydrogen    10.3           Oxygen      5.8

     The associated mineral  matter in the raw shale has the following typical

                      wt %                      wt %
          Dolomite     32            Albite      10
          Calcite      16            Microcline   6
          Quartz       15            Pyrite       1
          Illite       19            Analcite     1

Oil shale is a highly consolidated organic-inorganic rock system, with no
significant micropore structure, pore volume, or internal surface.  Over 99%
of the inorganic particles have equivalent spherical diameters of less than
44 microns, 75% are 2-20 microns, and 15% are less than 2 microns.

     The size distribution of the raw shale fines or rejects from crushing
depends upon the feed size requirements of the retort.  For the Union retort
B.the feed is 3 mm to 5 cm (1/8 to 2 in.), and the fines are therefore minus
3mm (1/8") (20).  Paraho fines are typically minus 6 mm, as are also the fines
from the Superior process (5).  There are no unusable fines from the TOSCO II
process (3). The size range of the dust collected from the various processes

has not been reported, but can be expected to be less  than  the average size
of the fines from crushing.  Dust will  probably normally  be disposed of as a
slurry or sludge.

 3.3.2  Retorted Shales

     Pyrolysis  of oil shale  results in the conversion of most of the original
 organic material  in  raw  shale  to  gaseous  and  liquid hydrocarbons (and sulfur,
 nitrogen,  and oxygen containing organics).   Retorted shales containing solid
 organic residues can  be disposed of directly  as  a solid waste, or can be
 further processed for recovery of heat value  of the residue.

     Burned Shale (e.g. Paraho  Direct Mode (GCR)): After retorting at approxi-
 mately 900F, the remaining  processed shale  is  soft and friable.  It usually
 has an organic  "carbon"  content of 2 to 3%,  depending upon  the retorting pro-
 cess.  Direct Mode Paraho  retorting produces  a  retorted shale which has been
 partially  "burned" after pyrolysis of oil shale kerogen.  Residual organic
 carbon amounts  to about  2% by  weight, and typically 30% of  the contained
 carbonate  minerals have  been calcined (24).  Particle size is greater than
 1.2 cm (0.5 inch).   It is  possible, in principle, to oxidize this carbonace-
 ous material, as  a source  of process energy,  and to discard a completely
 carbon-free shale residue, or  ash.  A typical composition- of such ash is
 shown in Table  3-14  for  several retorted  shale  residues.

     Typical shale ash has a composition  similar to Portland cement and has
 certain cement-like  physical properties.  The cement forming tendency of burn-
 ed shale can be used to  advantage to help create a physically and chemically
 stable disposal pile (26).  Before setting,  burned (and moistened) shale ash
 behaves like a  sandy silt.  After setting, it develops sufficient cohesion so
 that deep, well-stabilized piles  with high slope angles may be constructed.
 The strength of burned shale disposal pile depends upon the amount of moisture
 added (10% is optimum) and the amount of  cohesive hydrates  produced.  Approxi-
 mately 90% of its ultimate stability is reached in the first 16 days of stor-
 age.  Reduction in ash particle size, by  grinding, increases pile strength.

     Carbonaceous Retorted Shale  (TOSCO II.  Union B. Paraho Indirect Mode):
 Several retorting processes  do not utilize completely the carbonaceous residue
 remaining  on the  shale after pyrolysis, as a  source of energy.  Therefore, the
 retorted shale  still  contains  about 5% organic  matter.   In  addition, the maxi-
 mum temperature during retorting  is commonly less than that at which the dolo-
 mite and calcite in  the  shale  rock decomposes,  or at which  calcium silicates

      Cementation reactions produced  by subsequent moisturizing  of carbonace-
 ous  retorted shale  do not occur  during  compaction.  There  is, therefore,  less
 opportunity to  create a  water impervious  disposal pile,  except  through the
 cohesion  produced by compaction  alone.  The  possibility  of leaching of sol-
 uble  salts from the  pile is  therefore  greater than is  the  case  with burned

 Table 3-14.  Ash Composition of Typical  Retorted Oil  Shales
Union B
aColony Environmental  Impact Analysis, 1974 (data represent
 Mahogany zone shale (~35 gal/ton) from Parachute Creek area.
 See Ref. 3.

 Lipman,  S.  C., Union Oil Co. Revegetation  Studies  (data
 represent Mahogany  zone  shale  (~35 gal/ton) from Parachute
 Creek  area.  See Ref. 12.

 Stanfield,  et.al.,  Data  represent Mahogany zone  shale  (~30
 gal/ton) from Anvil Points.  See  Ref.  25.

      TOSCO  II  retorted shale contains approximately 4.5% organic "carbon,"
 and  is  to be moisturized to about 14% H20 for compaction (3). The retorted
 shale has a very  small particle size with 60% finer than 200 mesh, and 35%
 finer than  325 mesh.  The particles are crystalline and bulky, not platy.
 A typical ash  composition is shown in Table 3-14.

      Union  B retorted shale is similar in size to that produced by the
 Parano  process.   It  is a coarse, gravel-sized black material with about 4.3%
 organic carbon (12). Some 74% of the fresh uncompacted spent shale is 4.76 mm
 to 25.4*particle  size.  Uncompacted dry bulk density is 977 kg/cu. meter
 (61  Ibs/cu.ft.),  and its field moisture content is 16%.  The shale can be
 compacted to a density of 1440 kg/cu. meter (90 Ibs/cu.ft.) in a disposal
 pile.   Typical chemical composition of the ash is shown in Table 3-14.

      Table  3-15 below lists some typical values for densities, sizes, and
 porosities  of  carbonaceous and burned retorted shales before compaction.

                   Table 3-15.  Properties of Retorted Shales (27)

Geometric mean size, cm
Bulk Density, g/cm3
Solids Density, g/cm3
Porosity (fraction)
Permeability, cm2
'47 in
2.5 x lO'10
3.46 x

      Tests on field plots consisting of TOSCO II  (and  GCR)  retorted  shales
 have indicated that in place compaction densities  of about  880  kg/m3 (55  Ibs/
 ft3) can be attained, and surface compaction  densities as high  as  1620 kg/m3
 (101 lbs/ft3) are possible (26).

      Retorted shale  from  the  Superior process will have different properties
 than retorted shales from other  processes.  The raw oil shale found  in deep
 deposits  of the Northern  Piceance  Basin contains sodium and aluminum minerals,
 and  these are slated for  recovery  along with pyrolysis products by the Super-
 ior  Oil Company.   Superior retorted  and processed shale may be partially
 "burned,"  depending  on the mode  of operation, and will  have been stripped of
 most of the soluble  sodium and aluminum salts.  Little is known at present
 about the detailed physical and  chemical properties of such processed shales.

      Soluble  Salts Associated with Burned and Carbonaceous Retorted Shales:
 Processed  shales contain mineral components which may be partially dissolved
by water.   Laboratory and  field experiments have shown that sodium, calcium,
magnesium,  potassium, bicarbonate, sulfate, and chloride are present in waters
which have  contacted freshly processed shale (27). Table 3-16 presents results
of laboratory leaching experiments of raw and retorted shales.  TOSCO II and
USBM  retorted  shale each contain about 10 kg/tonnes (20 Ibs/ton) of readily
Teachable  salts, roughly ten times that Teachable from raw oil shale. Data for

the burned shale from the Union A process (column 4 in Table  3-16)  indicates
that total soluble salts depend heavily upon extent of carbon burnoff and
mineral decomposition which occur in the combustion zone of a 6CR.

     The rate and extent of soluble inorganic salt leaching of retorted
shale which will occur under field conditions depends  on a  number of factors
in addition to the type of retorting process employed.  Such  factors include
the amount of water added, the degree of compaction accomplished, the manner
in which a pile is laid down (eg, slope, depth of pile), the  extent of pre-
leaching which is accomplished in connection with revegetation, and the age
or weathered state of the shale pile.  Also, burned shales  can form partially
cemented barriers to water within a disposal pile which can serve to inhibit
further leaching.
   Table 3-16.
Inorganic Ions teachable from Freshly Retorted  Shales
(kgs/tonne) - Based on Laboratory Tests  (27)
u -H-
Total (kg/ tonne)
Raw Shale
GCR (Union A)
     Organic Substances in Retorted Shale:  The carbonaceous component of
processed shales contains organic substances which can be extracted by or-
ganic solvents  (ie, benzene), and by water.  From .01 to .1% by weight of
processed shales are benzene soluble, and substances such as phenols, aro-
matic acids, and amines are present in the soluble fraction.  Compounds
belonging to the POM class are also present in benzene extracts, including
the  suspected carcinogen benzo(a) pyrene  (BaP) (16).  Recent experiments  have
indicated that  POM and other organfcs can be extracted by water, along with
inorganic salts.  Further, process water to be used for moisturizing retorted
shale prior to  disposal contains similar organic substances (Tables 3-12 and
3-13),  some of  which may be subject to later removal by water running off of
or percolating  through disposal piles.

     Benzo(a) pyrene (BaP) is a readily measurable member of the POM class  of
compounds.  Commonly, BaP is used as an indicator compound for potential  car-
cinogenicity of materials in which it is found.  Table 3-17 lists some BaP
levels in some natural and industrial materials.  Carbonaceous retorted shales
contain BaP in concentrations similar to those found in many natural organic
materials (28).  Shale oils, in contrast, contain relatively high levels  of
BaP.  The values shown in Table 3-17 do not necessarily indicate the bioavail-
ability of BaP in individual materials, nor do they reflect the presence  of
other potentially carcinogenic substances.

     Retorted shales have also been tested for carcinogenic properties using
test animals (28).  Although benzene extracts of carbonaceous retorted shale
exhibit carcinogenic activity on the skins of mice, retorted shale itself has
not shown such skin activity in mice exposed to the shale as bedding in long
term experiments.  Further conclusions with respect to effects of retorted
shale on internal organs of test animals cannot be made at this time, pending
the results of pathological tests currently underway.  POM extracted from re-
torted shale by water may be somewhat more active as an animal skin carcinogen
than retorted shale itself (16).

3.3.3  Other Shale Derived Solid Wastes

     Retorting and on-site shale oil upgrading can result in the production
of shale derived wastes such as coke and oily sludges.

     Shale Oil Coke:  If the crude shale oil produced by retorting is upgrad-
ed on site prior to shipment to market,  a possible product is coke.
This coke must be stored prior to sale or will require disposal as a waste.
Shale oil coke is expected to have the typical composition shown in Table
3-18.  Storage or disposal piles must provide for non-leaching of soluble
salts and organic substances to the environment.

     API Separator Sludges:  Oily and tarry material separated from waste-
waters may constitute a semi-solid waste requiring disposal.  Such material
may contain suspended solids, hazardous organics, and trace elements.
Handling options include (1) burial with other solid wastes in the processed
shale pile, (2) incineration with air pollution control, and  (3) reinjection
into the retort or upgrading units.

3.3.4  Non-Shale Solid Wastes

     If substantial upgrading operations are conducted at or near the retort-
ing site, non-shale solid wastes will be generated which require disposal.
Such wastes include spent catalysts from hydrotreating, sulfur recovery, and
arsenic removal operations, lime sludges and other solids from water and
wastewater treatment systems, and spent carbon and diatomaceous earth from
gas and oil treating units.  Some of these wastes may contain highly toxic
substances such as arsenic, and/or may result in emission of hazardous

Table 3-17.  Levels of Benzo(a)pyrene (BaP) Reported in Selected
             Natural and Industrial Materials (28)
  Substrate Material
  Natural Materials
 (parts  per  billion)
  Coconut oil
  Peanut oil
  Oysters (Norfolk, Va.)

  Forest soil
  Farm field near Moscow
  Oak leaves

  Petroleums and  Petroleum Products
  Libyan crude oil
  Cracked residuum (API  Smpl  59)
  Cracked sidestream (API  Smpl 2)
  West Texas paraffin distillate

  Oil  Shale Related Materials
  TOSCO II retorted shale
  GCR  retorted shale
  Raw shale oil (Colorado)
  Crude shale oil  (TOSCO II)
  Hydrotreated shale oil (0.25%N)
  Hydrotreated shale oil (0.052N)

  High volatile bituminous
  Low  volatile bituminous
  Coal  tar
     10 to 20
 (based on dry weight)
     4 to 8
     300 max
1 x 10* to 1 x 105
     13 - 100
 30,000 - 40,000
3 x 106 to 8 x 106

to 7* arsenic
or dlpola?
                                  d1sposa1 or ^Processing.  Hydrodenltrlfica
                           '  ma.Vnta1n N>-13* carbon, 8-10* sulfur, and up
               Table 3-18.  Typical  Composition  of  Shale Oil Coke

Ash, wt %
Moisture, wt %
Carbon, wt %
Hydrogen, wt %
Oxygen, wt %
Total Nitrogen, wt %
Sulfur, wt %
Arsenic, ppm
91 (
3.6 J
1.3 (
(0.3 water soluble)
82. 5 >

                     -    . yj NX-W i wwr\ > nppi u i oa i ujf u i i olid I c I abr\
                    Group, National Petroleum Council, 1972, data are
                    for shale oil produced by TOSCO II retorting (Ref. 29).
                   'Detailed Development Plan, Lease Tract Ca,  data are
                    for combination Paraho and TOSCO II produced shale
                    oil (Ref. 7).

3.3.5  Inventory of Solid Wastes

      The anticipated quantities of solid wastes to be produced by example
retorting processes, to  the extent that these are presently known or predic-
table, are discussed below.

      TOSCO II - Colony  Development Operation (3):  A complete inventory of
the solid wastes from commercial shale oil production has been compiled by
Colony for the TOSCO II  process, and 1s shown 1n Table  3-19.  The basis is
a plant processing  55,000 tonnes (61,000 tons) of raw shale daily, and produc-
ing an average of 50,000 tonnes per day (18.3 million tonnes/year) of waste
for disposal.  Some 97% of this waste, or 48,300 tonnes (53,300 tons) per
day, is processed shale  (and processed dust).  An additional 385 tonnes (425
tons) per day is raw shale dust.  The remaining wastes are spent catalyst
materials, sludges, arsenic-laden solids, processed plant sanitary wastes,
and 725 tonnes/day  (800 tons/day) of coke.

      These wastes  (except for the coke) are to be transported by closed con-
veyor to a disposal site in Davis Gulch (north of the plant site at Parachute
Creek, Colorado), transferred to trucks for distribution in a processed shale/

plant wastes embankment-type landfill, and compacted to 1,360 kg/cubic meter
(85 Ibs/cu.ft.).

      Paraho - Anvil Points (5,21):  The present Paraho lease on the Naval Oil
Shale Reserve provides for the processing of a maximum of 362,000 tonnes
(400,000 tons) of mined shale over a 5-year period.  This could produce up to
308,000 tonnes (350,000 tons) of processed shale and other plant wastes from
the pilot plant and semi-works operations currently in progress, over the 5-
year lease period.  These modest quantities can be disposed of by Paraho at
the existing (USBM plant) dump site, or the new test site being created by

     When the single, full-size modular retort is constructed it will have
a nominal capacity of 11,800 tonnes (13,000 tons) per day of raw shale, and
produce approximately 8,800 tonnes (9,700 tons) per day of spent shale, plus
an additional 520 tonnes (570 tons) per day of raw shale crushing fines; or
9,300 tonnes (10,200 tons) per day of waste.   This is equivalent to up to
3.4 million tonnes of waste per year.

     There is authorization for the processing of as much as 10 million
tonnes of raw shale through the modular retort.  However, it is expected that
closer to 3.6 million tonnes (4 million tons)  will  be processed over the ex-
pected 30 months of operation of the modular unit, thus producing a total of
3.25 million tonnes (3.6 million tons) of total waste from the modular plant.
It is planned that these wastes will  be conveyed to the present Paraho,
canyon-disposal  site, compacted, contoured, and revegetated.

     Lease Tracts:  The quantities of solid wastes produced at Tract C-b will
be similar to those listed in Table 3-19, since retorting and upgrading opera-
tions at that tract.are similar to operations  proposed by Colony for the Para-
chute Creek development.  Quantities of solid  wastes associated with operations
at lease tract C-a will be somewhat larger than those at C-b on a unit product
basis, since a lower average grade of shale will be processed, and overburden
and sub-ore from open pit mining will  require  disposal.  Non-shale solid wastes
at C-a are expected to be of similar magnitude and composition to those re-
ported in Table 3-19.  Estimated quantfties of solid wastes for Phase IV opera-
tions at tracts U-a/U-b are listed in Table 3-20 (23).

         Table 3-19.  Major  Solid Wastes from TOSCO  II Processing (2)
       (Based upon processing  55,000 tonnes of raw shale  per day)
Source of Solid Waste
Pyrolysis Unit
Processed Shale
C1ar1f1er Sludge from
Wet Scrubbers-Preheat
Ball Circulation System
Processed Shale
Moisturizing System
Crushing Unit
Primary Crusher
Final Crusher
Shale Storage S1lo
Upgrading Units (Hydrotreate
Gas Oil
Gas 011
Hydrogen Unit
Hydrodesul furlzer
Caustic Wash
Guard Bed
Shift Converter
(High Temp.)
Shift Converter
(Low Temp. )
Sulfur Unit
Claus Unit
Tail Gas Hydrotreater
Gas Treating Unit
DEA Filter
DEA Filter
Coker Unit
Water Treatment

48,400 T/D*
780 T/D*
59 T/D*
39 T/D*
49,200 T/D
23 T/D
295 T/D
68 T/D
386 T/D
0-68 T/2 yrs (max)
55 T/yr
0-236 T/2 yrs (max)
318-432 T/yr
123 T/3-5 yrs
2.2 T/D
14 T/l-3 yrs
45 T/5 yrs
45 T/3 yrs
136 T/2 yrs
9 T/5 yrs
7.5 T/2 weeks
7.5 T/2 weeks
727 T/D
0.5 T/D
.02 T/D
17,650,000 T
285,000 T
21 ,570 T
14,268 T
8,300 T
107,800 T
24,900 T
0-34 T
55 T
0-118 T
318-432 T
31 T
800 T
6 T
9 T
15 T
68 T
2 T
390 T
390 T
265.000 T
200 T
8 T
Processed Shale
Raw Shale Dust
Processed Shale Dust
Processed Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Spent HDN Catalyst
Proprietary Solid
Spent HDN Catalyst
Proprietary Solid
Spent HDS Catalyst
Spent Aqueous Caustic
Spent ZnS Catalyst
Spent Fe-Cr Catalyst
Spent Cu-Zn Catalyst
Spent Bauxite Catalyst
Spent Co, Ni-Mo Catalyst
Dlatomaceous Earth
Deactivated Carbon
Green Coke
L1me & Alum Flocculants
Proprietary Coagulant Aid
T/D  tonnes/day
*Water Excluded

Table 3-20.  Solid Wastes Generated Durtng Construction and Operation of Shale Oil  Facilities at
             Tracts U-a/U-b - Phase IV (16,000 m? shale oil/day) (23)
                      Source of Waste
                 Retort Shale
                 (dry basis)
                 Raw Shale Fines
                 Spent Catalysts
                 Waste Fire Brick and Fines
                 Type Heat Carrier
                 Diatomaceous Earth  arid
                 Activated Carbon
                 Elemental  Sulfur
                 Construction Wastes
118,000 tonnes/day

155 tonnes/day
1550 tonnes/year
640 tonnes/year

90 tonnes/year

80 tonnes/day
27,000 tonnes (total)


 1.  Cameron Engineers, Inc., "Synthetic Fuels Data Handbook,"  1975.

 2.  Colony Development Operation, "An Environmental  Impact Analysis  for  a
     Shale Oil Complex at Parachute Creek, Colorado,  Part 1," 1974.

 3.  Colony Development Operation, "Draft Environmental  Impact  Statement/Pro-
     posed Development of Oil Shale Resources in Colorado," U.S.  Department of
     the Interior, Bureau of Land Management, December 1975.

 4.  Final Environmental Statement for the Prototype Oil  Shale  Leasing Program.
     Vol. I, Regional Impacts of Oil Shale Development,  U.S. Department of
     Interior, 1973.

 5.  Jones, J. B. "The Paraho Oil Shale Retort," 9th Oil  Shale  Symposium,
     Colorado School of Mines, Golden, Colorado, April 29-30,  1976.

 6.  Data collected by TRW/DRI during sampling at Paraho facility, Anvil  Points
     (Colorado), March 1976.  A detailed discussion of the analytical data  and
     findings can be found in a report, "Sampling and Analysis  Program at the
     Paraho Facility," to be published shortly by EPA.

 7.  Detailed Development Plan, Federal Oil Shale Lease Tract C-a (Rio Blanco
     Oil Shale Project, submitted to Area Oil Shale Supervisor, 1976.

 8.  Detailed Development Plan, Federal Oil Shale Lease Tract C-b (Roxana Oil
     Shale Project), submitted to Area Oil Shale Supervisor, 1975.

 9.  Hughes, E. E., et.al., "Oil Shale Air Pollution Control,"  Stanford Re-
     search Institute, EPA-600/2-75-009, May 1975.

10.  Cameron Engineers, Inc.,'Synthetic Fuels Quarterly," September  1974.

11.  Cameron Engineers, Inc. "Synthetic Fuels Quarterly," December 1975.

12.  Lipman, S. C., "Union Oil Company Revegetation Studies," Environmental
     Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, October
     9-10, 1975.

13.  Compilation of air pollutant emissions factors, 2nd Edition, Environmental
     Protection Agency, AP-42, April 1973.

14.  McKee, J. M. and Kunchal, S. K., "Energy and Water Requirements  for  an
     Oil Shale Plant Based on the Paraho Processes," 9th Oil Shale Symposium,
     Colorado School of Mines, Golden, Colorado, April 29, 1976.

15.  Federal Energy Administration, Project Independence Blueprint -  Potential
     Future Role of Oil Shale Prospects and Constraints, U.S.  Department  of the
     Interior, November 1974.

16.  Schmidt-Collerus, J. J. and Bonomo, F., et.al.,  "Polycondensed  Aromatic
     Compounds (PCA) and Carcinogens in the Shale Ash of Carbonaceous  Spent
     Shale from Retorting of Oil Shale," Science and  Technology of Oil  Shale.
     Ann Arbor Science Publishers, PI 15, 1976.

17.  National Academy of Sciences, "Particulate Polycyclic  Organic Matter,"
     Washington D.C., 1972.

18.  Cook, E. W., "Elemental Abundances in Green River Oil  Shale," Chemical
     Geology. Vol.  II, p. 321-4, 1973.

19.  Burger, E. D., "Prerefining of Shale Oil,"  American Chemical Society,
     Division of Petroleum Chemistry, Chicago,  Illinois, August 24-29,  1975.

20.  Data and information provided to TRW by Union Oil  Company, 1976.

21.  Cameron Engineers, Inc. Synthetic  Fuels Quarterly, June  1975.

22.  McCarthy, H. E. and Cha, C. Y., "Development of  the Modified  In-Situ Oil
     Shale Process," 68th AIChE meeting, Los Angeles, California,  November
     16-20, 1975.

23.  Detailed Development Plan, Federal Oil Shale Lease Tracts U-a and U-b
     (White River Oil Shale  Project), submitted to Area Oil Shale  Supervisor,
     June 1976.

24.  Data provided to TRW by Development Engineering  Inc. (operations  contrac-
     tor for Paraho Project  at Anvil Points, Colorado), January 1976.

25.  Stanfield, K.  E., et.al., "Properties of Colorado Oil  Shale," U.S.  Bureau
     of Mines, Report of Investigations No. 4825, 1951.

26.  Nevens, T. D., Culbertson, W. J.,  Hollingshead,  R. D., "Disposal  and Uses
     of Oil Shale Ash," U.S. Bureau of  Mines Project  SWD-8, 1967.

27.  Ward, J. E., et.al., "Water Pollution Potential  of Rainfall on  Spent
     Shale Residues," Colorado State University, prepared for the  EPA  under
     grant #14030EDB, December 1971.

28.  Coomes, R. M., "The Health Effects of Oil  Shale  Processing,"  9th  Oil
     Shale Symposium, Colorado School of Mines, Golden, Colorado,  April  29-30,

29.  U.S. Energy Outlook, Appraisal by  Oil Shale Task Group,  National  Petroleum
     Council, 1972.


     Assessment of the potential environmental impacts of oil shale develop-
ment is  the central  issue to be addressed by this chapter.  The assessment
includes a description of the baseline environmental conditions and a review
of the environmental impact studies performed  to  date  by  the  various  developers
and organizations.   The air quality section includes a discussion of the
existing meteorology and air quality in and around potential  development sites,
and a review of modeling studies which have been undertaken to predict air
quality  impacts.   The discussion of the impacts on water quality and hydrology
includes descriptions of existing  surface and gilund water quality and yields,
the relationship of ground and surface waters in the development areas, the
effects  of the consumptive use of water, and the potential effects of waste-
water disposal practices on surface and ground waters.  Spent shale and solid
waste disposal plans are summarized, including descriptions of the physical
settings of proposed disposal sites and an identification of potential hazards
and pollution problems.


     This section  includes  a  baseline characterization of the air quality and
meteorology of the  Piceance Creek and Uinta Basin areas, and a review and
evaluation of modeling efforts undertaken to predict the impact of oil shale
mining and processing activities on ambient air quality.

4.1.1  Baseline Characterization of Meteorology and Air Quality

     The size of the region, its sparse population and its topography will all
have a strong effect on the meteorology and ambient air quality of the region.

     Meteorology:  At the present meteorological  data are not available for
every potential oil  shale site; measurements are only now being made at cer-
tain sites.  Meteorological measurements are currently available for the
Parachute Creek Valley and Roan Plateau of Western Colorado as well as for the
Piceance Creek Basin.  Parachute Creek Valley and Roan Plateau data have been
taken by Dames and Moore and by Battelle Northwest Laboratories under contract
to the Colony Development Operation (1). Piceance Creek Basin data have been
taken by the Rio Blanco Oil Shale Project (2). Data and information from these
two sources will be  used to illustrate those features which are especially
important to the transport and dispersion of pollutants in the atmosphere.

     In  general, sunshine prevails over the region, and precipitation and
relative humidity are low.  Precipitation is highest during the winter, and
occurs in the form of snow at high altitude terrain and in the form of rain

at  lower altitudes.  Temperatures generally range between -40 to 100F in
the lower regions.

     Surface winds are variable with strong spatial, diurnal and seasonal 'de-
pendence, as to be expected, with the prevailing wind in the region being
southwesterly.  In Parachute Creek, Colorado River Valley and White River
Valley little information is available on air stagnation, but studies at near-
by Grand Junction show the region to have one of the highest frequency of in-
versions anywhere in the United States (14).

     Topography has an important influence on local  meteorology.  The presence
of rugged terrain causes turbulence within the planetary boundary layer (3).
This favors high dilutions which have, in fact, been observed (4,5).  Topo-
graphy  especially influences the mountain-valley systems, resulting in dif-
ferential heating and cooling.  In the presence of radiational cooling at night,
as would occur under clear skies, a drainage circulation is often set up in
which flow occurs down the side of a mountain or down a slope.  During the
daytime, the direction is reversed and flow becomes  up-slope or up-valley.
This system is commonly referred to as the mountain-val1ey breeze system.
From an air pollution standpoint, this is a very important system in the oil
shale region (6).

     The mountain-valley systems are typically weak, local circulations, with
the drainage flows characteristically weaker than the up-slope flows.  Even
at peak intensities, velocities seldom are greater than a few meters per
second.  Both up-slope and down-slope flows tend to  be confined near the
 Ground surface, being around 100m thick and only seldom thicker than 200m.
 The foregoing estimates represent drainage flow thicknesses in other regions
at latitudes similar to the oil shale region.  At the time of preparation of
this report no detailed drainage data were available for the study region.) A
drainage flow initiated at the top of a slope starts out very shallow and
gradually thickens as the air mass flows downhill.  An up-slope flow shows a
similar thickness  variation,  being shallow at the base of the slope and thick-
est at the top.  These flows  are very local  and, in  general, are not strongly
coupled to the mean flow within the Ekman layer.*

     There are other types of air flows which owe their origin to the com-
bined effects of meteorology and topography.  These, conceivably, may have a
deleterious effect on air quality.  One special flow can occur when a plume,
emitted close to the base of a stable layer, encounters a highly unstable
lower layer.  In this case, rapid mixing takes place, potentially producing
high levels of ground concentration (fumigation) which .may be intensified by
the presence of elevated terrain.  However, like other special flows (fanning,
coning, lofting and looping), fumigation requires the right set of conditions
of atmospheric turbulence structure and plume emissions.

     To summarize, limited meteorological measurements have been made for the
oil shale region, and site specific information is generally lacking except
for the lease tracts.  In another year or two more data may become available
*That part of the lower atmosphere in which surface induced stress decreases
with height, the Ekman layer usually extends to between 100 and 1000 meters
above ground level.


from on-going baseline measurement programs.   The data which are now available
show prevailing winds to be from the southwest, and inversions  to occur fre-
quently at Grand Junction.  Local flows are characterized by the mountain-
valley breeze systems.  A plume emitted within the drainage flow of such a
system may lead to elevated concentrations at downwind receptors along  the
valley floor.  Other special flows such as fumigation may also  pose a problem
but these require the right combination of turbulence conditions and emissions.
The most important circulation influence on ground level  concentrations is
probably the drainage flows.

     Air Quality:  At present, there are very few anthropogenic emissions in
the oil shale region.  Nevertheless, ambient levels of air pollution exceed
some state and federal standards.  Measurements taken to date at Tracts U-a
and U-b in the Uinta Basin  (21), show that ozone and nonmethane hydrocarbon
sometimes exceed the primary National Ambient Air Quality Standards (NAAQS).
However, the levels of most other pollutants are usually below the limits of
detection of common air monitoring instruments.  At tracts C-a and C-b, parti-
culates, ozone and nonmethane hydrocarbons (NMHC) currently exceed NAAQS.  The
most recent data (see Table 4-1) collected at Tracts C-a and C-b show that the
24-hour primary particulate standard was exceeded between 4 to 5 times, the
one hour oxidant standard was exceeded 5 times and the 6-9 am NMHC standard
was exceeded 94 times.

     At Tracts C-a and C-b  in the Piceance Creek Basin,  the air quality is
generally similar to that in the Uinta Basin  (Table 4-1).  Based on periodic
measurements taken over several  years  (1) in  the Piceance Creek Basin total
suspended particulates average 15yg per m3 annually, N02 averages  7yg per m3
annually, and SC^ less than 20yg per m3.  These values are much lower than the
NAAQS  (annual average of 75yg per m3 for particulates, lOOyg per m3 for N02,
and 80yg per m3 for S02). Hydrocarbon concentrations show seasonal fluctua-
tions with a maximum during the  growing season.  Tracts U-a and U-b show
similar annual averages:  22 yg  per m3 for TSP, 10 yg per m3 for N0 and 10
yg per m3 for S02-

     A significant amount of haze has been observed in Parachute Creek Basin
and along the Colorado River Valley (2,17). The origin of this haze is unknown
at the present, but  four mechanisms of formation have been suggested.   First,
in both the Piceance Creek  and Uinta Basins,  relatively  high levels of non-
methane hydrocarbons have been observed.  These have been attributed to natural
sources such as sagebrush and other vegetation.  Hydrocarbon and the N02 con-
centrations  (low though they are) could contribute significantly to the high
photochemical oxidant values whTcfi are sometimes observed in the Uinta Basin.
The photochemical process,  if it involves the  03-N02>cycle, may be accompanied
by visibility degradation.  Second, under high relative  humidity  ( 50%) parti-
culates in the air could serve as condensation nuclei which can grow by hetero-
geneous nucleation into "visible" sizes of a  few microns.  The  light scattering
of such "mixed" aerosols could explain the haze observed.  Third, long range
transport of anthropogenic  hydrocarbons and NOX, potential percursors of oxi-
dant  (and haze), is also possible.  Fourth, the  intrusion of stratospheric
ozone  into the lower troposphere is also a possibility especially at mid
latitudes where there is a  break in the tropopause.


  Table 4-1.  Existing Air Quality Data Summary for Federal Oil Shale Lease
              Tracts (2,17,21)
Criteria Pollutant
Parti cul ate
Maximum 24 hour (yg/m3)
Annual mean (yg/m3)
No. occurrences
exceeding NAAQS*
Maximum 3 hour (yg/m3)
Maximum 24 hour (yg/m3)
Annual mean (yg/m3)
Annual mean (yg/m3)
Maximum 1 hour (yg/m3)
Maximum 8 hour (yg/m3)
Maximum 3 hour (yg/m3)
No. occurrences
exceeding NAAQS*
Maximum 1 hour (yg/m3)
No. occurrences
exceeding NAAQS*




























  *Nationa1 Ambient Air Quality Standards
 **Nonmethane hydrocarbons
***Standard applies to N02

4'1'2  rc1'*"    Mde1 App1icat1on to 0" Shale Related Emissions in Colorado
4.,*.!eC!!Itlyi.fev?rf1 "19delin9 efforts have been undertaken to predict the
impacts that oil shale mining and processing might have on ambient air quality.
The modeling concept most widely used in these studies has been the Gaussian
model which is described in several standard references (7, 8,9).  In this model,
the basic equation describing concentration, X, from a continuous emissions
source at effective stack height, H, is given by:
  X =  "- H  "  pvn  r- ' y'2  "-- [- i (^"-)2 ] + exp [- I (^)"]|  (4-1)
 where Q is the emissions rate,  ay and a,  the  standard deviation of the plume
 distribution in the horizontal  arid vertical respectively, U  the mean wind
 speed, y the horizontal  coordinate distance reckoned from the plume center-
 line, and z the vertical coordinate distance  reckoned from ground level.

      The effective stack height,  H, is related  to  the actual stack height, h,
                                  H = h +  AH                            (4-2)

 where AH is commonly referred to  as the plume rise height.   Several methods
 (10,11) have L,een developed to  estimate this  quantity.  Typically, H depends
 on stack parameters (effluent velocity and temperature, and  stack radius), and
 environmental  conditions (atmospheric lapse rate of potential temperature
 and temperature differential  between plume and  environment).  The plume rise
 formulation has long been a source of controversy, and the matter is still not
 settled to the satisfaction of  all.

      Ap:lication of diffusion modeling must be  done with all due care.  The
 problem being  modeled is often  times complex  and requires simplifying assump-
 tions in order to make the problem tractable.   Uncertainties are frequently
 associated with the source input  data (meteorology and emissions).  These
 simplifying assumptions  and uncertainties have  led to the commonly held view
 that "most model  results are generally good to  within a factor of two."

      Battelle, Northwest Laboratories, conducted one of the  earliest oil shale
 modeling studies (12) for the Colony Development Operation.  A model was
 applied to a typical  oil shale  plant situated in the Parachute Creek Valley
 and to Roan Plateau using diffusion data  collected by Battelle and meteorolog-
 ical  data provided by Dames and Moore. Engineering Science, Inc. has also
 conducted a study (13) of the Piceance Creek  Basin for the Federal Energy
 Administration to assess the air  pollution potential of future oil shale dev-
 elopment.  Stanford Research Institute completed a similar study (14) for the
 U.S.  Environmental  Protection Agency, but with  the emphasis  on controls. Most
 recently, three other studies have been completed: Detailed Development Plan
 (DDP)  for Tract C-b submitted by  the C-b  Shale  Oil  Project (Roxana), DDP for
 Tract C-a submitted by the Rio  Blanco Oil Shale Project, and the DDP for tracts
 U-a/U-b submitted by the White  River Oil  Shale  Project (2,17,21).


     Battelle's Study of Parachute Creek and the Roan Plateau:(12)  In the
modeling study of the Colony Development Operation in the Parachute Creek
Valley and on the Roan Plateau, Battelle used the exact form of the equation
shown earlier in equation 4-1.  The standard deviations in plume distribution
oy and oz, were expressed in terms of observables, such as standard deviations
in anemometer and propeller wind vane fluctuations following methods developed
by others (8,15).  Buoyant plume rise was formulated after a method developed
by Hanna (11).

     The wind speed input for equation 4-1  was obtained from a 60m tower
measurement, while temperature and potential temperature lapse rates were
obtained from the Grand Junction radiosonde data. Total peak emissions for an
8000 m3/day TOSCO II plant (in kg per hour) were assumed to be:  65 SOg. 332
NOX, 136 THC (total  hydrocarbons), and 583 PM (particulate matter).

     The model was applied to a potential  site in the Parachute  Creek Valley,
and to another on the Roan Plateau.  Model  results indicate that for the
Valley site, N0 concentrations will  exceed NAAQS while S02 and  particulate
concentrations will  be just under standards.  THC levels will  be considerably
under NAAQS.  For the plateau site, all  concentrations are predicted to be an
order of magnitude less.   Based on these results, Battelle recommended that
the proposed oil shale plant be located on  Roan Plateau instead  of in the

     Stanford Research Institute's Study of the Piceance Creek and Uinta
Basins (14)In a study to assess oil  shale air pollution impact in the
Piceance Creek and Uinta Basins, SRI  used the Climatological  Dispersion Model
(CDM).  Topographic effects were recognized as a potential  influence, but were
not incorporated in the model.  Pollutants  treated were S02 THC and NOX.
Averaging times selected were those corresponding to air quality standards.

     Meteorological  inputs were obtained from observations at Grand Junction,
Colorado, for the Piceance Basin simulation and from Salt Lake City, Utah, for
the  Uinta  Basin simulation.   For the worst case conditions, a  meteorological
regime comprised of neutral atmospheric stability and a light wind of 1.5m
sec'l  was  assumed.   Such conditions are found to persist over 24 hour periods
in the oil shale region and occur an average of 15 days/year.

     In the actual modeling exercise the emissions from a 16,000 m3/day (or
100,000 barrels/day) TOSCO II type plant, assumed to be equipped with best
controls, were in kg per hour:  S02 1400, NOX 1850, THC 272, and PM 295.
Following the recommendation of the Battelle study (12), SRI assumed that the
proposed plant would be located on a plateau.  The results of the modeling
exercise show  that a TOSCO II type plant equipped with best available con-
trols will not violate the federal ambient air quality standards for criteria

     Under more stringent ambient air quality standards, such as those pro-
posed for a Class II region, (which seek to prevent significant deterioration
of ambient air quality in unpolluted areas) additional controls  will be re-
quired.  To meet the 24-hour particulate standard, 85% additional control will


be requ1red;while the annual average S02 standard  can  only  be met with 72%
additional control.  No additional  controls are required  for hydrocarbons and
oxides of nitrogen.

     SRI evaluated control technology for the Colony Development Operation
(TOSCO II type plant) and concluded that when best-available controls  (cyclones,
baghouses and wet scrubbers) are employed, particulars and sulfur  oxide emis-
sions can be reduced to one-third of the levels previously  calculated  by

      Federal  Energy Administration  Study  (Piceance Creek Basin) (13):  Modeling
of air  pollution levels associated  with oil  shale development was conducted
by Engineering  Science, Inc.  under  contract  to the Federal  Energy Administra-
tion.   Three  separate  models  were used  in  determining  ground level concentra-
tions:   up-valley wind model, gradient wind  model and  a fumigation model.   All
of these models are Gaussian  in  nature.  The up-valley model, APMAX, was used
to calculate  short-term concentrations  (3-10 minutes)  which were then extended
to 1-hour averages using  an empirical expression.  The gradient wind model,
APSIM,  was used to simulate annual  averages  by incorporating the wind flow
pattern and a stability frequency distribution function.   In the fumigation
model,  it was assumed  that the plume would move down  the valley at night with
the drainage  flow and  would be contained  in  a stable  layer above the valley
floor.   Then, with solar  heating in the morning,  the  ground-based  inversion
would be eroded upwards  to the plume layer;  whereupon, the plume would mix
within  the ground-based  layer to produce  elevated ground level concentrations

      Emissions data were  obtained  from  the developers and  operators of the
proposed oil  shale plants, from the Department of Interior, from the Environ-
mental  Protection Agency  emission  factors, and from estimates  by contractors.
Total  emissions, in kg per hour, at a proposed plant  site  (TOSCO II process
at 8000 m3/day) were:   604 S02, 664 NOX,  144 THC, and 336  PM.  Meteorological
data were obtained from the Atomic  Energy Commission, Department of Commerce,
and Colony Development Operation.   However,  available meteorological data were
not adequate  for defining important diffusion parameters in the Piceance Creek
Basin.   Engineering Science,  Inc.,  therefore, synthesized  a wind-flow pattern
and frequency distribution for use  in calculating dilution and dispersion of
released air  contaminants.

      The study evaluated  the  primary pollutants  - S02, NOX, THC and PM.  It
was found that under the  Accelerated Development  (which  would  produce up to
 200,000 m3/day during  the period 1980-1990), the  primary and  secondary  stan-
dards for S02 as well  as  those promulgated for particulate matter  and nitrogen
oxides  would^e met.  However, if the Colorado SO?  annual  standard* of 10 Mg/
m3 wire implemented, then a production  limit of 32,000 m3/day would be required
unless more stringent  emission controls could Be  employed. The proposed EPA
Class II incremental limits for SOg and particulate matter will result in a
production limit of 56,000 m3 per day without better  emission  controls.

*This standard has since  been changed to  15  wg/m3.


     The FEA study also considered a hypothetical  plant based on Union A pro-
cessing technology.  But the results are not reviewed here because Union B
technology, on which current plans are based, has  emissions different in
nature and magnitude than those associated with Union A technology.

     Colony Development Operation:  The Colony Development Operation study (1)
used the modeling methods of the Battelle study (12)  but with revised emis-
sions estimates.  Average emissions for normal  emissions, in kg per hour, were:
128 S02, 819 NOX, 147 THC and 376 PM; peak emissions  were calculated to be
144 S02, 792 NOX, 138 THC and 382 PM.

      The  results  of the  study  indicate that  the proposed Parachute  Valley plant
 can cause an  increase  in concentrations  (above background  values) of  14% SOg,
 0.01% HC,  25-100% NOX  and 3-6% particulate matter.   Higher ambient  concentra-
 tions may occur during plant start-up or during abnormal operating  conditions.

      Predicted  annual  mean concentrations due to plant emissions will  not ex-
 ceed Colorado's ambient  air quality  standards.  The  twenty-four hour  S02 con-
 centration may, however, exceed  the  State's  short term concentration  of 15yg
 per m3 (24-hour average, not to  be exceeded  more than once in a 12-month
 period).   Also, the 24-hour predictions of 171 yg per m3 particulates (see
 Table 4-3) will exceed the national  secondary standard of  150 yg per  m3.

      C-b DPP (2): The Detailed Development Plan submitted  by the  lessees of
 C-b lacks the details necessary to make  a  proper  assessment as  to  the adequacy
 of the modeling effort.   However, the following information has been  provided.
 A Gaussian plume model was  used to estimate  concentration  of S02  NOX, THC and
 PM.  Average meteorology was  used, and  the Brigg's  (10)  method was  used for
 treating plume rise.

      Emissions assumed,  in  kg per hour,  were:   121-160 SO?, 741-859 NOX,  119-
 142 THC, and 352-439 PM. The results of the study  indicate that  plant opera-
 tions will result in maximum increments  over a  24-hour period  of  9yg  per m3
 SO?, 34yg per m3 NOX, 5pg per m3 THC and 19yg per m3 PM.   The authors of the
 DDP concluded that based on  the limited  study "the  best estimate  is that com-
 pliance with federal and state standards is  achievable,"  and indicated that in
 Phase II  of the modeling study,  "the entire  modeling process is to  be repeated
 in more depth."

      EPA, in a review of the DDP (16), identified  three areas of deficiency:
 too few details with respect to air pollution emissions and controls, inade-
 quate modeling exercise, and the neglect of  "fugitive" emissions.   In attempt-
 ing to provide guidance  to  C-b,  the EPA ran  their C7M3D model  which includes
 topographic effects, using  Colony emissions  data.   The results  indicated that
 "state and federal air quality standards are predicted to be violated."  The
 developers of tract C-b  are presently re-evaluating emissions control and are
 doing further "worst-case"  modeling.

      Tract C-a DDP  (17): The EPA Valley model (C8M3D) was used for simulating
 air quality, with modification as necessary for making short-term (3-hour and


 24-hour) predictions.   Plume rise was  treated by Brigg's method  (10).  Emis-
 sions for two phases of operations were  considered.  It was assumed that Phase
 I  operations wi  1  begin in 1979 with a small open-pit mine and a single TOSCO
 II retort capable  of processing 10,000 tonnes of oil shale per day and producing
 approximately 720  nv* of pipelinableshale oil daily.  It was further assumed
 that by 1982 this  capacity would be doubled  to  1440 m3 per stream day
 Phase II operations were assumed to begin by mid-1985, with a total processing
 capability of 108,000 tonnes per stream  day.  Delayed coking and hydrotreating
 is to be employed  to produce upgraded  shale  oil at the rate of 8,98.2 m3 per
 stream day.  Emissions, in kg per hour,  for  Phase I were:  12 SO?, 146 NOX, 51
 NMHC  and 67 PM; and for Phase II: 120  S02, 451 NOX, 84 NMHC and 260 PM.

      Modeling results  indicate that Phase I  operations will meet the NAAQS
 and state standards for all criteria pollutants, except nonmethane hydrocar-
 bons.  The impacts of Phase II operations were  found to be similar to Phase I,
 except that the  short-term ambient standards set by the State of Colorado
 would be violated  unless  the area were classified Category II.

      Ambient air quality  was also simulated  under fumigation conditions using
 a  multiple-source  adaptation of the fumigation model (19).  The predicted air
 quality under these conditions was less  sevendy affected than previously de-
 scribed primarily  because baseline monitoring has indicated fumigation to be
 a  transitory state (1  hour duration).

      Tracts  U-a/U-b (51):   Two models were used for simulating air quality at
Tracts  U-a  and U-b.  Short term  (24 hours and less) concentrations were simu-
lated with  EPA's PTMTP  model while long  term predictions were made with EPA's
C9M3D "Terrain" model.  In the PTMTP application, 10 minute averages were cal-
culated and  extended over longer  averaging times (up to 24 hours) using statis-
tical concepts developed  by Larsen (52).  The "Terrain" model assumed as inputs
 the actual  terrain  features in the vicinity of the proposed plant site.  Both
model applications  were conservative in  their choice of meteorology, emissions,
stack height and other  parameters  so that predictions would represent worse
case  conditions.

      Detailed modeling  was done for Phase IV type operations (100,000 barrels
per day of  raw shale oil).   Phase IV involves emissions (in kg per hour) of:
134 S02,  1242 NOX,  50 NMHC and 410 PM.   Phase III production rate and emissions
will  be one  half those  of Phase  IV.

      The model results  indicate that, with the exception of hydrocarbons and
particulates, all short-term NAAQS will  be met by large margins.  Further, the
hydrocarbon  emissions include  those from the fines-type retort preheaters,
which may contain as much as 80 percent  methane.  If this were true, downwind
nonmethane hydrocarbon  concentration may be as low as 11.8 yg per m3.  Maximum
24-hour particulate levels were found  to be 257 yg per m3 but exceeds the sec-
ondary  NAAQS 150 yg per m3.  Modeling  results predict that all annual NAAQS
will  be met.

      Since ambient  levels  are  directly proportional to emissions, Phase III
operations will lead to ambient levels which are roughly one half of those
predicted for Phase IV  operations.


 4.1.3   Assessment of Models and Model Concepts Applied to Oil Shale Emissions

     All of  the studies reviewed in Section 4.1.2 have utilized the basic
 Gaussian equation in one form or another.  In the simplest of applications(12),
 ground  level concentrations were estimated using meteorological data measured
 at a tower,  and turbulence data collected during special diffusion studies.
 The most ambitious modeling exercise to date (17) simulated long- and short-
 term concentrations in the presence of topographic influences using input
 meteorological data collected during baseline monitoring at tract C-a.

     There are, however, several limitations of the Gaussian model.  It is
 known to overestimate ambient concentrations under calm conditions and at long
distances from the  source,  while underestimating  near surface  levels  (19).
The overprediction  under  calm  conditions  may  be attributed  to  the  inverse  de-
pendence of concentration on wind speed  in  equation  4-1  which  physically re-
presents the neglect of convective  mixing under calm conditions.   To  overcome
this  limitation,  similarity theory  can be applied to  the boundary  layer  (3).
In this method the  standard deviation in  plume distribution (oy and oz)  would
be expressed in terms of mean wind  speed, ground  roughness  and heat flux.   Such
a parameterization  would have  the effect  of removing  the u-1 dependence  (equa-
tion  4-1) since this will be coupled with the u dependence  in  the  ay  and az.

     Overestimation at long distances probably reflects the absence of a mea-
 sure of plume  meander in the turbulence parameterization.  Plumes traveling
 over great distances commonly meander along the way, especially in the pre-
 sence of topography.    Such  meandering will enhance plume dilution.  Under-
 estimation near the ground surface may be due to the mis-application of the
 Gaussian concept rather than to shortcomings inherent in the concept.   It is
 well known that special meteorological conditions such as fumigation, looping,
 etc. can cause high concentrations near  the ground.  Therefore, an acceptable
 modeling exercise should incorporate such effects.

     In its  present form the Gaussian concept is difficult to apply to  rugged
 terrain.  Such terrain has two effects on air pollution:  first,  it physically
 alters  air trajectory; and second, it increases  the turbulence level.  Tra-
 jectory effects can take the form of streamline  contouring around elevated
 terrain or the form of down-siope-up-valley flows induced by mountainous ter-
 rain.   Streamline modifications due to topography are currently handled mech-
 anistically  as in the EPA  Valley Model (C8M3D).  The only convincing method  of
 treating the enhanced turbulence which results from rugged terrain has  been
 direct  observation.  However, direct measurements are all too often quite
 expensive  and  could produce undesirable  delays in making environmental  assess-
 ments .

      In addition to the above mentioned limitations  of  the Gaussian  model,
 several other simplifying  assumptions are  implicit  or explicit in model pre-
 dictions.   In the  early model applications upper air data  collected  at  Grand
 Junction and Salt  Lake  City were applied to  the  Piceance Creek and Uinta
 Basins, respectively.  This is  a Questionable use of data  even though they
 represent upper  air measurements (especially over rugged terrain).   This  pro-
 blem has been partially  remedied by  the  site-specific measurements taken  as


part of  the on-going baseline monitoring programs.  In some models the time
averaged wind  speed and prevailing wind direction are used.  These quantities
are assumed to be constant  over  time.  Also, wind measurements taken at one
point are  frequently used to characterize the flow of the diffusing layer.
These represent obvious shortcomings which must be addressed prior to and dur-
ing model  application.

     Atmospheric diffusion  modeling in general is limited in its ability to han-
dle particulates and reactive (or secondary) pollutants. When applied  to parti-
culate emissions, a wide range of particle sizes must be considered.  Particles
smaller  than 20ym may be treated as a gaseous species while the larger ones
must recognize gravitational settling as an important removal mechanism.
Fugitive dust  remains difficult  to model for these reasons and also because
the emissions  themselves depend  on meteorology.   Secondary pollutants such
as photochemical oxidant and aerosols cannot be handled by simple Gaussian
models,  since  formation of  such  substances  in the atmosphere depends on sun-
light as well  as precursor  (and/or catalyst) concentrations.

     Finally,  all models are useful only to the extent that emissions data
are accurate and representative. Differing assumptions regarding emission
factors, plant size,  sources covered, and normal  vs. transient operations can
lead to  dramatically different predicted concentrations of pollutants.

4.1.4  Comparison of Modeling Results

     The emissions  (kg per  hour) used In the various modeling studies are
tabulated  in Table 4.2.  A  comparison of modeling results  is difficult be-
cause of the different assumptions with respect to processes (TOSCO II,
Paraho,  etc.), plant configuration and size, and  meteorological emissions fac-
tors.   Certain generalizations may, however, be made.  A typical  shale oil
plant with a production capacity of 8000 nn per day can be expected to have an
hourly emissions of 100-150 kg SOe, 400-800 kg NOX, 80-150 kg THC and 250-400
kg PM.

     The Colony Development Operation study used  the modeling methods devel-
oped by  Battelle, but with  a different set  of emissions  (as  may be seen in
Table 4.2).  Of the two, Colony's emissions are the more recent (reported  in
December 1975  versus October 1973 for the Battelle emissions), and are there-
fore, more realistic since  they  incorporate the most recent  data.  Colony
also estimated the average  maximum emissions of the proposed shale oil plant
for Roan Plateau.  These estimates were reported  in 1974 (20), and in kg per
hour, are  144  S0, 792 NOX, 382  PM and 138  THC.

     The summary of the air quality modeling predictions are presented in
Table 4-3. Ambient air quality  standards for major criteria pollutants are
likely to  be violated according  to the predictions.  Sulfur  dioxide will meet
federal  ambient  air quality standards at all sites but will  exceed the federal
significant deterioration standard and Colorado's maximum allowable increments
at certain sites.

    Table 4-2.   A Comparison of A1r Pollutant Emissions  (kg  per hour) Used 1n Modeling Studies
Battelle (Parachute Creek and
Roan Plateau)
FEA (Plceance Creek
SRI (Plceance Creek and
Ulnta Basins)
Colony Develop Operation (Parachute
Normal Creek and
Peak Roan Plateau)
C-b DDP (Plceance Basin)
C-a DDP (Plceance Basin)
Phase I
Phase II
U-a/U-b DDP (Ulnta Basin)
Phase II
Phase III*
KG per HR
KG per HR
KG per HR
KG per HR
*Phase IV Involves doubling of production and emissions  from Phase III  at Ua/Ub.

      Federal  particulate ambient air quality standards are currently exceeded
at  the  lease  tracts.   Particulate increment increases forecast to occur at
these sites will  also  exceed the federal significant deterioration standards.
The measured  hydrocarbon levels are currently quite high and occasionally ex-
ceed  federal  6-9  am standards.  Likewise, the forecast levels are also high at
all sites.

      Although the modeling studies reviewed in this section differ in complex-
ity and assumptions, all studies have predicted that certain ambient air qual-
ity standards will  be  violated if oil shale development occurs.   Currently,
levels of suspended particulates and non-methane hydrocarbons approach and
occasionally  exceed short term ambient standards in the oil shale region, and
additionally  emissions due to oil  shale development will  worsen  the situation.
Significant deterioration and incremental increase standards for S02 may also
be violated.  It  might be commented that the emissions assumed in some of the
modeling exercises  do  not include sources such as fugitive dust emissions,
blasting emissions, and transient releases (such as would occur during plant
upset).  Although difficult to quantify, these uninventoried contributions to
oil shale emissions suggest that the predictions in Table 4-2 are probably
underestimates of ambient levels.

      Much can still be done to reduce ambient air quality levels resulting
from  oil shale development and therefore to mitigate the impact on the air
environment.  Better emissions controls in the future would directly reduce
ambient levels.   Increased stack heights would provide a thicker diffusing
layer for plant effluents; and this, in turn, would lead to lower ground con-
centrations.  Reduced  plant size would lead to proportionately lower emissions
and therefore, lower ambient concentrations.  Plants may be sited on terrain
which would favor diffusion and transport.  One or more of the above features
may be combined to  provide even greater reduction in ambient levels.

      Table  4-3.
Comparison  of  Modeling  Results  with  Applicable  Standards     All  Quantities  in yg  per m3
(References  shown  in  parentheses)                                                                          M

Sulfur Oxtdei

Nitrogen Dioxide


(Corrected for
National Aablent

Annual b

Air Quality Standard*


Clan 1


Clii* 11

Colorado Aafctent Air Quality Standard*
Max. Alia
Category 1

able Increment*
Category 11

Category 111


HaitM Aafctent Concentrations Predicted by Modeling





C-b OOP* (2)
l/n Tract
Off Tract

C-a POP1 (17)
(Staga 2)

mate u


""JoT" (51)
               itrlc man.
           Arlthmtlc mn.
           NaxIwB alloMbla Fadaral IntraHnti for area clatiai (Plctanca Cratk Batln
           tubjtct to Clui  II regulation*).
           NaxIwB alloxabla arttlMtlc van Ineraamitt ovar battllna.
           Na>1>uB allombla aslant air concantratlon.
           Rapreiaoti HO,
           tepraiants THC.
           Includai a background valua of 14 g par m3.
           Eicludn background conctntratton
           Ineludts background concantratlon,
           Plant contribution (Sb.9 ug par >) Includti unknown aaount of aatnana; background contribution (480 ug par a3) auludat CHy
           Pradlcud off tract ooncwtratlon Incluilvt of background
           ConotntratlOM, Including background. Hda at 100-SOOO  downwind. Concentration! asiuaD Phata IV typ* optratlon (100,000
           barreli par day). Concentrations froa Phaia III typa oparattoni will ba roughly ona naif thota of Phaia IV
         " Rtpratantt projactloni for tno onUi of July, excluding background.


     Commercial development of Green River oil  shale can  have  impacts  on  local
and regional surface and ground water quality and flows.   Diversion of water
for consumptive use in the upper Colorado basin can adversely  affect the  aver-
age discharge and quality of water in the lower Colorado  basin.   Direct and
indirect wastewater discharges may degrade local water quality and change the
existing hydrologic regime.  This chapter includes a review of existing sur-
face and ground water quality and flows in northwestern Colorado  and north-
eastern Utah, a summary of predicted affects of consumptive water use  for oil
shale development, a summary of water pollution control plans  for major devel-
opments, and a discussion of potential indirect and accidental sources of water
pollution associated with the oil shale extraction, processing, and waste dis-
posal activities.

4.2.1  Existing Surface Water Quality and Flow

     The major rivers and streams in the oil shale region are  the White River
and its tributaries - Piceance and Yellow Creeks, and the Colorado and its
tributaries - Roan and Parachute Creeks.  Upper Colorado River Basin

     The oil shale regions of Colorado and Utah are located in the Upper  Colo-
rado River basin and includes all of the drainages of the Colorado River above
Lee's Ferry, Arizona and encompasses an area of approximately  50,000 sq.  km
(19,500 square miles).  In the upper basin, 77 percent of the  area receives
less than 50 cm (20 inches) of precipitation, and 42 percent receives  less
than 30 cm (12 inches) (22).

     Water quality and discharge are monitored by the U.S. Geological  Survey
at more than 50 stations in the Upper Colorado River basin on  the larger  tri-
butaries and main stem of the Colorado River.  Basic data are  published annu-
ally for each state.  Table 4-4 summarizes discharge and water quality data on
the White and Colorado Rivers at location nearest the Colorado and Utah oil
shale regions.  Piceance Creek Basin

      A major east-west trending topographic divide just south of the  Rio
 Blanco-Garfield County line separates the streams draining the Piceance  Creek
 basin into two drainage systems.  The northern part of the basin is  drained
 by tributaries of the White River (Piceance and Yellow Creeks).   The  southern
 part of the basin is drained by tributaries of the Colorado River (Parachute
 and Roan Creeks).  Figure 4-1 shows the location of proposed oil shale devel-
 opment activities relative to the surface drainage systems.

      Streamflow in the Piceance Creek basin is typical of those  regions  where
 the main source of water is snowmelt.  Starting in March or April,  snowmelt
 produces a period of high runoff that extends to June or July.  During the
 remainder of the year, streamflow is maintained almost entirely  by  ground
 water discharge.  The surface-water/ground-water systems in the  Piceance Creek


   Table  4-4.   Water and Dissolved Solids Discharge at Selected Stations in
               Upper Colorado River Basin C22)
Dissolved Solids
White River
near Meeker,
Colo. (1)
White River
near Watson,
Utah (2)
Colorado River
near Glenwood
Spr., Colo.
(loc.off map)
Colorado River
near Cameo, C
Colo. (4)
Weighted Annual
Average Annual AF Average Discharge
(m3/min) (109 m3) Concentration (tonnes/yr)
(cfs) (acre-ft) (mg/1) (tons/yr)
0.57 224
0.68 439
2.14 270
3.7 387
581 ,000
  (   )See Fig. 4-1 for location

basin are intimately related; ground water discharge accounts  for about
80 percent of the volume of stream flow (23).

       Piceance and Yellow Creeks:   Flows in Piceance and Yellow Creeks are
highly variable and strongly influenced by irrigation practices.   Table 4-5
summarizes stream flow records at four locations on Piceance Creek and one
location on Yellow Creek.   Mean annual discharge of Piceance and Yellow Creeks
into the White River i.s 14,520 and 1,130 acre feet, respectively.

     The upper reaches of both Piceance and Yellow Creeks surface waters can
be classified as a mixed bicarbonate type, grading to a sodium bicarbonate
type in the lower reaches.  Concentrations of dissolved solids, sodium, chlo-
ride, and fluoride all increase in the downstream direction.  In general,
water quality is best during periods of high discharge but the chemical char-
acter remains about the same.  The total dissolved solids (TDS) concentration
in Piceance Creek ranges from 440 to 5700 mg/1; the TDS content in Yellow
Creek ranges from 1400 to 3000 mg/1  (25).  The sulfate and dissolved solids
concentrations exceed the public water supply limits in the upper reaches of
both creeks and water in the lower reaches has fluoride concentrations of more
than twice the limit of 1.0 mg/1 established by the U.S. Public Health Service

                                                        PARACHUTE CR
                                SHOWING LOCATION OF
                                SELECTED STREAM GAGING
                                STATIONS AND CONTEMPLATED
                                OIL SHALE DEVELOPMENTS
                              A STREAM GAGING STATION
Figure  4-1.   Location  of Selected Stream Gaging Stations and  011 Shale Developments

  Table 4-5.  Summary of Piceance and Yellow Creek Stream-flow Records  (25)
Piceance Creek
at Rio Blanco
Piceance Creek
below Rio Blanco
Piceance Creek
below Ryan Gulch
Piceance Creek
at White River
Yellow Creek
near White
Ri-er (8)
of Record
(sq. miles)
m3/min (cfs)
Extremes of
m-Ymi n

( ) See Figure 4-1  for location
        Roan and Parachute Creeks:   Roan and Parachute Creeks  have peak flow
during spring snowmelt and low flows during autumn and winter  (26).  Although
Roan Creek flows throughout the year, Parachute Creek is  often dry from Dec-
ember through April.   Table 4-6 summarizes streamflow records  at three loca-
tions on the Parachute Creek drainage and three locations on the Roan Creek
drainage.  Average annual  discharges of Parachute Creek and Roan Creek into
the Colorado River are about 14,000 and 26,000 acre feet  of water, respectively.

     Chemical analyses of waters from Parachute and Roan  Creek show the streams
to have similar water quality characteristics.  Dominant  ions  are calcium,
magnesium, sodium, bicarbonate and  sulfate; TDS content increases in the down-
stream direction.  Disproportionate increases in sulfate  content are observed
in the lower reaches  of both streams.  Uinta Bastn

     The oil shale deposits of the  eastern Uinta basin are drained by the
White River.  Most of the flow in the White comes from snowmelt in the Colorado
mountains.  Local streams contribute very little water to the  White.  Stream-
flow records for the White River near Watson, Utah show a mean discharge of
about 750 cubic feet per second.  Dissolved solids concentration ranges from
209 to 2380 mg/1 (24); the discharge-weighted mean is about 426 mg/1.

  Table  4-6.   Summary of Roan and Parachute Creek Streamflow Records (25)
Station Location
(Number refers
to Fig. 4-1)
W. Fork Parachute
Creek (9)
Parachute Creek
near Union
Operation (10)
Parachute Creek
near Grand Valley
Roan Creek above
Junction with
Clear Creek (12)
Clear Creek above
Junction with
Roan Creek (13)
Roan Creek near
De Beque (14)
of Record





(sq. miles)

m3/min (cfs)

Extremes of
fc W W




     Streams in the Ujnta basin, which originate in the area of the oil  shale
deposits* drain relatively low elevation watersheds.  Consequently, except
during periods of snowmelt or thunderstorms, local streams are dry or almost
dry.  Water quality of the local streams is generally poor.  Boron, hardness
and sulfate concentrations are high.  IDS content is highly variable as  a func-
tion of flow, and during late summer and autumn often exceeds 5000 mg/1  (31).

     Lease Tracts:  The existing surface water quality at the federal lease
tracts is summarized in Table 4r7.  Maximum dissolved solids levels have ex-
ceeded the proposed water quality criteria at all the lease tracts.  Fluoride
has exceeded drinking water standards at tracts C-a and C-b; boron has exceed-
ed agricultural standards at C-a.  However, in many cases, the data in Table
4-7 represent a small number of samples.  Mean annual discharges of Piceance
and Yellow Creeks into the White River are 14,520 and 1,130 acre feet, respec-

 4.2.2  Existing  Ground  Water Quality  and  Yields   Piceance Creek Basin

      t  Bedrock  Aquifers:  Two  bedrock  aquifer systems are  present  in the
 Uinta and Green  River formations  of the Piceance  Creek basin.   The  upper
 aquifer is present over the  entire  basin  and  is comprised of  the  fractured

Table 4-7.  Maximum Values for Dissolved Constituents of Surface Waters on
            and Around Federal Oil  Shale Lease Tracts (31,40,41)



Ban* urn
Cadmi urn
Nitrate as N
Fl uoride





Water Quality
i 500-1000 I(sH
12000-50001 (t)J
11. OM/
10. 2M J
Drinking Water
Regulations *












    1) Proposed Criteria for Water Quality,  Volume I,  October 1973,  U.S.
       Environmental  Protection Agency
    2) Federal  Register, Wednesday, December 24,  1975, Environmental  Protection
       Agency,  Water  Programs,  National  Interim Primary Drinking  Water Regula-
       tions Maximum  Contaminant Levels.
    3) Limits on fluoride depend upon  annual  average air temperature.   Allow-
       able fluoride  concentration range:  1.4 mg/1  @ 90.5F to 2.4 mg/1 @  be-
       low 53.70F.

    I = Irrigation  (t)  tolerant crops; (s) sensitive crops
    M = Municipal drinking water
    A = Aquatic life

 lean oil  shales of the Green River formation and overlying fractured marl-
 stones, siltstones and sandstones  of the  Uinta formation, above the Mahogany
 zone.  The lower aquifer consists  of fractured and leached oil shale below
 the Mahogany zone and is best developed in  the north central part of the basin
 where it is commonly called the "leached  zone."  The Mahogany zone appears to
 impede flow between the two aquifers over most of the basin.

      The total  amount of ground water in  the Piceance Creek basin has yet to
 be accurately determined.  However, the Department of Interior estimates that
 the basin may contain as much as 25 million acre feet of water in the upper
 aquifer (24).  Weichman estimates that the lower aquifer may contain as much
 as 25 billion cubic meters (20 million acre-feet) of water  (28).

      Ground water movement in the  basin parallels surface stream flow.  North
 of the topographic divide that separates  the Piceance-Yellow Creek and Para-
 chute-Roan Creek drainages, surface and groundwater movement is to the north.
 South of this divide, ground water movement is toward the south.

      Most of the aquifer system recharge  comes from melting of the heavy snow-
 pack found at higher elevations around the  margin of the basin.  In these re-
 charge areas water percolates downward into the upper aquifer through the
 Mahogany zone and into the lower aquifer  charging both aquifers.  The ground
 water then moves laterally to the  discharge areas.

      In the  northern  part of  the basin, water moves upward from the lower
aquifer through  the Mahogany  zone and into the upper aquifer,  and is  then dis-
charged into the alluvium of  Piceance and Yellow Creeks,  ultimately reaching
the surface.  At the  southern margin of the basin, most of the water is  dis-
charged by springs along  the  sinuous line of cliffs near the top of the  Mahog-
any zone.

      Using limited hydrologic data obtained from test wells, the USGS and
 others have made model studies of  the hydrologic system of  the Piceance Creek
 basin to estimate the quantity of  water that will be produced in conjunction
 with mine dewatering, and to determine the  effects of dewatering on the sur-
 face and subsurface hydrologic regimes.   It is estimated that in the northern
 part of the basin, discharge rates of more  than 1.7 m3 (50  ft3) per second may
 be required to keep the mine workings dry (23,30). The net  result of this water
 removal  over a period of years will be to locally reduce spring and streamflow.
 In the southern margin of the basin, the  quantity of water  produced by dewater-
 ing will  be considerably smaller by comparison and the effects will be more

      Although the chemical quality of the groundwater in the Piceance Creek
 basin varies widely,  both the upper and lower aquifers can  be classified as
 containing  sodium bicarbonate type water, and the concentration of dissolved
 solids generally increases in the  direction of flow.

      In the  recharge areas, the dissolved  solids  content of upper aquifer
waters average about 500 mg/1.  At the northern discharge area the dissolved

solids content of upper aquifer water averages  about  2000 mg/1.  At  the  south-
ern discharge areas, the dissolved solids content of  the upper aquifer aver-
ages about 1000 mg/1.  Fluoride content of the  upper  aquifer  often exceeds  10
mg/1 in the northern part of the basin; but averages  less than 0.5 mg/1  at  the
southern margin.

     The dissolved solids content of the lower aquifer increases both with
depth and in the direction of flow.  In the recharge area  the dissolved solids
concentration of the lower aquifer is of the order of 1000  mg/1.  This in-
creases to more than 30,000 mg/1 at the discharge area at  the northern margin
of  the basin.   In individual wells in the north central part of the basin,
the dissolved solids content of water taken near the top of the lower aquifer
is  as low as 2000 mg/1 while in samples taken near the base of the "leached
zone" the dissolved solids content is more than 80,000 mg/1.   The ground water
in  the lower aquifer contains exceptionally high concentrations of dissolved
fluoride, with  an average level of nearly 10 times the recommended value for
most uses.  The areal distribution of fluoride has no discernible pattern.

       Alluvial Aquifers:  The alluvial aquifers in the Piceance Creek basin
are limited to  valley bottoms along creeks.  These aquifers are generally less
than  .8 KM (0.5 mile) in width and less  than 43 M (140 feet) thick.  Although
the alluvium is capable of transmitting  and storing more water  per unit
volume than the bedrock aquifers, the areal extent is  small.  Consequently,
high discharge  rates can only be maintained briefly.   Water  1n  the alluvium
occurs both under water-table and artesian conditions, depending upon the
occurrence of clay  beds.

     The alluvial aquifers are recharged by precipitation,  applied surface
water, streams  and infiltration from bedrock aquifers.  The aquifer discharges
to  streams, springs, and wells and to the atmosphere by evapotranspiration.

     Water in the alluvium has about the same chemical character as water in
the stream, but usually exhibits a higher dissolved solids  concentration.
Along Piceance  Creek, dissolved solids content ranges from less than 500 to
more than 8000  mg/1.  Water in the alluvium of Yellow Creek and Parachute
Creek includes   calcium, magnesium, sodium, bicarbonate and sulfate.  The
dissolved solids concentration of the water is sometimes as much as 7200 mg/1.
The sulfate concentration of a water sample near the mouth of Roan Creek was
4200 mg/1 (25).

      Table 4-8  summarizes the groundwater  quality data which have been col-
lected at  lease tracts  C-a and  C-b.  Dissolved solids, fluoride, and boron
levels  in  the  lower aquifers exceed water  quality criteria and/or drinking
water standards at  both tracts.   Boron  and copper in  the alluvial aquifer at
tract C-a exceed irrigation standards  while cadmium  and lead exceed drinking
water standards.  The data  in Table 4-8 represent a  limited  number of analyses
for many constituents,  and may  not be  completely representative.

    Table 4-8.  Mean Values for Dissolved Constituents in Groundwater on Federal Oil Shale Lease Tracts
                C-a and C-b (15,17,40)
Water c"a
Parameter Units Quality Criteria1 Alluvial Aquifer 011 Shale Aquifers

Dissolved mg/1 500-1000 I(s)
Solids 2000-5000 l(t)
Boron mg/1 0.5 I
Copper mg/1 0.2 I
1.0 H
Cyanide mg/1 0.005 A
mg/1 0.2 M
Water Regulations2
Arsenic mg/1 0.05
Barium mg/1 1.0
Cadmium mg/1 0.010
Chromium mg/1 0.05
Lead mg/1 0.05
Mercury mg/1 0.002
Nitrate as N mg/1 10.
Selenium mg/1 0.01
Silver mg/1 0.05
Fluoride mg/1 (3)
1. Proposed Criteria for Hater Quality, Volume



I. October 1973, U
2. Federal Register, Wednesday, December 24, 1975, Environmental
Water Regs, Maximum Contaminant Levels

3. Limits on fluoride depend upon annual average air temperature.
to 2.4 mg/1 0 below 53.7oF.
I  Irrigation (t) tolerant crops; (s) sensitive
M  Municipal drinking water
A - Aquatic life
*Mean chemical concentration based on swab tests


Upper Lower
1140.000 1550.000

.692 1.830
.027 .018
.027 .018
.000 .005
.000 .005

.004 .001
.000 .000
.002 .001
.005 .000
.353 .647
.000 .000
.534 .765
.000 .000
.007 .003
4.090 13.700
Alluvial Aquifer 011 Shale Aquifers









.S. Environmental Protection Agency.
Protection AGency, Water Programs, National

Allowable fluoride

concentration range: 1

Interim Drinking

.4 mg/1 3


of saturated sequence In question.

-------  Uinta  Basin

      Little  information  is  available on  the ground water hydrology of the
 Uinta basin.  Hydrologic test  information from a few scattered wells indicate
 that groundwater  can  be  found  in  the sandstone and si Itstone beds above and
 below the oil shale and  within fractures of the oil shale.  However, based
 on  current data,  it is unlikely that any of the aquifers contain significant
 amounts of water.

      The  Green River formation  probably contains more water than any other
 formation  in the Uinta basin.   Several  aquifers have been identified in
 test  wells, but the lateral extent of these zones has yet to be determined.
 Hydrologic investigations in connection with the U-a and U-b baseline
 studies have established the presence of an aquifer about 100 feet thick
 lying about 350 feet above the  Mahogany zone (21).  The aquifer crops out along
 the White  River and Evacuation  Creek and extends an undetermined distance
 northwestward beyond the tract  boundaries.  The aquifer is recharged along
 the outcrop; the discharge area is not known.  Ground water movement is to
 the northwest.  Pump tests run  in 4 holes yielded from 18-6500 liters (5 to
 1750  gallons) of water per minute, with dissolved solids content of the pro-
 duced water ranging from 1000  to 3500 mg/1 (31).  Elsewhere in the basin, the
 Green River  formation has yielded only small  quantities of water with up  to
 72,000 mg/1  dissolved solids content.

 4.2.3  Effects of Water Withdrawal by Oil Shale Development on the White and
        Colorado Rivers

      One estimate of the total   supply of surface water available to the  oil
 shale developments is estimated at 526 million m3 (427,000 acre-ft) per  year
 (13). This supply of water would be derived primarily from two river basins,
 the White River and the Colorado River.   The major potential  developments  that
 may utilize water from the White River basin are:   Colorado federal oil  shale
 lease tracts C-a and C-b, Utah  federal  oil  shale lease tracts U-a and U-b,
TOSCO (sand wash), and Superior Oil  Company.   The developments that will
 likely obtain thefr water from the Colorado River Basin are:   Occidental Oil
Company (modified in-sttu development},  Colony CTOSCO II)  development, Union
Oil  Company of California and the Paraho  Gas Combustion demonstration plant at
Anvil Points near Rifle,  Colorado.

      Although the exact water requirement for each of these developments at
 their full scale operation is uncertain at the present time,  it has been esti-
mated that for every cubic meter of oil  produced,  an approximate average of
 3.7 cubic meters of water will  be required (see Section 3.2.1).  If this
 approximation is realistic, then surface water might support an oil shale in-
 dustry  producing about 390,000 m3/day (2.4 million barrels/day) of shale oil.
However, the shale industry will Rave to compete with agriculture,  mining, In-
dustry, and urban users for this surface water.

      Some of the water requirements for development will  be met by ground-
water sources in the Piceance Basin.  Deeper aquifer water may be considered
 "geologic" water and its withdrawal  for consumptive use may have little  or


?n! I   I*        ace   WS'  However shallow aquifer water withdrawal for
mine dewatering  purposes and process needs will likely diminish local  surface
flows,  and  ultimately, the  flows  in the White and Colorado Rivers.  For the
nrst phases  of  oil shale development, lease tracts C-a and C-b, Superior Oil
Company will  use entirely or primarily groundwater to supply process needs.
The extent  to which surface water must supplement groundwater for expanded
operations  is not known at  present.

     One effect  of withdrawing water from the White and/or Colorado Rivers is
a potential salinity  increase downstream.  Since the White River merges with
the Green River  and ultimately the Colorado River, the effects of increased
salinity will be seen at downstream reservoirs on the Colorado River (e.g.,
Hoover  or Imperial Dam).  In general, salinity of the water will increase
progressively from the head waters to the lower reaches of the Colorado River.
Two factors contribute to increased salinity:  (1) increased salt loading, and
(2) salt concentration.  Salt loading is caused by both natural and manmade
sources  which contribute salts to the rivers.  Salt concentrating effects are
produced by removing  and consuming relatively high quality water or by eva-
poration in reservoirs and  in irrigation systems, thereby concentrating salts
into a  lesser volume  of water.

     Several  estimates have been  made of the effects of individual oil shale
development projects  on the salinity in the Colorado River.  Results of these
estimates indicate that the salinity increase due to the individual with-
drawals  in no case exceeds  7.0 mg/1  of total  dissolved solids at Imperial  Dam
(13).   One estimate for a 40,000 m3/day (250,000 bbl/day) oil shale industry
shows  a  salinity  increase of 1.0 mg/1  at Hoover Dam (14).  According to the
final  EIS of the  Department of Interior for a prototype oil  shale leasing pro-
gram,  the salinity at Hoover Dam will  increase by about 10 to 15 mg/1  for a
1,000,000 bbl/day (160,000 m3/day) oil  shale industry requiring 149 million m3
(121,000 acre-ft) to 233 million m3 (189,000 acre-ft) of water per year (24).

     It is  possible that certain  oil shale withdrawals may actually enhance
water quality in the  Colorado system by consuming high dissolved solids water
which would otherwise reach surface waters.  Consumptive use of Piceance Creek
water (for example, by Superior Oil Company  in the Northern Piceance Basin)
may improve the  quality of  the White River below its confluence with Piceance
Creek.   (Tables  4-4 and 4-7 show  the approximate dissolved solids levels for
the White River  and for Piceance  Creek near  tract C-b, respectively).  The
Rio Blanco oil shale  project (tract C-a) has indicated that oil shale develop-
ment on that  tract will actually  cause a decrease in salinity in the lower
Colorado system  via use of  saltne groundwater which would otherwise reach the
White River (see Table 4-8  and Reference 17).

    Based on  the above estimates, salinity increase due to consumptive with-
drawal  for oil shale  development  is expected to have minimum impact on exist-
ing water users  (including  municipal, industrial, agricultural, hydroelectric,
recreational  users).  More  significant water Quality impacts on either the
White or the  Colorado Rivers may  result from (1) uncontrolled leachate reach-
ing groundwater  or draining into  surface streams leading to the rivers and
(2) failure of holding ponds or disposal pile.  A discussion of these poten-
tial impacts  may be found in other sections of this report.


4.2.4  Effects of Development on Local  Surface and Groundwater

    All of the proposed programs for oil  shale development announced to date
have set forth a policy of no direct discharge of wastewaters during commer-
cial operations.  However, even if this policy is strictly followed, other
potential sources of pollution may exist.  Some activities, which have no
effluent products, may indirectly affect water quality.   Accidents may also
cause the release contaminates into the ground or surface waters.

    Water can be indirectly contaminated by activities which unbalance the
existing hydrologic regime.  Water can  also be indirectly contaminated by the
failure of systems designed to contain  or confine direct effluents.  Acci-
dental  leaks, spills, and dam overflows may contaminate  surface streams.

    Most of the activities that could cause or lead to indirect water pollu-
tion are common to several or all  of the  proposed developments.  These non-
site specific activities along with the proposed plan for mitigating water
quality degradation are discussed below.   Site specific  activities and pro-
posed mitigation plans are discussed in the succeeding section.  Accidental
sources of water pollution and control  plans are discussed in the last section.

    General Indirect Water Pollution Sources and Control Plans (1,2,17,24)

       Construct!'on Activities:  Irrespective of location, construction acti-
vities will be a necessary part of all  oil shale developments.  Construction
activities include the development of the mine and plant sites, establishment
of the processed shale and overburden disposal areas, development of ore stock-
piles, upgrading of existing roads, and construction of  new roads, service
corridors, dams, reservoirs, etc.  The  major effects of  these landscape modi-
fications will be to increase runoff which will, in turn, lead to increased
erosion and sediment load in local streams.  Concentration of dissolved solids
in the runoff may also be higher than that from undisturbed terrain, depending
upon the nature and properties of the surfaces that are  exposed.

    In order to prevent runoff waters from modified land surfaces from enter-
ing streams, dams will be built downstream of the construction activities.
The waters collected by these structures  will be used on site.  Other water
control structures will be built to prevent erosion and  control sedimentation
as needed.  In general, stream sediment load and siHation will be minimized
by disturbing vegetation and soil as little as possible  by contour grading
and by installing catchment basins and initiating restoration activities as
soon as feasible.

       Mining Activities:  The mining  of oil shale can  indirectly affect
water quality in several ways.  Mining will necessitate  dewatering when opera-
tions make contact with the aquifer.  Dewatering has two important aspects:
(1) groundwater produced by the dewatering could pollute streams if not con-
trolled and (2) dewatering could reduce or dry up spring and stream flow.
Also, subsidence of underground workings is a threat to  the surface and sub-
surface waters.  Rupturing of strata that naturally impedes vertical flow

 could allow poor quality water to reach the  surface.  Subsidence of the land
 surface would alter stream course and increase  sediment and dissolved solids

      Proposed  development plans indicate that during full-scale operations, all
water from  dewatering  operations  (supplemented by water from outside  sources)
will  be  utilized  in  processing and for  retorted shale disposal.  During pre-
commercial  development,  however,  surplus water may be obtained from the de-
watertng operations.   Depending upon amounts and location, several  techniques
will  be  used to handle this surplus water.  These include:  (1) storage  with
eventual  later on-site reuse,  (2) treatment to stream water quality standards
and release, (3)  use in  construction, and (4) reinjection into the aquifers.

     Because dewatering may diminish or dry up spring or stream flow, natural
surface water augmentation is planned where necessary.  Several  options  are
available for providing this water such as:   (1) release of supplemental water
from upstream sources  through natural stream channels,  (2) additional develop-
ment of groundwater sources, and  (3) haulage, pipelines, or canals.

     The effects of subsidence on surface and subsurface water quality are  not
 fully understood at this time.  Consequently, underground workings  have been
 designed to minimize  subsidence.

        Processing Activities:   Processing produces a variety of waste mater-
 ials that  potentially could degrade water quality.  The  sources and character-
 istics of  these solid and liquid wastes and plans for their disposal  so as to
 prevent effluent discharge from  directly entering surface waters are described
 in previous sections  of this report (Sections 3-2 and 3-3).  Generally, pro-
 cess wastewaters are  not planned to be directly discharged.  During plant  up-
 sets or accidental equipment failure, process wastewaters may be directly  dis-
 charged to surface waters.

     t   Retorted Shale Disposal:  Contamination of surface and groundwaters
 by salts,  organic substances and trace constituents can  occur as a result  of
 erosion of, runoff from, and percolation through retorted shale.  Such con-
 tamination may adversely affect  the quality of water from other uses in the
 upper Colorado Basin  (e.g., Irrigation) and add to the salt loading of the
 lower Colorado Basin.

      Like natural terrain, a disposal pile will be subject to surface  erosion
 and runoff during storms and snowmelt.  Soluble substances, particularly in-
 organic salts can be  mobilized from retorted shale along  with suspended mater-
 ial during the erosional process.  About 10 kg/tonne (20  Ibs/ton)  of salt
 (primarily sodium sulfate) is water  soluble in fresh, carbonaceous retorted
 shales  (Table 3-14).  Burned shales may contain larger quantities  of soluble
 salts.  Further, additional soluble substances are added  to retorted shale in
 the form of process water (about 1 kg soluble salts/tonne of processed shale
      Natural erosion  in the Piceance Creek basin averages about 7 tonnes/
 hectare/year  (3 tons/acre/year), although wide variations occur as a function
 of slope,  storm frequency and intensity, vegetative cover, and properties  of


 the  local  soils (44).  Retorted shale subject to  "average erosion" in the
 Piceance  basin might contribute 70 kg  (150 Ibs)  of salt along with 7 tonnes
 per  hectare of suspended material to surface waters annually.

     Although retorted shales have low permeability (Table 3-13), water has
 been shown to penetrate into retorted shale piles (43).  Winter freeze-thaw
 cycles can significantly reduce  compaction  densities, creating greater per-
 meability  in the upper portion (! meter) of a pile than was originally the

     Water will be normally applied to the surface of a disposal pile as part
 of the revegetation  program (to supply water requirements of vegetation and
 to leach soluble salts to below the root zones).  Such water applications en-
 courage the establishment of capillary structure in TOSCO II retorted shale
 which allows both upward and downward migration of water.  Salty deposits
 (mainly sodium and calcium sulfate) are occasionally observed as a thin crust
 on the surface of disposal piles between irrigation applications, particularly
 during hot weather when surface evaporation is high.  These salty deposits
 will be partially dissolved by rain or snow and will add to the salt load of
 surface runoff.

     Salts may also  be solubilized by water percolating through retorted shale.
 Laboratory experiments have demonstrated that less salt is generally Teachable
 from freshly retorted TOSCO II in percolation tests than in "blender" or
 "bottle" tests.  The hydrophobic nature of carbonaceous retorted shale is
 thought to encourage channeling and inhibit thorough water-shale contact in
 the  percolation tests.  If TOSCO II retorted shale is wetted and then allowed
 to dry, a  capillary  structure is established which allows a more complete
 re-wetting at a later time.  Upon prolonged water saturation, carbonaceous
 retorted shale  loses some of its hydrophobic properties.

     TOSCO II retorted shale can apparently allow percolation of water to
 occur, even when the pile is under-saturated with water.   Freeze-thaw induced
 permeability increases in the surface layer of a pile over time, and the
 ability of the shale to allow downward water migration may contribute to deep
 water infiltration and capillary structure development (42). Water migrating
 through a  pile can continue to dissolve salts until a concentration of about
 1400 mg/1  is attained  in the interstitial solution.  Percolate water, with a
 steady state dissolved solids content, may eventually mix with other ground-
 water, and/or reach surface waters.

     Burned shales  (e.g.,  gas  combustion  retorting) have  little or no carbon-
aceous  coating,  and carbonate  minerals  have  been partially calcined.   Such
shales  are less  hydrophobic than  TOSCO  II retorted shale, and contain salts  in
a more  readily soluble form (42,43).   Although  fewer runoff and infiltration
 experiments have been conducted with burned shales than with TOSCO II shale,
 the  results indicated that salts can be leached to below the root zone of
 most plants by repeated application of water to pile surfaces.  Commonly, a
 cemented zone is established about 1-2 meters down after repeated water appli-
 cations (37). This zone greatly reduces pile permeability and inhibits further
 downward migration of water.  During the leaching process and the establish-
 ment of the cemented zone, runoff and any percolate waters will contain large
 amounts of dissolved salts.


     In addition to the potential for mobilizing common inorganic  ions  from
retorted shales, water running off of or migrating through a  disposal pile
may dissolve organic and trace inorganic constituents.   Other solid  and liquid
wastes likely to be contained in a disposal  pile (Sections 3.2 and 3.3) in-
clude process wastewaters, oily sludges, spent catalysts,  and shale  coke.
Water  contacting such materials may dissolve toxic or  carcinogenic  organic
substances  (phenolics, organic acids, POM) and hazardous trace elements
(arsenic, nickel, molybedum, chromium).  Since small scale  experiments conduc-
ted to date have generally not included materials other than  retorted shale,
the potential for waterbornetransport of suspended or dissolved substances  de-
rived from  the above mentioned wastes is largely speculative.

     Salts  and other soluble substances, and suspended  solids mobilized by
water  contacting retorted shale can be potentially controlled or  contained.
Minimizing  pile slopes, constructing drainage systems,  and providing impound-
ments below disposal areas can in principle decrease the extraction of  salts,
etc., and contain those which are extracted.  Some of the site specific plans
for such control are discussed in section 4.3.  Despite controls,  however,
some runoff and percolate waters  may eventually reach  other  ground and sur-
face waters.  Actual effects such as the salt loading of surface waters, will
depend on a number of factors, including storm intensity and  frequency, snow-
fall rates, distance which leachate waters must travel  to reach groundwater
or a surface water interface, and the rate of groundwater movement.   Ground-
water in the Piceance basin is thought to ultimately discharge into the  alluv-
ium of Piceance and Yellow Creeks in the northern part of the basin (Section
4.2.2).  Movement of groundwater may be slow on the average,  but periodic
storm runoff and stream discharge may periodically flush salts into the White
and Colorado River systems  (indeed this is probably occuring  naturally  at
present (44)).
        Pollution Control Activities:  The attempt to contain wastewaters may
create an indirect source of water pollution.  Leakage of poor quality water
from impoundments is possible if the bottoms or dams of these impoundments
are permeated.   Eventual return  of any of these contaminated waters to the
surface through  springs or baseflow would pollute  streams in the area.

        Infiltration of poor quality water from dams and reservoirs can be
controlled  in several ways.  Reservoirs and other water control structures
can be lined with impermeable material.  Poor quality water that infiltrates
into the groundwater system can  be partially recaptured by shallow wells.
If the reservoir is within the area of significant drawdown caused by mine
dewatering, infiltrates may be collected by the mine dewatering system.

    Site Specific Indirect Uater  Pollution Sources  and  Control  Plans

    Variations in hydrology over the Piceance and Uinta Basins coupled  with
differing proposed methods of development create unique indirect sources of
pollution.  These are discussed below along  with proposed control  methods.

    The Superior Oil  Company lands are located at the northern margin of the
basin near the junction of Piceance Creek and the White River (Figure 4-1).


 It  is Superior's  Intention to mine oil shale and associated sodium and
 aluminum minerals from the lower oil shale zone of the Green River For-
 mation.  As the proposed mine zone is below the lower aquifer and 1s
 indicated to be dry, dewatering of the mine zone may be unnecessary.
 Superior proposes to dispose of the processed shale in the m1ned-out zones,
 which may constitute an Indirect source of pollution, however.  Eventual
 percolation of groundwater through the underground processed shale disposal
 area could contaminate surface and groundwater of the area.  However, it
 is  envisioned that this would be controlled by compacting the processed
 shale to render it impermeable or by sealing off the mined-out areas with
 barrier pillars.

    Superior intends to use groundwater from the lower aquifer as the princi-
 pal source of process water.   This may reduce spring and streamflow in the
 area.  However, as the spring and creek water in this  part of the basin have
 a high dissolved solids content, this  may actually Improve water quality in
 the White River.   If necessary,  Superior intends to augment any water lost to
 the stream system as a result of their activities  via  release of purified
 process water (condensed process steam).

    Tract C-a is located in the  headwaters of Yellow Creek near the western
 margin of the basin (Figure 4-1).   Stream water  quality in this area is
 generally good.  Both the upper  and lower aquifers are moderately well-devel-
 oped in the vicinity of the tract and  contain water in the order of 1300 mg/1
 total dissolved solids with high fluoride content  (Table 4-8).

    The open pit mine contemplated for Tract C-a would remove the strata that
 presently restricts vertical  movement  of waters.   As long as the pit is kept
dry this would not create a problem.   However,  if  the  dewatering operation is
 permanently halted, the pit may  fill with poor quality groundwater.   It is
 possible that such groundwater could enter surface streams.

    In order to prevent stream pollution, the pit  could be lined with a layer
of impermeable material  or semi-impermeable retorted shale.   Total  backfilling
or grouting is another option.   A third option is  to continue dewatering
operations in perpetuity.

    Tract C-b is located in the  southcentral  part  of the Piceance basin.  In
this area surface water has a TDS content of about 1000 mg/1; fluoride content
is moderate.   Both the upper and lower aquifers  are reasonably well-developed
in this area.   The TDS concentration of the water  in both aquifers is about
the same as the stream but fluoride content is higher  (Tables 4-7 and 4-8).

    Sprinkler irrigation and reinjection are two methods proposed for disposal
of surplus mine water during construction.  Both these methods could indirectly
pollute ground and surface waters.

    Evapotranspiration of high TDS and fluoride  content water from the sprink-
 ler system will build up salts in the  soil that could  be carried into the sub-
 surface during periods of high precipitation.  Eventual  return of any of these

contaminated waters to the surface through springs or baseflow  would  pollute
streams in the area.  Sprinkler irrigation would be used only in the area that
is to be later occupied by the processed shale pile.

    Data are insufficient to predict the total effects of  reinjection  on  the
hydrologic regime.  However, if the water is reinjected into the  same  aquifer
from which it came (as proposed), the potential  for pollution is  substantially
reduced.  Because the injected water will be later withdrawn as part of the
dewatering scheme, the reinjection program may be  considered as temporary stor-
age rather than a permanent solution of the water  disposal  problem.

    The present  Occidental  Oil  Company operation is located in  an oil  shale
outcrop area at  the southern margin of the Piceance basin.   Streamflow in
this area only occurs during spring snowmelt and during thunderstorms.  Limit-
ed amounts of groundwater are present in the upper aquifer; the lower aquifer
is very poorly developed in this area.

    Although Occidental proposes to develop the oil shale by in-situ methods,
many of the water pollution problems associated with processed  shale disposal
are the same as  for surface projects.  Surface or ground water  may percolate
through the underground processed shale  pile and become polluted.  If this
water is allowed to reach the streams in the area, severe water pollution
and/or degradation may result.

    It is assumed that a water  retention facility will be built so as to col-
lect any water that has filtered through the underground retort.   This water
could eventually be reused  in the processing and mining operation.

    The White River Oil Shale Project proposes to obtain water for development
as tracts U-a and U-b from  the  White River.  A dam has been proposed as a
joint project of the state  of Utah, the  Ute Indians, and the Uinta Water Con-
servation District, to have a total dead storage capacity of 145 million m3
(118,000 acre-feet) at completion.  The  impacts of dams on water quality in
the arid west include evaporative losses (and salt concentrating effects),
the deposition of sediment, erosion and dissolutionof bank material, the crea-
tion of new groundwater systems, and changes in downstream temperature regime
and erosion potential.  These and other potential  impacts are not unique to
the proposed White River dam, nor unique to oil shale development.

     Accidental  Sources of  Water Pollution and Control Plans

     Accidental  sources of  water pollution are the result of catastrophic
events.  These include dam  failure and accidental spills of oil or other
hazardous materials.  Since spill contingency plans  for oil and other  hazard-
ous materials must be submitted to the federal government and  such plans are
now in operation throughout the oil and  chemical  industries, no further dis-
cussion of this  subject is  included.  The probability of sudden and complete
dam failure, while remote,  warrants further discussion, however.

     Leachate from freshly  retorted shale tests have a maximum TDS content
of about 1400 ma/1 (42)  More typical concentrations of runoff waters  are in-
dlcSd to be about 20 percent  of this value (1).  While the quality of waters


retained below processed shale embankments is highly variable depending  upon
dilution and evaporation, it appears that the TDS level  of leacbate water
itself may be approximately the same as streams in the oil shale area.   How-
ever, organic and trace inorganic constituents could be higher in leachate
waters than in the streams.

     Sudden dam failure would release the stored processed shale runoff  and
leachate water into the streams.   Because the 70S of the stored water may not
be dramatically greater than that of stream waters,  dissolved solids content
of the latter would not necessarily increase.  Since  the concentration of
trace organic and inorganic constituents has not been quantified, it is  pre-
sently not possible to determine the effects of these substances on water
quality.  Studies are in progress to determine the levels of trace materials
in runoff and leachate from processed shale (1).

     Sudden dam failure would send large quantities  of water at high velocities
along the stream channels.  Extensive damage to the  stream system in the form
of erosion and siltation could occur.  Suspended sediment levels would be in-
creased both during and subsequent to the flood.  Dwellings and other struc-
tures might be inundated.  Much of the aquatic habitat and life could be de-
stroyed.  Damage and destruction caused by failure of a processed shale  water
retention dam would be similar to that caused by flash flooding of the same
magnitude anywhere.


     Solid waste streams are the largest by mass and volume  of any waste
streams encountered in the extraction and processing of oil  shale.   The bulk
of these wastes are processed shale, raw shale fines, and dusts (as  sludges)
collected during processing.  In addition, spent catalysts from shale  oil  up-
grading operations, and sludges from plant water and wastewater treatment  con-
tribute to solid wastes requiring disposal.  Also,  retorted  shale will commonly
serve as the repository for process wastewaters which are used for moisturizing
and compacting purposes.  The sources and characteristics of solid and aqueous
wastes were reviewed in Sections 3.2 and 3.3.  This chapter  is a review of
solid waste disposal plans proposed by major oil shale developers.   A  discus-
sion-of the potential physical and vegetative stability of disposal  piles  and
of solid wastes as an intermedia source of air and  water pollutants  is included.

4.3.1  Solid Waste Disposal Plans for Oil Shale Development

     The developers of private oil shale lands (e.g., Colony, Union, Superior,
Occidental) and of the federal lease tract lands (RBOSP-C-a, Roxana-C-b,  and
WROSP-U-a/U-b) have presented plans at varying levels of detail for  handling,
disposal, and stabilization of solid wastes from commercial  operations.   This
section summarizes these plans and the physical setting of individual  sites
proposed for the disposal of wastes.  All of the plans discussed below have
the objective of creating a stable disposal pile, suitably contoured and  reve-
getated, with provision for protection against leaching of substances  into
ground and runoff waters.

     Colony (1):  The Colony Development Operation has selected a canyon-type
disposal site in Davis Gulch, near the Middle Fork  of East Parachute Creek,
in the northwest corner of the Dow West property.  A schematic of the  800
acre disposal site is shown in Figure 4-2.  An estimated 363 million tonnes
(400 million tons) of waste will be placed in Davis Gulch and its side drain-
ages during the first 20 years of Colony's planned  plant operations.

     Placement will be by means of 150 ton dump trucks spreading a  layer  45 cm
(18 inches) deep across the fill at one time.  This will be  followed by com-
paction to either 1360 kg/cu. meter (85 Ibs/cu.ft.) in the pile interior  or
1520 kg/cu. meter (95 Ibs/cu.ft.) on frontal slopes, using a 12% average  pile
moisture content.  A drainage system will be provided, together with a catch-
ment basin and dam.

     After final contours are established, contained salts in the top  of  the
pile will be leached down into the pile, a 15 cm (6.0 inch)  layer of topsoil
added, and a revegetation program initiated.  The latter will include  the re-
quisite chemical fertilization and irrigation over a period  of several years
to insure a stable, self-sufficient soil cover of about 45%  grasses, 40%
shrubs, and 15% forbs.

     Tract C-b (2):  The Roxana group (Ashland, Shell), which holds  the federal
lease of Tract C-b, intends to use TOSCO II retorting technology, and  would
therefore produce a processed shale and associated  wastes similar to those de-
scribed previously for the TOSCO II process (Section 3.3).  The lessees would


                          12345678     9         10
Figure 4.2.
Aerial  View  of  Colony  Development Operation Disposal
Site  -  Davis-Gulch  (located  at the  upper  reach of
Parachute  Creek,  Colorado) (1)

prefer off-tract disposal of spent shale south of Tract C-b,  but this  currently
is not likely for legal reasons.  For on-tract disposal, a site in  Sorghum 
Gulch has therefore been selected.

     The disposal pile will eventually encompass some 486 hectares  (1200 acres)
after 20 years of plant production in an area over two miles  long and  over
one-half mile wide, and have a pile height of 61 meters (200  ft).  Processed
shale will be produced at the rate of 49,000 tonnes (54,000 tons) per  day
(dry basis), or a total of 335 million tonnes (370 million tons) over  the
first 20 years.  Disposal compaction procedures and provisions for  runoff will
be similar to those described for the Colony Operation.
     Tract C-a
     	JRBOSP) (17): Open pit extraction of oil shale for processing
at Tract C-a will create  several types of solid wastes requiring disposal.
In addition to  the  processing wastes (retorted shale, catalysts, etc.), mar-
ginal quality oil shale (sub-ore), overburden rock, and soil material will
require handling, relocation and/or disposal.

     RBOSP indicates that materials removed from the open pit must be placed
outside the pit for the first 2 phases of operation (about 30 years) so that
maximum resource recovery from the tract can be realized and rehandling of
material can be minimized.  During Phase I operations, RBOSP proposes to dis-
pose of overburden, sub-ore, and TOSCO II retorted shale at a site north of
Tract C-a called "84 mesa".  Figure 4-3  shows the proposed disposal location
and a side view of  the pile as envisioned.

     The 144 hectare (355 acre) disposal area of Phase I will be segregated
into sections containing  soil, overburden, processed shale, and sub-ore.
This segregation allows for later use of soil in revegetation operations, and
potential recovery  of sub-ore should it become economic.  The top soil (and
sub-soil) will  be stripped  from both the pit on Tract C-a and the disposal
site on 84 mesa.  RBOSP intends to use freshly stripped topsoil where possible
to facilitate revegetation  of disposal pile surfaces.

     During Phase II, the disposal area will be expanded east and north to
accommodate expanded solid  waste generation on the tract (Figure 4-4 ).  The
nature of the wastes will change, since GCR retorting as well as TOSCO II re-
torting is envisioned.  As  in Phase I, overburden, sub-ore, processed shale,
and topsoil will be segregated.  All processed shale will be compacted as it
is laid down, and exterior  slopes of 4:1 will be established.  An artificial
soil profile, using freshly stripped topsoil where possible, will be placed
on final surfaces.  During  Phase II, about 111,000 tonnes (120,000 tons) of
moisturized process shale will be produced daily.  At the end of Phase II the
total volume of compacted processed shale and sub-ore/overburden will amount
to 700 million  cubic meters (915 million cubic yards) and 450 million cubic
meters (593 million cubic yards), respectively.

     Surface runoff from  the pile will be collected by ditches around the pile
perimeter.  The outside of  the shale pile will be highly compacted so as to
minimize potential infiltration into the pile (with subsequent leaching).  All
runoff and possible leachate waters will be diverted to a lined collection

                                                        f%^ V^
                                                                                   rs'  /vs
                                                                                   i  i ^ f
                            r'tttUsff r y/^ -^-^F^JP**^
                                                                     woiaiTi:iiMt  snanri tiuii
              ,-v, r^ '*?
              ^ '/
                                              '"-^'^l"  ' ^^'4 ,"-
                  Figure 4-3.  Tract C-a  Conceptual  Phase I Solid Waste Disposal  Plan (17)

                   "3 /""'jjii^ As?>>
                   /A  <";.kvJr\ &*>,-.
                    l\Jr .:.  i^>-! i^T ... .- 
                                                             ' '  /'), rV .>/-
                                                             	^\ti^ "-*://  .-\

                     Figure 4-4.   Tract C-a Conceptual Phase II Solid Waste Disposal  Plan  (17)

                                                    '   SHALE
                                                ELEV. 6200' (5 YEARS)
                          -SLURRY TRENCH
Figure  4-5.    Schematic of Union Oil  Company Retorted Shale Disposal Plan for Operations
               at Parachute Creek Site (45)

                           evaporate or be later used fr d"st control or com-
                  The 9,000 tonnes (10,000 tons) per day modular plant proposed
 by  Union  Oil  Company to  be constructed on its land in Parachute Creek, will
 produce some  7,600 tonnes  (8,360  tons) of retorted shale (dry basis) daily.
 This  is approximately  2.8 million tonnes (3.1 million tons) per year, or 14
 million tonnes  (12.7 million  tons) over the expected five years of operation
 of  the  modular  plant.

      Retorted shale  from the  processing plant at 2130 meter (7000 ft.)  eleva-
 tion  will be conveyed downward through an ore pass to the 2010 meter (6,600
 foot)level (see Figure 4-5),  loaded into trucks, and transported to a dis-
 posal area in East Parachute  Creek canyon.  Here, it will be deposited in
 windrows  up the south embankment  of the canyon and compacted to a density of
 1,440 kg/cu. meter (90 Ibs/cu.ft.).

      Runoff from  the disposal pile will be caught in a leachate collection
 ditch at  the top  of  the  embankment.  The East Fork of Parachute Creek will be
 re-routed around  the embankment through a by-pass ditch.

      If a full-scale commercial plant is later constructed by Union Oil it
would produce some 47,000 tonnes  (52,000 tons) of spent shale per day, or 15.5
million tons per  330 day stream year.

      Tract U-a, U-b:(51)  The joint development of Tracts U-a and U-b is in-
 tended  to proceed through an  initial modular plant stage with a throughput of
 9,100 tonnes  (10,000 tons) of raw shale per day, to a first commercial plant
 processing 72,500 tonnes (80,000  tons) per day, and finally to a projected
 plant handling 145,000 tonnes (160,000 tons) of shale per day.  The latter
 plant will produce some  118,000 tonnes (130,000 tons) of processed shale daily
or approximately  39  million tonnes (43 million tons) per stream year.

      It is currently intended that the major portion (85*) of retorting will
 6e carried out in vertical, Paraho direct and/or indirect type retorts, but
 that  the  crushing fines  (15%) will be pyrolyzed in TOSCO II-type retorts. The
 processed shale will therefore be primarily of the Paraho-type, with some 15%
 of it having the  properties previously described for TOSCO II spent shales.

      It is expected  that all  of the 16,000 cubic meters (100,000 barrels) of
 shale oil produced daily will be  upgraded in facilities similar to those used
 for the Colony Operation.  As a result, some 3% of the wastes will consist of
spent catalysts,  sludges, and arsenic-laden solids from shale oil processing.

      Spent shale  and waste disposal is expected to be on Tract U-a, in Southam
Canyon, to the west  of the plant  area.  The processed shale pile will be built
southward along the  eastern half  of the canyon toward the southern limits of
Tract U-a.  A retention dam at the northern end of the canyon will prevent
contamination of  the White River.  The finished processed shale disposal pile
will  be contoured  to blend with the natural  terrain, and revegetated.

     It is projected that the combined 72,500 tonnes/day and 145,000 tonnes/
day commercial operations will produce of a total of about 1,040 million tonnes
(1,150 million tons) of retorted shale during the 20 (plus) years of contem-
plated full-scale production.  This will result in a disposal pile in Southam
Canyon of 727 million cubic meters (950 million cubic yards) volume, occupying
some 366 hectares (900 acres), with an average depth of 61 meters (200 ft.).

     Superior (28,46):  The Superior multi-mineral process is unique in that
it permits return of all  processed (e.g.  leached) shale underground, as a wet
cake, for compaction into the void spaces remaining after room-and-pillar
mining.  It is expected that the 22,000 tonnes (24,000 tons) per day commercial
operation will dispose of some 4.2 million tonnes (4.6 million tons) of leached
spent shale annually.

     The leached shale wet cake will  be returned to the mine and converted
into a slurry, which will  be pumped into the empty underground rooms and allow-
ed to drain to approximately 25% moisture content.  Because of the dipping
beds on the Superior property in the  northern Piceance Basin in Colorado, it
is claimed that the slurry can be emplaced up to the ceiling, by proper with-
drawal of the slurry discharge pipe as each room fills.

     As shown in Figure 4-6, the rooms will  be grouped into a series of "cells"
460 meters x 820 meters (1,500 ft.  x  2,600 ft.) with each cell  enclosed by a
rib pillar (barrier wall).  Cells within a given level  will be aligned with
corresponding panels above and below.   In the event of leakage, therefore, a
given cell can be sealed  off from the balance of the mine.

     It is projected that each "cell"  could contain up to 4.3 million tons of
leached spent shale, which is approximately the amount expected to be disposed
of annually from the commercial plant.  No revegetation, of course, of the dis-
posed shale will be required.

     Occidental (47.48):   In the modified vertical in-situ process currently
under investigation by Occidental Oil  Shale some 20% of the underground deposit
must be mined out, in order to produce the requisite void space for subsequent
rubblization.  This mined rock must be disposed of, if it is too lean for sur-
face retorting, or at least stored above ground if subsequent surface retort-
ing is contemplated.

     In a commercial Occidental in-situ operation using oil shale with an
average assay of .06 m3 /tonne (15 gallons/ton),'and producing some 7,950
cubic meters (50,000 barrels) per calendar day, it is estimated that 51,400
tonnes (56,700 tons) of "rock" must be mined and removed daily, or approxi-
mately 18.8 million tonnes (20.7 million- tons) annually.  If this rock is very
lean or nearly barren shale, it is proposed to dump it in canyons and gullies
near the in-situ operations and restore a vegetative cover.  The disposed
material would be essentially the same as the parent rock from which local
soils were derived.  It is estimated  that up to 16 to 24 hectares (40-60 acres)
of typical canyon disposal area could be required annually for such purpose.

     If the mined rock were richer in oil shale the above 50,000 barrel/day
plant would produce, for example, only 31,000 tonnes/day of mined material for


        CCESS OPES '.S
                               cfn'D DDnnaaDDannfn
       D ;D! P ET-.p .D P D O ,p p D  D p D D D DP .p D D D D.
      'b:.0;-:Q":p:p-D:d-'P-;t3';iji':;D'.n  G P.O.:D D Q D D D D: CTEJ
Figure  4-6.   Backfilling  of  Mined Out Shale Zone with Processed
              Shale - Superior  Oil  Company (28)

a 25 gallon/ton deposit.  This mined rock would most probably be stored tem-
porarily and subsequently processed by surface retorting, producing some
26,000 tonnes/day of retorted shale for disposal.  A canyon disposal  area of
some 8-12 (20-30 acres) annually would be required.

4.3.2  Potential Hazards and Pollution Problems

     The disposal of processed (retorted) shale involves the transport and
surface emplacement of large quantities of solids on a scale only rarely
attained to date in the mining industry.  The resulting disposal piles should
be stable, resistant to substantial erosion, and essentially impervious to
leaching by the normal rainfall and snowfall encountered in the shale region.
Provision should be made for protection against the flash flooding which might
rarely occur.  A suitable, permanent vegetative cover should be established.

     The spent shale will contain potentially Teachable salts and in some cases
a carbonaceous residue from retorting.  In addition, if upgrading of shale
oil is carried out in conjunction with retorting, spent catalysts, sludges,
arsenic-laden solids, and other plant wastes might also be present in a dis-
posal pile.  The latter could include process waters which might be used to
aid in compacting the processed shale.

     In the light of the above it would therefore appear that potential
hazards exist relating to (a) pile stability, (b) airborne partlculates,
odors, and/or organic vapors, (c) leachates, both inorganic and organic, as
a result of precipitation and/or ground waters, (d) transfer of possible haz-
ardous organics or trace elements to the biosphere, and (e) trans-locations
of toxic substances to vegetation.

     Pile Stability

     Most of the proposed major oil shale developers, as previously discussed,
plan to dispose of processed shale and also, perhaps, associated plant wastes
in canyon (or gully) locations.  Colony has selected a 325 hectare  (800 acres)
site in Davis Gulch, Middle Fork, East Parachute Creek.  Union's disposal area
will be in East Parachute Creek Canyon.  The Roxana Group (Tract C-b) will
utilize a 490 hectare (1200 acre) on-tract site in Sorghum Gulch (Piceance
Basin).  RBOSP plans to use "84 mesa" north of Tract C-a.  Tracts U-a/U-b
will utilize 366 hectares (900 acres) in Southam Canyon on Tract U-a.

     Among the surface process developers only Superior Oil will not use a
canyon disposal site, but rather return its retorted (leached) shale to its
underground mine.  Occidental will, of course, leave its retorted shale in-
place after in-situ retorting, but may dispose of mined lean shale or barren
rock on-surface.

     The large volumes of material which will be present in a disposal pile
can create pollution problems should the pile experience mass movements.
Slope stability and liquefaction studies have been conducted for TOSCO II pro-
cess shales (49,50). Large scale flow type failure of a pile is predicted to
be an unlikely occurrence.  However, local slumping or building is a more prob-
able event.  The angle of internal friction for TOSCO II retorted shale is


 about 20, suggesting that slopes  of 3:1  (18.50) would be stable in principle.
 Slopes of 4:1  are generally proposed for  the  sides of shale embankments, cor-
 responding to a 140 angie Of internal  friction.  The safety factor is not
 extremely high, and uncertainty exists regarding degree of saturation of some
 shale zones during part of the year.  Several potential interfaces between
 different materials are present 1n proposed disposal piles  including Valley
 floor - pile side Interfaces, compacted - non-compacted interfaces, over-
 burden - processed shale interfaces, and  topsoll - processed shale
 Interfaces.  These Interfaces may  promote lubrication, particularly when
 water saturated, and allow mass movement  to occur.

      Mass movement could adversely affect water quality.  Sediment and salts
 can  be added to local surface waters, or to  catchment structures.  Also,
 changes in pile drainage systems due to slumping, etc. may encourage infiltra-
 tion.  A destabilized pile surface will also  be difficult to keep vegetated,
 and both increased surface wind and water erosion may result.

      Since no large disposal piles have been  constructed to date, little is
 actually known about stability of  such piles  in real situations.  Further,
 most of the work to date  has  dealt with  carbonaceous shales;  burned shales
 are likely to have significantly different stability properties.

      Intermedia Transfer of Pollutants from Disposal Piles

      In order to control fugitive  dusts,  and  also to provide moisture for com-
 paction and stabilizing the disposal piles, retorted shale will be wetted
 prior to transport and distribution.  Whether this will be sufficient to mini-
 mize particulate emissions at the  scale of operations contemplated at each
 site is currently not completely known.  The  characteristics of the spent
 shale and the micro-meteorology for a given site are among  the pertinent vari-
 ables involved.

      Indirect water pollution resulting from runoff  from and infiltration into
 disposal piles has been discussed  in Section  4.2.4.  It is planned to route
 natural drainage at each disposal  site around the pile or through the pile in
 conduits.  Provisions must be made for drainages from side gullies, if present,
 and for protection of ground waters from  leachate contamination.  Whether the
 absorptive properties of the individual spent shales and the catchment basins
 planned by most developers are sufficient to  insure environmental protection
 against water quality degradation  is not  yet  clear.

4.3.3   Experience in Establishing Vegetative Cover on Retort Shale Piles

     The surface of a disposal pile  is subject to natural  erosion  by wind
and water.  In principle, non-vegetative protection  or  stabilization of  pile
surfaces  is possible,  but the large  areas  involved in commercial  shale oil
operations make vegetative stabilization the preferred  or  economic alternative.
Further, successful vegetation programs can create a  biotic  habitat similar
to or consistent with that of surrounding  areas.

     Several greenhouse and field experiments or tests have been conducted to
investigate the potential of retorted shale to support plant growth.   The re-
sults of these experiments indicate that successful  establishment of vegeta-
tion directly on the surface of retorted shale piles is partially limited by
inherent properties of retorted shale itself, including the high soluble salt
content of the shale, the alkalinity of Burned shale, the dark heat absorbing
color of carbonaceous retorted sfiale, and the lack of nutrients needed for
plant growth.  Studies have shown that germination and growth of most plants
are adversely affected when conductivity levels of soil saturation extracts
exceed 4 mmhos/cm, and that high pH values are a detriment to plant growth
(33,35,36).  Direct exposure of carbonaceous retorted shale to sunlight can
result in surface temperatures of up to 650C (1500F), and such temperatures
can prevent seed germanation (34).  Retorted shale usually lacks sufficient
available nitrogen and phosphorus to support vegetation.

     Some of the properties of retorted shales which limit plant establishment
and growth can be overcome.  Retorted shale's salinity and alkalinity levels
can be reduced by leaching the material prior to revegetation.  However,
channeling and incomplete wetting could result in pockets of unleached shale.
Also, upper layers can become resalinized via the capillary movement of salts
upward through the shale.  Large accumulations of salts in the upper 3-5
inches of surface soil may be toxic to plants, even  those with established
root systems (38).  For those retorted shales which  have  undergone significant
carbonate decomposition (due to high retorting temperatures), the addition of
granular sulfur effectively decreases alkalinity (37).  But the effectiveness
of this treatment is dependent on the adequacy of the moisture and temperature
conditions at the site.  The use of a light colored  mulch, such as straw, de-
creases the heat absorbtion by the shale, and therefore,  results in lower sur-
face temperatures.  However, straw has the disadvantage of being occasionally
contaminated with weed seeds, and is also subject to dispersal by the strong
winds that frequent some locations.  The addition of a complete fertilizer has
been shown to be a successful means of compensating  for spent shale's lack of
available nutrients.

     Local climate, slope angle, and slope direction can  have a large influ-
ence on the success of vegetative establishment.  Precipitation in the Pic-
eance Creek Basin in Colorado ranges from 30-40 cm (12-16 inches) per year,
with the higher values occuring at higher elevations (mainly in the form of
snow).  In contrast, the Uinta Basin is essentially desert except where the
White or Green Rivers form local riparian habitats.   Rainfall is well below
25 cm (10 in)/year and vegetation is fairly sparse.   Most of the oil  shale
related revegetation experiments to date have been conducted in the Piceance
Basin (32,37,38,39).  Only recently has revegetation been attempted in the
harsher desert environment.  The Research Foundation of Utah State University
is performing an ambitious program of revegetation research for U-a/U-b (see
Chapter 6) .

     Also, some of the earlier revegetation projects were conducted in rela-
tively flat areas along river valleys.  Slopes, particularly south facing,
are much more difficult to revegetate than flat terrain or slopes facing north,
east or west.  Jute netting and various polymers are effective in decreasing

surface erosion and thus are an aid in the initial  establishment of plant
cover on sloping surfaces.

     An alternative to attempting establishment of vegetation  directly on re-
torted shale is to construct a soil profile more conducive to  plant growth.
Developers of Tract C-a plan to place a layer of crushed rock  and gravel  be-
tween the spent shale and the soil layer in order to combat the capillary re-
salinization problem.  But regardless of how the re-salinization problems are
handled, the soil layer should be thick enough to (1) accommodate plants  with
extended root systems, and (2) be able to store adequate moisture for plant
growth during dry periods.  Retorted shale heat absorption problems could also
be overcome with the placement of a layer of soil over the surface of the
shale.  However, at some locations there is not an adequate soil supply and
the use of soil/retorted shale mixtures instead of soil alone  may be neces-

     Some additional problems or areas of uncertainty have been identified in
connection with revegetation experiments, including the following:

       A retorted shale pile will be compacted for physical stability.
        This practice, plus the cementation tendency of some shales may
        make portions of the embankment impenetrable to plant  root
        systems and to percolating water.  It may be difficult to estab-
        lish deep rooted  shrubs or trees on retorted shale piles.

     t  Success of revegetation may be hampered by foraging mice, rabbits,
        and deer.  Such foraging may be partially controlled by fencing
        (for large mammals), but in any case the problem is not unique
        to the revegetation of retorted shale.

       Plants growing on retorted shale may contain higher levels of
        trace elements than plants growing on native soils. One study
        has indicated that zinc and molybdenum levels in vegetation
        growing on retorted shale exceeds that recommended in  forage
        for cattle (38).

       Weedy species (eg, Russian Twistle) may invade revegetation sites.
        Initially, such invasion may not necessarily be undesirable, as
        "weeds" are commonly the first class of plants to become estab-
        lished in natural plant succession sequences.  If a shale pile
        surface is particularly conducive to the growth of certain unde-
        sirable species, herbicides or other controls may be necessary.

       Although some small retorted shale piles have been revegetated
        and some have sustained vegetation for over 10 years without
        extensive management(1,37), the longer term stability  and succes-
        sional characteristics of such plots are not accurately known at


 1.   Colony Development Operation,  Draft  Environmental  Impact Statement  (EIS),
     U.S.  Department of the  Interior,  Bureau of  Land Management, December 1975.

 2.   Detailed Development Plan,  Vols.  I and II,  Federal Oil Shale Lease  Tract
     C-b,  submitted  to  Area  Oil  Shale  Supervisor,  February 1976.

 3.   P.  B.  MacCready, Jr., L.B.  Baboolal  and P.  B. S. Lissaman, "Diffusion and
     Turbulence Aloft Over Complex  Terrain,"  presented at American Meteorolo-
     gical  Society Symposium on  Atmospheric Diffusion and Air Pollution,
     September 9-13, Santa Barbara, 1974.

 4.   E.  I.  Hovind, T. C.  Spengler and  A.  J. Anderson, "The Influence of  Rough
     Mountainous Terrain upon Plume Dispersion from An  Elevated Source,"
     presented at American Meteorological  Society  Symposium on Atmospheric
     Diffusion and Air  Pollution, September 9-13,  Santa Barbara, 1974.

 5.   G.  E.  Start, C. R.  Dickson  and N. R.  Hicks, "Effluent Dilutions over
     Mountainous Terrain and Western Mountain Canyons," presented at American
     Meteorological  Society  Symposium  on  Atmospheric Diffusion and Air Pollu-
     tion,  September 9-13, Santa Barbara,  1974.

 6.   Meyer, L. and Nelson, R., "Adequacy  of Regional Atmospheric Data for
     Specific Predictive Purposes in the  Piceance  Creek Basin," Quarterly of
     the Colorado School  of  Mines,  Vol. 7, No. 4,  October 1975.

 7.   D.  Bruce Turner, Workbook of Atmospheric Dispersion Estimates, Public
     Health Service  Publication  No.  999-AP-26, U.S. Department of Health Educa-
     tion  and Welfare,  1969.

 8.   F.  Pasquill, Atmospheric Diffusion,  D. Van  Nostrand Co., Ltd., London,

 9.   David  Slade, ed.,  Meteorology  and Atomic Energy. 1968, U.S. Atomic  Energy
     Commission, 1968.

10.   Briggs, Gary A., Plume  Rise. U.S. Atomic Energy Commission, Office  of
     Information Services, 1969.

11.   Hanna, Steven R.,  "Fog  and  Drift  Deposition from Evaporative Cooling
     Towers," Nuclear Safety. Vol.  15, No. 2, March-April 1974, pp 190-196.

12.   Battelle Pacific Northwest  Laboratories and Dames  and Moore: Air Studies.
     Environmental Impact Analysis. Appendix 13. prepared for Colony Develop-
     ment  Operation, October 1973.

13.   Federal Energy  Administration, Project Indepenqence Blueprint, Final Task
     Force Report.  Potential Future Role of Oil Shale:  Prospects and Con-
     straints, under direction of  U.S. Department  of Interior, November  1974.

     n'i cu i9*' n',?' Buder' C' B- FJ' R-  6-  Murray  and  R.  K. White,
     uil Shale Air Pollution Control, prepared  for the  Environmental  Protection
     Agency by Stanford Research Institute NTIS PB-242-858, May  1975.

15.  H. E. Cramer, G. M. Desanto, K. R. Dumbauld,  P.  Morganstern,  R.  N.  Swanson,
     Meteorological Prediction Techniques and Data Systems, Report GCA-64-3-G,
     Geophysics Corporation of American, Bedford,  Massachusetts, March 1974.

16.  EPA correspondence (Region VIII), letter of Mr.  C. H. Wayman, Director,
     Office of Energy Activities, to Mr. Darrell Thompson, Regional  Director,
     Bureau of Outdoor Recreation, Denver Federal  Center, Denver,  Colorado,
     March 1976.

17.  Detailed Development Plan, Vols. I-V, Federal Oil  Shale  Lease Tract C-a
     (Rio Blanco Oil Shale Project), submitted to Area  Oil Shale Supervisor,
     March 1976.

18.  EPA correspondence (Region VIII), letter of Mr.  C. H. Wayman, Director,
     Office of Energy Activities, to Mr. R. L.  Bolmer,  Mining Engineer,  Denver
     Mining Research Center, U.S. Bureau of Mines, Denver, Colorado, May 14,

19.  Carpenter, T. L. Montgomery, L. M. Leavitt, W. C.  Colbaugh, and F.  W.
     Thomas, "Principal Plume Dispersion Models; TVA Power Plants,"  Journal of
     Air Pollution Control Association, 21_, 8,  1971.

20.  Colony Development Operation, An Environmental Impact Analysis  for  a
     Shale Oil Complex at Parachute Creek, Colorado,  Part I,  1974.

21.  White River Oil Shale Project, Federal Oil Shale Lease Tracts Ua-Ub,
     Quarterly reports 1 through 6, 1974 through February 1976.

22.  Irons, W. V., Hembree, C. H., and Oakland, G. L.,  "Water Resources  of the
     Upper Colorado River Basin," U.S. Geologic Survey Prof.  Paper 441.  1965.

23.  Weeks, J. B., Leavesley, G. H., Welder, F. A., and Saulnier,  G. J., "Sim-
     ulated Effects of Oil Shale Development on the Hydrology of the Piceance
     Creek Basin, Colorado," U.S. Geological Survey Prof. Paper 908, 1974.
24.  U.S. Department of Interior, Final Environmental Statement for  the  Proto-
     type Oil Shale Leasing Program, 1973.

25.  Coffin, D. L., Welder, F. A., and Glauzman, R. K., "Geohydrology of the
     Piceance Creek Structural Basin Between the White and Colorado  Rivers,
     Northwestern Colorado," U.S. Geological Survey Hvdrologic Investigation
     Atlas HA-370, 1971

26   Coffin, D. L., Welder, F. A., Glauzman, R. K., and Dutton,  X. W.,  "Geo-
     hvdrologic Data from the Piceance Creek Basin Between the White and
     Colorado Rivers, Northwestern Colorado,"  Colorado Ground Water Circular
     No. 12, 1968.

27.  U.S. Public Health Service, "Drinking Water Standards," U.S. Public
     Health Service Publication 956, 1962.

28.  Weichman, B.E., "Depositional  History and Hydrology of the Green River
     Oil Shale, Piceance Creek Basin, Rio Blanco County, Colorado," proceedings
     102nd Annual Meeting of the AIME, 1973.

29.  Hem, J. D., "Study and Interpretation of Chemical  Characteristics of
     Natural Water," U.S. Geological Survey Water Supply Paper 1473, 1970

30.  Coffin, D. L. and Bedenhoeft,  J. E., "Digital  Computer Modeling for Esti-
     mating Mine-Drainage Problem - Piceance Creek Basin, Northwestern Colorado,"
     U.S. Geological Survey Open File Report, 1969.

31.  Andrews, C., et.al., "Oil  Shale Development in Northwestern Colorado:
     Water and Related Land Impacts," Water Resources Management Workshop,
     Institute for Environmental Studies, University of Wisconsin, Madison,
     Wisconsin, July 1975.

32.  Cook, C. W., Study Coordinator, "Surface Rehabilitation of Land Distur-
     bances Resulting from Oil  Shale Development" Technical  Report Series No.
     1. Colorado State University,  June 1974

33.  Richards, L. A., ed.,  "Diagnosis and Improvement of Saline and Alkali
     Solids," U.S. Department of Agr. Handbook 60,  1954.

34.  Striffler, W. D., Wymore,  and  W. A.  Berg, "Characteristics of Spent Shale
     Which Influence Water Quality, Sedimentation and Plant Growth Medium,"
     Technical Report Series No. 1, Colorado State University, 1974.

35.  Black, C. A., Soil-PIant Relationships, John Wiley and Sons, New York,

36.  Arnon, D. I., and Johnson, C.  M., "Influence of Hydrogen Ion Concentra-
     tion on the Growth of Higher Plants Under Controlled Conditions," Plant
     Phys. Vol. 17, pp. 525-539, 1942.

37.  Lipman, S. C., Union Oil Company, "Revegetation Studies," Environmental
     Oil Shale Symposium, Colorado  School of Mines, October 9-10, 1975.

38.  Halbert, H. P. and Berg, W. A., "Vegetation Stabilization of Spent Oil
     Shale," Colorado State University, 1974.

39.  Bloch, M. B;, and Kilburn, P.  D., "Processed Shale Revegetation Studies,"
     Colony Development Corporation, 1965-1973.

40.  C-b Shale Oil Project, "Environmental and Exploration Program," Summary
     Reports No. 1-7. through May 31, 1976.

41.  Rio Blanco Oil Shale Project (Tract C-a), Progress Reports No. 1-7,
     through May 1976.

42.  Ward, J. E., et.al., "Water Pollution Potential  of Rainfall  on  Spent  Shale
     Residues,  prepared under EPA Grant No.  14030 EDB, December  1971.

43.  Ward, J. C., et.al., "Water Pollution Potention  of Snowfall  on  Spent  Shale
     Residues,1 Bureau of Mines Open File Report No.  20-72.  June  1972.

44.  Ficke, J. F., et.al., "Hydrologic Data from the  Piceance  Basin, Colorado,"
     U.S.G.S. Colorado Water Resources Basic Data Release No.  31, 1974.

45.  Hopkins, J. M., et.al., "Development of Union Oil  Company Upflow Retort-
     ing Technology," 81st meeting AIChE, Kansas City,  Missouri,  April 11-14,

46.  Superior Oil Company, Application  for Consolidating Oil Shale  Lands by
     Acreage Exchange #C-19958, Bureau  of Land  Management, U.S.  Department
     of  the  Interior, Denver, Colorado.

47.  McCarthy, H. E., and Cha, C.  Y., "Development of the Modified In Situ Oil
     Shale Process," 68th AIChE Annual Meeting,  Los Angeles, California,
     November 16-20, 1975.

48.  McCarthy, M. C., "The Status  of Occidental  Oil Shale Development" 9th
     Oil Shale Symposium, Colorado School of Mines, Golden,  Colorado, April
     29-30, 1976.

49.  Dames and Moore, "Liquefaction Studies of a Proposed Processed  Shale
     Disposal Pile, Parachute Creek Colorado," study  for the Colony  Develop-
     ment Operation, 1971.

50.  Dames and Moore, "Slope Stability Studies of a Proposed Processed Shale
     Embankment, Parachute Creek Colorado," study for the Colony  Development
     Operation, 1971.

51.  Detailed Development Plan, Federal  Oil Shale Lease Tracts U-a/U-b,  sub-
     mitted to Area Oil Shale Supervisor, June 1976.

52.  Larsen, R. I., "A Mathematical Model for Relating Air Quality Measurements
     to Air Quality Standards," EPA Publications No.  AP-89,  1971.


     The commercial success of shale oil will depend in part on the ultimate
end use of the oil and on the refining steps necessary to produce a competitive
product.  This chapter is a brief review of shale oil upgrading and refining
experiences to date, waste streams and hazards associated with refining and
handling of shale oil, and emissions from the combustion of shale oil products.


     Crude shale oil is a high nitrogen, moderate oxygen and sulfur contain-
ing oil having a relatively high pour point and viscosity.  It contains a
large fraction of unsaturated and aromatic compounds, and tends to form gums
during storage.  Compared to most conventional crude oils, shale oil yields
less light ends upon distillation.  Crude shale oil contains ash in the form
of raw and retorted shale fines.  Most trace elements in shale oil are
associated with the ash fraction, and concentrate into higher boiling fractions
and coke upon distillation.  An exception is arsenic, which is found in
essentially all distillate cuts.  A summary of the properties of currently
produced crude shale oils are presented in Table 5-1.

5.1.1  Upgrading Plans for Oil Shale Developments

     The oil shale developments planned to date do not envision processing
crude shale oil into a full range of refined products as would be the case
with a modern petroleum refinery.  Rather, various levels of upgrading or
prerefining are planned in order to: 1) render crude shale oil transportable
and/or suitable as a refinery feedstock and 2) produce fuel oil and other
petroleum equivalent cuts for direct use.  Table 5-2 summarizes the major
prerefining or upgrading steps planned by oil shale projects.  Some of the
details of these steps are reviewed in Chapter 2 of this report.

     Crude shale oil can be upgraded by employing variations of conventional
petroleum refining techniques.  Solids removal is accomplished by either
filtration (diatomaceous earth) or by concentration of solids during coking.
Saturation of olefins and removal of organic sulfur, oxygen, and nitrogen
is accomplished by catalytic hydrogenation, although severe conditions must
be employed with shale oils due to the high nitrogen content.  Catalyst
poisons such as arsenic are removed prior to hydrogenation, commonly by use
of an adsorption catalyst.

5.1.2  Experiences in Oil Shale Refining

     Essentially all major oil companies which have an interest in or hold
mineral rights to oil s-hale have conducted research or demonstration programs

 Sn!I2  1     the refining of shale oils.  Generally, the results of such
 programs  have not been  published and are considered proprietary.  Experiences
 from  two  relative y large  scale refining runs with shale oil have been pub-
 lished  and are briefly  reviewed here.

 Union Oil  Company - 1961  (4)

    The crude shale oil obtained from the Union Oil Retort A process is a
 waxy, intermediate gravity (specific gravity of 0.943), high in nitrogen (2.0
 weight  %), intermediate sulfur (0.9 weight %) crude, with a pour point of
 26.7C  (80F) and a viscosity of 46 centistokes (210 SUS) at 37.8C (100F)
 Early in 1961,  approximately 3,180 m3 (20,000 bbl) of the crude shale oil
Inventory at  Union's Retort A demonstration plant were processed in the
American Gilsonite's refinery near Fruita, Colorado.  The basic operations
in the refinery included delayed coking, thermal  cracking, gasoline hydro-
genation and  catalytic  reforming, light gasoline sweetening, and coke calcin-
ing.  All  of  these  operations were reported to be successfully applied to
the Union  Retort A  shale oil in the refinery test run.  The refined products
were marketed by American  Gilsonite through marketing outlets in the
Grand Junction area.

      The detailed results  from shale oil refining at the American Gilsonite
refinery are  not available.  According to Union Oil, the test results are
similar to  those obtained  from the bench scale and pilot plant tests on shale
oil refining  performed  by  the Bureau of Mines.  Based on the results of
American Gilsonite  refinery and Union's pilot plant test runs, preliminary
process designs for producing and refining commercial shale oil were proposed
by Union.    The  processes proposed included delayed coking to reduce pour
point, Unifining*of the full range distillate to reduce nitrogen and sulfur
content, and  conventional  refining processes of primary distillation, cataly-
tic cracking, additional Unifining, reforming, alkylation and treating to
produce LPG,  gasoline,  stove oil, jet fuels, heating oils, and diesel.

Paraho Shale  Oil at Gary Western (1975) (5)

      In 1975, a program under Navy Contract N00014-75-C-0055 was carried out
by Applied  Systems  Corporation to demonstrate the production of military fuels
from  shale  oil.  Paraho crude from Anvil Point, Colorado, was selected as the
raw material.  Contractors  included Applied Systems Corporation (ASC); SOHIO;
Development Engineering, Inc., (DEI); Gary Western Co.; and Petroleum
Analytical  Research Corp., (PAR).

      Using  the  Gary Western facility, at Gilsonite, Colorado, 9,956 barrels
of crude Paraho processed  shale oil were refined into the following quantities
of military fuels:

 *Unifining is a hydrodesulfurization and hydrodenitrogenation  process jointly
  licensed  by  Union Oil  and Universal Oil Products Co.

                                         Table  5-1.  Summary of  Crude  Shale 011  Properties
Retort Type:
Data Source:
Gravity (API)
Specific Gravity (60F/60F)
Pour Point (F)
Pour Point (C)
Viscosity (Centlstokes)
Viscosity (SUS)
Weight % Carbon
Weight % Hydrogen
Weight % Nitrogen
Weight % Oxygen
Weight % Sulfur
Weight % Ash
C/H Ratio
Fischer Assay of Feed (gpt)
011 Recovery (% of Fischer)
Initial Boiling Point, F
10% Over
End Point
Ref. 1

113 at 100F



Ref. 1

106 at


Para ho
II Direct Mode
Ref. 4

100F --

011 "B"
Ref. 3




Ref. 2


f  i /







              NATO Gasoline         116 m3
              JP-4                   72 m3
              JP-5/Jet A            104 m3
725 barrels)
454 barrels)
650 barrels)
1,167 barrels)
              DFM/DF-2              187 m3  .,.,  _,_,
              Heavy fuel  oil         442 m3 (2.765 barrels)
                             Total   917 m3 (5,732 barrels)

    The fuels met a majority of ASTM specification requirements.   However,
they did not meet specifications with respect to particulate matter,  gum con-
tent, wax content, storage stability, and thermal  stability.  The opinion has
been expressed that more rigorous hydrotreating (at 100-200 kg/cm2 or 1500  to
3000 psi) and clay treatment might have allowed the final  products to meet  all
ASTM specifications.  The 672 m3 (4224 BBLS) of original crude shale  oil which
do not appear in the military fuels are accounted for in coke, distillation
gases, and flue gases from combustion.

     Using modified refining techniques, based on preprocessing studies
conducted by SOHIO, the Gary Western refinery operated at a rate of
2500 barrels a day to the coke/fractionator in relatively normal  fashion,
producing naphtha, liquid gas oil, heavy gas oil, heavy fuel oil, coke and

     It should be noted that this effort demonstrated only the feasibility
of producing fuels from shale oil.  Rates were below normal, yields were
low, and the properties of the products were subnormal.  However, none of the
problems encountered were entirely unexpected and, generally, appear soluble
with experience and practice.

     The products from the Gary refining run were distributed to several
laboratories, agencies and companies for testing.

       Wright Paterson AFB  (Dayton, Ohio)

       Lewis Research Center (Cleveland, Ohio)
       Naval Air Propulsion Test Center (Trenton, N.J.)
       Mobil Equipment Research & Development Center (Ft. Belvoir, Va.)

       Energy Research Laboratory (Bartlesville, Okla.)

     t  Fuels & Lubricants Laboratory  (San Antonio, Texas)

     0  Detroit Diesel-Allison/GM (Indianapolis,  Ind.)

       Naval Ship Engineering Center  (Philadelphia, Pa.)

       U.S. Coast Guard Station (Portsmouth, Va.)
     t  Southern California  Edison (Los Angeles,  Ca.)

       Cleveland Cliffs Iron Company  (Cleveland, Ohio)

       Paraho Test Facility (Anvil Points)

                  Table  5-2.   Summary of "On  Site"  Upgrading  of  Shale Oil Planned  at Development  Sites
                Colony Development
                Operation - Parachute
                Lease Tract C-b
                Lease Tract C-a
                Lease Tracts U-a/U-b
Steps of Upgrading or Prerefining
  Distillation followed by delayed coking of residue
  Dearsenatlon of naphtha  and  gas oil fractions
  Catalytic hydrogenatlon  of Naphtha and gas oil fractions
  Hydrogen production by catalytic reforming of naphtha
   followed by steam,  reforming shift conversion, C02 removal

t  Same as Colony

  Distillation, delayed coking
t  Catalytic hydrogenatlon
  Hydrogen production by gasification
   of heavy ends, followed  by shift conversion & C02 removal

  Catalytic hydrogenatlon  of naphtha and crude shale oil.
   Hydrogen production by catalytic reforming of retort gases
   and naphtha.
  Solids/fines removal  via filtration & water washing
  Catalytic dearsenatlon

  No upgrading Indicated,  company claims oil can be trans-
   ported directly to  refinery

  Company Indicates that blending with petroleum crudes will
   be attempted
  Low Sulfur fuel  oil

  Same as Colony

  Plpellneable shale oil
  Upgraded shale oil
   Refined shale oil
   Prerefined shale oil
  Crude shale oil
t  Crude shale oil
  Sodium bicarbonate
*  Alumina


                                :ompany shale oil upgrading and refining are
                                conventional petroleum refining.  Some of
                                CO 1 1 H uia C + AC* /J	^_ _    i     ***   .    _. -. 
these emissions               *          na  Peroeum renng.   Some o
-^=w^                                 1" ^Pter 3-0)

5.2.1  Waste Streams

fl  lOPnli?inf,rn!X?in1r!t1Jni?f -ha1e o11 uP9rad1"9 a"d refining  operations
U 10,11,12; suggests the following:

       Atmospheric emissions from  crude shale oil upgrading and
        refining are  similar in magnitude and composition to those en-
        countered with  processing of petroleum.  However, certain
        operations such as hydrogenation and ammonia and sulfur recovery
        must be tailored to the properties of shale oil, and pollution
        control equipment sized accordingly.

       Waste waters  from shale oil processing contain organic
        and inorganic constituents  similar to those found in the
        petroleum refining and byproduct coke industry.

       Solid wastes  from shale oil upgrading and refining operations
        include spent catalysts, clay finishing wastes and perhaps
        shale oil coke.   Such  wastes  may have somewhat different
        compositions and chemical properties than wastes from petroleum

5.2.2  Carcinogenic Properties of Crude Shale Otis and Refined Products

     Crude shale oils,  upgraded or  refined shale oil products, and certain
waste streams associated with shale oil processing may contain hazardous sub-
stances from which industrial workers and the general population should be
protected.  A current concern is the potential human exposure to carcinogens
associated with shale products.  Several authors have suggested that shale
derived oils may create more of a cancer hazard than is currently associated
with petroleum oils (21,22,23,24),  although the matter is still unresolved.

Epidemlological Studies

     Early awareness  of the potential carcinogenic!"ty of shale oils occurred
in the British cotton industry (8).  A high incidence of scrotal  cancer was
attributed to direct  worker contact with shale oil lubricants, used on the
spinning  machines.    However, studies of workers in the Scottish oil  shale
industry during the same period did not reveal a particularly high cancer
incidence in that industry.  The Scottish experience indicated that only cer-
tain types of processed shale oils possessed carcinogenic properties.

     The Estonian oil shale industry is one of the largest and oldest oil
shale industries in the world. For over 20 years the Institute of Experimental


and Clinical Medicine of the Estonian Ministry of Health has conducted
clinical, industrial hygiene  and toxicological studies on the workers employed
in this industry (8,9,10).  A greater cancer incidence among Estonian shale
workers over that of the general population has not been demonstrated.  The
Estonian shale industry attributes this lack of cancer problems to good hy-
giene practices, automation, and isolation of workers from potentially hazard-
ous materials.

     The largest current oil shale operation is the Petrobras Complex in
Brazil.  Although epidenriological data is limited, no special cancer problems
have been reported for the operation.

     The National Institute of Occupational Safety and Health (NIOSH) is spon-
soring a study of workers involved in the production of shale oil  from Colorado
oil shale to investigate possible relationships between exposure to oil shale
and shale products and cancer incidence (29).   This study is to follow up on
limited dermatological investigations by U.S.  Public Health Service of some
800 shale workers who were employed at Anvil Points in the early 1950s.  The
NIOSH study is aimed at determining possible latent effects of occupational

Suspected Carcinogens in Shale Products

     A variety of known and suspected carcinogens belonging to the POM* class
have been identified in crude shale oil and shale oil products.  Some reported
levels of Benzo(a) Pyrene (BaP) in shale derived materials are listed in Table
3-15.  Other carcinogenic compounds in the POM class have also been tenta-
tively identified in shale products, including 3-methylcholanthrene and an
isomeric  mixture of dimethylbenz(a)-anthracenes (12,24).  Generally, ROM's
have high boiling points (about 300C) and are found in the higher boiling
distillates or residues of shale oils, including shale oil coke and carbon-
aceous residues associated with processed shale (13).

     Some of the controversy about the carcinogenicity of shale derived mate-
rials arises from the use of BaP content as an indicator of activity.  Levels
of BaP in shale oils are generally in the same range as levels found in similar
boiling range petroleum oils, suggesting that shale oil presents no more of a
hazard than petroleum (11,12,14,15).  However, experimental tests  with crude
shale oil and various distillate fractions have shown that the carcinogenic
potency by non-human bioassay techniques cannot be attributed to the presence
of benzo(a)pyrene alone (13,16,17,18,19,20,21).  Other carcinogenic or co-
carcinogenic compounds may be present.  Conversely, high measured  levels of
BaP in a material do not necessarily indicate biological availability.  TOSCO
II retorted shale for example, has not been shown to be a skin carcinogen in
sensitive mice exposed to it as bedding, while benzene extracts of such shale
are carcinogenic to the skins of mice (12).  Other pathological tests on the
internal organs of these mice are still in progress.  It should be noted that
BaP has not been demonstrated to be a carcinogen in man (25).
*Polycycltc Organic Matter


Bioassay Tests

     A major problem for establishing the degree of cancer hazard for humans
presented by materials such as shale oil is that tests cannot be directly per-
formed on humans.  Animal testing results, in addition to being expensive to
obtain, cannot readily be extrapolated to humans.  Epidemiological  studies are
also expensive, may take years to produce results, and suffer from lack of
control of other factors which may affect cancer incidences.   One simple but
promising test for screening potentially carcinogenic substances and materials
is the Ames (or Salmonella Reversion) Test (26).  The Ames test is based on
the empirical observation that many mutanogenic substances are also carcino-
gens, and that certain strains of bacteria are good test organisms for indicat-
ing the mutanogenic properties of substances (27).  Several federal agencies
and private organizations are currently screening synthetic fuel related mate-
rials for potential carcinogenic properties using the Ames and related tests

     Experiments with  test animals  (mice  and rats) have shown that only cer-
tain fractions of  crude  and  refined  shale oils  exhibit carcinogenic activity.
High boiling distillation fractions  of  shale oil  have been shown to be carcin-
ogenic to the skins of mice  (9,10,20),  and the  active fractions do not neces-
arily contain large amounts  of BaP  (21).  The Colony Development has contracted
With the Eppley  Institute for animal  testing of shale derived materials (12).
Based on the results of  the  Eppley studies, carcinogenic potency indices for
various hydrocarbon material have been  determined.  Table 5-3 shows a compari-
son of the relative potency  of some  petroleum and shale derived materials.  The
indices suggest that shale derived oils are similar to petroleum oils of com-
parable boiling range  or intended use,  and that upgraded (hydrotreated) shale
oil is significantly less potent than crude shale oil.  It might be commented
that a latency period  is required for the development of carcinogens in mice,
and toxic substances other than POM  in  shale oil  can cause death before can-
cers might normally occur (20).

Potentially Carcinogenic Materials in Waste Streams Associated with Shale and
Shale Oil Processing                                                    -*

     The presence  of suspect carcinogens  in shale products suggests that waste
streams associated with  processing may  also contain such substances.  Some of
the studies regarding  retorted shale have been  reviewed in Section 3.3.2.  Air
and waterborneemissions  and  effluents resulting from retorting, upgrading, and
refining operations may  also contain such substances (Sections 3.1.1 and 4.2).
Generally, little  ts known about the hazards of shale related waste streams,
since retorting and refining operations conducted to date have been limited
in scope and size, and have  been aimed  primarily at demonstrating technology
rather than determining  effluent quantities and properties.

     Based on analytical data, animal testing,  and epidemiological studies,
some generalizations can be  made about the carcinogenic hazard of shale derived

     0  High boiling shale derived oils and carbonaceous residues contain
        BaP and other  POM.

a  Levels of BaP in shale derived products are similar to levels
   found in analogous petroleum derived oils and residues.

  BaP content may not necessarily be a good indicator of carcinogenic
   activity in test animals, both because of the possible presence
   of other carcinogens and because analytical measurements do not
   necessarily indicate bioavailability.

  Industrial exposure of humans to certain shale products has been
   correlated to cancer incidences, but the correlation is no
   stronger than that between exposure to many petroleum and coal
   derived substances and cancer.

t  Good industrial hygiene practices and isolation of workers from
   exposure can dramatically influence occupational cancer incidences.

  Bacterial and animal test results regarding the carcinogenicity
   of substances or materials cannot directly be related to carcin-
   ogenicity in man.

  Little is known about actual hazards to workers or the general
   population from carcinogens which might be present in the waste
   streams of shale and shale oil processing operations.
Table 5-3.  Comparable Carcinogenic Potency of Complex Mixtures (12)
        Oil Product
Potency Index Based on
   Mouse Skin Tests
  Industrial Fuel Oil                           0.17

  Naphthenic Distillate                         0.06

  Dewaxed Paraffin Distillate                   0.06
    from Petroleum

  Cracked Sidestream                            0.26

  Coke Oven Coal Tar                            0.54

  Crude Shale Oil                               0.10

  Upgraded Shale Oil                            0.03

  3-methylcholanthrene (reference compound)      1-0


      Emissions from the combustion of fossil fuels may be divided  into  two
 broad categories; those which occur due to the inherent properties and
 composition of the fuel, and those which occur as a function of combustion
 parameters.  Sulfur dioxide belongs in the first category, while carbon
 monoxide and hydrocarbons belong to the second category.  Particulate
 emissions can be placed in both categories; sooty material accompanying
 incomplete combustion, and ash derived from inorganic and noncombustible
 components of the fuel.  Similarly, oxides of nitrogen occur in combustion
 gases both from oxidation of fuel nitrogen and from the non-equilibrium
 reaction of atmospheric nitrogen and oxygen at combustion temperatures.

      The properties of crude shale oil have been discussed previously(Sec.  5-1)
 The high nitrogen content and, to a lesser extent, the inorganic content of
 the refined shale oils are the properties which present the major  emissions

      Very little  information  is available about emissions  from  the combustion
 of crude shale oils.   Limtted emissions information  has  been made available
 recently from the testing  of  refined  fuels from the  Paraho project.  The data
 at present indicate  that shale derived fuels are not significantly different
 from their petroleum derived  counterparts in either  performance or emissions
 characteristics.  In  the case  of the products from the 1975 Paraho  refining
 run, slightly higher nitrogen and ash contents  of certain  fractions account
 for differences in emissions  between  shale and  petroleum derived fuels  (6,7).
 About 50% of fuel  nitrogen is converted to NOX  during combustion.  The  South-
 ern California Edison Company tested  Paraho shale oil  in July of 1976 at the
 Highgrove, California generating station, but emissions  data has not been

     Particulate polycyclic organic matter may be emitted during the combus-
tion of shale oil  and its higher boiling distillate fractions.   However, emis-
sions of  POM are a function of combustion parameters as well as  shale oil com-
position.  Further, evidence to date suggests that particulate POM  emissions
associated with combustion of refined shale oils are not inherently greater
than those from combustion of similar boiling range petroleum oils.


 1.  Hendrickson, T. A., "Oil  Shale Processing Methods,"  Colorado  School  of
     Mines Quarterly. Vol.  69, No.  2,  April  1970.

 2.  McCarthy, H. E., and Cha, C.  Y.,  "Development of the Occidental  Modified
     In-Situ Oil  Shale Process,"  68th  AIChE  Annual  Meeting,  Los Angeles,
     California,  November 16-20,  1975.

 3.  Cameron Engineers, Inc.,  "Synthetic  Fuels Data Handbook.  December  1975.

 4.  Carver, H.  E., "Conversion of Oil  Shale to Refined Products," Quarterly
     of the Colorado School  of Mines,  Vol. 59, No.  3,  July 1964.

 5.  Bartick, H., et.al., "Final  Report on the Production and  Refining  of Crude
     Shale Oil into Military Fuels," Applied Systems Corp.,  Office of  Naval
     Research Contract No.  N0014-75-C-0055,  August 1975.

 6.  Hosier, S.  A., et.al.,  "Comparative  Characteristics  of  Petroleum and Shale
     Oil Base Diesel Fuel Marine. "Monograph on Alternate  Fuel  Resources.  Vol.20.
     California Polytechnic  State  University, San  Luis Obispo, California,  1976.

 7.  Hardin. M.  C., "The Combustion of Shale Reserved Marine Diesel Fuel  at
     Gas Turbine Engine Conditions," ibid  (6).

 8.  Commoner, Barry, "From Percival Pott to Henry Kissinger," Hospital Practice.
     Vol. 10. p 138, October 1975.

 9.  Bogowsky, P. A., and Jons, H.  J.,  "Toxicological  & Carcinogenic  Studies of
     Oil Shale Dust and Shale Oil," Inst. of Exp.  & Clin. Med. Tallin.  Estonian
     USSR. 1974.

10.  Vosame, A.  J., "Blastomogenicity  of  Estonian  Oil  Shale  Mazut  Soot,"  Voprosy
     gigieny trada i profess,  pa to log it v Estonskoi SSR Ed;  Valgus. Tallin, 1_,
     73, 1966.

11.  Atwood, M.  T. and Coomes, R.  M.,"The Question of Carcinogenicity in  Inter-
     mediates and Products  in Oil  Shale Operations," Report for the Colony Devel-
     opment Operation. Atlantic Richfield Co.. Operator.  Denver, Colorado,  May

12.  Coomes, R.  M., "Health Effects of Oil Shale Processing,"  9th  Oil Shale
     Symposium, Colorado School of Mines, April 29-30, 1976.

13.  Hueper, W.  C., "Experimental  Studies on Carcinogenesis  of Synthetic  Liquid
     Fuels and Petroleum Substitutes," Arch. Industrial Hygience and  Occupational
     Medicine, 8, 307, 1953.

14.  Coomes, R. M., Presentation  at the Colorado State Oil Shale Advisory. Com-
     mittee Meeting, Rangely, Colorado, May  1976.

15.  Atwood, M. T., Presentation at the Panel Discussion,  University of Denver
     Symposium on Management of Residuals from Synthetic  Fuels  Production,
     Denver, Colorado, May 1976.

16.  Hueper, W. D., Occupational Tumors and Allied Disease,  Springfield,  111.,
     Charles C. Thomas, pp 147-187, 1952.	

17.  Henry, S. A., "Occupational Cutaneous Cancer Attributable  to  Certain
     Chemical Industries," Brit. M. Bull. Vol. 4, 389, 1947.

18.  Berenbloom, I. and Schoental, R., "Carcinogenic Constituents  of Shale  Oil,"
     Brit. J. Path. 24, 232, 1943.

19.  Berenbloom, I. and Schoental, R., "The Difference in Carcinogenicity
     Between Shale Oil and Shale," ibid 25, 95, 1944.

20.  Hueper, W. C., and Cahnmann, H. J., "Carcinogenic Bioassay of Benzo(a)
     Pyrene-free Fractions of American Shale Oils," A.M.A. Arch. Pathol,  65,
     608, 1968.

21.  Bingham, E., "Carcinogenic Investigations of Oils from Fos*sil Fuels,"
     University of Cincinnati Kettering Laboratory, Cincinnati. Ohio,  1975.

22.  Sauter, D. Y., "Synthetic Fuels and Cancer," Scientists'  Institute  for
     Public  Information, New York, November 1975.

23.  Schmidt-Collerus, J.J., "The Disposal and Environmental  Effects of  Carbon-
     aceous Spent Solid Wastes from Commercial Oil Shale Operations,"  First
     Annual Report, NSF GI 34 282X1, Washington, D.C., January  1974.

24.  Schmidt-Collerus, J. J., "The Disposal and Environmental  Effects  of Carbon-
     aceous Solid Wastes from Commercial Oil Shale Operations,  A Synopsis of
     of the Results of the First Year's Research Program," National Science
     Foundation, June 1974.

25.  Selikoff, I. J., et.al., "Inhalation of Benzo(a) Pyrene and Cancer  in
     Man,"First Scientific Assembly of the American College of Chest Physicians,
     Chicago, Illinois, October 30, 1969.

26   Ames, B. N., "An Improved Bacteria Test System for the Detection  and
     Classification of Mutagens   and Carcinogens," Proceedings of the National
     Arch. Sci., Vol. 70, p 782, 1973.

27.  Longnecker, D. S., et.al., "Trial of a Bacterial Screening System for the
     Rapid Detection of Mutagens and Carcinogens," Cancer Research, Vol.  34,
     p 1638, 1974.

28.  Energy Research & Development Administration, "Federal Inventory of Energy
     Related Biomedical and Environmental Research in FY 1974 and FY 1975,
     Vols. Ill and IV, 1975.

29.  Cameron Engineers, Inc., Synthetic Fuels Quarterly, June 1976.



     This chapter is a summary of monitoring projects and studies which have
been or are being conducted in the Piceance and Uinta Basins, and which are
relevant to oil shale development.  Two general classes of programs are con-
sidered:  (1) private and/or specialized projects and (2) projects connected
with the Federal Prototype Oil Shale Leasing Program.  Section 6.1 is a cata-
log and brief description of various activities, most of which have been con-
ducted independently of each other.  Section 6.2 is a narrative summary of and
commentary on the monitoring programs of the lease tracts.  Section 6.3 pro-
vides some comments about monitoring programs with focus on scope, quality,
and the availability of data and results to interested parties.


     The major companies with interest in oil shale and several other organi-
zations have been involved in various aspects of baseline environmental moni-
toring.  Some of the data and results of the private programs are publically
available and have been published in research papers, conference proceedings,
Environmental Impact Assessments or statements, and other documents.   For
example, the Colony Development Operation has conducted and published the
results of numerous monitoring, modeling, and mitigation studies (1,2).  Many
additional studies have been discussed and referenced in the preceding chap-
ters of this report.

     Other data or findings are not generally available to the public at pre-
sent.  However, EIA or EIS reports are expected from Union and Occidental in
the next year or so if the climate for commercial development improves.

     Tables 6-1 through 6-4 summarize the projects dealing with meteorology
and air quality, surface and ground water, solid wastes, and revegetation.  The
tables are largely self explanatory.  Although the attempt was made to cover
all projects which have been conducted or are known to exist at present, no
doubt some activities are not listed.  The major information sources for Tables
6-1 to 6-4 are References 3,4,5, and 6.


     After the final EIS prepared by the Department of the Interior was ap-
proved in 1973, six 5,120-acre tracts (two each in Colorado, Utah, and Wyoming)
were offered for lease in 1974.  (See Section 2.4)  No bids were received for
the Wyoming tracts and, as envisioned in the EIS, the two contiguous Utah
tracts opted to operate jointly so that the three operations at present are

           Table 6-1.   Summary  of Meteorology and Air Quality Monitoring  and Studies
Quality Monitoring
Data - Ground Level
Inversion &
Diffusion Studies
Health Hazard Studies
& Control Technology
Union 011
S02, THC, NOX, Particu-
lates monitored at
Parachute Creek plant
site, other valley &
plateau locations.
Trace elements in
particulate matter also
measured.  Started

Two stations started
1974 - particulates.
One station - SO?, NO*,
 Hi-Volume Particulate
 samplers located
 at expected max stack
 plume concentration
 site and at plant site.
 Recently added gaseous
 pollutant monitors.

 Plant site monitoring
 of ambient air quality
 planned for 1977.
Wind speed, direction,
temp, relative humidity
precipitation at 8
stations in Parachute
Creek Valley &
Plateau.  Started 1971.
Wind speed, direction,
temp, relative humidity
at 9 stations, 30' &
200' levels.  Precipi-
tation, evaporation at
5 stations.  Started
July 1975.

2 met. stations, on &
near plant site -
wind speed, direction
Started 1972.
Wind speed, direction
temperature, humidity
at 4 sites; precipi-
tation at one site.
Balloon & tracer
studies, started in
1972.  Diffusion
Upper air studies
July, Oct. 1974 &
Jan. April 1975.
t  Mine dust studies -
   respirable concentra-
   tions, size characteris-
   tics, TLV estimates.
  Dust & diesel emission
   control techniques.
  Spent shale dust
   carcinogenic studies.
   Not known
Upper air and invers
                                                                                   on  Particulate sampler at
                                                                                       mine collects samples for
                                                                                       carcinogenic testing.
Upper air studies
planned for 1977.

                   Table 6-2.  Summary of Surface and Ground Water Monitoring Activities
US Geolo-
US Weather
Energy Adm.
to Colo. St.
Stream Flow
Spring flow
being monitored
at 70 locations
1n Plceance
Creek Basin
Streamflow being
monitored at
more than 50
locations on
Colorado River
and major tri-
butaries. All
thru Plceance Ck.
basin, USGS moni-
tors 21 addition-
al stations for
flow with the
support of
USGS to monitor
for spring flow
along Parachute
8 Roan Creeks.

Surface Water Quality
Spring water quality
>e1ng analyzed for 70
locations In Plceance
Creek Basin
tater quality and sedl-
nent analyzed for all
stations operated by /
nonltor spring water
juallty along
'arachute and Roan
Creeks .

Ground Water
Pumping Tests
& Water Quality

Groundwater data
collected on 97 wells
by USGS as part of
COSEP study (Includes
data on test lease
tract). USGS has drll
led 22 holes at 11
locations for testing
In 1976 - water occa-
sionally monitored at
domestic wells and
open holes along

tunoff Studies

Maintain weather
stations at towns
1n the area -
plus Little Hills
station 1n the
Plceance Cr. Basi

& Other Studies

USGS modeling studies
reported 1n Prof.
paper 908 and various
open file reports.
Describe simulated
effects of develop-
ment on hydrology of
Plceance Creek basin.
All electronic com-
puter simulation
model to determine water
availability In the White
River Basin.

             Table 6-2.  Summary of Surface and Ground Water Monftorfng  Activities  (Contd)




Cor s 1m II
17 Organi-
others may
join at
Stream Flow
3 gauging sta-
tions on Para-
chute Creek
6 gauging sta-
tions on Para-
chute Creek

Interml ttent
drainages at
rock dumping
site monitoring.
started 1975.
USGS gauging
station on
Plceance Creek,
on Superior

Surface Water Quality
15 stations In Para-
chute Creek Basin.

Periodic sampling
since 1958. 6 weekly
stations started 1n
Water quality samples
for springs & Inter-
mittent flows of
streams .

 Sediment @ one site,
Plceance Creek.
 4 chemical quality
stations on Parachute
 2 chemical quality
stations on the
White River.
 Chemical quality on
Alkali Springs

Ground Water
Pumping Tests
& Water Quality
Not known

Pumping and water
quality testing at
5 wells .started
Jan. 1975.
Mine water quality
samples taken.

 Fluid level record-
Ing on 7 coreholes,
Pump testing of 2
coreholes 1n leach
zone by USGS, plus
Runoff Studies
Runoff & salt load
study for upper
Parachute Creek.
Precipitation at 5
stations in
Parachute Creek

Not known

 Water quality 1n two
abandoned cable tool
wel 1 s .

Model 1 ng
& Other Studies

An electronic com-
>uter simulation
model of the White
i Colorado River
Basins to simulate
operating conditions
and Input parameters
:o be determined by
the user.

                        Table  6-3.  Summary of Spent Shale/Solid Waste Disposal  Projects
Physical Stabilization/
Properties of Spent Shale
Leaching Studies
         Paraho, Anvil Points
Has conducted or supported several
  Moisture requirements, handling,
   compacting spent TOSCO II shale.
  Nine backfilling
  Uquifactlon studies of disposal
  Slope stability studies.

Physical properties and compaction
studies in connection with revege-
tatlon research both at Parachute
Creek and at Brea, Calif.

Joint Paraho/USBM/EPA project for
defining retorted shale handling
and disposal systems.  Specifi-
cally aimed at Paraho spent shale
rather than TOSCO type spent shale.
Major emphasis on water requirements,
compaction, permeability and
   Water balance 1n Davis Gulch disposal  area  -
   Irrigation & leaching requirements.
   Leaching studies 1n connection with  revege-
   tatlon work.
   Colony 1s supporting stability & leaching
   of spent shale containing representative
   quantities of other wastes (coke, catalysts,
Leaching studies are part of revegetation
research at Anvil Points by Colorado State
University, and the Paraho/USBM program for
processed shale management.

                                  Table 6-4.   Summary  of Revegetatlon  Projects
Nature of Re vegetation Work
       (Anvil Points)
       TOSCO/Forest Service/
       EPA Project
       R1o Blanco "Shot"
       Test Plots.
       Soil Conservation
       Service Plant
       Materials Center.
1966-1974:  Greenhouse, valley, and plateau tests with TOSCO II spent shale.  Studies on
plant assimilation of trace metals and organlcs from spent shale at Rocky Flats Research
Center.  Colony sponsored several CSU studies of plant growth 1n TOSCO II spent shale.

Revegetation of Union A spent shale at Parachute Creek site, 1965-1967.  Greenhouse
revegetation and leaching studies 1967-1974, at Brea, Calif.  Valley and plateau plots
established 1n 1974 In Parachute Creek area.  Recent work has emphasized Union B spent
shale, since that 1s what will be produced during commercial production.

Revegetatlon test plots on processed Paraho shale were established 1n 1975 at Anvil
Points.  The revegetatlon was highly successful due mainly to the large amounts of water
applied.  Under contract to EPA, Colorado State University has undertaken at Anvil Points
1n 1976, a new, more ambitious program to compare revegetatlon of processed Paraho shale
covered with various depths of topsoll.

The Department of Agriculture established a Surface Environment and Mining (SEAM)  program
some years ago for joint funding by government/industry of rehabilitation projects on
disturbed lands.  TOSCO has entered Into such an agreement with the Forest Service for a
project Involving upper and lower plots in the Parachute Creek/Roan Cliffs area to experi-
ment on revegetatlon of processed TOSCO II shale in realistic situations.  TOSCO further
intends to perform ecosystem studies in conjunction with these  plots.

In 1974, at the site of the Rio Blanco nuclear stimulation test, plots were laid out on
processed shale.  Irrigation was done at irregular intervals and the plots failed.   They
were reconstructed 1n 1975.

The SCS, with support from the Fish & Wildlife Service, EPA, and several  other sources,  has
established a plant materials center in Meeker, Colo, for the Western  Oil Shale Region.
Such a center will help develop & multiply plant materials for various purposes including
processed shale revegetatlon.  Due to the salutory climate and resultant ecosystems in  the
Meeker area, this center will be of limited use for revegetation in the Piceance &  Uinta

                          Table 6-4.   Summary of Revegetatlon Projects (Contd)
Nature of Revegetatlon Work
Wolf Ridge Plots.
84 Mesa Test Plots
Colorado State
Dept. of Natural
Resources/U.S. EPA
Colorado State University has proposed a long range revegetatlon program to  ERDA  (not yet
funded) for work on Wolf Ridge, a few miles east of Tract C-a.   This  proposal  1s  unique
in that it would be a long range ecosystem study rather than a  narrow revegetatlon project.
One obvious difficulty 1s the limited supply of either TOSCO II or Paraho processed shale
for use.

Test plots were laid out on a flat area a few miles northeast of Tract C-a 1n  1973 and
again in 1974 to test the revegetatlon potential of numerous native & exotic grasses,
forbs, and shrubs.  No Irrigation was used.  Some species show  promise.

Test plots at two elevations (5700 ft and 7300 ft) using TOSCO  II and USBM retorted shales.
Several soil thickness layers have been Investigated.  Salinity measurements taken in piles,
leachate, and runoff.  The published results in 1974 indicated  that resalinization follow-
ing leaching of shale can limit the success of vegetative establishment, although some cover
has been partially established at both sites.  Plots are being  monitored to  determine longer
term success.

C-a (Rio Blanco Oil Shale  Project),  C-b  (Roxana Oil Shale Project), and U-a/U-b
(White River Shale Oil Project).

     The lease documents (7,8,9) .contain extensive environmental stipulations
The baseline survey, as defined by the lease stipulations, is a two year study
(one year must be completed  before submission of the Detailed Development Plan)
which must be completed before commercial operations may begin.  The baseline
is to define the environment as it exists now; however, lack of a philosophical
foundation for the baseline  science  has necessitated pragmatic decisions by
federal/state agencies and industries.  This has  led  to differing expectations
about what the baseline survey will  and will not accomplish.  The baseline
survey, as it is now being conducted, is the product of specific lease stipu-
lations plus many months of  joint negotiations between all interested parties
(federal/state/industry).  In the process, the Area Oil Shale Supervisor has
defined and/or added to the  stipulations.

     Because of the lessees' concerns of anti-trust action if baseline studies
were performed jointly, and  because  of varying ecological  conditions on the
tract, the three lessees have mounted distinctly different and separate envi-
ronmental monitoring efforts.  For a first-effort baseline program, multiple
approaches have the advantage of investigating methods for future operations.
But the disadvantage is the  potential difficulty of directly comparing certain
results between the tracts.  At this stage of environmental baseline science,
the advantages probably outweigh the disadvantages.  It would be useful to per-
form a critical review at  the completion of the ongoing environmental programs,
to determine'the most appropriate baseline survey data and methods, and to
standardize the rationale  for future efforts.

6.2.1   Geotechnical Data Gathering

     This part of the baseline survey is not of major environmental interest,
but some parts of this effort have important relationships to the environ-
mental survey.

     Geology:  Each lessee has conducted the classical core-hole drilling and
logging program to define  reserves on the tract.   Fischer  assays for shale
richness, sodium and aluminum analyses for recoverable Nahcolite and Dawson-
ite, and analyses for seven  trace elements (As, B, Cd, F,  Hg, Sb, Se) have
been made on core samples  to investigate resource and environmental potentials.
Interpretation of some of  these data has been inconclusive to date.  For ex-
ample, there is general lack of knowledge of the mobility, bioavail ability,
and hazards associated with  trace elements.

     Hvdrology:  The presence and location of aquifers has been determined by
all the lessees-  Because mine dewatering is necessary for both underground
and open-pit mining, the lessees  have modeled subsurface aquifers for
eventual dewatering operations.   Baseline water quality has been extensively
measured (both ordinary chemical  parameters  as well  as trace elements) even
though the lessees propose a "no  discharge"  practice for effluent waters from
commercial operations.

6.2.2  Environmental Baseline Programs (6JO.11,12)

     This program can be divided into two sections:  those projects that are
continuous over a two-year interval and those that essentially are "one-shot"
programs that may or may not need to be completed within the two-year time

     Air Quality and Meteorology (AQ & MET):  Each tract, by lease stipulation,
is to have four AQ-MET stations on or about its property (eight for the joint
U-a/C-b).  Both C-a and C-b have two stations fully instrumented for AQ para-
meters (S02, H2S, NO, NOX, 03, Cfy, CO, nonmethane hydrocarbons, particulates)
and two partially instrumented.  U-a/U-b has three stations fully instrumented.
The initial requirement, now changed, was 90% recovery of AQ data.  It should
be noted that approximately 5-9% of total time is needed for calibration
and zeroing of certain instruments.  Difficulties are encountered in operating
such remote stations, and the 90% recovery requirement may be hard to meet.

     MET stations are coincidental  with AQ stations.   The "main" station has
either a 30 to 60 meter tower taking data at three levels.   Wind speed and
direction, temperature, humidity, rainfall, and solar isolation, delta T and
wind sigma are obtained for use in modeling.  The ancillary stations have 10
meter towers measuring the normal MET parameters (eg, wind speed and direc-
tion).  The lease requirement for 95% data recovery has not been too difficult
to meet to date.   Isolated cases have occurred, such  as a solar insolation
meter being "knocked out" by lightning flashes.

     Upper Air Studies and Diffusion Modeling:  Although not a part of the
original lease stipulations, lessees have been required to perform four quar-
ters of upper air studies, 15 actual days each quarter.  (Tracts C-a and C-b
have conducted a fifth quarterly study.)  These studies are necessary for dif-
fusion modeling and demonstration of compliance with federal/state air quality

     Tract C-a had planned tracer studies to validate the diffusion model, but
these plans were initially aborted due to dust problems.  However, RBOSP has
recently completed field work in connection with tracer studies.  These studies
will be essential to ultimate plant design and should have been made part of
the lease stipulations.

     Tracts C-b and U-a/U-b have acoustical sounders  to measure inversion
layers.  The upper air studies have also provided inversion data albeit on a
less continuous basis.

     Terrestrial  Biology:  The greatest variations and difficulties in the
baseline programs are to be found in the biological  studies.  Despite the con-
certed efforts of the International Biological Programs, no standard method of
evaluating biological ecosystems is entirely agreed upon.  Both techniques of
measurement and methods of modeling ecological interrelationships remain an
enigma.  All three tracts are performing more or less complete analyses of the
flora and the small mammal fauna.  These components essentially determine the
local ecosystem dynamics.  But the "politics" of big game animals and birds
have influenced the focus and efforts of the programs.  Further, considerable


effort is being placed on investigations of amphibians and reptiles, while
far less is being placed on the invertebrate populations, especially on the
effects of grazing pressure in these ecosystems.

     The leases stipulate bimonthly sampling periods.  Sampling periods pat-
terned after animal activity patterns instead of arbitrary calendar periods,
could perhaps be more useful.

     Game Management Plan:  The lease stipulations requires lessees to formu-
late game management plans on and about the tracts.  Since game management is
a responsibility of federal/state agencies, it is not certain how such plans
can interrelate with government programs without usurping their powers and
authority.  To date, the game management plans consist mostly of species lists
and a cooperative attitude between industry/government.

     Aquatic Biology:  The aquatic biological component of the baseline survey
is actually geared to more humid regions.  Major streams and rivers are well
monitored with slightly less emphasis on seeps, springs, and intermittent
creeks.  Phytoplankton, zooplankton, periphyton, benthos, macrophytes, and
fish are being measured.  If these data can be related to terrestrial eco-
systems, they will be of compelling interest.

     Water quality (W.Q.) data is being intensively collected at each aquatic
biology station.  These data are of the utmost importance and will be abso-
lutely necessary for future comparisons after commercialization.  All normal
parameters plus trace elements are being measured.  Other W.Q. data is being
collected in cooperation with the U.S.G.S. programs (Table 6-2).

     Soil Mapping and Analysis:  Adequate soils maps and knowledge of the
interrelationships of soil and flora are essential not only to an understand-
ing of local ecosystem dynamics but also to proper long-term revegetation
planning.  All three lessees have completed soils data gathering projects.

     Revegetation:  Lease stipulations require an acceptable and demonstrated
plan in the Detailed Development Plan or firm plans to obtain such acceptable
revegetation before commercialization.  Each of the lessees  because of dif-
fering mining procedures and local ecosystems, has proposed different revege-
tation plans and has undertaken its own unique testing program to prove the
benefits of these plans.  C-a lessees,proposing open-pit mining, plan to cover
processed shale with overburden sized to prevent upward capillary movement of
salts.  C-b proposes to revegetate on about six inches of topsoil placed
directly over processed shale.  U-a/U-b plans to terrace processed shale, coat
the surface with a temporary impermeable plastic, form trenches of soil in
the low spots, and use these as water catchment systems.  Water is not nearly
IIgre^t aP pro'blem in Colorado's Piceance Creek Basin as  n Utah's Uinta Basin.
All lessees are undertaking trials of these systems with U-a/U-b performing the
most extensive work.

     Toxicology:  Processed shale contains small amounts of potentially haz-
ardous o>ginic compounds.  The potential carcinogenicity problem is only part
of thl S2J5ll toxicology problem associated with any new material and process.
The lessees of Tract C-b, through their connection with the Colony Development


operation, have contracted for extensive carcinogenic animal testing programs,
from which results are now beginning to appear.  The lessees of tract C-a have
openly spoken of plans to perform an extensive overall toxicology program not
only on spent shale but on shale oil and its products, but the program has not
begun to date.

     Trace Element Analyses in the Ecosystem:  One of the unresolved questions
in revegetation plans is whether processed shale piles will  introduce danger-
ous levels of trace elements into the environment either through erosion or
through uptake into plants.  A baseline is needed for levels of these elements
in the local ecosystems (see Section 6.2.1).  All three lessees are conducting
somewhat different programs to measure present levels in soils, flora, and

     Archaeology, Paleontology, and Historical  Values:  Federal laws require
archaeological,  paleontological,and historical  clearance of areas before dis-
turbance.  All lessees have mounted and finished extensive,  professional clear-
ance projects on and about the leases.

     Visibility and Scenic Studies:  Lessees have undertaken visibility studies
by photographic techniques, which should be most useful as a check on air
quality degradation from future pollution.  However, other scenic* values are
rather subjective, and descriptive techniques are the only available measuring

     Ecological  Interrelationships:  The leases stipulate that ecological
interrelationships be addressed,  which is a requirement of the National  Envi-
ronmental Policy Act (NEPA).  However, in the strictly scientific sense, it
is not yet known how to adequately treat this requirement.  It has been ad-
dressed in many ways in the Detailed Development Plans (eg,  by descriptive
words and by charts), but adequate models have  not been developed.

6.2.3  Continuous Monitoring Programs

     After the baseline studies are completed and when conmercialization
begins, a continuous monitoring program is to be undertaken  to compare the
ecosystems "before and after" and to serve as a warning system for possible
degradation of the environment.  As stated in the Detailed Development Plans,
the lessees plan to continue the baseline studies at a less  intensive but
sufficient level to measure changes that may occur.  There is little need for
a separate and distinct transition period unless a long delay ensues between
the end of the two-year baseline study and the beginning of commercial opera-
tions.  In such an event, the lease stipulates  that monitoring begin six
months before commercialization.   Monitoring will continue for the life of
the project and for that amount of time afterward necessary to ensure compli-
ance with lease stipulations.  Source monitoring will also be necessary once
construction and commercial operations begin on the tracts.


     The projects listed and summarized in this chapter differ dramatically
in scope, purpose, and approach since the goals of individual sponsors vary.


For most of the potential environmental impacts associated with oil shale
development, a corresponding project or series of projects aimed at baseline
or impact monitoring, or at mitigation, exists.  The use of data and project
results to assess environmental impacts on both a site-specific and regional
basis is difficult for three primary reasons.  First, information is fragmented
and in many cases, not publically available.  Secondly, the types of data
gathered have been dramatically different for different projects.  Thirdly,
the reporting and formating of data and information has not been uniform.  A
few comments regarding the adequacy of data and programs dealing with air,
water, solid wastes, and revegetation are presented below.

6.3.1  Air Quality and Meteorological Monitoring

     Adequate baseline air quality and surface meteorological data have been
or are being collected at most development sites.  As development proceeds,
source monitoring should be initiated.  Upper air studies have been conducted
at most sites, and the results are sufficient to indicate maximum impact sites
for placing ambient source monitors.  Additional upper air studies may be
needed for model input purposes (to define local inversion, turbulance, etc.).

6.3.2  Surface and Ground Water Monitoring

     If present surface water gaging stations are maintained, it appears that
adequate background data will be available for determining the effects of
direct discharges of most oil shale development activities on surface water.
A possible  exception is Occidental; adequate information is not available
for appraising their baseline monitoring program at present.

     Considerable subsurface hydrologic testing has been conducted in the
Piceance Creek and Uinta basins.  In the southernPiceance Creek and eastern
Uinta basin, the hydrology is reasonably well known, and adequate monitoring
programs have been or can be developed for determining the effects of oil
shale activities on subsurface waters.  However, in the northern part of the
Piceance Creek basin interpretations differ substantially as to the effects
that oil shale development may have on the hydrologic regime.  The crux of the
problem is the extent to which rich oil shale units within each of the two
major aquifers impede vertical flow.  Until sufficient data are available to
define vertical flows, adequate prediction of the effects of activities such
as mine dewatering on the surface water flows and quality cannot be made.
None of the current water monitoring programs are designed to obtain the in-
formation required for better characterization of the aquifer systems   One
approach might be to establish a program of pump Jesting of individual wells
at distinct depth intervals, and monitoring water levels in two or more nearby

6.3.3  Solid Wastes

     Several projects have addressed retorted shale handling and disposal.
Activities supported by Colony and Union in particular, have contributed greatly
to design and operational planning for retorted shale disposal.  A recent
Colony project, for example, is aimed at determining physical properties and
leaching potential of processed shale containing representative amounts of


other solid wastes (spent catalyst, coke, lime sludges, etc.).

     All research and monitoring programs to date have dealt with relatively
small quantities of retorted shale.  Potential problems such as mass stabili-
zation of shale piles, or the maintainence of an impervious layer below plant
root zones, can likely be defined and solutions found only by creation of a
large pile.  Commercial scale oil shale processing will be necessary in order
to allow the necessary experiments to be performed.

6.3.4  Revegetation

     Numerous experiments and studies have been directed toward demonstrating
vegetative stabilization of the surface of retorted shale piles.   The appli-
cability of the findings of such studies to large scale revegetation of re-
torted shale may not be straightforward.  Plot experiments have been conducted
mainly at valley sites in Piceance Basin, and the results may have no rele-
vance to plateau sites in Uinta basin.  Irrigation, mulch, and fertilizer
applications found to be successful in experimental plots may not be practical
for large plots.  Plant succession and the establishment of deep rooted shrubs
and trees have not been (and perhaps may not easily be) adequately researched.
One inherent problem for more extensive revegetation research and monitoring
is the current shortage of retorted shale.

 1.   Colony Development Operation, "An Environmental  Impact Analysis  for a
     Shale Complex at Parachute Creek, Colorado, Part 1,"  1974.

 2.   Colony Development Operation, "Draft Environmental  Impact Statement/Pro-
     posed Development of Oil Shale resources in Colorado," U.S.  Department of
     the Interior, Bureau of Land Management, December 1975.

 3.   Spence, H.  M., et.al., "Summary of Industry Oil  Shale Environmental Studies
     and Selected Bibliography of Oil Shale Environmental  References," Oil
     Shale Committee of the Rocky Mountain Oil  and Gas Association, March 1975.

 4.   Cameron Engineers, Inc., "Synthetic Fuels  Quarterly,  Vols. 12 and 13,
     January 1975 through June, 1976.

 5.   Shale Country. Mountain Empire Publishing, Inc., Vols. 1 and 2,  January
     1975 to June 1976.

 6.   Information provided by Thomas A. Beard and Richard B. Schwendinger,
     independent consultants.

 7.   U.S. Bureau of Land Management, "Tract C-a Oil  Shale  Lease," U.S. Depart-
     ment of the Interior, Denver, Colorado, 1974.

 8.   U.S. Bureau of Land Management, "Tract C-b Oil  Shale  Lease," U.S. Depart-
     ment of the Interior, Denver, Colorado, 1974.

 9.   U.S. Bureau of Land Management, "Tract U-a Oil  Shale  Lease"  and  "Tract
     U-b Oil Shale Lease," U.S. Department of the Interior, Denver, Colorado,

10.   Detailed Development Plan, Vols. I and II, Federal  Oil Shale Lease Tract
     C-b, submitted to Area Oil Shale Supervisor, February 1976.

11.   Detailed Development Plan, Vols. I-V, Federal  Oil  Shale Lease Tract C-a
     (Rio Blanco Oil  Shale Project), submitted  to Area Oil  Shale  Supervisor,
     March 1976.

12   Detailed Development Plan, Vols. I and II, Federal  Oil Shale Lease Tracts
     U-a and U-b, submitted to Area Oil Shale Supervisor,  June 1976.

                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
                                                            3. RECIPIENT'S ACCESSION-NO.
             5. REPORT DATE
               July 1977 issuing date
  K. W. Crawford, C. H. Prien,  L.  B.  Baboolal,
  C. C. Shih and A. A. Lee
                                                            8. PERFORMING ORGANIZATION REPORT NO.
  TRW, Inc.                Denver  Research Institute
  One Space Park          P.  0. Box 10127
  Redondo Beach,          Denver,  Colorado  80210
  California  90278
              10. PROGRAM ELEMENT NO.
                EHE 623
             11. CONTRACT/GRANT NO.
  Industrial  Environmental Research Laboratory-Cin.,  OH
  Office of Research and Development
  U. S. Environmental Protection Agency
  Cincinnati,  Ohio   45268
                Preliminary 7/75  - 7/76
       The  report is a summary of major oil shale extraction and retorting develop-
  ment activities.   The potential impacts on the physical environment which could
  result from commercial oil shale  development are discussed relative to  sources,
  properties,  and quantities of wastes.   The report describes existing air, water,
  and land  resources in northwestern  Colorado and northeastern Utah.  The identi-
  fication  of potential impacts of  oil shale development  on these resources, pollu-
  tion control technologies and management plans are reviewed.  Potential hazards
  associated  with refining and end  use of shale oil products are evaluated.  The
  major environmental monitoring and  impact studies are identified, and the scope
  of oil shale development projects is assessed by this document.
                                KEY WORDS AND DOCUMENT ANALYSIS
c.  COSATI Field/Group
  Oil Shale
  Waste Disposal
  Air Pollution
  Waste water
  Solid Waste
  Land Disposal
                                              19. SECURITY CLASS (This Report)
                           21. NO. OF PAGES
                                              20. SECURITY CLASS (This page)
                           22. PRICE
EPA Form 2220-1 (9-73)
                                                     . U S. GOVEMHENT HINTING OFFICE: <977-757-056/6li87 Region No. 5-11