EPA-600/2-75-009
                                                            May 1975
OIL  SHALE AIR  POLLUTION CONTROL
                         by

                    Evan E. Hughes
                    Patricia A. Buder
                    Carmen V. Fojo
                    Robert G. Murray
                    Ronald K. White
                Contract No. 68-01-0483
                       PEMP 02
              Program Element  1NB458


                    Project Officer:

                   James C. Johnson
                 Air Technology Branch
            Office of Research and Development
            U.S. Environmental Protection Agency
                 Washington, D.C. 20460
                     Prepared for:

            Office of Research and Development
            U.S. Environmental Protection Agency
                 Washington, D.C. 20460

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                               ABSTRACT








     This study evaluates the air pollution  potential  of  emissions  of




particulates,  sulfur dioxide, oxides of nitrogen,  and-hydrocarbons  from




the anticipated development of an oil shale  industry.   The  analysis is




based primarily on the published description of  a  TOSCO II  retorting




process as planned for commercial use by the Colony  Development Operation




The technology, processes,  plans, projections, and environmental  impacts




of oil shale development are reviewed.   The  results  of dispersion model




calculations of concentrations of pollutants in  ambient air near  oil




shale plants employing TOSCO II and in situ  processes  are presented.




These calculations for the TOSCO II plant assume that  best  available




controls are applied to the process planned  by Colony. Requirements for




additional control are estimated by comparing calculated  ambient  air



quality with standards.  Options for supplying the additional  control




indicated for particulates and sulfur dioxide are  identified.





     This report was submitted in fulfillment of Contract 68-01-0483 by




Stanford Research Institute under sponsorship of the U.S. Environmental



Protection Agency.  Work was completed as of May 1979.
                                  11

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                                 CONTENTS








ABSTRACT	     iii





LIST OF ILLUSTRATIONS	       v





LIST OF TABLES	     vii





UNITS OF MEASURE	      ix





ACKNOWLEDGMENTS  	     xii







   I  CONCLUSIONS  	 	       1





  II  RECOMMENDATIONS  	       3





 III  INTRODUCTION 	       5





  IV  OIL SHALE TECHNOLOGY AND PROCESSES  	       9





   V  PLANS AND PROJECTIONS FOR OIL SHALE DEVELOPMENT  	      23





  VI  ENVIRONMENTAL EFFECTS OF OIL SHALE DEVELOPMENT   	      31





 VII  AIR POLLUTION:   EMISSIONS AND AMBIENT AIR QUALITY  ....      41





VIII  CONTROL REQUIREMENTS FOR AIR POLLUTANTS	      77





  IX  ASSESSMENT OF AIR POLLUTION CONTROL METHODS  	      87
                                   iii

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                             ILLUSTRATIONS
 1   Processes,  Streams,  and Emissions  for Production
     of Oil from Shale  ..........  ..........       14
 2   TOSCO II  Plant  Configuration   ..............       18
 3   In Situ Plant Configuration  ...............       20
 4   Map of Oil  Shale Plant Locations   ............       25
 5   Annual Frequency Distributions  of  Wind  Direction
     at Four Colorado Sites   .................       46
 6   Annual Frequency Distributions  of  Wind  Speed
     at Four Colorado Sites   .................       48
 7   Annual Average Particulate  Concentration
     for a TOSCO II  Oil  Shale Plant Using  Grand  Junction,
     Colorado Meteorology  ..................       54
                                                   o
 8   Annual Average Particulate  Concentration  (|jg/m )
     for a TOSCO II Oil Shale Plant  Using Salt  Lake City,
     Utah Meteorology  .................... •      55
 9   24-Hour Worst Case Average  Particulate Concentration
     (pg/m3) for a TOSCO  II  Oil  Shale Plant Under Conditions
     of Neutral Stability;  and a North Wind of  1.5 m/sec  ...       56

10   24-Hour Worst Case Average  Particulate Concentration
     (pg/m3) for a TOSCO  II  Oil  Shale Plant Under Conditions
     of Neutral Stability and a  West Wind of 1.5  m/sec    ...       57

11   Annual Average S02 Concentration (pg/m3)  for a TOSCO  II
     Oil Shale Plant Using Grand Junction,  Colorado
     Meteorology .......................       58
                                           o
12   Annual Average SO2 Concentration ( )jg/m )  for a TOSCO  II
     Oil Shale Plant Using Salt  Lake City,  Utah Meteorology.  .       59

13   24-Hour Worst Case Average  S02  Concentration ((jg/m3)
     for a TOSCO II Oil Shale Plant  Under Conditions of Neutral
     Stability and a North Wind  of 1.5 m/sec ........       60
                                                      o
14   24-Hour Worst Case Average  S02  Concentration (pg/m  )
     for a TOSCO II Oil Shale Plant  Under Conditions of Neutral
     Stability and a West Wind of 1.5 m/sec  .........       61
                                   IV

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15   3-Hour Worst Case Average HC Concentration (p,g/m3)
     for a TOSCO II Oil Shale Plant Under Conditions  of  Neutral
     Stability and a North Wind of 1.5 m/sec	      62
                                                     q
16   3-Hour Worst Case Average HC Concentration (p.g/m )
     for a TOSCO II Oil Shale Plant Under Conditions
     of Neutral Stability and a West Wind of 1.5 m/sec	      63

17   Annual Average NO  Concentration (^g/m3) for a TOSCO II
                      A
     Oil Shale Plant Using Grand Junction,  Colorado
     Meteorology	        64
                                           o
18   Annual Average NOx Concentration (pg/m ) for TOSCO  II
     Oil Shale Plant Using Salt Lake City,  Utah Meteorology.  .        65

19   Simplified Process Diagram—Above-Ground Retorting
     Plant	        90

20   Ore Preparation System for TOSCO II  Plant	        92

21   Pyrolysis and Oil Recovery Unit for  TOSCO II Plant   ...        96

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                                  TABLES
 1    Identification of Streams Shown in Figure 1 	    15
 2    Stack Parameters and Emission Rates for a 16,000
      m3/D (100,000 B/D) TOSCO II Plant with Emissions
      Controlled	    17

 3    Stack Parameters and Emission Rates for a 16,000
      m3/day (100,000 B/D) In Situ Plant	    21

 4    Shale Oil Plant Locations and Types   	 .....    24

 5    Required Oil Shale Industry Growth Rates to Meet
      Selected Goals  	    28

 6    Estimates of Water Use in Oil Shale Production
      (m  of water per m3 of oil produced)	    34

 7    Estimates of Air Pollutant Emission Factors in Oil Shale
      Production	    37

 8    Stack Parameters and Emission Rates for a 16,000 m3/D
      (100,000 B/D) TOSCO II Plant with Emissions Controlled  ...    53

 9    Control Requirements Based on Federal Primary and
      Colorado Air Quality Standards and Emissions from a
      16,000 m3/day (100,000 B/D) TOSCO II Plant, Controlled  ...    66

10    Control Requirements Based on Federal Secondary, Class I
      and Class II Air Quality Standards and Emissions from a
      16,000 m3/day (100,000 B/D) TOSCO II Plant, Controlled  ...    67

11    Control Requirements Based on Federal Primary and Colorado
                                                         o
      Air Quality Standards and Emissions From a 16,000 m /day
      (100,000 B/D) In Situ Plant	    70

12    Control Requirements Based on Federal Secondary, Class I
      and Class II Air Quality Standards and Emissions from a.
      16,000 m3/day (100,000 B/D)  In Situ Plant	    71

13    Estimates of Additional Control Requirements for a
      16,000 m3/day (100,000 B/D)  TOSCO II Plant Based on
      Dispersion  Modeling and Various Ambient Air Quality
      Standards	    79
                                    vi

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14    Emissions from Combustion in the TOSCO II  Process
      Compared with Federal Standards for Utility Boilers 	     82

15    Range of Reasonable Requirements for Control Beyond
      Best Available for a 16,000 m3/day (100,000 B/D)
      TOSCO II Oil Shale Plant	     84

16    Ore-Preparation System Emissions for TOSCO II Plant
      (16,000 m3/day) 	     93

17    Typical Fuel Consumption Schedule for TOSCO II Plant*
      (16,000 m3/day) 	     97
                              *
18    Emission Factors for TOSCO II Plant Planned Fuels 	     98

19    Pyrolysis and Oil  Recovery Unit Emissions  for TOSCO
      II Plant (16,000 m3/day) .  .  . '	     99

20    Product-Upgrading System Emissions for TOSCO II Plant
      (16,000 m3/day) 	    100

21    Totals of Emissions for TOSCO II Plant (16,000 m3/day)   .  .  .    101
                                   vn

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                            UNITS OF MEASURE








     Conversion of U.S. units of measure to the metric system is now




proceeding rapidly.  Several agencies of state.and federal governments



now call for the use of metric units (e.g., the geothermal group of the



California Division of Oil and Gas).  The Environmental Protection Agency



has required the use of metric units in this report.





     .SRI has, therefore, employed the International System of Units (SI),



which is based upon the meter, kilogram, and second as the basic measures



of length, mass, and time.  Within this system,  energy units are derived



combinations of the basic units.  The preferred unit for energy is the



joule.





     During the period of changeover to metric units, a certain amount of



confusion must be expected—especially since energy is measured in such



various units as Btu, joules, kilocalories, barrels of oil equivalent,



kilowatt hours, therms, and so on.  To minimize this confusion, SRI has



expressed energies in joules or multiples of the watt hour and made sparing



use of hybrid units, such as metric ton and the engineering units of the



English system.  The prefixes kilo, mega, and tera are sometimes used



in accordance with standard SI practice.  The following listing summarizes



the most common conversion factors that readers may want to have



available while reading this report.  A list at the end of this section



presents a few conversion factors of special importance in discussion of



oil production and air pollution.





     Further information on the International System of Units can be



found in Special Publication 330, National Bureau of Standards,



Department of Commerce.





                                  viii

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Energy
                        3
     1 Btu = 1.055  X  10  joule  (J)

                        -4
     1 Btu = 2.929  X  10   kilowatt  hour  (kWh)

                        6
     1 kWh = 3.600  X  10  .joule  (J)

                        3
     1 kcal =  4.186 X 10   joule (J)
Length
                         -2
     1  inch  =  2.540  X 10   meter (m)


     1  inch  =  2.54 centimeter (cm)


     1  foot  =  0.3048 meter (m)


     1  yard  =  0.9144 meter (m)


     1  mile  -  1.609  kilometer (km)
 Mass
      1  pound  =  0.4536 kilogram (kg)

                                2
      1  ton (short)  = 9.072 X 10  kilogram (kg)


      1  tonne  =  1  metric ton (AIT)

                       3
      1  metric ton = 10  kilogram (kg)
 Area
      1  acre  =  0.407 hectare (ha)

                         3                2
      1  acre  =  4.047 X 10  square  meter (m )

                                -2                2
      1  square  foot - 9.290 X 10   square meter (m )

                                6                 2
      1  square  mile = 2.590 X 10  square meter (m )

                                            r    '^~\
      1  square  mile = 2.59 square  kilometer l(km)  J
Volume
                              -2                3
     1 cubic foot = 2.832 X 10   cubic meter  (m )

                          -3               3
     1 gallon = 3.785 X 10   cubic meter (m )

                                           3
     1 barrel (oil) = 0.1590 cubic meter (m )
                                   ix

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Pressure
     1 pound per square  inch = 6.895  X  10   Pascal  (Pa)

               5
     1 bar = 10  Pascal  (Pa)

                              5
     1 atmosphere = 1.013 X 10  Pascal  (Pa)

                            2
     1 Pascal = 1.0 newton/m
Equivalents
Factor
-3
10
-2
10
-1
10
1
10
2
10
3
10
6
10
9
10
12
10

Prefix

milli

centi

deci

deka

hecto

kilo

mega

giga

tera

Symbol

m

c

d

da

h

k

M

G

T
Conversions especially important in this report:



     •  Oil—1 m3 = 6.3 barrels



     •  Particulate loadings--! mg/m  = 0.00043 grains/ft3


                                  3              r>
     •  Volumetric flow rates—1 m /sec = 2120  ft°/min
        Emission factors—1 kg/GJ =2.3 Ib/million Btu

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                           ACKNOWLEDGMENTS








     This study was organized within the Operations Evaluation Department



of SRI.  The project leader was Evan E.  Hughes.   Supervision was exercised



by Edward M. Dickson, Manager of the Resources Program of the department.



Ronald K. White had major responsibility in the study as the author of the



sections of the report dealing with air pollution control technology.





     Robert G. Murray of the Chemical Engineering Group contributed the



sections on oil shale technology and the plans of the industry.  He also



provided other members of the project team with insights and information



on oil shale processes and plans.





     Carmen V. Fojo of the Energy  Technology Department reviewed various



sources of information on the environmental effects of oil shale development



and organized a summary of such effects for this report.





     Patricia A. Buder of the Atmospheric Sciences Laboratory carried out



the dispersion modeling of air pollution from oil shale production and



wrote the section of the report discussing such results.  Support in this



work was provided by Francis L. Ludwig.   Walter F. Dabberdt supervised this



aspect of the project.





     Elizabath D. Gill of the Literature Research staff of the SRI library



provided support for the project.   This work was supervised by Ardra F.



Fitzgerald.
                                  xi

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                            I   CONCLUSIONS





     During the next decade a commercial oil  shale industry could develop



 in western Colorado and eastern Utah  and grow to a production capacity



 of 80;000 m3/day  (500,000 barrels/day) of oil.  The TOSCO II retorting



 process  is likely to be used in most  of the first generation plants.




     Colony Development Operation has published a detailed environmental



impact analysis of a  proposed  TOSCO II oil  shale plant.   A number of



 air pollution control systems are included in the proposed plant, but the



 level of control is less than that attainable with the best available



 control  technology.




     Application of best available control technology would result  in



 improved removal of particulates by cyclones, baghouses, and wet scrubbers,



 thereby  reducing overall particulate  emissions  to about  a third  of  the



 level specified in the Colony publication.




     More extensive treating of fuels burned in the plant would  constitute



 the application of best available control to the emissions of SO^ and



NOX.   This would reduce S02 emissions by about  15 percent and NOX



emissions by about 50 percent.



                                                                 o

     Atmospheric dispersion modeling  of emissions from a 16,000  m /day



 (100,000 B/D) TOSCO II plant having best available controls suggests



that  such a plant can avoid violations of federal primary ambient air



quality  standards for particulates, sulfur dioxide (SOg), hydrocarbons



 (HC),  and oxides of nitrogen (NO ).
                                X



     From the same modeling, requirements for controls beyond those



considered to be the best available have been estimated by application



of more  strict ambient air quality standards that can reasonably be



                                   1

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expected to apply in the oil shale region.   The standards most likely to



apply are those for regions that the state  designates as Class II  under



the proposed federal standards to prevent significant deterioration of



ambient air quality in unpolluted areas.  For particulates and sulfur



dioxide, Class II standards lead to the following requirements for



additional control:




     •  Particulates:   85 percent additional control required to


        meet the 24-hour average Class II standard.



     e  SOg:   72 percent additional control required to meet the


        one-year average Class II standard.






     No additional control requirements are indicated for hydrocarbons and



oxides of nitrogen.  This conclusion is based on comparison of calculated



concentrations with the federal primary standards for HC and NO .
                                                               £i


Photochemical oxidant formation was not included in  the dispersion model



use, nor were comparisons made with ambient air quality standards  for



oxidant.

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                         11   RECOMMENDATION S


     Additional efforts are needed to assure that the development of an
oil shale industry does not produce significant degradation of air

quality through emissions of particulates,  sulfur dioxide,  and oxides

of nitrogen.   For each of these three pollutants, the problem and

suggested steps toward a solution are specified below:

     •  Particulates:  Appreciable control  beyond best available is
        required to meet air quality standards applicable in Class II
        regions under proposed federal "non-degradation" standards.  The
        potential contribution of higher stacks and more perfectly
        maintained baghouses to the attainment of this additional control
        should be determined.  The potential for increased  control should
        be specified on a unit operation basis, guided by additional
        dispersion modeling to determine the relative contributions of
        various units to the excessive concentration of particulates.

     •  Sulfur Dioxide (SO2):  These emissions from combustion sources
        within the oil shale plant must be  controlled to a  significant
        degree beyond the emission levels considered best available
        according to new source performance standards for liquid fossil
        fuel  fired boilers.  The additional control is necessary in
        order to meet the Class II "non-degradation" standards expected
        to apply to ambient air quality in  the oil shale region.  Flue
        gas desulfurization and additional  hydrotreating of liquid fuels
        burned in the plant are actions that could be taken to meet the
        requirement for additional control.  No steps to develop new
        control technology, other than continued efforts to improve flue
        gas desulfurization, are recommended for SC^ emissions from oil
        shale plants.

     •  Oxides of Nitrogen (NOV):   No requirement for additional control
                              yi
        has been established by comparison  of dispersion modeling of oil
        shale plant emissions with ambient  air quality  standards.
        However, because the achievement of emissions consistent with
        best  available control are likely to require a  much lower
        nitrogen content in the fuel, some  investigation of the feasibility
        of much more extensive hydrotreating should be  carried out.   This
        has significance beyond the oil shale plant,  because the product
        oil,  with its high nitrogen content,  is a candidate for sale as
        a fuel oil rather than a refinery feedstock.

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     Some recommendations for further research and development are more

general than those classified by pollutant type above.   These are:
     •  Analysis of the tradeoffs between taller stacks and increased
        cleanup of emission or process streams should be made for the
        case of oil shale plants.

     •  Sensitivity analyses of the dispersion modeling and the resulting
        control requirements should be carried out.

     •  Ambient air quality in a region occupied by a number of plants
        should be made the basis of a control requirement determination;
        the sensitivity of the result to various strategies for
        incorporating regional and multiplant considerations should be
        determined and evaluated.

     •  Other oil shale production processes, differing from TOSCO II
        primarily in the retorting stage, should be analyzed to the
        extent practical in the light of available information,  using
        the present analysis as a reference case.

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                          Ill   INTRODUCTION






     This is a report on Phase II of an SRI project in support of energy



research and development planning in the Office of Research and



Development of the U.S. Environmental Protection Agency.  Phase I of this



effort consisted of a survey of the environmental effects of some new



energy technologies and an identification of some research and develop-



ment needs directed toward environmental quality control.  An account of



this previous work is presented in the SRI report, "Control of Environ-



mental Impacts from Advanced Energy Sources," published as EPA-600/2-74-



002, dated March 1974.  Four advanced energy sources were emphasized in



that report:  solar, geothermal, oil shale, and solid wastes.





     The present report emphasizes the air pollution control problems



expected from first generation commercial plants for producing oil from



the shale of the Green River Formation found in Colorado, Utah, and



Wyoming.  The main conclusions of the study have been summarized in the



two preceding sections (Sections I and II).  The following sections



(Sections IV through IX) present the specific analyses that support



these conclusions.  The organization of the following sections outlines



SRI's analysis:





     Section IV reviews the technology and processes for the production



of shale oil.  It builds on the discussion in the previous report (see



Section IV-D and Appendix C of "Control of Environmental Impacts from



Advanced Energy Sources") and focuses on the technology that is nearest



to commercial realization, namely the TOSCO II retorting system.  In-situ



retorting is also reviewed.

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     Section V presents the announced plans of the companies and



organizations of companies that may build plants for the production of



oil from shale during the next decade.  It also discusses projections




of growth of the oil shale industry by three different sources.





     Section VI reviews the general environmental impacts of oil shale




development as presented in the previous report and in some other recent




sources.  The review covers air, water, and land impacts.





     Section VII begins the specific task of quantitatively determining




the air pollution control requirements of the oil shale industry by




presenting the results of some atmospheric dispersion modeling to




determine the concentrations of pollutants in ambient air arising from




omissions from proposed oil shale production facilities.  The facilities




are assumed to employ the best available air pollution control technology.




Hence, this modeling is based on a plant with the emission properties



specified in a later section (Section IX) of the report.  Control




requirements beyond "best available control" are estimated by comparison




of the calculated air pollutant concentrations with various possible




ambient air quality standards.  While the focus is on TOSCO II retorting,




some results are also presented for an in-situ retorting facility.





     Section VIII summarizes the control requirements determined by the



air quality modeling approach of Section VII.  The control required to




bring TOSCO II combustion operations into compliance with new source



performance standards for emissions from fossil fuel fired boilers is



briefly discussed.  The conclusions as to what constitute reasonable




requirements for control beyond the best available are presented in



this section.





     Section IX describes the air pollution control planned for the




TOSCO II retort and oil production complex proposed by Colony Development




Operation.  Tables and figures are used to describe the production

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processes and their associated controls.  Tables describe unit operations



within the total oil production system and present the uncontrolled



emissions, the results of planned controls, and the results of best



available control.   Here "best available" is quantified and specifically



defined for each unit operation.

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                IV  OIL SHALE TECHNOLOGY AND PROCESSES


A.   Introduction

     As the oil shale situation in the western United States slowly

emerges from pilot plant to commercial production, the problems change

in character.  Specific technical problems pertaining to retorting assume

less importance and the problems related to industry requirements assume

greater importance.  The necessity for an organization to solve a wide

range of practical problems in order to get a plant on stream tends to

make it favor proven technology and high reliability over more advanced,

potentially more efficient, but untested solutions.  Thus, while there

are several different types of retorts at various levels of development,

only two or three of the most advanced designs are likely to be placed

in commercial production.

     In addition to a large reserve of adequate quality shale, a suffi-

cient supply of water is an essential prerequisite for a shale enterprise,

Converting oil shale to a salable crude oil and by-products will also re-

quire the following operations:

     •  Mining of the shale and transporting it to the retorts.

     •  Separation of valuable hydrocarbons from the mineral
        residue.

     •  Disposal  of all residues,  effluents and emissions in
        an acceptable manner.

     •  Conversion of the  crude shale oil to a transportable
        product.

     •  Transport of the product and by-products to market.

     •  Disposal  of valueless by-products.

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     Economies of scale in most of the process steps required in a

commercial shale enterprise are of such importance that a small-sized
operation is economically unattractive.  As a result, the industry cannot

start small and make its early mistakes on a small size.  This requirement

to be big limits entry into the industry to groups with relatively large
capital resources.


B.   Underground Mining and Above-Ground Retorting

     The classical method of obtaining and retorting shale is underground

mining followed by above-ground retorting.  It has been practiced in

many places around the world for over 100 years.   The methods developed

for the U.S. shales differ due to the use of modern mining technology and

due to the special characteristics of the shale.   Mining, transporting,

and crushing operations for shale are quite similar to those used in

several rock and mineral industries.   The principal difference lies in

the magnitude of the proposed operations.

     Retorting, on the other hand, is not quite like any existing industry

operation.  It resembles the production of coke from coal, except that

the solid produced (spent shale) is not a valuable product, but is a

liability to be disposed of.  It resembles metallurgical ore roasting,
except that the product is combustible.  These differences in physical

characteristics and product values place severe restrictions on what is
economically possible in retort design.

     Retorting processes can be placed into four classes according to
the method of transferring heat to the shale.

     Class I,External Combustion--Heat is transferred to the shale
     through a wall.  The simplest form of this retort  is a Fischer
     assay device for measuring the amount of oil that may be re-
     covered from a sample of shale.   The shale is placed in a
     closed container and heated by means of a fire outside the
     retort.  The retorted gas and liquids are uncontaminated by
                                  10

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     air and the sulfur compounds are in a reduced state, e.g.,
     hydrogen sulfide rather than sulfur dioxide.  Because the
     heat source is external to the retort, any fuel may be used.
     The emissions from the heat source will depend upon the fuel
     used.  This type of retort is expensive in terms of capital
     and operating costs per unit of produced oil.  It is not
     likely to be competitive with other types of retorts.

     Class II, Internal Combustion—Heat is transferred to the shale
     from hot gases generated in the retort by the combustion of
     some of the carbon and hydrogen present in the shale.  Ex-
     amples include the Paraho* retort, the N-T-U retort, and the
     gas combustion and Laramie simulated in situ retorts of the
     Bureau of Mines.  A controlled amount of air and recycle
     gas is introduced into the retort and a mixture of product oil
     and low heat content (low Btu) gas is recovered.  The
     advantages of this system are low capital and operating costs
     per unit of shale input.  Disadvantages are low recovery of
     the total energy in the shale and the production of a large
     quantity of flue gas containing about 3 MJ/m  (80 Btu/scf)
     energy content.  For example a typical gas combustion
     retort plant producing 16,000 m3 (100,000 barrels) per day
     of shale oil would also produce about 23 million cubic
     meters per day of low heat content gas.  Sulfur contained
     in this gas would be on the order of 200 tonnes per day.

     Class III, Hot Fluid—Heat is transferred to the shale by
     passing hot gas that has been heated in an external furnace
     through the shale bed.  The Petrosix, the Union-SGR, and
     one variation of the Paraho are examples of this type of
     retort.  By circulating high heat content (high Btu) product
     gas through the retort, the problems of the Class II retort
     are eliminated.  The gas has much more value and sulfur
     compounds can be removed by amine scrubbing.  However, the
     capital cost of the equipment required to heat the re-
     circulating gas makes this an expensive type of retort.
     Additional problems are caused by the tendency of the
     external gas heater to accumulate carbon deposits caused by
     oil mist in the gas.
*
 The Paraho project is committed to developing two different retorts—I,
 a gas combustion type and II,  a hot gas circulation type.

                                  11

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     Class  IV, Hot Solid—Heat is transferred by the introduction
     of hot solids into the retorting bed.  The two best known
     examples of this class are the TOSCO II retort in which heat
     is transferred by ceramic balls and the Lurgi-Ruhrgas retort
     in which heat is transferred by recirculating hot shale ash.
     The  principle of retorting is to combine raw shale with
     enough hot recycle solids to produce retorting temperatures
     in the mixture.  This class of retort is fairly expensive,
     but  does recover a high percent of the energy in the shale.
     The  gas from the retort has a high heat content (high Btu)
     and  sulfur compounds are in the reduced state.

     As shown below in Table 4,  most of the  first generation  commercial

ventures plan to use the TOSCO II  retort.   This is the  only retort that has

been demonstrated in the configuration of the commercial facility.  Union

Oil Company plans to use their own retort system and will build a

demonstration unit before proceeding with a  commercial  plant.

     The  group on the combined Utah a and b sites may use a Paraho  type

of  retort if the Paraho demonstration is successful.  Superior Oil  Company

has not announced the type of retort they plan  to use.  However,  their
process requires that the shale ash not be overheated as would occur  in

a gas  combustion type of retort.

     There  is an interaction between the method of retorting and  the
sulfur dioxide emissions that has not yet been  resolved.  Class  II  retorts
(gas combustion and Paraho I) produce a large quantity of low heating

value  (3.7  MJ/m3 or 100 Btu/scf) gas as a by-product that may contain
oxidized  sulfur compounds.  Class IV retorts (TOSCO  II and Union-SGR)

produce gaseous products that are not diluted with air;  the  gas  has a

high heating value  (about 30 MJ/m3) and the sulfur is in the reduced  state.

In  general,  it  is much  less expensive to remove sulfur compounds  from

high heating value gas.

     Of  the three  retorts likely  to reach commercial production,  infor-
mation in the public  domain  is  available only  for TOSCO  II.  Neither
                                  12

-------
Paraho nor Union have published sufficient details of their processes to

allow calculation of off-gas composition.  However, both Paraho and Union,

or any other retort, could meet the sulfur dioxide and hydrocarbon emis-

sion restrictions presently applicable to new fossil-fueled power genera-

tion plants by using stack gas scrubbing.  (It may be that such stack gas

scrubbing would be so expensive as to make the retort uncompetitive with

other types of retorts that do not require scrubbers.)

     From the above line of reasoning we conclude that overall emissions

from a conventional shale industry may be estimated using TOSCO II emis-

sion rates.  Such estimates of emissions have been derived for a typical

production facility based on TOSCO II retorting with subsequent upgrading

of the crude shale oil to a low sulfur fuel oil by delayed coking and

hydrogenation.  This facility is described in the next section.


C.   Shale Oil Production Module

     The basic unit used in this study of a shale oil industry is a com-

plete facility for mining oil shale, retorting the shale, disposing of

the spent shale, and upgrading the crude shale oil to 16,000 m /day

(100,000 barrels per day) of low sulfur fuel oil.*  A complete description

of these operations as they are proposed by the Colony group may be ob-
                      j.
tained in Reference 1.'   The information obtained from this reference was

scaled to our 16,000 m3/day (100,000 barrels per day) unit size and the

resulting plant flows are shown in Figure 1 and Table 1.  The block flow

diagram, Figure I/ shows the major processing units, the major process

flow streams, and all plant inputs and output streams.  Table 1 lists the
*
 The proposed low sulfur fuel oil is about 0.3 percent sulfur, somewhat
 higher than some previous plans  for a synthetic crude oil of less than
 0.1 percent sulfur content by weight.

 References are listed at end of section.

                                  13

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quantity and type of water flow streams 'and atmospheric emissions.


Table 2 lists the physical characteristics of the emission streams  and


Figure 2 is a diagram showing typical locations of the stacks in a  shale


oil facility.





D.   In Situ Retorting



     The previous sections discussed conventional oil shale technology


and some plans of groups who intend to enter the industry.  This


section considers in situ extraction of oil from shale and its potential


for augmenting the conventional approach.  In situ technology is believed


to be several years behind conventional above-ground retorting and  there


have been no publicly announced plans for a commercial in situ venture.


Nevertheless, it must be considered a potential method to produce oil


after about 1980 because there may be lower capital and operating costs


as well as less water consumption.



     Methods proposed for in situ oil recovery include hot fluid circula-


tion, solvent extraction, and underground combustion.  Several procedures


have been proposed for preparing the shale deposit prior to the retorting


operation such as rubblizing, fracturing, leaching out soluble inorganic


components, or draining water from the naturally porous areas.  The


method most apt to be developed to commercial practice consists of  pre-


paring underground retorting chambers filled with shale rubble using con-


ventional mining methods and then heating the shale by combustion start-


ing at the top of the column.  This procedure is similar to that used  in


fixed bed retorts such as the N-T-U and the simulated in situ retort

                                 2
located at Laramie Energy Center.   Of course the in situ retorts must


be on a much larger scale to be economic.



     Garrett Research Division of Occidental Petroleum Corporation has


developed and field tested this method of retorting.   The first field


test contained about 3,500 tonnes of shale rubble, and 190 m^


                                   16

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(1,200 barrels) of oil were recovered.  At present they are preparing to


test a retort 75 m (250 feet) in height and 30 m (100 feet) square.  These


dimensions are in the range of a commercial development of a shale deposit.

Larger retort dimensions, if possible, would result in lower overall costs


as well as a greater recovery of the oil (kerogen)  in-place in the shale.


     Although the mining and retorting costs for in situ recovery are

estimated to be lower than for conventional shale oil retorting, there


are a great many unknown cost factors that must be established before a


commercial venture can be established.  Retort and facility design will

be dependent upon the geology and hydrology of the particular shale de-


posit to be developed.  Aquifers above or below the shale bed will re-


quire water control or extensive dewatering.  Fractures or porosity in


the shale must be determined and taken into consideration in the retort


development plan.  A sequence of retort construction and operation must


be designed to allow use of mine adits and drifts for shale transport and


recycle gas flow under conditions of complete mine safety.  These are


just a few examples of the difference between a successful field test of


one retort and a commercial development that could require the integrated


operation of thousands of retorts over the life of a venture.  (Figure 3


illustrates this procedure with successive in situ retorts at la,  Ib,  and  Ic.)


     Table 3 and Figure 3 characterize possible atmospheric emission


streams from an in situ retorting plant.  The major stream consists of

a large quantity of off-gas that must be disposed of by venting to the


atmosphere during retort operation.  The retort off-gas composition will


vary somewhat in accordance with several retorting parameters but will
                               o
probably contain about 1.8 MJ/m  (50 Btu/scf) of combustible hydrocarbons


and carbon monoxide as well as some sulfur compounds.   The heating value


of this gas may be sufficient to allow recovery of some energy by burning


the gas in a turbine or steam generating system.  In any event,  the
                                  19

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                                            200m
NOTE: STACK NUMBERS REFER TO TABLE 3
      NOT TO SCALE
                         FIGURE 3  IN SITU PLANT CONFIGURATION
                                   20

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carbon monoxide and hydrocarbons will -be removed  before  venting  and  the

sulfur compounds converted to sulfur dioxide.   It is  estimated  that  a
        o
16,000 m /day (100,000 barrels per day)  in  situ operation  would  produce

1300 m3/sec (2,670,000 ACFM)  of effluent gas from an  incinerator at  a

temperature of 95°C (200°F).   This effluent stream would contain about

440 kg/hr (16 Ib/min)  of hydrocarbons and about 4400  kg/hr (160  Ib/min)

of sulfur dioxide.  This is roughly equivalent to the quantity of stack

gas emitted from a 1000 MW oil-fired electric generating plant,  burning
      o
5500 m  (35,000 barrels) per day of 1 percent sulfur  residual  fuel oil.

     Another class of  important environmental  questions  center around  the

large quantities of burned shale that will  be left underground  indefinitely,

Shale ash disposal will probably not be as  great  a program for  in situ

operations as it will  be for surface retorting.  The  major problem in both

cases will be to prevent soluble minerals from entering  the ground water

or the Colorado River.
                                REFERENCES


      Atlantic Richfield Company,  "An Environmental Impact Analysis for
      a Shale Oil Complex at Parachute Creek,  Colorado," Vol.  I,  Part I,
      Colony Development Operation (1974).

      A. E. Harak, A. Long Jr.,  and H. C.  Carpenter,  "Preliminary Design
      and Operation of a 150-Ton Oil Shale Retort," Quarterly  of  the
      Colorado School of Mines,  Vol. 65,  No.  4 (October 1970).

      R. D. Ridley, "in Situ Processing of Oil Shale,"  Quarterly  of the
      Colorado School of Mines,  Vol. 69,  No.  2 (April 1974).

      "The Economics of Commercial Shale Oil  Production by the TOSCO II
      Process," by R. N. Hall and L. H. Yardumian,  The  61st meeting of the
      American Institute of Chemical Engineers,  Los Angeles, California
      (1968).
                                   22

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          V  PLANS AND PROJECTIONS FOR OIL SHALE DEVELOPMENT







     The oil shale industry has been "just about to emerge" for the past



25 years.  Predictions concerning the first commercial plant were made



more than fifty years ago.  However, the discovery of the vast East Texas



oil fields in the early 1930s pushed shale out of the picture until recent



Middle East problems brought it back to economic viability.





     Even at present, not all of the economic and social forces in the




United States can be said to be converging in favor of the development



of a shale oil industry.  In opposition to the high cost of petroleum



and the desire for U.S. independence from foreign crude oil are the re-



quirements for a nonpolluting shale industry, for little or no disturbance



to the land containing the shale, and for competitive uses for the re-



quired water.  The above factors, in addition to the fact that 80 percent



of the shale reserves are publicly owned and subject to the ebb and flow



of the political process, clearly make  prediction of industry growth



patterns hazardous.





     Nevertheless, there is a considerable momentum built up in favor of



the development of a shale industry; about 400 million dollars are now



committed to that development.  The forces for shale oil are stronger



than the forces against shale oil.  The question which cannot be answered



at this time is:  Can the theoretical techniques devised to create a non-



polluting shale industry be realized, in actual practice?  If they can



be realized, or suitable new solutions found, then there will be a long-



term shale industry.  If suitable solutions to the air and water problems



cannot be found, then the American people will have to decide how they



wish to proceed.
                                  23

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     The present situation can be described by placing the economic groups

who have a stake in the shale industry into two categories:  (1) those
corporations that have large amounts of money invested in shale and will
lose much if they do not move quickly, and (2) those corporations that
have acquired shale reserves over the years and can afford to wait.  These

are rather loose definitions and there are corporations who fit both
categories at the same time.  The important difference is that the first
category has made a corporate decision to enter the shale industry.

     The corporations in the first category are listed in Table 4.  Also
listed are six locations in Colorado and Utah where the probable first

generation of shale oil ventures will be placed.  The geographic locations
are shown on the map in Figure 4.  Tracts U-a and U-b are shown as one
location since they are adjacent and will probably be developed jointly.
                                Table 4
                  SHALE OIL PLANT LOCATIONS AND TYPES
Location, as
  Shown in
  Figure 3
                             Probable   Estimated
                 Probable   Plant Size  Completion
Group
Retort    (m 3/day):
Date
C-a
C-b
U-a
U-b
Colony
Union
Superior
Amoco-Gulf
ARCO-Ashland -Shell -TOSCO
Phillips-Sun I
Phillips-Sun-Sohio I
ARCO-Ashland -Shell -TOSCO
Union Oil of California
Superior Oil
TOSCO II
TOSCO II
Paraho
TOSCO II
TOSCO II
Union-SGR
Not known
16,000
16,000
16,000
8,000
16,000
8,000
1981
1982
1983
1979 +
1981
1982
 *         3
  16,000 m /day  is  a  100,000  barrel-per-day  plant.

  In  October 1974 Colony  announced  that  the  construction  of  this  plant
  would  be postponed  indefinitely,  thereby making  the  completion  date
  later  than 1979.
                                   24

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IDAHO
UTAH
                                                        WASHAKIE
                                                        .  BASIN .
           ,.. .  UNIT* BASIN.
                                                             SUPERIOR
                                                                 PICEANCE
                                                                  REEK BASIN
 AREA OF OIL SHALE DEPOSITS
 AREA OF NAHCOLITE OR
 TRONA DEPOSITS
                                                 Grand JuMtton   ***"*> MESA
AREA OF O.I m /tonnt OR RICHER
OIL SHALE 3m OR MORE THICK
                                                COLORADO
                        30       100
                          SCALE IN KILOMETERS
                                                   2OO
       FIGURE  4   MAP OF OIL SHALE  PLANT LOCATIONS
                                 25

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     The second category of potential participants in a shale industry
includes those corporations that own adequate shale reserves to support
at least 8,000 m3/day (50,000 barrels per day) of oil production, but have
not announced any plans to develop the reserves.  This group could enter
the industry; and some of them might, if the overall economic conditions
for shale development were made more favorable.  This group includes:'
Cities Service, Exxon, Getty Oil Corp.,   Mobil  Oil Corp.,  and Standard

Oil of California.

     A third category of companies can be defined as those companies who
own low quality shale reserves on reserves that would require a large
amount of  'blocking up'  in order to obtain a compact mining plan.

     A fourth category would include companies who have no shale reserves,
but are developing processes that could be the basis of a joint venture.
Occidental Petroleum and the Geokinetics group are in this category.
Both have indicated a willingness to enter the shale industry by their
unsuccessful bids on the federal sh'ale leases.  Such groups may also
obtain shale reserves from Utah state lands at some future date.

     From a historical point of view, the. U.S. Bureau of Mines has long
advocated an orderly growth of a domestic shale oil industry and has
promoted this concept by supporting research and by the leasing program.
The federal leasing program was originally conceived with this orderly
growth in mind and is progressing along this course.  More recently,

however, programs for accelerated oil shale development have been suggested
  "Blocking up" occurs when an owner has a sufficient quantity of shale
  reserves, i.e., about 2,000 hectares  (5,000 acres), but in land too
  widely dispersed  to design an efficient mining plan.  Such an owner
  hopes to exchange some  remote land for federal land of equal value
  close to his principal  holding.  Superior Oil Co.  is  trying to do this
  for  its land.  Exxon would probably  try to block up its holdings before
  putting up  a plant.

                                   26

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 as part  of Project  Independence.   Early  in  the  project  very  rapid  oil

 shale development was  contemplated.   The original  concept1   of  complete

 independence from foreign  oil  supplies by 1980  has been abandoned  as
 impossible—a more  realistic goal  combining a reduced growth  rate  for

 U.S.  energy  consumption and a  longer  transition period  is now advocated.2

 Table 5  presents the three cases:   (1) National Petroleum Council  (NPC)

 prediction made in  1970,3  (2)  original Project  Independence1  and,  (3)

 revised  Project Independence,2 as  each  relate   to  the growth  of an oil

 shale industry.  The required  capital costs for the industry  are also

 shown.

      SRI predicts that the growth  of  a shale industry will be much closer

 to the 1970  NPC prediction than to the revised 1974 Independence numbers,

 up to 1985.  The announced shale plants,  as shown  in Table 4, indicate a

 production rate of  about 80,000 m3/day (500,000 barrels  per day) by 1984,

 allowing one year for a plant  to reach full production.  In addition to

 this  amount  of production  from conventional mining and  retorting, between

 16,000 and 32,000 m3/day (100,000 and 200,000 barrels per day) in situ

 production could be obtained by 1984.  This total production  of 80,000-

 112,000 m3/day (500,000-700,000 barrels  per day) represents the first

 generation shale industry.

     Growth beyond  the first generation will depend upon several factors

 that  are not presently known.  These are  listed:

      •  The salinity of the Colorado River as a result  of
         increased use of the pure upper  source water, spent shale
        runoff,  and  saline water percolation.
      •  The cost of  crude petroleum in the United States and  on
        the world markets.

      •  The economic and social costs of  shale oil production as
        perceived by the voters of the United States.
*
 References are listed at end of section.
                                 27

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                                Table 5

               REQUIRED OIL SHALE INDUSTRY GROWTH RATES
                        TO MEET SELECTED GOALS
                                  1970           1973            1974
                                  NPC         Original        Revised
                        Year  Task Force*  Independence!  Independence^
Shale oil production
Thousands of m3/day§
Total capital expendi-  1975
tures required for oil
production**
 *
  Reference 3.

  Reference 1.
  Reference 2.
1975
1980
1983
1985
1975
1980
1983
1985
0
100
200
400
400
1,500
3,400
6,400
0
500
1,500

400
6,000
22,000

0


500
400


8,000
  p
  16,000 m3/day is equivalent to 100,000 barrels per day.
**
  Millions of dollars, assuming 6% per year cost escalation.
If all of the above factors are positive in the sense that they will not
limit the growth of the shale industry, the industry should continue to
grow at a rate of 32,000 m3/day (200,000 barrels per day) p>er year until
limited by the available water supply.  Thus, growth would level off at

about 240,000 m3/day (1,500,000 barrels per day) production by 1990.  Be-
yond 1990, an average of 16,000 m3/day (100,000 barrels per day) of new
plant construction will be required each year to replace old facilities.

     The physical characteristics of this predicted development (for the

revised Project Independence) are discussed in  U.S. Energy Prospects:
An Engineering Viewpoint" (Chapter 6).2  Among the major efforts are:

                                   28

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     •  Bringing into production 250 million tonnes per year of
        shale mines.

     •  Laying, stabilizing, and restoring 17 square kilometers
        (5 square miles)  of shale ash 13 m (40 feet)  deep each
        year.
     •  Developing and conveying 100 million cubic meters
        (80,000 acre-feet)  per year of new water supplies.
                              REFERENCES
1.   "The Nation's Energy Future,"  submitted  to the President  by Dixy
     Lee Ray,  Chairman,  U.S.  Atomic Energy Commission (December  1973).

2.   "U.S. Energy Prospects:   An Engineering  Viewpoint,"  Task  Force  on
     Energy,  National Academy of Engineering,  Washington,  D.C.,
     Chapter 6 (1974) .

3.   "An Initial Appraisal by the Oil Shale Task Group—1971-1985,"
     National  Petroleum Council, Washington,  D.C.,  p.  117 (1972).
                                  29

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          VI  ENVIRONMENTAL EFFECTS OF OIL SHALE DEVELOPMENT








     Discussion of the environmental effects of oil shale development



tends to be controversial and could become especially significant.  The



controversy is strongest in Colorado, the region of the most promising



oil shale resources,  and is most concentrated in Denver, which is the



center of both general population and that special segment of popula-



tion of Federal,  State, corporate, and environmentalist personalities



involved in the controversy.  The special significance of this discussion



is its role in making the first assessment of environmental impacts of an



industry before the industry exists as a commercial operation.





     The environmental impacts themselves are unusually significant due



to the physical and chemical properties of the oil shale.  Oil shale is



an alkaline rock containing a relatively small hydrocarbon fraction, the



10 to 15 percent by weight which is the kerogen that can be converted to



a fuel.  After extraction of the fuel, the vast majority of the mass of



the shale remains as a waste material.  This waste, known as spent shale,



of crushed and retorted  rock  contains minerals that can be dissolved



easily by rain or snowmelt and is therefore a potential source of increased



salinity in the Colorado River.





     Political issues in this case are tied directly to environmental im-



pacts.  The quantity and quality of water in the Colorado River have been



the subjects of a number of political and legal arguments.  The salinity



of the Colorado has been the subject of a recent agreement between the




United States and Mexico, thus bringing international political overtones



into the environmental impact assessment of oil shale development.  Some



details are given below in the discussion of water quality.
                                  31

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     This  section of the report contains a summary of the environmental
effects of oil shale development under the headings of land, air, water,

and aesthetics.  Two precautions should be stated here, before the specific
summaries:

     (1)   The extent to which the different kinds of environmental
           impacts can be adequately quantified varies a good deal.
           Because this report is directed toward the air pollution
           and control aspects of the oil shale industry, most of
           the effort at quantification has been made in that area.
           These findings are presented in greater detail in subse-
           quent sections of the report.  In this section, quantita-
           tive estimates are made for land, water, and air impacts.
           Aesthetic impacts tend to defy quantification and no
           attempt is made here to quantify them.

     (2)   The actual environmental impacts of oil shale development
           will be determined by the type of processing that finally
           passes the economic and regulatory requirements.  The
           form of technology that will prove satisfactory in these
           respects is not yet determined.  Perhaps the most signif-
           icant example of this uncertainty is the technology for
           in situ processing of oil shale.  This technology is under
           active study and development.  Its use would signifi-
           cantly change the environmental impacts.  Water use, for
           example, will be considerably less with in situ processing.
A.    Land  Impacts

     The amount of rock that must be excavated in order to yield one cubic

meter of shale oil is staggering.  Oil shale of 0.125 m3/tonne (30 gal/ton)
                                Q
will require the mining of 3.8 m  oil shale per cubic meter of oil produced.

This much shale will yield 5.2 m3 of spent shale; the volume increases

after crushing and retorting.
                         *

     The land disturbance due to the mine, surface facilities, and

disposal area has been estimated by three sources.  The ARCO source

estimates a disturbance of 12.1-12.3 ha per 106 cubic meters of oil

produced.1*  The Department of the Interior predicts 12.6-13.7 ha per

million cubic meters of oil.3  SRI has previously estimated the disturbance

                                  32

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to be 12.5 ha per million cubic meters of oil.3  The area most likely to

                                                        2
be developed in the next 25 years will be about 2,100 km  in Colorado


in the Piceance Creek Basin and up to 1,000 km2 in the east side of Uinta


Basin of Utah.  The land disturbed will range from 2-8 percent of the


total of about 3,000 km2 of good shale reserve land depending on the


processing method used.3  The production of about 2 x 10^ m3 (12 billion


barrels) of oil would be associated with this land disturbance, assuming


8 percent of 3,000(km)2 and-12.5 ha per 106 m3.





B.   Water Impacts



     1.   Water Use



          It is generally believed that available water will limit the


ultimate size of an oil shale industry.  All good western shale is in


the upper Colorado River drainage system, the only replenishable source


of water.  There is ground water in the shale area, some of it fresh and


some containing up to 60,000 ppm dissolved minerals.  At present it is


estimated that 2.2 X 10  cubic meters  (180,000 acre feet) per year of


Colorado river water could be made available for shale development.  This


quantity of river water, plus the use of ground water at the mine sites,


would allow an overall industry size ranging from 2.4 X 10  to 4 \ 10


cubic meters (1.5 to 2.5 million barrels) per day of shale oil.



          The water used per unit of net product will depend upon the


type of mining, retorting, and upgrading used.  In situ methods are ex-


pected to require less water than conventional mining and retorting.


Table 6 contains a list of estimated water use per cubic meter of shale


oil produced.  The values range from two to almost six cubic meters of


water per cubic meter of shale oil.
*
 References are listed at end of section.
                                   33

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                              Table  6
          ESTIMATES OF WATER USE IN OIL SHALE PRODUCTION
               (m3 of water per m3 of oil produced)
Impact
Impact
Quantity
(ra3/m3)
Ref-erence
Impact
Quantity
(m3/m3)
       Underground      4.1
       Mine Water
       Use

       Surface Mine    4.0
       Water Use

       In Situ         2.1
       Water Use
Colorado River Water
Conservation District


Department of the
Interior

Cameron and Jones

Denver Research
Institute
ARCO

Colorado Water
Conservation Board
3.6"
2.70-4.27
(underground)

2.894
3.234
                                                      3.90
                                                      4.45*-5.57
Sources:    "Control of Environmental Impacts From Advanced Energy
           Sources," E. E.  Hughes,  E.  M. Dickson, and R. A. Schmidt,
           SRI,  Menlo Park,  California,  p.  34 (1974).

          3Roland C. Fisher, "Colorado Oil  Shale and Water,"
           Quarterly of the Colorado School of Mines, Vol. 69,
           No.  2, pp. 135-6.

          3Department of Interior,  Final Environment Statement for
           the  Prototype Oil Shale  Leasing  Program, Vol Iy(1973).

          4Felix C. Sparks,  "Water  Prospects for the Emerging Oil
           Shale Industry," Quarterly of the Colorado School of
           Mines, Vol. 69,  No.  2 (April  1974).

           ARCO, "An Environmental  Impact Analysis for a Shale Oil
           Complex at Parachute Creek, Colorado," Vol. I, Colony
           Development Operation (1974).
                                34

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     2.   Water Quality


          Current plans call for no effluent from the oil shale plant

 into surface water.  Process water will be piped into the disposal area

 for wetting of the spent shale pile.  Runoff from the pile will be held

 in a catchment dam below the disposal area.  The amount of water piped

 from the Colorado River will not be returned.  It is estimated that this

 consumptive use of water will increase the salinity of the Colorado River

,at Hoover Dam by 0.2 mg/1.  By 1981, with a projected 40,000 m3/day

 (250,000 B/D) industry, this will have caused a salinity increase of 1.0 mg/1,


          Secondary water quality impacts which are not readily predicted

 or measured may be more significant.  The Mahogany Zone, which will be

 the first oil shale layer to be mined, is the barrier or "lid" to the

 main aquifer in the area called the leached zone.  Mining in this zone

 will encourage greater seepage of brackish water from this aquifer through

 the Mahogany Zone into the surface waters of the area.  Mines to be lo-

 cated at the center of the basin, such as tracts C-a and C-b, will have  to
                                      q
 be dewatered at rates of at least 50 m /hr.  In this area, about 70 per-

 cent of the water will be of poor quality.   This poor quality water will

 average about 25,000 mg/1 in dissolved solids, contain mostly sodium and

 bicarbonate ions, and have chloride concentrations of 500-2,500 mg/1,

 according to a USGS source.   This water may not be recycled back to the

 plant for use and must be diverted onto the disposal pi'le, reinjected

 into lower aquifers, evaporated, or transported to nearby oil shale

 operations which need water for disposal and dust control.


          The Treaty of 1944 assured Mexico of 1.9 x 109 m3 (1,500,000 acre-

 feet) annually of irrigation water from the Colorado River.  The river has

 become increasingly saline over the years due to dissolving of rock and

 the vast irrigation runoff from the southwestern United States.  Two

 revisions have been made to the treaty, one in 1972 and the other in

 August 1974.  The last revision calls for a maximum 115 ppm increase in


                                  35

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total dissolved solids between Imperial Dam and Morelos Dam.  Since


the maximum advisable salinity at Imperial Dam is 1,000 ppm, the United


States may not deliver to Mexico any water more saline than 1,115 ppm,


TDS.  In order to accomplish this, a plant will be built upstream from


Morelos Dam to desalinate the Wellton-Mohawk drainage flow which is


the main contributor of salinity in the lower part of the river.  This


drainage flow averages 8.6 m /sec (220,000 acre-feet/year) with a salinity


of 3,700 ppm.




C.    Air Impacts



     Industrialization of the Western shale regions will result in a


decline of the general air quality.  The main sources of air pollution


will be vehicular emissions from mining, construction, and transporting


equipment; dust from shale-handling operations; and gases from retorting


and refining units.  Other sources of air degradation will be the in-


creased vehicular traffic, residential heating caused by an increase in


population in the area, and emissions from the mine-blasting procedures.


The estimated emissions for an oil shale plant are given in Table 7.  The


first two columns show the numbers listed in the previous EPA report.


The third column lists the figures derived from an ARCO primary reference.


The fourth column shows the ARCO emissions as listed in a secondary source


based on ARCO's data.  In the fifth column are listed the emissions pre-


dicted by the Department of the Interior.  The more recent numbers listed


in the third and fourth columns show a ten times increase in NO  emis-
                                                               x

sions.  This is because the older estimates were based on the use of


natural gas or clean fuel in the retorting operation.  Now  the estimates


are based on the use of shale oil, which has greater nitrogen content.
                                   36

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                               Table  7
                 ESTIMATES OF AIR POLLUTANT EMISSION
                   FACTORS IN OIL SHALE PRODUCTION

                                                2
                     Emission Factor in kg per m  of Oil Product
Table 163
(uncontrolled
Pollutant Table II1 Class IV)
SO 2 11 22.6
NOX 0.68 0.755
Particulates 0.054 1.13
H S — 11.3
Department
of
Tosco II3 Tosco II4 Interior5
2.25 1.91 2.62-3.88
7.45 11.1 0.456-0.685
1.46 1.43 2.52
.. _
Sources:
          i",
  Control of Environmental Impacts from Advanced Energy
 Sources," E. Hughes, E. Dickson, R. Schmidt, SRI, Menlo
 Park, California, Table 11 (1974).

2 ibid., Table 16.

 SRI calculations based on "An Environmental Impact Analysis
 for a Shale Oil Complex at Parachute Creek, Colorado,"
 Vol. I, Colony Development Operation (1974).
A
 SRI estimate from other sources.

 Cited in "Environmental Considerations in Energy Develop-
 ment," Appendix D, Battelle Memorial Institute (1973).
D.   Aesthetic Impacts

     The spectrum of changes caused by the development of a new industry
ranges from those that are easily quantified, such as size of mine tailing
area, to effects that are purely subjective, such as increased monotony
of landscape.  For convenience, all environmental changes that contain a
high proportion of subjective evaluation are placed in the aesthetic
                                   37

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category.  This category includes changes in land use, plant growth,
wildlife, recreational facilities, and cultural and scenic values.

     The shale areas have a low population density, on the order of one
person per square kilometer (three per square mile) less than half of
whom live in towns.  The population doubles during the few weeks of the
deer-hunting season.  Advanced planning of mine and process facility
locations would allow the preservation of the few historic Indian culture

ruins in the area.  The quantity of shale residue accumulating in surface
disposal areas will eventually create large plateau areas in a region
that consists of rounded hills and deeply cut canyons.

     Mining, transportation, and processing operations will produce
noises similar to those now being experienced in other related industries.
In addition to the usual human discomfort and loss of working efficiency,
industrial noises will adversely affect the wildlife in the immediate
area.  For the most part, noise control methods developed for other in-
dustrial and transportation equipment will be satisfactory for the shale
industry.  There may be instances where long conveyor systems used between
processing units create enough noise to prevent normal wildlife migration
paths from being used, even though there is no physical barrier.
                              REFERENCES
1.   Atlantic Richfield Company, "An Environmental Impact Analysis for a
     Shale Oil Complex at Parachute Creek, Colorado," Vol. I, Part I,
     Colony Development Operation (1974).

2.   Department of the Interior, Final Environment Statement for the
     Prototype Oil Shale Leasing Program,  Vol. I (1973).

3.   R. G. Murray, "Energy from Oil Shale," EPA-600/2-74-002, SRI Project
     No. 2714, Stanford Research Institute, Menlo Park, California
     (March 1974).
                                   38

-------
4.   Department of the Interior,  Final Environmental Statement for the
     Prototype Oil Shale Leasing  Program,  Vol.  Ill (1973).

5.   USGS, Geoh'ydrology of the Piceance Creek Structural  Basin Between
     the White and Colorado Rivers,  NW Colorado,  Hydrologic Investiga-
     tions Atlas HA-370 (1971).

6.   Private communication with Mr.  Robert Smith,  Colony  Development
     Operation.
                                 39

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        VII  AIR POLLUTION:  EMISSIONS AND AMBIENT AIR QUALITY





A.   Background



     Concern over possible environmental degradation has been engendered


by the proposed construction of new oil shale processing facilities in


the oil shale regions of Colorado and Utah.  Federal and State laws


require review of the environmental impact of proposed sources of air


pollution in view of current air quality standards.  If an impact assess-


ment reveals that pollution levels resulting from a new facility will


exceed the standards, adequate control measures must be proposed before


a building permit will be issued.  Since the impact assessment is required


during the planning stages of plant development,  a rational methodology


must be devised that will utilize appropriate emission and meteorological


data in the prediction of pollutant .concentrations.  Simulation modeling


provides the necessary link between the collections of meteorological


and emission data and the picture of air quality that is required for


successful evaluation of control measures;   Modeling permits assessment


of the ramifications of projected growth patterns and emission control


procedures.



     Somewhat limited studies of the environmental impact of proposed oil


shale recovery schemes have been conducted.  One such study was performed


by Engineering Science,  Incorporated  (ESI)  and described in the Department

                                           1*
of Interior s Final Environmental Statement  on oil shale.   ESI used the


emission estimates then available,  various meteorological data,  and a


number of assumptions as to stack characteristics and locations in a
*
 References are given at the end of this section.


                                   41

-------
mathematical model to predict air quality levels resulting from an oil
shale facility.*
B.   Model Description

     The model used in the present study for calculation of concentra-
tions from oil shale plants is the Climatological Dispersion Model (CDM),
                                                                        2
which is a revised form of a model first proposed by-Martin and Tikyart.
                                               3
The CDM has been described in detail by Calder.

     The computerized CDM permits calculation of long-period seasonal or
annual average pollutant concentration patterns resulting from stationary
point sources and area sources.  The fundamental physical assumption of

the model is that the steady-state spatial distribution of concentration
from a continuously emitting point source is given by the Gaussian plume
formula.  It is assumed that meteorological conditions over short periods
of time (of the order of an hour) can be regarded as steady-state, and
that these conditions can be approximated with a constant and spatially
uniform wind speed and with a unique horizontal mean wind direction for

the entire area.

     The Gaussian plume formulae are used when there are no restrictions
on diffusion in the vertical direction.  When vertical diffusion is
restricted to a finite mixing depth, a uniform vertical concentration
distribution is assumed at greater downwind distances.
*
 Note added in review:  Subsequent to the Department of Interior's
 environmental statement, ESI has extended its work by contributing an
 air quality analysis to the Federal Energy Administration's Oil Shale
 Task Force for the Project Independence Blueprint, published at the
 end of 1974.
                                    42

-------
     Equations for the long-term average concentrations due to point and
area sources are weighted according to a frequency function to account
for the variability of meteorological conditions.   These empirical

functions express the observed joint frequency of occurrence of various

classes of wind direction, wind speed, and stability.  Integration of
the formulae over the area and point sources will describe the concen-

tration that would be observed at a selected location for a certain set

of meteorological conditions.  These concentrations, taken together with
the frequency of occurrence of each combination of conditions, produce

the required climatologically averaged spatial distribution of concentra-

tion.

     The CDM program formulation used in this study assumes that the land

at the plant site and in the surrounding area is--essentially flat.  The

influences of complex terrain have not yet been incorporated into dis-

persion models currently in use.

                                       *
C.   Topography of the Oil Shale Region

     The principal oil shale deposits considered in this study are

located in the Piceance Creek Basin in Colorado and the Uinta Basin in

Utah.

     The Colorado Counties of Rio Blanco, Garfield, and Mesa encompass
the Piceance Creek Basin.  The major oil shale area of the Basin lies
on the Roan Plateau,  bounded by steep escarpments in all directions.

The land surface of the region has been shaped by erosion into valleys
and ridges oriented in the north and north-easterly directions.  The
*
 The information contained in this section was extracted from the Final
 Environmental Statement for the Prototype Oil-Shale Leasing Program,
 Vol. I, Regional Impacts of Oil Shale Development, U.S. Department of
 the Interior (1973).   This is Reference 1 in the list at the end of
 this section.
                                    43

-------
difference in elevation from ridge to valley floor ranges from 62 to 185 m


(200 to 600 feet),  and for the most part the valleys are narrow and steep


sided.  The northern part of the oil shale area is drained by tributaries


of the White River,  while the Colorado River drains the southern part of


the oil shale region.   Land elevations above mean sea level (MSL) range


from about 1600 m (5250 ft.) near the White River to about 2800 m (9000 ft.)


on southern ridge crests.



     Utah's Uinta Basin is a depression bounded by the Uinta  and Wasatch


Mountains, the Roan Cliffs and the cliffs west of the Douglas Creek Arch.


Land features include rough mountains and flat valleys, with deep gulleys


and rock capped ridges.  The White and Green Rivers drain the area.


Elevations range from 1400 m (4600 ft.) to more than 2500 m (8000 ft.) MSL.



     In general, the oil shale regions of Colorado and Utah contain many


steep-sided valleys that are unsuitable locations for plant sites.  In


the past, serious air pollution episodes have occurred in such valley


locations as the Meuse Valley, Belgium in 1930 and at Donora, Pennsylvania,


in 1948.  These episodes were a result of restriction by valley walls of

                                                                   4
mixing of pollutants into the atmosphere.  Conclusions from a study


conducted by Battelle, Pacific Northwest Laboratories indicate that oil


shale processing facilities should be located on plateau, rather than


valley, sites to minimize pollution potential.  Concentrations in a


valley resulting from a plateau plant site were found to be at least


an order of magnitude lower than the concentrations that would result


from a valley plant site.  Therefore, in view of compelling supportive


evidence for the necessity of such location, the diffusion modeling per-


formed in the present study was conducted under the assumption that the


oil shale plants will be located on plateau sites.
                                    44

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D.   Meteorology of the Oil Shale Region



     The Climatological Dispersion Model used to simulate the pollutant


pattern resulting from operation of an oil shale facility was formulated


assuming flat terrain in the modeling area.  If an oil shale plant is


located in a narrow valley, the CDM will under-predict pollutant con-


centrations;  However, if the facility is located in a plateau or in


a broad valley, as previous studies have strongly recommended and which


has been assumed for the modeling, the dispersion model will adequately


predict concentration patterns.  The wind regimes of plateaus and broad


valleys in the oil shale region are undoubtedly influenced by surround-


ing terrain, but the influence is not of sufficient magnitude, as is that


of steep-sided valleys, to justify modification of the CDM to account for


it.



     Figures 5 and 6 are illustrations of the influence of topography


on wind direction and speed.  The data used in these figures were taken

             5
from a report  prepared by Dames & Moore for the Colony Development


Operation and from Grand Junction, Colorado, weather records.  Stations


1, 2,  and 5 are weather stations that were established in the oil shale


area of Colorado to collect data for the above study.  Station 1 was


located at the confluence of the Middle Fork and the East Middle Fork


of Parachute Creek at an elevation of 1850 m (6025 ft.) MSL.  Station 2


was part way up the valley side of the Middle Fork of Parachute Creek at


an elevation of 1930 m (6270 ft.)  MSL.  Station 5 was located on top of


the Mesa above the Middle Fork of Parachute Creek.   The annual frequency


distributions of wind direction for each station and for Grand Junction


are shown in Figure 5.  Since the class intervals of wind direction


reported for the experimental stations differ from the class intervals


reported for Grand Junction,  the percent frequency of occurrence per


degree of class interval has been used in the figure.  This normalizes
                                   45

-------

1.2
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NOTE: 9.3% OF OBSERVATIONS SHOWED CALM
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HISTOGRAM





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WINDS WHICH ARE NOT INCLUDED IN
HISTOGRAM

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                  46

-------
    1.0 r
                                           STATION  #5
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kl
U
                                                           NOTE: 1.2% OF OBSERVATIONS SHOWED

                                                                 CALM WINDS WHICH ARE NOT


                                                                 INCLUDED IN HISTOSMAM


                                                       005    035    065    095
                                                                                       155
                                       DEGREES FROM NORTH
u

g

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a.

t-

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                                     GRAND JUNCTION, COLORADO
    0.2
      101   124   146   169   191   214  236   299   201   304  326  349  Oil   034  096   079
                                       DEGREES FROM  NORTH
                                       FIOWU 5  (Concluded)
                                                47

-------
cr
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   40 r
   30
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                                STATION
   40 r
STATION
                                                NOTE:  0.4% OF OBSERVATIONS SHOWED

                                                     WIND SPEEDS >»m/«»c
    0
                                  SPEED-m/nc
               FIGURE  6  ANNUAL FRBQUENCY DISTRIBUTIONS OF WIND

                          SPEED AT  FOUR COLORADO SITES
                                         48

-------
E

K
u
a.
UJ
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 9 m/!*c
                                                          K^
                                     4      5


                                   SPEED - m/MC
   20 r
                            GRAND JUNCTION, COLORADO
    16
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it!
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    12
                                                    NOTE: 0.6% OF OBSERVATIONS SHOWED

                                                         WIND SPEEDS >ll m/»«c

                                     45


                                        SPEED-
                                                                               10
                                    PIOVM  • (Concluded)
                                             49

-------
the data so that the vertical scales are comparable.  The histograms were




drawn so that the class interval with the greatest frequency appears on



the left and subsequent class intervals are taken clockwise from  it.




This was done so that the bimodal nature of the'wind direction distribu-




tion would be most apparent for comparison purposes.  Stations 1  and 2




show strong channeling of the wind by the valleys, with  the orientation




of the maxima reflecting the orientation of the valley.  Station  5,




located on the plateau, and Grand Junction, located  in a broad valley,




have less pronounced maxima and their patterns are rotated 180° from




those of Stations 1 and 2.  It is evident from examination of Figure 5




that the variability of wind direction from station  to station in the




oil shale area is at least as great as the variability between Grand




Junction and any station.  Grand Junction data best  approximates  the




wind direction distribution of the mesa site, and the differences between




the two distributions are no greater than those between  other sites suit-




able for oil shale processing facilities.





     Figure 6 illustrates the wind speed frequency distributions  for




the sume locutions cited above.  Here the frequencies luwe been plotted




in percent per unit of speed, since lht> speed class  intervals differed



for the two data sets.  The valley stations show greater frequencies




of oct:urreiice in the low wind spi-t-d classes than do  Grand Junction and




the mesa station.  Grand Junction has'somewhat more  occasions of  the



higher wind speed classes Hum Station 5.  However,  it should be  noted



that tlie frequency distributions of Stations 1, 2, and 5 wei'c based on




only 14 months of d;ita, while Grand Junction distributions were based




on I i vi  yc-urs of da tu .





     Sufficient me-U-orological data for application  of the CDM is not




available- for sites within the oil shal<  region.  Atmospheric stability



seldom varies abruptly within a geographic area, so  the  use of the
                                      50

-------
stability at Grand Junction is a good approximation.  In view of the
previous discussion and since specific sites for the processing facili-
ties and the associated meteorology have not been supplied, the use of
Grand Junction meteorology is justified for obtaining order of magnitude
estimates of pollutant concentrations.  A similar argument can be made
for the applicability of Salt Lake City,  Utah,  data.  In order to pro-
duce detailed pollutant patterns for an oil shale development, specific
meteorological and stack data for a proposed site must be used.


E.   Dispersion Modeling

     1.   Cases Adopted

          The CDM has been used to predict air pollutant concentrations
                       3
resulting from 16,000 m /day (100,000 barrel per day) plants using two
different retort processes, the TOSCO II process and an in-situ process.

Concentrations of particulates, SO ,  HC and NO  were calculated over the
                                  ^           x
same averaging periods as those for which air quality standards exist.
These periods include annual averages for particulates, SO  and NO ;
                                                          2       x
24-hour averages for particulates and SO ; and a 3-hour average for HC.
                                        £»

          Annual averages were calculated from frequency distributions
of meteorological conditions observed at Grand Junction, Colorado, and
Salt Lake City,  Utah.  These distributions are the output of the National
                 *
Climatic Center's  STAR computer program.  Twenty-four hour averages and
3-hour averages were calculated using the assumption that worst-case
*
 U.S. Department of Commerce
 National Oceanic and Atmospheric Administration
 Environmental Data Service
 National Climatic Center
 Federal Building
 Asheville,  N.C. 28801
                                    51

-------
meteorological conditions prevailed.  Statistical weather records indicate


that neutral atmospheric stability and a light wind of 1.5 m sec   occur


for 24 hours or longer in the oil shale region an average of 15 days per


year.  These conditions have been shown to be representative of worst-


case conditions in the oil shale region and do not involve use of Grand


Junction or Salt Lake City meteorological data.  The CDM was used to


compute the 24-hour and 3-hour averages, for various wind directions,


assuming 100 percent frequency of occurrence of neutral stability and


1.5 m sec   winds.  Stack configurations were assumed on the basis of


the best available information.  Radical changes in the assumed con-


figurations (see Figures 2 and 3 in Section IV) could result in con-


centrations somewhat different than those presented here.



     2.   Results for TOSCO II Retorting



          Figure 2 (in Section IV) illustrates the configuration of

                                                     3
stack locations that have been assumed for a 16,000 m /day (100,000


barrel per day) TOSCO II plant.  Table 8 gives the stack characteristics


and emission rates used in model calculations.  Isopleths of concentra-


tions for various pollutants and averaging times are shown in Figures 7-


18.  Tables 9 and 10 summarize model results for the TOSCO II process and


give background concentrations, air quality standards, and the level of


control required to meet each standard.  Background concentrations were

                      6
taken from the results  of monitoring conducted in the Colorado oil shale


region by Colony Development Operation.  When computing the required


level of control, background concentrations and concentrations resulting


from oil shale operations have been considered together for the federal


primary and secondary standards and for the Colorado standards.  This


has been done by subtracting the background concentration from the stan-


dard and then computing the level of control needed so that the concen-


trations resulting from oil shale facilities do not exceed the remaining
                                   52

-------











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   20
             i    I   I    l   l    I    i   I    I    1   I    I   I    I    l   I    I    T
   15
E
o
    10
BACKGROUND.   < 15 ^g/m3



fi^fc»  PLANT


larff   REMOTE STACK

16,000 m3/day PLANT WITH EMISSIONS CONTROLLED
                                                        STANDARDS

                                                       FEDERAL PRIMARY    75
                                                       FEDERAL SECONDARY  60
                                                       COLORADO         45
                                                       CLASS n           10
                                                       CLASS I           5
                                              I	l	l	i	i	i
                                          10
                                  DISTANCE- kilometers
                                                            15
                                                                    20
       FIGURE 7    ANNUAL AVERAGE PARTICULATE  CONCENTRATION
                    FOR  A TOSCO D  OIL SHALE PLANT USING GRAND JUNCTION,
                    COLORADO METEOROLOGY
                                       54

-------
   20
    15
UJ
u
-2.
    10
                                                                   I   I    I
                                                                     N
                                                                     \
           BACKGROUND.  < 15
                PLANT

                REMOTE STACK

           16,000 m mVday PLANT WITH
           EMISSIONS CONTROLLED
 STANDARDS ( ^g/m  )
FEDERAL PRIMARY   75
FEDERAL SECONDARY 60
COLORADO         45
CLASS n           10
CLASS I           5
                                          10
                                  DISTANCE - kilometers
                                                            15
                                                                              20
        FIGURE 8    ANNUAL AVERAGE PARTICULATE CONCENTRATION Ug/m3)
                     FOR A TOSCO n OIL SHALE PLANT  USING SALT  LAKE CITY,
                     UTAH METEOROLOGY
                                      55

-------
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   13
   12
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                                                                    N
                                             ,200
                                          150
                                           100
          BACKGROUND:
               PLANT
                       15
          E33
REMOTE STACK
                                       STANDARDS
                                     FEDERAL PRIMARY    260
                                     FEDERAL SECONDARY  150
                                     CLASS H           30
                                     CLASS I            10
          16,000 mVday PLANT WITH
          EMISSIONS CONTROLLED
                                  9      10      II

                                 DISTANCE - kilometers
                                        12
                                               13
                                                                     14
15
     FIGURE  9   24-HOUR WORST CASE AVERAGE PARTICULATE CONCENTRATION
                 (/jg/m3)   FOR  A TOSCO n OIL SHALE PLANT UNDER  CONDITIONS
                 OF NEUTRAL  STABILITY AND  A NORTH WIND OF  1.5msec'1
                                       56

-------
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   20
         I    I    T
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                                                        r   r   i   i   T   T
                                                                     N
          BACKGROUND^  <26^g/m3


          (f|^  PLANT

          16,000 m'/day PLANT WITH
          EMISSIONS CONTROLLED

         I    I    I   I    I    i   I    I   I
 STANDARDS (/xg/m3)

FEDERAL PRIMARY   80
CLASS 0          5
CLASS I          2
                                              I   I.   I   I    I
                                         10
                                  DISTANCE -kilometers
                                                            15
       FIGURE  II    ANNUAL AVERAGE S02  CONCENTRATION  (Mg/m3 )  FORA
                    TOSCO E OIL SHALE PLANT USING GRAND JUNCTION,
                    COLORADO METEOROLOGY
                       20
                                      58

-------
   ao
    15
LJ
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    10
          BACKGROUND :  < 26 pq/m

          &$2>  PLANT

          16,000 mVdoy PLANT WITH
          EMISSIONS CONTROLLED
          I   I    I    I
                            I    I   I    I    I   I
 STANDARDS (^q/m3)
FEDERAL PRIMARY   80
CLASS H           5^
CLASS  I           2
                                                      I   I    I    I
                                          10
                                   DISTANCE - kilometers
                                                            15
                                                                               20
  FIGURE 12  ANNUAL  AVERAGE S02  CONCENTRATION  Ug /m3 )   FOR A TOSCO H OIL
             SHALE PLANT USING  SALT LAKE CITY, UTAH METEOROLOGY
                                       59

-------
    13
    12
    10
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          FEDERAL PRIMARY
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                           15
          BACKGROUND •  26 ^g/m3


                 PLANT

          16,000 mVday PLANT WITH
          EMISSIONS CONTROLLED
                                   9       10      II

                                   DISTANCE-kilometers
                                                        12
13
                                                                       14
                                                                              15
      FIGURE  13    24-HOUR WORST CASE  AVERAGE S02 CONCENTRATION  (Mg/m3)
                   FOR A TOSCO E OIL SHALE PLANT UNDER CONDITIONS OF
                   NEUTRAL STABILITY AND A NORTH WIND OF 1.5 msec'1
                                       60

-------
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   13
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            STANLARD

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15
      FIGURE 15   3-HOUR WORST CASE AVERAGE  HC CONCENTRATION (Mg/m3)
                  FOR A TOSCO H OIL SHALE PLANT UNDER CONDITIONS OF
                  NEUTRAL  STABILITY AND A  NORTH WIND OF  1.5 msec"1
                                     62

-------
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   20
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            STANDARD

          FEDERAL PRIMARY  100
PLANT
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                                                 EMISSIONS CONTROLLED
                                        10
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                                                         15
                                                                          20
  FIGURE 17  ANNUAL AVERAGE NOX CONCENTRATION ( Mg /m3)   FOR A TOSCO  Tl OIL
            SHALE  PLANT USING GRAND JUNCTION, COLORADO METEOROLOGY
                                      64

-------
UJ
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          STANDARD ( /tg/m  )

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                                                          16,000 m3 /day PLANT
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                                  DISTANCE-kilometers
        FIGURE 18   ANNUAL  AVERAGE  NOX CONCENTRATION (^g/m3)   FOR A
                    TOSCO I OIL SHALE PLANT USING SALT LAKE CITY, UTAH
                    METEOROLOGY
                                       65

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portion of the standard.  When background concentrations equal or exceed


a standard,  the level of control has been specified as 99+ percent.  The


Federal Class I and Class II standards are the so-called "non-degradation"


standards; they refer to increases in concentrations and do not involve


background concentrations.



          For particulates of the TOSCO II process, uncontrolled emissions


will produce concentrations that exceed all standards listed in Tables 9


and 10, except the federal primary and secondary air quality standards.


Background concentrations for particulates and SO  were measured in the
                                                 £

Parachute Creek area of the Colorado oil shale region by the Colony

                                              6
Development Operation and analyzed in a report  by Dames & Moore.  The


median of the 24-hour averages of background concentration of particulates

                             3
was found to be about 15 |ag/m .   The average annual background concentra-

                                        3
tion is expected to be less than 15 M-g/m .  The combination of background


concentrations with plant-produced concentrations for those standards for


which this is applicable reveals the necessity for controls slightly  in


excess of 35 percent in order to meet the federal primary 24-hour  standard.


The Colorado annual standard requires 12 percent control.  The federal


24-hour secondary standard can be met with approximately 64 percent control


of plant emissions.  Approximately 97 percent control will be needed  to


meet the Class I 24-hour standard and 85 percent will be needed to comply


with the Class I annual standard.  The Class II 24-hour and annual stan-


dards require 92 percent and 71 percent controls, respectively.



          Projected concentrations of SO  do not exceed the federal
                                        £

primary air quality standards nor the Class II 24-hour standards.


Dames & Moore found the 24-hour average background concentration of

                 3
SO  to be 26 Hg/m .  The annual average is expected to be less than


this amount.  The addition of background concentrations to the calcu-


lated concentrations resulting from the plant is not sufficient to
                                   68

-------
exceed the federal primary air quality  standards.  However, SO  concen-
                                                              £

trations from the plant exceed the stringent Colorado annual  air quality



standard, where 99+ percent control is  required, since background concen-



trations alone may exceed the standard.  The Federal Class  I  annual  and



24-hour standards can be met with 89 percent and 71 percent control,



respectively.  The Class II annual standard requires 72 percent control.




          No controls are required for  HC and NO , since the  concentra-
                                                x

tions of these pollutants are well below all applicable standards.




     3.   In-situ Process




          Figure 3 (in Section IV) shows the stack configuration of

          3
a 16,000 m /day (100,000 barrel per day) in situ plant.  The  incinerator



off gas release point shifts location from la to Ib to Ic during the



20-year life of the plant.   Table 3 (in Section IV) lists the stack



characteristics and emission rates used in concentration computations.




          The results of modeling the air quality levels of an in situ oil



shale plant are summarized in Tables 11 and 12 from production of 16,000 B/D



and 100,000 B/D respectively.  Projected annual and 24-hour average partic-



ulate levels do not exceed federal primary and secondary standards nor



Colorado standards; therefore,  no controls are required.   The radical



reduction of particulate levels for the in situ process,  as compared to the



TOSCO II process,  can be attributed to  the nature of subsurface  retorting



techniques.   However, the Class I annual standard requires 29 percent control



and the Class I 24-hour standard requires 76 percent control.   The Class II



annual standard requires no control and the Class II 24-hour standard can



be met with 27 percent control.




          Sulfur dioxide concentrations do not exceed the federal



primary annual and 24-hour standards,  regardless of the location of



the incinerator.   However,  99+ percent  control is required to meet



Colorado annual standards due to background concentrations, 78 percent




                                   69

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control is needed to avoid violation of the Federal Class I annual standard


and 45 percent control is required -to meet the Class II annual standard.


No controls are required for maintenance of the Federal Class I and


Class II 24-hour standards.  Concentrations of HC and NO  from the
                                                        x

in situ plant are well below the federal and Colorado standards, regard-


less of the noted changes in plant configuration.




          It should be stressed that a stack's diameter, temperature and



exit velocity have a great deal of influence on the concentrations result-


ing from the stack's emissions.  A comparison of TOSCO II process and



in situ process emissions and concentrations exemplify this influence.   An


inspection of Tables 2 and 3 (in Section IV) reveals that the total S02


emissions from the in situ plant are approximately three times the total SO


emissions from the TOSCO II plant, while the in situ concentrations are



one-third to one-half of the TOSCO II concentrations.  It was found that


most of the in situ plant's SO  emissions are released from one stack,


and the large diameter and temperature of that stack allow the pollutant


to be mixed in a layer of sufficient depth so as to result in negligible



ground-level concentrations.  Since little contribution to ambient con-


centrations resulted from this stack, the concentrations appearing in


Table 11 were produced by the remaining stacks.  It should be noted,


however, that changes in the stack characteristics of this source could


drastically change SO  concentrations.
                     £



     4.   Complex of Plants




          The preceding discussions of- control levels applies to a


single plant using a particu'lar retort process.  If more than one plant



is present, the interaction of pollutant dispersion between the plants



must be considered.  To evaluate this interaction, the complex of plants,



each with its own production level, stack characteristics and emission


rates, should be modeled together.  At the present time, sufficient
                                   72

-------
information on the different oil shale recovery schemes and the planned


configuration of plants is not available for a proper assessment of


resulting pollutant patterns.  The information available does not seem


to warrant modeling a plant complex with the fine mesh of receptors


necessary to resolve the pollutant distributions.  However, on the basis


of the modeling results for the TOSCO II and in situ plants, some recom-


mendations can be made.  The distances of maximum concentration for each


pollutant and the rate at which the concentrations change with distance


are the determining factors for effective plant placement.  It is evident


from an examination of the pollutant patterns shown in Figures 7 through 18


that plants situated in fairly close proximity can produce significantly


higher concentrations than those arising from a single plant, particularly


when one plant is directly downwind of another plant.  A separation of


20 to 25 kilometers between plants should be sufficient to minimize any


adverse effects arising from the interaction of each plant's pollutants.



          The concentrations,discussed above were computed assuming a

        3
16,000 m /day (100,000 barrel per day) level of production.  For other


production levels, the concentrations should be multiplied by the appro-


priate factor and the required control adjusted accordingly.  For example,


concentrations should be reduced by one-half to obtain values for a 8,000

 3
m /day (50,000 barrel per day) plant.



     F.   Recommendations



          The above results for the oil shale region were obtained using


a number of assumptions involving plant emission rates and configurations


as given in Tables 2 and  3  and Figures 2 and 3 and the meteorology of


Grand Junction,  Colorado, and Salt Lake City, Utah.  Changes in any of


these variables could produce important differences in the predicted


concentrations and, therefore, control requirements.  Before definitive
                                    73

-------
results can be obtained  for a  specific  oil  shale  facility,  the  actual

stack parameters and their emission rates for the proposed  or existing

plant should be obtained and sufficient meteorological  information  on

the actual plant site should be gathered.



                               REFERENCES
1.   Final Environmental Statement for the Prototype Oil-Shale  Leasing
     Program, Vol.  I.,  Regional Impacts of Oil  Shale Development,  U.S.
     Department of the  Interior (1973).

2.   D. O. Martin,  and  J. A.  Tikvart,  "A General Atmospheric  Diffusion
     Model for Estimating the Effects  on Air Quality of One or  More
     Sources," Air Pollution Control Association Paper No.  68-148  (1968).

3.   K. L. Calder,  "A Climatological Model for  Multiple Source  Urban
     Air Pollution," presented at the  First Meeting of the  NATO Committee
     on the Challengers of a Modern Society, Paris, France  (26-27  July
     1971).

4.   Parachute Creek Valley Diffusion  Experiments,  Battelle Pacific
     Northwest Laboratories,  September 1972.

5.   Climatology at Parachute Creek, Colorado,  Dames & Moore, April  1973.

6.   An Evaluation of Existing Air Quality Data Obtained at the Parachute
     Creek Site of Semi-Works Plant, Dames & Moore, July 1973.

7.   Impact on Air Quality from Oil Shale Development, Final  Draft,  for
     U.S. Department of Interior, Engineering Science, Inc.,  McLean,
     Virginia (January  1973).

8.   A. D. Busse, and J. R. Zimmerman, "User's  Guide for the  Climatological
     Dispersion Model," Office of Research and  Development, Environmental
     Protection Agency, Research Triangle Park, North  Carolina  (1973).

9.   Air Quality Data for 1968 from the National Air Surveillance  Networks
     and Contributing State and Local  Networks.  Environmental  Protection
     Agency, Division of Atmospheric Surveillance,  Research Triangle Park,
     North Carolina (August 1972).
                                   74

-------
10.    E.  E.  Hughes,  E.  M.  Dickson,  and  R. A. Schmidt, "Control of
      Environmental  Impacts  from Advanced Energy Sources," Contract
      No. 68-01-0483,  prepared  for  Office of Research and Development,
      Environmental  Protection  Agency,  SRI Project No.  2714, Stanford
      Research Institute,  Menlo Park, California  (1974).

11.    Air Quality Data—1972 Annual Statistics, Environmental Protection
      Agency, Monitoring and Data Analysis Division, Research Triangle Park,
      North Carolina (March  1974).

12.    G.  A.  Briggs,  "Plume Rise," U.S.  Atomic  Energy Commission, Office of
      Information Services (1969).

13.    D.  B.  Turner,  "Workbook of Atmospheric Dispersion Estimates," Office
      of  Air Programs,  Environmental Protection Agency, Research Triangle
      Park,  North Carolina (1970).
                                    75

-------

-------
              VIII   CONTROL REQUIREMENTS FOR AIR POLLUTANTS



     In order to determine whether the emissions of air pollutants* from


the oil shale industry are likely to be excessive and, therefore, to


require more control than appears available with the best current


technology, we have compared the anticipated emissions with two different


types of standards.  The first is the ambient air quality standard.


Comparisons with this type of standard have been presented in the preceding


section (Section VII), where emissions from TOSCO II and in situ retorts


were used to calculate ambient concentrations at ground level in the
                      3
vicinity of a 16,000 m /day (100,000 barrels per day) plant.  The second


type of standard that can be used in an estimate of the need for air


pollution control is the emission standard.  This section of the report


summarizes the findings of the previous section on ambient air quality


and presents some relevant comparisons of emission standards.


     Throughout this section control requirements are expressed in percent,


meaning the percent of the emission that must be removed in order to


achieve an ambient concentration or an emission level lower than the


comparison standard.  The control requirement derived here refers to the


degree of control needed in addition to that achievable with best available

control.  The following section (Section IX) presents our,findings as to


what constitutes best available control applied to the TOSCO II retorting


system proposed and described by the Colony Development Operation.1*  As


defined in Section  IX, best available controls lead to emission streams

                                           3
with particulate loadings less than 46 mg/m  (0.02 gr/SCF) and emissions


of combustion gases that meet the new source performance standards for


fossil fuel fired boilers.  The proposed Colony plant is the basis for
*
 Numbers refer to references given at the end of this section.


                                   77

-------
the discussion of control requirements in this report, the only exception


being use of an in situ plant for some of the work reported in the


preceding section (Section VII).



     The control requirements derived from dispersion modeling and


comparison with ambient air quality  standards are summarized in Table  13.


The multiplicity of possible standards leads to the multiple estimates


of control requirements.  The implication of Table 13 and the supporting


work in Section VII is that significant additional control may be needed


to prevent the violation of some of  the very strict ambient air quality

                                                                o
standards for particulates and  SO  in the vicinity of a  16,000 m /day
                                 £t

(100,000 barrels per day) oil shale  plant using the TOSCO II process.



     It should be pointed out that the maximum requirements for additional


control summarized in Table 13  are not necessarily requirements for


improved technology for removing pollutants from emission streams.  Some


of the maximum values given in  Table 13 are based on maximum concentrations


calculated to occur quite close to some of the relatively low stacks of


the proposed plant.  While details of this phenomena are apparent only


through an examination of a number of calculations using different stacks,


stack locations, and stack heights as inputs, the effect is clearly


displayed in some of the figures presenting results of the dispersion


modeling in Section VII.  Figures 10 and 14 are significant examples of


this effect and the implications.for deriving control  requirements.   In


both of these cases,  a high concentration of the pollutant occurs next


to a low (only 15 meters high)   stack because winds will bring some of the


pollutant to the ground right at the stack.   Because this problem can be


solved by use of moderate height stacks (about 50 meters),  it should not


be made the basis of a requirement for additional emission stream clean-up.



     The same logic does not apply,  however, to avoiding excessive ground


level concentrations associated with taller stacks.   The implication of
                                   78

-------
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                                            79

-------
the EPA position limiting the use of tall stacks to control air pollution



from electric power plants would suggest that stacks more than 100 meters



(very approximately) should not be considered acceptable means of air



pollution control for an oil shale plant.  The stacks in question here could



be made considerably higher without exceeding likely EPA restrictions on



stack heights deemed suitable for inclusion in an air pollution control



system for such a facility.  Further clarification concerning the use of



tall stacks will depend upon the generation of definitive data regarding



sulfates and chemical transformations in the atmosphere.





     A comparison of Figure 14 with Tables 9 and 10 will show that the



concentration chosen for calculating the SO2 control requirements is the



         level that  occurs  over  5  km from the  plant  rather  than  the very
much higher  level  (perhaps 900(j,g/m3)  that  is calculated  for  a  small  area



within  the plant itself.  On the other hand, the maximum particulate



concentration of 377^g/m3 shown in Figure  10 is used  as  a basis  for



deriving control requirements in Tables 9 and 10, despite the fact  that  it



occurs  very  close  (about 0.5 km) to the plant and must reflect a significant



contribution that  could be removed by increasing the  height  of the lowest



stacks.  In  this latter case, there is no  obvious alternative  level of



concentration on which to base a control requirement.  The summary table



that concludes this section presents control requirements that reflect



our judgment on this matter.





     The estimation of control requirements on the basis of emission



standards must be  carried out under the assumption that  emission standards



set for other industries can be applied to the oil shale industry.  The



sources of significant quantities of emissions from oil  shale  processing



will be new  plants.  Therefore, it is appropriate that the emission



standards applied  be new source performance standards.   In the absence



of such standards  for the oil shale industry itself,  we  have sought



analogies elsewhere.  It appears that the  developers  of  oil shale tend to





                                    80

-------
make comparison to the standards for emissions from utility boilers,



and that these comparisons are made on the basis of weight of pollutant




per unit of energy consumed in the process.  Such a comparison is presented



in Table 14.





     Not all the emissions of the three pollutants are included in Table



14.  Only those emissions that are produced in combustion processes are




included, because only these are logically comparable to the fossil fuel



boiler case.   This point is especially significant with respect to the




particulate emission because less than a tenth of the total particulate




emissions from a TOSCO II plant having "best controls" are included in




the category  of emissions from the combustion process itself.   Over 90



percent  of the particulate emissions are from processes other than pure




combustion, namely, from the  shale handling, shale heating, and ball



cleaning operations shown in Figure 21 and Tables 16 and 19 of Section IX.




The pure combustion processes  are those listed in Table 20 as associated



with product upgrading.  Therefore, the implication of Table 14 that no




additional control of particulate emissions is required is not inconsistent




with the results of the air quality modeling of Section VII.





     The conclusions to be drawn from the comparison of combustion




emission factors in Table 14  are as follows:  (1) no additional control



is required on particulate emissions due directly to the combustion of



fuel to  fire the retort; (2) about 20 percent additional control is



required in the combustion process to bring the SO  emissions into



compliance with analogous emission standards for oil fired fossil fuel



boilers; (3) nearly 95 percent control of NO  is required to bring the
                                            X


combustion of fuel oil into compliance with analogous emission standards



for oil  fired fossil fuel boilers.  The table also suggests that much,



but certainly not all, of this additional control requirement for NO
                                                                    X



can be met by making maximum  use of gas and butane (C4 liquids) fuels




produced along with the  shale  oil.





                                  81

-------
                                            14

                     EMISSIONS  FROM COMBUSTION  IN THE TOSCO  II

             PROCESS  COMPARED WITH FEDERAL STANDARDS  FOR UTILITY BOILERS
   Pollutant
(and fuel burned*)
                            Emission  Factors  in Weight  per Energy Consumed
Emission Factor (kg/GJ)
               Emission Factor (lb/10 Btu)
TOSCO
Standard
TOSCO II
                                      t
Standard*
Particulates (gas) 0
Particulates (C ) 0
Particulates (oil) 0
S°2
S°2
S°2
NO
X
NO
X
NO
X
(gas)

(oil)
(gas)

(C4)
(oil)
0
0
0
0

0
2
.007
.009
.045
.22
.06
.43
.37

.39
.09
0.
0.
6.

0.
0.
0.

0.
0.
0043
043
043

35
35
087

130
130
0,
0
0,
0
0
1
0

0
4
.017
.02
.11
.51
.14
.00
.85

.91
.85
0.
0.
0.

0.
0.
0.

0.
0.
1
1
1

8
8
2

3
3
   The TOSCO II plant can burn any one of three fuels produced from the oil
   shale:  a fuel gas, a butane fuel (C  compounds), or a fuel oil.

   Source:  Colony Development Operation, Reference 1.

   Source:  EPA new source performance standards for fossil fuel boilers,
   The Federal Register, 23 December 1971.
                                       82

-------
     The findings presented in this section and the preceding one,


Section VII, indicate a wide range of quantitative estimates of control


requirements, depending primarily on the choice of comparison standard.


The table just presented, Table 14, provided an emission standard


comparison for estimating requirements for controls beyond those


planned for Colony's TOSCO II plant.  Our estimates for control required


beyond the best available control case presented in the following


section, Section IX, are given in Table 15.  These control requirements


are derived from the dispersion modeling (Section VII) applied to the


emissions of the "best available control" case presented in Section IX.


No need for additional control beyond the best available is indicated for

hydrocarbons and oxides of nitrogen.  A range of control requirements


is indicated in Table 15 for both particulates and sulfur dioxide.


These are the ranges we consider to be reasonable, as explained below.



     The range of estimated control requirements has been narrowed from


the extremes that can be found in the preceding tables of this section


and Section VII by making the following assumptions, which we take to be


reasonable:  (1) because the oil shale region now enjoys a minimum of air


pollution, it is unlikely that air quality there will be allowed to be


degraded to the most lenient standard.  Hence, the federal primary


ambient air quality standards are ruled out; (2) if a significant oil
                                                                 j
shale industry is allowed to come into being in western Colorado, the


region will not be classified as one where the most strict non-degradation


standards will be applied.   Hence, the Class I federal and the most strict

                          2
Colorado (i.e. , the 15'pg/m  24-hr. SO ) air quality standards are ruled


out;  and (3) to compensate for local effects of unnecessarily low (about

15 m) stacks only concentrations applicable over areas more than one square


kilometer in size and more than one km in distance from the plant are used for


quantifying control requirements.   Hence, the calculated maximum con-

                                                                         o
centration of particulates for the 24-hour worst case is taken as 200^g/m


rather than the 377|j,g/m3 peak used in Tables 9, 10 and 13.


                                  83

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     The conclusions in Section I regarding requirements for control of
oil shale air pollution beyond the best available control case are drawn

from Table 15 and the discussion presented in this section to explain
and justify the values adopted in Table 15.


                               REFERENCE


1.    "An Environmental Impact Analysis for a Shale Oil Complex at
     Parachute Creek, Colorado," Vol.  1, Part 1,  published by Atlantic
     Richfield Company as operator for the Colony Development Operation,
     Denver, 1974.
                                    85

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-------
            IX ASSESSMENT OF AIR POLLUTION CONTROL METHODS




A.   Introduction



     As described in Sections IV and V of this report,  the TOSCO II re-


torting process seems likely to dominate the oil shale  industry at least


in the early stages of industry growth.  This process is the only one for


which emissions figures are available on a unit operation basis.  These


considerations have led SRI to adopt this process as representative of


the industry for purposes of estimating emissions.  It  will be seen that


certain elements of the process will be common to other above-ground re-


torting methods, while other elements are unique to TOSCO II.   These


distinctions will be discussed so that an appreciation for the degree


to which conclusions depend on this choice may be" gained.



     The data on the TOSCO II process are taken from the Environmental

               1*
Impact Analysis   published by the Colony Development Operation.  The


Atlantic Richfield compa'ny (ARCO) is the operator for the group of com-


panies that comprise Colony.  The shale oil complex planned by Colony


incorporates certain control devices and methods that are considered by


the operator to be adequate to ensure that appropriate  federal and state


standards are met.  No claim is made by the operator that "best control"


is achieved, or that a complex of plants like the Colony operation in the


same vicinity would not violate appropriate standards.   The objective in


this section of the study is to ascertain how effective the applied con-


trols are, and to estimate what degree of control may reasonably be ex-


pected in an effort to apply best available control to the system des-


cribed by Colony.  The estimate of these limits will help in the assess-


ment of the impact of a developing industry, and will help define the


need for improved control technology.
*References are listed at end of section.



                                   87

-------
     A definitive,  detailed engineering analysis  of  all  process  streams


and potential control methods comparable to the effort extended  by the


operator and his contractors responsible for designing controls  systems


is far beyond the scope of this study.   In any event, important  details


of various process  steps are considered proprietary  and  not  available  for


our examination.  In spite of these facts, the available data  are ade-


quate for a model and several useful conclusions  may be  drawn  concerning


emissions control.   The selection of control methods is  intimately bound


to process economics, a particularly proprietary  matter.   Hence,  it is


assumed that the kind of device selected for a particular application  is


the appropriate choice, but not necessarily that  it  is operated  at maxi-


mum effectiveness.   Where control remains inadequate at  maximum  effec-


tiveness, further development would be  necessary.  Where alternative


controls were considered by the operator, these are  discussed.  In other


words, redesign of  the TOSCO II process as implemented by Colony is not


attempted.



     For each of the major process steps in the Colony design  the


emissions are estimated assuming "best  control"  is applied.  These


judgments are based on familiarity with the types of control equipment


specified by Colony and with the performance that can be expected at


what is judged a reasonable cost.  Specific, quantitative estimates


of best control are given in this section for each unit  of the process.


Control performance is conservatively estimated  in that  better perfor-


mance has been achieved in limiting cases.  Where improved control is


achieved with cleaner fuels, the assumptions underlying  the 'best con-


trol" case are clearly stated.  However, it must  be  emphasized that the


plans for the fuels to be used are only tentative in any case.



     In addition to the data in the Environmental Impact Analysis,

                                                               2
some data gained in personal communication with  representatives  of
                                  88

-------
Colony were useful in the study.  This assistance is gratefully ack-



nowledged.






B.   Description of Process





     A detailed description of process streams for the TOSCO II process



is given in Section IV.  A modular description is presented here so that



elements common to other retorting methods can be identified and the



emissions for each module can be characterized.   A simplified process



diagram for any above-ground retorting plant is  given in Figure 19.





     In the ore-preparation module shown in Figure 19 the run-of-mine



ore is reduced to a maximum size compatible with the retorting method.



A sufficient quantity of ore in the various stages of preparation is



placed in storage to guard against interruptions in mine output or



crushing equipment failures.  The only emission  of consequence here is



dust--fugitive dust from the transport and storage of the ore and dust



generated in the crushing operation.  The magnitude of these emissions



depends in part on the fineness of the feed required by.the oil shale



plant, but may be unprecedented in magnitude lecause of the vast quantitj



of material to be handled.





     In the retorting module shown in Figure 19  the ore is converted



to a useful hydrocarbon product plus a shale ash to be discarded.  The



emissions to the atmosphere from this module vary greatly in kind de-



pending on the retorting method.  Products of combustion are always



present, and these may be mixed with process constituents in some re-



torts.  Control problems in this module may be unique to oil shale



processing or to specific retorts.  In the TOSCO II process, for



example, flue gases are loaded with dust and hydrocarbons from direct



contact with the shale.  Control problems are compounded by the large



quantities of effluent to be treated.  Most of the fuel consumed in a
                                   89

-------
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plant is consumed in this module.  Finally, shale ash disposal presents


dust control problems for any retort.



     In the product-upgrading module shown in Figure 19, the hydrocarbon


product from the retort is further processed into a more useful form.


Emissions in this module consist of combustion products plus sulfur


dioxide resulting from removal of sulfur compounds from the process


streams.  None of these emissions is unique to oil shale processing.



C.   Emissions and Controls



     The emissions estimated and controls planned by the Colony Develop-


ment Operation  for a TOSCO II plant are now considered in some detail.

                                      3
The Colony plant would produce 8,000 m /day (50,000 barrels/day) of


product.  The present estimates are made for a hypothetical plant twice


that size.



     The ore-preparation system is indicated schematically in Figure  20.


The primary crusher reduces the ore to a maximum size of about 23 cm


(9 in), and this is further reduced in the final crusher to less than


1.25 cm (1/2 in).  Dust control at these sites and at the fine ore


storage facility is maintained with a baghouse.  Estimates of emissions


and control performance are given in Table 16.



     The estimates of "Emissions Without Control Devices" were not


given directly by Colony, but were deduced by SRI from the values given


for disposal of dust from these control points and from the stated flow


rates.  The "Emissions Remaining With Planned Control" shown are as given by


Colony.  From these values the "Device Efficiency" shown is calculated.

                                                       3
SRI estimates that a dust loading not exceeding 46 mg/m  (.02 gr/ACF)


is an achievement reasonable to expect in a well maintained baghouse.


Higher performance might be achieved, but this conservative estimate


serves as a base to calculate the "Emissions Remaining With Best Control"
                                  91

-------
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          93

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and "Efficiency With Best Control.   The resulting  values  for  efficiency



appear quite reasonable.





     Various sources of fugitive dust  remain in the ore-preparation



system planned by Colony, even after the provision  for enclosures



surrounding transport and processing equipment.   The most  important



potential source is the stockpile of coarse  ore from the primary



crusher.  Control is maintained with water sprays,  and the planned



site is selected to minimize the surface area exposed to the wind.



The magnitude of this problem will  depend directly  on the  detailed



topography of the stockpile, which is  constantly changing  in normal



operation, and the persistence in applying a water  spray.   In  the



absence of detailed assumptions, estimates have little meaning.



However, it seems reasonable to assert that  sufficient spraying  can



be applied to effectively suppress dust levels below those resulting



from the sources listed in Table 16.





     The pyrolysis and oil recovery unit for the TOSCO II  process  is



shown schematically in Figure 21.  This unit is analogous  to the re-



torting module in Figure 19.  The majority of each  type of pollutant



emitted from a TOSCO II plant is emitted from this  unit.   About  two-



thirds of all combustion takes place here, and the  shale  is further



crushed very finely in the pyrolysis drum.





     Colony plans to use only process  fuels for combustion. Three



distinct fuels will be used—fuel gas, C  liquids (butanes and butenes),



and a distillate fuel oil.  All the fuel gas and C   liquids produced



will be consumed.  The remaining needs will be made up with the fuel



oil.  A complicated fuel system provides various combinations  of fuels



to furnaces equipped with multiple burners.   The proportions will be



highly variable during normal plant operation.  A typical  consumption



schedule for the plant is given in Table 17 and is  the basis for
                                  94

-------
 emission rates presented below in Tables 19,  20,  and 21.


      The fuel gas and C  liquids are treated  in the gas recovery and


 treating unit to remove hydrogen sulfide.   The fuel oil could be gas


 oil or naptha (see Fractionator in Figure  21) or a blend of the two.


 Colony plans to use gas oil before upgrading  and removal of moderate

 sulfur and high nitrogen content.  The maximum emission rates for these


 three fuels as specified by Colony are given  in Table 18,  along with the


 federal performance standards tor new power plants for comparison.


     Estimates of emissions from the pyrolysis and oil recovery unit using


these fuels are given in Table 19.  The raw shale preheat system consumes


nearly all the fuel supplied to this unit.   Hot flue gases from the  ball

heater contact the raw crushed shale directly,in a fluidized bed, adding


particulate and hydrocarbon loads to the combustion products.  An


incinerator reheats the flue gases and reduces the hydrocarbons volatilized


in the fluidized bed.  The ball circulation system uses flue gases from


the steam super-heater to remove residual,  processed-shale dust.  Dust


removal is accomplished with dry cyclones followed by venturi wet scrubbers.


The processed-shale moisturizing system emits  only particulates in the form


of processed-shale dust, controlled with a  venturi wet scrubber.


     The values given for particulate emission in Table 19 were deduced or


calculated as in Table 16.  An exception is the Emissions Remaining  7/ith


Planned Control of particulates in the raw  shale preheat system.  The

emission rate and loading values given by Colony seemed to be inconsistent.

The loading value, consistent with SRI estimates of performance reasonably

to be expected, was accepted and used to calculate an emission rate  nearly
                                                          o
double the Colony value.  This same loading value, 46 mg/m  (.02 gr/ACF),


is the basis for the SRI estimate of Emissions Remaining 'Vith Best Control


for the other scrubbers in this unit.
                                    95

-------
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                                          101

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     The basic control method for SO  planned by Colony consists of the
                                    £t

use of treated fuels.  Flue-gas desulfurization was considered by Colony


and judged to be more expensive and less reliable.   Colony has indicated


that if the emissions of SO  must be reduced for the plant, a treated
                           2t

fuel would be used to replace the planned fuel oil  in the proportion


necessary to meet requirements.  The cost for this  was estimated at


"approximately one-eighth of a barrel of low sulfur fuel oil product


.  . . per barrel of  'treated' fuel oil burned."  The characteristics of


such a treated fuel oil were not specified;  however, both SO  and NO
                                                            ^       x

emissions could be reduced by additional hydrogenation of the fuel oil.


This hydrogenation would remove sulfur as H S and nitrogen as NH .  In
                                           ^                    «3

practice the nitrogen is harder to remove than the  sulfur, so that re-


ducing the relatively high nitrogen content in the  fuel oil to lower


levels would result in even greater reduction of the sulfur level.


However, for purposes of defining best available control, SRI has


assumed that the treated fuel oil cbuld meet the federal performance


standards for oil fired boilers shown in Table 18.   The substitution


of this treated fuel oil results in the SO  and NO   Emissions Remaining
                                          2      x

With Best Control shown in Table 19.  It is seen that the NO  emission
                                                            x

is substantially reduced with this substitution. The SO  emission
                                                        £t        ^

must be regarded as an upper limit, since hydrotreatment is more effec-


ti.ve on sulfur as described above.



     A major cost consideration for Colony regarding flue-gas desul-


furization is related to the large (125 to 150 percent) excess-air


firing in the shale preheat system where nearly all the fuel oil is


combusted.  This practice, done for process reasons, results in much


larger quantities of effluent to be treated and correspondingly larger
                                  102

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capital and operating costs.  Nonetheless, should greater control of


SO  emissions be required to meet a standard,  flue-gas desulfurization
  £t

is certainly an option to be considered and compared in cost with addi-


tional hydrotreatment.  Flue-gas desulfurization equipment appears to


be capable of meeting the additional control requirement shown in

                                   3
Section VIII and in Table 21 above.



     Estimates of emissions from the remainder of a TOSCO II plant are


given in Table 20.   These units comprise the product-upgrading module


shown in Figure 19, and would be similar for any retort producing a


similar product.  Emissions result from the combustion of treated fuels,


as examined above,  and from the operation of the sulfur plant.  The


performance of the specified tail-gas treating plants is considered to


be a reasonable estimate.



     Finally, Table 21 shows the totals of emissions of each type listed


in Tables 16, 19, and 20.  This table is intended to be an indication of


overall performance showing planned controls and, with reasonable assump-


tions, limits of best available control using the same basic scheme.




D.   Estimates for Other Retorting Schemes



     The emissions estimates for ore-preparation modules would be similar


to those given in Table 16 for any retorting method requiring a maximum


size of 1.25 cm (1/2 in).  Furthermore, it is seen that the emission


rates, for both primary and final crusher are approximately the same


in spite of the size difference.  A reasonable estimate for any retort


accepting a large-size feed of about 20 cm (8 in) would be that for the


primary crusher, and for a retort requiring a  substantially smaller size


the total for both crushers would be a reasonable estimate.   The estimate


for ore storage could be used for either case.
                                 103

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     Emissions from a retorting module could differ significantly from


the estimates in Table 19.  Particulate and hydrocarbon emissions from


the raw shale preheat system and ball stack system result  from the
                                                            W

specific design of TOSCO II.  These could be absent in other retorts,


except for relatively insignificant particulate emissions  from the


combustion.  The estimate for the processed-shale moisturizer  should


serve as an upper limit for other retorts where the shale  has  not been


so finely crushed.



     Estimates of SO  and NO  emissions in the retorting and product-
                    ^       X

upgrading modules depend primarily on the sulfur and bound-nitrogen


content in the process fuels and the total quantities combusted.   Under


present conditions, hydrotreating the process fuels is the likely con-


trol method due to the nature of the plant and respective  costs.   Again,


if further reduction of SO  emissions is required after hydrotreatment,
                          2t

flue-gas desulfurization could be applied.  Unlike the operation  planned


by Colony, process restrictions may not exist to make flue-gas desul-


furization more difficult.  Even other TOSCO II installations  could


differ with regard to the fuels planned, especially for the shale-


preheat system.



     The emission of SO  from the sulfur plant depends primarily  on the


total output of low-sulfur product, but is small relative  to combustion


emissions.
                                 104

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                          REFERENCES
Atlantic Richfield Company,   An Environmental  Impact Analysis for
a Shale Oil Complex at Parachute Creek,  Colorado," Vol.  1,  Part I,
Colony Development Operation (1974),

Private communication, Robert E. Smith,  Atlantic Richfield  Company
(Colony Development Operation).

Proceedings: Flue-Gas Desulfurization Symposium—1973,  EPA-650/
2-73-038, December 1973.
                             105

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 SECURITY CLASSIFICATION Of THIS PACE (Wtait Ottm
              REPORT DOCUMENTATION PAGE
                                                           READ INSTRUCTIONS
                                                       BEFORE COMPLETING FORM
 I  REPORT NUMBER

          EPA-600/2-75-009
                                          2. OOVT ACCESSION NO,
                                                                RECIPIENTS CATALOG NUMBER
 4 TITLE (an* Sufcflll*)

          OIL SHALE  AIR POLLUTION CONTROL
                                                  I. TYPE OF REPORT • PERIOD COVERED

                                                       FINAjL
                                                                PERFORMING ORG. REPORT NUMBER
                                                                  Project  2714
     E. E. Hughes,  P.  A. Buder, C.  V.  Fojo,
     R. G. Murray,  R.  K. White
                                                     CONTRACT Oft CHANT NUMBER/*.)

                                                       68-01-0483
 9. PERFORMING ORGANIZATION NAME AND AOORESJ
     Stanford Research Institute
     Menlo Park, California   94025
                                                   10.  PROGRAM ELEMENT. PROJECT, TASK
                                                      AREA • WORK UNIT NUMBERS
                                                    1NBH58    PEMP  02
 II. CONTROLLING OFFICE NAME AND ADDRESS
     Office  of Research and  Development
     U.S. Environmental Protection Agency
     Washington, D.C.   20460    	
                                                  II.  REPORT DATE
                                                    (date  sent to publication)
                                                   IS. NUMBER OF PAGES
                                                       105
 14  MONITORING AGENCY NAME ft ADORESftfff tffffwwtt
                                   Cwtfr*flln4 Office)
IB. SECURITY CLASS, (ol lltlt
    UNCLASSIFIED
                                                             1S«. OECLASSIFICATION/OOWNGRADINO
 )•.  DISTRIBUTION STATEMENT (•! tfil* JUpwrlJ

    Unlimited
 17.  DISTRIBUTION STATEMENT (•! If)* •fecfrMl «H(*rW In •!••» M. II HIHrml Hum
 IS  SUPPLEMENTARY NOTES
                         (continued  from No.  20)
 Colony.  Requirements for additional control are estimated by comparing calculated ambient air
 quality with standards.  Options  for supplying the additional control Indicated for particulates
 and  sulfur dioxide are identified.
   KEY WORDS rC«rttaw «n
     oil  shale
     TOSCO II retort
     air  pollution
     dispersion  modeling
                •14* If *•*•••«? tnt Mmrf fr ftp fel«cfc i
                       control technology
                       control requirement
                       Colony Development Operation
                       environmental  impacts
 0 ABSTRACT CCcntlnu* *n IWMTIM »I4» H n*c***a/r «Ml l«M«lf^ »r M*«*
     This study evaluates the air  pollution potential of emissions of particulates, sulfur
 ioxide,  oxides of nitrogen, and hydrocarbons from the anticipated development of an oil  shale
 ndustry.   The analysis is based primarily on the published  description of a TOSCO II retorting
 rocess as planned for commercial  use by the Colony Development Operation.  The technology,
 recesses,  plans, projections, and environmental impacts of  oil shale development are reviewed.
The results of dispersion model  calculations of concentrations of pollutants in ambient air near
 11 shale plants employing TOSCO II and in situ processes are presented.  These calculations for
 he TOSCO II plant assume that best available controls are applied to the process planned by
                          	(continued  under  No. 18)
    1 JAN TJ
1473
                  EDITION OF I NOV •• IS OBSOLETE
                                                SECURITY CLASSIFICATION OF THIS PAGE (•»••« OM« *nr*r*«

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