United States
Environmental Protection
Agency
industrial Environmental Research  EPA-600/8-83-005
Laboratory           April 1983
Cincinnati OH 45268
Research and Development
Pollution Control
Technical Manual:

Lurgi Oil Shale
Retorting with
Open Pit Mining

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i TECHNICAL REPORT DATA
f Please read instructions on the reverse before completing)
1 REPORT NO. 2.
EPA-6GO/8-83-OQ5
4. TITLE AXD S'J3TITuE
POLLUTION CONTROL TECHNICAL MANUAL: Lurgi Oil Shale
Recorting v»ith Open Pit Mining
7 AUTFOR(S)
Denver Research Institute
a PERFORMING ORGANIZATION NAME AND AODHESS
' Denver Research Institute
University of Deaver
Denver, Colorado 80208
J12. SPONSOt'NG AGENCV NAME AND ADDRESS
Industrial Environmental Research Laboratory
Cincinnati, Ohio 45268
3. RECIPIENT'S ACCESSION NO
r^jmj^^iiijL— J
5 REPOBT DATE
April 1983
6. PERFORMING ORGANIZATION COr>€ ;
8 PERFORMING ORGANIZATION REPORT MO,
1O. PROGRAM ELEMENT NO
N104 CZN1A
11, CONTRACT/GRANT NO
CR-807294
13 TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
f.
EPA/600/12 ]
1.15 SUPPLEMENTARY NOTES
 !6 ABSTRACT
    The Lurgi oil shale PCTM addresses the Lurgi retorting  technology,  developed  by
 Lurgi Kohle and Mineralotechnik GmbH, West Germany, in the manner  in which  this  tech-
 nology may be applied to the oil shales of the western United States.   This  process
 has been proposed for use by both  the Rio Blanco Oil Shale Company  (a  partnership  of
 Gulf Oil Corporation and Standard Oil Company  [Indiana]) and Occidental Oil  Shale, Inc..
 in the phased development of their Federal oil shale lease Tracts  C-a  and C-b  in
 western Colorado.  This document describes a commercial-scale Lurgi oil shale  plant,
 coupled with an open pit mine, based on the design proposed by Rio  Blanco Oil  Shale
 Company.
    This manual proceeds through a description of the Lurgi oil shale plant proposed  by
 Rio Blanco Oil Shale Company, characterizes the waste streams produced in each medium,
 and discusses the array of commercially available controls which can be applied  to the
 Lurgi plant waste streams.  From these generally characterized controls, several are
f examined in more detail for each medium in order to illustrate typical control tech—
| nology operation.  Control technology cost and performance estimates are presented,
I together with descriptions of the discharge streams, secondary waste streams and energy
| requirements.  A summary of data limitations and needs for environmental and control
I technology considerations is presented.
17 KEY WORDS AND DOCUMENT ANALYSIS
a DESCRIPTORS
!
|18. DISTRtBUTION STATEMENT
1 Release to Public
b IDENTIFIERS/OPEN ENDED TERMS
"
t9 seCUfUTV CUASS fTOu Repaxti
Utic Las s ifi ed
jso, SSCWWTY CUXSS flftis,page)
. U-aelas-s£fie4
c COSATI 1 leW/Group

2V, NO, OF PA-G-ES - ; ;
.. 362
22 PfhG-E
    Fen* 2220—1

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                                              EPA-600/8-83-005
                                              April 1983
            POLLUTION CONTROL TECHNICAL MANUAL

                            FOR

                 LURGI OIL SHALE RETORTING
                   WITH OPEN PIT MINING
                  Denver Research Institute
                     University of Denver
                   Denver,  Colorado 80208
                   Cooperative Aareement
                        CR 807294
            Program Manager:   Gregory G.  Qndich
Office of Environmental Engineering and Technology (RD-681)
           U.S.  Environmental Protection Agency
                     401 N Street, SW
                   Washington, DC  20460
             Project Officer:   Edward R.  Bates
 Industrial Environmental Research Laboratory - Cincinnati
                  Cincinnati,  Ohio  45268

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                                 DISCLAIMED
     The  Information  in this  document  has been funded wholly or  in part by
the United  States Environmental  Protection Agency  under  Cooperative Agree-
ment CR-807294  to the  Denver Research Institute,  University  of Denver.   It
has been  subject  to  the Agency's peer  and administrative  review,  and it has
been approved for publication as an EPA document. Mention of trade names or
commercial products does not constitute endorsement or recommendation for use.
                                     11

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                                  FOREWORD
     The  purpose  of the  Pollution Control Technical  Manuals  (PCTMs) is to
provide  process,  discharge, and  pollution control  data  in summarized form
for  the  use of  permit writers,  developers,  and other  interested parties.
The  PCTM series covers  a range  of  alternate fuel  sources,  including coal
gasification,  coal  liquefaction by direct and indirect  processing,  and the
retorting of oil shale.

     The  series consists  of a set of  technical  volumes  directed at produc-
tion facilities based upon specific conversion processes.   The entire series
is  supplemented by  an appendix  volume which  describes  the  operation  and
application of approximately 50 control processes.

     All   PCTMs  are  prepared on a base plant  concept (coal  gasification and
liquefaction)  or  developers'  proposed designs  (oil  shale)  which  may  rot
fu^ly reflect  plants to  be built in the future.   The PCTMs present examples
of control  applications,  both  as  individual  process units and as integrated
control  trains.   Tnese examples  are  taken in part from applicable  permit
applications and,  therefore, are reflective of specific plants.   None of the
examples  are intended to convey an Agency endorsement or recommendation,  but
rather are  presented for  illustrative purposes.  The selection of  control
technologies for application to specific plants is the exclusive function of
the designers  and permitters  who  have the flexibility to utilize the lowest
cost and/or  most  effective  approaches.   It  is  hoped that readers  will  be
able to  relate  their waste streams and controls  to those presented in these
manuals  to  enable  them  to  better  understand the  extent to which  various
technologies may control  specific waste streams  and utilize the information
in makirg control  technology selections for their specific needs.

     The   reader  should -be  aware  that the PCTMs  contain  no  legally  binding
requirements or guidance,  and that nothing contained in the  PCTMs relieves  a
facility   from  compliance  with existing or future  environmental  regulations
or permit requirements.
                              Herbert I.  Wiser
                    Acting Oeputy Assistant Administrator
                     Office of Research and Development
                    U.S.  Environmental  Protection Agency
                                     m

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                                  ABSTRACT
     The  Environmental  Protection  Agency  (EPA),  Office  of  Research  and
Development,  has  undertaken an  extensive study  to  determine  synthetic fuel
plant  waste  stream  characteristics  and  pollution control  systems.   The
purpose of this and all other PCTMs is to convey this information in a manner
that is readily useful to designers, permit writers and the public.
     i 1
      The  Lurgi  oil   shale PCTM  addresses the  Lurgi  retorting  technology,
developed  by  Lurgi  Kohle  und Mineralotechnik  GmbH, West  Germany,  in  the
manner  in which  this  technology may be  applied to  the  oil shales  of  the
western  United States.  This  process  has  been proposed for  use  by both  the
Rio  Blanco Oil  Shale  Company (a  partnership of  Gulf Oil  Corporation  and
Standard  Oil  Company  [Indiana])  and Cathedral  Bluffs Shale Oil  Company (a
partnership of  Occidental  Oil  Shale, Inc.  and Tenneco Shale Oil  Company) in
the phased development of their Federal oil shale lease Tracts C-a and C-b in
western Colorado.  This document describes a commercial-scale Lurgi oil shale
plant,  coupled with  an  open  pit  mine,  based on the  design  proposed  by  Rio
Blanco  Oil  Shale Company.  Plants proposed or built  by  other  developers in
the  future can be  expected to be similar in most aspects  to  the plant  de-
scribed  in this document,  but each can be expected to vary in some respects,
such  as mining methods,  selection of  particular control  technologies, or
methods for upgrading the raw shale oil.

     This manual  proceeds  through a description of the Lurgi oil  shale plant
proposed  by  Rio  Blanco  Oil Shale  Company,  characterizes the  waste streams
produced  in  each medium,  and  discusses the  array  of commercially available
controls which  can  be applied to  the  Lurgi  plant waste streams.   From these
generally  characterized controls,  several  are  examined  in  more  detail  for
each  medium  in order  to   illustrate  typical control  technology operation.
Control  technology  cost  and   performance  estimates are  presented, together
with  descriptions  of  the  discharge  streams,  secondary  waste  streams  and
energy  requirements.   A summary  of data limitations  and  needs  for environ-
mental and control technology considerations is presented.

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                                  CONTENTS
Foreword	1 i 1
Abstract	„	  iv
Figures	viii
Tsb1es 	 ...... 	  xi
Abbreviations.	xvi
Conversion Factors ...........  	  .....  xix
Ac  40
   3.   PROCESS FLOW DIAGRAMS AND FLOW RATES,  ,/...,..,.....  45
       3.1  STRUCTURE OF THE DIAGRAMS.  ,	45
    "  "3,2  OVER-ALL.PLANT COMPtEX.  ..'.'..	,'.„,,'	45

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                           CONTENTS  (cont.)

    3.3  UNIT  PROCESS FLOW DIAGRAMS	47

         3.3.1  Mining, Crushing and Transport of Raw Shale	49
         3.3.2  Lurgi-Ruhrgas Aboveground Retorting	51
         3.3.3  Lurgi*Ruhrgas Oil Recovery 	 :......  51
         3.3.4  Lurgi Lean Oil Absorber and Naphtha Stripper . . .  .  53
         3.3.5  Retort Gas Compression and Cooling 	  56
         3.3.6  Amine Treatment/Triethylene Glycol
                   Dehydration. ...  	 ..........  56
         3.3.7  Stretford Sulfur Process 	  56
         3.3.8  Ammonia Recovery Process ..... 	  60
         3.3.9  Solid Waste Disposal  ...  	 ......  62
         3.3.10  Water Management 	  ....  62

4.  INVENTORY  AND COMPOSITION OF PLANT PROCESS AND
    WASTE STREAMS	  67

    4.1  INVENTORY OF STREAMS	67

    4.2  MAJOR STREAM COMPOSITIONS	91

         4.2.1   Material Balance 	  91
         4.2.2   Raw Oil  Shale	  91
         4.2.3   Processed Shale.  ........ 	  96
         4.2.4   Crude Shale Oil	99
         4.2.5   Retort Gas	99
         4.2.6   Flue Gas	102
         4.2.7   Gas Liquor	  Ill
         4.2.8   Mine Water ...-.-	112

    4.3  POLLUTANT CROSS-REFERENCE TABLES 	  .   112

5.  POLLUTION CONTROL TECHNOLOGY	  123

    5.1  AIR POLLUTION CONTROL.	  .  124

         5.1.1   Participate Control	124
         5.1.2   Sulfur Control	130
         5.1.3   Nitrogen Oxides Control	158
         5.1.4   Hydrocarbon Control	   164
         5.1.5   Carbon Monoxide Control	   168
         5.1.6   Control  of Other Criteria Pollutants  	  .   173
         5.1.7   Control  of Noncriteria Air Pollutants.  .  .  	   174

    5.2  WATER MANAGEMENT AND POLLUTION CONTROL 	   174

         5.2.1   Suspended Matter,  Oil  and Grease	174
         5.2.2   Dissolved Gases and Volatiles	185
         5.2.3   Dissolved Inorganics	192
         5.2.4   Dissolved Organics 	   206
         5.2.5   Water Requirements	   237

    5.3  SOLID WASTE MANAGEMENT .  	   244

         5.3.1   Disposal  Approaches	246

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                           CONTENTS  (cant.)

         5.3.2   Surface Hydrology Control Technologies 	  248
         5.3.3   Subsurface Hydrology Control Technologies	256
         5.3.4   Surface Stabilization Technologies 	  265
         5.3.5   Hazardous Waste Control Technologies ...  	  272

6.  POLLUTION CONTROL COSTS 	  275

    5.1  ENGINEERING COST DATA	  275
         6.1.1   Bases of Engineering Cost Data	275
         6.1.2   Details of Engineering Costs	280

    6.2  COST ANALYSIS METHODOLOGY	  280

         6.2.1   Overview of Cost Analysis Methodology	280
         6.2.2   Economic Assumptions Used in Total
                   Cost Calculations	286
         6.2.3   Solid Waste Management Costs 	  293
         6.2.4   Control Cost Example	294
    6.3  COST ANALYSIS RESULTS	  2S7
         6.3.1   Results for Standard Economic Assumptions.  ....     297
         6.3.2   Sensitivity Analyses 	  304
    6.4  DETAILS OF COST ANALYSIS METHODOLOGY 	  314
         6.4.1   Cost Algorithms.	314
         6.4.2   Example Calculation of a Fixed Charge Factor ....  316
         6.4.3   Cost Levelizing Calculations ,	318

7.  DATA LIMITATIONS AND RESEARCH NEEDS	321
    7.1  DATA LIMITATIONS	  321

    7.2  RESEARCH NEEDS	  .  322

8.  REFERENCES	335

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                                   FIGURES
Number
2.1-1   Location of Tract C-a in Piceance Creek Basin	27
2.1-2   Plant Complex	29
2.1-3   Plot plan for processing facilities	30
2.1-4   30-year open pit design	31
2.1-5   30-year pit cross section	32
2.1-6   Lurgi-Ruhrgas oil shale retorting process	34
2.2-1   Process flow diagram	38
3.2-1   Process operations and waste streams 	   46
3,3-1   Overall plant complex	48
3.3-2   Mining and crushing	50
3.3-3   Lurgi-Ruhrgas retorting	52
3.3-4   Oil recovery	54
3.3-5   Naphtha recovery .....  	   55
3.3-6   Retort gas compression and cooling	57
3.3-7   Diethanolamine/triethylene glycol treatment	58
3.3-8   Stretford sulfur recovery	59
3.3-9   Ammonia recovery 	   61
3.3-10  Solid waste disposal 	  .  	   63
3.3-11  Water management 	  .......   64
3.3-12  Overall water management scheme. 	  .  .   65
5.1-1   Participate control technologies	   125
5,1-2   Cost of participate control with baghouses	   136
5.1-3   Cost of participate control with
          electrostatic precipitators	137
5.1-4   Sulfur dioxide control technologies	   141
5.1-5   Hydrogen sulfide control  technologies	147
5.1-6   Cost of sulfur recovery with Stretford process  	  ....   157
5.1-7   Nitrogen oxides control  technologies 	  .  	   160

                                    viii

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                               FIGURES   (cont. )
                                                                          Page
5.1-8   Hydrocarbon control technologies  ................   166
5,1-9   Carbon monoxide control technologies  ..............   171
5.2-1   Suspended matter, oil and grease  control
          technologies ........................  „   176
5,2-2   Cost of mine water clarification  ..........  .  .....   181
5.2-3   Cost of oil/water separation ... .......  .  .......   183
5.2-A   Cost of equalization pond. . .  .................   186
5.2-5   Cost of excess mine water clarification .....  ,  .  ......   188
5.2-5   Dissolved gases and volatiles control technologies  .......   189
5.2-7   Cost of arasionia recovery with Phosam-W process  .........   196
5,2-8   Dissolved inorganics control technologies ............   197
5.2-3   Cost of boiler feedwater treatment
          with reverse osmosis .............  ...  .....   203
5.2-10  Cost of cooling water treatment .........  .  .....  .  .   205
5.2-11  Flow scheme for RO, boron adsorption and
          phenol adsorption treatments  .................   207
5.2-12  Reverse osmosis process flow scheme ...............   208
5,2-13  Boron and phenol  adsorption process flow scheme .........   209
5.2-14  Ccst of organics removal with reverse osmosis ..........   214
5.2-15  Cost of boron removal  with ion exchange system  .  .  .......   215
5.2-1S  Cost of phencl removal with ion exchange system .........   216
5.2-17  Flow scheme for cooling tower makeup and
          solar evaporation treatments ...............  .  .   217
        Cost of solar pond	220
5.2-1S  Dissolved organics control technologies	221
5.2-20  Cose of aeration pond	  .  229
5.2-21  Upper aquifer dewatering rate increase with
          reinjection distance 	  231
5.2-22  Lower aquifer dewatering rate increase with
          reinjection distance 	  .  	  .........  232
5.2-23  Reinjection pressure as a function of distance .  . 	 .  .  233
5.2-2*  Cost of excess nine water reinj-ection	  235
5.2-25  Carbon adsorption process flow scheme.  ...,.	  236
5,2-25  Cost, of .organics control with carbon- adsorption.  , «.„_...,  233

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                              .FIGURES  (cont»)
Number                                                                   Page
5.3-1   Surface hydrology control technologies 	   250
5.3-2   Typical runoff collection systems	253
5.3-3   Runcff collection and channeling ................   254
5.3-4   Runoff collection costs	255
5.3-5   Runoff/I eachate pond costs	257
5.3-6   Runoff/Ieachate pond liner costs 	   258
5.3-7   Subsurface hydrology control technologies	259
5.3-8   Liner costs	262
5.3-9   Leachate collection costs	   264
5.3-10  Groundwater collection costs 	   266
5.3-11  Surface Stabilization Technologies 	   267
5,3-12  Dust control costs	270
5.3-13  Reclamation and revegetation costs 	   271
5.3-14  Hazardous waste control technologies 	   273
6,0-1   Interrelationships among various cost
          and economic terms	,	   276
6.3-1   Sensitivity analyses:   total per-barrel air              ,  _
          and water pollution control costs	   309

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                                   TABLES
Numssr
1.5-1    Performance  Levels Estimated for Major
           Pollution  Controls.	  .   7
1.5-2    Components of Fixed Capital Cost Estimates	8
1.5-3    Components of Direct Annual Operating Cost Estimates	9
1.5-4    Summary of Major Standard Economic Assumptions
           Used in Control Cost Evaluations	   10
1.6-1    Major Features of the Oil Shale PCTHs .............   II
1.8-2    Pollution Control Technologies Examined
           in the Oil Shale PCTMs	   13
1.7-1    Composite List of Streams	  .   17
2.1-1    Major Parameters Defining the Size of the
           Commercial Plant Complex	   25
2.3-1    Summary of Pollution Control Technologies 	   41
2.3-2    Inventory of Major Pollution Control Technologies 	   42
2.3-3    Pollution Control Cost Summary.	44
4.1-1    Inventory of Gaseous Streams.  .	  .   68
4.1-2    Compositions of Gaseous Streams 	   73
4.1-3    Inventory of Liquid Streams 	   81
4.1-4    Compositions of Liquid Streams.  	   86
4.1-5    Inventory of Solid Streams	   89
4.1-6    Compositions of Solid Streams  	  .........   90
4,2-1    Gross Material  Balance for Retort and Shale  Burner	  92
4.2-2    Composition of Raw Shale	93
4.2-3    Laboratory Column Leachates from Some
           Colorado Raw Oil  Shales 	  94
4.2-4    Leachate Water Quality Data from the
           Tract.C-a Run-«f-Mine Stockpile ,  ,	  95
4.2-5    Composition of the Processed Moisturized Shale.  V	96
4.2-6    Inorganic Analysis of the Processed Shale .  .,,..,.,..  97
                                     x1

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                               TABLES  (cont.)
Number
4.2-7    Physical Properties of Processed Shale	 ........  98
4.2-8    Analysis of Leachate from the Processed Shale , . 	 .  .  99
4.2-9    Composition of Retort Vapors. ,	100
4.2-10   Properties of Naphtha-Free Shale Oil	'.  .  101
4.2-11   Composition of Retort Gas After Middle Oils Scrubber	103
4.2-12   Composition of Retort Gas After Light Oils Scrubber ......  104
4.2-13   Composition of Naphtha-Free Retort Gas	  105
4.2-14   Composition of Naphtha.	106
4.2-15   Composition of Retort Gas After Compression 	  107
4.2-16   Composition of Retort Gas After Amine Absorber	  108
4.2-17   Composition of Dried Fuel Gas	109
4.2-18   Material Balance Around Stretford Unit	110
4.2-19   Composition of Flue Gas from the Lift Pipes	Ill
4.2-20   Composition of Total Feed to Ammonia
           Recovery Unit	  ,  113
4.2-21   Haterial Balance Around Ammonia Recovery Unit 	  114
4.2-22   Groundwater Quality of Lease Tract C-a.  	  .  115
4.2-23   Composition of Excess Mine Water Before
           and After Aeration.  .	117
4.3-1    Pollutant Crass-Reference for Gaseous Streams 	  118
4.3-2    Pollutant Cross-Reference for Liquid Streams. ....  	  120
4.3-3    Pollutant Cross-Reference for Solid Streams 	  122
5.1-1    Key Features of Particulate Control Technologies.  .......  126
5.1-2    Particulate Control Equipment and
           Design Parameters 	  ...  131
5.1-3    Baghouse Specifications	  132
5.1-4    Major Items in Electrostatic Precipitator 	  .  	  133
5.1-5    Cost of Particulate Pollution Control 	  134
5.1-6    Design and Cost of the Fiberglass Fabric Baghouse .......  138
5.1-7    Total Particulate Emissions from the Plant	139
5.1-8    Key Features of Sulfur Dioxide Control Technologies 	  142
5.1-9    Key Features of Hydrogen Sulfide
           Control Technologies. .  	  148

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                               TABLES  (cpnt. )
                                                                          Page
5.1-10   Major Items in the Holmes-Stretford Process  ..........   155
5,1-11   Total S02 Emissions from the Plant ....... .  .......   158
5,1-12   Key Features of Nitrogen Oxides
           Control Technologies. , ...................   161
5.1-13   local NOx Emissions from the Plant ..............  .   154
5.1-14   Key Features of Hydrocarbon Control Technologies ........   167
5.1-15   Hydrocarbon Control Practices and Equipment  ...... ....   168
5.1-16   Cost of Hydrocarbon Pollution Control ........  .....   169
5.1-17   Total Hydrocarbon Emissions from the Plant ...........   170
5.1-18   Key Features of Carbon Monoxide Control
           Technologies. ...  .......... .   ..........   172
5.1-19   Total CO Emissions from the Plant ...............   173
5.2-1    Key Features of Control Technologies for
           Suspended Matter, Oils and Greases ..............   177
5.2-2    Design and Cost of Mine Water Clarification  ..........   180-
5.2-3    Design and Cost of API Oil/Water Separator
           for Gas Liquor.  ...........  ............   182
5,2™4    Design and Cost of Oil/Water 'Separator for
           Runoffs and Leachat'e ........  .  .........  ...   184
5.2-5    Design and Cost of Equalization Pond.  ........ .....   185
5.2-6    Design and Cost of Excess Mine Water Clarification. ......   187
5.2-7    Key Features of Control Technologies for
           Dissolved Gases and Volatiles .......... . .....   190
5.2-3    Design of Ammonia Recovery System ...............   193
5.2-9    Cost of Ammonia Recovery ..................  .  .  195
5.2-13   Key Features of Control Technologies for
           Dissolved Inorganics .....................  198
5.2-11   Design and Cost of Boiler Feedwater Treatment .........  202
5.2-12   Design and Cost of Cooling Water Treatment ...........  204
5.2-13   Excess Mine Water Composition After RO,  Boron
           Adsorption and Phenol Adsorption Treatments ...........  210
5.2-14   Design and Cost of Reverse Osawsis Treatment
           of "Excess Mi-ne -Water ..... _*.-,...,..-.......  £11
5.2-15   Design and Cost of Boron Adsorption System.  . .....  . .  .  ,  .  212
5,2-16   Design and CosVtff WienoT.ftdsOT^iiWi, System  .-...• .......  213
                                    xi n

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                                TABLES   (cont.)
 Number                                                                   Page
 5.2-17    Haterial  Balance  Around Cooling Tower  .  .  	 .  218
 5.2-18    Design  and  Cost of  Cooling Tower Makeup  Treatment 	  219
 5.2-19    Design  and  Cost of  Solar Evaporation Pond  .	219
 5.2-20    Key  Features of Control Technologies for
            Dissolved Organics	  222
 5.2-21    Design  and  Cost of  Aeration Pond	  228
 5.2-22    Design  and  Cost of  Reinjection System  	  234
 5.2-23    Material  Balance  Around Carbon Adsorption  Unit. 	 ...  237
 5.2-24    Design  and  Cost of  Activated Carbon
            Adsorption for  Process Waters 	  238
 5.2-25    Steam Production, Uses and Boiler Feedwater Needs 	  240
 5.2-26    Water Quality Parameters for Boiler Feedwater 	  240
 5.2-27    Plant Cooling Water Requirements	241
 5.2-28    Water Quality Parameters for Cooling
            Tower Recirculation	242
 5.2-29   Water Requirements  for Processed Shale
            Disposal  and Dust Control		243
 5.2-30    Potable and Service Water Requirements.  .  , . . .  	  . .  244
 5.3-1     Major Wastes Produced Over a Period
            of 20 Years	  245
 5.3-2     Key Features of Solid Waste Disposal Approaches ...  	  247
 5.3-3     Key Features of Surface Hydrology
            Control Technologies	251
 5.3-4     Key Features of Subsurface Hydrology
            Control Technologies	260
 5.3-5     Key Features of Surface Stabilization Technologies	".  268
 5.3-6    Key Features of Hazardous Waste
            Control Technologies	,  .	274
 6.1-1    Detailed Engineering Costs for Air Pollution Controls  	  281
6.1-2    Detailed Engineering Costs for Water
            Pollution Controls.   .	283
6.1-3    Engineering Costs and Timing of Solid Waste
           Management Activities ...........  	  284
6.2-1    Summary of Standard Cost and Economic Assumptions  .......  287
6,2-2    Economic Assumptions that Vary from
           Control to Control.  .	   288

                                     xiv

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                               TABLES  (cont.)
Number
6.2-3    Fixed Capital and Direct Annual Operating Costs
           for Solid Waste Management	295
5.2-4    Par-Barrel Cost Breakdown for Electrostatic
           Precipitators ...........  	  .  296
6.3-1    Pollution Control Costs, by Control Group,
           for the Standard Economic Assumptions 	  299
6.3-2    Control Groupings	• .  .	300
6.3-3    Details of Air Pollution Control Costs,
           Standard Economic Assumptions 	  301
6.3-4    Details of Water Pollution Control Costs,
           Standard Economic Assumptions 	  302
6.3-5    Details of Solid Waste Management Costs,
           Standard Economic Assumptions .  , 	  303
6.3-6    Assumptions for Sensitivity Analyses	305
5.3-7    Charge Rates for Sensitivity Analyses  	  306
6.3-8    Sensitivity Analyses Expressed as a
           Percentage of Shale Oil  Value .....  	  307
6.3-9    Sensitivity Analyses by Medium.	  308
8.4-1    Example of Fixed Charge Factor Calculation	317
7.1-1    Data Limitations and Research Needs .	324
                                     xv

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                      ABBREVIATIONS
o
 API      — gravity (American Petroleum Institute)
ACF       — actual cubic feet
ACFM      — actual cubic feet per minute
ACRS      — accelerated cost recovery system
ADA       — anthraquinone disulfonic acid
ADR       — asset depreciation range
AMB       — ambient
BHP       — brake horsepower
BOD       — biochemical oxygen demand
BP        -- annual by-product credit
BPSD      — barrels per stream day
CA        — carbon adsorption
CC        — total annual capital charge
COD       — chemical oxygen demand
CPB       — per-barrel control cost
CS/SS     — carbon steel/stain!ess steel
DCF       — discounted cash flow
DCF ROR   — discounted cash flow rate of return
OOP       — Detailed Development Plan
DEA       — diethanolamine
DGA       — diglycolamine
DIPA      — diisopropanolamine
DOC       — direct annual operating cost
DRI       -- Denver Research Institute
ED        — electrodialysis
ESC       — annual extra start-up costs
ESP       — electrostatic precipitator
FCC       — fixed capital cost

                           xvi

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                  ABBREVIATIONS  (cont.)
 FGD        —  flue gas desulfurization"  ""
 FGR        --  flue gas recirculation
 fpl        —  feet per minute
                     -««r"
 god/ft2    —  gallons per day per square foot
 gpsB        --  gallons per minute
 gpt        —  gallons per ton
 HP         —  horsepower
 IBP        —'  initial boiling-point
 IOC        ~  indirect annual  operating cost
 ITC        --  investment tax credrt  ' s-""1*-^
 LHV        —  low  heating va-l-ue           ^  -
                                        ^       ""
 LTPSD      —  long tons per stream day, *,"
 MDEA       —  methyl dTethanol ami ne   ,,
 MEA        —  monoetnanolamine
 HEB        --  multip"le,leffectjboiling
 meq        —  mil11 equivalent
 MIS        --  Modified- In Situ
 MMBtu      —  Billion British  thermal units
 ,MSF        --  multistage flash "  .
 MTPSD      —  metric  tons per^tream day
 MW         -1-  megawatts         ..       ^-^"~-"
 MWt        --  molecular  weight
 pcf        —  pounds  per cubic"foot
 PCTM       ~  PcllutiQfi Control Technical  Manual
 POM        —  polynuclear 6'rganic  matter
 ppmv       —  parts per  million, by  volume
 ppmw       --  parts per  million, by  Weight
 PSD        —  Prevention of  Significant  Deterioration
psia       —  pouMs  p«r square inch, absolute
psig       --  pourids  per square inch, §aitge>
 RBQSC      —  Rfo'-Blanco Oil Shale Company       ."..„  ,
RF         --  fixed capital  charge rate  4  -
                               <*   ,   ^ -_ ^ ~ i
 RHC- • • "" *-.  reactivfi,hydrocarbons    K"  „- ,
                     •^             *
                          Xvii

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                 ABBREVIATIONS   (cant.)

 RO        —  reverse  osmosis
 RSH       —  alkyl  thiols, mercaptans
 RW        —  working  capital charge  rate
 SCF       —  standard cubic foot
 SCFM      —  standard cubic feet per minute
 SCOT      ~  Shell  Glaus Off-gas Treating
 SCR       —  selective catalytic reduction
 SEA       --  standard economic assumptions
 SNPA/DEA  —  Societe  Nationale des Petroles d'Aquitaine/
               diethanolaraine
 SS        —  stainless steel
 STC       —  annual severance tax credit
 SWEC      —  Stone  and Webster Engineering Corporation
 TC        —  total  annual control cost
 TDS       --  total  dissolved solids
 TEG       --  triethylene glycol
 TIA       —  annual property tax and insurance allowance
 TOC       —  total  annual operating cost
 TPM       —  total  participate matter
 TPSD      --  tons per stream day
TSS       —  total  suspended solids
 UF        —  ultrafiltration
 USBM      —  U.S. Bureau of Mines
VCE       —  vapor  compression evaporation
VOC       —  volatile organic compounds
WAG       —  wet air  oxidation
WC        —  working  capital
WPA       — Water  Purification  Associates
                          xvm

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                             CONVERSION  FACTORS
1 poyrd, 1b


1 ton

1 inch, in

I foot, ft


1 mile, mi


1 square inch, in2

I square foot, ft-2

1 square mile, ml2


1 acre


I cubic inch, in3

1 cubic foot, ft3

1 gal TOT,  gal


1 barrel,  bbl


1 acre-foot

I pound/square inch, psi



1 pound/cubic inch, Ifo/lti3
 =  453.5924 grams,  g
    0.4538  kilograms,  kg

 =  0.9072  nietic  tons,  tonnes

 =  2.5400  centimeters,  cm

 =  30.4800 centimeters,  cm
    0.3048  meters, m

 =  1,609.3440 meters,  m
    1.6093  kilometers,  km

 =  6.4516  square centimeters,  cm2

 =  0.0929  square meters,  m2

 =  2.5900  square kilometers, km2
    258.9988  hectares,  ha

 =  4,046.8564 square meters, m2
    G.4047  hectares,  ha

 =  16.3871 cubic centimeters,  cm3

 =  28.3161 liters,  1

 =  3.7853  liters, 1
    0.0038  cubic meters,  m3

 =  158.9828  liters, 1
    0.1590 cubic meters,  m3

 =  1,233.4818 cubic meters, ra3

-   70.3070 grams/square  centimeter, g/cm2
    0.0680 atmospheres, ,atra
    0.3591 millimeters of mercury, mm of Hg

=  27.6799 -grams/cubic centimeter, g/ca3
    27.6807 grams/»il111iter,
                                     XIX

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                         CONVERSION FACTORS  (cont.;
1 pound/cubic foot, pcf, lb/ft3  =


1 gallon per ton, gpt            =

1 barrel par day, BPD            =

1 gallon per minute, gpm         =

1 British thermal unit, Bta      =
   0.0160 grams/cubic centimeter, g/cm3
   16.0185 kilograms/cubic meier, kg/ra3

   4.1726 liter/tonne,, I/tonne

   0.1590 cubic 
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                               ACKNOWLEDGMENTS
     This Pollution  Control  Technical  Manual was prepared for the EPA by the
Denver  Research  Institute  (DRI),  University of  Denver, Denver,  Colorado,
uncle*1  EPA  Cooperative   Agreement  CR-807294.    Subcontractor  support  was
provided  to  DRI  by  Stone and Webster  Engineering Corporation  (SWEC)  of
Denver,  Colorado,  and Water  Purification  Associates  (WPA) of  Cambridge,
Massachusetts.    The project manager for DRI  was Mr. Kishor  Gala,  Chemical
and Materials Sciences Division.
                                     xxi

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                                  SECTION 1

                                INTRODUCTION
1.1  PURPOSE

     Future  U.S.  energy production envisions the  development of an environ-
mentally  acceptable,  commercial synthetic  fuels industry.   As  part of this
overall effort, the Environmental Protection Agency (EPA), Office of Research
and Development,  has  for the past several years undertaken extensive studies
to determine synthetic fuel plant waste stream characteristics and potential-
ly applicable pollution control systems.

     The  purpose  of the  Pollution Control Technical  Manuals (PCTMs)  is  to
convey,  in  a summarized  and readily  useful  manner,  information  on synfuel
waste  stream characteristics  and pollution  control  technology  as  obtained
from  studies by  the  EPA and  others.   The  documents provide  waste  stream
characterization  data  and describe  a wide variety of  pollution controls  in
teriss of  estimated  performance, cost and reliability.  The  PCTMs contain  no
'egaTiy binding requirements,  no  regulatory guidance, and include no prefer-
ence for  process  technologies  or  controls. , NotMng within these documents
relieves  a   facility  from compliance with  existing or future environmental
regulations or permits.

     The  Pollution  Control Technical  Manuals  consist of a set of seven dis-
crete documents.   There are  six  process specific  PCTMs  and  a  more general
appendix  volume which describes over fifty pollution  control technologies.
Application  of  pollution  controls to  a particular  synfuel  process  is  de-
scribed in each process specific manual.  The seven manuals are:

     *    Pollution Control  Technical Manual for  Lurgi Based Indirect, Coal
          Liquefaction and SNG

     •    Pollution  Control   technical  Manual   for   Koppers-Totzek   Based
          Indirect Coal Liquefaction

     *    Pollution Control  Technical Manual for Exxon Donor-Solvent  Direct
          Coal Liquefaction

     »    Pollution Control  TeefinicaJ Manual for  Lurgi Gil  Snal«  Betorting
          with Open Pit Wining

     •    Pollution Control  fecnaieaj Manual  for Modified In  Situ Oil  Shale
          Retorting Combined  witft iMrgi Surface  fietortingr

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      *    Pollution Control Technical Manual  for TOSCO II Oil Shale Setorting
          with  Underground Mining

      *    Control  Technology  Appendices   for  Pollution  Control  Technical
          Manuals

      By  focusing on specific process technologies, the PCTMs attempt to be as
definitive  as possible  on  waste  stream  characteristics and control technology
applications.   This focus  does not  imply any  EPA recommendations for particu-
lar  process or control  designs.  Those described  in the manuals are intended
as  representative examples of processes and  control  technologies that might
be  used.   The  design of  the  PCTMs,  from  process  description through waste
stream  characterization and  control  technology  evaluation,  is  intended to
provide  the user  with  a  comprehensive  understanding of  the environmental
factors  inherent in operating synthetic fuel  plants.

      Control technology discussions presented in the PCTMs reflect pollutant
removal  levels  which  are  believed  to be achievable  with currently available
control  technologies  based upon existing data.  Since  there  are no domestic
commercial-scale synfuels  facilities,  the  data base supporting this document
was  derived from bench- and pilot-scale synfuel facilities, developer's esti-
mates, engineering analyses and  analogue industries.  As commercial synthetic
fuel  plants  are built,  the EPA  will continue conducting research in order to
develop  a more  comprehensive data  base.  Based on findings from these future
studies, the Agency may update these documents or promulgate industry specif-
ic  standards.    In the interim,  the  Agency encourages  facility  planners,
permit officials,  and other interested parties to take  advantage of the in-
formation contained in these documents,

1.2  APPROACH

     The approach  taken in developing  this manual is to describe, in detail,
an oil shale  facility which has been proposed  for development and to empha-
size  its pollution control aspects.  This facility is the basis for the case
study described in Section 2 "Summary  of Study Features," Section 3 "Process
Flow  Diagrams  and Flow  Rates,"  and Section  4  "Inventory  and Composition of
Plant  Process  and Waste  Streams."   The   process  descriptions  and  control
technologies presented  in  this case study are based on documents (identified
in Section  1.3) published  by the proposed  facility  developers and parallel,
as closely as possible, the current thinking  of the developers.

     This manual  examines  Lurgi-Ruhrgas aboveground retorting with  open pit
mining and  pit backfilling as  proposed by Rio Blanco Oil  Shale Company for
development of Federal Lease Tract C-a  in the Piceance Basin of Colorado.  It
should be noted, however,  that effective August 1, 1982, Rio Blanco Oil Shale
Company  and the U.S.  Department  of the Interior (DOI) agreed to a suspension
of operations and  production  for a period  of 5 years  or until DOI issues to
Rio Blanco Oil Shale Company a lease for land other than Tract C-a (U.S. DOI,
July 29,  1982).   The  company  is seeking this  additional  land  for  purposes
connected with  operations  on  Tract C-a, including the disposal of processing
wastes.

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      In  order to enhance the flexibility of  this  manual,  and since  oil  shale
development  plans  are  continually  changing,  Section 5  "Pollution  Control
Tscnnology"  expands  beyond  the  case   study description  to  examine  other
pollution  control  technologies  and approaches that  may be applicable to  the
waste sources identified in the case study.  While  controls  applied to  major
gaseous,,  Hquid,  and solid  streams  described in the case  study  are  tnose
which have  been proposed by the developer,  Section 5 also examines  alterna-
tive  pollution control  technologies  on a  stream-by-stream basis.   For each
stream receiving control, all major control technologies are  discussed,  while
some  example technologies  are  analyzed in  considerable depth.  Stream flow
"•atas ar>d pollutant characteristics are  used  in estimating  the  size,  perform-
ance,,  ana cost of the  controls,  and  secondary  streams  resulting  from  the
pollution control activities are identified.

      It  should be noted that the  case  study, as  described in Sections 2,  3
and 4 of this  manual, would begin approximately  30 years after the  initial
start of development  operations on Tract C-a.  Due  to the  space requirements
for  simultaneous  production and backfilling operations,  the first  30  years
are  spent  developing  the mine to a point when waste backfilling can  commence
ypthcut  interfering  with production.   Also,  water  management and  treatment
activities  would have  reached  a  steady-state condition  by  this  time.  By
examining the  mining,  backfilling,  and water management/treatment operations
urcer steady-state conditions,  a more useful analysis  can be made  for  these
operations.   This  does not  impair  the usefulness  of examining control  tech-
nologies  for the1 Lurgi  retorting  process  since it  would  be  operating  under
stable conditions from the outset.

1.3  DATA,SOURCES

      Trns manual  focuses on  the plans  that  have emerged  over the  past  few
years  for the development of Federal  Lease Tract 'C-a.   The operation of  the
tract  is monitored  under  the  Federal   Prototype  Oil Shale  Leasing Program
through the U.S. Department of Interior's Minerals Management Service.   Under
this  program,  a Detailed Development Plan (DDP), modifications to  the OOP,
and extensive  environmental  information must be submitted on a regular  basis
to,  t.ne  Mlrterals  Management Service  by the  leas«  operators.   The DDP  and
subsequent modifications  to  the OOP submitted by the developers of Tract  C-a
warfe  the (principal data  sources used to prepare the case  study described in
Sections 2, 3 and 4 of this manual.
     i
     The  first Commercial development  plan,  or OOP, for  Tract C-a  was  pub-
lished in 1976 (Gulf  Oil Corp.  and Standard  Oil  Co. [Indiana], March 1976).
This plan called for open pit mining of 119,000 tons per stream day (TPSD) of
raw  siale  to  produce  approximately  56,000 barrels per stream  day (SPSD)  of
hydro-treated shale oil.   According  to the  DDP,  the processing facilities  and
waste disposal  site were to be located $ff tract; however, the Department of
Interior,, based on acreage  restrictions in the Minerals Leasing Act, denied
the request fo** additional federal  land,  fts a result, the  developers submit-
ted  a revised DDP to' the Area  Oil  Shale: Office' (now part  of the  Minerals
Manag€i8&rit * Service) in 197?  (Gulf-Oil Corp. and Stawdard,  Oil Co.  [.Indiana.],
May ;S77).   Thi* -modified 'plan  was  based  on pwkicing 76,000  BPSD  of shale
oit  .by,  using  a  combinatiolt of the  Modified In Si-W (MIS) and  -TOSCO II

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retorting  technologies.   The MIS development was  planned!  to  take place in a
modular fashion, consisting  of buTTiing"seveYal small*' and" targe-si zed retorts
over  a  period of ten years.  In 1981* another modular program was incorpora-
ted into the  OOP to demonstrate the feasibility of open pit mining and Lurgi-
Ruhrgas  aboveground  retorting  (Rio  Blanco Oil   Shale  Co.,  February 1981).

      The  case study  described  in this  manual  is based  on  a combination of
open  pit  mining frora the original  1876 DOP and  Lurgi  surface retorting as
described  in  the 1981 modification to the DDP.  In addition, the 1977 revised
DDP provided  the basic site description and hydrologic data.  Although these
three documents  were  the major sources  used  in  deriving the process, pollu-
tion  control,  and  other information presented in  Sections 2, 3 and 4 of this
manual,  several  supplemental   sources   were  also used and  they are  cited
throughout the document.

     Where  available, actual data  from the various  scale operations in oil
shale  processing  were  used.   It  is  believed  that  these  data accurately
reflect the major  technical  features which will be  encountered in a commer-
cial  oil  shale industry.   In addition, technologies from analogue industries
are transferred, when appropriate.   When necessary, engineering analysis and
judgment provided  by  the authors of this manual  (Denver Research Institute,
Stone and  Webster  Engineering Corporation and Water Purification Associates)
and vendor  information  were  used.   In each case,  all assumptions required to
carry out the analyses are listed, and areas lacking hard data are identifies
(see Sections 1.5 and 7 for more detailed discussions).

1.4  STATE OF TECHNOLOGY DEVELOPMENT

     As stated above, the processing plant considered in this manual  is basad
on a  combination of information from the three  different ODPs submitted for
Tract C-a.  Approximately  119,000  TPSD  of raw shale will be mined using oppr
pit  mining.    In  addition,  62,100 TPSD  of  overburden  and  11,900  TPSD  of
subgrade shale  (subore)  will be removed.  The raw shale on Tract C-a has an
average oil yield  of  23 gallons per ton  (gpt)  based on the modified Fiscner
assay.  This  shale will be processed in 13 Lurgi-Ruhrgas aboveground retorts,
at  an  efficiency  equal  to 100%  of  Fischer assay,  to  eventually  produce
63,140 BPSD  of  crude  shale oil  (The  stream-day  rates  are  the  maximum,
24-hr/day  rates  that  can be achieved;  however,  occasional  equipment failure
and required  maintenance  result in a reduced production efficiency.   Normal-
ly, the plant can  be  expected to  operate at 90%  of  its capacity on  a long-
term  basis,   or  for  328.5 calendar days per  year.   Thus,  the calendar-da>
production rates would  be 90% of the stream-day  rates.)   The current status
of the mining and retorting technologies is reviewed below.

1.4.1  Open Pit Hlninp

     The  open pit mine  considered in  this manual would  be the  largest  of
its type  in the  world.   This mining method is used in other industries, such
as copper  ore mining, but the  scale used is considerably  smaller than that
required in this,study.   Some preliminary design  work for a commercial-scale
open  pit  on  Tract C-a was published  in the original  DDP, while  the second,
or  revised,  DDP  did not  consider  the method  at  all.   An  experimental

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 (small-size)  open pit was subsequently  described in the modification  to the
 DDP,  but this plan, which also  included a  full-scale Lurgi  retort demonstra-
 tion  program, was suspended  in late  1981 due  to  rising cost  estimates for the
 demonstration  program.   Thus, only_a_J_1m1ted_junpjjntofd^^
 neeri'ng  data  for  an_ open pit mine orTTractC-a is avaTTalTe~]

      A*though  open  pit mining  is   commonly  used  in  other  industries,  the
 design  for any  pit should  be  evaluated on  an   individual  basis, since  its
 design  and potential  environmental  impacts  would  be  site dependent.   For
 example, ojiJ^rjcJijCj^jyiiejj^^               the upper and  lower aquif_ers_of
 •che_ Pi ceance_ Creek Bas1 n_and, consequen"tTyTjTTeT~TTiiemliyiriaTo^v of the area.
 DewateHng~the^"sfrala""Tn  the  vicinity  of  the pit would reduce  the  problems
 associated with its  development, but several  legal,  engineering,  and  environ-
 mental  issues may be  raised  and  would need  to  be  resolved.   The  e^gess
 fljjijiilJjjiuSt^^                              ' dischafged,	or• Ji sposed| of 1" some
 manner.   , The  processing and ai sposaT^fSihrrTeteT^'iT l'f'o'ca^leiTuoir'T€h'e"ml""acC7*
 wauld  take up a_ significant portion of the  available  land  and this  would
 severely hamper the development  of  the  pit.  Backfilling of the  pit  with the
wastes  could ease  the  space problem to some extent, but  the logistics  of
 having  simultaneous mining  and  backfilling operations  require an extensive
 effort.   It was  estimated  in the original  DDP that  approximately  30  years of
 commercial-scale  pit development would  be  necessary  before the  backfilling
 could .ae' initiated.

 1.4.2  Lurgi"RuhrgasTechnology             , ,  ,

     Small Lurgi-Riihrgas pilot plants have  been  operated by Lurgi Kohle  und
Mineralotechttik GmbH in  West Germany.  -The  necessity  to  ship  ore  to West
GenriEny  has limited the amount of available test data.   To'date,  the experi-
 ence "elevant to  this manual  is limited  to  three tests:   one in 1976  on shale
 from  the Colony mine in Colorado, and two  in 1980  on shales from  Tracts  C-a
 and Ob.  The earlier (1976) test was run  in a 5-ton/day pilot plant,  while
the 1980 tests were performed in a 25-ton/day plant.  Data from the 1980 test
 on Tract C-a shale, published in the modified OOP for the Lurgi demonstration
modu's,  were  used In this  manual (Rio Blanco  Oil Shale  Co., February  1981).
Tests have been run on  other shales and reported in the  literature (Marnell,
Septae'iber 1976; Schmalfeld,  July 1975),  but  substantially different results
were obtained.

     The Lurgi-Ruhrgas  demonstration plant  processing 4,400 TPSD of  shale  on
Tract C-a (as  proposed  in the modified  OOP)  was to  be  operational by  early
1983, but these plans were suspended indefinitely during the  summer of 1981
 in  favor of  building  and  operating  a  5-ton/day  pilot  plant at  Gulf  Oil's
research facility in Pennsylvania,

1.5  ASSUMPTIONS                        , •

     In performing a detailed analysis of the Lurgi-Ruhrfas retorting process
used with open pit mining, a number  of  specific  assumptions which influence
the results of the analysis  and their interpretation  were  made.  The under-
 lying, majof as sumptions VelatiRf- to .pollution -control performance and  cost,
as will'  as the ts^ses• b«Mtrd the  assumptions,  are susmarizeij in this  section.

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1.5.1   pojlutipn  Control and  Performance Estimates     .  .

     In the process  of preparing this  manual,  applicable pollution control
technologies for  different waste  streams were reviewed, and controls proposed
by  industry were  evaluated  to the point that performance  and cost could be
estimated.   Equipment vendors' estimates  and guarantees vere used whenever
available.   Other performance levels were estimated using laboratory testing
data.   These performance estimates should be viewed tentatively because very
little  data  based  on  actual  source  testing  exist.   The  major pollution
controls  evaluated in  this  manual are presented  in  Table 1.5-1,  along with
the performance levels  estimated  as a result of  the analysis.

     The  major air  pollution control technologies  evaluated (electrostatic
precipitator,  Stretford) are commercially available  and  are used  in other
industries  at  a  scale similar to that  involved  in  this  manual;  therefore,
operational  difficulties in  adapting  these technologies  to oil  shale proc-
essing  are  not expected to be great and may primarily involve adapting these
technologies to oil shale off-gas  characteristics.

     In  the area  of water pollution  control,   it  has  been  proposed  by  the
developer that the plant will achieve zero-discharge of the process generated
waters, but that  excess mine water will  need to be discharged.  The process
waters  are  treated  to  the   degree  necessary for  reuse.    The  technologies
considered  (ammonia  recovery, aeration  pond)  have  been  used in  analogue
industries  and  can be expected to be  employed  successfully in the oil shale
industry.    Waters  used in  auxiliary plant operations  are  also treated since
the  wastes  produced  from these  operations may  be  used  in  processed shale
moistening  and  thus  may become a  source  of pollution.   Reuse of some waters
may negate  a need for pollution control; in such cases, no pollution controls
in a conventional sense are applied.

     Solid  wastes are managed by  backfilling the open pit.   This approach was
mentioned   in  the original   DDP   for  Tract C-a  and  was  to  commence  after
30 years of pit development and off-site disposal of the wastes, but detailed
plans were  not presented.  The pollution control technologies that are judged
appropriate  for open  pit backfilling include surface hydrology technologies,
such as a  runoff  collection  system and pumps during  the  project  life, sub-
surface  hydrology technologies  primarily  involving  the  monitoring  of  the
groundwater,  and  surface  stabilization technologies  for  dust suppression,
revegetation,  etc.   These  technologies are  traditional  practices  associated
with solid waste management in other industries.

1-5.2  Componentsof Pollution Control Cost Estimates

     Fixed  capital and direct annual operating costs were estimated for each
piece  of  pollution   control  equipment  and  each  control   activity.   These
figures were then  used, along with economic  assumptions,  to calculate total
annual  control costs  which  include an annual charge  for  capital.   The total
annual  capital charge  provides for a required after-tax return on investment
of 12 percent.   The approach  used  to estimate the capital  and operating costs
and the economic  analysis  techniques applied to these data are summarized in
Tables 1.5-2 throuah 1.5-4.

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                   TABLE  1.5-1.   PERFORMANCE  LEVELS  ESTIMATED FOR MAJOR POLLUTION CONTROLS
Control Description
                                         Pollutant  Control!ed
                                                                                 Control  Level  Estimated
AH PC.lilTION CONTROL
Baghouses
Water Sprays
Foam Sprays
Electrostatic P^ecipHator
Holnes-Stretfo-d Gas Treating
  Process
Raw and Processed Shale Oust
Raw and Processed Shale Dust
Raw and Processed Shale Dust
Processed Shale Oust
H2S
99 T
50*"
99
30 ppnw
WftT ES __POJLLUTIQN^ CONTPQL.
Ammonia Recovery Unit
Aerat'on Pond
NH3
Organic Matter
CQO
99%e
25% reduction6
2S%f
SOuID WASTE,jjANAGEMENT
K'ne Backfill
Processed Shale, Sludges,
  Slowdowns, Concentrates, etc.
                                                                                N/A
  Bender estimates assuming 1Q grains/ACF inlet loading.
" SWEC estimates.  Efficiency is based on the quantity of airborne material.  The efficiency may  be  higher
  -n tarn-s of the material contacted by the spriys.
c Rio Bleico Oil Shale Co , February 1981
  Eased OP Peabody Process Systems, Inc , February 1981.
e Estimates from treatability studies on similar waters conducted by VJater Purification Associates,
      estTHates.

-------
      Fixed  capital  and direct annual operating cost estimates were developed
on  a component  basis,  using current dost  data  from the 'actual installation
and  operation-of simi-lar facilities and using vendor quotes for major equip-
ment  items.   Capital cost estimates are expected to have an average accuracy
of  ±30 percent.   This  level  of  accuracy can  only be  verified  fay  actual
equipment  installation.   Experience in using  the  cost estimating procedures
for  units  which  actually have been  constructed and operated  indicate that
this  level  of accuracy should be achievable if the unit installed is exactly
as  described  in determining  the  cost estimate.   Arty design  changes  could
cause the actual  installed capital cost to  fall outside the range.
     Table 1.5-2  lists  the  components estimated in determining the installed
fixed capital cost of pollution control equipment.   For simple equipment, all
components may  not be present.  For large  and complex equipment, estimating
the cost of each  component may be a major effort.  A description of the major
equipment included  in each  capital cost estimate is provided in Section 5 of
this document.
          TABLE 1.5-2.  COMPONENTS OF FIXED CAPITAL COST ESTIMATES

                                 Components
               Hajor Equipment (vendor quotes)
               Site Preparation, Excavation and Foundations
               Concrete and Rebar
               Support Structures
               Piping, Ductwork, Joints, Valves, Dampers, etc.
               Duct and Pipe Insulation
               Pumps and Blowers
               Electrical
               Instrumentation and Controls
               Monitoring Equipment
               Erection and Commissioning
               Painting
               Buildings
               Engineering and Other Indirect Costs
               Contractor's Fee
               Contingency Allowances

Source:   ORI.

-------
     -Table 1.5-3  shows  the  components  comprising  direct  annual  operating
costs.  Operating  supplies  include such items as baghouse bags.  Maintenance
includes  the cost  of parts  used, but  the  needed  inventory  of replacement
parts  is  included  in fixed capital cost.  The  cost of water consumed is not
included  due to  uncertainties  in estimating  the  value  of water.   Direct
annual operating costs do not include by-product credits; however, by-product
credits are  included  in  total  annual operating costs.   The operating costs
(direct,  indirect  and total)  for each  pollution  control,   along  with a de-
ta-'Tea  discussion  of how  the  costs  were  determined,  are presented  on  a
component basis in Section 6.
     TABLE 1.5-3.  COMPONENTS OF DIRECT ANNUAL OPERATING COST ESTIMATES



                                 Components

               Maintenance and Maintenance Supplies

               Operating Supplies

               Operating Labor

               Cooling Water

               Steam

               Electricity

               Fuel

               Indirect Costs (e.g., supervision,  laboratory, etc.)*


* Indirect costs are included in the labor rate.

Source:  DRI.
     Table 1.5-4 presents  the major  economic assumptions  used  in the  cost
evaluations.   Most  economic  assumptions have  been standardized so that the
results found in all  of the  oil  shale  PCTMs  may  be compared.  A sensitivity
analysis was performed (see Section 6  "Po-lluti-on Control  Costs")  to determine
the effects of  changes  in  some of the  standard economic assumptions.   These
changes  include delayed  start-up,  changing  capital and  operating  costs,
financing  considerations  and  others.  All  of the  oil  shale  PCTMs  use  a
discounted cash  flow approach (DCF) and constant dollars  (mid-1980).

-------
        TABLE  1.5-4.   SUMMARY OF MAJOR STANDARD ECONOMIC ASSUMPTIONS
                       USED  IN CONTROL' COST EVALUATIONS
                                 Assumptions3

•    Approach:  Discounted Cash Flow Evaluation (DCF)

•    Method:  Revenue-Requirement determined from capital charge plus
       operating cost

*    Required DCF ROR:  12% (100% equity basis)

*    Cost Base:  Mid-1980 constant dollars

•    Income Tax:  In accordance with current regulations (48% combined tax
       rate, 20% investment tax credit); tax credits and allowances can be
       passed through to a parent company that can benefit from them
       immediately, without waiting for the project to become profitable

•    Project Timing:  4 years construction, 20 years life

•    Normal Plant Output:  63,140 barrels per stream day (net, after in-
       plant use)

«    Operating Factors:   Year 1     -  50%
                         Year 2     -  75%
                         Years 3-20 -  90%


a A more detailed list of assumptions is presented in Section 6, Table 6.2-1,

  This method permits accurate costs to be determined separately for each
  control using the OCF approach,  without the need for an estimate of total
  plant cost,

Source:  DRI.
1.6  UNIQUE FEATURES

     Three  oil  shale  retorting processes  were  selected  for the  oil  shale
PCTMs  to  allow  consideration  of  different types  of  retorting  processes,
mining  and disposal  techniques,  and  pollution  control technologies.   Some
features  are  found in  more than  one  manual, but each  process  examined has
important unique features which are listed in Table 1.6-1.

     Table 1.6-2  lists  the  pollution control  technologies examined  in the
three PCTMs,  The table is designed to assist the reader in locating detailed
information on any specific control technology.


                                     10

-------
             TABLE 1.6-1.  MAJOR  FEATURES  OF  THE  OIL SHALE PCTKs
                                                     PCTMs
caature
TOSCO II
MIS-Lurgi     Lurgl-Open Pit
JOONG

Jncierground
  Room-and-Pillar

Underground MIS

Open Pit


RETORTING

AbOi/sground

Underground

Direct-heated

Indi rect-heated

Solid-to-Solid
  Heat Transfer

Gas-to-Solid
  Heat Transfer

Resource Recovery
  from Processed Shale

High Carbon Processed Shale

Low Carbon Processed Shale

Raw Shale Preheating


PROCESSING

High Stu Cff-gas

Low 3 tii Off-gas

Oil Fractionatton
                  X

                  X

                  X

                  X
                  X

                  X

                  X
                                                         ^-Continued)
                                    '•II

-------
                            TABLE 1.6-1  (cont.)
                                                    PCTMs
Feature                           TOSCO II      MIS-Lurgi     Lurgi-Open Pit
PROCESSING (cont.)
Oil Upgrading                        X
Gas Upgrading (for sale)             X                              X
In-PIant Fuel Use                    X              X
Excess Electricity                                  X

POLLUTION CONTROL
Retort Gas Cleanup                   XXX
Process Water Cleanup                XXX
Excess Water Discharge                                              X
By-product Recovery                  XXX

WASTE DISPOSAL
Surface Landfill                     X              X
Permitted Design                     X
Open Pit Backfill                                                   X
Groundwater Contamination
  Potential (subsurface
  disposal or retort abandonment)                   X               X
Surface Water Contamination
  Potential (valley fill)            X              X

Source:  DRI,
                                     12

-------
TABLE 1.6-2.  POLLUTION CONTROL TECHNOLOGIES EXAMINED
               IN THE OIL SHALE PCTMs

PCTMs
Control Technology TOSCO II
AIR POLLUTION
QietbaRolaraine (OEA)
Methyl diethanol ami ne (MOEA)
Claus
Well man- Lord
Stratford
Sneil Claus Off-gas
Treating (SCOT)
Limestone Scrubber (FGD)
Absorber/Cooler
Low Flare
High Energy Venturi Wet Scrubber
Venturi Wet Scrubber
Electrostatic Precipitator
Thermal Oxidizer
Fabric Filter (baghouse)
Foam Sprays
Wate** Sprays
Double Seal Oil Storage
Refrigerated Aosnonia Storage
Catalytic Converter
Mai ntenance
X
X
X
X
X
X


X
X
X

X
X
X
X
X
X
X
X
MIS-Lurgi




X

X
X


X
X

X
X
X
X
X
.X
X
Lurgi-Qpen Pit




X






X

X
X
X
X
X
X
X
                        13

-------
TA8LE 1.6-2 (cant.)

Control Technology
WATER MANAGEMENT
Ammonia Recovery
Biological Oxidation
Steam Stripper
Kettle Evaporator
Reverse Osmosis
Carbon Adsorption
Wet Air Oxidation
Vapor Compression
Evaporation
Reinjection
Multimedia Gravity
Filtration
Clarif ier
Process Oil/Water
Separator
Runoff Oil /Water
Separator
Boiler Feedwater
Treatment
Cooling Tower
Makeup Treatment
Equalization Pond
Aerated Pond
Solar Pond

TOSCO II
X
X
X

X
X
X
X


X
X
X
X
X
X

X
PCTMs
MIS-Lurgi
X

X
X
X
X
X


X
X
X
X
X
X
X

X

Lurgi-Qpen Pit
X



X
X


X

X
X
X
X
X
X
X
X
                            (Continued)
        14

-------
                             TABLE 1.6-2  (cont.)

Contro' Technology
SOLID WASTE MANAGEMENT
Runoff Collection System
Upper Embanscments
Lcwer Embankments
RLRorr Collection System
Stilling Basin
Water Impoundment
Leac^ate Collection System
Spr-'pg Col lect^'on/Underdrains
Covers and Bottom Liners
WIS Soerst Retort Treatment
Ous'C Suprsssion
Surface Reclamation
Piezometers

TOSCO I!

X
X
X
X
X
X
X
X
X

X
X

PCTMs
MIS-Lurgi Lurgi-Open Pit

X X

X
X


X
X
X X
X
X X
X X
X

Scares:  DRI.
1.7  ORGANIZATION AND USE OF THE MANUAL

     Following this  "Introduction"  to the PCTM are  six  major sections which
presept material ranging from basic background information to detailed pollu-
tion control data and costs.  In addition, a conplete listing of all informa-
tion  sources  used  to develop  the manual is  provided  in  Section 8 "Refer-
ences."   A brief  description  of  eacft  of the  major sections  is presented
     Section 2 provides  &tt overview of the Lurtji  retorrtS-ng  process and the
case study  examined in  the manual.   It gives  background  information OR the

-------
proposed  project  development,  including  the  site  involved,  retorting  and
mining  processes,  and  the pollution controls  proposed"by the developers of
Tract C-a.

     Section  3  expands upon the case study  outlined in Section 2,   Detailed
process  flow diagrams and  descriptions-are  given for  each  unit  process.
Individual  streams,  thei> mass  flow rates,  and other  characteristics  are
generated during the unit  process analyses, and this information is the basis
for detailed  stream discussions  presented in Section 4.

     Section  4  provides  the  detailed   compositions  for  the  major  process
streams identified in  Section  3.  These  parameters are then used in designing
and costing the pollution control  technologies  discussed  in  Section 5.   All
streams identified in  Section  3  are inventoried by media (gas,  liquid, solid)
and  important  features  of  each stream are  noted  (Tables 4.1-1, 4.1-3  and
4.1-5,  respectively).   Also,  the detailed stream compositions  are summarized
by media (Table 4.1-2, 4.1-4 and 4.1-6).

     Section  5  presents concise inventories  of the available control  tech-
nologies and  approaches for  air,  water and  solid wastes.  .Key features of
each  technology  are   briefly described and many  leading technologies  are
analyzed in greater depth.   The fixed  capital  and direct annual  operating
costs and  design details  for the  leading  technologies are  also  presented.

     Section  6  presents the  total  annual and  per-barrel  cost of  pollution
control  based upon the  cost data developed for  the control  technologies in
Section 5 and the  standard economic assumptions used in all oil shale PCTMs.
This section  also analyzes the sensitivity of the control costs to variations
in the  standard economic assumptions and capital and  operating cost parame-
ters.

     Section  7 discusses the limitations of the data base used  in the prepar-
ation of  the manual.   It  also  identifies  important areas that may require
more research.

     Table 1.7-1 provides  a composite  list  of  the  major process and  waste
streams  generated  by  the  facility  described in  Section 3.   All  streams  are
identified with a  unique name and number.   An asterisk (*) is placed next to
the stream  number if  the  stream comes   into contact with  the environment at
any point in  the  process,  and a descriptive  letter  is given to identify the
state of  the  stream,  i.e.,  gaseous (G),  liquid (L)  or solid (S).   Also,
cross-references are  included for  the  flow diagrams in which the  stream is
produced   and/or   processed   (Section  3),   detailed   composition   tables
(Section 4),  and applicable  control technologies (Section 5)  to allow track-
ing of the stream from its origin to its final disposition.

     For example,   stream  34  in Table  1.7-1  is the  retort   gas—a  gaseous
stream that does  not  contact the environment.   It  is  produced by processing
of the  retort vapors  (stream 26)  from  the Lurgi retorts,  as  illustrated in
Figure 3.3-4,  Section 3.   Table 4.2-12  (Section 4)  provides the  detailed
composition of the gas, and Section 5.1.3 ("Nitrogen Oxides Control") briefly
discusses  approaches  to lower the  ammonia  content  of the  gas in  order to


                                     16

-------
                                                TABLE 171   COMPOSITE LIST 01- STREAMS
Cross-References
Stream
Number
1*
2*
3*
4*
S*

6*

7*

a*

9*

10*

11*

12*


13*

14*


IS*

16*


17*

18*

Description of Stream
Raw Shale Teed
Subore
Overburden
Mine Water
Primary Crusher (ore),
Baghouse Emission
Primary Crusher (subore).
Baghouse Emission
Primary Crusher (overburden),
Baghouse Emission
Raw Shale Conveyor Transfer
Point, Baghouse Emission
Swinging Boom Stacker,
Baghouse Emission
Coarse Ore Conveyor Transfer
Point, Baghouse Emission
Secondary Crusher, Baghouse
Emission
Secondary Crushing to Screening
Conveyor Transfer Point,
Baghouse Emission
Secondary Screening, Baghouse
Emission
Secondary Screening Conveyor
Transfer Point, Baghouse
Emission
Tertiary Crusher, Baghouse
Emission
Tertiary Crushing to Tertiary
Screening Conveyor Transfer
point, Baghouse Emission
Tertiary Screening, Baghouse
Emission
Tertiary Screening to Fine Ore
Type of
Stream
S
S
S
L
G

G

G

G

G

G

G

G


G

G


G

G


G

G
How Uictgram Composition Table
Numbers Numboi s
3 3-2, 3.3-3 4 2-2
3 3-2, 3.3-10
3 3-2, 3 3-10
3 3-2, 3.3-11 4 2-22
3 3-2

3 3-2

3.3-2

3 3-2

3 3-2

3 3-2

3.3-2

3.3-Z


3 3-2

3,3-2


3.3-2

3.3-2


3 3-2

3.3-2
Control Technology
Sections
..
5 3 1, 5 3 2, 5 3 3, 5 3.4
5.3 1, 5 3 2, 5 3,i, 534
521, 5.2.3
5.1 1

5 1.1

5.1 1

5 1.1

511

511

5.1 1

5.1.1


5.1.1

5.1.1


5 1.1

S 1.1


5 1.1

b.1.1
19*
  Storage Conveyor Transfer
  Point, Baghouse Emission

Fine Ore Storage, Baflhouse
                                                          1,3-2
                                                                                                             5.1 1
                                                                                                                      (Continued)

-------
                                                                            TABLE 1 7-1  (cont.)
CD
Stream
Nupber
20*
21*
22*
23*
24*
25
26
27
28*
29*
30
31*
32*
33
34
35
36
37
38
39
40
41
42
43
44*
45
Description of Stream
Retort Feed Hopper Conveyor
Transfer Point, Baghouie
Emission
Retort Feed Hopper, Baghouse
[mission
Baghouse Dusts
Processed Shate Load-out
Hopper, Baghouse Emission
Diesel Emissions
Combustion Air to Lift Pipes
Retort Vapors
High Pressure Steam
Blowdown from Waste Heat Boiler
Processed Shale
Steam to Humidifier
Lurgi Flue Gas
Raw Shale Retort Feed Conveyor,
Baghouse Emission
Raw Retort Gas
Retort Gas
Retort Gas to Lift Pipes
Light Oils to Storage
Light Oil Makeup to Naphtha
Recovery
Middle Oils to Storage
Diesel Fuel - Mining
Equipment
Diesel Fuel ~ Disposal
Equipment
Gas Liquor
Heavy Oils to Storage
Oily Oust
Fugitive Hydrocarbon Emissions
from Storage Tanks
Naphtha- free Retort Gas
Type of
Stream
G
G
S
G
G
G
G
G
L
S
G
G
C
G
G
G
L
L
L
L
L
L
L
S
G
G
Cross-References
flow Diagram Composition Table Control Technology
Number !. Numbers Sections
33-2 -- 511
33-2 — b 1 1
3 3-2, 3 3-3 4,2-2
3 3-2, 3 3-10 -- 5 1.1
3 3-2, 3 3-10 — 514,515
3 3-3
3.3-3, 3.3-4 4 2-9
3 3-3, 3.3-6
3 3-3, 3 3-11 — 5 2,1
3 3-2, 3.3-3, 3 3-10 4 2-5, 4.2-6, 4,2-7 5.3 1, 5 3 2, S 3 3, 5 3 4
3 3-3
3 3-3 4 2-19 511
3.3-3 — 5.1 1
3,3-4 4 2-11
3 3-4, 3 3-5 4 2-1.2 5 1.3
3.3-3, 3 3-4
"3 3-4 4 2-10
3 3-4, 3 3-5
3 3-4 4 2-10
3 3-2. 3 3-4, 3 3-10
3 3-4, 3 3-10
3 3-4, 33-9 4 2-20 5 2 1, 5,2 2, 5 2 3
3 3-4 4 2-10
3 3-3, 3.3-4
33-4 -- 514
3 3-5, 3 3-6 4 2-13 S 12, 5.1.3
                                                                                                                                         (Continued)

-------
                                                         TABLfc 1 1-1  (cont )
Stream
Number
46
47*
48
49
50
51
SZ •
S3
54
55
56
57
SB
59*
60*'
61
*2
63*
64
«l*
Description of Stream
Naphtha Product to Storage
Hydrocarbon Emissions from
Naphtha Storage
Compressed Naphtha" free Gas
Compressor Condensate
Steam to Naphtha Recovery
Steam to DEA Unit
Steam to Stretford Unit
Steam to Ammonia Recovery Unit
Ami'ne Makeup
TEG Makeup
Sweet Gas from DEA Unit
Dried Fuel Gas to Pipeline
Acid Gases from DEA
Regeneration
Spent Anine
T£S Regeneration Vent Emission
Stripping Air to Strettord
Stretford Chenicals
Stretford Treated Acid Gases
Stretford Oxidizer Vent Gas
Stretford Spent Liquor to
Type of
Stream
L
G
G
L
G
G
G
G
L
L
G
G
G
L
G
G
L
G
G
L
Cross-References
[low Dlaqtam Composition Table Control Technology
Number:, Numbers Sections
335 4 2-14
3 3 b -- b 1 4
3 3-6, 3 3-7 4 2-15 S 1 ?, 5 1 3
3 3-6, 3 3-9 4 2-20 5 2 1, 5 ? 2, b.Z 3
3 3-5, 3 3-6
3 3-6, 3 3-7
3 3-6, 3 3-8
3 3-6, 3 3-9
3 3-7
j 3-7
3 3-7 4 2-16 5.1.2
3 3-7 4 2-17
3 3-7, 3 3-8 4 2-18 5.1 2
3 3-7, 3 3-10 — 5 3.1
3 3-7
3 3-8 4 2-18
3 3-8
3 3-8 4.2-18 b.l 2
3.3-3, 3 3-8 4 2-18
3 3-8
          Reclaim
$6      Liquid Sulfur Product to              L
          Storage
67      Phosphoric Acid                       L
18      Caustic (NaOH)                        S
69      Steam Condensate from                 L
          Ammonia Recovery
70*     Stripped Gas Liquor                   L
71      Anhydrous Ammonia to Storage          L
72      Ammonia Overhead Vapors               G
73*     Processed Shale Conveyor              t
          Transfer Point, Bayhou&e
          Emission
3 3-8

3 3-9
3.3-9
3 3-9, 3 3-11

3 3-9, 3 3-11
3 3-9
3 3-3, 3 3-9
3 3-10
                          4 2-18
4 2-21
4 2-21
4 2-21
5.2 3
513
"i.l 2, 5 2 2
511
                                                                                                                      (Continued)

-------
TABLE 1.7-1  tcont )

Cross-References
Stream
Wiitihpr
74*
«*

76*
77

78*

79

80

81

82

iv, 83
ro
o
81

85

86

87

88*

89

90*
91*

92*
93*
94
95*
96*
Description of Stream
riigititfp Dusts
Excess Mine Water to Aeration
Pond
Aerated Water to Discharge
Feedwater to Waste Heat
Boiler
Total Processed Shale
Moistening Water
Cooling Water to LurQi CHI
Recovery
Cooling Water to Naphtha
Recovery
Steam Condensate from Naphtha
Stripper
Cooling Water to Compression
Cooling
Cooling Water to DEA-TEG
Treatment
Steam Condensate from DEA-TEG
Treatment
Steam Condensate from
Stretford
Cooling Water Hakeup to
Stretford
Process Water Makeup to
Stretford
Humidified A1r Cooler
6 1 tfwdown
Cooling Water to Ammonia
Recovery
Water for Dust Palliatives
Processed Shale Revegetaticm
Water
Raw Shale Leachate
Storm Runoff
Boiler Feedwater Makeup
Service and Tire Water
Mine Water Clarifier Sludqe
Type of
Stream
G
L

L
L

L

t

t

L

L

L

L

L

L

L

L

L

t
L

L
L
L
L
I
How fiidigrcUTi Composition Table
Numbers Numbej s
3
3

3
3.

3

3,

3

3

3

3

3

3-?,
3-11

3-11
,3-3,

3-3,

.3-4,

3-5,

3:5,

3-6,

3-7,

3-7,

3.3-8,

3

3.

3

3.

3
3.

3
3
3
3
3

3-8,

3-8,

3-4,

3-9,

3-2,
3-10,

3-2,
3-11
3-11
3-11
3-11
3



3

3

J

3

3

3

J

3

3

J

3

3,

3

3
3

3




3-10
4 2-23

4.2-23
3-11

3-11

3-11

3-11

3-11

3-11

3-11

3-11

3-11

3-11

3-11

3-8, 3 3-11

3-11

3-10, 3 3-11
3-11

3-11 4 2-3, 4.2-4
•-
--
--
—
Control Technelogy
Sections
5.
5




5.

5,

5.



5.

5.





5

5

5.

5

5
5.

1
2,




2.

1
3,




1


524

-
—



2.3

2



2.

2





2

2.

2

2

2
2

5.2
5
5.
5
5
2
2
2
2

J



3

3





3

1,

1

3

1,
1,

1.
1,
3
1
1



--





—

—



5 2.3





5.3 4
5.3.4

5.3 3
532




-------
                                                          TABLE  17-1   (cont.)
Crdss-Referertt.es
Streaai
Number
97

98
•99*
100*

101*

102*
103*

104*

105*
10$*
107*
108*

109*

WO*

lit*
lit*

Description of Stream
Water to Coolinq Tower
Makeup Treatment
Treated Water to Cooling Tower
Potable/Sanitary Water
Water Evaporation from Mine
Water Clarifier
Used Sanitary Water to
Municipal Treatment
Treated Sanitary Water
Sanitary Water Treatment
Sludge
Boiler Feedwater Treataent
Concentrate
Cooling Tower Slowdown
Cooling Tower Drift
Cooling Tower Evaporation
Equalization Pond Discharge
to Processed Shale Moistening
Clarified Mine Water to
Processed Shale Holstenlng
Water Evaporation from
Equalization Pond
Aerated Pond Sludge
Miscellaneous HC Emission
Type of
Stream
L

L
L
G

L

L
L

L

L
L
a
L

L

G

L
G
Mow Diagtain Composition Table
Numbers Numbers
3 3-11

3.3-11
3 3-11
3 3-11

3,3-11

3 3-11
3 3-10, 3 3-11

3 3-11

3 3-11
3 3-11
3 3-11
3 3-11

3 3-11

3.3-11

3 3-10, 3.3-11
--
Control Cechnolwqy

5

5
5
b

S

5,
5

5

5
5
5
5

5.

5,

5,
5
Sections
2.3

2,3
2.1
2 3

2 1

,2.1
3 4

2 1, 5 2 3

2.1, 523
2.3
2 3
3.3, 534

,2 1, S.3 3, 5 3 4

,2.1

2.3
1.4
* Indicates streams  that come  Into  contact with  tht  environment

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control   the  nitrogen   oxides   emissions.   Figure 3,3-4   indicates   that
Figure 3.3-5 Is the destination for the gas.             '                  '

     Figure 3.3-5 exemplifies the processing of the retort gas to produce the
naphtha-free  retort gas  (stream 45)  for  which  the detailed  composition is
given  in Table 4'.2-13.   The naphtha-free  fas  can be  followed sequentially
through Figures 3.3-6 (stream 48), 3.3-7 (stream 58) and 3.3-8 (stream 63) to
illustrate the compression  of the gas, removal of the acidic components from
the  gas,  and  release  of  the  treated  acid  gases (after  the removal  and
recovery of  H2S)  into  the atmosphere, respectively.  Other process and waste
streams can be followed in a similar manner.
                                     22

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                                  SECTION 2

                          SUWWRY OF STUDY FEATURES
     The  Federal  Prototype Oil  Shale Leasing  Program was  initiated  fay the
U.S.  Department of the  Interior (001)  in 1974.  The  purpose  of the program
was to  encourage  commercial  development of the  energy resource in the Green
River  Oil Shale  Formation.    Six  lease  tracts, two  each  in  the  states of
Colorado,  Utah  and Wyoming,  were  created and  offered to  the  public  on the
basis  of  hign  bid.   The first  of  these tracts, Federal  Lease Tract  C-a in
Colorado, was subsequently awarded  to Gulf Oil  Corporation and Standard Oil
Company  (Indiana) after  submission  of  a joint bonus1 bid of  approximately
$210 nil lion.   The  two companies then  formed a  general  partnership  in 1978
and created  the  Rio  Blanco Oil  Shale Company (RBOSC) to  operate  the  tract.

     Under  the  requirements   of  the  Leasing  Program,  Gulf  and  Standard
submitted a  Detailed  Development Plan (DDP) to  develop the tract  using open
pit mining and  a  combination  of TOSCO II and gas combustion type aboveground
retorting, with the  understanding  that off-tract disposal  of  the  overburden
and processed shale would be  allowed'so that the tract co'uld be explored to
its fj1]  potential  (Gulf Oil  Corp,  and Standard  OiV:Co.  [Indiana],  Harcii
1976).  However, due to acreage restrictions in the Minerals Leasing Act, the
DOI   rafused  to   grant   additional   Federal   land  for  disposal   purposes.
Subsequently, a revised  DDP was submitted emphasizing Modified In  Situ (MIS)
retorting with a supporting TOSCO II aboveground retorting facility (Gulf Oil
Corp.  and  Standard Oil  Co.  [Indiana], May 1977).  This'plan did not require
open pit mining or off-site disposal  of the solid wastes.

     In  1981,  a  modification  was  added  to  the   DDP  to demonstrate  the
feasibility  of  open  pit mining with  Lurgi-Ruhrgas  aboveground  retorting.
Specifically, the plan called  for an experimental open pit to support a Lurgl
demonstration plant that would process approximately 4,400 TPSD of  shale (Rio
Blanco 0"»1 Shale Co.,  February 1981).   The retort was scheduled for operation
1n  ea^ly  1983;   however,  due  to rising  cost estimates  for the plant,  the
demonstration project  was suspended  in  the  summer  of'1981.   Recently,  DOI
approved  a  suspension  of  development operations  on Tract C-a (U.S.  DOI,
July 2S, 1982).

     Currently,  RBOSC is  planning to  build a Lurgi  pilot  plant (1  to 5 TPSD)
at Gulf's  research facility in Pennsylvania,   The objective of the  study is
to  obtain essential   technical   details  on the  Lurgf retorting technology.

     This manual examines open  pit  mining as  proposed ifl  the original  OOP of
March  1S76S, combined  with ilurgi retorting as proposed in  the  February 1S81
    *ication to  the DDP.


                                    23                     .    .

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2,1   PtQCESS OVERVIEW.

      The  starting, point  for the analysis  is some 30 years after the operation
has  reached full production capacity.  This  amount  of time was estimated to
be   necessary  to  create  enough  working  space   in  the  pit  so  that  mine
backfilling could commence  (Gulf Oil Corp.  and  Standard 'Oil Co.-[Indiana],
March 1976).   The  overburden  and  processed shale  generated during these
30 years  will  be disposed of permanently on  an off-tract location.  In order
to be consistent with, other oil  shale Pollution Control Technical Manuals, a
project  life of  20 years,  following the initial  30  years,  has been assumed
for  costing purposes.   The  wastes  generated during  this 20-year period are
placed back  in  the  pit.   The   dewatering  of  the  aquifers is  continued
throughout  the  project,  and the  excess aquifer water is treated for surface
discharge.   The  shale oil  is not upgraded  on site,  but the  retort  gas is
cleaned  to  pipeline  quality  so  that  it  can be  sold.  Also,  there  is  a
potential for generating some electricity from the excess steam.

      Open  pit  mining of 119,000 TPSD of raw oil shale with 62,100 TPSD of
overburden  and  11,900 TPSD  of   subgrade  ore  will  be  required  for  the
commercial  operation.   The  mining  of  approximately  193,000 TPSD  of  solids
will  be  the  largest  open  pit  operation  in the  world; by  comparison,  the
largest  open pit  at present  is  the Kennecott  copper  mine  in  Utah, which
produces 110.000 TPSO of copper ore.

      A full-sized Lurgi  retort  can process  about 4,500 TPSD  of  oil  shale.
However,  some  of , the noncritical  units of  the  module,  such as  the  feed
hopper,  collecting  bin, and  surge vessel,  can  be increased  in size  to
accommodate" two  each of  the critical  units, such as the  screw  mixer,  lift
pipe,  etc.   As   a  result^  approximately  9,150 TPSD  of the  shale  can  be
processed in a  single train on a 24-hr/day basis.   Thirteen larger capacity
trains  would  be required  to  process  119,000 TPSD  of oil  shale for  the
commercial  operation.

      A gross  oil production  rate of 65,167  BPSD  (including  naphtha)  may be
expected; this  is based  on  a yield of  23 gallons  of crude  oil  per  ton of
shale  and  a  retorting  efficiency  of  100%  of  the modified  Fischer  assay.
However,  approximately  2,000 BPSD of  naphtha are calculated to  be consumed
with  the retort gas, which is used as supplemental fuel to balance the energy
needs  of  the lift pipes; thus,  the net  oil  production  rate  is 63,140 BPSD.
The  net  retort  gas production  is at 149 x 10s Ib/hr before  naphtha removal
and  122 x 103  Ib/hr  after   recovering  the   naphtha.   The  gas  rate  to  the
pipeline  is 62 x 103  Ib/hr  after  cleanup.  Approximately 600 gpm  of process
water, or gas  liquor, are also produced, from which 22.6 TPSD of ammonia are
recovered.   The  processed shale  is produced and disposed of at a rate  of
95,000 TPSD (dry basis).

     The quantities defining  the  dimensions  of the plant complex  are  listed
in Table  2.1-1.   Process  related quantities have been  estimated primarily
from  the data published by the developer  (Gulf Oil Corp.  and Standard Oil Co.
[Indiana],  March 1976;  Rio  Blanco  Oil  Shale Co.,  February  1981).   These
quantities  form  the  basis  for  the  technical   analyses  and  discussions
presented in this document.

                                     24

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              TABU 2.1-1.   MAJOR PARAMETERS DEFINING THE SIZE OF
                         THE COMMERCIAL PLANT COMPLEX
 Parameter, Unit                                              Quantity
 Net Oil  Produced,  BPSD                                        63,1*0*
 Retorting Oil  Yield, % Fischer Assay                             100
 Net Retort Gas Produced,  103 "Ib/hr                               149
 Treated  Gas to Pipeline,  103 Ib/hr (109 Btu/hr)                   62 (1.2)
 Total  Solids Mined,  TPSD                                      193,000
    Raw Oil Shale,  TPSD                                       119,000
    Raw Shale Grade,  gpt                                           23
    Overburden, TPSD                                            62,100
    Subore, TPSD                                               11,900
 Processed Shale Disposed  (dry basis),  TPSD                    94,956
 Processed Shale Moistening Water,  gpm                           3,644
 Flue Gas Produced, 103 Ib/hr                                   7,195
 Gas Liquor Produced, gpm                                          586
 Sulfur Produced, MTPSO    .,                '                        7.6
 Ammonia  Produced,  TPSD                         •   .                22.6
 Mine Water Produced, 'gpm            '      '             .        16,500
    Mine  Water  Consumed, gpm (bbl/bbl of oil)                    8,170 (4.4)
    Mine  Water  Discharged,  gpm                                  8,330
 Number of Retort Trains                                            13
 On-streaif Factor, %                                                90
 Project  Duration, years                                            20
 Total  Lard Area, acres                                         5,100
 Opei Pit Area, acres                                           1,150
 Open Pit Surface Diameter,  feet                                7,900
JjjjieJSepth,  feet_                                              1,350
 Processed Shale Disposal Area,  acres                            1,150

 * The  gross  oil  production  rate is 65,167  BPSO.  Approximately  2,000 BPSD  of
  the  naphtha  oil are used  in the  lift pipes.
 Source:   DRI estimates based  on ctsta from  Gulf  Oil Corp. and Standard Oil
          Co.   (Indiana), March 1976> and Rio Blanco Oil Shale Co.,
          cei?ruary 1981,            -, .

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 2.1.1  Site Description               .,  .

      Tract  C-a  covers  approximately  5,100  acres  In  Rio  Blanco  County,
 Colorado.   It is located on the west flank of the Piceance  Creek Basin, about
 5 miles east of  Cathedral  Bluffs  between Yellow Creek  and  Big Duck  Creek, as
 illustrated In Figure 2.1-1,

      Valleys and ridges crossing  Tract C-a originate to  the southwest in the
 vicinity of Cathedral Bluffs.   Most of the tract is  drained by Corral  and Box
 Elder Gulches,  which eventually join Stake Springs Draw to  form Yellow Creek.
 Yellow Creek  initially flows  northeast,  but curves to the  northwest  before
 emptying  into  the  White  River,  about 20 miles  north of  the tract at an
 elevation  of  some  5,500 feet.   The  first principal  drainage north  of the
 tract  is   Big  Duck  Creek,  which  flows  into  Yellow  Creek  about  7 miles
 northeast   of  the  tract.    On  the  south,  Ryan  Gulch passes within about
 2.5 miles  of the tract's  southern  boundary  before  converging with Piceance
 Creek,  about  10 miles  due east  of the  tract where the elevation  is about
 6,100 feet.    Tract  C-a  is   located  approximately  20 miles  southeast  of
 Rangely,  35 miles southwest of Meeker,  and some 75  miles due north of Grand
 Junction (Gulf  Oil  Corp. and  Standard Oil  Co.  [Indiana], March  1976).

      Two basic weather systems affect  precipitation  on  Tract C-a.    Frontal
 systems  generally  result  in widespread,  uniform precipitation.   Convection
 systems  or thunderstorms result in  erratic patterns  of precipitation  over an
 area  of a few square miles.   Annual precipitation on  the  tract (measured at
 Stake Springs  Draw)  for the  years 1975  and  1976 measured  13.25  and 11.83
 inches,  respectively.  Ambient  temperatures  are moderate during  the  spring,
 summer  and fall;  winter minimum^ temperatures are -low.   Gradient .winds are the
 prevailing westerlies which occur all  year, interrupted only occasionally by
 the passage  of  frontal  systems.  In  the absence  of strong gradient winds, the
 terrain  produces  local  meteorological  conditions (Gulf  Oil Corp. and Standard
 Oil Co.  [Indiana],  Hay  1977).

      Peak  stream flows usually occur  after spring snowmelt  (March-April) and
 lows  occur in late  summer or  early fall  (August-November).   Records  kept from
 1974  to  1976  indicated that both  Corral  Gulch  (east)  and Yellow Creek
 sustained  baseflow,  with  Yellow  Creek having  higher  discharges  (averaging
 approximately  1,150 acre-feet annually).  Corral  Gulch (east) had an average
 annual  discharge  of 450 acre-feet over  this  period.   Box  Elder  Gulch  and
 Corral Gulch (west)  do  not sustain baseflows;  however,  both showed effects of
 snowmelt.   A water analysis of Yellow Creek  near the White  River, conducted
 over  an 8-month period  in 1976,  showed  an  average of 2,650 mg/1 TDS  and
 1,475 mg/1  bicarbonate.  A  similar  analysis  of  the water  in Corral Gulch
 (east)  indicated a TDS content of 795 mg/1 with 455 mg/1 bicarbonate.   Among
 the stream reaches on Tract C-a,  iron,  pH, and total  dissolved solids (TDS)
 exceed  suggested drinking water  limits.   Along the  lower  section of  Corral
 Gulch on  the tract, and in Yellow Creek,  groundwater inflows cause increases
 in  hardness,  fluoride  and  sodium   (Gulf Oil  Corp.   and  Standard Oil  Co.
 [Indiana], May 1977).

      It  is probable that some  of the  springs  in the area supplying perennial
water flow are  fed by  the alluvial  aquifers.   Along the main fork of Corral

                                      26

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                                      R97W  ]   R96W  |  R95W  J  R94W
 MILES
DR1 based TO 6oK Oil C«fi tutd
       Oil Cai Indiano), Murch
FIGURE 2>t
                                        c-n  i« f»GE««:-E
                                    2?

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Gulch,.-Box Elder  Gulch,  and Stake Springs Draw,.the thickness of saturated
alluvium  ranges  from  12 to 54 feet  and averages  27 feet.   Comparison  of
aquifer water level  and stream flow indicates that the alluvial aquifers are
very closely  related to regional surface water.  Springtime rises in alluvial
aquifer water levels result  from infiltration of snowiuelt.

     An  extensive deep  aquifer  system also  exists  in  the  Piceance  Creek
Basin.   The  system  mainly  consists  of  two artesian bedrock aquifers—the
upper aquifer and i;he lower aquifer.    Although  the  impermeable Mahogany oil
shale zone  separates the two aquifers,  they are interconnected in some places
via  natural faults and fracturing; however,  there is little interconnection
under  Tract C-a  except  for the  northeast corner.   The  aquifer  thickness
varies  from  100 to 400  feet,  with  220 feet  being  the  average  for  both
aquifers, and  together they contain 25 million acre-feet of water.

     Some  significant  differences  can  be  observed  in  the lower  and  upper
aquifers.   For example, the  gradient  of the  lower  aquifer  is much flatter
than the  gradient of the upper aquifer.  One cause of this difference may be
the  much   higher  transmissivity  of  the  lower  aquifer.   Another  major
difference  is  that  the  upper  aquifer  discharges directly into Yellow and
Piceance Creeks,  while  the lower aquifer must discharge by upward leakage to
the  upper  aquifer.  This  slow,  diffuse  discharge over a  large area should
result  in  a region near the  center of the basin  over which  the gradient is
nearly  flat.    The  middle  of Tract C-a  appears   to  be  the  border  of  this
discharge area  (Slawson, April 1980).

2.1.2  Description of the Plant Complex

    ^Figure 2.1-2- shows   the 'location  of  thfe  off-tract  disposal  area,
processing  facilities,  and open  pit  mine, with  respect to  Tract  C-a.   The
disposal  area  located  to  the  northeast  of the  tract  is  reserved  for the
wastes  generated  during   the initial   30 years  of  tract  development.   The
wastes produced during the  20-year project  life will be placed back in the
pit.

     The  processing facilities  will  be  situated  off of  the tract, to the
north.    Figure 2.1-3 depicts  a plot  plan  for  the  facilities, which  will
include 13  Lurgi  processing trains with the  same  number of product recovery
sections.    The  secondary  and tertiary crushers will  be  located at the plant
site;  however,  the primary crushers  will  be  placed  in  the pit  itself.
Overland conveyors  will transport the  raw  shale to  the plant  and  carry the
processed  shale from the  plant back  to the pit.   The raw  shale  stockpile
(open) and fine shale storage bin (enclosed) will also be suitably located at
the plant site.  Other pertinent processing facilities on the plant plot will
include gas  and water  (process  as well as mine)  treatment,  product tankage
and pipelines,  utility area, shop and warehouse,  etc.

     The  open  pit  will   begin  in  the  northwest  quadrant of  the  tract.
Figure 2.1-4 presents a detailed schematic of the pit at the beginning of the
project (after the initial  30-year  development).    A partial  geologic  cross
section of  the pit is  shown in Figure  2.1-5;  as  the figure illustrates, the
pit will  intercept  the upper and lower aquifers  located  under the tract.

                                     28

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                                                         •R99W
R98W —
T
I
S
2
S
                                                         84 MESA
                                                         DISPOSAL
                                                          AREA
                                  LURGI-RUHiGAS
                                  < PLANT
 SOURCE-' DRI based on Gulf Oil Corp. and
         Standard Oil Ca {Indiana), March 1976
                               FIGURE  2.1-2 PLANT COMPLEX

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                                PRODUCT
                                STORAGE
                              GAS a WATER

                                TREATING
                                FACILITIES
                FiNE ORE
                STORAGE
                                              CONVEYOR
                                              TO PROCESSED SHALE DISPOSAL
                 COARSE ORE
                 STOCKPILE
                  CONVEYOR
                  TO RETORTING
                   AREA
'SOURCE^ DRi based on Gulf Oil Corp.'ond  .
         Standard Oil Co.( Indiana), March 1976
               FIGURE  2.1-3 PLOT PLAN TOR PROCESSING FACILITIES

                                    30

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                                                      N
                                                      1
                                                   SCALE IN FT
                                               0   500  1000  1500
                                               I	1	L	1
                                                                                          CONTOUR INTERVAL SO*
                                                                                          TERRACE INTERVAL 100'
SOURCE'  QR j basedj>o Gjlf Oil Co^ ond
         Standard Oi!  Co. (Indiana), March (976
                                 FIGURE 2.1-4   30-YEAR OPEN PIT DESIGN

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  WEST
                                                                                                            C'
  7000-
  6500-
  6000-
  5500J
        GENERALIZED
         fir
                                                                                                   GENERALIZED

                                                                                                      PIT LIMIT
                                             WEST TO  EAST SECTION  C-C
                                                                SOD
                                                            FEET

                                                  HOTE. CROSS SCCTION 228,000 N
                                                       W£ST EAST CENTERLINE

                                                       JSfE flfJURE 2.1-4)
                                                                                                               EAST
                                                                                                             -7500
-7000
                                                                                                             -650Q
                                                                                                             -6000
L5500
SOURCE1 DRi bosedon Gulf Oil Corp, ond
        Stondord Oil Co(lndiano),Moich 1976
                                  FIGURE 2.1-5  30-YEAR PIT CROSS SECTION

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2.1.3  Description of the Retorting Process

     A  detailed  description  of  the  Lurgi  retorting process  is  presented
below.  Unit  flow diagrams describing the operation of other  processing units
in the integrated plant complex  are presented in Section 3.

     Lurgi-Ruhrgas RetortIngProcess--

     A  schematic for the  Lurgi  retorting  process  is shown  in  Figure  2.1-6.
Initial  crushing in  the  pit  reduces  the size  of  the  run-of-mine  shale  to
mi pus  8  inches.  Secondary  and  tertiary  crushing  further reduce the  shale
size to sninus 1/4 to 1/3 inches.    The crushed oil shale  is fed through  a feed
hopper to a double screw mixer,,  where four to eight times its weight of a hot
(1,200-1,300°F)  circulating  heat  carrier,  such as  sand or  processed  shale
from  the collecting  bin,  is  thoroughly mixed  in,  thus heating  the  entire
mixture  to   approximately   950-1,000°F  within  a  few  seconds.   At  this
temperature,  pyrolysis  of  the  kerogen in the oil  shale occurs,  resulting in
the  production  of  retort  gas,  shale  oil  vapor  and water  vapor.    The
circulating  heat carrier and  the  partially retorted  shale  are  then dropped
from the screw mixer into the surge vessel, where residual oil components  are
distilled off.   The mixture of  heat carrier  and retorted  shale  residue  is
passed to the lower section of the lift pipe, where combustion air (preheated
tc  450-93G°F)  is  introduced,  raising  the mixture pneumatically to  the
collecting bin  (TRW, and' DRI,  1975-1978; York,  June  13, 1980).    Essentially
all  avai'aole organic • carbon  ,contained  in  the retorted  shale  residue  is
burned in the lift pjipe.'  Supplemental fuel .may be added to the bottom  of  the
lift pipe  to sustain tfje  combustion .of the organic  residue  when processing
leaner  oil  shales.   Also,  at   the 'high  lift  pipe temperature,  a  moderate
amount, of carbonate .decomposition  occurs  in the processed shale.  At the  top
of trie lift  pipe,  the hot,  burned shale  is  separated from the flue gases  in'
tn,e  collecting  bin.   Pities  ara  carried out  of the  collecting  bin  with  the
flue gas stream.  The  coarse-grained ,shale residue accumulates  in the  lower
section of the  collecting  bin  and flows continuously  to the  mixer.   Partial
removal of  the solids to prevent  accumulation  in the collecting  bin  may be
rscuired  if  the   fines   carry-over  is  not  sufficient.    If  the   shale
disintegrates to  the  extent that  tnore'fines are produced than  expected, an
additional  coarse-graindd heat carrier,  such as sarid or low-grade shale, may
be  needfed.   The combustion  air  supplied to  the lift pipe   is  preheated say
counter-current heat exchange with the flue gas  stream in the preheat section
of the waste  heat  boiler.   The calcined minerals in the burned shale combine
with the sulfur  dioxide! produced by combustion  of the organic sulfur to font!
calcium  and  , magnesium  (sulfites  and  sulfates   (Rio  Blanco  Oil   Shale Co.,
February 1981).

     The pyrolysis products  stream containing shale  fines is  withdrawn at the
end of the screw mixer  and passed through two series-connected cyclones to a
product  recovery section.    The  fines  are separated  in these  cyclones and
returned to  the  recycle  system.   The  vapor  stream  then  passes through a
sequence  of  three  scrubbing   coolers   (not shown;   see  Figure  3.3-4  in
Section 3).    The first scrubbing  cooler is  designed to operate  at a high
temperature (~350°F) and to  remove dust from the gas  stream  by  condensation
of heavier oil fractions.   Circulation -of the condensed heavy  oil through the


                                   •  33

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                                                    HEAT
w
                  FLUE GAS
                                                                     FEED
                             I - •-
                                                                                     TO OIL RECOVERY
           PROCESSED SHALE MIXES
                        MOISTURIZED  NKHSTUR1ZINS
                          RE9DUE      AND  tl>lrt
                                     QUENCHING
                                       WATER
                   DRf twsed on Schmolfeld,
                   July 1975
 BOILER

FEEDWATER
,OILY

 DUST
                           FIGURE 2,1-6 LURSI-RUHRGAS OIL SHALE RETORTING PROCESS

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 scrubber  aids  in removal of the dust.  A dusty  heavy oil  is  obtained  ai  this
 point.    The   operating  temperature  of  this  scrubber   is  controlled  by
 introducing and evaporating the gas liquor through the  scrubber.   The amount
 of  heavy  oil  and its properties can  be varied in this  fashion.   In the  next
 scrubb^rg  cooler,   further  condensation  of  the  oil   takes  place at   a
 teste^amre above  the dew point of water  to  produce a  water-free  middle oil
 (Schnalfeld,  July  1975),   Final cooling  of the gas  produces an aqueous gas
 cor-densats and a  light oil fraction.  The  light oil  is  separated f**ora the
 cordensate  or  gas  liquor  in  an  oil /water separator.    Partial  amounts  of
 amrnorra and  sulfur dioxide in the gas stream are absorbed in the gas  liquor.
 If  necessary,  further removal  of these species  from  the  gas can be achieved
 oy  circulating  more  of the  gas  condensate  through  the  third  scrunber.
 Finally,  the   gas  is  scrubbed with a  lean oil in  the naphtha scrubber  to
 recove^ naphtha and  noncondensable gases, as deemed desirable.  Residual H2S
 may  bs removed  from  the remaining  gas  by one of several methods.  The gas
 liquor ray also be cleaned before reuse or discharge,

     ~!"e  flue  gas stream  in the  lift  pipe is  dedusted  in  a cyclone after
 leaving tne  collecting  bin; it  is then routed through  a  heat exchanger for
 preheating of  combustion air,  a waste heat boiler to  produce process  steam,
 arctha-"  cyclone,  and  a, humidifier  or  flue gas  conditioner.   The flue  gas
 stream is cooled  somewhat and conditioned in the  humidifier by adding steam
 generated  -during  processed   shale   quenching.    After   humidifi cation  and
 coo*'nc,  residual  dust  is  removed  from  the  flue  gas  stream  using   an
 electrostatic   precipitator   and   discharged ' into    a   processed   shale
 ouenchef/mo" sturizer • where  more water  is  added  to  cool 'the 'solids.   The
 processed  shal-e residue,  cooled  to  ~2QQ°F,   is  moisturized to a suitable
 moistjrs content and discarded,   !            ,              -

     "re dusty  heavy  cil  obtained  from the first scrubbing cooler  Is thinned
w:th   an   available   lighter  oil   from  the   process   and  subjected    to
certrifugatiop to remove the dust. , The clean oil is  stabilized by vaporizing
the light cil  components and, then  sent for storage.   The recovered light oil
 is '."ecyclsc to the process and the  dust is fed to the bottom of the lift pipe
 and barred.                 i.

2.2  POLLUTION CONTROL CASE STUDY

     The case study examined in this  manual  is based  primarily on information
published by the developers  (Gulf  Oil  Corp.  and Standard  Oil Co.  [Indiana],
Harcn 1S76;  Rio Blanco  Oil  Shale Co.,  February 1981).   The pollution control
approaches analyzed for the  commercial  plant  activities,  such  as  mining  and
crushing,   Lurgi  flue  gas  discharge,   retort  gas   treatment,  gas   liquor
treatment s  excess  mine  water  discharge,  and  solid  waste disposal,  are
intended  to   serve  as  illustrative examples only  and  should  not  lirait
const deration of
     Since  standard  -industry  practices  are -adopted,  for  various  minor
treatments ,  these technologies ATS not  discussed in  detail (e.g.,  boiler
fsedwater raak&bp treatment).  < The  impact on the cost of treatment as a result
of variations in  the  -pollution  control  strategy in other processing areas is
                                     35

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assessed,  but a detailed analysis of  the, .treatment technology itself is not
presented.

2.2,1  Key Features of Pollution Control

     The primary feature of this manual  is that it  provides an opportunity to
analyze  the  impacts  resulting  from open  pit mining.   This mining technique
was  selected by the  Tract C-a developer  because the  oil  shale deposits are
technologically  and  economically  amenable   to  this  type  of  recovery  and,
furthermore,  it  affords  nearly  complete mining  of  the  resource.   As  a
disadvantage, however, large amounts of  overburden  and subgrade ore also must
be removed along  with the retortable  oil  shale, making it the largest mining
operation  of  its kind in the world.

     All of  the mined materials  are crushed  in the pit  and transported for
disposal  or  processing.   The  transportation  is   achieved  by an  extensive
network  of  overland  enclosed conveyors  equipped  with dust  control  systems
such as  baghouses and water and  foam sprays.  Further crushing  of  the oil
shale takes  place  at the plant located  off  site,  to the north of the tract.
Because of the  size  and extent of  this  materials  handling system, the plant
uses  an unusually  high number  of  baghouses and  dust  suppression devices.

     The  commercial   open  pit  will   intercept  two extensive deep  aquifer
systems  which  lie under  the tract.   These  aquifers slope  gently  to  the
northeast  toward  the center  of  the hydrologic basin  of  Piceance  Creek;  the
waters  are mostly stagnant,'  as  the aquifer  recharge  occurs  primarily  from
precipitation  along  the  basin  margins,  and  discharge  is  by  release  to
Piceance Creek.  The  effec.t  of intersecting  the aquifers  in the  pit will be
the tendency  of  the  waters to flow  from all  directions into the pit.  Thus,
the aquifers  would  need  to be dewatered throughout the project life to avoid
infiltration of water into the pit.  The transmissivity, storage coefficient,
and  thickness  data  for  the  two  aquifers  suggest  a  dewatering   rate  of
approximately  16,500 gpm  (Gulf  Oil Corp.  and  Standard  Oil  Co.  [Indiana],
March 1976).   About  70  dewatering wells around  the periphery of  the pit may
be required for dewatering (these wells are assumed to be in place before the
process analysis in  this case study begins).   Although the process will  have
zero water discharge  in  terms of process waters, the result of dewatering is
that an  excess of mine  water  will  remain after the process  needs  have  been
satisfied.    Since  this  will  necessitate disposal   of  the  excess  mine water,
the overall plant will no longer be a zero discharge facility.

     The plant complex considered  here will  not burn  any  fuels for power or
steam  generation.   Electricity will  be obtained  from outside sources,  and
sufficient steam  will be  generated by the Lurgi process.   Thus,  there  will
not be  any major flue gas sources  besides the stack  in  the processed  shale
discharge system.   Since the retort gas is prepared for selling purposes, its
cleanup does  not qualify as pollution control.  If the gas were being cleaned
for on-site  use,  the cleaning  process  would have qualified  as  a pollution
control  measure.   Nonetheless,  any  treatment  of  the  tail  streams  before
discharge into the environment is considered as pollution control.
                                     36

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     Another  unusual  feature  of  this  study  is that  it assumes  full-scale
 development  of  the  open  pit,  with  this  operation  occurring  during  the
 30 years  prior  to the starting point  of this  analysis.  In  such  a case,  the
 currett  plant will  be the second oil shale processing facility and many  of
 the  pollution   controls  and  other  equipment,   such  as   baghouses,  dust
 suppression  system,   water  management  system,  storage  tanks,  etc.,  will
 already  be  in place.  For the economic  analysis, however, this  study assumes
 that all  pollution control measures are newly  installed during the start-up
 period  for  the  second, or current, plant.  Furthermore,  the  wastes generated
 during  the  initial  30  years  have  already  been  disposed  of  on  a  remote
 location, and the environmental  and cost issues associated with the off-size
 disposal  are not  addressed,

 2.2.2  Pollution  Control Case Study

     A  block flow diagram  for  the  basic  processing  and  pollution control
 system  for  the  case study  analyzed  in  this manual  is  presented in  Figure
 2.2-1.    The  pollution control  areas are highlighted  in the diagram by  heavy
 lines.   A brief overview of the entire process follows.

     Mining  of  the  oil   shale  is  performed  by  the  open  pit  method.   Tne
 fugitive  dust  generated during  this  operation is  controlled with water and
 foam sprays.  The run-of-mine  oil  shale, subore, and overburden are crushed
 to a size of 6  to 8  inches in individual crushers  located in the pit itself.
 The crushing  operation als'o  generates  particulates  which  are controlled  by
 baghouses installed  on the crushers.   The crushed  subore and overburden are
 sent for  disposal  in the back of the pit, while the-oil  shale is transported
 to the  surface  using .enclosed conveyors.  These conveyors  are equipped with
 baghouses and dust suppression  devices  to control  the particulates generated
 at transfer points.  The diesel-powered machinery used  in mining ard disposal
 activities  is  equipped  with  catalytic converters  to  control  the  carbon
 monoxide and unburned hydrocarbons in the exhaust gases.

     The  primary  crushed shale  is  further  reduced in  size  by secondary and
 tertiary  crushing and  then fed  to the retorts.   The  crushing,  screening>
 transporting, storage, and  feeding  operations  generate airborne particulates
wnid- are also controlled by baghouses.

     In  the  Lurgi' retorts,  the  raw shale  is  pyrolyzed  by mixing  it with a
portion  of   previously processed  hot  shale.    The  vaporized  oil  and  gas
products  from the  pyrolysis  are  sent to the oil and gas recovery section of
the plant,  while  the retorted  shale is sent  to   the  lift pipes  where the
 residual organic  matter  on  the  retorted  shale  is incinerated to generate the
heat necessary for retorting the  raw shale.   A  flue  gas is also produced as a
 result  of incineration.  As  mentioned previously,  a portion of the processed
 shale is  recycled to  the  retorts,  while the- remainder  is passed  along  with
the flue gas through the discharge system.

     In  the  discharge  system,  the  flue gas and  entrained  processed  shale
particles are separated  from each  other  via a series of cyclones,  waste  heat
recovery  system,  humidifier,  etc.   The  flue gas is  then passed  through  an
electrostatic precipitator  to   remove  the residual  particulates and  is

                                    37

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                                                                                                                                         FLUE GAS
CD
                                                                     * SEE DISCUSSION IN SEC 3 3-10
        SOURCE  Wl  tesertonBtilf Oil Corp end Slumlord Oil Co [Imfisoai
                Morch 1976, and RioBlonco Oil Shole Cn.Feirtwrj 1981
                                                                                                                                                            POXES WITH HEAVY LINES WOiC*Tt
                                                                                                                                                            PfflXUTION COMIROL ftCtlVlriES
                                                           FIGURE 2 e-1   PROCESS FLOW OttOBAM

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eventually  vented  to  the atmosphere.   The processed  shale separated  along
these  steps is  sent  to  the  processed shale  mixer for quenching and  proper
moisturizing before final disposal.

     In  the  oil  and  gas  recovery   unit,  the  products  of  pyrolysis  are
separated   into   heavy,   middle  and   light  oils,  naphtha,  gas  liquor  and
noncordensable  ^etort  gas.   The oils  and naphtha are sent  for  storage,  while
tne  gas  Mquer  and  retort gas  are treated further.   Fugitive  hydrocarbons
emanate  from  the  product  storage and  these are controlled  primarily  by
employing floating roof storage tanks.

     The  retort gas is  cleaned for  the  purpose of selling it.   The gas  is
first  compressed to  remove  much of the moisture  and ammonia, then subjected
to  treatment  by  diethanolamine  and  triethylene  glycol,  which  remove  the
acidic   components  and  the  residual   moisture,   respectively,  from   the
compressed  gas.   The  clean,  dry gas  is  then  sent to the pipeline.   Since
these  are  processing  steps,   they  are not considered as  pollution control
measures.

     The acid gas obtained from the diethanoTamine  regeneration is treated  by
the Stretford process, which converts  the H2S in the gas to  elemental sulfur.
The  clean  gas is  then  vented  to  the atmosphere.    Since  a  direct release  of
the  acid  gas   (before  treatment  by  the  Stretford process)  would create
portion,  the  acid  gas treatment is considered a pollution control  measure.

     The gas  liquor from the  oil  and gas  recovery section is subjected  to
o""/water  separation,  but  it still  contains  dissolved  ammonia  ar>d sulfur
compounds _ and   its  direct  discharge  :or  use may -also   create  pollution.
Therefore,,  the  ammonia  and  dissolved volatile compounds  from  the liquor are
removed by  an  ammonia  recovery process.  The treated water is then  used for
processed shale  moisturizing.

     Dewatering  of the  two  aquifers under Tract C-a is necessary in  order  to
keep the pit  dry.   The water thus obtained is  used to satisfy the processing
require
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The  mine water  is  also u&ed for  dast,-co.rrtJ*Ql»  revegetation,  sanitary .uses,
and  as service and fire water.

     Proper   maintenance  practices   are   used  to   reduce   the  fugitive
hydrocarbons emanating from valves, pumps, etc.

2.3  SUMMARY OF  POLLUTION CONTROL  TECHNOLOGIES AND COST

     The  control technologies  examined  in the  case  study are summarized in
Table 2.3-1.  As a means of organizing the presentation, the plant complex is
divided  into  different  areas  of processing activities and pollution control.
It  should be noted  that the  control technologies examined  here  are not the
only  choices available,  nor  are  they  necessarily sufficient  for pollution
control;  rather, they are merely examples from broad classes of technologies.
These examples  have  been examined on the  basis  that  they have been proposed
at  one  time or  another by oil shale developers.   Additionally,  good vendor
guarantees  and  cost data  on  these  technologies were  available  for  the
economic  analysis.

     Throughout  this  analysis  of  the Lurgi-Open Pit project, the distinction
between process  and  pollution control  is not always clear.  For example, the
diethanolamine  treatment of the  retort gas could be considered  a pollution
control measure  because  it  affords removal of HgS.   However,  since the main
purpose behind  the  treatment  is to sell  the  gas and not  to use  it  on site,
the  treatment  is considered a  processing  step.   Similarly,  boiler feedwater
treatment,  cooling  water  treatment^ source  water clarification,  etc.,  are
listed as pollution control  measures,  when they  may  also  be classified as
process related activities.   In some such instances—for example,  the cooling
water  treatment—only  the  cost  increase  due  to  the  pollution  control
activities  is   included,  but  this  distinction  is  not  always  possible.
Consideration of  an  activity  as a pollution control  or as a process related
activity  becomes  important when  calculating the total  cost of  pollution
control.    Because  all   of  the  borderline  activities  are  classified  as
pollution  control,  the  user  of this manual  should  be made aware  that the
total pollution  control  costs  are conservatively stat«d due to the inclusion
of activities which could also be considered process related.

     Table 2.3-2  lists  the  control technologies examined  in the  case study,
along with  information  describing  location,  control function and size.  More
detailed  design  information for the technologies  is  presented in Section 5.
A discussion of other possible control  choices is also given in that section.

     Table 2.3-3  summarizes  the  costs  of  air  pollution control  and water
management  and  pollution  control  for  the  case study analyzed  for  the
Lurgi-Open  Pit  facility.   The costs  for  solid  waste  management are  not
included  in  the table  because  of  insufficient  information   regarding  the
developer's plans for solid waste disposal.  Detailed  engineering costs for
the  technologies  analyzed and  the cost computation methodology are presented
in Section 6.
                                     40

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                                 TABLE 2.3-1.   SUMMARY OF POLLUTION CONTROL TECHNOLOGIES
	 ' ' 	 	 - •
Areas of Control
Mining, Crushing and
Materials Handling
Baghouses
Water and Foam
Sprays
Retorting
Treatment
Electrostatic
Precipitator
for Flue Gas
Retort Gas
Treatment
Stretford for
the Acid Gases
from DEA Unit
Mine Water Gas Liquor
Treatment Treatment
Aerated Pond Ammonia
Recovery
Process
Steam, Power
Generation
Steam Generation
inherent to the
retorting process;
no control necessary
Solid Waste
Management
Open Pit
Backfilling
...... , „
Source:   ORI based on information from Gulf Oil  Corp.  and Standard Oil  Co.  (Indiana), March 1976, and Rio Blanco Oil
         Shale Co.,  February 1981.

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                                                   TABLE 2.3-2.  INVENTORY OF MAJOR POLLUTION CONTROL TECHNOLOGIES
ISJ
Type of Control
(Number of Units)
Water and Foani Sprays
Fabric niter (2)
Fabric Filter (1)
Fabric Filter (1)
Fabric Filter (2)
Fabric Filter (3)
Fabric Filter (2)
Fabric Filter (8)
Fabric Filter (2)
Fabric Filter (8)
Fabric Filter (2)
Fabric Filter (9)
Fabric Filter (4)
Fabric Filter (9)
Fabric Filter (2)
Fabric Filter (1)
Fabric Filter (2)
Fabric Filter (4)
Fabric Filter (13)
Electrostatic
Prec1p1tator (13)
Fabric Filter (2)
fabric Filter (3)
Origin of Material Controlled
Hlne, Open Stockpiles
Primary Crushers (ore)
Primary Crushers (subore)
Primary Crushers (overburden)
Conveyor to Stockpile
Raw Shale Conveyor Transfer
Points
Conveyor to Secondary Crushers
Secondary Crushers
Conveyor to Secondary Screens
Secondary Screens
Conveyor to Tertiary Crushers
Tertiary Crushers
Conveyor to Tertiary Screens
Tertiary Screens, Both Sets
Conveyor to Fine Ore Storage
Fine Ore Storage
Conveyor to Retort Feed Hoppers
Retort Feed Hoppers
Conveyor to Retorts
Flue Gas Discharge System
Processed Shale Conveyor
Transfer Points
Processed Shale Load-out
Hoppers
Material Controlled
Raw and Processed Shale Dust
flaw Shale Dust
Subore Shalp Dust
Overburden Dust
Raw Shale Oust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dwst
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Raw Shale Dust
Processed Shale Dust
Processed Shale Dust
Processed Shale Dust
Flow Rate
Each Unit
..
61,100 ACFM
12,200 ACFM
63,800 ACFM
36,300 ACFM
40,500 ACFM
20,200 ACFH
69,800 ACFH
20,200 ACFH
69,800 ACFH
20,200 ACFM
69,800 ACFM
20,200 ACFH
69,800 ACFM
20,200 ACFM
2B,BOO ACFM
20,200 ACFM
53,100 ACtM
18,400 ACFM
293,700 ACFM
32,300 ACFM
21,500 ACFM
Processing
Activity Area
Mining, etc
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Mining, ate.
Mining, etc.
Mining, etc.
Mining, etc
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Mining, etc.
Processed Shale Removal
(pyrolysis)
Processed Shale Disposal
Processed Shale Disposal
                                                                                                                                     (Continued)

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                                                              TABiE 2.3-2  (font.)
Typ® of Control
(Number of Units)
Stretford (1)
(hi/Water Separator (1)
Ammonia Recovery (1)
Mine Water Clartfler (1)*
Aeration Pond (1)
Floating 8oof Storage
Tanks 11)
Ammonia Storage Tank (1)
Catalytic Converters
Proper Maintenance of
•** Valves • Pumps, etc.
Boiler Feedwater Treatment*
Cooling Water Treatment*
"Equalization Pond
Oil/Water Separator
Origin of Material Controlled
DEA Unft
Lurgi Product Recovery
Oil /Water Separator
Underground Aquifers
Mine Water Clartfier
Lurgi Product Storage
Ammonia Recovery Unit
Diesel Equipment
Valves, Pumps, etc
Mine Water
Mine Water
Water Treatments
Plant Sit* Storm Sewer
Material Controlled
H*S
Oil Emulsion 111 Water
H2S, NH-, and Volatile
Organic? in Water
Suspended Matter
Dissolved Organlcs
Hydrocarbons
Araraoni a
CO, HC
Hydrocarbons
Dissolved Solids
Dissolved Solids
Slowdowns, Runoff,
Concentrates, etc.
Plant Runoff
flow Rate
Carli Unit
10,500 ACI"M
586 gpm
586 gpm
16,500 gpn
8,330 gpw
63,140 BPSD
22 6 TPSD
—
~-
43 gpm
2,676 gpm
2,525 gpm
J69 gpm
Processing
Act jvi ty A* ea
Retort Gas Treatment
Gas Liquor Ireatraent
Gas Liquor Treatment
Mine Water Treatment
Excess Hine Water
Treatment
Miscellaneous Air
Treatment
Miscellaneous Air
Treatment
Miscellaneous Air
Treatment
Miscellaneous Air
Treatment
Miscellaneous Water
Treatment
Miscellaneous Water
Treatment
Miscellaneous Water
Treatment
Miscellaneous Water
Treatment
ftunoff Collection Sumps
Runoff Collection 1>umps
Dust Suppression
Grubbing, Stripping,
  and Clearing
Reclamation and
  Revegetation
Waste Landfill
Runoff Collection Sumps
Waste Landfill
Waste Landfill
Waste Landfill
teachable Compounds
Leached Compounds
Partitulates
Soil (erosion)

bail (erosion)
Surface Hydrology
Surface Hydrology
Surface Stabilization
Surface Stabilization

Surface Stabilization
* The technologies marked with an asterisk (*) could be considered part of the process as well as pollution control
Source   OKI based on information from Gulf Oil Corp  and Standard Oil  Co  (Indiana), March 1976, and Rio Blanco Oil Shale Co , February 1981

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                              TABLE 2.3-3.   POLLUTION CONTROL COST SUMMARY*

Control Medium
Air Pollution
Water Management and
Pollution Control
Solid Waste Management
Fixed
Capital Cost
($000 's)
91,042
7,122
N.O.
Total Annual
Capital Charge
($000' s)
14,747
1,412
N.D.
Total Annual
Operating Cost
($000 's)
9,013
2,446
N.D.
Total Annual
Control Cost
($000 's)
23,760
3,858
N.D.
Per-barrel
Control Cost
(cents)
115
19
N.O.

  See Section 6 for details.

  The solid waste management  costs  have not been determined (N.D.) in an integrated fashion.
  See Section 6 for details on individual  solid waste management items.

Source:   DRI.

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                                  SECTION 3

                    PROCESS FLOW DIAGRAMS AND FLOW RATES
     Flow  diagrams  illustrating all  operations in  the  Lurgi-Open Pit plant
complex  are presented  in  this  section.  The  integrated designs  shown are
consistent with proposed development plans.

3.1  STRUCTURE OF THE DIAGRAMS

     In order to understand the interactions throughout the plant complex, an
overall f'ow diagram  is presented first,  followed by  flow diagrams for each
unit  process.    Flow  rates  for  all  major  process and  waste streams  are
indicated on each of the more detailed diagrams; flow rates for streams cf an
auxiliary  nature,  such  as  cooling  water  and  steam, are  included only when
relevant to pollution control  activities.   The following symbols are used to
indicate the physical  state of each stream:

     «    Gases—Circles
     •    Liquids—Squares

     »    Solids—Hexagons.             ;

     A  unique  stream  number  is  placed within each  symbol.   In addition,  an
asterisK {*) is  placed  next to  the symbol  for  a  stream  if it  comes  into
contact  with   the  environment  at  any  point  in  the process.   The  stream
numbering system established  in  this section is used throughout this manual.

3.2  OVERALL PLANT COMPLEX

     A  flow diagram  of the  complete plant  complex,  emphasizing  the  waste
streams produced,  is  presented in Figure  3.2-1.  Production-scale  mining  of
the oil shale  will  be accomplished utilizing the concept of a migrating open
pit.    Initial  excavation  will  have  begun  in the northwest  quadrant  of
Tract C-a (see Figure 2.1-2) and  continued for 30 years.   The waste material
produced during  these years will  have been removed to an  off-site disposal
ares.   After the 30-year  development,  the  pit would  be sufficiently la^ge  to
accommodate the  simultaneous  waste  backfilling  and  mining  operations.   The
Lurg^-Open  Pit case study  examines  activities that  occur  after simultaneous
Backfilling and mining operations commence.

     The pit boundaries  at the end of the 20-year project life (following the
initial 30 years) will  extend  south  across Corral  Gulch  and east to near the
confluence of Dry Fork  and Corral  Gulch.  The working pit will have a depth
of approximately 1,350 feet and a. diameter  of 7,900 feet  at the surface.   The •

                                     45

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 LIGHT OILS—-IK]

MIDDLE OILS

 HEAVY OILS •»
FUEL—
                                                                                                                                                                    I.TF5
                                                                                                                                                                    JxTOENERATQR
                                                                                                                                                        DEA *M1NE
                                                                                                                                                          TRIETHfLtNE
                                                                                                                                                          61YCOL ORWNS
      FiUE(
      GAS
                       LURGI-RUHRSAS

                        RETOBTtHG
                   FLUE GAS DISCHARGE
                   (ELECTROSTATIC
                        PRECIPITATORI
              HAWf
            SHALE
                                                  PROCESSED SKALE
                                                  MOISTENING WATER

"1
ADO BASES
4f«"
Y^AS
STBETFORD
SULFUR
RECOVERY
                                           BOILER FEEOWATEB
                                                       WASTE HEAT
                                    P~HOUSE  rffiK-lnu- BOILER BLOWDOWH
                                    pMISSIONS EMISSIONS
                         MINING
                            8
                        CRU SHIMS
                                                    ~H RAW SHALE
                                                        LEACHATE
                                                                                         ANHYDROUS
                                                                              STR.PPEO   'Mmm
                                                                              OAS LIOUOR
                                                                                                                                   AEftATEP POND SLUDGE
                                                                                    LIQUID
                                                                                   SULFUR
  WATER
MANAGEMENT
	 :,
t> i
MINE
WATER

DUST PALLIATIVES tsf 1




                 SLUDGE

                 	O
                                                                                                                                 EXCESS  MINE HATER
AERATION
  POND
                                                                                                                                                 TREATED WATER  .  ,
                                                                                                                                                 TO DISCHARGE   M
                                                                                                                                              LEGEND SEE TIOURE 33-1
        SOURCE  DRI Nosed on Gulf Oil Cerp end Sloidord Oil Co IIndianol,
                Morrt  igK, ami Rio Dlonco Oil 5hol! Co, rcbruorr  1931
                                                                                                                             BOXES WITH IIEAW LINES INDICATE
                                                                                                                             POLLUTION CONTROL ACTIVITIES
                                        FIGURE 32-1  PROCESS OPERATIONS AND WASTt STREAMS

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slope  of  the  pit wall  will  be  45°, which  will  be sufficient  to  avoid
subsidence.  The benches will be placed 50 feet apart.

     "he mined raw shale is first crushed in movable  primary crushers  located
ir  the  pit and then transferred to the surface by  covered conveyors.   Proper
retort  feed  is  then  prepared  by  secondary  and  tertiary  crushing  and
screening.  The  crushed shale is fed to  the  Lurgi retorts where  it is  mixed
wix.h  hot,   burned,  processed  shale,  raising  it  to  a  sufficent  temperature
(950-1f09C°F) to  release  a mixture of  oil and  high-Btu gas which moves to  a
recovery section of the plant.  After retorting, the  processed shale contains
a carboi  residue  which is burned in a  lift pipe, thereby further  raising the
temperature of  the processed  shale (1,200-1,3QO°F)  before  it  is mixed  with
tie  Incoming  raw  shale.   Part of  the  burned, processed  shale  that  is  not
recycled exits with  the flue gas and is  separated, quenched with water,  ancs
rois^ened to 19% water content before disposal.

     In the Lurgi  oil  recovery section of the plant, three oil fractions  and
5 high-Btu  gas are  recovered.   A gas  liquor, or  condensate,  with dissolved
ammonia  and organics  is   also  recovered  in  the  product  recovery  section.

     After the stripping of naphtha, the retort gas is compressed  and sent to
tt-e diethsnolanr'ne (DEA)  scrubbers  for  removal  of acid gases.   The clean  gas
is  subsequently dried  in  the triathylene glycol (TEG) dehydration system  and
sent to the pipeline.   The acid gas overhead from the amine absorption system
is  treated  in  a  Stretford unit to produce a sulfur by-product and a tail gas
whicn ~s released to'the atmosohere.

     The gas liquor is sent to the ammonia recovery unit to produce anhydrous
an""oria and then  the  stripped liquor is used for processed shale moistening.

     Sines the pit will intercept two underground water bodies,  the upper and
lower aquifers,  dewatering of the  mine will  be necessary  during the  active
life  of  the  project.  The  amount  of  mine  water  obtained by  dewatering,
hoveve", w'11  be  in  excess of that needed in the plant and this excess water
w-11  leec  to  be  discharged.   Aeration of  the excess  water to  oxidize the
organic material  and  to settle  out oxidizable  inorganic  compounds will  be
carried out prior to  the discharge,

     The  overall  processing  steps  outlined  above comprise  the  case  study
examined i<* this  manual.

3.3  UNIT PROCESS FLOW DIAGRAMS

     This section describes the operation of  the Lurgi-Gpen Pit plant complex
{r>  «icre  detail  using   flow  diagrams for  each unit  process  in  the  plant.
Figure 3.3-1 is  intended  to be used as a road map showing  the  relationship
between the unit process flow diagrams.   Each  box  (except the product storage
boxes)  in  the  figure  represents   an   individual   fTow  diagram,  and  the
appropriate figure number  for each  diagram  is indicated,   fill   streams are
numbered as we1!.   A  complete list of all  the  streams, in numerical order, is
included in Section 1.7t Table 1.7-1.
                                     47

-------
CO
            y
                                                                                 LEgrup

                                                                           O GASEOUS  STREAM

                                                                               LIQUID STREAM

                                                                               SOUD STREAM

                                                                           ^ SPLIT FLOW
                      -HUNTOW BETOHIIH6
                  «ND FLUt 6«S DISCHARGE
              KLECTROSTAIIC PBECIPIWOBI
          ®  ©I®  ©I® © © ®
          SOURCE 001  to'eil w full Oil Cwo  wfl Stomliwcl M Co (Indianol,
                 More* W6, OHO Wo Blomo OH Sd»l> Co, Fsbruor) I9B!
                                                                           FIGURE  33-1  OVERALL PUST COMPLEX

-------
      The  individual,  unit process  flow diagrams  are  presented throughout this
 section   (see  Figures 3.3-2  through  3.3-11);   also,  Figure 3.3-12  provides
 details on  the water  management  system for  the entire  plant complex.   In each
 diagram,  streams  enter on the left  and exit  on  the  right,  and mass flows are
 given  at  the bottom.   Composition  data on major  process  and waste  streams can
 be  found  in Section 4.

 3.3.1  Mining, Crushing and Transport  of Raw  Shale

     A flow diagram illustrating mining and crushing processes for  the  Lurgi-
 Opsn Pit  oil shale complex is presented in  Figure 3.3-2.

     Run-of-mine  oil  shale, overburden,  and subore will be reduced to  6  to
 8 inches  in size  in  separate 72-inch  gyratory  crushers located in the  pit.
 These  primary  crushers will  have the  capability of  being moved  as the pit
 migrates.   Airborne  particulate matter from  the primary crushing  operations
 will  be controlled with baghouses and  the  uncontrolled  particulates will  be
 emitted to  the  atmosphere (streams 5,  6 and  7).   The  baghouse dust collected
 from  the  overburden  and subore crushing operations will be  combined with the
 crushed materials,  while the  shale dust (stream 22)  will  be added into the
 feed  to  the Lurgi-Ruhrgas  retorts.   The primary crushed shale will  be  con-
 veyed  to  the coarse  ore stockpile  located on  the  surface and subsequently
 reduced in  size by secondary and tertiary crushing.   All crushing,  screening,
 and  transfer  operations  will  use  baghouses  to   control   dust   emissions.
 Fugitive  dust  associated  with  the  mining and  crushing operations  will  be
 controlled  with water  sprays  arid  other dust palliatives  (stream 90).  The
 f-Jne crashed shale will be stockpiled in an -enclosed storage bin and conveyed
 to  the retort  feed 'hopper.   The 'airborne particulates from the storage  bin,
 conveyor ,j and feed:hopper will  be, controlled with baghouses and then emitted
 to  ihe atmosphere  (streams  19, 20 and 21,  respectively).  Individual convey-
 ors wfll  than  transport  the  shale  from the  feed hopper to  each  of  the re-
 torts.   Fugitive  dust  from these conveyors will   also  be  controlled with
 baghouses.  (Alternately, the shale can be distributed to the  retorts direct-
 ly  from jthe storage  bin.   In such  a case, the feed  hopper depicted in the
 figure- would nat be included;  therefore, stream 21 would not exist.  Instead,
 each  retort would use  an individual feed hopper, which would be  controlled
 with  the  baghouse 'installed on  :the ffied conveyor.)   The crushed  overburden
 and subore  (streams 2 and 3)  and processed shale (stream 29)  will  be trans-
 ferred by covered  conveyor  to  150- ton truck load-out hoppers for redistribu-
 tion ih'tfie back* of the pft.

     DUe  to the  interruption  of  the  existing  aquifers during development
 of  the pit, a  considerable  amount  of  water  will need  to  be  pumped  through
 the dewaten'ng  wells.   Shown  as  stream 4  on the flow  diagram,  this  water
will be sent to the water management system (see  Section  3,3.10) for clarifi-
cation  and  subsequent treatment  before  being   used  throughout   the  plant
     leachate  from  th«  raw shale pile,  if present,  and storm  runoff  will
oe  pumped  to  an  oil /water  separator and then  used  for  processed  shale
moisturizing.   The  vari-ous  mining  and   disposal   equipment  (e.g.,   power
shovels,  trucks,  crushers)  operates  on  diesel  fuel.  The  exhaust  gases


                                     43

-------
O
            TER, DUST     \_Ba
             LIATIVES      /~Wt
FROM FI6 33-11


DIESEL FUEL MINE

EQUIPMENT
                                                                                                                                                                TO FI6 3 3-11
                                                                                                                                                            J-J MINE WATER    ^>
                            PRIMARY CRUSHING
                                                                       FOR LEGEND SEE  FIGURE  3 3-1
                                                                                                                                                               TO FI6 3.3-11
                                                                                                                                                                          SCHATO
STREAM NO
STREAM
IDENTITY
FLOW ID3 ACFM
RATE I03 lo/ln
TEMP, °F
PRESSURE, psig
CD*
RAW
SHALE
FEED
9799
AMB
AMB
of
SUB-
ORE
992




(J)
OVER
BUROCf
5175




00*
MINE
WATER





©|® |<2f ®*


1222
157
Ib/tic





122
16





638
82





72 E
04




(D*
®*
BASBOUSE
1215
15.6




404
02




®*
©*
EMISSION
5584
719




404
02




©*j@*F@*


5584
719


__

404
02





eza-t
80.8

. —

(£)


808
04

	

(II)'


6282
808




OS)


404
02




(«)'


286
17




(zg)'
^!)'


404
02





2124
27.3




1?)"
8AG-
IOUSE
DUSTS
MB 1




(21)'
BAG-
10USE
EMtSS
645
63
Ib/hr





-------
 (stream 24)  from  this  equipment will  be  controlled  through  the  use  of
 catalytic converters.

 3.3.2  Lurgl-Ruhrgas ftboveground Retortlng

     The   Lurgi-Ruhrgas   aboveground   retorting   process   is    shown   in
 Figure 3.3-3.   Raw  shale  (stream 1)  from  the  crushers and  collected dust
 (stream 22)  from  the  baghouses provide  the  feed  to  the  screw  nixer where
 pyrolysis occurs.  Vapors containing retort gases, oil mist, water vapor, and
 some processed  shale participates exit the screw mixer  and pass through two
 cyclones.  Processed  shale  participates are removed in  the cyclones and the
 vapors (stream 26) continue on to the oil recovery system.

     Processed  shale  exits  the  screw mixer  into  a  surge vessel  where  it
 combines  with  participates  captured  by  the  gas  stream  cyclones.   The
 processed shale  is then forced up a lift pipe by injection of preheated air
 (stream 25).   A portion of the retort gas (stream 35) is a necessary addition
 to the lift  pipe to sustain combustion of the residual organic matter on the
 processed shale.   Oily dust from the oil/dust centrifuge (stream A3) is also
 injected  into  the bottom of  the lift pipe.   Combustion  of residual organic
 matter on processed  shale particles  and oil from oily dust produce flue gas
 and hsat.

     The processed shale particles then enter a collecting bin which recycles
 a predetermined amount of hot processed shale into the screw mixer to provide
 Heat necessary  to raise the  raw shale  feed  to  pyrolysis  temperature.   The
 processed shale is mixed with raw shale in the screw mixer in a mass ratio of
 approximately 6:1 (Marnell,  September 1976;  Schmalfeld, July 1975).

     Hot flue gas and entrained processed shale particles exit the colj'eeting
 Din and  enter a  cyclone where most particulates are removed  and  fed  to  a
 processed shale  quencher/moisturizer.   The  flue gas then enters a waste heat
 recovery  boilar where  high pressure  steam  (stream 27)  is  produced through
 heat transfer to  the entering waste  heat boiler  feedwater  (stream  77).   The
 high pressure  steara is  utilized  as  the  prime mover  for  the  turbine-driven
compressors in the gas compression section (Figure 3.3-6).

     The  flue gas  continues through  another cyclone for  further  participate
 removal  and then enters a humidifier  and an  electrostatic precipitator and is
ventsd  to  the  atmosphere   as  stream 31.   Processed  shale  quenching  and
,110: starling  water  (stream 78)  enters   the   quencher/moisturizer where  the
p-ocessed  shale   is   cooled   to   below  2QO°F  and  is   wetted  to  contain
approximately  19%  water   by  weight.   The  moisturized   processed  shale
 (stream 29) is then  sent for  disposal.  The steam produced by  the  quenching
 operation is  added to  the  flue gas via the  humidifier.   This aids  in  the
electrostatic precipitation  of the particulates.

3,3.3  lurgi-Ryhygas011jtecovgry

     The Lurgi-Ryhrgas  oil  recovery  system, shown in Figure 3.3-4,  has three
 stages involving two-not oil  scrubbers and  one coel  water scrubber.   The oil .

-------
FROM FIGS3-9

STRETFORD
OXIDIZER
FROM FIG J3-4
PROCESSED SHALE
MOISTENING WATER .
FROM FIG 33-11
                                           ^MAMAAA^^AAA/VVWVVV\AA/V
                                            	aUENCHER/MOISTURIZa.	
                                                                                                                                               TO re 13-2,10
STREAM HO
STREAM
IDEMTITV
FLOW I03 ACFM
RATE ' ID3 »/hr
9(1"
TEMP, °F
PRESSURE, psig
CD*
RAW 1
SHALE
FEED

9799

AMB
AMB
(§)*
BAGHOUSE
DUSTS

ne i

AMB
AMB
©
COMBUSTION
AIR

5439

740
N 0
@>
RETORT
VAPORS

1425.?

950
AMB
©
HIGH
PRESSURE
STEAM

1060

475
550
m*
WASTE
HEAT
BOILER
aafflpwjL


21
N D
AMB
nr
PROCESSED
SHALE

9?33

ISO
AMB
®
STEAM TO
HUMIDIFIES

998

«0
H D
©*
FLUE
GAS
3820
72026

460
AMB
®*
RETORT
TEED.
BAGHOUSE
EMISSION
Z392
1 Sib/lit

AMB
6WB
©
RETCRTGAS
TO
LIFT PIPES

1070

90
AMB
(§1
OILY
OUST

706

ND
AMB
®
STRETFORD
OXIOI2ER
VENT GAS

243

N.O.
AM9
©
AMMONIA
OVERHE40
VAPORS

202

210
3
0
WA$TE»€W
BOILER
rEEOWATER


?I20
AMB
A«B
BT
PROCESSEO
SHALE
WISTENWS
WATER
^

S62
-------
recovery system primarily removes oil mists and water vapor  from  the  entering
retort vapors (stream 26).

     The first  oil  scrubber removes heavy oils and particulate material  from
the  gas  stream  but retains  water  in  the  vapor  phase   due  to  the  high
temperature  involved.   Gas  liquor,  which is obtained  in  the latter part  of
the  oil  recovery system,  is recycled to the  heavy  oil scrubber to  decrease
the  temperature  of  the  vapors through water  evaporation.   Dusty heavy  oils
ex't  at  the bottom of  the  scrubber  at  approximately 350°F  and  enter  a
centrifuge  for  dust/oil  separation.   A  small  stream of  light oils  is  a
necessary addition  to  the centrifugation process in order to thin the  highly
viscous   heavy   oils,   thereby  enabling   a  more   effective  separation.
Centrifugation can  be a  two-stage  process, coupled  with solids  drying  and
light oil stabilization  processes  (Rio  Blanco Oil Shale Co., February  1981).
Oily  dust  (stream  43)  recovered  through centrifugation  is  recycled to  the
Lurgi  retort  lift   pipe.   The dust-free heavy  oils  (stream  42)  recovered
through csntrifugation  are  pumped  to  storage.   Retort gas  exits  the first
scrubber  and passes through  a  cyclone  for  removal  of  oil  droplets   and
pa^ticj"!ates before entering the second oil scrubber for middle oils  removal.

     """he second oil  scrubber operates similar to the first, affording removal
of middle oils  from the retort gas.  This scrubber operates at a temperature
lower than  the  first, yet  above the dew point of the gas  so  that  moisture
condensation dees not occur; therefore,  the middle oils (stream 38) recovered
from this unit  are  free of water and may be pumped directly to storage.  Tne
operating temperature for the  scrubber  is about 150°f,  and  it  is controlled
with nwidified ,air coolers..

     The third .scrubber  operates   at  a  temperature'  low  enough  to  promote
condensation  of'  light  oil   vapors  and moisture.  This unit recirculates a
potion of the condensed  oil/water  mixture to aid in scrubbing of oil and to
promote  removal  of ammonia.   The  exit  temperature   of  this  scrubber  is
approximately  90°F.   Light  oils   (stream  36) and  gas  liquor  (stream 41)
condensed from this  scrubber undergo separation, with light oils being pumped
to storage  and  gas  liquor  continuing on  to  the ammonia recovery  unit (see
Section 3.3.8).    The  oil  storage   tanks  will  be   a  source   of   fugitive
hydrocarbon  emissions (stream 44).

3.3.4  Lurgj  Leani Oil Apsorber^and Naphtha Stripper

     The lean oil .absorber  and naphtha  stripper unit,  shown in  Figure 3.3-5,
fractionates   the retort  gas  (stream 34) after  oil   recovery  into  naphtha
(stream 46)   and  nbncondensable hydrocarbons  such as  Cj,'s,  C2' s and  C3's.
This unit is  used to absorb the naphtha  from  the  gas  into  a naphtha-free or
lean oil.   Noncondensable hydrocarbons  are  not absorbed in  the lean  oil  and
ex-'t the absorber overhead as naphtha-free retort gas  (stream 45)  for  further
clsanup and  use.   Natihtha  is then  stripped from the  naphtha-rich  oil  and
co'ncstised for collection and storage,  while  the stripped lean oil  is  recycled
to the absorber. .Makeup  lean  oil (stream 37)  is  obtained,  as required, from
1 light Oils grc-duced  in  th« oil  recovery  unit.
                                     53

-------
                           HEAVY OIL SCRUBBER
            ,	(g>_
FROM FIS 33-3
                                         y.
 COOLING
 WATER
J>	gj	j
                                                   MIDDLE OIL SCRUBBER
                                                                            LI CUT OIL SCRUBBER
                                                                           r





1
r.
i
0
N
~rn



<^A£_I




0
s
n
                                                                                         am
                                                                                  AIR
                                                       (GAS LIQUOR RECYCLE )
                                                                                                                                 OO      V
                                                                                                                                SLOWDOWS/
                                                                                                                                TOPIC 33-
                                                                                               OIL/WATER
                                                                                               SEPARATOR
cw
FROM FIG. 33-M
              FOR LEGEND SEE FIGURE 3 3- I
                                                                                                                                TO FIG 3 3-9
ICENTR1FUGE
! OIL/ DUST
SEPARATION
1

LIGHT OIL
STABILIZER
J
HEAVY
OILS
                                                                                                                                 TO STORAGE
                                                                                                                      •JOILY OUST
                                                                                                                       TO FIG  33-3
STREAM MO,
STREAM
IDFNTITY
FLOW IO'ACFM
RATE IQ3ib/l>r
qpm
TEMP., *F
PRESSURE, pslj
@
RETORT
VAPOR
MZ5Z
950
AMB -^

@
RAW
RETORT
GAS
738 8
150


@
RETORT
GAS
1490
90


©
RETORT
GAS
TO
LIFT PIPES
1070
90


S
LIGHT
OILS TO
STORAGE
185 2
106
90


S3
LIGHT OIL
MAKEUP TO
NAPHTHA
RECOVERY
N D
90


LH
MIDDLE
OILS TO
STORAGE
4113
937
ISO


in
DIESEL
FUEL
MINE
EQUIPMENT
N D
AMB


S
DIESEL
FUEL
DISPOSAL
BJU1PMENT
MO
AMB


G3
GAS
LIOUOR
29? T
586
90


m
HEAVY
OILS TO
STORAGE
1965
416
350


<§>
OILY
OUST
786
NO


@*
HC EMISS
FROM
STORAGE
TANKS
(includes
#47}
65 5 lb/W
AMB


@
COOLIHG
WATER
325
AMB


S*
rOOLEI?
SLOWDOWN
661
WD
«.AMB
SOURCE: DR1 bostt on Rio Blonco Oil Sbole Co,  February 1981
                                                                   FIGURE  3 3-4  OIL RECOVERY
                     )  ,

-------
in
                                                                                        V~\
                                                                                     I	fvv4 W  SEPARATOR

                                                                                  X^-J—O-XV  v
                                                                                 f      \   CW
                                                                                                                                jO,    I NAPHTHA-

                                                                                                                                •<&-f^ i iftEE GAS



                                                                                                                                       TO FIG 33-6
                                                                                                                                         NAPHTHA

                                                                                                                                         PRODUCT
                                                                                                                                        TO STORAGE
                                                                                                                                        STEAM CONOENSATE
                                                                                                                                        TO FIG 33-11
                                                                                                                           CW?—{eijj—»-
COOLING WATER
      FROMFI6 55-11
TO FI6 3,3*11
                         FOfl  LEGEND SEE FIGURE 33-1
STREAM NO,
STREAM
IDENTITY
FLOW I03 ACFM
HftTg' j
gpro
TEMP, »F
PRESSURE, pan
©
RETORT GAS
uao
90
AMB
S3
LIGHT OIL
MAKEUP
ND
90
AMB
©
NAPHTHA-FREE
GAS
121 7
AMB
AM 8
H
NAPHTHA
PRODUCT TO
STORAGE
27 3
AMB
NO
©'
HCEMISSiOHS
FROM NAPHTHA
STORAGE
(included
in *44)
N 0
AMB
AMB
@
L P,
STEAM
10
275
60
H
COOLING
WATER
5
AMB
AMB
[i]
STEAM
CONDENSATE
20
NO
AMB
SOURCE^ GUI based cm rtio HloncoOil Sholc Co.,
                                           FIGURE 3 3-5  NAPHTHA RECOVERY

-------
3.3.5   Retort Sas  Conyression  and Cool1ng .

     Figure 3,3-6   shows   a flow  diagram for  retort  xjas  compression  and
cooling.   This  operation  consists of  three-stage  compression of the retort
gas  from  ambient  pressure  to about  1»000 psig.   This step  also  serves to
eliminate  a  considerable amount  of moisture  and ammonia from  the retort gas.

     The naphtha-free retort gas  (stream  45)  from the  naphtha  stripper enters
the  first  of four flash drums.   This  flash drum operates  at ambient pressure
and  also  receives the  compressed condensate  streams  from  the  other three
drums.   The  dissolved gases in the compressed condensates  are flashed in the
first  drum and  combined with  the retort  gas.  The condensate (stream 49) is
recovered  at the bottom and  sent  to the ammonia  recovery unit  (Section 3.3.8)
along with the gas liquor.   The combined  gas  stream from the first flash drum
then  enters the   first  stage  of compression.   The compressor  discharge is
water cooled and fed to the  second flash  drum, then to the  second compression
stage,  and so  on.   Eventually,   the  compressed retort gas  (stream  48)  is
obtained   from   the  last   of  the^  flash  drums  and  transported  to  the
diethanolamine  (DEA)  absorber for the  removal  of acid  gases  (Figure 3.3-7).

     The compressors  are  driven  by steam turbines  using high pressure steam
(stream 27) from the  waste  heat  boiler.   The turbines  are  of a noncondensing
type, discharging  low pressure steam  (streams 50, 51, 52  and 53) to be used
in other plant operations.

3.3.6  Amine Treatment/Triethylene Glycol  Dehydration

     The amine  treatment  and  dehydration for the  compressed retort gas are
shown  in Figure 3.3-7.   The compressed  naphtha-free  gas  (stream 48)  enters
the  gas  treating  column   and   is   scrubbed   with   30%  by   weight  DEA
(diethanolamine/water  solution)   to  remove  H2S.   The C02 level  in the gas
stream  is  also  reduced  to a low  level  by the amine solution.  The rich amine
solution  leaving  the absorber   is  regenerated  by  steam  stripping,  which
produces the  acid  gases  (stream 58)  from the top of  the  amine  regenerator.
This  stream  is  sent to  the  Stretford  unit where  the hydrogen  sulfide  is
converted  and  recovered  as elemental  sulfur.    The   retort  gas  (stream 56)
emerging from the  top of the DEA  absorber  is  virtually  free of acid gases and
enters  the triethylene  glycol  (TEG)  dehydrating system.   The retort  gas is
scrubbed with  the  glycol,  which  picks up the residual  moisture  in  the gas.
The dry  gas  (stream 57)  is  sent  to the pipeline, and the glycol  solution is
regenerated  by   steam stripping   and   then   recycled.    The TEG  regenerator
overhead vapor (stream 60),  containing mostly steam with  a slight  amount of
glycol, is emitted to the atmosphere.

3.3.7  Stretford Sulfur Process

     A flow diagram for the  Stretford process is shown  in Figure 3.3-8.  This
process  affords  simultaneous  removal  and recovery of hydrogen  sulfide from
the gaseous feeds  containing low amounts  of  H2S.  High  concentrations  of H2S
as well as C02 are detrimental  to the efficiency of the  process.
                                     56

-------
                                                                  — COMPRESSOR        
L P STEAM TO
STRETFOHD
UNIT
1

275
60
@
L f STEAM TO
AMMONIA
RECOVERY
53

275
60
	 - -i
B
COOLING
WATER

8
AMD
1MB
.. 	 __ 	 _ 	
SOURCt' DRI  based on (nfornialioii provided by SWEC
                                    FIGURE 3 3-6  RETORT GAS COMPRESSION AND COOLING

-------
                                            .WINE ABSORBER SYSTEM
tn
OJ
                                                                                           TRIETHYLENt 6LYCOL DIIYIN6 SYSTEM



                                                                                                   HEAT EXCHANGER
         NAPIITHF\   ,-.
         FI1EE GAS      V448)—«-
         (COMPRESSED!/   ^
        FROM FIG J3-6
                                    FOR LEGEND SEE FIGURE 3,3-f
                                                                                                              FLASH  FILTER
                                                                                                               TANK
TO FI6 3 3-11
STREAM MO
STflEAM
IDENTITY
FLOW I03«CFM
RATE 103 lli/tir
gpm
TEMP,"F
PRESSURE, psig
©
KAPHTHA-
FREE 6AS
(COMPHESStDl

1180

AMB
1000
(a)
LP
STEAM

130

275
60
Lm
AMINE
MAKEUP

HO

AMD
AMB
@
TEG
MAKEUP

ND

AMB
AMB
®
SWEET
CAS

619

N D
1000
©
ORIEO FUEL
GAS TO PIPE! i*

£1 8

AMB
NO
(SS)
ACID
GASES
105
571

105
AMB
@*
SPENT
AMIN£

NO

HO
AMB
©*
TEG
REGENERATION
VENT EMISSION

«a

4MB
AMB
|5ij
COOLINS
WATER


C6
AMB
AMB
0
STEAM
CONDENSATE


260
«D
AMB
         SOURCE  t)RI  bosed (ininforiiKilionpiBVitfjiJ by SWEC
                                                                 FIGURE  33-7  DiETtWMOLAMtlC/TRIETIIVLENE GLYCOL TREATMENT

-------
to
      FROM FIG. 3 3-11
      LOW PRESSURES^    &&
      STEAM      /	w
                                                                                                                                           COOLER
                                                                                                                                           SLOWDOWN
                                                                                                                                           TO FIG 33-1
                                                                                                                      SULFUR
                                                                                                                    SEPARATION
                                                                                                                        a
                                                                                                                     FILTRATION
                                                                                                                                           TO FIG 33-3
           FIG 13-6
                                    FOR  LEGEND SEE  FIGURE 33-i
                                                                                                                                           TO FIG, 3.3-1
STREAM MO
STREAM '
lOEHTlTf "
FLO* 103 ACEM
RAT€. I08 ll)/hr
gpm
tlMP^F
PtH^^^liftl^ nsln

H_M__
LP
STgAM
1
t?9
fin

- @)
AGIO GASES
FROM DEA
105
571
105
Atttf _

©
STRiPPINO
AIR
20.9
AMD


H
STRETFORD
CHEMICALS
0.03
AM 8


©"
STRETFORD
TREATEO
ACIO GASB
90
53 0
95


@ -
OXWIZEB
VENT
GAS
60
243
NO


...i-.fi, iL.
m
SPENT
LIQUOR TO
RECLAIM
N D
/ 95


HI
LIOUlp
SULFUR
PRODUCT
0,7
(76LTPSB
?60


®
STEAM
COHOENSATE
Z
ND


@
COOLING
WATER
MAKEUP
2
AMB


(gj
PROCESS
WATER
MAKEUP
3
AMB

*
(3*
COOLER
SLOWDOWN
661
N D


     SOURCE' DRI based on Peaiwdy Process Systems, Inc., Februory  1981


                                                        FIGURE  3 3-8 STRETCORO SULFUf? RECOVERY

-------
     The-Stratford process consists of HgS absorption, solution regeneration
and  sulfur recovery systems.  The Stretford  solution  consists  of a buffered
solution  of  sodium  carbonates,  anthraquirwne  disulfonic  acid  (ADA),  and
sodium  vanadate  which,  in  effect,  oxidize  H2S  to  elemental   sulfur.   The
resctants  are  regenerated by  stripping and  oxidizing  with  air,  then  are
recycled.

     The  acid  gases  from the  amine regenerator  (stream 58)  are introduced
into  the  absorber  through   venturi  inlets  under the  solution  level.   By
reacting with vanadate in the presence of ADA* H2S is converted to elemental
sulfur, which then floats to the  surface and is skimmed off in the oxidizer.
After  filtering  and  melting,  the sulfur  product (stream 66)  is  taken  to
storage.   The treated acid gases  (stream 63) are  released  to  the atmosphere
without further treatment.

     Stripping  air is purged through the Stretford solution  in the oxidizer
tank to  regenerate the ADA.   The  oxidizer vent gas, containing the stripping
air  with  some  desorbed  materials (stream 64),  is then used as a combustion
air  source for the lift pipes.   The  regenerated  solution is recycled to the
absorbers.    Some  nonregenerable compounds  like  thiosulfates form during the
solution regeneration.   These are removed periodically as part of the spent
liquor (stream 65), which  is  sent  for reclaim.

3.3.8  Aasconia Recovery Process

     A schematic  flow diagram for  an ammonia recovery process is presented in
Figure 3.3-9.   This unit  treats  combined ammoniacal  gas  liquors (streams 41
and  49)  from  the oil recovery and gas  compression  units,  respectively,  for
recovery of anhydrous ammonia.            -  -

     The ammonia  recovery process illustrated consists of  a water stripper,
an  ammonia absorber,  an  ammonia stripper,  and  an ammonia concentrator  or
boiler.   The  gas  liquor feed  is introduced to the water stripper in which the
dissolved  ammonia and other  volatile matter are  evolved by steam stripping
the water.   Sodium hydroxide  may be added to the aqueous charge to facilitate
release  of   fixed  ammonia.    The  stripped  water .(stream  70)  is  used  in
processed shale moisturizing.

     In the  ammonia  absorber,  the ammonia released  from the  gas  liquor is
absorbed out  of  the  vapor phase in a phosphoric  acid  solution.   A solution
stoichiometry  between  monoammonium phosphate  and  diammonium  phosphate  is
maintained for efficient absorption of ammonia.   Unabsorbed gases such as H2S
and  C02   continue  on,   as   the  ammonia  recovery   unit   overhead  vapors
(stream 72), to the Lurgi retort lift pipes for incineration of H2S.

     Desorption of the  ammonia from the  ammonium phosphate solution takes
place in  the ammonia  stripper section.  Both  temperature  and  pressure  are
increased and steam is passed through the  solution.   An  aqueous solution of
10-20% ammonia  is condensed  overhead,  while the stripped or lean solution is
recycled to the absorption section.  Ammonia is then obtained in an anhydrous
state (stream 71)  in  the  distillation section by steam stripping the aqueous
ammonia solution and fractionating the vapors.

                                     60

-------
                                         (PMOSAM-W  PROCESS  ILLUSTRATED)
ILOWPHtSSURC
 STEAM
 FROM F1633-4

STREAM NO
STREAM
. IDENTITY
FLOW I03 A6FM
RATE • I03 H/hr
flpm
TEMP, "F
PRESSURE, psiQ
BD
GAS
LIQUOR
2977
see
90
AMB
E3
COMPRESSOR
COHOENSATE
38
8
NO
NO
<§>
LOW PRESSURE
STEAM
53
275
60
@
PHOSPHORIC
fiCID ,
001
4U6
1MB
$1
CAUSTIC
(MoOHl
03
AMB
&MB
P
STEAM
CONDENSATE
106
NO
4MB
®*
STRIPPED
GAS LIQUOR
279 7
558
180
6
E]
ANHYDROUS
AMMONIA
STORAGE
19
226TPSO
NO
NO
®
AMMONIA
OVERHEAD
VAPORS
76
202
210
3
@
COOLING
WATER
ioao
AMB
AMB
-II
SOURCE  DRI
                  on  U5S  Engineers ant Consultants,  Inc, April 1978
                                                         FIGURE 3 3-9  AMMONIft RECOVERY

-------
3-3.9   Sol id Waste Pisposal

     figure 3.3-10 presents  a conceptual design for solid waste disposal via
backfilling the open pit.  This disposal approach, which was mentioned in the
original   OOP   for  tract C-&,  was  to   commence   after   30 years  of  pit
development, but details were  not presented.

     The  subgrade  ore,  overburden,  an-d processed shale (streams 2, 3 and 29)
constitute the majority of the wastes.  Several wastewaters, such as stripped
liquor  (stream 70),   cooling  tower  blowdown  (stream 105),  boiler blowdown
(stream 28), boiler  feedwater treatment concentrate (stream 104), mine water
clarifier  sludge  (stream  96),  storm runoff (stream 93), and service and fire
water  (stream 95),  are  used  to moisturize  the  processed  shale  to a  19%
moisture  content  before  disposal.   The  water  management  diagrams  (see
Figures 3.3-11  and  3.3-12)  indicate the  makeup  of the  moisturizing water
(stream 78).

     The waste transfer to the pit will  be carried out in two phases.  First,
the  waste material  from  the processing facility will be  transported to the
site using  covered  conveyors.   Then, it will be  loaded  into 150-ton trucks
and hauled into the pit.  The backfilling operation will begin at the back of
the  pit,  away from  the mining operation.   The pile will  be constructed in
25-foot benches at 50-foot vertical  intervals, using a slope of 2:1 (2 units
horizontal: 1 unit vertical).  The runoff will be collected (during the back-
filling operation only) using runoff collection sumps located at the junction
of  the  pile  and  the  pit  walls.   As  the  pile  reaches  surface  level,
revegetation of the area will be carried out.

     Transport  of  the  processed  shale  to  the-  pit  will  generate  some
participate emissions at  the conveyor transfer points (stream 73) and at the
load-out hoppers (stream 23).  These emissions are controlled with baghouses.
The backfilling operation will also create fugitive dust (stream 74) which is
controlled by the  use  of dust palliatives (stream 90).   The diesel fuel  used
to operate  the  disposal equipment will   create  diesel  emissions  (stream 24).

3.3.10  Water Management
     1 !
      The  water  management  plan   for  the  Lurgi-Open Pit  plant  complex  is
presented  in  Figures 3.3-11  and  3.3-12.   Groundwater  (stream 4) collected
from  the mine  dewatering  operation  is  clarified prior  to use  or further
treatment,  A portion of the clarified mine water  is used as sanitary/potable
water  (stream  99),  fire and service water  (stream 95),  process makeup water
(stream 87),  etc.,  while  the  remainder  is  aerated  and  then  discharged
(stream 76).  Before  use  in the cooling tower  (stream 86),  water  is treated
to  retard biological  growth and  minimize  scaling.   Treated process  waters
from the plant, blowdowns, and concentrates are recycled to appropriate uses.
The  equalization  pond serves  as  a  source  of  water  for processed  shale
moistening   (stream 78).    Sanitary  wastes   are   treated   by   conventional
biological processes;  the water (stream 102) is then used for processed shale
moisturizing and the sludge (stream 103) is used in revegetation.
                                     62

-------
 WENT ABIMC  \	[5|—
  SSJBORE


FROM FIG 33-2
 FROM FIG 3,1-11
f*MJJ»TIVE
W4TER
FBOMFIO 1J-II
\—@£—-
                    FOR LEGEND SIE FIGURE  3 3-1
SWAI* Ntt
smcAft
IDENTtTV
FLOW RATE to3Acm
10%/ltf
9P«i
TEMP, "F
PRESS , psifl
(5)*
SUBORE
992
AUB
AMB
$*
OVEROIHDEN
SITS
AMB


@s*
BSCHOUSE
EMISSION
645
8 3 Ib/hf
AMB


(^*
DIESEL
EMISSIONS
151 3
Nil


@*
PROCESSED
SHALE
9733
^_i5S__i


~s
OIE5EL
FUEL
MINE EQUIP
ND
4MB


@
BIESEL
FUEL
DISP tQUIP
N a
AM8


ii*
SPENT
AMINE
NU
ND


®*
9A6HOUSE
EMISSION
64 6
031b/lir
AMB


®*
FUGITIVE
DUSTS
52 0 Ib/tu




S"
WATER,
DUST
PALLIATIVES
1566




H*
PRO. SHALE
RWEGtT/STIOK
WftTER
649




0*
SAWT WATER
TREATMENT
SLUDGE
NO



ft-
u*
AERATED
POND
SLUD8E
N D
AMS
AU[t
SOURCE.  DRI  lMSe4on6»lIOilCof>«(id
        S'dinlom Oil CD (In Jionol, March 1976
                                                                     FIGUHE  33-10  SOLID WASTE DISPOSAL

-------
     fROM FI6 33-2


      SrtAM

      CONDEHSOTE

               -5,7,8,9
     FflOMFIG 33-3
                                          FOR LEGEND SEE FIGURE 33-1
                                                                                                                                                           TO fit. 3.3-3
 STREAM

 IDENTITY
MINE
wrtn
FLOW RATE |034CFM
TEMP.'F
                13'
                    BOILER
               16,500
                MB

                Him
PRESS, fwg	

SOURCE  DRI bosed 01 iniontialiorspfovrt!^
                         LKIUCM WATER
                     4MB
           H*
                               SXCES. ttfttlH)
s
                               8330
HI*
                                          Ettffll*WR
           'ROC

           >{|j|-Tf COOLIN6HWER
                                    5TESM
                                                                            ffiUP MKUP
                                                                            4MB
                                                                                     TO.
                                                                                 SHLE
                                                                                                 ND
                                                                                          •tco-

                                                                                          aKUEtaEBy
                                                                                           DCODLWMR
                                                                                           ICTtf
waa WSTB USED mat, sun BOI,
5»»r EV#> gswr SSNir «WB rown
*MR  fBCB smm 8BSTR IR& JBIA!
                                                                                                                                                    mw JL*-wris«p
                                                                                                                                                    SKUSL.
                                                                                                                                                         BXl
                                                                                                                                                                    EOUH
                                                                                                                                                                 442
 1ARI
 «W  .
11091,
. «£  ,
iapu
".MB
                                                                                                                                                                    2525
                                                                                                                                                                        2912
                                                                                                                                                                                 «iy«
                                                                           FIGURE 33-11  WMEH MflNaSEMENT

-------
                                  MINE WATER

                                        116,500
 FLOWS IN GPM
                         13,528
                                                                                883
                                                                             -—EVAPORATION
                                       SURFACE DISCHARGE  _
                                         8,330
SOURCE  WP4
                   FIGURE 3.3-12  OVERALL WATER MANAGEMENT SCHEME


                                          65

-------

-------
                                  SECTION 4

        INVENTORY AND COMPOSITION OF PLANT PROCESS AND WASTE STREAMS
     The  stream  compositions  presented in this section were  derived,  to z;he
extent  possible,  from pilot  plant test  data.   In the absence  of data from
actual  source  testing, engineering  analyses  (by  Denver  Research Institute,
Stone and Webster  Engineering Corporation and Water Purification Associates)
were  performed  on the  technology and  raw  stream information  from proposed
Industrial  developments.   The sources  of these  data, whether  actual, esti-
mated,  or derived from published  or  unpublished  information,  are indicated.

     The  data  presented   are internally consistent  for  the overall  plant
ccmpTex;  i.e.,  the  principal  chemical elements involved in emissions,  efflu-
ents, and wastes are balanced throughout the plant.  Trace elements generally
are  not considered  because  of the  lack of consistent  data  available  as  a
starting  point.   Tne  stream  compositions  derived  by  engineering  analysis
generally  agree  with the  available data  from  published  sources.   Therefore,
the data presented in this section, even though partly derived by engineering
analysis, are Believed  to be  both representative of the actual  operations of
such a  plant  and accurate enough to lead to relevant conclusions in analyses
of various pollution controls.

4.1  INVENTORY OF STREAMS

     All  but the  most minor streams in the plant complex are inventoried in
tMs section, and quantitative  data are presented to define  important char-
acteristics of  the   streams.   Section 4.2 presents detailed  compositions  of
tha  major streams and  shows  changes  in  composition,  from one point  to the
next, throughout the plant.

     Trie  streams  encountered  during the analysis of pollution  control  tech-
nologies for the plant are listed, along with  their flow rates and components
of  concern,  in  Tables 4.1-1  (gases),  4.1-3   (liquids)  and 4.1-5  (solids).
Whether  or  not  a stream  must be  controlled  will depend upon its  size,  the
quantities  and   characteristics  of  components,  their  allowable limits  if
released  into  the   environment,  and  the  disposition  of  the  stream  in  an
Integrated plant design.

     Tables 4.1-2,  4.1-4,  and  4.1-6  list the  major  constituents  in  the
streams.  The  streams a.re  likewise  divided into §as*s,  liquids,  and  solids
based on their  physical  characteristics,  These  tables  summarize the  data
presented  in  Section 4.2, allowing  for  a quick  comparison of the  streams.
            Preceefing page blank
67

-------
                                                             TABLE 4.1-1.  INVENTORY OF GASEOUS STREAKS
CO

Stream
Number
(Table Ho )
5*
6*
7*
8*
9*
10*
11*
12*
13*
14*
15*
16*
17*
18*
Hass flow,
103 Ib/hr
Description of Stream (103 ACFH)
Primary Crusher (ore), Baghouse
Emission
Primary Crusher (subore), Baghouse
Emission
Primary Crusher (overburden),
Baghouse Emission
Raw Shale Conveyor Transfer
Point, Baghouse Emission
Swinging BOOB Stacker, Baghouse
Emission
Coarse Ore Conveyor Transfer
Point, Baghouse Emission
Secondary Crusher, Baghouse
Emission
Secondary Crushing to Screening
Conveyor Transfer Point, Baghouse
Emission
Secondary Screening, Baghouse
Emission
Secondary Screening Conveyor
Transfer Point, Baghouse Emission
Tertiary Crusher, Baghouse Emission
Tertiary Crushing to Tertiary
Screening Conveyor Transfer
Point, Baghouse Emission
Tertiary Screening, Baghouse
Emission
Tertiary Screening to Fine Ore
(122.2)
(12.2}
(63.8)
(72.6)
(121.5)
(40.4)
(558.4)
(40.4)
(558.4)
(40 4)
(6?8.?)
(80.8)
(628 2)
(40.4)
Components
ot Concern
Pat tlculates
Particulates
Particulatos
Particulates
Particulates
Particulates
Particulates
Particulates
Particulates
Particulates
Partfeulates
Particulates
Participates
Particulates
Mass Flow of
Component, Ib/hr Remarks
15 7
1 6
8.2
0 4
0 6
0 2
71.9
0,2
71.9
0 2
80.8
0 4
80 8
0.2
Baghouse controlled.
Baghouse controlled,
Baghouse controlled.
Baghouse controlled.
Baghouse controlled.
Baghouse controlled,
Baghouse controlled. ,
Baghouse controlled.
Baghouse controlled.
Baghouse controlled.
Baghouse controlled.
Baghouse controlled.
Baghouse controlled- '
Baghouse controlled.
               19*
  Storage Conveyor Transfer Point,
  Baghouse Emission

Ftne Ore Storage,  Baghouse Emission    (28 8)
                                                                              Particulars*
                                                                                                          3.7
Baghouse controlled
                                                                                                                                     (Continued)

-------
                                                                         TABLt 4.1-1  (cont.)
en
Stream
Number
{Tabln No )
20*

21*

23*

24*





Mass How,
ID3 Ib/hr
Description of Stream (10d ACFH)
Retort Feed Hopper Conveyor Transfer
Point, Baqhouse Emission
Retort Feed Hopper, Baghouse
Emission
Processed Shale Load-out Hopper,
Baghouse Emission
Diesel Emissions




{40 4)

(212.4)

(64 5)

(151 3)




Components
of Concern
Particulates

Participates

Particulates

CO
NOx
S02
Hydrocarbons
Parti cuiates
Mass Flow of


Component, Ib/tir Remarks"
0 2

27 3

8.3

34.8
469 9
35.6
12.7
33.0
Baghousa controlled

Saghouse controlled

Bagbouse controlled







Catalytic converters are Installed
on the diesel-operated



equipment



                25
                26
             (4.2-9)
                27
                30
                31*
             (4  2-19)
                           Combustion Air -  Lift Pipes
Retort Vapors
                          High Pressure Steam
                           Steam to Humidifier
Iurgi Flue Gas
                                     5,439
1,425 2
                                     1,060
                                                                 992
7,202 6
                                                                              Processed Shale Dust
                                                                              COS
                                                                              K,D/
CO
NOx
SO,,
Hydrocarbons
Particulates
                       78,600
                        1,924
                        1,197
                          256
                          N.D.
                                                                                                        N 0,
  657
2,440
  500
6,262
1,107
                The air Is preheated in the waste
                heat boiler and then used in the
                lift pipes for processed shale
                incineration

                Oil products are dedusted before
                blending.   Aranoma and sulfur
                dioxide are removed by subsequent
                gas liquor condensation
The steam 1s raised from the treated
mine water and should be pure.
Approximately 194 x 103 Ib/hr of
the steam are used for generating
electrical power.

The steam is produced during
processed shale quenching and it
nay contain some entrained dust
It is added to the flue gas.

Approximately 93% of the S02 is
irreversibly adsorbed on the
processed shale   The particulates
are controlled by an electrostatic
precipitator   RBOSC's modified OOP
indicates pmssion of a large amount
of hydrocarbons, measured as
methane.
                                                                                                                                     (Continued)

-------
                                                                        TABU 4.1-1  (cont.)
-J
o
Stream
Number
(Table No )
3?*
33
(4 2-11)
34
(4 2- 12)

35
44*
45
(4 2-13)
47*
48
(4 2-15)
Description of Stream
Raw Shale Retort Feed Conveyor,
Baghouse Emission
Raw Retort Gas
Retort Gas

Retort Gas to Lift Pipes
Fugitive Hydrocarbon Emissions
from Storage Tanks
Naphtha-free Retort Gas
Hydrocarbon Emissions from
Naphtha Storage
Compressed Naphtha-free Gas
Mass Flow,
10J Ib/hr Components
(It)3 ACfM) of Concern
(219.2) PaiticulatPS
738.8 Nil,
H2S
S02
149 0 NH3
H2S
S02

107 0 NH;j
H2S
SOS
N 0. Hydrocarbons
121 7 NH3
H2S
SOZ
C02
H20
H D. Hydrocai boris
118.0 NH,
H2S
C02
H20
Mass Flow of
Component, tb/hr
1 2
J.924
1,197
256
29
697
19

21
501
14
65.5
29
697
19
55,981
3,832
N.D.
2
697
55,964
97
Remarks8
Baghouse control lea
Ammonia and sulfur dioxide are
removed from this retort i)»s by
subsequent water scrubbing
Condensation of water vapor along
with light oils results in removal
of substantial quantities of ammonia
and sulfur dioxide. The miss flows
given are for the net retort gas
after subtracting the amount sent to
the lift pipes as supplemental fuel.
The gas is supplied to the lift
pipes as auxiliary fuel to support
combustion NOx and SOZ emissions
from the lift pipes may be sonwwhat
increased, but S02 is control 1MI to
93X by adsorption on the processed
shale.
Proper storage tanks are used to
prevent excessive hydrocarbon
emissions Includes strew 47.
The acid gases and moisture must be
removed to achieve pfpelirw quality
for the retort gas.
Included in stream 44.
Ammonia and water are reduced
significantly by compression and
cooling. Further dryiny is still
necessary. Hydrogen sulfide and
               50
                          Steam to Naphtha Recovery
                                                                  10
carbon dioxide also must be
removed

The steam is produced from the
softened and demineralized mine
water
                                                                                                                                    (Continued)

-------
                                                              fABLC 4.1-1  {rout.
  SlreiM!
  Number
(Table No )
              Bescriptioti  of  Stream
     SI

     52
     56
  (4.2-16)
  (4.?- 17)
     SB
  (4,2-18)
     60*
   61
(4.2-18)

   63*
(4.2-18)
    ' 64
  (4 2-18)
     72
  (4.2-21)
     73*
Steam to DEA Unit

Steam to Stretford Unit

Steam to Ammonia Recovery Unit          b3

Sweet Gas from DEA Unit                 61.9




Brled Fuel Gas to Pipeline              61.a




Acid Gases from DEA Regeneration        57.1



TEX5 Regeneration Vent Emission         N D.


Stripping Air to Stretford              20.9


Stretford Treated Acid Gases            53,0




Stretford Oxidlier Vent Gas             24 3




Ammonia Overhead Vapors                 20 2
                Processed  Shale  Conveyor Transfer       (64 6)
                  Point, Baghouse  Emission

Mass flow,
103 Ib/lir Components
(103 ACFM) of Concern
130
I
Mass Flow of
Component, Ib/hr
—
Remarks3
See stream 50
See stream 50,
                                                                 NH3
                                                                 H2S
                                                                 C02
                                                                 H20

                                                                 NH3
                                                                 H2S
                                                                 C02
                                                                 H20

                                                                 H2S
                                                                   N D
                                                                   H2S
                                                                 NH3
                                                                 Organics
                                                                   Particulates
              See stream 50

  2           A majority of carbon dioxide and
  0.3         hydrogen sulfide is removed by
620           absorption in DLA   The treated gas
 86           should be dried before pipelining

  2           Trtethylene glytol (TEG) is used
  0.3         for absorbing most of the moisture
620           In the gas.   The dry gas may contain
  9           a small amount of TEG

696           The acid gasos are treated by the
              Stretford process before being
              released to the atmosphere.

M.D           The emission is water vapor with a
              small amount of TEG
  1.3         A majority of the hydrogen sulfide
              has been removed from the acid
              gases   The amount of HZS emitted is
              negligible.

              The vent gas Is primarily air, with
              some carbon dioxide and water vapor
              It is used as a source of combustion
              air for the lift pipes.

 14           The overhead vapors are added to the
 66           lift pipes for the combustion of
              organics   As a result,  the HOx
              pmission from the lift pipes may be
              slightly increased

  0 3         Baghouse controlled.
                                                                                                                          (Continued)

-------
                                                              TABLE 4.1-1  (cont.)
  Strew
  Number
(Table No,)

     74*
    100*



    107*

    110*


    112*
Description of Stream
 Mass Flow,
 TO3 Ib/hr
UQ3 ACFM)
                                                    Components
                                                    of Concern
                Fugitive Ousts                      J9.650          Participates
Water Evaporation from Nine Water       44
  Clarifier
Cooling Tower Evaporation              442

Water Evaporation from                   7
  Equalization Pond

Miscellaneous HC Emission              N.D.          Hydrocarbons
  Mass now of
Component, Ib/hr
                                                                                                    Remarks
                                           52 0         Fugitive dusts emanate frsa min1figt
                                                        hauling, open storage, disposal,
                                                        etc,   Iheso are controlled by watsr
                                                        and foam Sprays.

                                                        Tho evaporation 1s essentially purjs
                                                        water vapor, as clarified mine, water
                                                        is used.

                                                        See stream 100.

                                                        See stream 100.
                                           36 5         This emission represents the leakage
                                                        from valves,  pumps, etc.  Proptr
                                                        maintenance practices are userf- to
                                                        control  the leakage.
* Indicates streams that come into contact with the environment.

a The remarks  Indicate  the  stream disposition.  The control  technologies  applied to the streams  are  those proposed for the  Lurgi-Open Pit
  technologies

  Dashes (—) indicate no known components of concern,

c H D.  = Not determined.

Source   ORI estimates based on information from Gulf Oil  Corp.  and Standard Oil  Co.  (Indiana),  March 1S76,  and Rio Blanco Oil  Shale Co.»
         February 1981

-------
                                           (ABLE 4 1-2   COMPOSITIONS Qt GASEOUS STREAMS
Stredm
Number
(Table No.)
5*

6*

7*

8*

9*

10*

11*

12*


13*

14*


15*

16*


17*

18*
Mass Flow,
Stream W3 Ib/hr
Description {10a ACFM)
Primary Crusher (ore),
Baghouse Emission
Primary Crusher (subore),
Baghouse Emission
Primary Crusher (overburden),
Baghouse Emission
Raw Shale Conveyor Transfer
Point, Baghouse Emission
Swinging Boon Stacker,
Baghouse Emission
Coarse Ore Conveyor Transfer
Point, Baghouse Emission
"Secondary Crusher,
Bighouse Emission
Secondary Crushing to
Scrsening Conveyor Transfer
Point, Uaghouse Emission
Secondary Screening,
Baghouse Emission
Secondary Screening Conveyor
Transfer Point, Baghouse
EaUffan
Tertiary Crusher,
Baghouse Emission
Tertiary Crushing to Tertiary
Screening Conveyor Transfer
Point, Baghouse Emission
Tertiary Screening,
Baghouse Emission
Tert1iry Screening to Eine
(122 2)

(12.2)

(63 8)

(72 6)

(121.5)

(40 4)

(558 4)

(40.4)


(558 4)

(40.4)


(628.2)

(80 8)


(628.2)

<40.4)
Components , 1Q3 Ib/hr
H2
0**

0

0

0

0

0

0

0


0

0


0

0


0

0
CO
0

0

0

0

0

0

a

0


0

0


0

0


0

0
C02
0

0

0

0

0

0

0

0


0

- o


0

0


0

0
Kz
H D **

N D

N D

N D.

N D.

H D

N 0

N D


N 0

N.O


N.D

N D.


N.O

N D
NH,
0

0

0

0

0

0

0

0


0

0


0

0


0

0
H2S
0

0

0

0

0

0

0

0


0

0


0

0


0

0
cm
N 0.

N D.

N D

N.D

N.O

N.D.

N D

N.D.


N D

N.D.


N.D.

N D


N D

N D
CjtH4
0

0

0

0

0

0

0

0


0

0


0

0


0

0
C?H(, CjHb
0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0


0 0

0 0


0 0

0 0


0 0

0 0
c ,H» r.,
0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0


0 0

o a


0 0

0 0


0 0

0 0
Ore Storage Conveyor
Transfer Point, Baghouse
tmissian
                                                                                                                    (Continued)

-------
                                                       TABLE 1.1-2  tcont )

Humber
(Table No )
S*

6*

7*

8*

9*

10*

11*

12*


13*

14*


15*

16*


17*

18*

Stream
~"~~ ' • '
I03 )b/hr
Components ,

Description (103 ACfM) C^H.o
Primary Crusher (ore),
Baghouse Emission
Primary Crusher (subore),
Baghouse Emission
Primary Crusher (overburden),
Baghouse Emission
Raw Shale Conveyor Transfer
Point, Baghouse Emission
Swinging Boom Stacker,
Baghouse Emission
Coarse Ore Conveyor Transfer
Point, Baghouse Emission
Secondary Crusher,
Baghouse Emission
Secondary Crushing to
Screening Conveyor Transfer
Point, Baghousa Emission
Secondary Screening,
Baghouse Emission
Secondary Screening Conveyor
Transfer Point, Baghouse
Emission
Tertiary Crusher,
fiaghouse Emission
Tertiary Crushing to Tertiary
Screening Conveyor Transfer
Point, Baghouse Emission
Tertiary Screening,
Baghouse Emission
Tertiary Screening to Fine
(122 2)

(12 2)

(63 8)

(72 6)

(121.5)

(40.4)

(558.4)

(40.4)


(558.4)

(40.4)


(628.2)

(80.8)


(628,2)

(40 4)
0

0

0

0

0

0

0

0


0

0


0

0


0

0
M!sc,
(1C
0

0

0

0

0

0

0

0


0

0


0

0


0

0
Light Middle
 ?

1 6

8,2

0.4

0 «

0.2

71 9

0 2


71.9

0.2


SO, 8

0.4


80.8

0 2
Ore Storage Conveyor
Transfer Point, Baghouse
Emission
                                                                                                                    (Continued)

-------
                                                                              TABU: 412   (c.ont.)
tp
Stream
Number
(Table No )
19*

20*


21*

23*

24*

2S
26
(4.2*9)
27
30
31*
(4.2-19)
32*

33
(4.2-11)
34
(4 2-12)
35
44*


45
(4 2-13)
Stream
Description i
Fine Ore Storage, Baghouse
Emission
Retort feed Hopper Conveyor
Transfer Point, Baghouse
Emission
Retort Teed Hopper,
Baghouse Emission
Processed Shale Load-out
Hopper, Baghouse Emission
Diesel Emissions

Combustion Air - Lift Pipes
Retort Vapors

High Pressure Steam
St*»m to Humidifier
turgi Flue Gas

Raw Shale Retort Feed
Conveyor, Baghouse Emission
Raw Retort Gas

Retart Gas

Retort Gas to Lift Pipes
Fugitive Hydrocarbon
Emissions from Storage Tanks
(stream 47 included)
Naphtha- free Retort Gas

Has1; flow,
10 J Ib/hr
[10J ACKH)
(28 8)

C40 4)


(212,4)

(64 5)

(151 3)

5,439
1,425 2

1,060
992
7,206 6

(239 2)

738 8

149 0

107.0
H.D


121 7


H2
0

0


0

0

0

0
4 97

0
0
0

0

4 97

2 89

2 08
0


2 89


to co^
0 0

0 0


0 0

0 0

34 8 N D
Ib/hr
0 0
7 14 98 46

0 0
0 0
0 66 1,443 63

0 0

7 14 98 46

4 16 55 98

2 99 40 2
0 0


4 16 55 98


N2
H D

H D


N D

H D

N D

4,146
7 14

0
0
4,170 9

N 0.

7 14

4 16

2 99
0


4 16


NIIj
0

0


0

0

0

0
1 92

0
0
0

0

1 92

0 03

0 02
0


0 03

Components
H2S
0

0


0

0

0

0
1 20

0
0
0

0

1 20

0.70

0 50
0


0 70

, 103 Ib/hr
CH4 C2H,i CZH6
NO 0 0

NO 0 0


N D 0 0

N.O 0 0

000

000
18.95 12 24 12 S7

000
000
000

N.O 0 0

18 95 12.24 12.57

11.03 7 13 7 32

7 92 5 12 5,26
000


11 03 7 13 7 32


C*H« C ,H8
0 0

0 0


0 0

0 0

0 0

0 0
15.68 8.42

0 0
0 0
0 0

0 0

15 68 8 42

9.13 4 90

6.56 3 52
0 0


9 13 4 90


c.ifis~
0

0


0

0

0

0
13.77

0
0
0

0

13 77

8 01

5.75
0


8 01

                                                                                                                                           (Continued)

-------
                                                                     TABLF 4 1-2  (cent.)
Stream
Number
O«l>le No }
19*

20*


21*

23* ,

24*
20
26
(4 2-9)
27
3D
31*
(4 2-19)
32*

33
(4 2-11)
34
(4.2-12)
35
44*
Strsam
Description
Fine Ore Storage, Baghouse
Emission
Retort Feed Hopper Conveyor
Transfer Point, Baghouse
Emission
Retort Feed Hopper,
Baghouse Emission
Processed Shale Load-out
Hopper, Baghouse Emission
Diesel Emissions
Combustion rtir - Lift Pipes
Ketort Vapors

High Pressure Steam
Steam to Humidifier
Lurgl flue Gas

Raw Shale Retort Feed
Conveyor, Baghouse Emission
Raw Retort Gas

Retort Gas

Retort Gas to Lift Pipes
Fugitive Hydrocarbon
Mass Flow,
103 lb/lii>
(10a ACFH)
(28 8)

(40 4)


(212.4)

(64 5)

(151 3)
5,439
1,425 2

1,060
992
7,202.6

(239.2)

738 8

149 0

107 0
N.D
Components ,
C..HIO
0

0


0

0

0
0
4 23

0
0
fr

0

4 23

2 46

1 77
0
Wise
HC C,/
0 0

0 0


0 id

0 0

0.013 0
0 0
0 24 23 87

0 0
0 0
6.26 0

0 0

0 24 23 87

13.10 13.89

9 41 9 97
0 066 0
Light
Oil
0

0 "


0

0

D
0
205 77

0
0
0

0

205. 77

0

0
0
Kiddle
011
0

0


0

0

0
0
4 [3 24

0
0
0

0

1 91

0

0
0
Heavy
Oil
0

0


0

0

0
0
196 51

0
0
0

0

0

0

0
0
COS
0

0


0

0

0
0
N.O

0
0
0

0

0

0

0
0
103 1b/hr
«,
0

0


0

0

0
0
0

0
0
0

0

0

0

0
0
CHSSH
0

0


0

0

0
0
0

0
0
0

0

0

0

0
0
H20
N D.

N.O


N.D.

N.D.

N 0
35
300. 05

1,060
992
1,224

N.D.

300 OS

4.10

2 94
0
0,
s,e,

B D -


N.O,

H 0.

N.6.
1,258
0

.0
0
353. 11

»,0

0

0

8
0
NQX
!b/hr
0

0


ft

6

469 9
0
ft

0
»
2 ,«»

0,

0

0

0
B
SO, TW
IWhr 1i»Vhr
0 | 7

0 0.2
(

0 27.3
,
. -0 9,3

.35.6 33
0. 0
2$6 78,600

» , 0
e no,
SCO 1J07
„
0 £"2

256 - jO
",'
19- 8,".
' *
J4' fl
0 »
              Emissions  from Storage Tanks
              (stream 47 Included)

   45       Naphtha-free Retort Gas          121 7     2 46     0      0       0        0       0       0       0       0     3.83      0      B     19
(4 2-13)



                                                                                                                                  (Continued)

-------
                                                                  TABLE 4 1-2  (cont.)
Nupt>er
'(Table «o )
47*


48
(4 2-15)
50
SI
62
S3

S6
(4 2-16)
§7
(4 2-17)
58
(4 2-18)
60*

61
{4 2-18)
63*
(4.2-18)
64
(4.2-W)
72
(4 2-21)
73*
Stream
Description
Hydrocarbon Emissions from
Naphtha Storage
( included in stream 44)
Compressed Naphtha-free Gas

Steam to Naphtha Recovery
Steam to DEA Unit
Steam to Stretford Unit
Steam to Ammonia Recovery
Unit
Sweet Gas from DEA Unit

Dried fuel Gas to Pipeline

Acid Cases from DEA
Regeneration
TEC Regeneration Vent
Emission
Stripping A1r to Stretford

Stretford Treated Add
Gases
Stfetford Qxldlzer Vent Gas

Auraonia Overhead Vapors

Processed Shale Conveyor
Mass Flow,
ID3 Ib/hr
(103 AUM)
N D,


118 0

10
130
1
53

61,9

61.8

57,1

N D.

20 9

53.0

24.3

20.2

(64 6)
Components
Hz
0


2 89

0
0
0
0

2 89

2,89

0

0

0

0

0

0

0
10
0


4 16

0
0
0
0

4 16

4 16

0

0

0

0

0

0

0
C02 N2 NH3
0 00


55 96 4 16 0 002

0 00
0 00
0 00
fl 00

0 62 4 16 0 002

0 62 4 16 0 002

55 34 NO 0

0 00

0 16 12 0

52 00

3 32 16 12 0

2 30 00 014

0 0 0
ri2S
0


0.70

0
0
0
0

0 0003

0 0003

0 70

0

0

0.0013

0

a

0
, 103 Ib/hr
CH4
0


11 03

0
0
0
0

11.03

11 03

0

0

0

0

0

0

0
C2H4
0


7 13

0
0
0
0

7 13

7 13

0

0

0

0

0

0

0
r*H6
0


7 32

0
0
0
0

7.32

7 32

0

0

0

0

0

0

0
C3H8
0


9 13

0
0
0
0

9 13

9 13

0

0

0

0

0

0

0
C3H8
0


4 90

0
0
0
0

4 90

4.90

0

0

0

0

0

0

0
C«HS
0


8 01

0
0
0
0

8.01

8 01

0

0

0

0

0

0

0
           Transfer Point, Baghouse
           tnission

74*      Fugitive Dusts                19,650         000         00          00000


                                                                                                                               (Continued)

-------
                                                                             TABLE 4 1-2  (cent.)
00
Streatn
Number
(fable Ho.)
47*


48
(4 2-15)
BO
51
52
53

56
(4.2-26)
57
(4 2-17)
58
(4 2-18)
60*

61
(4 2-18)
63*
(4 2-18)
64
(4 2-18)
72
(4.2-21)
73*
Stream
Description
Hydrocarbon Emissions from
Naphtha Storage
(included 1n stream 44)
Compressed Naphtha-free Gas

Steam to Naphtha Recovery
Steam to DEA Unit
Stean to Stretford Unit
Steam to Ammonia Recovery
Unit
Sweet Gas from DEA Unit

Dried Fuel Gas to Pipeline

Acid Gases from DEA
Regeneration
TEG Regeneration Vent
Emission
Stripping Air to Stretford

Stretford Treated Add
Gases
Stretford Bxldlzer Vent Gas

Ammonia Overhead Vapors

Processed Shale Conveyor
Mass Mow,
UP lb/hr
(1Q3 ACFH)
N D.


118

10
130
1
53

62

62

57

N D.

20 9

53

24.3

20 2

(64 6)

C,H,0
0


2 46

0
0
0
0

2.46

2 46

0

0

0

0

0

0

0

Wise
IK
N 0


0

0
0
0
0

0

0

0

0

0

0

0

0.07

0

e,'
0


0

0
0
o
0

0

0

0

0

0

0

0

0

0

light
Oil
0


0

0
0
0
0

0

8

0

0

0

0

0

0

0

H'ddle
Oil
0


0

0
0
0
0

0

0

0

0

0

0

0

0

0
Components ,
Heavy
Oi 1 COS
0


0

0
0
0
0

0

0

0

0

0

0

0

0

0
0


0

0
0
0
0

0

0

0

0

0

0

0

0

0
101 lb/hr
rs,
0


0

0
0
0
0

0

0

0

0

0

0

0

0

0
CHjSH
0


0

0
0
0
0

0

0

0

0

0

0

0

0

0
H20
0


0 ]0

10
130
1
53

0 09

9
Ib/hr
1.03

N.D

0.13

0 96

0.60

17 79

N D
02
0


0

0
0
0
0

0
_,
tt

0

0

4 63

0'

4 29

0

0
HO*
jjj/lw
0


0

0
0
0
0

0

0

0

0

0

0

0

0

0
S02
Ib/hi
0


0

0
0.
0
D

0

0

0

0

0

0

0

0

0
TPH
0


0

0
0
0
0

0

0

0

q

B

0

0
,
0*
-
0.3
            74*
  Transfer Point,  Baghouse
  Emission

Fugitive Dusts
                                                  19,650
0     NO.       0_     0


          (Continued)
                                                                                                                                                             0     52

-------
TABLE 4.1-2  (cant }
Streati
Number
(Table No }
100*

107*
110*

112*
St ream
Description
Water Evaporation from Mine
Water ClaHfier
Cooling Tower evaporation
tfat^r Evaporation from
Equalization Pond
Miscellaneous HC Emission
Mass HOM,
1G3 Ib/hr
(103 ACrM)
44

442
7

N 1)
Components ,
1I2
0

0
0

0
10 t02
o o

Q 0
0 0

0 0
N,
0

0
0

0
NHj
0

0
0

0
H*i
0

0
D

0
101 Ib/hr
'cHI
0

0
0

0
C*H4
0

0
0

0
C2H« CjH,,
0 0

0 0
0 0

Q 0
CjH8
0

0
0

0
C4H»
0

0
D

0
                                                             (Continued)

-------
                                                                             TABLE « 1-2  (cont >

Number
(Table No )
100*

107*
110*


112"

Stream
Description
Water Evaporation from Mine
Water ClaHfier
Cooling Tower Evaporation
Water Evaporatton from
Squalization Pond

Miscellaneous HC Emission

10s !b/hr
(W ACFH)
44

442
7


N 0
Components ,
Mlsc
C H HC
0 0

0 0
0 0


0 0.037


-------
                                                    TABU 4.1-3   IMVtNTORY OF LIQUID STREAMS

Stream
Number
(Table No. )
4*
(4 2-M)

Description of Stream
Mine Water

Mass Flow, §p«i
(10' Ib/hr)
16,500

Components
of Concern
TDS
Boron
Phenol

Mass Flow of
Component, Ib/hr
8,266
5
0 02

Remarks0
The water is clarified
treated before use in


and properly
the plant
   28*
   36
(4,2-10)
   37
   38
(4.2-10)
   40

   41
(4.2-20)
             Slowdown - Waste Heat Boiler
Light Oils to Storage
Middle Oils to Storage
Gas Liquor
   42        Heavy Oils to Storage
(4 2-10)
   49        Compressor Comtensate
(4 2-ZO)
                                                  21
  406
(18S.2)
             Light Oil Makeup to Naphtha         N.D
               Recovery
  937
(411.3)
             Diesel Fuel - Mining Equipment      N.D.
Diesel Fuel - Disposal Equipment    N.D.
  586
(297.7)
                                     416
                                   (1% 5)
   46        Naphtha Product to Storage         (27.3)
(4. 2-14)
                                      8
                                    (3 8)
Organic
-Nitrogen
-Sulfur
                                                                 H.D
Organic
-KHroflen
-Sulfur
Free NHa
Fixed NHjj
Fixed S02
                 Organic
                 -Nitrogen
                 -Sulfur
                 Free Nil,
                 Fixed NH3
                 Fixed SO,
                                                                             16,000
                                                                              7,000
                                                                                            N 0.
1,758
  117
  221
                             11
                              9
                             16
                Clarified mine water is softened and
                demineralized before use in the boiler
                The blowdown is used for processed
                shale moisturizing.

                The composition of individual oil
                fractions is not known.  The quantities
                of nitrogen and sulfur indicated are
                for combined heavy oils, middle oils
                and light oils   Treatment may be
                required if on-s
-------
                                                                            TABLE 4.1-3  (corrt )
CO
Stream
Number
(Table Ho.)
54

55

Description of Stream
Amine Makeup

TEG Makeup
Mass Flow, gpw Components
(103 Ib/iir) of Concern
H D

N.D.
Mass Flow of
Component, Ib/hr Remarks
The diettianolamine js
the reagent losses
A small amount of T£fl


added to make up

is lost during
                 59*       Spent  Amine
                 62        Stratford Chemicals
                 65        Stretford Spent Liquor to
                             Reclaim
   66        Liquid Sulfur Product to
(4 2-18)       Storage

   67        Phosphoric Acid
                 69        Steam Condensate  from
                            Ammonia  Recovery
                 70*        Stripped Gas  Liquor
              (4 2-21)
                 71        Anhydrous  Ammonia  to  Storage
              (4 2-21)

                 75*        Excess Mine Water  to
              (4 2-23)       Aeration Pond
                 76*        Aerated Water  to  Discharge
              (4 2-23)
                                                 K 0.
                                                              (0 03)
                                                               M.D.
 (0.70)
7 6 LTPSD

 (0.01)
                                                                106
                                                  558
                                                (279.7)
                                                 (1.9)
                                               22 6 TPSD

                                                 8,330
                                                                 N.D.
                                                                               N 0
                  TOS
                  NH3
                  Dissolved Qrganics
                      vapors
                  TOS
                  Boron
                  phenol
                                                                 TDS
                                                                 Boron
                                                                 Phenol
                                                                 COD
                                                                                            H.D.
                                                                                            N D.
  471
    4
  170
                                                                                                          R.O
),170
    2.6
    0.004
                                            4,170
                                                2 6
                                                0 001
                                               50
                the reaejent regeneration ahd Is jtiade
                up with the fresh chemical,'

                The auiine spent during the reagent
                regeneration 1s removed periodically
                and sent for disposal,

                The Holmes-Stratford mix and soo> ash
                are added to make up the reagent
                losses.

                The liquor Is shipped, for off-site
                disposal or the useful chemicals nay
                be reclaimed.

                Stretford sulfur is reported to have
                +99.9% purity.

                This Is a reagent makeup to the amnonia
                recovery process.
Softened and demineralized mine
is used for raising the steai*   The
steam is condensed upon use and
returned to the boilers.

The free and fixed amnonia in the gas
liquor are recovered in the ammonia
plant   Stripped Uqtior is used for
processed shale moisturizing.

Refrigerated storage tanks are us«d to
reduce the HH3 emissions

This is the excess mine water after
process needs.  It is aerated to reduce
the organics content, then discharged
on the surface,

The COD is reduced by 25% du* to
aeration   The treated yrater 1s
discharged on the snrface.
                                                                                                                                         (Continued)

-------
                                                                           TABLE 4 1-3  (cont }
00
Stream
Nuisber
(Table Mo )
77
78*
79
80
81
82
83
84
85
86
Description of Stream
Feedwater to Waste Heal Boiler
Total Processed Shala
Moistening Water
Cooling Water to Lurgi
Oil Recovery
Cooling Water to Naphtha
Recovery
Stem Condensate from Naphtha
Stripper
Cooling Water to Compression
Cooling
Cooling Water to DEA-TEG
Treatment
Steam Condensate from
DEA-TE6 Treatment
Steauft Condensate from Stretford
Cooling Water Makeup to
Mass 1 low, gpm Components
(10s )b/hr) of Concern
2,120
5,624 TOS
325
5
20
8
66
260
2
2 — -
Mass Flow of
Component, Ib/hr Remarks
See stream 28


H D. Various wastewater streams are
combined and used for processed shale
quenching and moisturizing
Treated mine water is used for plant
rooling requirements
See stream 79, The quantity given
to make up the losses.
See stream 28.
See strean 79, The quantity given
to make up the losses.
See stream 79 The quantity given
to make up the losses
See stream 28,
See stream 28,
See stream 79. The quantity given
is

is
IS


is
                            Stretford

                87        Process Water Makeup to               3
                            Stretford

                88*       Humidified Air Cooler Slowdown       661
                89        Cooling Water to Ammonia            1,080
                            Recovery

                90*       Water for Dust Palliatives          1,568
                91*       Processed Shale Revegetation         649
                            Water
to make up the losses

Process water of boiler feedwater
quality is used.

Treated mine water is used in the
humidified air coolers in the oil
recovery and Stretford processes
The blowaown is used in processed
shale moisturizing

See stream 79   The quantity gis/en is
for the cooling water circulated.

Clarified nine water is used for the
raw and processed shale dust control

Clarified Kline water is used.
                                                                                                                                        (Continued)

-------
                                                            M8LI 4.1-3  (cent.)
Stream
Number
(Table Mo )
92*
(4 2-3,
4 2-4)
93*
94
95*
96*
97
98
99*
101*
102*
Description of Stream
Raw Shale 1 oar hate
Storm Runoff
Boiler Feedwater Makeup
Service and Fire Water
Mine Water CtaHfier Sludge
Water to Cooling Tower
Makeup Treatment
Treated Water to Cooling Tower
Potable/Sanitary Hater
Used Sanitary Water to
Municipal Treatment
Treated Sanitary Water
Hass Flow, gpm Components
(10s lb/hr) of Concern
N D, TOS
DOC
150 N, D
43
43
165 H,0.
2,676 TDS
2,676 TOS
26
18 N.D
18
Hass Flow of
Component, Ib/ltr Remarks
3,490 tng/1 leachate data are derive?) from a
13 mg/1 Tract C-a sh*le lysiBeter study.
N.D. storm runoff water Is Collected »fid
used for processed shale moiiliiri/ing,
Softened and dem1r»er«11*ed min« watfcr
is used to compensate steam and
blowdown losses.
Clarified nine water is u$ad.
N 0. Suspended solids and debris are ;- V "
collected during the nine Water -
clarification and used for processed' '-.
shale moisturizing
1,340 Clarified mine water is treated with '
HZSO, to retard the biological growth
In the water and then used for plant
cool ing.
1,340 Treated nine water Is used to cool the
cooling water return fwm th* plant.
Clarified mine water 1s treated aftd
used for the sanitary needs.
N.D. Used sanitary water 1* sent to
municipal treatment before disposal,.
The' sanitary water after municipal
103*       Sanitary Water Treatment
             Sludge
104*       Boiler Feedwater  Treatment
             Concentrate
105*       Cooling  Tower  Slowdown
                                              N.D.
                                               11
1,123
                                                          treatment is used for processed shale
                                                          moisturizing.

                                                          The sludge from the sanitary water
                                                          treatment is dewatered, then used as
                                                          a fertilizer In rewegetaMoo.
Regenerated waste from
softening and demineraliiatlon Is used
for processed shale noisturfilng.  ,

Treated nine water is used for plant
cooling requirements   The (juanttty
given does not include ttie humidified
air cooler blowdown (stream 88)'.   The
to Uil blowdown would be 1,784 gpm.
                                                                                                                        (Continued)

-------
                                                                           TABLt 4.1-3  (cont
00
trt
  Stream

(Table No }     Description  of  Stream

    106*
                                                          Mass How,  qpm
                                                           (I03 Ih/hr)
                          Cooling lower Drift
    108*       Equalization Pond Discharge to
                 Processed Shale Moistening
109*       Clarified Mine Water to
             Processed Shale Moistening

111*       Aerated Pond Sludge
                                                            .  2,525




                                                              2,912


                                                              H D
                                                                   Components
                                                                   of Concern
  Mass Flow of
Component, Ib/hr
                                                                              N 0
                                                                   TDS


                                                                   N D
      M.D




     1,096


      N 0
                                                                                                                      Remarks
                                                                                                            Treated mine water is used in the
                                                                                                            cooling tower   The drift is
                                                                                                            essentially pure water.

                                                                                                            Various wastewaters (eg, sludges,
                                                                                                            concentrates, blowdawns) are combined
                                                                                                            and used for processed shale
                                                                                                            moisturizing

                                                                                                            Clarified nine water is used to fulfill
                                                                                                            the processed shale moisturizing needs

                                                                                                            The sludge may contain some bio-oxidized
                                                                                                            material and settled inorganic salts
                                                                                                            It 1s sent for processed shale
                                                                                                            moisturizing.
* Indicates streams that come into contact with the environment

  The remarks  Indicate  the stream disposition.  The  controls  and treatments applied to  the  streams are those proposed  for  the Lurgi-Open Pit
  technologies.

  Dashes (--) indicate no known components of concern

* N 0  * Not determined.

Source;   OKI estimates based on Information from Gulf  Oil  Corp   and  Standard  Oil  Co   (Indiana), March 1976, and Rio Blanco Oil Shale Co.,
         February 1981.

-------
TftBU 4 1-4.  COMPOSITIONS OF LIQUID STREAKS
Stream
Number
(Table NO )
4*
(4 2-22)
28*
36
(4 2-10)
37

38
(4 2-10)
39
40
41
(4 2-20)
00 42
m (4 2-10)
46
(4 2-14)
49
(4 2-20)
54
55
59*
62
65
66
(4 2-18)
67
69

70*
(4.2-21)
Stream Mass Flow, gpm
Description (103 Ib/hr)
Mine Water

Blowdown - Waste Heat Boiler
Light Oils to Storage

Light Oil Makeup to Naphtha
Recovery
Middle Oils to Storage

Diesel Fuel - Mining Equipment
Diesel Fuel - Disposal Equipment
Gas Liquor

Heavy Oils to Storage

Naphtha Product to Storage

Compressor Condensate

Amine Makeup
TEG Makeup
Spent An me
Stretford Chemicals
Stretford Spent Liquor to Reclaim
liqutd Sulfur Product to Storage

Phosphoric Acid
Steam Condensate from Ammonia
Recovery
Stripped Gas Liquor

16,500

21
406
(185 2)
N.D.

937
(411.3)
N 0.
N.D
566
(297.7)
416
(196.5)
(27 3)

8
(3.8)
N.D.
N.D.
N.D.
(0.03)
N.D
(0.70)
7.6 LTPSO
(0 01)
106

558
(279 7)
Components , 1 b/hr
C02
N.O.**

0
0

0

0

0
0
2,2/S

0

0

20

0
0
0
0
0
0

0
0

0

NH3
0*i

0
0

0

0

0
0
1,758

0

0

17

0
0
0
0
0
0

0
0

4

HJ.S
0

0
0

0

0

0
0
0

0

0

0

0
0
0
0
N.D.
0

0
0

0

TDS & TSS
8,266

22
0

0

0

0
0
N D.

0

0

29

0
0
0
2.6
N.D.
0

0
0

471

Organics
N.D.

N D
185,160

N.D

411,330

N.D.
N.D.
236

196,510

26,990

N.D.

N.D.
N.D.
N.D.
N.D.
N.O.
0

0
0

170

«S0
8,250,000

10,500
0

0

0

0
0
293,000

0

270

3,735

N.O.
H.D.
N.D.
N.O.
N.D.
0

N 0
53,000

279,076

                                                                         (Continued)

-------
                                                                          TABLE 4 1-4  (cont.)
00

Stream
Number
(Table No )
71
(4 2-21)
75*
(4 2-23)
76*
(4 2-23)
77
78*

79

80

81

82

83

84

85
86

87

88*
89

90*
91*
Stream Nass Flaw, 9pm
Description
Anhydrous Ammonia to Storage

Excess Mine Water to Aeration
Pond
Aerated Water to Discharge

Feedwater to Waste Heat Boiler
Total Processed Shale
HoHtenlng Water
Cooling Water to Lurgi Oil
Recovery
Cooling Water to Naphtha
Recovery
Steam Condensate from Naphtha
Stri pper
Cooling Water to Compression
Cool i ng
Cooling Water to DEA-TEG
Treatment
Steam Condensate from DEA-TEG
Treatment
Steam Condensate from Stretford
Cooling Water Makeup to
Stretford
Process Water Makeup to
Strstford
Humidified Air Cooler Slowdown
Cooling Water to Ammonia
Recovery
Water for Dust Palliatives
Processed Shale Re«egetdtion
(103 Ib/hr)
(1 9)
22 6 TPSD
8,330

8,330

2,120
5,624

325

5

20

8

66

260

2
2

3

661
1,080

1,568
649


C02
0

0

0

0
0

0

0

0

0

0

0

0
0

0

0
0

0
0


NH3
1,883

0

0

0
0

0

0

0

0

0

0

0
0

0

0
0

0
0


H2S
0

0

0

0
0

0

0

0

0

0

0

0
0

0

0
0

0
0
Components, Ib/hr

IDS & TSS Qrganics
0 0

4,170 N D

4,170 N D.

SO NO
NO. N D

163 0

25 0

0 0

4 0

33 0

0 0

0 0
1 0

0 0

496 0
540 0

784 0
325 0


M
N 0

4,165,000

4,]65,000

1,060,000
2,812,000

162,500

2,500

10,000

4,000

33,000

130,200

1,000
1,000

1,500

330,500
540,000

784,000
J24.500
                             Water



                                                                                                                                      (Continued)

-------
                                                                           TABLE 4.1-4  (eont.)
00
00
Stream
Number
(Table No.)
92*
(4.2-3,
4 2-4)
93*
94
95*
96*
97

98
99*
101*

102*
103*
104*

105*
106*
108*

109*

111*
Stream Mass Flow, qpm
Description (W Ib/hr)
Raw Shale Leachate


Storm Runoff
Boiler Feedwater Makeup
Service and Fire Water
Mine Water Clarifier Sludge
Water to Cooling Tower
Makeup Treatment
Treated Water to Cooling Tower
Potaole/Samtary Water
Used Sanitary Water to
Municipal Treatment
Treated Sanitary Water
Sanitary Water Treatment Sludge
Boiler Feedwater Treatment
Concentrate
Cooling Tower Slowdown
Cooling Tower Drift
Equalization Pond Discharge to
Processed Shale Moistening
Clarified Mine Water to
Processed Shale Moistening
Aerated Pond Sludge
N D


150
43
43
165
2, $76

2,676
26
16

18
N 0
11

1,123
9
2,525

2,912

N 0
Components, Ib/hr
C02
0


0
0
0
0
0

0
0
0

0
0
0 ,

0
0
0

0

0
Ml,
4.6
fig/]

0
0
0
0
0

0
0
0

0
0
0

0
0
0

0

0
HZS
0


0
0
0
0
0

0
0
0

0
0
0

0
0
0

0

0
TDS 4 TSS
3,490
nig/1

N D
1
22.5
M.O
1,340

1,340
13
N.D

N 0
N.D.
N D

842
5
N.D.

1,096

H D
Organics
13
mg/1

N.D
0
0
N D.
0

0
0
N D.

0
N.O.
N.D.

N D.
0
N.D.

0

H D.
H20
N 0.


75,000
21,500
21,500
82,500
1,338,000

1,338,000
13,000
9,000

9,000
N.O
5,500

561,500
4,500
1,262,500

1,456,000

N.D
           * Indicates streams that cowe into contact with the environment


           **N D  = Not determined, 0 = Estimated to be insignificant (less than 1 !b)


           Source   DR1 estimates based on information from Gulf Oil  Corp  and Standard Oil  Co  (Indiana),  March 1976,  and Rio Blanco Oil  Shale Co.,

                    february 1981.

-------
                                                             TABIF 455   INVENTORY Of SOLID STREAMS
00
10
Strean
Number
(Tdbla No.) Deitrlption of Stream
1* Raw Shale Feed
(4 2-2)


2* Sufaore



3* Overburden


22* Baghouse Dusts
. (4.2-2J

29" Process ad Shale
{4,2*5>
4,2-6,
4.2-7)
43 Oily Dust



68 Caustic (MaOH)




Mai.i Flow, Components Mass Flow of
TO3 Ib/hr of Concern Component, lb/hr Remarks
9,799 Participates 118,100 Oust collection and suppression are
employed to minimize the particulate
emissions from tha raw shale handling
operations
992 Participates 520 The subore is crushed and disposed of
with the processed shale. The dust
from crushing is control lad with
baghouies.
5,175 Particulates 2,730 The overburden is crushed and disposed
of with the processed shale. Oust from
crushing is controlled with baghouses.
118 1 -- -- This dus.t is collected from raw shale
handling operations and combined with
the raw shale for retorting.
9,733 Particulates 2,820 The processed shale is properly
teachable Salts 280,000 moisturized to reduce dust emissions.
Proper compaction should reduce water
permeability, hence leaching of salts.
78.6 Adsorbed Oil N D c This dust is obtained from heavy oils
Residual Organlcs ~1,8QO deducting It is Incinerated in the
lift pipes alonfl with the bulk of the
processed shale.
0.3 — •- Caustic 1s added to the ammonia
recovery process to nake up the reagent
losses as well as to release the fixed
ammonia.
,
       * Indicates  slreams  that come  into contact with  the  environment
       * The  remarks Indicate  the stream disposition.   The  controls  and treatments applied  to  the streams are  those  proposed for the  Ltirgi-Open  Pit
         technologies.
         Dashos  (--)  Indicate no  known  components of  concern.
       c N.D,  =  Hot determined.
       Source:   DRI  estimates based on  information  from Gulf  Oil  Corp.  and  Standard Oil  Co.  (Indiana),  March 1976, and Rio Blanco 011 Shale Co t
                February  1981.

-------
                                                     TABLE 4,1-6,   COMPOSITIONS Of SOLIO STREAMS
Stream
Number
(Table No )
1*
(4.2-2)
2*
3*
22*
(4.2-2)
29*
g (4.2-5,
4 2-6,
4.2-7)
43
68
Stream
Description
Raw Shale Feed

Subore
Overburden
Baghouse Dusts

Processed Shale



Oily Dust
Caustic (NaOH)
Mass Flow,
10J Ib/hr
9,799

992
5,175
118.1

9,733



78.6
0.3
Components,3 103 Ib/hr
H ' "" 0
131 73

N.O.15 N.D
N.D. N.D.
2" 1

0 2



0 0 02
0 0
N
40

N.D.
N.D.
0.2

a



0.06
0
C
1,025

N.D.
N.O.
12

24



0.19
0
S
98

N.D.
N.D,
1

91



0.73
0
H20
261

N.D.
N.D.
3

1,820



0
0
* Indicates streams  that  come  Into  contact with  the  environment.
  Elements reported  for organic portion of materials,  except  for  sulfur which 1s  total,
  N.D.  = Not determined;  0 = Estimated to be  insignificant (less  than 1 1b).
Source   DRI estimates based on information from Gulf  Oil  Corp. and Standard  Oil  Co   (Indiana),  March 1976,  and Rio Blanco 011  Shale Co.,
         February 1981

-------
4,2  MAJOR STREAM COMPOSITIONS

     Much  of  the  significant data  for the  Lurgi-Ruhrgas  retorting  process
have  beer« proprietary  in the past  and largely  remain so  at  present.  The
limited  information  that is  available has  been extracted  from Rio  Blanco
Oil  Shale Company's  (RBOSC) Modification  to the Detailed  Development  Plan
(DDP)  (February 1981)  and  communications  with  RBOSC  and  Lurgi  Kohle und
Minera'otechnik  GmbH  personnel.   Some generalized information on the  stort-
ing technology is also published and this was used when  appropriate (iMarnell,
Septasser 1978;  Schmalfeld, July 1975).

     In the  following sections,  major streams generated from different plant
operations (see  Section 3) are listed along with their detailed compositions.
Material balances for selected streams (both before and after treatment) are
also presented.  When detailed information on stream compositions or perform-
ance of a control technology was not available, calculations were made  on the
bas"'s c"? engineering analysis.

4.2.1  Material  Balance

     The material balance for retorting 23 gpt oil shale by the Lurgi-Ruhrgas
process  is   presented  in Table 4.2-1.   This  balance  is  for the  retorting
process only.   The  amount  of raw shale  retorted (119,000 TPSD)  is  derived
froot  the original  DDP   (Gulf  Oil  Corp.   and Standard  Oil Co.  [Indiana],
March 1976).   The combustion air,  processed shale, quenching and moisturizing
water, net retort gas, and flue gas quantities have been calculated using the
modified DDP  (Rio Blanco  Oil  Shale Co., February 1981)  for  the  Lurgi demon-
stration project.   Amounts  of oil,  naphtha,  and retort gas  have been esti-
mated  assuming  a 100%  Fischer assay  oil  yield and,  also,  by material  and
elemental balances.   After pyrolizing the shale, the amount of coke remaining
is insufficient  for  raising  the  recycle shale stream to the desired tempera-
tare of about 1,240°F; therefore,  a portion of the retort gas (before naphtha
removal) is  added to the lift pipes as supplemental  fuel.

4.2.2  Raw Oil Shale

     The exact composition of the  raw shale was not available.   Therefore, an
estimation v/as made  using the published analyses of different grades of Green
River oil  shale and  its kerogen (Stanfield,  et al.,  1951).   The estimates are
fairly reorasentative of expected  values and are further strengthened by good
overall material and elemental balances.   Derived  composition  for  the  raw
shale :s presented in Table  4.2-2.

     Raw iSha]eii leachate—

     Recently, some  literature on  leachates  from Colorado oil shales has been
published  (McWhorter, 1980;   Rio  Blanco  Oil  Shale  Co.,  March 1981).   The
results cf  laboratory column  leaching  experiments  from the  first  reference
are presented  in Table 4.2-3.  The second  reference  provided field lysimeter
study results from Tract C-a run-of-mine stockpile tests, and these are shown
in 'able 4.2-4.
                                     91

-------
      TABLE 4.2-1.  GROSS MATERIAL BALANCE FOR RETORT AND SHALE BURNER

Material In
Raw Shale
Air
Makeup Water3
Total In
Material Out
Processed Shale
Retort Gas (net, naphtha- free)c
Gas Liquor
Product Oil
Naphtha (net)d
Flue Gas
Total Out
Flow, 103 Ib/hr
9,917
5,439
2,812
18,168
Flow, 10s Ib/hr
9,733
122
298
793
27
.1,135
18,168

  The makeup water includes 992 x 103 Ib/hr for processed shale quenching
  and 1,820 x io3 Ib/hr for processed shale moisturizing to a moisture
  content of approximately 19% by weight.

  The processed shale is burned (after the lift pipes) and includes the
  moisturizing water.  The processed shale quantity on a dry basis would be
  7,913 x 10s Ib/hr.

c The net retort gas quantity is that remaining after subtracting
  87.4 x 103 Ib/hr of the gas used in the lift pipes.

  The net naphtha quantity is that remaining after subtracting
  19.6 x io3 Ib/hr of the naphtha used along with the retort gas in the
  lift pipes.

Source:   ORI estimates based on data from Rio Blanco Oil Shale Co.,
         February 1981.
                                     92

-------
                   TABLE 4.2-2.  COMPOSITION OF RAW SHALE*
                               (Streams 1, 22)

Component
Raw Sha'e
Hydrogen (organic)
Moisture
Oxygen (organic)
Nitrogen (organic)
Caroon (organic)
Sulfur (total)
Weight
Percent
100. 00
1.34
2.66
0.75
0.40
10.46
1.00
Mass Flow,
10s Ib/hr
9,917
133
264
74
40
1,037
99
Flow,
103 Ib-moles/hr
—
133.0
14.7
4.6
2.9
86.4
3.1

* Based on 65,167 BPSD crude shale oil  at 100% Fischer assay yield, with
  23 got oil shale.   Baghouse dusts are included.

Scurcs:  DRI estimates based on information from Stanfield,  et a!., 1951.
                                     93

-------
                                      TABLE  4.2-3
                                                     LABORATORY  COLUHN  LtACHATfS  FROM SOME  COLORADO RAW OIL SHALES
                                                                       (Stream 12)
USBM Raw Shale
Component Unit (Saline ione)
«
As
B
Ba
Be
Ca
Cl
CQ3
Cr
Cu
EC
F
Fe
HCQ,
Hg
K
Li
Mg
Mn
HO
Na
Ni
NDa
Pb
pH
Se
Si
Sn
SO,
TDS
In
mq/1 0 34
" <0.
" 0.24
" 0 061
" <0.
" 36
" <1 0
0.1
" <0.025
" <0.025
|jn>hos/cm 280
mg/1 9 5
" 0 01
" 83.1
" <0 0001
1 1
0.02
" 6 7
" 0 075
" 0.09
11 <25
11 <0 025
" <1.25
" <0 04
68
rng/1 <0
" 1.65
<0 025
11 20
" 70
" 0 01
- 7.54
005
- 43
- 0 17
025
- 750
- 560
-11
- 0.68
- 0 30
- 13,000
- 75
- 1 8
- 321
- 0.0035
- 22
-3.1
- 1,050
-32
- 0.87
- 1,430
- 0.60
- 40
- 1.9
- 8.06
01
-97
- 1.28
- 5,700
- 13,300
-68
Colony Raw
Shale
0.05
<0
<0.025
0 07
<0.
40
1 I
0 03
<0.025
<0 025
240
4.0
<0 03
50
<0
1 7
0.02
5.5
0 074
0.09
5.8
<0.05
0 9
<0 05
7.06
<0
2 12
0.12
28
110
<0.02
- 0 75
005
- 2 75
- 0 48
025
- 1,550
- 22
-16
- 0.04
- 0 41
- 5,400
-72
- 0.89
- 558
0005
- 59
- 0.151
- 140
- 2.74
- 0.65
- 145
- 0.10
- 25
- O.S4
- 8 18
01
- 10 58
- 0 67
- 5,150
- 7,160
- 0 68
C-a P-5/Mahoq
Shale
0 3

-------
             TABLE 4.2-4.   LEACHATE WATER QUALITY  DATA  FROM THE
                       TRACT C-a  RUN-OF-MINE  STOCKPILE
                                  (Stream 92)
Constituent
Concentration*  Constituent
Concentration*
Alkalinity  (mg/1 as CaC03)    48.0
Alumir)um                      10.0
Arsenic                        2.0
Bar-*u~,                       100.0
Beryllium                      0.0
Boron                        150.0
Cadmium                        0.0
Calcium (mg/1)               440.0
DOC (mg/1)                    13.0
Chloride (mg/1)               29.0
Chromium                       0.0
Cobalt                       100,0
Copper                         8.0
Fluoride (mg/1)                2.4
Hardness (noncarbonate)
         (mg/1)            2,300.0
Hsrdness (total) (mg/1)    2,300.0
Iron                          60.0
Lead                           0.0
Lithium                       50.0
Hagnesium (mg/1)             300.0
Manganese                    220.0
Mercury                        0.0
Holybdanun                   270.0
NicKel                          37.0
                Nitrate-Nitrite (as N)      45,0
                Ammonia (as N)               4.6
                Kjeld-N (as N)               9.1
                DON (as N)                   4.5
                Total  Nitrogen (as N)       54.0
                pH (field)                   7.7
                pH (lab)                     7.1
                Phenols                      3.0
                Total  Phosphorus (mg/1)      0.0
                Potassium (mg/1)             3.5
                Potassium 40 (pc/1)          2.6
                TOS (calculated) (mg/1)  3,490.0
                SAR                          1.6
                Selenium                     0.0
                Silica (mg/1)                 4.6
                Sodium (mg/1)               180.0
                Sodium (%)                   14.0
                Spec.  cond.  (field)
                            (|jmhos/cm)    3,950.0
                Spec.  cond.  (lab)
                            (umhos/cm)    3,877.0
                Strontium                3,000.0
                Sulfate  (mg/1)            2,300.0
                Vanadium                     4.0
                Zinc                          50.0
* All concentrations are expressed in pg/1, unless listed otherwise, and
  apply to the dissolved fraction only.
Source:  Rio Blanco Oil Shale Co., March 1981.
                                     95

-------
4.2.3  Processed Shale

     The quantity and composition of the processed shale, derived by material
and  elemental  balances,  are presented in Table 4.2-5.  Due to burning of the
processed  shale  in  the lift pipes and extensive recycling to the retort, the
residual  organic matter  is  fairly low.  The  moisturizing water  amounts  to
approximately  23%  of the dry processed shale  weight.   Major inorganic ele-
ments in the processed shale obtained from a retorting test on oil shale from
Tract C-a  are  presented  as  their  oxides  in  Table 4.2-6.   Some  physical
properties of  the processed shale have also been determined and are presented
in Table 4.2-7.  Due to partial calcination in the lift pipes, the processed
shale has  good cementitious properties.   The unconfined compactive strength,
at  optimum moisture content  and curing period, is high  and  permeability  is
low.
        TABLE 4.2-5.  COMPOSITION OF THE PROCESSED MOISTURIZED SHALE
                                 (Stream 29)

Component
Retorted Shale
(moisturized)
Moisture
Oxygen (organic)
Nitrogen (organic)
Carbon (organic)
Sulfur (total)
Weight
Percent
100.00
18.70
0.02
0.08
0.25
0.93
Mass Flow,
10s Ib/hr
9,733
1,820
2
8
24
91
Flow,
10s Ib-moles/hr
._
101.1
0.1
0.6
2.0
2.8

Source:  DRI estimates  based  on information from Rio Blanco  Oil  Shale  Co.,
         February 1981.
     Processed Sha1e Leachate—

     The  results  from  column  leaching  of  processed  shale  are  given  in
Table 4.2-8  (Woodward-Clyde  Consultants,  October 13,  1980).   Some  soluble
elements  are reported  as  their  oxides.   As  seen in  Table 4.2-7,  properly
moistened  and compacted processed  shale  has  low permeability;  therefore,
actual  field leaching may  not be represented by  laboratory  column leaching
experiments.
                                     96

-------
           TABLE 4.2-6.  INORGANIC ANALYSIS OF THE PROCESSED SHALE
                                 (Stream 29)

Component
Silicon Dioxide
Iron Oxides
Aluminum Oxide
Calcium Oxide
Magnesium Oxide
Sulfate
Sodium Oxide
Potassium Oxide
Carbonate
Chloride
Loss on Ignition
Weight Percent
46.00
4.40
12.70
22.40
4.80
3.80
3.20
2.70
4.40
0.08
4.60

Source:   Woodward-Clyde Consultants, October 13,  1980.   The results are for
         processed shale from a retorting test on Tract C-a oil  shale.
                                     97

-------
                                                      TABLE 4.2-7.
PHYSICAL PROPERTIES OF PROCESSED SHALE
       (Stream 29)
u>
00
Gradation

0*
u
I .
c:
'x 8
Test Condition * «
3/8
As Received |^|
Compacted — <
1/2 0 698
(6,200 ft-lbs) --





Compacted
0 698
(12,375 ft-lbs) —





Compacted
D 1557
(56,250 ft-lbs) --







?
S
O
0
fr
o
M
17
15
16
.1
.3
.2
17.6
15
15




16
18
5
.5




.2
.8
8.8





16
0.
12










.2
1
8






c.
in
I



i
o
o
i
« i



i
4-
01
•r- O IS U
V*O (/I O
MO « «
47.
46
48.
44.
37.
37.




48,
44.
8
4
2
2
9
9




2
2
42. S





48.
56.
45.










2
3
9





33.
36.
35%
4
6
6
38.2
4ft.
46.




35.
37,
48.





35.
43.
41.





6
6




6
0
7





6
6
3





1.
1,
0.
0.
0.
0.




0.
0.
0.





0
0
0





,7
7
.0
.0
.0
.0




0
0
.0





0
0
0





Remarks

Initial
After Compaction
After TrlaxiaJ
Shear Test




Initial
After Compaction
After TriaxlaT
Shear Test




Initial
After Compaction
After Triaxlal
Shear Test




Permeability
Compaction ft/yr Shear Strength
Triaxla! Shear . line
ft* <*• oft c: u.
>» 3 C '»- O
•*-» +* >> ra i» £i
mow) *r~ Ol «1 « O> •> in O fSl
t3 0) CL C ^C O T?
u 0, -p~ "a T^ T3u*-aiu_ 01 3' tfi
VOX m ««•!-«+> -C *J-r- >,
V) d< % _l .1 ^U.O»-tOO M0. O
2.83
2.84
30 3 85.6 0.002 0.003 — 0.69 34.5 22.2 7.6 0
0
7
7
14
14
28
28
28.5 88.2 0.003 0.005 ~ 0.62 32.0 33 3 13.9 0
0
1
7
14
14
28
28
23 2 96 8 0 001 0.001 — 0.80 38.5 41.0 27.8' 0
0^
?"~
7
14
•>•"-,- 14
28
28

onf inert
a,
'I
c £
if

28.8
33.1
590-7
785.9
575,0
682.4
—
~~
38.5
42. S
874,5
865,5
940.8
912. i
1,222.2
1,222.1
378.5
3SO.fi
971.1
1,182.6
986.5
1,081.0
-*•

         Source-  Woodward-Clyde Consultants, October 13, 1980.  The results are for processed shale from a retorting test on Tract C-a oil shale

-------
         TABLE 4.2-8.  ANALYSIS OF LEACHATE FROM THE PROCESSED  SHALE



          Component                               Concentration, mg/1

          Si1icon Dioxide                                 18
          Iron Oxides                                     <0.01

          Aluminum Oxide                                  <0.1
          Calcium Oxide                                1,080

          Magnesium Oxide                                102

          Sodium Oxide                                   337

          Potassium Carbonate                             37

          Carbonate                                       90

          Bicarbonate                                     <0.1

          Chloride                                        28

          Sulfate                                      1,810
          Hydroxide                                      222

          Total Dissolved Solids                       3,530

          pH = 11.4


Source:  Woodward-Clyde Consultants,  October 13, 1980.   The results are for
         processed shale from a retorting test on Tract C-a oil shale.


4.2,4  Crude Shale Oil

     The  composition  of  vapors  from  the  Lurgi   retorts  is  indicated  in
Table 4.2-9.   The  Lurgi  retorts  also include  three  condensation-absorption
towers;  consequently,  a product  breakdown  of the condensable hydrocarbons
occurs, forming heavy, middle and light oil fractions.   The properties of the
individual  oil  fractions  are  indicated  in Table 4.2-10.   Since  the  naphtha
tract*'on  is still  contained  in  the gas  phase,  it is  not included  in  the
table.   The physical  properties  for each oil  fraction  have  been  estimated
using the oil distillation  data published in RBOSC's modified DDP (Rio Blanco
Oil "shale  Co.,  February 1981).   The composition for the combined  shale  oil
has been calculated by material and elemental  balances  and from data provided
by Occidental Oil  Shale,  Inc.

4.2.5  Retort Gas

     The heavy oils  and most of the entrained  dust in  the retort vapors  are
eliminated  in  the  first condensation  tower.   The  middle  oil  fractions  are
condensed in the second tower by reducing the  vapor temperature  to 150°F by
wet cooling.  The light oils, naphtha, water,  and noncondensable gases remain

                                     99

-------
                 TABLE 4.2-9.
COMPOSITION OF RETORT VAPORS
  (Stream 26)

Component
H2
CO
C02
N2
NH3
H2S
S02
CH4
C2H4
C2H6
C3H6
£3%
C4H8
C4H10
r +
L4
Light Oils
Middle Oils
Heavy Oils
Miscellaneous
HC
H20
TOTAL
MWt
MWt
2
28
44
28
17
34
64
16
28
30
42
44
56
58
79.4
114
166
274
132.6
18

Mass 5
0.37
0.53
7.31
0.53
0.14
0.09
0.02
1.41
0.91
0.93
1.16
0.63
1.02
0.31
1.77
15.28
30.69
14.59
0.02
22.28
99.99

K Mole %
8.20
0.84
7.39
0.84
0.37
0.12
0.01
3.91
1.44
1.38
1.23
0.63
0.81
0.24
0.99
5.96
8.22
2.37
0.01
55.03
99.99
44.45
Mass Flow,
103 Ib/hr
4.97
7.14
98.46
7.14
1.92
1.20
0.26
18.95
12.24
12.57
15.68
8.42
13.77
4.23
23.87
205.77
413.24
196.51
0.24
300.05
1,346.63*

Flow,
Ib-moles/hr
2,486.6
255.0
2,237.7
255.0
113.2
35.2
4.0
1,184.1
437.2
419.0
373.4
191.3
245.9
72.9
300.6
1,805.0
2,489.4
717.2
1.8
16,669.4
30,293.9


* In  addition,  approximately  78,600 Ib/hr  of processed shale  dust are
  entrained  in  the retort vapors.   The  presence of COS and  other  organic
  sulfur compounds has not been determined.

Source;  DRI  estimates based  on  data  from  Rio Blanco Oil  Shale  Co.,
         February 1981, and provided by Occidental Oil Shale, Inc.
                                     100

-------
                                TABLE 4.2-10.   PROPERTIES  OF  NAPHTHA-FREE  SHALE  OIL
                                               (Streams  36, 38,
M
O
....H— -I...— 	 1 	 	 ....1^-*. *~, . v™-".— *— *"-»- 	 : 	 ~
Component
Heavy Oils (Stream 42)
Middle Oils (Stream 38)
Light Oils* (Stream 36)
TOTAL SHALE OIL
Composition
Hydrogen
Oxygen
Nitrogen
Carbon
Sulfur

'••---- - -•• • • ' "
Boiling Volume Gravity,
Point, °F Percent (BPSD) °API
-360-920 23.65 (14,260) 18.5
-270-920 53.27 (32,120) 30.0
-290-510 23.08 (13,920) 24.0
-270-920 100.00 (60,300) 25.5

—
—
—
—
—

.
Weight
Percent
24.78
51.87
23.35
100.00

11.47
1.37
2.05
84.25
0.86


Mass Flow,
103 Ib/hr
196.51
411.33
185. 16
793.00

91.00
31.00
16.00
668.00
7.00


Flow,
Ib-ntoles/hr
717.20
2,477.90
1,624.20
4*819.30

91.00
0.69
1.14
55.67
0.22

    * The light  oils  are  stabilized.  API gravity  for  the  light  oils  before  stabilization  is  36.5°.

    Source:   DRI  estimates  based on data from  Rio  Blanco Oil  Shale  Co.,  February  1981,  and provided  by
   !          Occidental Oil Shale, Inc.

-------
                    TABLE 4.2-14.  COMPOSITION OF NAPHTHA
                                 (Stream 46)

Component
Cs^ia
CeHg
C6H14
C?Hi6
Light Oils .
Middle Oils
H20
TOTAL
MWt
Total H
Total C
MWt
72
78
86
100
78
166
18




Mass %
25.22
1.52
18.39
5.83
43.97
4.08
0.99
100.00
77.81
12.17
86.84
Mole %
27.25
1.51
16.64
4.54
43.86
1.91
4. 28
99.99



Mass Flow,
103 Ib/hr
6.88
0.41
5.01
1.59
11.99
1.11
0,27
27.26

3.32
23.68
Flow,
Ib-moles/hr
95.5
5.3
58.3
15.9
153.7
6.7
15.0
350.4

3,318
1,973

Source:  DRI estimates based on data from Rio Blanco Oil Shale Co.,
         February 1981.
                                     106

-------
         TABLE 4.2-15.  COMPOSITION  OF  RETORT GAS AFTER COMPRESSION
                                  (Stream  48)

Competent MWt
H2
CO
C02
«2
NH3
H2S
CH4
^2^-4
C2HS
C3h6
C3hs
Ms
£4^10
H20
TO
MWt
Total H
Total 0
Total N
Total C
Total S
Heating
2
28
44
28
17
34
16
28
30
42
44
56
58
18
TAL

(excluding
(excluding



Value, LHV
Mass %
2.45
3.52
47.45
3.52
0.0014
0.59
9.35
6.04
6.20
7.74
4.15
6.80
2.09
0.08
100.00
24.86
H20) 10.12
H20) 36.52
3.52
49.18
0.56
Btu/lb (Btu/SCF)
Mole %
30.51
3.13
26.81
3.13
0.0021
0.43
14.53
5.37
5.14
4.58
2.35
3,02
0.89
0.11
100.00






10,010
Mass Flow,
10s Ib/hr
2.89
4.16
55.96
4,16
0.002
0.70
11.03
7.13
7.32
9.13
4.90
8.01
2.46
0.10
117.95

11.94
43.08
4.16
58.01
0.66
(656)
Flow,
Ib-moles/hr
1,447.3
148.4
1,271.9
148.4
0.1
20.5
689.2
254.5
243.9
217.3
111.3
143.1
42.4
5.4
4,743.7

11,937
2,692
297
4,834
21


Source:  DRJ  estimates  based  on data  from Rio  Blanco Oil  Shale Co.,
         February 1981.
                                     107

-------
        TABLf 4.2-16.
COMPOSITION OF RETORT GAS AFTER AMINE ABSORBER
          (Stream 56)

Component
H2
CO
C02
N2
NH3
H2S
CH4
C2H4
C2H6
CsH6
CsHg
C4Hg
£4^10
H20
TOTAL
MWt
MWt
2
28
44
28
17
34
16
28
30
42
44
56
58
18

Total H (excluding
Total 0 (excl
Total N
Total C
Heating Value
uding


, LHV
Mass %
4.68
6.71
1.00
6.71
0.0027
0.0005
17.82
11.52
11.82
14.75
7.91
12.95
3.97
0.14
99.98
17.86
H20) 19. 22
H20) 4. 58
6.72
69.32
Btu/lb (Btu/SCF)
Mole %
41.77
4.28
0.41
4.28
0.0029
0.0003
19.89
7.35
7.04
6.27
3.21
4.13
1.22
0.14
99.99





19,080 (900)
Mass Flow,
103 Ib/hr
2.89
4.16
0.62
4.16
6.0017
0.0003
11.03
7.13
7.32
9.13
4.90
8.01
2.46
0.09
61.90

11.90
2.83
4.16
42.92

Flow,
Ib-moles/hr
1,447.3
148.4
14.1
148.4
0.1
0.01
689.2
254.5
243.9
217.3
111.3
143.1
42.4
4.8
3,464.8

11,896
177
297
3,576


Source:  DRI  estimates based  on data  from  Rio  Blanco Oil  Shale Co.,
         February 1981.
                                     108

-------
                TABLE 4.2-17.  COHPOSITION OF DRIED  FUEL  GAS
                                  (Stream 57)

Component MWt
H2
CO
C02
N2
NK3
H2S
CH4
C-2^4
^2^6
C3H6
C3H8
£4^3
C4H13
H20
i%'t
Tola"
Tctai
Total
Total
heati
2
28
44
28
17
34
16
28
30
42
44
56
58
18
TCTAL

H (excluding
0 (excluding
N
r
ng Value, LHV
Mass %
4.68
6.72
1.00
6.72
0.0028
0.0006
17.84
11.53
11.84
14.77
7.92
12.97
3.98
0.01
99.98
17.
H20) 19.24
H20) 4.58
6.73
69.41
Btu/lb (Btu/SCF)
Mole %
41.82
4.29
0.41
4.29
0.0029
0.0003
19.92
7.35
7.05
6.28
3.22
4.14
1.23
0.01
100.01
86




19,080
Mass Flow,
10s Ib/hr
2.89
4.16
0.62
4.16
0.0017
0.0003
11.03
7.13
7.32
9.13
4.90
8.01
2.46
0.0090
61.82

11.90
2.83
4.16
42.92
(900)
Flow,
Ib-moles/hr
1,447.3
148.4
14.1
148.4
0.1
0.01
689.2
254.5
243.9
217.3
111.3
143.1
42.4
C.5
3,460.5

11,896
177
297
3,576


Source:   DRI estimates based on data from Rio Blanco Oil Shale Co.,
         February 1981.
                                     109

-------
                           TABLE 4.2-18.   MATERIAL BALANCE AROUND STRETFORD UNIT
                                       (Streams  58, 61,  63, 64,  66)

Component
H2S
C02
N2
02
H20
Sulfur (S8)
TOTAL
MWt
34
44
28
32
18
256
Acid Gases From
OEA Regeneration
(Stream 58)
Ib/hr
696
55,344
--
__
1,033
__
57,073
Acid Gases
After Stretford
(Stream 63)
Ib/hr
1.3
52,023.0
—
—
956.0
—
52,980.3
Stripping Air
(Stream 61)
Ib/hr '
—
—
16,117
4,633
126
__
20,876
Stretford Oxidizer
Vent Gas
(Stream 64)
Ib/hr
__
3,321
16,117
4,285
597
--
24,320
Stretford
Sulfur
(Stream $6)
Ib/hr (LTPSD)
—
—
—

—
695 (7.56)
695

Source:   SWEC  estimates  based  on  information  from  Peabody  Process  Systems,  Inc.,  February  1981.

-------
levels  of  pollutants emitted, different flue  gas  compositions have not  been
calculated.
         TABLE 4.2-19.
COMPOSITION OF FLUE GAS FROM THE LIFT PIPES
         (Stream 31)

Component MWt
N2
02
C02
H2G
Sr»
U£
CO
NOx
HC
TPM
28
32
44
18
64
28
31.08
16
--
Mass %
57.91
4.90
20.04
16.99
0.0069
0.0092
0.0339
0.0869
0.0154
Mole %
57.01
4.22
12.56
26.02
0.0030
0.0090
0.0300
0.15
—
Mass Flow,*
10s Ib/hr (10s SCFM)
4,170.90
353.12
1,443.63
1,224.00
0.50
0.66
2.44
6.26
1.11
(942.13)
(69.79)
(207.51)
(430.08)
(0.05)
(0.15)
(0.50)
(2.47)
--
     TOTAL
   99.99
100.00
7,202.62  (1,652.68)
MWt
          27.56
Total H (excluding H20)     0.02

Total 0 (excluding H20)    19.51

Total N                    57.92

Total C                     5.54

Total S                     0.0035
                                   1.57

                               1,405.00

                               4,172.00

                                 398.70

                                   0.25
* S02,  NOx, and CO assumed to be 30, 300, and 90 ppmv, respectively, in the
  flue  gas.  Participate matter estimated to be 1,107 Ib/hr.   Includes steam
  frorp  the quencher.

Source:  DRI estimates based on data from Rio Blanco Oil Shale Co.,
         February 1981.


4.2.7  Gas Liquor

     The majority  of the gas  liquor  (stream 41)  is obtained as  a result of
the moisture  condensation in  the  third tower.   An additional  amount  of the
                                     111

-------
liquor  is  produced  as  the  compression cqndensate  (stream 49) during  the
retort gas  compression.   These streams -are combined  to  form the feed to the
ammonia  recovery plant  in which anhydrous  ammonia  is  recovered  as  a  by-
product.  The  compositions of the gas  liquor  and  compression condensate  are
given  in  Table 4.2-20,   while Table 4.2-21  presents  the  material  balance
around  the ammonia  unit.  NaOH  is  added  to  release ammonia  from  ammonium
sulfite.

4,2.8  Mine Water

     Two aquifers are intercepted during the open pit mining.   The  composi-
tion of  the aquifer waters, along with the values adopted in this manual, is
presented in Table  4.2-22.  Excess mine water,  after process needs,  is held
in an aeration pond to reduce the alkalinity  and  to  oxidize/consume organic
matter.   The composition of water ready for surface discharge is presented in
Table 4.2-23.

4.3  POLLUTANT CROSS-REFERENCE TABLES

     Tables 4.3-1 through  4.3-3  list some pollutants of  concern, by  medium,
and provide a  cross-reference to the numbered  streams in this manual.   Many
of  these pollutants  are  trace  constituents,  and measurements  to  identify
or  quantify them  in oil  shale  processing related  streams   have never been
made.   Those pollutants  which have been identified in the plant streams are
cross-referenced  to the  detailed composition tables.   Engineering  judgment
was used in identifying  other probable pollutants.   The  entry for  "unknown"
(U) indicates that no testing has been done and the presence  of the  pollutant
is  unlikely.   Judgment  was  also used  in  specifying the  pollutants  which
definitely should not be present.
                                     112

-------
                     TABLE 4.2-20.   COMPOSITION Of TOTAL FEED TO AMMONIA RECOVERY UNIT
                                             (Streams 41, 49)

" " " ' " ' "u «'.»'-
•
"""'*' "**

Gas Liquor (Stream 41)


P
U)



Component
NH3
COg
(NH4)2S03
Stripjlafctle
Organlcs
Nonstrippable
Organfcs
H20
TOTAL

Mass %
0.
0.
0.
0.
0.
98.
99.

59
76
13
02
06
43
99
-
Ib/hr (gpm)
1,758
2,275
400
66
170
293,000 (586)
297,669
- .- • -



Compression
Condensate (Stream 49)
Mass %
0.45
0.53
0.76
—
—
98.26
100.00
- - . •
Ib/hr (gpm)
17
20
29
—
—
3,735 (8)
3,801




Total Feed to
Stripper
Mass %
0.
0.
0.
0.
0.
98.
100.

59
76
14
02
06
43
00

Ib/hr
1,775
2,295
429
66
170
296,735
301,470

(gpm)





(594)

Source:   WPA estimates based on information from Rio Blanco Oil  Shale Co.,  February 1981.

-------
                       TABLE 4.2-21.  MATERIAL BALANCE AROUND AMMONIA RECOVERY UNIT
                                           (Streams 70, 71, 72)
.- . . • , , Ammonia,, Recovery :7~-\--^
Stripped' Wastewater " ' Overhead Vapors < Ammonia Product

Component
NH3

C02 ' '•
'
(NH4)2S03

/Qrganics
NaOH*

Na2S03
1
,M20
•' ..,.' TOTAL
'-Feed to-
Mass %
d. 59

•;'• V0.76 •

0.14

Q.,08
0.10

,, — -

98, 33
100. 00
Stripper Col uinn
Ib/hr (gpm)
'; 1,775"
' /
",•2,295'
' t !
429

, 236
' " 301

,;"-'--
,
296,735 (5f4)
301,771
(Stream 70) ^-Jfff (Stream 72) - ? (Stream 71)
Mass %
,0.0014-'',
* '
--.• I:';1'-"
' ' •>* '
, — ' " •
* j - ''
, 0.06'";/
0.0018

' ; 0.17'"r-'-
'-'»
99.77 ..
100.00 ;,
t v Ib/hr, (gpm) ,_/;•_ ^.Ib/hr ' - . _,;^ •, .lb/hr t(TPSO)^ ' -
'•^•'' 4, /'/•' '"''•'•'" 14'. \ ">l.'883f'<22"6);' •/
iv / { "* J ' i i''Y'< ''.""
,./•'• '-7 -;K> *€,{?,*,'295'' -, 'V'? \ffi'l: .'':;'
f , '*•' Is,, t ' ' ! I •> ' i * f
i '„ ^ ' *i_ ; M_ v ^ »-' n :
J ' -J • •, , "'"":>'
,;;; 170.<-; , ' --, ,'*• •- .,' 6,6 - '/'/ ^'7-
,"""7. JS-VT" . *« '' ^ " ' ' ' -—- -"','' •'!'/'"'-''!
' " ^ .- ^ ~~^~r ~' , ' " • -~ -
/ 466,/v r"': :> 7?7^--, •' ''n, . /r7':-^ f"''
. --._ '.;, ''•'. '"/'^•-. ~- "^- i ' ' /'.'""»!- ^ '^
279 ,076 • (558)' ' ''''"'•,- •„.•'' 17; TSZ'.^V^.C. '"'-—"/
"'<'<' '"-
;/ l -


^

'279 ,721 :'"/v- , " '' ^ / "20; 167^T'f'"'^,''^' 1,883' .,'"'-.-;,,
* NaOH is added to the steam stripping column to elevate pH and release fixed famropnia.v

Source;   WPA estimates.

-------
                                                        TABLL 4 2-22.
                                                                       GROUNDUATER QUALITY OF LEASE TRACT C-s

                                                                             (Stiean 4)
H
tn

Parameter
(fflg/1 unless otherwise specified)
Alkalinity
Aluminum
Ammonia as Ml,
Arsenic
Barium
Berylliura
Bicarbonate
Biochemical Oxygen Demand
Boron
Broitn de
Cadini um
Calcium
Carbon, Dissolved Organic
Carbonate
Chloride
Chromium
Chemical Oxygen Demand
CollforiH, Fecal (col/100 ml)
Collform, Total (col/100 ml)
Conduct! «i ty , (J^ho/cm
Copper
Cyanide
Fluoride
Hardness, as CaCO,
Iron
Kjeldahl Nitrogen
Lead
Lithium
Magnesium
Manganese
Hethylene Blue Active Substances
Hercury
Molybdenum
Nickel
Nitrate as N03
Nitrite as N
Nitrogen, Ammonia
pH (units)
Phenols
S ower Aquifer
Mfn.
52
<0,01
0.02
<0 01
<0.1
<0.1
260
—
0.01
<0.02
<0.001
0.80
3.0
'0.1
<0 1
<0. 01
<0.1
—
—
845
<0.01
<0.01
0.3
20
<0.05
--
0.003
0.1
1.9
0 05
..
<0.001
<0.05
<0 001
<0 1
<0.20
0 40
6 0
<0 001
Max.
4,500
1 0
9 6
0 03
<1
<0.1
3,310
—
5 7
<0 1
0.03
98
73
710
160 0
<0.05
92
—
—
5,180
0.3
0 08
85
630
16 2
—
26
0.6
105
0 8
._
<0 01
0 2
<0 1
2
0 60
3 2
a 9
1.0
Avq a
674
0.24
0 59
0 01
<0,97
	 c
842
—
0 84
<0 05
0.0099
B 8
10 5
68 8
21 7
<0 Oil
12 9
"
—
1,459
0 088
0,01
14.69
110
0.78
--
0 21
0 13
20
0,075
—
0 0024
0 I

-------
                                                                        TABLE 4 2-22  (cont.)
M
M
cn
Parameter
(mg/1 unless otherwise specified)
Phosphate, Ortho
Potassium
Radioactivity, (pc/T)
Gross alpha
Radium 226
Gross beta
Selenium
Silica as SiOz
Silver
Sodium
Solids, Dissolved
Strontium
Sul fate
Sulfide
Temperature (°F)
Vanadium
Z1nc
Lower Aqui fer
Mln
<0.10
<1 0

0.1
0.09
2 0
<0 01
<0 1
<0 001
155
540
0 2
<4
<0.01
46 9
<0 05
0.02
Max.
1.
15.

30
0
830
<0
60
0
1,560
3,640
3
580
6,
75
<0
68

0
0

0
9
0
1
0
1


5

SO
2
05
0
Avg
0
2

3.
0.
21
a
11
64

31
31
4
<0.010
10.
0
397
1,075
0
l\Z
0.
56
—
0
1
0089


68

56
5

24
Mm
0 09
<1.0

0 1
0 1
2 0
<0 001
<0 1
0 001
92
530
0 1
<4
0 03
46 4
<0 05
0 01
Upper Aqui fer
Max
1 0
11 0

29 0
0 8
73 0
<0 01
58
0 1
1,170
2,850
10,5
900
49
68.9
<0 05
15 0
Avq s
0
2

3
0
12.
<0
25.
0
212
905
2
325
0
54
—
0.
10
19

48
17
7
0098
6
012
0

89

63
0

26
Values Adopted for Case
Studyb (Stream 4)
0
2.

3
0
17.
<0.
20
0.
317
1,002
1,
204
0
56.
—
0.
11
44

38
25
6
01
3
01


62

59
6

25
  Arithmetic mean for pH and temperature,  geometric mean for all  other parameters
  Based on 43% and 57X of upper and lower  aquifer water production,  respectively
  Dashes (—) Indicate data not reported.
Source-   Gulf Oil  Corp.  and Standard 011 Co  (Indiana), Hay 1977

-------
  TABLE 4.2-23.  COMPOSITION OF EXCESS MINE WATER BEFORE AND AFTER AERATION
                              (Streams 75, 76)

Parameter, mg/1
Alkalinity, as CaC03
Aluminum
.3fiimonia, Total
Arsenic
Boron
Calcium
Chloride
Chromium
COD
Cyanide
Fi uof'da
Lead
Mercu"y
ph (units)
Phenols
Silica
Sodiun
•me
! Le -3
Sulfate
Sulfids
Flow Rate, gpm
Raw Mine Water*
(Stream 75)
550
0.2
0.89
0,01
0.62
20
18
<0.01
15
0.01
8.5
0.2
0.003
7.0
0.0025
20
320
1,000
206
0.6
8,330
Treated Mine Water
(Stream 76)
500
0.2
0.67
0.01
0.62
20
18
<0.01
12
0.01
8.5
0.2
0.003
~7
0.0025
20
320
1,000
206
0.6
8,330

* Based on data in Table 4.2-22, assuming mine water is 43% from upper and
  57% from lower aquifer.

Source:  WPA estimates based on data from Gulf Oil  Corp.  and Standard
         Oil Co. (Indiana), May 1977.
                                     117

-------
                                                     TABLE 4.3-1.  POLLUTANT CROSS-REFERENCE FOR GASEOUS STREAKS
CO
Pollutants
Stream No Table No.
5*
6*
7*
8*
9*
30*
11*
12*
13*
14*
15*
16*
17*
18*
19*
20*
21*
23*
24*
25
26 4.2-9
27
30
31* 4.2-19
32*
33 4.2-11
34 4 2-12
35
44*
45 4.2-13
CO
K
N
N
N
N
N
N
K
N
N
N
N
N
N
N
N
N
N
N
U
Y
N
P
Y
N
Y
Y
Y
Y
Y
N0x
N
K
H
N
N
N
N
N
N
H
N
N
N
N
N
N
N
N
N
U
Y
N
P
Y
N
Y
Y
Y
Y
N
SO
X
N
N
N
N
N
N
N
N
N
N
N
N
H
N
N
N
N
N
N
U
Y
N
P
Y
N
Y
Y
Y
Y
Y
1PM
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
U
P
N
Y
Y
Y
P
P
N
P
N
03
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
S
N
N
U
N
N
N
N
N
N
N
H
N
N
As
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
U
P
N
Y
N
Y
P
P
H
P
N
Be
Y
,Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
, Y
Y
Y
Y
Y
Y
U
U
N
Y
N
Y
N
N
N
N
N
Hg Fluorides
Y.
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y.
Y
Y
U
U
N
Y
N
Y
U
U
N
U
N
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
U
U
N
Y
N
Y
U
U
N
0
N
Mist
N
N
N
N
N
N
N
N
N
N
H
N
H
N
N
N
N
N
N
N
U
N
U
P
N
N
N
N
N
N
HSS
N
N
N
N
N
N
N
K
N
N
H
N
N
N
N
N
N
N
N
N
N
N
U
N
N
Y
Y
U
Y
Y
Pb
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
N
Y
N
Y
N
y
U
U
N
U
N
Total
Reduced
Sulfur
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
U
N
P
N
P
Y
Y
U
Y
Y
Vinyl
Chloride
N
N
N
N
«
N
N
N
N
N
N
N
N
N
N
N
N
H
N
N
Y
N
N
H
N
N
N
U
N
N
Polymjclear
Organic
Matter
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
^P
'p
N
K
N
P
P
P
N
N
N
N
N
Asbestos
N
H
N
N
N
N
N
N
H
N
N
N
N
N
N
N
N
N
N
H
N
«
N
N
N
N
N
N
H
N
                                                                                                                                     (Continued)

-------
                                                              TABIt 43-1  (ccrot )
	 , 	 . — , ___
Stream No, Table No.
47*
48 4 2-15
50
51
52
53
56 4 2-16
57 4.2-17
58 4.2-18
60*
61 4 2-18
63* 4 2-18
64 4.2-18
72 4.2-21
73*
74*
100*
107*
110*
112*


CO
Y
Y
N
N
N
N
U
N
P
P
p
P
P
N
N
N
N
N
N
H


NOX
Y
N
N
N
N
H
P
U
P
P
U
P
P
N
N
N
N
N
N
U


sox
Y
Y
N
N
N
N
P
U
P
P
U
p
p
N
N
N
N
N
N
p


1PH
U
N
N
N
N
N
N
N
U
H
N
N
N
N
Y
Y
N
N
N
P


Oa
N
H
N
N
N
N
N
U
N
H
U
U
U
N
N
N
H
N
N
N


As
N
N
N
N
N
N
N
N
N
H
N
N
N
N
Y
Y
N
N
N
N


Be
N
H
N
N
N
N
N
N
N
N
N
N
N
N
Y
Y
N
N
N
N


Hg
N
H
N
N
N
N
N
N
N
N
N
N
N
N
Y
Y
N
N
N
N

PC
Fluorides
N
N
N
N
N
N
N
N
N
N
N
N
N
N
Y
Y
N
N
N
N

jllutants
H2S04
Hist
N
N
N
N
N
N
U
N
M
P
N
N
N
N
N
H
N
N
N
N,


H,S
U
Y
P
P
P
P
N
U
U
P
U
U
U
Y
N
N
N
H
N
N


Pb
I)
N
N
N
N
N
N
N
N
N
N
N
N
N
Y
Y
N
N
N
N


Tutal
Reduced
Sulfur
U
Y
P
P
P
P
U
U
P
U
U
U
U
Y
P
P
N
N
N
N


Vinyl
Chloride
N
N
N
N
N
H
N
H
U
U
N
N
N
N
N
N
N
N
N
N


Organic
Matter
N
N
N
N
N
N
N
N
U
U
N
N
N
N
P
P
N
N
H
N


Asbestos
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N

* Indicates streams  that come  Into contact with the environment,

Key:   Y = Present
      N = flat Present
      p = Probably Present
      U = Presence Unknown

Source   DRI estimates.

-------
TABLE 4.3-2.  POLLUTANT CROSS-REFERENCE FOR LIQUID STREAMS

Pollutants
Stream No Table No
4* A ") '^'J
t / £c
28*
36 4 2-10
37
38 4 2-10
39
40
41 4 2-20
42 4 2-10
46 4 2-14
49 4 2-20
54
55
59*
62
65
66 4,2-18
67
69
70* 4 2-?l
71 4 2-21
-JCK Jj f 
-------
                                                                TABLE 4 1-2  (cont )
Pollutants
Stream No Table No
87
88*
89
90*
91*
92* 4 2-3, 4 2-4
93«
94
95»
96*
97
99*
101*
102*


106*

111*
ftl
P
p
P
P
P
P
P
P
P
P

P
P
P


H

P
As
P
p
P
P
P
P
p
P
P
P
P
P
P
P


N

'
B
P
P
P
P
P
P
P
P
P
P
P
P
P
P


N

p
Cd
P
P
P
P
P
P
P
P
P
P
P
P
P
P


N

p
Cr
P
P
P
P
P
p
P
P
P
P
P
f
P
P


N

'
Co 1-
p p
P P
P P
P P
P P
P P
P P
P P
P P
P P
P P
P P
P P
P P


N N

p p
Hg
P
P
P
p
P
P
P
P
P
P
P
P
P
p


N

P
N)
P
P
P
P
P
V
P
P
P
P
P
P
P
P


N

P
Pl>
P
P
V
f
P
P
P
P
P
P
P
P
P
P


N

P
Ra
P
p
P
P
P
P
P
P
P
P
P
P
P
P


H

P
V
P
p
P
P
P
P
P
P
P
P
p
P
P
f


N

P
Zn
P
P
P
P
p
P
P
P
P
P
P
P
P
P


N

P
Nil,
Y
P
Y
Y
Y
P
Y
Y
Y
Y
Y
P
Y
N


N

N
COD
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
P
Y
N


N

P
tor
Y
Y
Y
Y
P
Y
Y
Y
Y
P
P
P
P
N


N

P
Phenols
Y
P
Y
Y
P
P
Y
Y
Y
P
P
P
P
H


N

P
IDS
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y


N

Y
rss
N
Y
N
Y
N
Y
Y
Y
Y
Y
N
N
Y
N


N

Y
* Indicates streams that come into contact with the environment

Key   Y = Present
      N = Not Present
      P K Probably Present
      U - Presence Unknown

Source   DRI  estimates

-------
                                            TABLE 4.3-3.   POLLUTANT CROSS-REFERENCE FOR SOLID STREAKS
Pollutants/Hazards

Stream No.
1*
2*
3*
22*
29*

43
68

Table No
4,2-2


4 2-2
4 2-5, 4 2-6,
4.2-7



Ag
Y
Y
Y
Y
Y

Y
N

As
Y
Y
Y
Y
Y

Y
N

Ba
Y
Y
Y
Y
Y

Y
N

Cd
Y
Y
Y
Y
Y

Y
N

Cr
Y
Y
Y
Y
Y

Y
N

Hg
Y
Y
Y
Y
Y

Y
N

Pb
Y
Y
Y
Y
Y

Y
N

Se
Y
Y
Y
Y
Y

Y
N
Pesti-
cides
N
N
N
N
N

N
N
Ign It-
ability
U
U
N
U
N

Y
N
Corro-
sivity
N
N
N
N
N

N
Y
Reactivity, Radio
Explo
U
U
U
U
U

U
N
Activity
P
P
P
P
P

P
N
Phyto-
toxicfty
U
U
U
U
U

U
U
Mutageni-
city
U
U
U
U
U

. U
a
* Indicates streams that come into contact with the environment

Key   Y = Present
      N = Not Present
      P = Probably Present
      U = Presence Unknown

Source   DRI estimates.

-------
                                                                TABLE 4,3 2  (cent.)
Pollutants
Stream No Table No
87
88*
89
90*
91*
92* 4 2-3, 4 2-4
93*
94
95*
96*
97
98
99*
Ml*
102*
103*
104*
105*
106*
108*
111*
A1
f
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
As
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
B
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
Cd
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
Cr
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
Co
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
I
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
Hq
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
Mi
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
Pb
P
P
P
P
P
P
P
P
P
P
P
P
P
P
f
P
P
P
N
P
P
Ho
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
V
P
P
P
f
P
f
P
P
P
P
P
P
P
P
P
P
P
P
N
P
P
Zn
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
P
H
P
P
NH,
Y
P
Y
Y
y
p
Y
Y
Y
Y
Y
Y
P
Y
N
P
N
N
N
P
N
COD
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
P
Y
N
Y
Y
Y
N
Y
P
roc
Y
Y
Y
Y
P
Y
Y
Y
Y
P
P
P
P
P
N
Y
Y
Y
N
Y
P
Phenol?
Y
P
Y
Y
P
P
Y
Y
Y
P
P
P
P
P
N
Y
P
P
N
Y
P
IDS
Y
Y
Y
Y
V
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
N
Y
Y
TSS
N
Y
N
Y
N
Y
Y
Y
Y
Y
N
N
N
Y
N
Y
Y
Y
N
Y
Y

* Indicates streams that come Into contact with the environment

Key   Y = Present
      N = Not Present
      P = Probably Present
      U ~ Presence Unknown

Source   OR!  estimates

-------
                                                  TABLI 4 3-3   POLLUTANT  CROSS-REfERENCE FOR SOLID STREAMS
IS5
Pol 1 utants/Hazards

Stream No
1*
2*
3*
22*
29*

43
68

Table No.
4.2-2


4.2-2
4 2-5, 4.2-6,
4.2-7



Ag
Y
Y
Y
Y
Y

Y
N

As
Y
Y
Y
Y
Y

Y
N

Ba
Y
Y
Y
Y
Y

Y
N

Cd
Y
Y
Y
Y
Y

Y
N

Cr
Y
Y
Y
Y
Y

Y
N

Hg
Y
Y
Y
Y
Y

Y
N

Pb
Y
Y
Y
Y
Y

Y
N

Se
Y
Y
Y
Y
Y

Y
N
Pesti-
cides
N
N
N
N
N

N
N
Ign it-
ability
U
0
N
U
N

Y
N
Corro-
sivity
N
N
N
N
N

N
Y
Reactivity
Explo,
U
0
U
U
U

U
N
, Radio
Activity
P
P
P
P
P

P
N
Phyto-
toxicity
U
U
U
U
U

U
U

Mutageni-
city
U
U
U
U
U

U
, U

      * Indicates streams that come into contact with the environment.

      Key:  Y = Present
            N = Not Present
            P = Probably Present
            U = Presence Unknown

      Source   DRI estimates.

-------
                                  SECTION 5

                        POLLUTION CONTROL TECHNOLOGY


     This section presents an inventory of pollution control technologies and
discusses, in depth, some representative controls for each medium (air, water
and  solid waste).   The inventory expands beyond  describing the technologies
that have been  proposed for the Lurgi-Qpen Pit processes at Tract C-a.  That
is,  it  discusses alternate and additional technologies  that provide varying
levels of control.   Although  the inventory is quite  extensive,  other possi-
bilities  may  exist  and  should  not be excluded  from  consideration.   Changes
in  the  design  of  the plant  complex,  changes in  the assumptions made  (see
Section 1.5),  and/or improved  data from  future testing  could lead  to  the
selection of different controls.

     Each subject area for control  (e.g., particulate  control) begins with an
inventory of available  technical  approaches,  or technologies.  Promising new
control   technologies not yet applied commercially,  even in  related indus-
t"ies. are  also included in  the  inventory  but are not  described  in detail.
Such new technologies may be applicable to the oil shale industry if they are
sufficiently developed and  tested  fn  the future.  The  inventory  is  followed
by a discussion of the most important considerations  in selecting a control.
Fina'ly,  a  more detailed analysis  of  performance and cost  is presented  for
the  control  technologies that  have been considered by  Rio  Blanco Oil  Shale
Company   (RBOSC)  in  conjunction  with  the   Lurgi-Qpen  Pit  processes  (see
Sections 2  and  3  for a  description   of the case  study which includes  the
proposed processes and technologies).

     7te  detailed  analysis  seeks to  estimate pollution  control  performance
and  cost.   Performance estimates generally  require no  more  than  conceptual
designs; however, the reliability of the  performance estimates varies depend-
ing  upon  the application.  The estimates  should be highly  reliable  where  a
proven technology  is applied to  a conventional  stream  for  which  experience
exists (e.g.,  flue gas  desulfurization)  but may be  much  less accurate  for
controls  which  require  testing  and  which   are  applied  to  unconventional
streams  (e.g.,  biological oxidation).  All  performance  levels are given  for
instantaneous control and reflect optimal operation, which may be  higher than
the average level  of performance  actually achieved.   All cost estimates  are
in mid-1980  dollars  and are taken  to  the  level  of detail  believed to  be
necessary to achieve ±30% accuracy.  This  level  of accuracy  is based on  the
cost of equipment already built  and operating in  related industries.
                                     123

-------
 5.1  AIR  POLLUTION  CONTROL

     As  in  other  industrial  and oil  shale operations,  the  lurgi-Qpen Pit
 p1ant*~from  mining  activities to  final  product  storage  and transfer—will
 generate   particulate  and   gaseous  component  emissions,    The  primary  air
 emissions  are:

     *     Particulates, TPM                                             *

     *     Sulfur  Dioxide, S02

     •     Nitrogen  Oxides, NOx

     «     Carbon  Monoxide, CO

     •     Hydrocarbons, HC.

     This  section describes the  current,  commercially available alternative
 systems for  controlling  the above primary pollutants.  The following subsec-
 tions provide inventories of control technologies  for each of the air pollut-
 ants, a discussion  of advantages and  disadvantages,  and important points to
 consider  in  selecting a particular technology.  Performance, design, and cost
 data for the leading technologies examined are also presented.

 5-1-1  Particulate  Control

     Participate  matter  is  generated during the mining, crushing, conveying,
 and processing of oil  shale.  Participates are emitted from fugitive sources
 such  as   conveyor belts  and  from  point sources  such  as flue  gas stacks.
 Federal and  State standards and regulations limit  these particulate emissions
 because  of  their  potentially hazardous  effects  on human  health and  the
 environment.

     Inventory of Control Techno1ogies—

     As shown  in Figure  5.1-1,  particulate  control can be  divided into two
 general categories:

     •     Control of point sources

     •     Control of fugitive  sources.

     The  particulate matter  from a  point  source is  confined within  some
 equipment  boundaries  and  is  controlled  by passing  the  dust-laden  stream
 through a  control device.   Fugitive particulate matter  is  unconfined  and is
 generally  controlled by wet suppression techniques which are generally not as
 efficient  as the point  source control  techniques.   Table 5.1-1  presents  a
 listing and review of particulate control technologies.

     Control of point sources.   There  are  two primary classes of particulate
 control equipment for  point sources:   dry and wet.  Both classes offer proc-
 esses that are feasible  for particulate control  in  oil  shale applications.
Dry dust  collectors can  only  be used with  dry  dusts.   Sticky particulates
 tend to  clog the dry  collector  and reduce its performance.   In such  cases,
wet collectors are used.


                                     124

-------
  PARTICULATE
 1  CONTROL
 (TECHNOLOGIES
SOURCE:  SWEC
                 FIGURE 5.1-1  PART1CUUTE CONTROL TECHNOLOGIES

                                     125

-------
                                                     TABLE 5.1-1.  KEY FEATURES OF PARTICIPATE CONTROL TECHNOLOGIES
Control
Technology
       PRY COLirCTPRS

       Fabric  Filter
       Electrostatic
       PrecipHator
       Cyclone
rva
en
       liapingenent
       Separator
       Settling
       Chamber
                          Operating Principle
The dust-laden gas passes
through woven fabric or felt
material which filters out
the dust, allowing the gas
to pass on.  Tfte filters are
cleaned by mechanical shaking
or reverse jet compressed
air flow

Particles suspended in a gas
are exposed to gas ions in
an electrostatic field.  These
particles then become charged
and migrate under the action
of the field to collector
plates

The dust-laden gas enters a
cylindrical or conical
chamber tangentially at one
or more points and leaves
through a central opening.
The dust particles, because
of their inertia, will tend
to move toward the outside
separator wall and then into
a receiver.

The dust-laden gas impinges
on a body, and the gas is
deflected while the dust
particle, by virtue of its
greater inertia, collects
on the surface of the body

The simplest type of dust
collection equipment,
consisting of a chamber in
which the gas velocity is
reduced to enable dust to
settle out by the action of
gravity.
                                                       Performance
                                                       Removal efficiency  is
                                                       99.7-99 9%   Operating
                                                       temperature is limited
                                                       to 600°F, depending on
                                                       the fabric material,
                                                       and the pressure drop
                                                       is typically 4 in.  H20
Removal efficiency is
99-99 9%.  Operating
temperature is limited
to 850°F, and the
pressure drop is
typically 1 in  H20
Removal efficiency is
50-90%   Operating
temperature is limited
to 1,000°F, and the
pressure drop is
typically 1-5 in.  HjO
Removal efficiency is
0-80%.  Operating
teinperature is limited
to 1,OQO°F, and the
pressure drop is
typically 4 in  H20.

Removal efficiency is
0-50%   Operating
temperature is limited
to 1,0000F> and the
pressure drop is
typically 0.1 in  H20
                                                                                     Bevel opment
                                                                                       Status
                                                         Advantages
                          Commercially proven    High removal efficiency and
                                                 low operating cost
Commercially proven.
                                                                                 Commercially proven.
                                                                                                  High removal  efficiency and
                                                                                                  a very low pressure drop.
                       Low capital and operating
                       cost.  Good as a gas
                       precleaner before a more
                       efficient removal device.
Commercially proven
                                                                                 Commercially proven.
                                                                                                  Low capital  and operating
                                                                                                  cost.   Good  as a gas
                                                                                                  precleaner before a more
                                                                                                  efficient removal device.
                       Low operating cost and a low
                       pressure drop.
                                                           Disadvantages
                                                        The fabric can be sensi-
                                                        tive to gas humidity,
                                                        velocity and temperature,
                                                        as well as participate
                                                        characteristics.
High energy consumption.
Sensitive to varying
process conditions and
particle properties.
                                                                                                                                   Low removal  efficiency
                                                                                                                                   for s«a1T particles
                                                                                                                                          Low  removal  efficiency.
                                                                                                                                   Low removal  efficiency
                                                                                                                                   and a very laige space
                                                                                                                                   requirement
                                                                                                                                       (Continued)

-------
                                                                    TABIF 5 1-1  (cont )
Contro 1
Technology
   Operating Principle
MET COLLECTORS

Venturi
Scrubber
Imp1 ngement-
Plate Scrubber
Spray Tower
Cyclone
Scrubber
                                Performance
Gas and liquid are passed
concurrently through a
venturi throat at 200 to
800 ft/sec.
The high velocity jjas passes
through a perforated tray with
an impingement baffle above
each perforation.  The gas
atomizes the liquid on the
tray into droplets which then
collect the dust

Liquid droplets produced by
spray nozzles settle through
rising gas stream and remove
dust by Impactton
Liquid is sprayed Into the
gas stream and removes the
dust particles by inertia)
impaetion.
Electrostatic    SEE DRY COLLECTORS
Precipitator

Vet Suppression  Fugitive dust generated in
                 the crushing and handling of
                 the oil shale is sprayed with
                 a foam suppressant made from
                 a water/surfactant mixture
Removal efficiency Is
95-99%   Operating
temperature is limited
to 40-700°F, and the
pressure drop is
typically 1-bO in.  H^O

Removal efficiency is
80-99%   Operating
temperature is limited
to 40-700°F, and the
pressure drop is
typically 1-20 in  H20
Removal efficiency 1s
50-80%   Operating
temperature Is limited
to 40-?OQ°F, and the
pressure drop is
typically 0 5 in  H20

Removal efficiency is
50-75%.  Operating
temperature is limited
to 40-70Q°F, and the
pressure drop is
typically 2 in.  H20
                                Removal efficiency is
                                9S-39%   Operating
                                temperature is limited
                                to 40-200"F
                                                              Development
                                                                Status
                                                         Advantages
                                                                                                                     Disadvantages
Commercially proven    High removal efficiency
Commercially proven    High removal efficiency
Coflunercial )y proven.
Commercially proven
Low pressure drop and a low
operating cost
Low pressure drop and a low
operating cost
                                 Efficiency drops for
                                 small particles
                                 Efficiency drops for
                                 small particles
Low removal  efficiency
Low removal  efficiency
                          Commercially proven.
                       Low capital and operating cost
                       and a high removal efficiency.
                                 Used only for conveyor
                                 transfer points and
                                 crushing and grinding
                                 operations
Source;  SVftC based on information from Research and Education Association, 1980

-------
 systems,- truck loading  and unloading, and disposal operations.  These  fugi-
 tive sources of participates  are  controlled by water  and foam  spray suppres-
 sion.   This system  is  inexpensive  and offers low water  consumption and high
 removal  efficiency.

      Table  5.1-2   lists  the  design parameters  for the  participate control
 technologies examined,  Table  5.1-3 presents  more design  details  for the bag-
 houses,  and Table 5.1-4  gives the design basis  for  the ESP.   The capital,
 operating,  and annual  costs  for  the  participate control equipment are pre-
 sented  in Table 5.1-5.   Figures 5.1-2 and 5,1-3 present  the cost curves for
 the  baghouses  and ESP,  respectively.  The curves have been derived specifi-
 cally from  the stream  characteristics  and design parameters  used  in this
 manual.

      Other  Parti culate  Control Techno!og1es Analyzed—

      In  addition  to  the ESP,  another  technology was analyzed for the control
 of participates from the Lurgi flue gas--a fiberglass fabric baghouse.  This
 technology  has  not been proposed  by RBQSC,  but  it is  judged to be applicable
 to the flue  gas.

      As  mentioned previously,  the flue gas  is  at a fairly high temperature
 at  the point of control;  therefore,  conventional polyester fabric baghouses
 cannot be used  for dust control.  The  fiberglass  reinforced fabric baghouses,
 on  the other hand,  have a  much higher  operating temperature limit (600°F).
 The  operation  of  the latter type  of  baghouses is similar to that of conven-
 tional  baghouses, and  comparable  dust  removal   efficiencies  are  obtained.
 Table 5.1-6  presents the design and cost  details for  the fiberglass baghouse
 analyzed for the Lurgi flue  gas application.   The cost curve for conventional
 baghouses (see  Figure 5.1-2)  can  be   used for fiberglass baghouses because,
 except for the  fabric material, the two types  of  baghouses are quite similar.

     Total Parti cul ate Emissions—

     The controlled  particulates  from the  point  as  well  as fugitive sources
 are  summarized  in Table 5.1-7, along with  the type of control  technology
 examined  for each source.   The uncontrolled  emissions are  also included in
 the  table to give  total particulate emissions from the commercial operation.
 Estimates for   these  emissions were  based  on  information  provided by the
 equipment vendors.

 5.1.2  Sulfur Control

     Processing of sulfur-containing fossil fuels will result in emissions of
sulfur compounds,  such  as  H2S,  COS,  CS2,  RSH,  etc.,   or  their combustion
product,  S02.   Federal  and State standards limit  sulfur  emissions because of
their  potentially  hazardous  effects   on   human  health and  the environment.

     Inventory of Control Technologies—

     Two  general   categories  of technologies  are available for  the  control
of  sulfur  emissions:   (1) removal  of  sulfur''compounds from  flue  gases


                                     130

-------
                                       TABLE 5 1-2.  PARTICIPATE CONTROL EQUIPMENT ftNO DESIGN PARAMETERS
Stream
Number
5
6
7
8
9
' 10
11
12
13
14
15
16
. IT
18
19
28
21
23
31
33
73
74
Control Description
Baghause
Baghouse
Baghouse
Baghause
Baghause
Baghouse
Baghause
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
BaghouEO
Baghouse
Electrostatic
Precipitator
Baghouse
Baghouse
Water and Foam
Sprays
Control Location
Primary Crushers (ore)
Primary Crushers (subore)
Primary Crushers (overburden)
Conveyor to Stockpile
Raw Shale Conveyor Transfer
Points
Conveyor to Secondary Crushers
Secondary Crushers
Conveyor to Secondary Screens
Secondary Screens
Conveyor to Tertiary Crushers
Tertiary Crushers
Conveyor to Tertiary Screens
Tertiary Screens
Conveyor to Fine Ore Storage
Fine Ore Storage
Conveyor to Retort Feed Hoppers
Retort Feed Hoppers
Processed Shale Load-out
Hoppers
Flue Gas Discharge System
Conveyor to Retorts
Processed Shale Conveyor
Transfer Points
Open Stockpiles, etc.
Number of
Units
2
1
1
2
3
2
8
2
8
2
9
4
9
2
1
2
4
3
13
13
2

Klnw Rate
Each
(ACI-M)
61,100
12,200
63,800
36,300
40,500
20,200
69,800
20,200
69,800
20,200
69,800
20,200
69,800
20,200
28,800
20,200
53,100
21,500
293,700
18,400
32,300

Dust toad
(Ib/hr)
5,237.1
522 9
2,734 3
124 5
208 3
69 3
23,931 4
69.3
23,931 4
69 3
26,922.9
138.5
26,922.9
69 3
1,234.3
69.3
9,102.9
2,764 3
1,106,554.8
410.1
110.7
3,466.7
Removal
Efficiency
(X)
99.7
99 7
99 7
99 7
99 7
99 7
99 7
99 7
99 7
99 7
99 7
99 7
99 7
99.7
99.7
99 7
99.7
99.7
99.9
99 7
99 7
98.5
Total Particulate
Emissions
(Ib/hr)
35.71
1 57
8 20
0 37
0 62
0 21
71 79
0 21
71.79
0.21
80.77
0 42
80.77
0.21
3.70
0 21
27 31
8.29
1,106.6
1,23
0 33
52 0
Source-
         SWEC estimates based on information from Gulf Oil Corp  and Standard Oil Co  (Indiana), March 1976, and Rio Blanco Oil Shale Co
         February 1981

-------
                                         TAfLC  5.1-3.   BASHOUSE SPECIFICATIONS*
Stream
Number
3

6

7

8

9

10

11

12

13

14

15

16


16


17

18

19

20

21

23

32

73

Control Location Flow Rate Each No, of
(No of Units) (ACFK) Bags
Primary Crusher (ore)
(2)
Primary Crusher (subore)
(1)
Primary Crusher (overburden)
(1)
Conveyor to Stockpile
(2)
Raw Shale Conveyor Transfer Points
(3)
Conveyor to Secondary Crushers
(2)
Secondary Crushers
(8)
Conveyor to Secondary Screens
(2)
Secondary Screens
(8)
Conveyor to Tertiary Crushers
(2)
Tertiary Crushers
(9)
Conveyor to First Set of
Tertiary Screens
(2)
Conveyo>- to Second Set of
Tertiary Screens
(2)
Tertiary Screens
(9)
Conveyor to Fine Ore Storage
(2)
Fine Ore Storaoe
(1)
Conveyo" to Retort Feed Hoppers
(2)
Retort Feed Hoppers
(4)
Processed Shale Load-out Hoppers
(3)
Conveyor to Retorts
(13)
Processed Shale Conveyor
Transfer Points
61,180

12,200

63,800

36,300

40,500

20,200

69 ,800

20,200

69,800

20,200

69,800

20,200


20,200


69,800

20,200

28,800

20,200

53,100

21,500

18,400

32,300

882

176

921

461

514

256

1,008

256

1,008

256

1,008

256


. 256


1,008

256

416

256

767

310

234

466

Net
Cloth ftret
(ft2)
10,399

2,076

10,858

5,428

6,057

3,021

11 ,879

3,021

11,879

3,021

11.87S

3,021


3,021


11,879

3,021

1,901

3,021 •

9,037

3,659

2,752

5,497

Alr-to-
Cloth Ratio
5 87/1

S 87/1

5 87/1

6 68/1

6 68/1

6 68/1

5.87/1

6 68/1

5 87/1

6 68/1

5.87/1

6 68/1


6.68/1


5 87/1

6 68/1

5 S7/1

6 68/1

5.87/1

5 87/1

6 68/1

5.87/1

Fan AP
(
-------
          TABLE 5.1-4.  MAJOR ITEMS IN ELECTROSTATIC PRECIPITATQR*
     Capital Cost Items
Operating Cost Items
     Chambers (13)

     Collecting Plates

     Transformer Rectifiers

     Fans and Motors

     Dampers and Ductwork

     Supports

     Handrail ing and Grating

     Piping

     Concrete and Foundations

     Painting

     Insulation

     Instrumentation and Controls

     Discharge Electrodes

     Electrical

     Bins

     Discharge and Conveying System

     Rappers
Electricity
  4,907 kW

Maintenance
* Design basis:   293,700 ACFM/unit.

Source:  SWEC estimates based on information provided by Research Dottrel!
         Corp.
                                     133

-------
                                       TABLE 5.1-5   COST OF PARTICIPATE POLLUTION COHTROL

Stream
Number
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Control
Description
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Control Location
Primary Crushers
(ore)
Primary Crushers
(subore)
Primary Crushers
(overburden)
Conveyor to Stockpile
Raw Shale Conveyor
Transfer Points
Conveyor to Secondary
Crushers
Secondary Crushers
Conveyor to Secondary
Screens
Secondary Screens
Conveyor to Tertiary
Crushers
Tertiary Crushers
Conveyor to Tertiary
Screens
Tertiary Screens
Conveyor to Fine
Ore Storage
Fine Ore Storage
Conveyor to Retort
Feed Hoppers
Number
of Units
2
1
1
2
3
2
8
2
8
2
9
4
9
2
1
2
Flow Rate
Each
(ACtH)
6J, , 100
12,200
63,800
36,300
40,500
20,200
69,800
20,200
69,800
20,200
69 ,800
20,200
69,800
20,200
28,800
20,200
Fixed Capital
Cost ($000's)
987
105
552
628
1,051
348
4,828
348
4,828
348
5,432
696
5,432
348
249
348
Total Annual
Operating
Cost ($000's)
63
6
34
' 85
65
22
297
22
297
22
334
44
334
22
15
22
Total Annual
Control
Cost ($000' s}*
250
26
138
205
264
SB
1,211
88
1,211
88
1,363
176
1,363
88
62
88
21
         Baghouse
Retort Feed Hoppers
                                                                 53,100
1,837
                                                                                                     113
                                                                                                                       471
                                                                                                                  (Continued)

-------
                                                                         TABLE 51-5  (cont  }

St» earn
Number
23

31

32
73


74

TOTAL


Control
Description
Baghouse

Electrostatic
Precipitator
Baghouse
Baghouse


Water and Foam
Sprays



Number
Control Location of Units
Processed Shale J
Load- out Hoppers
Flue Gas Discharge 13
Sy s tern
Conveyor to Retorts 13
Processed Shale 2
Conveyor Transfer
Points
Open Stockpiles, etc




Flow Rate
Each
(ACFM)
21,500

293,700

18,400
32,300


--




(-ixed Capital
Cost (1000's)
559

50,734

2,059
559


909

83,185


Total Annual
Operating
Cost ($000' s)
34

2,144

127
34


1,456

5,592


Total Annual
Control
Cost (1000's)*
140

12,016

528
140


1,650

21,654

                * See Section 6 for details on computation of the total annual control cost

                Source:  ORI estimates based on Information provided by SWEC
GO
tn

-------
cr>
                 800
                 60°
             VI
—

t:  400
o.
•a
o
             Ixl
             >e
                 200
                   0.
                    10
                  20
                                                                      I
30          40           50

 GAS FLOfl,  103 ACFM/UNIT
60
     SOURCE:   ORI based on Information provided by SWEC



                             FIGURE 5.1-2   COST OF PARTICIPATE CONTROL WITH BAGHOUSES
                                                                                  160
                                                                                  120
                                                                                                   tf)
                                                                                                   o
                                                                                               80
                                                                                                   ft:
                                                                                                   CL.
                                                                                                   O
                                                                                     cc
                                                                                  40 5

-------
           4.6
           4.2
        tn
        s
        a.

        s

        a
        LU
        X
           3-8
            3.4
           3.0,
             180
220
260          300         340


  GAS FLOW,  I03ACPM/UNIT
380
                                                                1.6
                                                                                            ID
                                                                                             Q
                                                                 1.2
                                                                                             o
                                                                                             o
                                                                    «sf
                                                                    or
                                                                0.8
                                                                    -<*

                                                                    o
                                                                 0.4
d°
SOURCE:  DRI based on Information provided by SWEC



                FIGURE 5.1-3  COST OF  PARTICULA1E CONTROL  WITH ELECTROSTATIC  PRECIPITATORS

-------
       TABLE 5.1-6.  DESIGN AND COST OF THE FIBERGLASS FABRIC BAGHOUSE

Item
No. of Bagliouses
Flow Rate (each)
No. of Bags (each)
Net Cloth Area (each)
Air-to-Cloth Ratio
Fan, AP
Fan Motor-
Dust Loading
Dust Removal Efficiency
Outlet Dust Concentration
Fixed Capital Cost
Direct Annual Operating Cost
Hai ntenance
Electricity
TOTAL
Unit
—
ACFM
—
ft2
ftVACF
in. H20
BHP
grai ns/ACF
103 1b/hr
%
Ib/hr
$103
$103



Quantity
13
293,700
3,774
44,462
6.6
10.5
2 x 315
33
1,106.6
99.7
3,319.7
33,015

644
1.279
1,923
.
Source:  SWEC estimates based on information provided by North-Monson Co.,
         August 11, 1980.
                                     138

-------
        TABLE 5.1-7.  TOTAL PARTICULATE EMISSIONS FROM THE PLANT

Stream
NuffiBer
5
6
7
8
9
10
11
12
13
14
15
-Lo
17
18
IS
20
Emission Source
Primary Crushers (ore)
Primary Crushers (subore)
Primary Crushers
(overburden)
Conveyor to Stockpile
Raw Shale Conveyor
Transfer Points
Conveyor to Secondary
Crushers
Secondary Crushers
Conveyor to Secondary
Screens
Secondary Screens
Conveyor to Tertiary
Crushers
Tertiary Crushers
Conveyor to Tertiary
Screens
Tertiary Screens
Conveyor to Fine Ore
Storage
Fine Ore Storage
Conveyor to Retort Feed
Control
Description
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Particulate
Emissions
(Ib/br)
15.71
1.57
8.20
0.37
0.62
0.21
71.79
0.21
71.79
0.21
80.77
0.42
80.77
0.21
3.70
0.21
21
  Hoppers



Retort Feed Hoppers
Baghouse
27.31
                                                       (Continued)
                                   139

-------
                            TABLE 5.1-7  (cont.)

Stream
Number Emission Source
Control
Description
Parti cul ate
Emissions
Ob/hr)
  23


  24

  31


  32

  73


  74
Processed Shale Load-out
  Hoppers

Diesel Equipment

Flue Gas Discharge
  System

Conveyor to Retorts

Processed Shale Conveyor
  Transfer Points

Open Stockpiles, etc.
  Baghouse
Electrostatic
  Precipitator

  Baghouse

  Baghouse
Water and Foam
  Sprays
     TOTAL
    8.29


   33.00

1,106.6


    1.23

    0.33



   52.00

1,565.52
Source;  SWEC  estimates based  on  information  from Gulf  Oil  Corp. and
         Standard  Oil  Co.  (Indiana),  March  1976,  and  Rio Blanco  Oil
         Shale Co., February 1981.


after  combustion  (sulfur dioxide  removal,  or flue gas  desulfurization)  and
(2) removal  of sulfur  compounds  from  gases prior  to  combustion  (hydrogen
sulfide removal).   Several  technologies in both categories offer recovery of
sulfur in  a  useful  form, while others chemically fix the sulfur compounds on
a reagent which then requires disposal.

     Sulfur djoxltie control (f1ue gas desulfurlzation).    Removal  of  sulfur
compounds  from flue gases—that is, flue gas desulfurization (FGD)—is based
on the physical  and chemical  properties of S02  because  fuel-based  sulfur is
usually converted to S02  upon combustion.  Flue gas desulfurization  can be
divided into two categories:

     *    Wet scrubbing

     *    Dry scrubbing.

     Wet scrubbing  utilizes a  solution or a slurry to  absorb  the  S02.  Dry
scrubbing uses either a dry reagent bed or an atomized solution of an aqueous
reagent at a  high  temperature to  remove  the S02.   Both categories  can be
divided into  regenerate and nonregenerable processes.   The different types
of S02 removal processes are shown in  Figure 5.1-4,  and Table 5.1-8 gives a
brief description of each process.
                                     140

-------
                                   REGENERABLE
                                    PROCESSES
                                   NONREGENERABLE
                                     PROCESSES
                                   REGENERABLE
                                    PROCESSES
- WELLMAN-LORO

- MAGNESIUM OXIDE

- ABSORPTION/STEAM
  STRIPPING RESQX SYSTEM

-LIMESTONE

-LIME

-DOUBLE ALKALI

-SODIUM CARBONATE

-DOWA ALUMINUM SULFATE

-OILSHALE{PROCESSEO
  SHALE, NAHCOLITE)
-CHIYODA THOROUGHBRED 121


-AQUEOUS CARBONATE


NONREGENERABLE
PROCESSES




                                                     I—LIME

                                                        SODIUM CARBONATE

                                                     '—OIL SHALE{PROCESSED
                                                         SHALE, NAHCOLITE)
SOURCE: SWEC
            FIGURE  5.1-4  SULFUR DIOXIDE CONTROL TECHNOLOGIES

                                    141

-------
                                                     TABLE 5.1-8.   KEY FEATURES OF SULFUR DIOXIDE CONTROL TECHNOIOGIES
       Control
       Technology
   Operating Principle
                                Performance*
                                                              OevcIopnent
                                                                Status
       SEG[N ERABIE WET SCRUBBING PROCESSES

       Wei 1 man-Lord'
•*»
N3
       Magnesium

       Oxide6
       Absorption/
       Steam Stripping
       Resox System
Absorbs S02 with a sodium
sulfite/bisulfite solution.
A bleed stream of the rich
solution is sent to
evaporators where SO., and
water are driven off and the
reagent 1s regenerated.

Absorbs S02 with a Magnesium
oxide slurry,   ft bleed stream
of the spent slurry is dried
and calcined to regenerate
the magnesium oxide and
produce a dilute SPa stream
(10% S02)
An aqueous solution of a
suitable reagent (e g ,
sodium carbonate, citric
acid) absorbs the SO;., and
the solution is regenerated
by Indirect steam heating to
evolve a concentrated S02
stream.   The SO^ ts then
reacted with crushed coal in
the Resox system to produce
elemental sulfur.
                                                        Reduces the outlet ftye
                                                        gas S02 concentration
                                                        to 50 ppmv
Reduces the outlet flue
gas S02 concentration
to 50 ppmv
Reduces the outlet flue
gas S02 concentration
to 50 ppmv
                                                         Advantages
                          About 30 coiwiiercla}
                          units ate in opera-
                          tion in the U S  and
                          Japan
Three demonstration
plants have been
tested in Japan
(e*th about 100 tw
size).  Two coimaer"
cfal units are under
construction In the
U S

The systems have been
tested in separate
demonstration plants
A demonstration plant
for the combined
system has been
proposed
                       Produces a concenttated S02
                       stream which can be used to
                       make salable sulfur or
                       sutfunc acid
Produces an S02 stream
suitable for manufacture of
sulfurlc acid.
Uses a simple absorption/
steam stripping system and
produces salable elemental
sulfur
                                                           Disadvantages
                                 Requires fuel for the
                                 solution evaporators
Requires fuel for the
MgSOa/MgSOj drysr and
calciner.
Has not been demonstrated
as a combined system
       NONREGFHERABLE WEI SCRUBBING  PROCESSES

       Limestonea       Absorbs  S02  with  a  limestone
                        slurry.   A bleed  stream of
                        the  slurry is  partially
                        dewatered and  disposed  of  tn
                        a landfill.

       lime             Absorbs  SQj  with  a  lime
                        slurry    A bleed  stream of
                        the  slurry 1s  partially
                        dewatered and  disposed  of  in
                        a landfill
                                Reduces the outlet flue
                                gas S02 concentration
                                to SO ppmv
                                Reduces the outlet flue
                                gas S02 concentration
                                to 50 ppmv
                          Many commercial
                          units in operation
                          worldwide
                          Many commercial
                          units in operation
                          worldwide
                       Low capital and operating
                       cost   Simple and proven
                       process with conventional
                       process equipment.
                       Very similar to the limestone
                       process and can potentially
                       give a greater SOZ removal
                       efficiency than limestone
                                 Has a low operability
                                 factor due to scaling,
                                 erosion and corrosion
                                 Sulfur is nonrecoverable.


                                 Lime costs are rising
                                 rapidly because of
                                 higher energy costs
                                 Sulfur is nonrecoverable
                                                                                                                                        (Continued)

-------
                                                                    TABLL 5.1-8  (cont )
Control
Technoloijy
Double Alkali
             a
Sodium
Carbonate
Dowa Aluminum

Sulfateb
Oil Sftale
(Processed
Shale,
Nahcolite)
   Operating Principle
                                Performance*
Uses two alkaline solutions,
sodiwn hydroxide and sodium
sulfite, to convert S02 to
sodium bisulfite   The spent
solution is regenerated by
lime addition.   The precipi-
tated solids are partially
dewatered and disposed of
1n a landfill

Absorbs SOg with a sodium
carbonate solution   A bleed
stream of the spent solution
Is partially dewatered and
disposed of in a landfill
Absorbs SQ2 with an acidic
clear solution of basic
aluminum sulfate.  The spent
solution Is oxidized to
aluminum sulfate   Limestone
is added to the solution to
regenerate basic aluminum
sulfate aid produce gypsum
fchfeh Is partially dewatered
and disposed of in a landfill

Absorbs SO2 with a shale
slurry.  A bleed stream of
the slurry is partially
dewatered and disposed of
in a landfill.
                                                 Reduces the outlet flu<>
                                                 gas S02 concentration
                                                 to SSO ppmv
Reduces the outlet flue
gas S02 concentration
to 50 ppmv
Reduces the outlet flue
gas S02 concentration
to 50 ppmv.
                                                              Development
                                                                Status
Reduces the outlet flue
gas $02 concentration to
~50 ppmv
The process is only
conceptual at this
time and has not been
tested on a pilot
scale
                                                         Advantages
                          Nine commercial
                          units in operation
                          and three under
                          construction in the
                          U S
Four commercial
units In operation
worldwide
Not used commercially
in the U S
                       Low in capital and operating
                       cost like the limestone
                       system, but the use of a
                       clear scrubbing solution
                       reduces scaling, erosion,
                       and corrosion in the scrubbing
                       loop
Low capital cost.  A very
simple and reliable process
Uses the sane basic process
design as the double alkali
process and, therefore, has
the same advantages   The
process uses a clear scrubbing
solution which reduces scaling,
erosion, and corrosion In the
scrubbing loop.
Low capital and operating
cost.  Also, an abundant
supply of processed shale 1s
available at the plant site.
Nahcolite is plentiful in
the Plceance Basin
                                                           Disadvantages
Requites, soda ash
(Na2CQ.j) makeup in
addition to lime for
precipitation.  Soda ash
i ^ an expens i ve raw
material   Fhe sludge
contains soluble and
Teachable sodium salts
Sulfur is nonrecoverable

Soda ash is an expensive
raw material   Produces
a sludge which is very
difficult to dewater and
dispose of   Sulfur is
nonrecoverable.

Requires dewatering and
landfill disposal
Has not yet been tested,
even on a pilot plant
scale   Sulfur is
nonrecoverable
                                                                                                                                 (Continued)

-------
                                                                    TABLE 5.1-8  (eont )
Control
Technology

Chiyoda
Therough-
bred 121
tCT-121)
   Operating Principle
The flue gas 1s first
quenched to Its saturation
temperature and then sparged
into a limestone slurry,
generating a jet bubbling
froth layer.  The SO^ in the
flue gas is absorbed by the
limestone slurry in the jet
bubbling layer   The calcium
sulfite formed by this
reaction is oxidized to
calcium sulfate (gypsum) by
the Introduction of air into
the jet bubbling layer.   A
bleed stream of the waste
slurry can be dewatered and
landfilled as a recoverable
resource or given away to
local cement, fertilizer or
«a51board industries.
REGENERABLE DRY SCRUBBING PROCESS
Aqueous
Carbonate9
                                Performance*
                              Development
                                Status
                                                         Advantages
Reduces the outlet flue
gas S02 concentration
to 50 ppmv
The process has been
tested on a demon-
stration size scale
Absorbs S02 and oxidizes
calcium sulflte to gypsum in
one reacto> vessel
Flue gas is contacted with an
atomized solution of aqueous
sodlure carbonate In a spray
dryer scrubber   The sodium
carbonate absorbs the S02, is
dried, and then collected in
a baghouse or electrostatic
precipitBtor (ESP).  The dried
product is sent to the reducer
vessel where it is reacted
with coal in a molten sodium
carbonate and sodium sulfide
solution to form sodium
sulfide.   The sodium sulffde
is then reacted in another
vessel with C02 in the off-gas
from the reducer vessel to
regenerate sodium carbonate
and evolve hydrogen sulfide
gas   The hydrogen sulfide 0as
1s sent to a Claus unit to
produce elemental sulfur.
Reduces the outlet flue
gas S02 concentration to
75-100 ppmv.
The process steps
have been tested
individually on a
pilot scale   An
integrated demon-
stration size
(100 HW) unit is
currently under
construction in the
U.S.
Produces salable elemental
sulfur using coal as a fue)
instead of higher priced and
less available oil and natural
gas.
                                                           Disadvantages
Has only been tested on
a demonstration size
scale.  Sulfur is
ntsnrecoverable
The hot molten carbonate
solution used in the
regeneration section of
the process is very
Corrosive and will
require very expensive,
special construction
materials
                                                                                                                                 (Continued)

-------
                                                                    TABLE 5,1-8  (cont.)
Control
Technology
time"
Sodium
Carbonate8
011 Shale
(Processed
Shale,
Nahcolitc)
   Operating Principle
Flue gas is contacted with an
atomized lime slurry in a
spray dryer scrubber   The
lime absorbs the S02, is
dried, and then collected in
a baghouse or electrostatic
precipitator (ESP).
Flue gas is contacted with
an atomized solution of
aqueous sodium carbonate in
a spray dryer scrubber   The
sodium carbonate absorbs the
S02, 1s dried, and then
collected in a baghouse or
electrostatic precipitator
(ESP).

Flue gas Is contacted with an
atomized absorbent slurry in
a spray dryer scrubber   The
alkaline minerals in the
shale (primarily calcium and
sodium carbonates) absorb the
SQfc, are dried, and then
collected in a baghouse or
electrostatic preelpltator
(ESP).
                                Performance*
                                                 Reduces the outlet flue
                                                 gas S02 concentration
                                                 to 100-J50 ppmv
                                                 Reduces the outlet flue
                                                 gas S02 concentration
                                                 to 75-100 ppmv
Reduces the outlet flue
gas S02 concentration
to ~100-150 pprav
                                                              Development
                                                                Status
                                                          Two commercial units
                                                          are in operation in
                                                          the U S.   Ihree
                                                          additional units are
                                                          currently under
                                                          construction
                          The process has been
                          tested on a demon-
                          stration size scale
                                                         Advantages
                                                 Since the flue gas is not
                                                 saturated, slightly less
                                                 makeup water is needed and
                                                 less stack gas reheat is
                                                 needed.
                                                                                 Same as for the lime dry
                                                                                 scrubbing process
                                                          The process is only
                                                          conceptual at this
                                                          time and has not been
                                                          tested on a pilot
                                                          plant scale; however,
                                                          the Lurgi oil shale
                                                          retorting process
                                                          Hffc pipe and flue
                                                          gas treating equip-
                                                          ment and the TOSCO II
                                                          preheat unit closely
                                                          resemble this system
Same as for the lime dry
scrubbing process   Also, an
abundant supply of processed
shale 1$ available at the
plant site.  Nahcollte Is
plentiful in the Piceanee
Basin.
                                                                                                                     Disadvantages
                                 This system is usually
                                 only economically
                                 feasible where low sulfur
                                 fuel is burned because of
                                 the low reagent utiliza-
                                 tion rate   Very high
                                 removal efficiencies are
                                 also not usually possible
                                 because of the low
                                 reagent utilization rate
                                 Sulfur is nonrecoverable

                                 Same as for the lima dry
                                 scrubbing process   Also,
                                 soda ash is an expensive
                                 raw material   Sulfur is
                                 nonrecoverable
                                                                                                                                   Same  as  for  the  lime  dry
                                                                                                                                   scrubbing  process.
                                                                                                                                   Sulfur is  nonrecoverable
* Performance somewhat depends  on Inlet S02  concentrations,  fuel  quantities  and reagent  utilization.

Sources.   SWEC based on information from

            a Kohl  and Riesenfeld,  1979

              Stone and Vfebster Engineering  Corp  ,  January 30,  1979

            c Electric Power  Research  Institute,  April  1980

-------
      Wet scrubbi ng—The regenerate wet scrubbing processes  generally employ
 a  clean alkaline solution to  absorb S02,-in a scrubber.-  The resulting  spent
 solution is treated  with an  insoluble alkali  makeup which  precipitates the
 absorbed S02.   The  insoluble  alkali  sulfite  and sulfate  crystals  are then
 separated from the regenerated solution  in  a clarifier  and possibly a second
 dewatering  step such as  a centrifuge.  The  spent alkali  sludge is treated by
 calcining,  evaporation,  stripping,  etc.,  which  drive off the S02.   The S02
 can  then be  converted to a  useful form of sulfur  such as sulfuric acid or
 elemental sulfur.

      In the nonregenerable processes,  this  spent alkali  sludge is sent to a
 disposal  area  for  land  filling.

      Dry scrubbing—The dry  scrubbing processes  use  a concentrated slurry of
 alkaline crystals which are atomized and  injected into the flue gas stream as
 it passes through a spray dryer.  The  scrubbing  slurry absorbs the S02 and is
 dried by the hot flue gases.   The dried spent alkali  is  then  removed from the
 flue  gas  by an electrostatic precipitator or a baghouse.

      In the regenerable processes,   the spent alkali  is  reduced to a sulfide
 and  then reacted with  C02 to  regenerate  the alkali  and  evolve H2S gas.  The
 regenerated alkali  is  recycled,   while  the  H2S  gas  may  be converted  to
 elemental sulfur in a sulfur recovery  unit.

      In the  nonregenerable processes,  the spent  material  is   sent   to  a
 disposal  area   for  landfilling.   The spent material  also may be  recycled to
 increase  alkali utilization,

      Hydrogen  s u 1 f ide control.    H2S  removal  can  be divided  into  two  cate-
 gories:

      •    Direct conversion

      *    Indirect conversion.


      Direct conversion  actually oxidizes H2S to elemental  S.  Indirect con-
 version  involves  removing acid  gases (H2S and  C02)  from the gas  stream and
 requires  downstream direct  conversion or  further  processing to  treat the
 sulfur  compounds.   Figure 5.1-5  lists the H2S removal systems available, and
 Table 5.1-9 presents a  brief description of the  process technologies.

      Pirect conversion—As  shown in Table 5.1-9, several  direct  conversion
 technologies  are  currently  available,  including  Claus,   IFF,   Stretford,
Beavon,  Giammarco-Vetrocoke,  Takahax,  Ferrox and Haines.   The conversion of
 H2S to  elemental sulfur takes place  in  the liquid-phase in all the processes,
except the  Claus and Haines which are dry gas-phase removal processes.

      Liquid-phase  direct  conversion processes  are   ideal  for treatment  of
gases containing low concentrations  of H2S.  In  these processes, the acid gas
components  are  absorbed by alkali  solutions and  then oxidized with dissolved
oxygen  to elemental sulfur.   High   circulation  rates  of the  alkali  solution
are  required  for   high performance  and  to  reduce   thiosulfate  precipitate


                                     146

-------
 HYOTOGE^
 SULF1DE
 CONTROL
TECHfJOLQGESi
n
                                           PHYSICAL
                                           SOLVENTS
SOURCE- SWEC

ALKALINE
SALTS





-CLAUS
•Iff
• STRETF0RD
• BEAWN
• GIAMMARCO-VETRQCOKE
• TAKAHAX
•FERRQX
• HA1NES

•MEA
•DEA
-MDEA
-ADIP/DlPft
-DGA(ECOWMINE)
-SNPA/OEA
-SCOT

-BENFIELD
-CATACARB
-GIAMMARCO-VETROCOKE
-ALKAC1D(ALKA2!D)

-DiAMOX
  CARL STILL
- COLLIN

-SELEXOL
-R.UOR SOLVENT
-PURISOL
-SULFINOL
- AMiSOL
-RECTISOL
                                                            r—MOLECUtAR SIEVE
                                                              CABiO« &EO
                                                            r-ltON OXIOElSPONGE)
                                                               KATASULF
                                                            i—ZINC OXIDE
                FIGURE 5.1-5  HYDROGEN  SULFIOE CONTSOL TECHNOLOGIES
                                       147

-------
                                                    TABLE 5.1-9.  KEY FFAT11RES OF HYDROGEN SULFIDE CONTROL TECHNQLOS1ES
Control
Technology
                           Operating Principle
                                                        Performance
                                                                                      Development
                                                                                        Status
                                                                                         Advantages
                                                                                      Disadvantages
       D1RFCT CONVERSION
       Claus'
       IFPU
            a>b
       Stretford
                ,a,b
CD
             a,b
       Beavon'
       Giaromarco-

       Vetrocokeb
       Takahax
                        Partial oxidation of H2S to
                        SOa and subsequent reaction
                        ZH2S + S02 •» S + 2HZQ in
                        gas-phase.
                 Absorption of  H2S and S02
                 (Claus  tail gas) in
                 polyalkene fllycol, followed
                 by conversion  to elemental
                 sulfur  using a catalyst
                 (liquid phase  Claus
                 reaction)

                 H2S absorption and liquid-
                 phase oxidation H2S + %02 -»
                 S t H2Q in an  alkaline
                 solution of a  vanadium salt.
Catalytic hydrogenation and
hydrolysis of all sulfur
coinpounds to HjS, followed
by recovery of elemental
sulfur using the Stretford
process (see above).

HZS absorption and liquid-
phase oxidation H2S + %Q2 •*
S ••• H20 in a solution of
arsenic salt.
                        HaS absorption and liquid-
                        phase oxidation HjS + %02 -»
                        S + H20 in an alkaline
                        solution of naphthoquinone
                        compounds
                                95% removal of HZS
                                                        Reduces sulfur species
                                                        to < 1,500 pp«iv
                                                        Reduces the outlet HJ.S
                                                        concentration to
                                                        30 ppmv
                                                        Reduces the outlet Hj>S
                                                        concentration to
                                                        
-------
                                                                    TABLE 5 1-9  {cont )
Control
Technology
Ferrox
Operating Principle Performance
M2S absorption and liquid- S5-992, removal of H2S
phase oxidation HZS * !s02 •»
S + H20 in a solution of
Na2CQ3 and Fe(OH)a
Development
Status
Few terrox plants
arc still in
operation
Advantages
Harked improvement over
dry-box purification due to
reduced installation and
labor costs.
Disadvantages
Sulfur from the ferrox
process is not suitable
for mast uses and
chemical replacement
costs are high.
Names
                 Molecular sieves remove HgS
                 and water.   HgS is stripped
                 from the bed and reacted with
                 $02 to form elemental  sulfur.
INDIRECT CONVERSION
MEA"
DEA"
HDEA
    ,a,b
AOlP/filPA3'"
(tednamine)
                 HSS and Cfl2 absorbed by a
                 regenerable reaction with
                 Honoethanolamine at ambient
                 temperatures.
                 lf2S and C02 absorbed by a
                 regenerable reaction with
                 Oiethanolamine at ambient
                 temperature.
Selective absorption of H2S
by a regenerable reaction
with Nethyldiethanolaniine.

Selective absorption of H2S
by a regenerable reaction
with Diisopropanotamine
Absorption of HZS by a
regenerable reaction witti
Diglyrolamine.
                                Reduces the outlet
                                concentration to
                                <5 ppmv.
                                Reduces the outlet
                                concentration to
                                30 ppmv
                                99% removal of H2S
                                                 99% removal  of H2S,
                                                 30-65% removal of C02,
Reduces the outlet H2S
concentration to
<100 ppmv
                                                 99% removal  of H2S.
                          Pilot plants in
                          operation in Canada.
                          Used almost exclu-
                          sively for years to
                          remove H2S and C02
                          from natural and
                          certain synthesis
                          gases.

                          Preferred choice for
                          treatment of high-
                          pressure natural gas
                          with high concen-
                          trations of COS and
                          CS2

                          Commercial plant
                          under construction.
More than 100 plants
constructed world-
wide.
                          Sour gas processing
                          irt operation.
                       Selective adsorption of H?S
                       in the presence of C02.  Also,
                       removes nwrcaptans
                       Simultaneous removal of H2S
                       and C02   Applicable to low
                       concentrations of HZS and
                       CO..
                       Predominantly used in refining
                       or aanufacturing.  Does not
                       absorb COS and CS2.
                       Higher selectivity to HaS than
                       primary or secondary amines.
Selective for H2S removal.
Substantial amounts of COS
removed without detrimental
effects   Low regeneration
steara requirements.

DGA similar to DEA with lower-
vapor pressure   Lower circu-
lation rates and steaw
consumption than OEA.
                                 Zeolite adsorption beds
                                 may become fouled,
                                 impairing regeneration.
                                 Nonselective for H2S
                                 (e.g , C02 also
                                 absorbed).  Reacts
                                 irreversibly with COS
                                 and C$2
                                 Nonselective for H2S
                                 Reclaiming requires
                                 vacuum distillation
                                 Reactions between MDEA
                                 and HCN are irreversible
                                                                                                                                   Can require long
                                                                                                                                   residence times for
                                                                                                                                   sufficient removal
                                                        BGA costs are high   High
                                                        corrosivity   Losses due
                                                        to reaction with C02, COS
                                                        and CS2 are high
                                                        Reclaiming requires
                                                        vacuum distillation
                                                                                                                                 (Continued)

-------
                                                                          TABLE 5 1-9  (rent )
Control
Technology
SNPA/DlAb






SCOTa,b







Operating Principle
Process utilizes experience
gained by SNPA in using OCA





Process uses DIPA to absorb
HgS from the Claus tail gas
Kon-H2S sulfur compounds are
converted to HZS before
absorption in DIPA. Regen-
erated HjS is oxidized to S02
before venting.

Performance
99% removal of H2S.






Reduces the outlet S02
concentration to
300 ppmv.




Development
Status
Widely accepted
choice for the
treatment of high-
pressure natural
gases with high
concentrations of
acidic components.
Several commercial
unfts in operation
since 1972.





Advantages
COS and CSZ are not harmful
to the solution. Decomposition
products removed by filtering
through activated carbon.



Removes all sulfur compounds.
Specifically suited for the
Claus tail gas cleanup.





Disadvantages
High pressure process
Vacuum distillation
probable.




DIPA removes ~30X CQ2
which is recycled to the
Claus process, diluting
the feed.



       (Hot Potassium
       Carbonate)
(Ji            b
O    Catacarb
      Giammarco-
      Vetrocoke

             a'b
      Altacid
      (Alkazid)
      DIAMOX
      Carl Still
                a,b
Process uses hot (UO^F)
potassium carbonate to absorb
C08 and B2S   Regenerated by
pressure reduction.
90-98X removal of H?S,
10-40% removal of cb%.
                       Similar to Benfield with the    Reduces the outlet H2S
                       use of a proprietary catalytic  concentration to
                       additive to the hot KHC03       <5 pprav
                       SEE DIRECT CONVERSION PROCESSES
Process uses various pro-
prietary absorption solutions
of alkaline salts and organic
acid.
Selective H2S removal  process
using absorption character-
istics of ammonia with total
(0 7 wtX NH3) liquid recycle

Selective 0*5 removal  process
using ammonia for absorption
(2 0 wt* NH3) with total
liquid recycle
Reduces the outlet H2S
concentration to
<5 ppmv
Reduces the outlet H2S
concentration to
100 ppmv.
                                                       Reduces the outlet
                                                       concentration to
                                                       —560 ppniv.
                   i2S
Process utilized
worldwide, with
further developments
in recent years
                                                          Plants ift operation
                                                          worldwide
Although operated
abroad since the
1930's, no known
commercial instal-
lations exist in the
U.S.

Recently developed
and commercialized
in Japan
Commercial process
now in operation
in the U S
High temperature permits usa
of highly concentrated solu-
tion   Process 1s very simple.
COS, CSj and RSH easily
removed.

Higher gas purity and lower
steam consumption than
Benfield.  Lower capita, 1 cost.
Solutions are relatively
noncorrosive.  Solution
tailored to requirements for
H2S selectivity and to minimize
effect of contaminants.
Add gas produced is suitable
Claus feed or sulfuric acid
plant feed   Low pressure
process.
Low pressure process.
Claus plant feed
                                                                                                                               Good
                                                                                                                                         High pressure process
                                                                                  High pressure process
Hay require special
alloys to handle hot
solutions.  High COS
concentrations result 1n
lower HjS removal
efficiency

Purge stream of ammonia
liquor Is produced.
H2S selectivity less than
DIAMPX.  Concentrated HH3
solutions are highly
corrosive.  Organic
sulfides are not removed.
                                                                                                                                       (Continued)

-------
                                                                          TABiE  •>  1-9   (tout  )
Control
Technology
ColHnb
,Selexola'b
Operating Principle
Selective H2S removal process
using NH3 for absorption with
total liquid recycle in a
six-stage spray tower.
Uses an anhydrous organic
solvent dimethylethter of
polyethylene glycol which
Performance
Reduces the outlet H2S
concentration to
-2,000 ppmv
Reduces the outlet H2S
concentration to
<1 ppmv
Development
Status
Commercial procasr,
now in use in
L u rope.
Few plants in opera-
tion for natural gas
treatment and for
Advantages "
Low pressure process Good
Claus plant feed
Nontoxic solvent partially
removes COS and organic sulfur
compounds
Disadvantages
Does not remove organic
sulfur compounds
Requires high partial
pressure of acid gas
                 physically dissolves acid
                 gases and 1s stripped by
                 reducing pressure without
                 adding heat

Fluor Solvent    Uses an anhydrous organic
                 solvent proprylens carbonate
                 which physically dissolves
                 acid gases.
       Pur1so1
              a,h
tn
       Sulfinol
       flmlsor
               afb
       Reetisol
               a,b
                       Uses  an  anhydrous organic
                       solvent  H-i»ethy1-2-pyrolidine
                       whtcti physically dissolves
                       acid  gases.
                        Uses  a  mixture  of  chemical
                        (BIPA)  and  physical  solvent
                        (sulfolane) and water.
                        Uses  a  mixture  of a chemical
                        (NEA/DEA)  and a physical
                        solvent (methanol).
                        Uses  physical  absorption  in
                        nethanol  at  low  temperature
Molecular        Use of molecular sieves to
j.   a,b         adsorb sulfur compounds.
                                                        Reduces  the  outlet HZS
                                                        concentration  to
                                                        <5  ppmv
Reduces the outlet H2S
concentration to
<4 ppmv and COa
concentration to
2-3 vol  %.

Reduces the outlet H^S
concentration to
<1 ppmv and C02 to
<5Q ppmv.
Reduces the outlet H2i
concentration to
<0.1 pprav and COj to
<5 pprav.

Reduces the outlet H2S
concentration to
<0 1 ppmv.
                                                        Reduces  the  outlet
                                                        concentration  to
                                                        <4  ppmv
                                                                                  synthesis  and  coal-
                                                                                  derived  gas
                                                                                  purification.
Plants 1n operation
for CO^ gases and
combination C02 and
HZS gases.

Four commercial
installations in
operation as of X979
Wide application in
the treatment of
natural, refinery and
synthesis gases.
                                                 Low operation costs
High H2S selectivity.   Par-
tially removes COS and organic
sulfur compounds
Removes COS and RSH   Capacity
of the sulfinol high at high
partial pressure of H2S.
Only semi-commercial
plants in operation.
Thirty-six plants
ai*e fn Operation
worldwide   Twelve
units are under
construction
                          Not widely used for
                          removing H^S from
                          gas streams
Capable of removing all
sulfur compounds.
Heat input low because
temperature is maintained by
flashing   Removes all
undesirable components (COS,
CS2, RSH, HCN) in a single
step.

Extended useful life
(3-5 years) of adsorbent
possible with properly
designed molecular sieve
Removes mercaptans.
                                 Solvent intended
                                 primarily for removal
                                 of C02
                                                                                                                                   Operating temperatures
                                                                                                                                   must be near an&ient and
                                                                                                                                   a certain minimum acid
                                                                                                                                   gas partial  pressure is
                                                                                                                                   required.

                                                                                                                                   Optimum operation
                                                                                                                                   requires high pressure.
                                                                                                                                   Solution absorbs heavy
                                                                                                                                   HC's, requiring flash
                                                                                                                                   tank separation

                                                                                                                                   Nonselective for H2S.
                                                                                                                                   Complex operation
                                                                                                                                   High solvent losses.
                                                                                                                                   Best suited for  higher
                                                                                                                                   pressures    Low
                                                                                                                                   temperature process
                                                        Preferably used on high
                                                        pressure streams
                                                        Regeneration gas
                                                        disposal
                                                                                                                                        (Continued)

-------
                                                                     TABLE  5 1-9  (cont  )
Control
Technology
Carbon Beda>b






Iron Ox1d«a'b
(Iron Sponge)




Katasulfb




?inc Oxide8



Operating Principle
Activated carbon catalytically
oxidizes H2S to elemental
sulfur at ambient tempera-
tures. Sulfur removed by
solvent washing.


HjS removed completely by
reaction with ferric oxide
2Fe2Q<, * 6H2S -» ?f e2Sa +
6H20 Exposure to afr
oxidizes re2S3 to Fej-Og and
sulfur.
Air and preheated gas with
HSS catalyzed to form S02
which is absorbed in an
aqueous ammonium sulfite-
blsulfite solution
The gas 1s passed through a
bed of zinc oxide, resulting
1n the reaction ZnO + H2S ->
ZnS + H20
Performance
Reduces the outlet H2i>
concentration to
0.2 ppmv




Reduces the outlet H2S
concentration to
0. 3 ppmv



Reduces the outlet H2S
concentration to
<4 ppmv


Reduces the outlet H2S
concentration to
0 2-0 5 ppmv

Development
Status
Sixty cominercial
plants in operation
in the U S




Very old process.
still used on a large
scale for the
treatment of coal
gases.

Large commercial
units in operation
worldwide.


One hundred cosnmer-
ciaT plants in opera-
tion worldwide

Advantages
Very pure sulfur is obtained.
Complete H2S removal.





Low pressure drop process.
Complete removal of HZS.




Produces a salable ammonium
sulfate



Virtually complete removal of
H2S


Disadvantages
Carbon 
-------
formation.  High  selectivity  for H2S removal can  also be achieved by taking
advantage of the higher H2S versus C02 absorption rates.

     The gas-phase direct conversion (Claus and Haines processes) consists of
thermal  oxidation  of one-third  of the  H2S  to S02,  followed  by a series of
catalytic  reactors  that react  S02 with the remaining H2S to form elemental
sulfur.  The  heat  for combustion in the  furnace  is obtained from the oxida-
tion  of H2S;  thus,   the  H2S  concentration  must  be  high enough  to sustain
spontaneous combustion.   Therefore, the gas-phase conversion requires an acid
gas stream with  a  higher H2S concentration than the liquid-phase conversion.

     Iid irect convars f on—There are essentially  five  classes of commercially
available,  indirect  H2S  removal  technologies that are used  in conjunction
with direct conversion technologies; these are, removal of H2S by:

       I. Alkanolamine

      II. Alkaline salts

     III. Aqueous ammonia

      IV. Physical  solvents

       V. Dry bed processes.

     The alkanolamine processes (I) remove acidic impurities, i.e., H2S, C02,
CCS, and  CS2) from gases  by  an acid-base chemical reaction with  the amine.
The process involves  an  absorption-regeneration cycle of a circulating amine.
CoRHionly used amines  are monoethanolamine (MEA),  methyldiethanolamine (MDEA),
diethanolamine  (DEA),  >diisopropanolamine (OIPA)   and diglycolamine  (DGA).
f>*ajor equipment systems used  in the amine process  are a -gas-amine contactor
(absorber) for absorption  of  the acid gases  and a regenerator (stripper) for
releasing the acid gas  from  solution.   A downstream sulfur recovery facility
is required to oxiaize,  or recover, the H2S.

     Alkaline salt  processes  (II) use  an aqueous solution  of a  buffered
potassium salt.   The  weak  alkaline solution  absorbs the  acid  gas components
of  the  feed gas.  The  process  operates  at medium  to  high pressures because
the absorption capability is  influenced by the acid gas (H2S and C02) partial
pressures.   The alkaline solution  is  regenerated by reducing the  rich  solu-
tion  pressure to  near  ambient  pressure, followed by  steam  stripping  and
sulfur recovery.

     The ammonia process (III) uses the same  mechanism for H2S removal as the
alkaline  salt process  (II)  except  the  ammonia  is  used as the  absorption
agent.   Regeneration  and additional sulfur recovery are necessary.

     Physical solvents  (IV)  have  low  heats  of solution and can absorb acid
gases in proportion to their  partial pressures.   These processes require high
acid gas partial pressures which are achieved at  low  gas pressures and high
acid gas concentrations, or at high gas pressures and low acid gas concentra-
tions.   Physical solvent processes  are  most  economical when the feed gas is
at  high pressure  and  bulk  removal of  the  acid  components  is desired.   A
high  aagree  of  selectivity  of  H2S absorption  is  possible, but  additional

                                     153

-------
 equipment is  required, increasing  costs.   A downstream  stilfur facility is
 also  necessary to recover  the H2S.

      Dry  bed processes  (V) generally employ  two  techniques  to  remove H2S from
 a  gas stream:   (1)  adsorption onto a dry bed,  such as a molecular sieve or
 activated carbon, followed by  desorption  of the H^S from the  bed using a hot
 gas  stream;   and  (2) reacting the  H2S with a dry  bed material  such as iron
 oxide to  form a solid  sulfide compound, which  is then oxidized  by  air to
 regenerate the dry  bed  and to form  elemental  sulfur.

      Sulfur;_Control  Technologies  Analyzed—

      The  fuel-based sulfur in  the  processed shale  is  the prime  source of the
 S02  emissions  from  the Lurgi-Open  Pit  plant.   The  residual  organic  matter
 remaining on the of! shale after retorting  is incinerated  in  the lift pipes,
 which results  in  the formation  of S02-   In addition, the hydrogen sulfide
 from  the retort gas  is  removed so  that the  gas  can be sold.   The separated
 H2S would also be a  source OT  sulfurous emissions  from the plant.  Since the
 plant does not consume  any fuels  (except for the  diesel fuel), there would be
 no additional  S02 emissions.

      The  concentration  of  SQz  in the  flue gas from a  4,400 TPSD Lurgi module
 is estimated to be about  30  ppmv (Rio Blanco Oil  Shale Co.,  February 1981).
 A  comparable  value  of  20 ppmv has  been estimated  for the Lurgi commercial
 plant processing  approximately   62,000 TPSD  of   oil  shale  at  Tract C-b
 (Occidental  Oil Shale,  Inc.  and Tenneco  Shale  Oil Co.,  April 1981).   These
 values  are  very  low  for   an indirectly  retorted  shale  such as  the  Lurgi
 processed  shale.   As an explanation for the low value,  Rio Blanco suggests
 that  approximately 93% of  the S02 formed during the processed  shale incinera-
 tion  reacts  irreversibly  with the   calcined  material  in  the processed shale
 and the excess  oxygen, forming  stable  sulfates.  The possibility of this type
 of reaction  has also been mentioned for the plant  at  Tract C-b and by Colony
 Development  Operation (see the MIS-Lurgi  and TOSCO II PCTMs,  respectively).
 Since the S02  concentration in  the  Lurgi flue gas is reported  to be at such a
 low  level,  SQ2  control technologies  were  not   examined  for the  flue  gas.

     As stated earlier,  instead of burning the retort  gas in the plant,  it is
 cleaned for  selling  purposes; therefore, its treatment by the DEA process is
 viewed as a   processing,  rather  than  pollution  control,  activity.   However,
 the acid  gases (H2S,  C02) from  the DEA process,  if  emitted  as such,  would
create pollution because approximately 700 Ib/hr of H2S (15,7 TPSD S02  equiv-
alent) are contained in,the gases.  The Holmes-Stretford process was examined
 for the removal  and recovery of  H2S  from  these  acid  gases.  This process is
 selective  in  removing  H2S  in the presence of C02.  The acid gases have a C02
to H2S  ratio of 80:1 and  only 6% of  the  C02  (approximately 3,300 Ib/hr)  is
estimated to  be absorbed by  the  Stretford solution; also, the H2S concentra-
tion  in  the   treated gas  can be  reduced  to 30  ppmv,  or  1.3  Ib/hr  (Peabody
Process Systems,  Inc.,  February 1981).   The H2S conversion reactions require
the presence  of large amounts of the  Stretford  chemicals,  and absorption of
C02 further increases the demand  for these chemicals.  Thus, at high absolute
concentrations  of both  H2S  and C02, the Stretford process  becomes  less  at-
tractive due  to  the  increased cost of solution circulation and regeneration.


                                     154

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     Although the  Stretford  process can remove H2S  efficiently,  this is not
the  case  for other  sulfur  compounds such as COS,  CS2,  mercaptans, etc.  In
general,  all  of these  compounds  have been found in  oil  shale retort gases,
and  Lurgi  has  indicated that COS is present in the Lurgi retort gas  (Private
communication with  Hans  Weiss,  Lurgi  Kohle  und Mineralotechnik  GmbH,  West
Germany, January 1981).

     Table 5.1-10  gives equipment and  cost details  for  the Holmes-Stretford
unit.   Since  this is  the only point of sulfur control  in the Lurgi plant,
the  table also  includes  the  cost of sulfur control.  A  specific  cost curve
based  on  the design of the  Stretford unit used in  this  i»anua1 is presented
in  Figure 5.1-6.   The  description and  stream characteristics  for  the Stret-
ford process can be found in Sections 3 and 4.
        FABLE 5,1-10.  MAJOR ITEMS IN THE HOLMES-STRETFORD PROCESS5
Capital Cost Items
Operating Cost Items
Knock-Qut Drum
     3' diameter x 7'

Absorber
     3' diameter x 65'

Cxidizers (6)
     15' diameter x 19'

Pump Tank
     26! diameter x 14"

Circulation Pumps (3)
     1,700 gpm 6 120 HP

Flash Drum
     3' diameter x 7'

Slurry Tank
     20' diameter x 40'

Slurry Pumps (2)
     75 gpm

Filte** System
     250 Ib/hr

Sulfur Melter
     200,000 Btu/hr
Holmes-Stretford Mix
     16 Ib/day

Soda Ash
     607 Ib/day

Process Water
     3 gpm

Steam
     207 Ib/hr

Cooling Water
     14 gpm

Electricity
     600 kW

Manpower
     3 Men/day

Direct Annual Operating Cost, $103
     Maintenance           134
     Operating Supplies    164
     Labor                 350
     Utilities             121
       TOTAL
769
                                                         CContlnued)
                                     155

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                            TABLE 5.1-10  (cont.)
Capital Cost Items                       Operating Cost Items

Sulfur Decanters (2)
     14' diameter x 14'

Sulfur Storage Pit
     75-ton capacity

Evaporator
     250 gpm liquor feed

Heater
     6,000 Btu/hr

Cooler
     4,000 Btu/hr

Feed Gas Booster
     90,000 ACFM @ 0 psig

Flash Gas Boosters (2)
     2,000 ACFM

Plot Area
     87,000 ft2

Site Preparation and Foundations

Ductwork and Piping

Electrical

Instrumentation and Controls

Painting

Fixed Capital Cost, $103    6,860

Total Annual Operating Cost, $10S    915

Total Annual Control Cost,b $103 ($/bb1)    2,044 (9.9)


a Design basis:  10,500 ACFM, 7.6 LTPSD sulfur recovered.

  See Section 6 for details on computation of the total annual control cost.
Source:  SWEC estimates based on information from Peabody Process Systems,
         Inc., February 1981.


                                     156

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e  :
                  456789
                                          SULFUR RECOVERED, LONG TONS/DAY

     SOURCE;   DRI  based on information provided by SWEC
                           FIGURE 5,1-6  COST OF SULFUR RECOVERY WITH STRETFORD PROCESS
10

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     Tota 1  Sul fur  Emfss 1 ons—

     Sulfur dioxide, as  such,  is emitted only  from  the Lurgi  flue gas dis-
charge  system  and  diesel  equipment.    In  addition,  the  Stretford  tail  gas
emits  HgS.   These  three  sources  constitute  the total  sulfur emissions from
the plant and these are listed  in Table  5.1-11.


              TABLE 5.1-11.  TOTAL SQ2 EMISSIONS FROM THE  PLANT

Stream
Number
24
31
63
Emission Source
Diesel Equipment
Flue Gas Discharge
DEA Unit
Control Description
—
—
Stretford
S02 Emissions
(Ib/hr)
35.6
500. 9a
2.4b
     TOTAL                                                        538. 9
& According  to  the information from Rio Blanco Oil Shale Co.,  February 1981,
  the control  of S02 occurs in the lift pipes by adsorption on the processed
  shale.  Approximately  93% of the S02  is claimed to be adsorbed, resulting
  in an S02  concentration of 30 ppmv in  the flue gas.

  According  to  the  information   from  Peabody  Process Systems,  Inc. ,
  February 1981,  H2S  in  the acid gases  from  DEA is reduced to a  level  of
  30 ppmv.   The  value given above  is  the  SQ2 equivalent from 1.3 "Ib/hr of
  H2S emitted in  the  treated gases.

Source:   SWEC estimates, except as  noted.


5.1.3  Nitrogen Oxides Control

     In  oil  shale processes,  nitrogen enters  the  system  from  two primary
sources:   (1)  the fuels derived from  the  raw shale,  and (2) the  air re-
quired  for   combustion  in the  various  furnaces,  heaters,  auxiliary boilers
and incinerators.   A portion of this  nitrogen  is  converted into other forms
such as  nitrogen  oxides  (NOx) and ammonia  (NH3).  The  NOx produced during
fossil   fuel  combustion  are  emitted   as  NO   and  N02  in  flue  gases.   These
compounds a^e formed  from the oxidation  of nitrogen compounds (e.g., ammonia,
cyanides) in the shale-derived fuels  and/or from the fixation of atmospheric
nitrogen  (N2).   A  large  portion  of ammonia  resulting  from the pyrolysis of
the  shale is  usually removed in  the  gas condensate,  or  foul  water,  when
the retort gas is  cooled or scrubbed with water.  This removal and subsequent
recovery  of  ammonia  provide  an indirect control  over  NOx emissions.   Since
the  recovery of  ammonia from an  aqueous solution  also  constitutes  water
pollution control, this  aspect of the  NOx control  is  discussed  under water

                                     158

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management  (Section 5.2).   The  portions  of ammonia  and fuel-based  nitrogen
that  are not  removed  in the  gas condensate  may require removal or  control
on"or  to emission to the environment.  Federal  and Colorado State standards
and  regulations  limit  NOx  emissions because  of  their potential  role in the
formation of photochemical  smog  and acid precipitation.

     Inventory  of ControlTechno!ogles—

     There are  three categories  of NOx control technologies:

     »    Reduction of  nitrogen  in the fuel

     <*    Combustion modifications

     •    Stack gas removal.

     These processes are shown in Figure 5.1-7 and  are discussed briefly in
Table 5.1-12.

     Reducl1on  of nltrogen  1n the fuel.  Burning fuels low in nitrogen is the
simplest  method of controlling NOx emissions  arising from fuel-based nitro-
gen.    Hydrotreatment of  fuel  oils  and water scrubbing  of fuel  gases are
fairly effective  in removing the  fuel-based nitrogen,

     Combustion modificati ons.    The generation of NOx by thermal fixation of
atmospheric  nitrogen  is dependent upon the  flame temperature,  concentration
of nitrogen,  time  history of  individual   combustion gas  pockets,  and the
amount of excess  air present.   To some extent, these variables are control-
lable, and the production of NOx can be minimized for a particular combustion
process.

     Combustion control  of  NOx  may be accomplished by  several  methods.   One
approach  is  design and  operation of burners  with  fuel-rich mixture  ratios.
This   technique,  called off-stoichiometric  combustion,  produces  low  flame
temperatures and, hence, potentially low NOx formation.  A significant excess
of oxygen is  avoided  in the combustion zone by diverting some portion of the
inlet air through remote locations in the  burner or through entirely separate
secondary combustion air ports.

     Another NOx reduction technique,  based on combustion modification, takes
advantage of  the strong temperature  dependency of nitric oxide  (NO) forma-
tion   on  peak  combustion temperatures.   Reduced flame  temperatures  may  be
obtained by direct  reduction of  gas temperature or by  indirectly increasing
heat  transfer.   Direct techniques  include  recirculating product  flue gases
back  into the combustion zone where  they  serve as diluents  absorbing heat,
thereoy  reducing  maximum  flame   temperatures  achieved.   Other direct  tech-
niques are  reduced combustion  air preheat  and  water/steam  injection.   The
latter is more  applicable  to gas turbines.   Indirect NOx  reduction relating
to the  combustion  process  usually involves furnace  designs with  increased
burner  spacing and  heat removal  capability.   Flame temperature  reduction
doss  not reduce NOx formation  from fuel nitrogen  but does  reduce atmospheric
N2 fixation.
                                     159

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NITROGEN OXIDES
    CONTROL
TECHNOLOGIES
                             FUEL NITROGEN
                               "REMOVAL *'
                              COMBUSTION
                              MODIFICATIONS
                               STACK GAS
                                REMOVAL
SOURCE:  SWEC
     NH3
  SCRUBBING
                                                             TWO-STAGE
                                                             COMBUSTION
                                                             LOW-EXCESS
                                                               AIR
                                                            FLUE GAS
                                                           RECIRCULATiON
                                                          LOWER TEMPERATURE
                                                          THROUGH FASTER
                                                          HEAT RELEASE
                                                             ACTIVATED
                                                              CARBON
                                                             ABSORPTION
  CATALYTIC
DECOMPOSITION
                                                             SELECTED
                                                            CATALYTIC
                                                            REDUCTION
                                                              THERMAL
                                                              DENOx
                                                           ELECTRON BEAM
                                                             SCRUBBING
                                                             ABSORPTION
                                                             REDUCTION
                                                             ABSORPTION
                                                             OXIDATION
                                                             OXIDATION
                                                            ABSORPTION
                                                             REDUCTION
         FIGURE 5.1-7   NITROGEN OXIDES CONTROL TECHNOLOGIES

                                    160

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                                                    TABLE 5.1-12.  KEY FEATURES OF NITROGEN OKIDCS CONTROL TECHNOLOGIES
       Control
       Technology
   Operating Principle
                                Performance
       FUEL NITROGEN ...REMOVAL.
       NH3 Scrubbing
Absorption of NH3 by counter-
current scrubbing with water.
Up to 100% of NHa
removal possible by
changing water rate,
composition and
temperature
                                                              Development
                                                                Status
                                                         Advantages
Commercially proven
Removes source of NOx before
formed   By-product NHs is
produced
                                                                                                                      Disadvantages
Does not reduce NOx
emissions formed by
thermal fixation of
nitrogen and oxygen in
combustion air.
eft
       Two-Stage
       Combustion
       (either low-
       emission
       burners or
       engineered
       combustion box)

       Low-Excess Air
       Flue Gas
       Recirculatien
       
-------
                                                                   TABLE 5 1-12  (cont )
Control
Technology
Thermal BeHOx
Electron Beam
Scr ut>b i ng
Absorption
deduction
Absorption
Oxidation
Oxidation
Absorption
Reduction
Operating Principle
HH3 injected In a 1,300-
1,800"F flam* zone where
NO + W\3 * N2 + H20
Removal of S02 and NOx by
reaction with MH3 in the
presence of electrons
Products are (NH^SO, *
NH4NOa
NOx 1s converted to HH3 by
tht reducing effect of S02 to
sake (MH«)XS04 with a liquid
Fe EOTA catalyst In a 20-tray
coluwi.
NOx and $02 art absorbed in
a KOH/KHn04 solution and »r«
oxidized to KHDa and K2504,
Either 0a or C102 are used to
oxidize NO to N02.
Performance
Up to 70% HQx removal
Up to 85% NOx, 90% iOs
removal
70-85% H0X, 90S SO,
resieval .
No data available
Up to 85* NOx, 95% SOZ
removal if S0;./H0x
ratio is 2.5.
Development
Status
Demonstrated
commercial ly
Pilot plant stage
only
Hot demonstrated
commercially.
Not demonstrated
commercially
Not demonstrated
commercially.
Advantages
By-product recovery not
required tow capital cost.
Simultaneous removal of SO*
and NOx
Ho oxidizing agent required.
Sinultaneous removal of S02
and NOx.
Simultaneous renaval of SOS
and NOx
01 satlsantages
Requires large amounts «f
N% Narrow operating
range .
Power consunption is 3%
of plant output for beam
accelerator High
capital cost Require*
nigh efficiency ESP
R«
-------
     Stack gas removal.   Flue gas treatment for  NOx removal  is a  relatively
new,  developing  technology.    Two  broad categories  may  be  defined:   wet
processes  in which  NOx  is  absorbed into an aqueous solution,  and dry  proc-
esses in which NOx is  reduced by  ammonia.

     The wet NOx removal processes also serve as  a mechanism to reduce sulfur
dioxide  emissions  and, as such,  can provide  effective environmental control
wnere both pollutants  are present.   However, due  to  the low solubility of NOx
in  aqueous  solutions and the low removal efficiencies obtainable,  absorption
techniques usually prove to be  very  expensive.

     Dry  NOx  removal   systems,  in  general,  display  higher  nitrogen   oxide
reduction  capabilities and  are  economically more  viable than wet systems.
These  processes  are  usually  ammonia  based  and  may be  selective  or  non-
selective and catalytic or noncatalytic.  Depending on the individual process
applied, ammonia  is  injected into the  flue gas  at some point after complete
combustion and prior to a minimum gas temperature of 350°F.  In the resulting
reaction,  NOx combine with  ammonia to  form  molecular nitrogen  and water.

     NitrogenOxides Control Technologies Analyzed—

     The primary source of NOx emissions from the Lurgi-Open Pit plant is the
Lurgi flue gas  discharge  system.   According to Rio Blanco, the NOx emissions
in  the  Lurgi flue  gas originate only  from the  fuel-based nitrogen  in the
organic  residue  on  the-, processed shal.e.   The temperature in  the  lift pipes
(1,240°F) is  claimed to  be  low enough so that thermal fixation of the atmos-
pheric  nitrogen  does  riot  occur  during- processed  shale incineration  (Rio
Bianco Oil Shale  Co.,  February 1981). •  Since there  is JIG  fuel  combustion in
the plant, additional NOx emissions are not formed.

     Ammonia in the Lurgi retort gas is removed during product liquor conden-
sation.   Since this  is an integral  processing step  in  the Lurgi  technology,
it is not considered a pollution control measure.

     Once  removed  in  the Lurgi  gas  liquor,  the actual  recovery  of NH3  is
achieved with an ammonia  recovery process.   Since the process  is  considered
to be a water treatment technology, it is discussed in Section 5.2.

     The modified DDP for Tract C-a (Rio Blanco Oil  Shale  Co.,  February 1981)
reports that the concentration  of NOx in the flue  gas  is 300 ppmv, which is
equivalent to 3,600  Ib/hr of  N02, or 2,430 Ib/hr NOx assuming 90% NO and 10%
N02, by weight.   In a separate organic nitrogen material balance presented in
the  same  document,  however, 0.3  Ib  of  organic nitrogen/ton of raw shale  is
reported to  be  converted to NOx.   This latter value is equivalent to  about
4,900 Ib/hr N02,  or 400 ppmv in the flue gas.

     If the  formation  of NOx  in the flue gas  is due only to  the  oxidation
of  fuel-based  nitrogen,  as  is  claimed  by Rio  Blanco (.Rio Blanco  Oil  Shale
Co., February 1981),  combustion modifications  cannot be employed to  control
the  NOx.   Also,  techniques  do  not exist for removing organic  nitrogen  from
the  processed  shale.   However, if  thermal  fixation of atmospheric nitrogen
does occur  in  the  lift pipes,  combustion modifications  can  be  applied  in

                                     163

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order  to  reduce the NOx formation.  The stack gas NQx removal techniques may
be applicable regardless Of the origin of NOx; but most ofsthe« have not been
successful  in  commercial-scale,   continuous  operations.    Only  refrigerated
tanks  for the  storage  of ammonia were  examined as  an  indirect NOx control
measure.   The fixed  capital  cost  for the  storage tanks  is  estimated to be
$466,000  and  the total  annual operating cost  is  $15,000.   This  results in a
total  annual  control  cost of $88,000* or 0.4 cents/bbl of oil (see Section 6
for  details  on  computation of the total annual  control  cost).   The cost for
the  ammonia  storage tank£ also constitutes the total cost of NQx control for
the plant.

     Total Nitrogen Oxides Emissions—

     There  are  only  two  plant emissions that contain N0x--the  flue gas and
diesel  exhaust.   The quantities  of NOx  in the two streams are  listed in
Table  5.1-13.
              TABLE 5.1-13.  TOTAL NOx EMISSIONS FROM THE PLANT

Stream
Number
24
31

TOTAL

Emission Source
Diesel Equipment
Flue Gas Discharge
System

NOx Emissions3
(Ib/hr)
469.9
2,432.4b

2,902.3

a Expressed as 90% NO and 10% N02, by weight.

  Value is based  on 300 ppmv NOx in the flue gas, according to the informa-
  tion from Rio Blanco Oil Shale Co., February 1981.

Source:  SWEC estimates, except as noted.


5.1.4  Hydrocarbon Control

     Hydrocarbon  compounds are  emitted to  the  atmosphere as  a  result  of
incomplete  fuel  combustion  or as  a fugitive emission  from small  leaks  in
processing or storage equipment.

     The hydrocarbon emissions from noncombustion sources are usually refer-
red to as  volatile  organic compounds (VOC) or reactive hydrocarbons (RHC)  in
government regulations  restricting their emission.   Federal  and State regu-
lations  limit  these  hydrocarbon  emissions  because  of  their  role  in  the
formation of photochemical smog and ozone production.
                                     164

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     Inventory of Control Technologies—

     As  illustrated  in  Figure 5.1-8  and  discussed  in  Table 5.1-14, hydro-
carbon  emissions  can be  controlled by  the  following categories  of control
technologies:

     *    Additional sealing of process equipment

     *    Vapor recovery

     «    Complete fuel combustion

     «    Catalytic converters

     *    Thermal oxidizers.

     Additional sealing of process equipment.   Hydrocarbon  emission control
by additional  sealing of  process and  storage equipment  is best accomplished
by engineering these  features  into the plant.  This includes double seals on
tanks,  pumps,  and  other  rotating machinery,  closed-loop sampling,  caps on
open-ended  valves,  and periodic monitoring of equipment  to  find hydrocarbon
leaks quickly.  This  will  result in a minimum additional  plant capital cost
and will more  than  pay for itself due to the value of the hydrocarbons which
are prevented from being emitted.

     Vapor recovery.  When  hydrocarbon vapor emissions  cannot be controlled
by additional  sealing of  equipment,  a vapor recovery system can be installed
to collect  and condense the vapors  by refrigeration and  return  them to the
process.

     CgjHplete fuel combustion.   The most cost-effective way to control hydro-
carbon  emissions  from fuel combustion processes is  to  operate  the process
with enough  excess  air to  ensure complete oxidation of  all  hydrocarbons to
C02 and 1^0, i.e., complete fuel combustion.

     Catalytic converters.   When complete fuel combustion does not occur, the
hot exhaust  gas  from  the  process can  be sent through a catalytic converter.
In the  catalytic converter,  the  gas is  passed over  a catalyst where the
unburned hydrocarbons are reacted  with the excess air in the exhaust gas and
are converted to C02 and H20.

     Thermal oxl dl zers .   Hydrocarbon  vapor  streams or  any  other waste gas
stream containing unburned  hydrocarbons  can  be burned in  a  thermal  oxidizer
with excess  air and additional  fuel,  if  needed;  this completely oxidizes all
hydrocarbons to C02  and H20.

     Hydroca rbon Control  Techno 1 ogj e $
     The hydrocarbon emissions  in  the  iurgi-Open Pit plant emanate  from the
leakage  in  the  valves,  pumps, etc.,  as the  fugitive  emissions  from  oil
product storage,  and due to the incomplete combustion of the fuels.

     Hydrocarbon emissions  from diesel -burning  equipment are controlled  by
installation  of, catalytic  conversion  systems.   The  least costly  fugitive

                                     165

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     HYDROCARBON
      CONTROL
     TECHNOLOGIES
                                  ADDITIONAL SEALIN6
                                     ON PROCESS
                                     EQUIPMENT
                                       VAPOR
                                      RECOVERY
COMPLETE FUEL
 COMBUSTION
                                     CATALYTIC
                                    CONVERTERS
                                      THERMAL
                                     OXIDIZERS
SOURCE' SWEC
       FIGURE 5J-8   HYDROCARBON CONTROL TECHNOLOGIES

                           166

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                                                      TABLE 5,1-14.  KEY FEATURES OF HYDROCARBON CONTROL TECHNOLOGIES
Control
Technology
Additional
Sealing on
Process
Equipment
Operating Principle
Double seals an pumps and
rotating machinery and caps
on open-ended valves reduce
hydrocarbon losses from the
equipment
Performance
About 60%-65% reduction
of fugitive hydrocarbon
emissions Is possible
with this level of
control
Development
Status
Commercially proven.
Advantages
Requires a small capital and
operating cost and will
probably more than pay for
this cost due to the value of
the hydrocarbons which are
prevented from being emitted.
Disadvantages
Should be implemented
during naw plant
construction Requires
more capital Investment
to retrofit the controls
of an existing plant.
tn
       Vapor Recovery
Complete Fuel
Combustion
       Catalytic
       Converters
       Thermal
       Qxidizers
Hydrocarbon vapors emitted
from process equipment are
collected and condensed by
refrigeration and then
returned to the process

Combustion process 1s operated
with excess air to ensure
complete oxidation of all
hydrocarbons to C02 and H20.

Hot exhaust gas Is passed over
a catalyst where the unhurried
hydrocarbons are reacted with
the excess air 1n the exhaust
gas and are converted to C02
and H20.
                 Waste gas streams  containing
                 unburned hydrocarbons ire
                 burned with excess air and
                 additional  fuel  1f needed to
                 completely  oxidize all
                 hydrocarbons to  C02 and H20.
About 80-90% of the       Conacre tally proven.
hydrocarbon vapors can
usually be condensed
and returned to the
system.

Can convert close to      Commercially proven.
100% of all hydrocarbons
in the fuel to C02 and
HZ0.
                                                 Can convert up to BOSS
                                                 of the hydrocarbons In
                                                 diesel exhaust gas
                                                 streams to C02 and H20,
                                                 for other fuel burning
                                                 processes, up to 99%
                                                 conversion 1s possible
                                Can convert close to      Com
                                1QOX of all hydrocarbons
                                in the gas stream to C02
                                and H20
                          Commercially proven.
                              erclally proven
                                                                                                  A reliable system which is
                                                                                                  best applied to potential
                                                                                                  point source emission streams.
Eliminates the need for
downstream equipment to
complete the conversion of CO
to COZ.

Does not require any fuel and
has no moving parts so that
routine maintenance Is minimal.
Will ensure complete oxidation
of hydrocarbons and any other
unwanted components in the gas
stream.
                                 Can be a high energy
                                 requirenent to operate
                                 the refrigeration system.
An adequate air.fuel
ratio must be maintained
The catalyst, which is
expensive, must be
replaced periodically.
Can have a high energy
requirement when supple-
mental fuel is used.
       Source:  SWEC based on information from Research and Education Association, 1980

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 hydrocarbon  emissions control for storage  tanks  is proper sealing.  Alterna-
 tively,  vapor recovery  can be  used,  but  the  expense is extremely high for
 these  systems.   As  a standard industry practice,  double-sealed, floating roof
 storage  tanks  are  provided  for  volatile  product storage.   Internal  plant
 leaks  are  controlled by use  of  adequate seals and strict maintenance proce-
 dures.   Approximately 232  Ib/hr  of  hydrocarbons  (expressed  as  methane) are
 estimated by Rio Blanco  for the  4,400  TPSO  Lurgi  module (Rio Blanco Oil Shale
 Co., February 1981)..  Except for  using  proper  combustion practices, no other
 technologies are provided to reduce the hydrocarbon release in the flue gas.

     Table 5.1-15 lists  the hydrocarbon  control  practices and equipment con-
 sidered, and Table 5.1-16 presents the  costs for hydrocarbon control for the
 entire plant.


         TABLE 5.1-15.   HYDROCARBON CONTROL PRACTICES  AND EQUIPMENT
Capital Cost  Items                                Operating Cost Items

Floating Roof Storage Tanks (2)                   Maintenance
  200' diameter x 48', 268,000 bbl  (each)
  Welded API  550 code
  Double seals
  Carbon steel

Complete Combustion of Fuels

Dual Mechanical Seals on Pumps and  Valves

Catalytic Converters on all Diesel  Equipment

Monitoring Equipment
Source:  SWEC.
     Total Hydrocarbon Emissions—-

     Table 5.1-17  summarizes  the hydrocarbon  emission sources  and control
equipment used for the emissions.

5.1.5  Carbon MonoxideControl

     Carbon  monoxide  (CO)  is usually  formed by  incomplete  combustion  of
fossil  fuels.   Normally,  an  excess  of oxygen  Is  supplied to  a combustion
process to ensure  that all of the  carbon  in the fuel is converted to carbon
dioxide (CG2).  When  a shortage  of oxygen  occurs in the combustion process,
some  of the  carbon  is  only  partially oxidized to CO.  Federal  and  State
standards  and regulations  limit CO  emissions because  of  their deleterious
effect on the human respiratory system.
                                     168

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                                 TABLE 5.1-16.  COST OF HYDROCARBON POLLUTION CONTROL
CB  -
<£>  -

Stream
Number
24
, 112
44, 47
Control
Description
Catalytic
Converters
Maintenance
Floating Roof
Storage Tanks
Control Location
Diesel Equipment
Valves, Pumps, etc.
Product Storage
TOTAL
Fixed
Number Capital Cost
of Units ($000' s)
170
61
2 300
531
Total
Annual Operating
Cost ($000 's)
65
(59)b
(Ml)
(135)
Total
Annual Control
Cost ($000' s)a
106
(44)
(89)
(27)

       See Section 6 for details on computation of the total annual control cost.

       Values in parentheses ( ) indicate profit after subtracting the total annual capital and operating
       charges from the annual by-product credit of $125,000 from maintenance and $155,000 from the storage
       tanks, both at $32/bbl of oil.

     Source:   DRI estimates based on information provided by SWEC.

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           TABLE  5.1-17.   TOTAL HYDROCARBON  EMISSIONS  FROM THE PLANT

Stream
Number
24
31
Emission Source Control Description
Diesel Equipment Catalytic Converters
Flue Gas Discharge
Hydrocarbon
Emissions (Ib/hr)
12.7
6,261.7*
              System
112
44,
47
TOTAL
Valves,
Product
Pumps, etc.
Storage
Maintenance
Floating
Tanks
Roof Storage
35.
65.
6,376.
5
5
4

* According  to  the information from Rio Blanco Oil Shale Co.,  February 1981,
  about  232  Ib/hr  of hydrocarbons (expressed as CH4) are estimated from the
  4,400  TPSD  Lurgi module  (the  processed shale rate is  3,518 TPSD).   The
  reported value  is extrapolated for the  commercial  operation (94,956 TPSD
  of processed  shale).

Source;  SWEC estimates, except as noted.


     The  easiest  and most  cost-effective way to  control CO  emissions is to
use excess oxygen  in the combustion processes to  ensure complete combustion.
When  incomplete combustion does occur,  catalytic converters  or  thermal  or
chemical oxidizers  may be used to oxidize the remaining CO to C02.

     Inventory  of Control Technologies—

     Figure 5.1-9  shows a  list  of  the  applicable carbon monoxide  control
technologies,  and  Table 5.1-18  describes  in  detail the features of these
control methods.

     Complete fuel  combustion controls  CO emissions by  not allowing  them to
be formed.   This  is done by  operating  with  enough excess air to ensure com-
plete oxidation of  all carbon to C02 instead of only partial oxidation to CO.
When CO  is  formed in a combustion process,  a  catalytic converter or thermal
or chemical oxidizer can be used.

     Carbon MonoxideControl Technologles Analyzed—

     By far,  the largest amount of CO is emitted from the Lurgi flue gas dis-
charge system.   The sources  of  this  CO may be the incomplete combustion of
the  residual  organic  matter  on  the processed  shale,  decomposition  of  the
carbonate  minerals,  and  a  steam/coke  reaction  in  the  processed  shale
quencher/moisturizer.  To maximize  the  combustion of the organic residue, an

                                     170

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         CONTROL
       TECHNOLOGIES
                                   COMPLETE FUEL
                                     COMBUSTION
                                    CATALYTIC
                                    CONVERTERS
                                     THERMAL
                                    QXIQIZERS
                                     CHEMICAL
                                     OXIDIZERS
SOURCE: SWEC
    FIGURE 5.1-9   CARSON MONOXIDE CONTROL TECHNOLOGIES

                           171

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                                                    TA8LE 5.1-18   KEY FEATURES OF CARBON MONOXIDE CONTROL TECHNOLOGIES
"si
PO
Control
Technology
Complete Fuel
Combustion
Operating Principle
Costbustlon process is operated
with excess air to ensure
complete oxidation of all
carbon to C02, instead of
only partial oxidation to CO
Performance
Can convert close to
100X of all carbon in
the fuel to CO^.
Development
Status
Commercially proven.
Advantages
Eliminates the need for
downstream equipment to
complete the conversion of CO
to C0t
Disadvantages
An adequate a1r:fuel
ratio must be maintained
       Catalytic        Hot exhaust gas is passed over
       Converters       a catalyst where the CO in the
                        gas is reacted with the excess
                        air !n the exhaust gas and is
                        converted to C02.
Thermal          Waste gas streams  containing
Oxidizers        CO are burned with excess air
                 and additional fuel If needed
                 to completely oxidize alt CO
                 to CO*

Chemical         Gas streams containing CO are
Oxidizers        scrubbed with a solution
                 containing a chemical  oxi-
                 dizing agent which oxidizes
                 the CO to C02.
Can convert up to 90S!
of all CO in diesel
exhaust gas to COg; for
other fuel burning
processes, up to 99%
conversion Is possible.

Can convert up to 100%
of all CO in the gas
stream to C0j.
                                                        Can convert up to 99%
                                                        of all CO In the gas
                                                        stream to CO;.
                                                                           Commercially proven
Commercially proven
                          Commercially proven.
                       Does not require any fuel and
                       has no moving parts so that
                       routine maintenance Is minimal.
Will ensure complete oxidation
of CO to C02 and complete
oxidation of any other unwanted
components In the gas stream.
                       Oxidizes the CO to C02 without
                       using fuel to heat up the
                       entire gas stream.
The catalyst, which 1s
expensive, must be
replaced periodically
Can have a high energy
requirement when Supple-
mental fwel 1s used.  *
Requl res the use of
expensive chemicals
       Source   SWEC based on Information from Research and Education Association,  1980.

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excess  of air  is  used.  Decomposition  of  carbonates is unavoidable  because
the  processed  shale  recycle  stream  has  to  attain  a high  temperature  to
provide the heat of  retorting.  The steam/coke reactions may also  be unavoid-
ab'a.

     The  CO content  of the flue  gas  is reported  to  be  less than 90  ppmv.
"^"his may  be reduced further by the post-combustion of  the  flue gas; however,
due  to  the large volume and low  heating value of the  flue gas,  it would  be
Inpractica'.

     Diesel-powered  equipment is  another  source  of  the CO  emissions.   The
diesel  engines are  equipped  with catalytic  converters  to control  the CO.
Since the  converters also control  hydrocarbons, they  have been included  under
hydrocarbon emission control.

     Total Carbon Monoxide Emissions--

     Table 5.1-19 summarizes the carbon monoxide emission sources and  control
equipment  used for the emissions.


              TABLE 5.1-19.   TOTAL CO EMISSIONS FROM THE PLANT

Stream
Number
24
31

TOTAL

Emission Source
Diesel Equipment
Lurgi Flue Gas Discharge
System

CO Emissions
Control Description (Ib/hr)
Catalytic Converters 34.8
657.4*

692.2

* According to  the  information from Rio Blanco  Oil  Shale Co.,  February 1981,
  the flue gas contains about 90 ppmv CO.

Source:   SWEC estimates, except as noted.


8.1.6  Control of Other Criteria Pollutants

     In addition to the primary air pollutants discussed so far, there may be
oths" criteria  pollutants,  such  as lead, mercury,  beryllium  and fluorides,
emitted  from  the  Lurgi-Qpen   Pit  facility.   Some  of  these pollutants  are
nonvolatile; therefore, they may  be released only as fugitive dust constitu-
ents.  Any  control  of  the  dust will  also serve to  control  the nonvolatile
pollutants.   Volatile  pollutants  may potentially be  released with  the Lurgi
flue gas  and/or the tail  gas   from the Stratford  process.   Some pollutants
do  not   occur   naturally  and  some are  unlikely to form  during oil  shale
processing.

                                    " 173

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 5.1.7   Control  of Moncn'teria Air Pollutants

     Meaningful  test data are not available to  determine whether emissions of
 noncriteria air  pollutants  are a  concern.   Consequently,  no information on
 control  technologies for such pollutants was  generated  for this manual.  Men-
 tion  of species  such as  PQMs (U.S.  EPA,  1980) and trace  elements such as
 arsenic (Fox, Mason and Duvall,  1979;  Girvin,  Madeishi  and Fox,  June 1980)
 are noted.

 5.2  WATER  MANAGEMENT AND POLLUTION CONTROL

     As in  other  industries  and  oil  shale operations, the  Lurgi-Open Pit
 plant—from mining  activities  to final  product and waste disposition-~wi11
 produce water effluents which will require proper disposal.  These  effluents
 may contain the  following pollutants:

     *    Suspended Matter,  Oil and Grease

     *    Dissolved Gases and Volatiles

     *    Dissolved Inorganics

     «    Dissolved Organics.


     This  section  describes the  current,  commercially  available  alternate
 systems  for controlling  the  above  pollutants.  The following subsections pro-
 vide inventories  of control  technologies  for  each of the pollutant classes, a
 discussion  of advantages and disadvantages,  and important points to consider
 in selecting a particular technology.  The performance, design, and  cost date
 for the  leading  technologies are  also presented.

 5.2.1   Suspended  Matter,  Oil  and Grease

     Undissolved  matter  found in  wastewater  effluents  includes  solid parti-
 cles as well as  oils  and greases.  The solids   are usually the raw  and proc-
 essed  shale particles  that  are washed into  the retort water  and  those that
 are entrained in the  retort  vapors and  subsequently removed in the gas con-
 densates.   The  retort water and gas condensate  also contain trapped oil and
 oil-in-water emulsions.   Service  and  storm runoffs contain suspended matter,
 as well  as  oils  and  greases.  Also, the  source  water contains suspended soil
 particles and debris.

     In  general,  the control of suspended matter at oil shale plants will be
 accomplished using  conventional  technology.   For example,  clarification in
 gravity  settlers  (with  addition  of  flocculants) and  multimedia  filtration
will,  in most cases,  provide adequate control.   Associated energy consumption
 and costs are generally  low.

     The control  of  undissolved oils- and  greases in oil shale wastewaters has
 not been studied in detail.   API-type gravity settlers have the potential to
 provide  adequate  control  for most of the waste  streams generated.   It is
 possible, however,  that some wastewaters  will contain oil-in-water emulsions;
 if so,  additional  control steps may be required.  Heating the water or adding

                                     174

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chemicals  may  be sufficient  to break  the  emulsion; otherwise,  filter coa-
lescence (or possibly ultrafiltration) may be required.

     The degree  to  which emulsified oil needs  removal  is dependent on down-
stream  processing  and  reuse.   In  cooling  towers,  the oil  may  foul  heat
exchange surfaces  and thus  require prior removal.   Similarly,  fouling,  and
possibly foaming,  may occur  when  stripping the retort  water  or gas conden-
sats.  The extent to which such problems will arise is not known.

     The energy  consumption  and cost of oil separation  by  gravity means are
generally  low.   Thermal  or chemical treatment, if required, would cause some
increase in  costs.   Filter  coalescence and,  in  particular, ultrafiltration
generally  are  more costly  and would be considered  only if other procedures
prove inadequate.

     Inventory of Control Technologies—

     Figure 5.2-1 shows different types of technologies  that apply to control
of suspended matter and oils and greases.  Key features  of these technologies
are provided in Table 5.2-1.

     API-type separators.   For gravity  separation  of  oil   in  large holding
tanks, seoarators  should be designed within the following  limits:  (a) hori-
zontal velocity  of  less  than 3 fpm, (b) depth between 3-8 ft,  and (c) depth-
to-width ratio  of approximately 0,4.   Oil   is  skimmed   from the surface  and
collected  for  reuse or  disposal.   Gravity  separation  is not  effective  for
emulsified  oils  that  might  be  present  in  some  retort  waters  (American
Petroleum Institute, 1969).

     Sedimentation.   This  is  a gravity  process  in which  the solid  phase
settles and  is withdrawn  as  a slurry.   Clarification may be  carried  out  in
large holding  ponds,  plate  (lamella)  settlers or hydrocyclones.   Chemicals
(flocculants and coagulants) may be added to  precipitate salts  (softening)  or
to aid settling of suspended solids (Humenick,  1977).

     Flotation.  This  is a gravity process in which the solid  phase rises  to
the  surface  and is skimmed off as  a slurry.  Air bubbles may  be  introduced
into the flotation vessels to assist separation (Humenick, 1977).

     Csntrifugation.   This is  a modified gravity method to  afford separation
or settling of  fine,  suspended matter and oils.   The wastewater is subjected
to  a radial force  greater than the gravity field  by  rapidly  rotating  it.
Suspended matter  denser  than  water moves radially  away from  the  center  of
rotation,   while  the lighter  matter moves toward  the center.   Concentrated
matter can be removed periodically  or in a continuous manner.  For continuous
operations,  the  sludge  should  be  fluid to  facilitate its  removal.  The
technology may not be applicable to highly viscous  fluids.

     Coagulation - fjocculation.   Fine. particles  suspended in  a  fluid are
subjected to size enlargement by addition of chemicals  (coagulants and floc-
culants),  then allowed to  settle by gravity or under applied  force.   Gentle
agitation alone  sometimes  may afford the flocculation of the particles.  The


                         .         '  ' 175

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  SUSPENDED
 MATTER, OIL 8
 GREASE CONTROL
  TECHNOLOGIES
                                 GRAVITY
                                 SEPARATION
                                CENTRIFUGATtQN
                                  PHYSICAL/
                                  CHEMICAL
                                  FILTRATION
 API-TYPE
"SEPARATORS

•SEDIMENTATION
                                                   • FLOTATION
 COAGULATION-
 FLQCCULATION

•CHEMICAL SEPARATION

.THICKENING




• SOLIDS FILTRATION

• FILTER COALESCENCE

• ULTRAFILTRATtON
SOURCE' WPA
  FIGURE 5,2-1  SUSPENDED MATTER, OIL AND GREASE CONTROL TECHNOLOGIES

                                 176

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                               TABLt 5.2-1   KEV FEATURES OF CONTROI  TECHNOLOGTCS FOR SUSPENDED MATTER, OHS AMD GREASES
Control
Technology
     Operating Principle
                                  Components
                                  Removed
Removal
Efficiency
Feed
Requirements/
Restrictions
By-products
and Wastes
                                                                                                                Comments,
Gravity Separation
(API-type
Separators,
Sedimentation,
Flotation)
Csntrifugaiion
Provision of adequate residence   Suspended        90+% removal of
time in a stagnant vessel to      solids,          TSS typical for
allow suspended matter to         tars, oils,      sedimentation,
separate Into lighter and         Immiscible       50% for
heavier than water components.    liquids.          flotation.
Extra surfaces may be included
to save space (lamella settler),
or rising air bubbles nay be
used to assist separation
(dissolved air flotation).

A greater than gravity force      As above         As above
field is applied by rapid
rotation to accelerate the
separation
                  Minimum feed
                  stream
                  turbulence.
                 Oils, sludges,
                 sol ids
                   Not useful for emulsions
                   or very fine particles
                                                                                                           As above.
                                                      More expensive than
                                                      gravity separation.
                                                      Used for predrying
                                                      sludges from gravity
                                                      separation devices or
                                                      for separation of fine
                                                      particles.
Physical/Chemical
(Coagulation*
Flocculatlon,
Chemical
Separation,
Thickening)
Filtration
(Solids Filtra-
tion, Filter
Coalescence,
UltrafHtration)



Use of agents to promote the
coalescence of fine suspended
solids, tars and oils.
Generally used in conjunction
with a gravity separation
process.
Involves passing wastewater
through a suitable filter
medium. Filter material 1s
discarded cr cleaned by
backf lushing



Promotes
removal of
finely
dispersed
particles

Depends on
medium Both
coarse and
fine
structure
materials
are used
industrially.
90+% removal of
„ fine solids is
achievable with
proper design.


90-99% is
typical.





.'. 	 •
A wide range
of commercial
flocculants
are available.


Filter media
(sand, clay,
fabric or
polymeric
membrane)


	
Same as
gravity
separation.



Filter backwash,
spent filter
media.




	 ,. 	
Widely used in makeup
water treatment systems
to remove fine solids.



Filter coalescence or
ultrafiltration are use-
ful for oil emulsions.





Source:   WPA.

-------
 technology may also be  applicable  to liquid dispersions-and liquid particu-
 lates.-   -•        •-.'"•.         "  .   " "          '* """'          '   '"

      Chemical  separation.   Addition  of  chemicals  to break  emulsion  way be
 used  in  conjunction  with filtration and*is normally followed  by gravity sepa-
 ration.   The  type  and dosage  of  chemicals required  is  determined by trial
 (American Petroleum  Institute,  1969).   Chemicals may also be  added to precip-
 itate sa1ts.or_ to  increase crystal  size.

      Thickening.   Slurries previously obtained  from gravity, centrifugation,
 and filtration methods can be  further concentrated,  or thickened, by addition
 of  chemical agents  or binders.  The  thickened  slurry may then be subjected
 to  the  same  methods  for  final  disposition  (Adams  and  Eckenfelder,  1974;
 Humenick,  1977).

      Solids filtration.   The water  stream is  passed through  a filter medium
 which holds back the solid phase.   Filters may be of the fabric type, as in
 plate and frame, rotating drum  (vacuum)  and cartridge units, or granular, as
 in  sand  filters.  Filtration  is generally more expensive than sedimentation
 but can  remove smaller particles (Humenick, 1977).

      Filter coalescence.   Gravity   separation  of oil  from water  is standard
 industrial  and refinery  practice; however, the API-type separators are inade-
 quate for  very  small  oil particles.  One very  important method  for removal
 of  small   oil  droplets  is   coalescence (Water   Purification  Associates.
 December  1975).

      When   a  dispersion  of micron-sized  droplets  of one  liquid  (oil)  in
 another  (water)  flows through  an appropriate porous solid, coalescence of the
 dispersed  phase is induced and separation of  the liquids results.   The dis-
 persed phase can be allowed to accumulate without  leaving the porous medium,
 with  periodic  regeneration to  remove  accumulated oil.

      Filter media  are usually either the packed fibrous type  (e.g.,  fiber
 glass, steel  wool)  or unconsolidated granular materials (e.g., sand, gravel,
 crushed  coal).  Because of their   large  specific  surface  and  high  voids,-
 fibrous media  are usually  more efficient  in removing droplets for a given bed
 depth than  are granular media.  However,  fibrous  media  are  more susceptible
 to  blockage by suspended  solids  and are more  difficult to  regenerate,  in
 addition to being more costly than  most granular media.

      Advantages  of filter-coalescers  include  high separation efficiency for
 dilute suspensions  of very small droplets, potentially  small space require-
ments, the possibility  of continuous operation,  and  the potential for  the
 recovery  of the  dispersed phase.   Disadvantages  of  this process  are  that
 suspended  solids can accumulate to require frequent  medium  regeneration or
replacement, and pumping costs can be substantial.  As  far  as is known,  the
 system has  not  been  evaluated on  retort waters,  and extensive  pilot plant
testing  would  be  required to determine  its  feasibility  on these  waters.

     UltraflItration.   Passage  through  a submicron-sized  membrane  filter
separates  emulsified  oil   as  well  as  suspended  matter  and large  organic


                                     178

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 molecules  (MWt S 1,000).   The oil  droplets  are collected in the  concentrate
 and  removed by gravity  separation.  This process  is significantly  more  costly
 than normal filtration  (Water Purification Associates, December  1975).

      Con tro 1 Tec hno 1 ggi es
     The  streams  that require removal of  suspended matter,  oils and  greases
are:                                                          .-  *•

     •    Mine Water  (stream 4)

     •    Gas Liquor  (stream 41)

     •    Runoff and  Leachates (streams 92, 93)

     •    Slowdowns and Concentrates (streams 88, 104).

     Mine  water  is  obtained  from  dewatering  of  the  deep  aquifers under
Tract C-a.   While  the water does  not contain any  oils  and  greases, it does
contain  suspended  matter.  Sedimentation  by  gravity settling and clarifica-
tion with addition of  alum are the  approaches proposed  to  reduce the sus-
pended  matter  in the mine water.   Table  5.2-2  presents the design features
and cost  data  for  clarification, and Figure 5.2-2 shows a cost curve for the
clarifier.   This activity could  be considered as  part  of the process rather
than pollution control.

     In the  Lurgi retorting process, gas liquor is condensed along with light
oils in the  third  condensation tower.   It may  also contain  some particulate
matter that was not removed in the cyclones and two previous  towers, but this
is not  envisioned  as  a problem;  however, the gas liquor will need separation
from the light oils.  An API-type oil/water separator with channel covers was
examined for this  purpose.   As stated earlier,  the  separators are not fully
established  as  useful devices for  shale  oils,  but difficulty  in  achieving
separation from light oils is  not anticipated.   Table 5.2-3  and Figure 5.2-3
present the cost and design information and the cost curve, respectively,, for
the API separator.

     Service and  fire water runoff,  storm runoff,  and leachate  from shale
piles may contain oily materials.  Again, an API-type oil/water separator was
examined as the control.   This will  also allow separation of  suspended matter
along with the water.   The cost and design data for this separator are given
in Table  5.2-4,  while  a   cost  curve  is  already  included in  Figure 5,2-3.

     The  blowdowns,  sludges,  and concentrates from  various  processing units
will   also contain  suspended  matter.    These streams  are  collected  in  an
equalization pond  for possible  use  in processed  shale  moisturizing.   Since
gravity settlement affords  separation  of the suspended matter, the equaliza-
tion pond also might  be  viewed as  a pollution  control.   Its design and cost
are presented  in  Table S.2-5,  and a  cost curve  is given in  Figure  5,2-4.

     Other Technologies Analyzed—

     In the  event that the excess  mine water is reinjected  into the aquifer
(instead of  discharging it on  the  surface}, even more water  will  need to  be

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          TABLE 5.2-2.  DESI6N ANQ COST OF MINE WATER CLARIFICATION8

Item
Mine Water Flow Rate
Flow Rate/Clarifier
Number of Clarifiers
Diameter
Area of Clarifier
Alum Rate (30 ppm)
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 4%
Alum § 12t/lb
TOTAL
Total Annual Control Cost
Unit
gpm
gpm

ft
103 ft2
ton/yr
$103
$103


$103
Quantity
16,500
970
17
40
22,3
980
2,560

84
235
319
961

  This technology could be considered as part of the process rather than
  pollution control.

  Retention time and rise rate are 120 qiin. and 1 gpm/ft2, respectively.

c Maintenance is based on the fixed capital cost less contingency.

  See Section 6 for details on computation of the total annual control cost.

Source:  WPA estimates.
                                     180

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oo
           100
     SOURCE:   WPA
                                   1000
1500        2000        2500
 FLOW RATE, gpm/CLARiriER
3000
                                                                                                       10
3500      4000
                                  FIGURE 5,2-2  COST OF MINE WATER CLARIFICATION

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          TABLE 5.2-3.  DESISN AMD COST OF API OIL/WATER SEPARATOR
                               FOR GAS LIQUOR

Item
Gas Liquor Flow Rate
No. of Channels (1 standby)
Channel Cross Sectional Area
Channel Depth
Channel Length
Fixed Capital Cost
Direct Annual Operating Cost3
Maintenance.© 3%b
Total Annual Control Cost
Unit
gpm
—
ft2
ft
ft
$103
$103

$103
Quantity
586
2
21
6.5
50
161

4
35

  The fixed capital cost and direct annual operating cost for the standby
  channel are included.

  Maintenance is based on the fixed capital cost less contingency.

  See Section 6 for details on computation of the total annual control cost.

Source:   WPA estimates based on information from American Petroleum
         Institute, 1969.
                                     182

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M  '.
CO
CO
            tO
             o
             en
             o
             o
a.

o

a
ui
x
                              500
     SOURCE:  WPA
1000       1500       2000       2500

    FLOW RATE,  gpm/SEPARATOR
                                                                         3000
                                                                                                     12.0
                                                                                                     10.0
                                                                                                         to
                                                                                                          o
                                                                                                 —  8.0
                                                                in
                                                                O
                                                                O
                                                                
-------
            TABLE 5.2^4.  DESIGN AND COST OF OIL/WATER SEPARATOR
                          FOR RUNOFFS AND LEACHATE

Item
Runoff Flow Rate
No. of Channels (1 standby)
Channel Cross Sectional Area
Channel Depth
Channel Length
Fixed Capital Costa
Direct Annual Operating Cost9
Maintenance @ 3%
Total Annual Control Costc
Unit
gpm
—
ft2
ft
ft
$io3
$103

$103
Quantity
169
2
8
3
50
41

1
11

  The fixed capital cost and direct annual operating cost for the standby
  channel are included.

  Maintenance is based on the fixed capital cost less contingency.

  See Section 6 for details on computation of the total annual control cost.

Source:   WPA estimates based on information from American Petroleum
         Institute, 1969.
                                     184

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             TABLE 5.2-5.  DESIGN AND COST OF EQUALIZATION POND
Item                                    Unit               Quantity

Total Water Flow Rate             gpm (acre-ft/yr)          2,525 (4,065)

Pond Area                               acre                    3,27

Pond fleetii                               ft                    10

Fixed Capital Cost                      $103                  181

Direct Annual Operating Cost            $103

  Maintenance t 2%a                                             3

Total Annual Control Costb              $103                   46


a Maintenance is based on the fixed capital cost less contingency.

D See Section 6 for details on computation of the total annual control cost.

Source:   WPA estimates.
dewatered because some of the reinjected water will flow back to the dewater-
ing we!Is.

     The water to  be  reinjected would need to  be  clarified.   This should be
performed in closed clarifiers  to avoid exposure  of  the  excess water to tne
environment.   A closed  clarifier was examined for the reinjection water, and
its design  and cost  information is  presented in  Table 5.2-6.   A cost curve
based on the design of the clarifier is shown in Figure 5.2-5.

5.2.2  Dissolved Gases and Volatiles

     Dissolved gases  include ammonia, carbon dioxide,  and hydrogen sulfide,
while  volatile materials  are  low  molecular weight  organics.   Methods for
removing  these  substances  from  water are summarized  in  Figure 5.2-6.   Steam
stripping is  the most  likely process to  be  used and  has been successfully
despor»strayed on a  laboratory scale  for some oil shale wastewaters (Hicks and
Liang, January 1981).

     Inventory of Control Techno!ogles—

     Tabie 5.2-7 presents  m inventory  of applicable control  technologies,
along with their key  features,  for the dissolved volatiles.  Basically, most
technologies involve stripping of the d-isso-1 v«d gases  by either elevating the
temperature,  applying  vacuum,  -or  displacement  with  carrifer  gases.   More
specific  removal can  be accomplished by using an adsorbent selective for the
gas in question.
                                     185

-------
00
en
                  200
                  150
               O
               O

-------
     TABLE 5.2-6.  DESIGN AND COST OF EXCESS MINE WATER CLARIFICATION*

Item
Excess Mine Water Flow Rate
FT Of* Rate/Clarifier
Number of Clan'fiers
Diameter
Area of Clarifier
Alum Rate (30 ppm)
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance 0 4%b
Alum @ 12$ /I b
TOTAL
Unit
gptn
gpm
—
ft
103 ft2
ton/yr
$103
$103

Quantity
15,330
510
30
30
20.7
900
3,545
115
216
331

  This technology could be considered as part of the process rather than
  pollution control,

  Maintenance is based on the fixed capital cost less contingency.

Source:  WPA estimates.
     Steam stripping.   Steam stripping  of  sour  waters  (e.g.,  waters  con-
taining  dissolved  ammonia  and  hydrogen  sulfide)  and  coke-oven  liquors
(e.g., waters  containing dissolved  ammonia  and carbon  dioxide)  is standard
practice in the petroleum and steel industries.   Stripping has also been used
as part of the "Phenosolvan" process on coal  gasification process condensates
(American Petroleum Institute, March 1978; Beychok,  1967).

     The dissolved  gases are stripped  from  the  solution  by  bubbling  steam
through it, generally  in packed or tray  columns.   The  steam may be directly
sparged (live) or  used indirectly in a reboiler,  as in distillation columns.
The stripped  gases, along  with other volatile materials,  are removed  in a
relatively  concentrated  gas  stream  which  may  be  treated  for  adsorption/
recovery of a  specific substance or incinerated.   Carbon dioxide  is  readily
stripped at efficiencies  of +99%;  ammonia strips less easily, and pH eleva-
tion may  be required  in  some cases for 99% removal.  Hydrogen  sulfide  does
not strip  as  easily as  carbon  dioxide  but can generally be removed  down  to
the 10-20 ppm  range.   Casts are for eqyipaent and steam and  are  proportional
to the volume of water to be treated.

     Steam  requirements  range   from  approximately  10  to 15  IDS  steam  per
100 Ibs water  treated.  For  a  given separation,  .a greater  column height  Is

-------
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                             188

-------
       DISSOLVED GASES
         8 VQLATILES
          CONTROL
       TECHNOLOGIES
                                        STEAM
                                       STRIPPING
                                        VACUUM
                                      DISTILLATION
                                        INERT GAS
                                        STRIPPING
                                       ADSORPTION
SOURCE'  WPA
 Fi&URE 5-2-6*  ,OtSS0LV|l*0tSE3 AND VQUTltES-tQNfROL TECHNOLOGIES

                               189

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                                         TfliLE 5.2-7.  KEY FEA1URF.S OF CONTROL TFCHHOLOGIES TOR DISSOLVED GASES AND VOLATILES
Control
Technology
Steam Stripping
Operating Principle
Increasing temperature and
providing a po$itive flow
of steam through the waste-
water Removes volatile
orgamcs and inorganics
with overhead steam.
Components
Removed
NHa, acid
gases
(C02, H2S,
HCN), light
hydrocarbons
Removal
Efficiency
90+% of "free"
anuDonia and acid
gases typical.
Hydrocarbon
rewoval varies
with volatility
of stripped
components
Feed
Requirements/
Restrictions
Acid/caustic
for pH adjust-
ment optional.
By-products
and Wastes
Stripped gases,
uncondensod
steam
Comments
Acid/caustic addition
can be used to improve
the efficiency and
selectivity of the
stripping process
U3
O
        Vacuum               Low pressure, low temperature     As above         As above
        Distillation         stripping process.
        Inert Gas            Same as stream stripping, but     As above         As above
        Stripping            using air,  nitrogen,  or other
                             available inert gas in place
                             of steam.
                                                                                                  As above.
                                                                                                  As above.
Stripped gases.
Stripped and
inert gases
High energy require-
ments.  Not cost
competitive in a plant
where stripping steam is
readily available.

Normally used at ambient
temperature, most
suitable for low concen-
tration wastes.
Adsorption
Adsorption of NH3 onto
clinoptilolite and volatile
orgamcs onto polymeric
res i ns
NH3,
volatile
orgamcs
High removal
efficiencies
possible.
Not suitable
for high con-
centrations
Regenerant and
adsorbent wastes.
Generally used as
polishing step.
a
        Source:   WPA

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required  for a  lower steam  rate.   The  selection  of steam  rate and  column
height  is based on energy and equipment costs.

     The  stripped gases  may  be incinerated  or treated  further to  recover
ammonia and  sulfur.   Ammonia  may  be  recovered as  anhydrous  ammonia,  aqua
(20-30%)  ammonia  or  ammonium sulfate.  In cases where the sulfate is  derived
from flue  gas desulfurization,  the sulfate route may be viable depending,  in
part, on  the marketability of ammonium sulfate  and on the costs of alterna-
tive flue  gas desulfurization processes.   Because  oil shale plants generally
will have ammonia available  as  a by-product, S02  scrubbing  with NH3  may  be
attractive  when  the  technology  is  sufficiently developed and  tested.  Re-
covery  of  anhydrous  ammonia involves considerable  capital and energy  (steam)
requirements,  but these are partially offset  with  by-product ammonia  sales.
The  stability  of the  ammonia  market  must be  considered when  selecting a
recovery process.

     Vacuum disti1lation.   Distillation  at reduced pressure  has  many  indus-
trial applications, but these primarily involve distillation or fractionation
of compounds  with high boiling points or  low  thermal  stability.   The method
may  be  applicable  to  stripping  of  gases and  volatile compounds,  but the
energy  requirements  are  high relative to those for steam or inert gas strip-
ping.

     Insrt^ gas sjtrlgptM-   This  method  is  applicable  to   dilute,   or  low
strength, wastewaters  for which  steam  stripping may not  be  practical.  The
operating  principle  is  similar  to  that  for  steam  stripping,   except air,
nitrogen, carbon  dioxide,  or other  inert gases may be used.   Its application
to  high strength  liquids  is  generally  not  practical  because,large  column
heights and gas compression costs are required.

     Adsorption.  Dissolved  gases and volatile components may be adsorbed on
specific surface-active materials by passing wastewaters through a bed of the
adsorbent.   The  gases may  then  be  desorbed  thermally,  and  the  regenerated
adsorbent  is  recycled.   This  method  is generally used  in trace  removal
applications.

     Control Technologies Analyzed—

     The streams  that may  require  removal of dissolved gases and  volatiles


     •     Gas Liquor (stream 41)

     *     Compression Condensate (stream 49).


     The  compression  condensate  is  also  a retort gas condensate  obtained
during   compression and cooling  of the retort gas;  therefore,  it  is  combined
with the gas liquor for treatment.  The  condensates  are  previously freed from
oil  and emulsion in the oil/water separator,  but some polar organics,  such as
phenols   and  fatty  acids,  remain  dissolved.   A  portion of  the dissolved
organics can  be steam stripped  along with other  dissolved gases.  The  gas
liquor   also  contains a significant amount of ammonia,  both free as well  as


                                     191

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 fixed, with  sulfur dioxide and carbon dioxide.  Since the intended use of the
 gas  liquor is  in processed shale moisturizing, most of the fixed ammonia must
 also  be removed from  the gas liquor prior to its  use;  otherwise,  it may be
 released into  the environment upon contact with the alkaline processed shale.
 Steam stripping alone  would  remove free ammonia and other volatile components
 from the liquor, but pH  adjustment may be necessary to release fixed ammonia.
 A  further  control  of  the released ammonia  is also desirable and this may be
 accomplished with an ammonia recovery plant.

     Ammonia recovery  was  examined as a control for the gas liquor.  The de-
 sign specifications  for the ammonia recovery plant are given in Table 5.2-8s
 the  cost  is presented  in   Table 5.2-9,  and a  cost  curve  is  presented in
 Figure 5.2-7.   The  description  and material  balance for  the process  are
 presented in Sections  3,3.8  and 4.2.7, respectively.

 5-2.3  Dissolved Inorganics

     Dissolved  inorganics are usually not a problem unless the compounds are
 judged  to  be  hazardous (e.g.,  trace metals) or  when fouling  of  equipment
 (e.g., boilers)  occurs because of the high  salt  content of the waters being
 used.  Natural  waters  and  waters that come  into  contact with the solids may
 need  to be  treated  if they are  intended for critical  uses in the plant.
 Processed  shale  moisturizing, on the other hand,  may  not require control of
 dissolved inorganics.  In fact, waters with high salt content can be used for
 this purpose,  thereby  avoiding the need for  other controls.   Since gas con-
 densates do  not contain significant amounts of dissolved inorganics, a treat-
 ment may not be necessary.

     Inventory of Control Technologies—

     Methods  for removal of dissolved inorganics  are  shown  in Figure 5.2-8,
while  some  of  the   key  features  of  the  technologies  are  presented  in
Table 5.2-10.  The operating principles  for some of the methods shown in the
 figure are detailed below.

     Precipitation.   Chemicals may be added to precipitate salts, e.g., lime
 addition for carbonate (hardness)  removal.   Processed shale is also believed
to behave  like a  softener   for inorganic  carbon  reduction  (Humenick, 1977).
The process  is simple, but  it will  usually  require the use of other methods
 (e.g., gravity separation,  centrifugation, filtration) to remove the precipi-
tate.

     Ionexchange.  Cations  and anions in solution are replaced with hydrogen
and hydroxyl  ions  on exchange resins capable of  producing  a water virtually
free of common salts.  The resins are regenerated with relatively strong acid
and alkali  solutions,  and the regenerant wastes must be controlled.   Costs go
 up with  increasing  concentration of  salts  in the  water.   Ion  exchange is
normally used  only where a  very clean  water is  required from  a relatively
clean or  mildly brackish supply.  The organics present are  not removed and
may foul the exchange  resins (Calmon and Gold, 1979),
                                     192

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TABLE 5.2-8.  DESIGN OF AMMONIA RECOVERY SYSTEM*

Design Parameter
Gas Condensate Feed Rate to
Stripper Column
Ammonia Rate
Steam Rate
Ceo] ing Water Circulated
Electricity
Chemicals
H3P04
NaOH
Steao Stripping Column
Diameter
Height
Material
Reboilers on Steam Stripping Column
Number
Surface area (each)
Material
Keat Exchanger on Steam Stripping Column
Nunbsr
Surface area (each)
Material
Absorption Column
Diameter
Height
Material
Recoil er on Absorber
Surface area
Material
Heat Exchanger on Absorber
Surface area
Material
Stripper Tower
Diameter
Height
Material
Unit
gpm

"Ib/hr
10s Ib/hr
gpm
kW

Ib/hr
Ib/hr

ft
ft
»—

—
ft2
~—

—
ft2
""""

ft
ft
~~

ft2
--

ft2
--

ft
ft
--
Quantity
594

1,883
53
1,080
47

13
293

6.3
95
CS/SS

1
2,300
CS/SS

3
5,000
CS/SS

5
50
SS

701
CS/SS

948
CS/SS

3.3
60
SS
                                              (Continued)
                      1S3

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                             TABLE  $.2-8   (cent.)

Design Parameter
Heat Exchanger on Stripper
Surface area
Material
Fractionator
Diameter
Height
Material
Fractionator Feed Tank
Diameter
Height
Capacity
Material
Reboiler on Fractionator
Surface area
Material
Heat Exchanger on Fractionator
Surface area
Material
Flasn Drum
Diameter
Height
Capacity
Material
Lean Solution Cooler
Surface area
Material
Solution Heat Exchanger
Surface area
Material
'Unit

ft2
-"-

ft
ft
_ —

ft
ft
gal
_-.

ft2
--

ft2
—

ft
ft
gal
-"""

ft2
- —

ft2
-•*
Quantity

1,137
SS

1.5
64
SS

7
4.3
1,278
SS

209
CS/SS

645
CS/SS

4
1.4
142
SS

1,554
CS/SS

303
SS

* This table is based on the Phosam-W process, which is only one example of
  many available processes for the recovery of ammonia,

Source:  WPA estimates based on information provided by U.S.S.  Engineers and
         Consultants, Inc., April 1978.
                                      194

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                   TABLE 5.2-9.  COST OF AMMONIA RECOVERY
Item                                          Unit             Quantity
Fixed Capital Cost                            $103
  Towers                                                        1,660
  Heat exchangers                                               1,920
  Drums, etc.                                                   	47
     TOTAL                                                      3,627
Direct Annual Operating Cost
  Maintenance @ 4%a                                               118
  Labor, 24 hr/day @ $30/hr                                       237
  Steam @ $3/MMBtu                                              1,565
  Cooling water @ 3t/m3 circulated                                 60
  Electricity § St/kW-hr                                           11
  Chemicals
    NaOH                                                          404
    H3P04                                                       __2f
     TOTAL                                                      2,419

Credit for Ammonia Sales @ $110/ton          $103/yr              816

Total Annual Control Costb                    $103              2,395
a Maintenance is based on the fixed capital cost less contingency.
  See Section 6 for details on computation of the total annual control cost.
Source:   WPA estimates based on information provided by U.S.S. Engineers and
         Consultants, Inc., April 1978.
                                     195

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             6000

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      DISSOLVED INORGANICS
      CONTROL TECHNOLOGIES
SOURCE= WPA
                                      CHEMICAL
                                    PRECIPITATION
                                    ION EXCHANGE
                                     MEMBRANE
                                    PROCESSES
                                    EVAPORATION
                                    FREEZING
                                     SPECIFIC
                                    ADSORPTION
  REVERSE
  ' OSMOSIS (RO)


L-ELECTRODIALYSISCED!


 -THERMAL
                                                       .VAPOR
                                                        COMPRESSION
        FIGURE-5.2-8   DISSOLVED tNORGANICS,CONTROL TECHNOLOGIES

                                   197

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                                            TABIE 5.2-10.   KEY FEATURES  OF  CONTROL  TECHNOLOGIES FOR DISSOLVED  INORGANICS
ifl
00
Control
technology
Chemical
Precipitation
Ion Exchange
Operating Principle
Use of agents to promote
the precipitation of
inorganic solids from
wastewaters
Substitution of H+ and
OH" ions for objectionable
ionic species Exchange
Components
Removed
Ca, Hg, heavy
metals,
alkalinity
Heavy metals,
F' , Cft ,
scaling species
Removal
Efficiency
Variable,
depending on
constituents.
90+X for most
ions. Regenera-
tion frequency
Feed
Eequi rements/
Restrictions
Lime, polymer,
and soda ash
may be required,
Regenerants ,
replacement
resins.
By-products
and Wastes
Sludg« contam-
inated with
heavy metals.
Spent
regenerants
and resins.
Comments
Generally followed by
filtration and/or
activated carbon
adsorption
Most effective as a
polishing process.
Clearly applicable to
                            resins regenerated with
                            add base or salt  solutions.
is a key
parameter
boiler feedwater treat-
ment Reeds; of limited
use in treating process
wastewaters containing
high concentrations of
organics or dissolved
solids
Membrane Processes
(RO, ED)
Evaporation
(Thermal , Vapor
Compression)
Freezing
Specific
Adsorption
Separation of dissolved
matter by a seralpermeable
membrane under a pressure
(RO) or electric (ED)
gradient
Application of heat (solar,
steam, etc.) to evaporate
wastewater or concentrate
streams.
Cooling with formation of
ice which fs separated
from remaining brine.
Adsorption of specific ions
onto resins or other adsorbent.
Ionized salts
All nonvolatile
species will
remain in brine
Dissolved salts,
including
organits.
Boron, fluoride,
trace metals
90-99% removal
of dissolved
salts
99+% rejection
of nonvolatile
dissolved solids.
90+% possible
90+X in properly
designed systems
Filtration, pH
adjustment,
foulant
control .
Fouling/scaling
of heat
exchange sur-
faces must be
prevented

As above
Concentrate ,
spent membranes.
Recovered
co ndens ate , non-
condensible
gases, waste
brine
Concentrate
stream
As above.
RO and ED have been used
commercially for desalt-.
nation Concentrate
stream way be 10-30J6 of
Input stream.
Solar evaporation itey be
unacceptable due to air
pollution Vapor
compression evaporation
has been successfully
tested on retort waters.
Not yet demonstrated
comraerda'Hy. ,*
Useful as a polishing
process
       Source:  WPA

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     Reverse osmosis (RO).  Sometimes called "hyper filtration,"  RO  Is  a proc-
ess  for recovering relatively  pure water  from solutions.   Water  is passed
through  a  hyperfilter,  or  semipermeable membrane, which rejects dissolved
materials.   As  in  normal  filtration,  the  driving  force  is hydrostatic
pressure,  but  in this  case, the pressure has  to be greater  than the  osmotic
pressure of the  solution.   Osmotic pressures  are  related to the total molar
concentration  of   the  solution  and  its  temperature   (Hicks  and  Liang,
January 1981).

     The water is passed under pressure (greater than 200  psi) through a mem-
brane which is  impermeable to most inorganic salts and many  organics.  These
"rejected1*  substances  remain  in a concentrate  stream which  may be 10-20% of
the  feedwater  volume.   The treated water or permeate will generally  contain
less than  10%,  and often  less  than  1%,  of the  rejected substances.   Costs
scale primarily with the volume of water to be treated but are also dependent
on concentration.  At very high solute concentrations (e.g.,  seawater), costs
increase rapidly due   to the  high  applied  pressures that are required.  The
flux of  water through  the membrane,  i.e.,  the permeate  recovery  rate,  in-
creases linearly with  the  pressure by which the applied pressure exceeds the
osmotic pressure.   Fluxes  of  10 gal/ft2/day  have  been measured  for  retort
water  at   an  applied   pressure  of  600  psi.   Typical  applied  pressures  for
brackish waters range from 200 to 600 psi  and greater.

     Membranes consist essentially  of  a thin skin (0.1  to 0.25 urn) of active
chemical (cellulose acetate^  polyamide) on a- porous substructure,  which  may
then be  housed  in  a  spiral-wound module for  commercial  application.   Other
geometries  are also available.   Rejection of >strong,,electrolytes is normally
in excess  of 90%  and  can exceed  99 percent.   Nearly  complete  rejection  is
obtained from  most species with molecular weights-  greater  than about  150.
However, low molecular weight  nonelectrolytes  (e.g., small organic molecules
like urea,  and weak acids  such  as boric  acid) are  poorly rejected.   Rejec-
tions of these substances can sometimes  be improved by adjusting the solution
pH to a value  where the compound dissociates  (e.g., boron is rejected above
pH = 10).

     Some advantages of RO treatment are the low labor  and space requirements
and the high rejection rates  obtained  for a wide range  of dissolved contami-
nants,   Of particular  relevance to oil  shale retort water is that both organ-
ic and inorganic compounds  can  be simultaneously removed  under  favorable  pH
conditions and that such a system can  accommodate changing water flow rates.
A serious  disadvantage of  the  process  is  that  the membranes  are susceptible
to Dlockage  by deposition of  solids.   This so-called  fouling  results  from
solids present  in  the feed solution or from precipitation of solids  as the
concentration in the brine  exceeds  the  solubility limit;  it  may even  result
     biological  activity on the membrane surface.
     Fouling rates may be  reduced  by proper pretreatment and by reducing the
concentration increase in  the brine.   Reverse osmosis does  not  destroy the
pollutants,  it  merely  concentrates  them  into a smaller  liquid  stream.   Re-
ducing the  concentration increase  implies reducing the product  recovery and
increasing  the  amount  of  brine   for disposal.   Fouling  can  be  further

-------
 controlled  by periodic washing, although  there  is generally a certain amount
 of  irreversible fouling  that determines  membrane  life and operating costs.

      Costs  scale proportionately with the  volume of product water recovered,
 but  they are  also dependent on the  degree of recovery and membrane fouling
 characteristics.   As  the  concentration of  pollutants in wastewater increases,
 so does  the  osmotic pressure;  hence,  higher applied pressures are required to
 maintain the  desired permeate  flux.   Energy costs,   however,  are normally
 small  relative  to  membrane  costs.

      Electrodialysis  (ED).   Electrodialysis  is  the  use  of an electromotive
 force  to transport  ionized materials in  a solution through  a diaphragm, or
 membrane.  The  process can be made selective by using  ion-specific membranes
 which  allow  passage of only  certain  ions.   A common application of electro-
 dialysis is  in  the desalting  of  brackish waters containing  1,000-5,000 ppm of
 salts.   A removal  efficiency  of  90-99% is  usually achievable.

     Thermal evaporation.   This  approach includes processes in which heat is
 applied  to  vaporize  water,  leaving  a  concentrated  solution or  slurry for
 disposal.   The  high  energy  required for  evaporation is  recovered  in most
 processes by condensing the water vapor and,  as a result,  producing a stream
 of  relatively  pure  water.    Volatile  contaminants,  if present,  may require
 removal  in an upstream stripping process in cases where a clean product water
 is necessary.   Multiple effect  boiling  (MEB)  and multistage  flash  (MSF) are
 two procedures  commonly used for evaporation  (Water Purification Associates,
 December 1975).

     Disadvantages of thermal processes  are  that volatile  substances are not
 controlled,  and (energy) costs  are generally higher  than  for processes not
 involving a phase change.    Problems related  to scaling  of heat  transfer
 surfaces  and corrosion are also encountered.  These problems may be accentu-
 ated with waters containing high organic  loadings,  such  as oil  shale waste-
water.   Thermal  processes may find application  if there  is a need for dirty
 steam, as occurs in many  in situ processes.

     Vapor,.compression evaporation.   This-is  a  method for  evaporating water
 by the use  of mechanical energy.  Thermal  energy required  for evaporation is
 obtained  by  mechanical  compression of the  vapor  instead  of by heating.  The
wastewater is boiled  in an evaporator to produce a vapor which is compressed
 in order  to  raise  its temperature, and then  it is passed through the tubes in
 the evaporator where the  necessary heat exchange between the vapor and waste-
water  takes  place.   The  vapor cools  and condenses upon  heat  exchange and a
 relatively pure water is  produced.

     The  advantage of vapor compression is  that  the heat required for vapor
formation is  recirculated so  that the amount that must be dissipated is much
 less  than the  latent  heat  of vaporization.  This approach results  in rela-
tively  low  energy  requirements and  essentially  negligible cooling  water
 requirements.  The penalties  are the  high  capital costs  associated  with the
compressor,  which  must  handle  the  large  volumes  of  vapor,  and  increased
maintenance  costs.  Other disadvantages  of  vapor compression evaporation are
 similar  to those of the thermal  processes.


                                     200

-------
     The  energy required  for  the single  effect vapor  compression  units  is
about  70-90  kW-hr  per thousand gallons of product water.  Some  single  effect
vapor  compression  units (RCC evaporator) can recover up to 98%  of the  waste-
water  containing up to  11,000 mg/1 total dissolved solids.

     Freezing.  The water is reduced in temperature to produce  a solid (ice)
phase  and a  concentrated brine.   The  ice  is washed free  of salts and then
melted to produce  a virtually pure water.   Both inorganics and organics are
removed  in  the brine  stream.  Since the costs scale with the volume of water
to be  treated, freezing would normally be applied to relatively concentrated
low  volume  wastes.  While this process is theoretically more efficient than
evaooration,  it has yet to be applied  commercially.   It is included irs this
inventory  as  it may be useful for controlling retort waters, provided  opera-
t'ing proolems can  be  resolved in the  future (Barduhn,  September 1967;  Water
Purification  Associates,  December 1975).

     Sgecif1c  adsorption.  The processes  in  this category are similar  to the
ion  exchange  processes, except that the affinity between the sorbent materi-
als  and  the  solutes  being removed is of a physical nature.   The sorbents may
be  natural  or synthetic  and  usually  have  pores,  or lattice  vacancies,  of
uniform  size  and  dimensions  which are specific for the solutes.  The proces-
ses  are  not  applicable to high strength wastewaters and are generally used
fo" t^aca removal  applications.

     Control  Technologies Analyzed—

     Tie  following streams  may  require  control  of dissolved inorganics:
     ®    Boiler feedwater (stream 94)

     «    Cooling Tower Makeup Water (stream 97).

     Based  on  the quality  of  the water,   demineralization  using  reverse
osmosis was  examined  as the  most economical  treatment of  the mine water.   A
relatively large boiler blowdown is required, however, to maintain acceptable
concentration  levels  in the  boilers  in order to prevent scaling.  The boiler
blowdown  is used for processed shale moistening.   The blowdown does represent
an  energy loss  from  the boiler  system,  and some  heat recovery  from this
stream might  prove  cost effective.   The material rejected by reverse osmosis
is also  used  for  processed  shale moistening  after equalization with  other
wastewaters.   Table 5.2-11 gives  the  basis  for design  and costs  of  boiler
feedwater treatment, and  Figure 5.2-9  shows  a specific cost curve for boile**
feeawater  treatment by  reverse osmosis.  This treatment could  be considered
as part of the process rather than pollution control.

     Clarified mine water is  usexl as cooling tower makeup.   As  a treatment,
some sulfuric  acid  is  added  to convert calcium carbonate to the more soluble
calcium sulfats.  The cooling  tower  is operated at 1.5-  cycles  of concentra-
tion, which means  that the concentration of dissolved species in the blowdown
is 1.5 times  that  in  the makeup*   Since this concentration  is not excessive,
there  should  not  be  any problem in  using the  cooling tower  blowdown for
processed shale moisturizing.  Table  5.2-12 contains design  and cost informa-
tion for  the  cooling tower  makeup treatment,  and Figure 5.2-10 presents  a

                                     201

-------
       TABLE 5.2-11.  DESIGN AND COST OF BOILER FEEDWATER TREATMENT3
 Item                                          Unit             Quantity

 Boiler Slowdown                                gpm                 21

 Steam Losses                                   gpm                 11

 Softener Regeneration Waste                    gpm                 11

     TOTAL MAKEUP (clarified mine water)       gpm                 43


 Fixed Capital Cost                            $103

  Elements @ $1,160 each                                           20
  Pressure vessel t $1,920 each                                     6
  Degasifier                                                       _5
     Subtotal                                                      31
  Total equipment cost
     (250% of subtotal)                                            78
  Civil work & installation
     (25% of total equipment cost)                                 19
  Contingency                                                      25

     TOTAL                                                        122


Direct Annual Operating Cost                  $103

  Maintenance § 3%b                                                 4
  Labor, 4 hr/day @ $30/hr                                         40
  Electricity @ 3$/kW-hr                                           11
  Membrane replacement (1.5-yr life)
     and chemicals                                                 14

     TOTAL                                                         69


Total  Annual  Control Costc                    $103                 94


a This technology could be considered as part of the process rather than
  pollution control.

  Maintenance is based on the fixed capital cost less contingency.

c See Section 6 for details on computation of the total annual control  cost.

Source:   WPA estimates based on information from Peters and Timmerhaus,
         1980.
                                     202

-------
            180
                        TOO
                                                30          40

                                                FLOW RATE, gpm
50
60
                                                                                              90
                                                                                          -  70
                                                                                                 o

                                                                                                 •V9-

                                                                                                 J~"
                                                                                                 (f>
                                                                                                 O

                                                                                              eo „
                                                                                                  o:
                                                                                                  LU
                                                                                                  a.
                                                                                                  o
                                                                                                  O
                                                                                                  Ul
                                                                                                  a:
                                                                                              60  =
                                                                                              50
70
SOURCE:  WPA
                 FIGURE  b.2-9  COST OF BOILER  FEEDWATER TREATMENT WITH REVERSE OSMOSIS

-------
cost  curve for  the  treatment.  The cooling tower  makeup  treatment  could be
considered as part of the process rather than pollution control.


          TABLE  5.2-12.  DESIGN AND COST OF COOLING WATER TREATMENT3
Item                                          Unit             Quantity

Evaporation and Drift Losses                   gpm

Slowdown                                       gpm

     TOTAL MAKEUP (clarified mine water)       gpm


Cycles of Concentration                        —                   1.5

Sulfuric Acid Addition                     ,mg/l (ppm)             150
                                             ton/yr               785

Direct Annual Operating Cost                  $103

  Sulfuric acid @ $65/ton                                          51

Total Annual Control Cost                                          52


  This technology could be considered as part of the process rather than
  pollution control.

  See Section 6 for details on computation of the total annual control cost.

Source:  WPA estimates based on information from Peters and Timmerhaus,
         1980.
     Other Control TechnologiesAnalyzed—

     Several  additional   dissolved   inorganics  control   technologies  were
analyzed.   These  include  reverse  osmosis,  boron adsorption,  and  phenol  ad-
sorption to  remove  dissolved salts,  boron and phenol, respectively, from the
excess mine  water prior to its discharge.  Cooling towers and solar evapora-
tion ponds  were  examined  for treating  the  process waters.   Although these
technologies have  not  been proposed  for the  Lurgi-Open Pit plant,  they were
analyzed as viable alternatives in the event that the wastewater disposal  and
reuse strategies for the plant are varied.

     As stated  earlier,  the approach adopted for excess  mine  water disposal
is to discharge it on the  surface.   If  the  quality of the excess  mine water
after clarification  does  not satisfy the criteria for surface discharge,  the
gross  inorganic  content  can be  reduced  first by  reverse  osmosis  (RO),
followed  by the  removal  of  boron  and  phenol  from  the  RO  permeate using
specific ion exchange resins.

                                     204

-------
O
tfi
                         1000     2000     3000
4000    5000     6000

    FLOW RATE, gpm
7000     8000     9000    10,000
    SOURCE:   WPA
                                  FIGURE 5.2-10  COST OF  COOLING WATER TREATMENT

-------
      Reverse osmosis is  a  useful  technology in that it  affords  simultaneous
 removal  of the dissolved inorganics  .and-organics.   With-this  technology,  the
 wastewater is forced through  a semipermeable membrane  which allows  the  water
 to pass  through  but rejects  the  dissolved matter, especially that which  is
 highly ionized.   At optimum pH,  up to 95% of the inorganics and  organics  can
 be rejected.  The permeate  is usually a fairly clean  water that is suitable
 for high quality  water  needs.   The RO technology has been tested  on  the  aqui-
 fer waters from Tract C-b  and a rejection of over 98%  of the  total  dissolved
 solids has  been  obtained (Water Purification Associates,  unpublished).   The
 resin adsorption technologies are widely  used in wastewater treatment,  al-
 though experience with the aquifer waters from Tract C-a  has not been  docu-
 mented.   Two flow schemes  (Examples  I  and II) depicting the above  treatment
 and water reuse technologies  are  presented in Figure 5.2-11,  while the flow
 diagrams  for the  RO  process and the boron and phenol  adsorption processes  are
 presented in Figures 5.2-12 and 5.2-13, respectively.   Table 5.2-13  gives  the
 mine water  composition  before and  after these treatments.  Design and cost
 information  for the  RO  process is  presented in Table 5.2-14 and for  the  boron
 and phenol adsorption systems  in Tables 5.2-15 and 5.2-16,  respectively.  The
 cost curves  for  the three technologies  are illustrated  in  Figures  5.2-14,
 5.2-15 and 5.2-16.

      In  the   event  that the process  generated  waters are not  used for  proc-
 essed shale  moisturizing,  then  a water reuse  plan  would have to  be  de-
 veloped    One approach  among  many possibilities  would  be  to treat  the gas
 liquor (after ammonia  removal) by adsorption on activated carbon to reduce
 the organic  content.  The  treated  water could then be used as cooling  tower
,makeup water, thereby controlling  the  dissolved inorganics.   Since  the  cool-
 ing tower can  b'e run  at fairly high  cycles of  concentration,  roost  of the
water is  lost  as evaporation  and  drift, and  a small  amount  of blowdown  is
 produced.  The  blowdown could then be  placed in a solar evaporation  pond  to
 evaporate  the remainder of the  water,  and the precipitated material could  be
 properly  discarded.  Figure 5.2-17  shows this train for the gas liquor treat-
ment.   Table 5.2-17  presents  the material  balance around the  cooling tower,
while Tables 5.2-18  and  5.2-19  give  the  design  and  cost details  for the
 cooling tower makeup treatment and  solar evaporation pond,  respectively.  The
 cost  curve presented previously  in  Figure  5.2-10  is applicable to the  cooling
 tower makeup treatment  indicated  here.   This  treatment could be considered
part  of  the  process rather than  pollution  control.   A cost curve  for the
 solar pond is presented in  Figure 5.2-18.

5.2.4 EH s so 1 .ygd_0r_ganjcs

      Removal   of volatile  organics by  stripping may  be sufficient  for reuse  of
process waters  in processed shale  moisturizing; however, nonvolatile  organic
components are not  removable  by  stripping.   Therefore,  for  higher  quality
uses,  further treatment may be  necessary.   Some of the available approaches
are discussed below,

      Inventory of Control Technologies—

      The  technologies  available for  dissolved  organics control  are  shown  in
Figure 5.2-19 and are described  in  Table 5.2-20.


                                      206

-------
ISS'
o
                                                     EXAMPLE  I
txctss
MINE WATER
11,242
REVERSE
OSMOSIS


PERMEATE
8,330
CONCENTRATE
2,912
BORON
ADSORPTION

PROCESSED SHALE
MOISTURIZING
s*~
8,330 r
PHENOL
ADSORPTION

SURFACE
DISCHARGED
8,330
        EXCESS
      MINE WATER
        10,190
REVERSE
OSMOSIS
PERM EAT
  8,149
                                 CONCENTRATE
                                   2,04!
       ALL FLOWS IN 6PM
       SOURCE^ WPA
                                                    EXAMPLE  IT
AERATION
  POND
                           PROCESSED SHALE
                             MOISTURIZING
 SURFACE
DISCHARGE
                                               8,149
                 FIGURE 5 2-11  FLOW SCHEME FOR  RO, BORON ADSORPTION AND PHENOL ADSORPTION TREATMENTS

-------
                                                                           CONCENTRATE
                                                                           TO PROCESSED
                                                                           SHALE
                                                                           MQ'STUWWS
                               LOW PRESSURE SYSTEM
                                                                            PERMEATE
                                                                           TO 80RON
                                                                           ABSORPTION
STREAM
IDENTITY
FUQWRATE:
I03!b/hr
gpm
TEMPERATURE,0?
PRESSURE, psig
EXCESS MINE
WATER
11242
AMB
AMB
RO PERMEATE
8330
MO
AMB
R 0 CONCENTRATE
2912
no
AMB
COOLING WATER
N.D.
80
AMB
SOURCE^ WPft
                 FIGURE 5.2-12  REVERSE  OSMOSIS PROCESS FLOW SCHEME

                                      208

-------
          RQ PERMEATE   >
RQ PERMEATE
           RESIN
           MAKEUP

          REGENERATION \

9        JgJRT>
          ______

          CHEMICAL    N
          1CH OH)

           RESIN\
           MAKEUP
                                AMBERLIFE
                                IRA-743
                                      IN
                                      SERVICE
                                                             AMBERLlTE
                                                              XAD-4
                                                                  IN
                                                                  SERVICE
                                                                                  BORON
                                                                               -HAOSORPTION
                                                                                  DISCHARGE


n_zni





PHENOL
ADSORPTION
DISCHARGE
                                                                          REGENERATION
> —

1

in i

!


















I





_ TREATED
*" WATER


   STREAM
   IDENTITY

flowRATE*
                            RO
                          PERMEATE
qpm   8330
                         RESIN
                        MAKEUP
               ND.
REGENERATION I REGENERATION
  CHEMICAL   CHEMICA
                                             0.03
                                           RESIN
                                          MAKEUP
                                                       N.D.
 BORON
ADSORPTION
 DISCHARGE

   NO.
 PHENOL
ADSORPTO*
DISCHARGE


  N.D.
                                                      SOgpd
            TEMPERATURE, °F    110     AMB

            PRESSURE, psigl  AMB
TREATED
 WATER
                                                                                8330

                                                                               -AMB

                                                                               -AMB
                        FIGURE  5.2-13  BORON AND PHENOL ADSORPTION PROCESS FLOW SCHEME

-------
                    TABLE 5.2-13.   EXCESS  MINI HATER COHPOS1TION AFTER RO, BORON ADSORPTION
                                       MIS PHENOL ADSORPTION TREATMENTS
Parameter
AlKalinity, as CaCOa
Aluminum
Ammonia, total
Arsenic
Boron
Calcium
Chloride
Chromium
COD
Cyamde
Fluoride
Lead
Mercury
pH (units)
Phenols
Silica
Sodium
TCS
Sulfete
Sulfioe
Flow Rate (gpn>)
Example I
Example II
Raw
Mine Water8
560
0.2
0.89
0.01
0.62
20
18
<0.01
15
0 01
8 5
0.2
0,003
7 0
0 0025
20
320
1,000
205
0.6

(11,242)
(10,190)

RO
Permeate
28
0.01
0.22
0.0005
0.31
0.2
0.9
<0.0005
1.5
0 001
0.85
0.04
0.0008
~7
0. 0013
4
16
50
4.1
0.03

(8,330)^
(8,14Sr
After
RO
Concentrate
2,688
1.0
3.6
0.05
1.9
99.2
86.4
0.05
69
0 05
39 1
0.8
0 01
~7
0.01
84
1,536
4,800
1,004
2.9

(2,912)
(2,041)
Treatment, wg/1
Boron Adsorption
28
0.01
0.22
0.0005
~o
0.2
0 9
<0.0005
1.5
0,001
0 85
0.04
0 0008
~7
0 0013
4
16
50
4 1
0 03

(8,330)
-~

h
Phenol Adsorption
28
0 01
0 22
0 0005
~0
0 2
0 9
<0.0005
1.5
0 001
0 85
0.04
0 0008
~7
~o
4
16
50
4 1
0.03

(8,330)
—

  Based on data in Table 4.2-22, assuming mine water is 43% from upper and 57% from lower aquifer.
  The removal efficiencies for very small concentrations of boron and phenol have not yet been established.
c In Exaiwle II, more of the mine water is ysed in processed shale moisturizing; therefore,  a  lower amount
  is available for treatment and disposal.
  Assuming permeate recovery factor is 80%.
Source   WPA estimates based on data from Gulf Oil Corp.  and Standard Of!  Co,  (Indiana),  Hay 1977,
                                                    210

-------
         TABLE 5.2-14.  DESIGN AND COST OF REVERSE OSMOSIS TREATMENT
                            OF EXCESS MINE WATER

Item
Nine Water Flow
Number of Elements
Number of Pressure Vessels
Surface Area
Membrane Flux
Electricity
Fixed Capital Cost
Elements @ $1,160 each
Pressure vessels i $1,920 each
Subtotal
Total equipment cost
(250% of subtotal)
Civil work and installation
(25% of total equipment)
Contingency
TOTAL
Direct Annual Operating Cost
Maintenance & 4%
Labor, 48 hr/day § $30/hr
Electricity @ 3$/kW-hr
Membrane replacement (1.5-yr life)
Scale inhibiting chemical
TOTAL
Unit Example I
gpm 11,242
5,000
800
ft2 /element 165
gal/day/ft2 15-20
kW 3,520
$103
5,800
1,536
7,336

18,340

4,585
5.275
28,200
$103
917
473
832
3,457
70
5,749
Example IIa
10,190
4,530
730
165
15-20
3,190

5,255
1,402
6,657

16,643 ,_

4,161
4,796
25,600

832
473
754
3,133
65
5,257

  In Example II, more of the mine water is used for processed shale moist-
  urizing; therefore, a lower amount is available for treatment and
  disposal.

  Maintenance is based on the fixed capital cost less contingency.

Source:   WPA estimates based orr information from Hicks and Liang,
         January 1981.
                                     211

-------
              30,000
              25,000
              20,000
8  15,000


I
a.
           a
              10,000
                5000
                              2000
                                4000       6000       8000


                                      FLOW RATE, gpm
                                                                                6000
                                                                                5000
                                                                                           4000  O
                                                                                                 t/j

                                                                                                 8


                                                                                           3000  1
                                                                                                 to
                                                                                                 a.
                                                                                                 O
                                                                                2000
                                                                                                 LU

                                                                                                 fK
                                                                                           1000
10,000      12,000
SOURCE:  WPA
                       FIGURE 5.2-14   COST OF ORGANICS REMOVAL WITH REVERSE OSMOSIS

-------
             9.5
             9.0
          CO
          O
          o
          o.
          
                                                                     z


                                                                     <£
                                                                     1
   0.8
9500
SOURCE:  WPA
                      FIGURE 5.2-15   COST OF BORON  REMOVAL WITH ION EXCHANGE SYSTEM

-------
             70
         S 6,5
         V)
         o
£
% 6,0


o
UJ
X
            5,5
            5,0
             5000
               I
6000         7000
                                           8000         9000

                                        FLOW RATE, gpm
                                                                    1.4
                                                                    1.2
                                                                                              1,0
                                                                                                  o

                                                                                                  v»
                                                                                                  o

                                                                                                  to
                                                                        cc
                                                                        UJ
                                                                        Q_
                                                                        O
                                                                                                  =3
                                                                                                  z

                                                                                                  *t
                                                                   0.8 S
                                                                   0.6
10,000       11,000
SOURCE;  WPA
                      FIGURE 5.2-16   COST OF PHENOL REMOVAL WITH ION EXCHANGE SYSTEM

-------
       LOSSES
         i

         132
MINE WATER j 528
 MAKEUP
         t
GAS LIQUOR
594
AMMONIA
RECOVERY
STRIPPED
562 *"
CARBON
ADSORPTION
0/*it IQ&JCTft
"wl«* 3*lt,y
562 "*
COOLING
WATER
TREATMENT
TREATED
WATER ^
562
COOLING
TOWER
EVAPORATION^
681 *"
DRIFT mr
Q ^
 COOLING
  TOWER
SLOWDOWN
ALL FLOWS IN GPM

SOURCE: WPA
                                                                                        200
                                                                                            EVAPORATION
                                                                                            200
            FIGURE 5.2-17  FLOW SCHEME FOR COOLING TOWER MAKEUP AND SOLAR EVAPORATION TREATMENTS

-------
                                             TABLE 5.2-17.  MATERIAL BALANCE AROUND COOLIHfi TOWER
CD
Before Treatment
Components
NH3
TOS
Qrganics
H20
TOTAL
Wastewater From
Carton Adsorption
Ib/hr {gpm)
6
429
85
281.049 (562)
281,569
Mine Water
Makeup
Ib/hr (gpm)
__
265
—
264.000 (528)
264,265

Mass %
0.001
0.127
0.016
99.856
100.000
Total Evaporation
Ib/hr (gpm) Ib/hr
6 6
694
85
545,049 (1,090) 440,500
545,834 440,506
After Treatment
Drift Slowdown
Ib/hr (gpm) Mass %
__
0.688
0,084
4,500 (9) _3i._227
4,500 100.00

to Solar Pond
Ib/hr (gpm)
'—
694 ;
65
1D0.049 (200)
100,828
     Source:  WPA estimates.

-------
      TABU 5.2-18.  DESIGN AND COST OF COOLING TOWER MAKEUP TREATMENT*

Item
Evaooratlon and Drift Losses
Slowdown
TOTAL MAKEUP
Cycles of Concentration
Sulfurlc Acid Addition
Direct Annual Operating Cost
Sulfuric acid @ $65/ton
Unit
gpm
gpm
gpm
—
mg/1 (ppm)
ton/yr
$103

Quantity
890
200
1,090
5.5
550
1,185

77

* This technology could be considered as part of the process rather than
  pollution control.

Source:  WPA estimates based on information from Peters and Timmerhaus,
         1980.
          TABLE 5.2-19.  DESIGN AND COST OF SOLAR EVAPORATION POND

Item
Flow Rats to Pond
Evaporation Rate
Pond Area
Pond Depth
Liner (chlorosulfonated polyethylene)
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 2%*
Unit
gpm
acre^ft/yr
in/yr
acres
ft
103 ft2
$103
$103

Quantity
200
290
15
257
3
11,200
14,200

231

* Maintenance is based on the fixed capital  cost less contingency.

Source:   WPA estimates.


                                   - 219

-------
        to
        o
        CO
        o
        o
        a.
        
-------
 DISSOLVED QRGAN1CS
 CONTROL TECHNOLOGIES
SOURCE' WPA
                                  BIOLOGICAL
                                  WET AIR
                                  OXIDATION
                                  CHEMICAL
                                  OXIDATION
                                  THERMAL
                                  OXIDATION
                                   MEMBRANE
                                   PROCESSES
                                  ADSORPTION
                                  FREEZING
                                   SOLVENT
                                  EXTRACTION
                                  EVAPORATION
                                  DISPOSAL AHD
                                  CONTAINMENT
r REVERSE OSMOS!S(ROS


  •ULTRAFILTRATIQN(UF)


  •CARBON

  -RESIN

  -PROCESSED SHALE
  STRIPPING

  COOLING TOWER
  SOLAR
  FIGURE 5.2-19   DISSOLVED ORGAIttCS CONTROL TECHNOLOGIES
                                  221

-------
                                              TABLE 5.2-20.   KEY FEATURES OF CONTROL TECHNOLOGIES FOR DISSOLVED OR6AKICS
ro
w
IsS
Control
lechnology
Biological














Wet Air Oxidation






Chemical Oxidation



Thermal Oxidation





Membrane Processes
{UF, RQ)



Adsorption
(Carbon, Resin,
Processed Shale)



Operating Principle
Oxidation to C02 and H20
(aerobic) or reduction to CH4
(anaerobic) in the presence of
suspended bacteria











Direct reaction of 02 with
wastewater in a closed,
pressurized vessel at
elevated temperatures.



Reaction of organics in
wastewater with 03,
peroxides or chlorine-based
oxidants
Organics are combusted and the
water stream is simultaneously
evaporated.



Separation of water and
dissolved matter by semi-
permeable membrane under
influence of pressure field.

Adsorption of organics in
water by activated carbon
or polymeric resin Powdered
activated carbon has been
used in conjunction with
biological processes
Components
Removed
TOC, BOD, COD.














TOC, BOD, COO,
as wel 1 as some
oxidizable
inor games



TOC, BOD, COD,
oxidizable
inorganics

All oxidtzable
organics




Large molecules
(UO, inter-
mediate size
and ioriizable
molecules (RO).
Many organics





Remova1
Efficiency
50% rfflioval of
TOC typical for
retort waters
Efficiency
enhanced by
addition of PAC









90+X removal of
BOD, COD, TOC
is possible in
a system with a
residence time
of one hour or
greater.
90+% achievable
depending upon
conditions of
operation
Essential 1y
100% in
properly
designed system.


50-98% of
separable
components


50% removal of
TOt typical for
raw and
pretreated oil
shale
was tews ters
Feed
Requirements/
Restrictions
Relatively
constant feed
temperature
and pollutant
loadings are
required to
ralmmize
"shocks" to the
system Air or
oxygen must be
added to aerobi c
systems.
Supplemental
nutrients may
be required
Air or oxygen,
heat If
autothermic
reaction
conditions are
not present

Oxidant



Feed should be
concentrated
to reduce fuel
required for
water
evaporation
Filtration,
pH adjustment,
removal of
foul ants.

Adsorbent.





By-products
and Wastes
Biosludge, COZ
In aerobic,
CH, in anaerobic
process











Vent gases con-
taining CO,
C02, light
hydrocarbons,
NH3, sulfur
species.

Vent gases ,
wastewater and
reaction
products.
Flue gases





Concentrate
stream, spent
membranes


Spent adsorbent





Comments
Long residence times
(days) require large
reactor vessels, ftir
emissions during
aeration may require
that the vessels be
enclosed








Promising, but not
proven in this applica-
tion Fairly rigorous
construction materials
are required


Chlorine-based
oxldants may cause
problems with treated
wastewater
If NH3 or sulfur-
species are present,
NOx and S02 emissions
may require control.
Effective but
expensive control
Long-term membrane
fouling not yet studied.



Probably more effective
as a polishing rather
than a bulk organics
removal process


                                                                                                                                       (Continued)

-------
                                                                 TABLE 5.2-20  (cant  }
Control
Technology
Freezing




Solvent Extractian





Evaporation
(Stripping, Cooling
Tower, Solar)




Disposal and
Containment




*^™« 	 > 	
Operating Principle
Cooling to form pure ice
crystals which are separated
from the concentrated brine


Wastewater is intimately
mixed with a water- immiscible
organic solvent. Dissolved
organics partition occurs
between water and organic
solvent phase.
Evaporate volatile components
by applying heat via steam,
solar energy, or exchange with
the cooling water return from
the plant. Simultaneously
concentrate the nonvolatile
compounds.
Fixing of the contaminants on
a substrate or disposal or
contalnnent with Isolation
from surroundings



Components Removal
Removed Efficiency
TOC, TBS 90+% possible




Components Found to be
soluble in ineffective for
organic solvent oil shale
used wastewaters.


TOC, TDS, _ Variable,
depending on
the volatility
of the
compounds


TOC, TDS Variable,
• depending upon
the method used
and surrounding
factors.

•
Feod
Requirements/ By-products
Restrictions and Wastes
Concentrate
stream, ice



Solvent, Recovered
solvent regen- organics
eration system



Removal of Overhead vapors
volatile and concentrate
components stream
preferred.



Remova 1 of
volatile
components
preferred.



Coiranents
Volatile components
are removed along with
the nonvolatile? Not
yet demonstrated
commercially
Will not be used unless
suitable solvent is
found



Direct steam stripping
may remove azeotropic
components Slow air
and biological oxidation
are possible with the
cooling tower and solar
evaporation
The wastewater may
be contained, or
remjected, underground.
Contaminants nay be
chemically and physi~
cally fixed on the
processed shale
Source:   WPA,

-------
      Biologicaltreatment.   Biological  processes  may  be  aerobic, where organ-
 ics   are  oxidized  to -carbon  dioxide  'and.  water,  or  anaerobic,  where the
 organics  are reduced to methane.   BotJr approaches  produce  sludge as a waste.
 Aerobic  processes are faster and  less  susceptible to toxicity problems than
 anaerobic  processes,  but  oxygenation  equipment  is  required.   Bench-scale
 tests on  retort  waters  have shown  that  minor changes  in  retort water composi-
 tion  can result in a  significant reduction  in  the performance of  a weTl-
 acclimated   system.   In  the  presence  of  biorefractory  (nonbiodegradable)
 organics,  powdered-activated  carbon  may  be  added  to the  bioreactors  to
 achieve  acceptable  reduction  in  organic  content.   Necessary pretreatment
 includes -stripping,  pH  adjustment,  and  nutrient addition; control of specific
 toxic materials  may be required as well  (Adams and Eckenfelder, 1974; Hicks,
 et al., June 1979;  Hicks and Wei,  December 1980).

      Met air oxidation  (WAO).   This  is  a procedure for the  destruction  of
 organic  matter  dissolved   or  suspended  in  water  or wastewater by  oxidiz-
 ing  with air at  high  temperatures.   The  temperatures used  are  above the
 normal  boiling point of  water, and the  reaction is  carried out under pres-
 sure  to prevent  boiling.   The pressure  is usually  600 psig  or above.   The
 degree  of oxidation achieved  depends  on the temperature  and the material
 oxidized.

      The  advantage  of WAO  is that  the  organics do not  have to be  biodegrad-
 able  to be  oxidized.   In  fact, WAO  often produces biodegradable  substances
 from  refractory  material.    For  economic reasons,  it  is  recommended  that
 WAO  systems  be  designed  to  remove no more  than 80% of the  organics.   The
 optimum  effluent is one that has  a COD/BOD ratio  of unity, i.e.,  the chemi-
 cally oxidizable  material   is  also   biologically  oxidizable.    Biological
 oxidation can be used  as  a post  treatment  (Water Purification Associates,
 December 1975; Wilhelmi and Knopp,  August 1979).

      The  WAO  procedure  is  normally  used for high  strength  wastes  because
 costs  scale  with the volume of water to  be  treated.    The energy  needs for
 WAO  often can be  supplied by  heat  released  in the process  itself  if the
 wastewater has a  high concentration of  reactive material.   It is an expensive
 process and  would be considered only for  high  strength wastes not amenable to
 other treatments, such as solvent extraction.

      Chero1ca|oxidation.    In  this process,  oxidation  of  the  organics  is
 caused  by adding oxidizing  agents to  the  wastewaters.   The  oxidants are
 usually  comprised  of  ozone,  peroxides, chlorine,  chlorates,  etc.   These
 chemicals are nonselective;  that   is,   they  oxidize total  organic  carbon  as
well  as  some  inorganics.    The  oxidation  may  be  carried out at  ambient
 temperature,  which  is  an advantage.  Formation of  obnoxious wastes is likely
with  chlorinated oxidants.   Explosion  is  also  a possibility under uncon-
trolled conditions.

     Thermal oxidation.    The  wastewater is  evaporated and   the  dissolved
 organics  are  simultaneously combusted by directly firing  burners that are
 submerged  under  the  wastewater.   Organic  nitrogen  and   sulfur  compounds
will  convert  to  NOx and   S02,  which   is a  disadvantage.   Additional  waste
gases  may  form  if  the  fuel combustion  is incomplete.   Heat transfer within

                                     224

-------
the wastewater  is  efficient;  however, due to  the presence of a large amount
of  noncondensable  combustion  gases,  waste  heat  recovery from  the overhead
vapors may  not  be  practical.   Energy requirements  can be reduced by using a
praeoncerrtrated wastewater,

     Reverse osmosis.   In  addition  to  removing  inorganics,  this  process
removes  orgam'cs  to  a  certain  extent,  particularly  if  the  organics are
ionized.  Tests on in situ retort waters have shown that, at a high oH,  about
95% of  the organics  are  removed.   Modern polyamide  thin film membranes are
available  for  high  pH operation,  but  additional  data  on  membrane fouling
characteristics  with  retort  waters  are required.   The  concentrate  stream
produced requires  treatment,  possibly by WAO (Water Purification Associates.
December 1975; Hicks and Liang, January 1981).

     Ultraflltratign.   In  addition  to  separation  of  oils  and  suspended
particles,  ultrafiltration  will   also   separate  large  organic  molecules
(HWt £ 1,000).  It is unlikely that ultrafiltration will be incorporated into
a  treatment  train  for the  removal  of large organic molecules,  as  these are
not a  significant  fraction of  total organics  in retort waters.   However,
ultrafiltration may  be used for  emulsified oil separation and, in that case,
would serve  as  a  useful  pretreatment to RO (Water Purification Associates,
December 1975).

     Carbon adsqrptToru  This technology  is  used  to remove organic materials
from sewage  and industrial water,  as well  as taste  and  odor  from drinking
water.    It  is  usually used  in  conjunction with  biological  treatment  as  a
pretreatraept  or polishing treatment (Cheremisinoff  and  Ellerbusch,  1978;
Water  Purification  Associates,   December 1975).    Laboratory  results   from
combined carbon adsorption  and biological  treatment of modified in  situ oil
shale retort water  indicate that up to 85% removal of dissolved organics can
ba achieved compared to  approximately 50% removal  with biological  treatment
alone (Jones,  Sakaji and  Daughton,  August 1982).

     Activated carbon  is produced  by  charring  wood or  coal  at  high tempera-
tures.   Charring temperature  is the  main factor  determining  the  adsorption
characteristics  of  granular or powdered-activated  carbon.

     Carbon must be regenerated when  it is exhausted.   The  regeneration  is
accomplished by  passing  the carbon  through a furnace at high  temperature,
usually around 800-1,000°C, with restricted  oxidation to remove the adsorbed
layer on  the  carbon.  The  quality of carbon after regeneration is  slightly
lower than the  virgin  carbon,  and  small  quantities of  virgin  carbon must  be
added to retain  the required activity.

     Activated carbon has  ion  exchange groups and  can  be used to remove  metal
ions from water.   It has  been found that, under  proper conditions  of pH ana
oxidation,  some  metal ions  are adsorbed very strongly.

     Regeneration costs are a significant  pmrt  of overall treatment costs,
making the process  uneconomical  for high strength wastes, for which frequent
regeneration  is  required.   Regeneration also  is  not  attractive for  small
units.    Energy  costs  for  running  an activated  carbon wastewater  treatment

-------
 plant are  small,  not considering  regeneration,  and are proportional to the
 pressure  drop  across  the  activated- carbon  contactor.   Fouling  in carbon
 adsorption  units is  reduced  if  the influent stream is  adequately pretreated.

      Resin  adsorption.   Resin adsorption  is a physical  process for removal
 of  organic  materials.  Normally, it is  considered as a polishing step, after
 bulk organic removal in upstream wastewater treatment  steps, but may be used
 on  waters having higher loadings than would be used for carbon.  Also, it is
 useful  for  removal  of specific toxic materials and phenol.

      The  polymer  (resin)  surface  can  be  made  hydrophobic  or hydrophilic.
 Activated groups can be  introduced  to increase selectivity.  Regeneration can
 be  accomplished by washing with methanol, weak acid or weak base.  Steam can
 be  used to  vaporize adsorbed  materials.

      Adsorption on  processed  shale.    This   method  has  been   proposed  for
 organics  control   in  retort waters  at oil  shale plants.   In  studies  at
 Lawrence  Berkeley   Laboratory,  processed   shale   from  the  Lurgi,  Parana,
 TOSCO II,  and  three simulated  in   situ processes were  contacted  with four
 separate  simulated  in  situ  retort  waters  in batch and continuous (column)
 systems  (Fox, Jackson  and Sakaji,   1980).   These  studies indicated that the
 processed shale reduces the inorganic carbon by 50-98%,  the organic carbon by
 7-73%,  and  elevates  the  pH  from  initial  levels   of 8-9  to a  final level  of
 10-11.  An  advantage of the  process is  that the increase in pH  would facili-
 tate  downstream ammonia stripping and would reduce the loading  on downstream
 organic removal steps.

      freeaing.   As  previously  discussed,   freezing also  removes  dissolved
 organics.   One  advantage  of freezing  over evaporation processes  is  that
 volatile  organics  are  removed as  well.   This process  has yet  to be applied
 commercially   (Barduhn,   September 1967;   Water   Purification   Associates,
 December  1975).

      Solvent  extraction.   When  wastewater  is  contacted with  a  sparingly
 soluble   immiscible  organic  solvent,   the   dissolved  organic  contaminants
 partition  themselves between the  aqueous   and  organic  phases  according  to
 their relative  solubility in each.   The organic  phase is  separated  and the
 dissolved   contaminants  removed  in  a  distillation   step.   Alternatively,
 the  solvent and dissolved organics  may  be  incinerated.   Solvent extraction
 is  most  economical  for high strength wastes because  costs  scale with  the
 volume  of water to be  treated  and  are  relatively independent  of the amount
 of  substances removed.   Unfortunately, effective   solvents for the wide range
 of  organics  present  in retort  water  have  not been  found,  and  it  appears
 unlikely  that solvent extraction will be useful  in retort water  treatment
 (Hicks,  et al., June  1979).

     Stripping.   Volatile  organics  are  removed along  with ammonia  and  the
 acid  gases  in a stripping column or other thermal evaporative  process.  The
amount  of organics  removed depends  essentially on their volatility relative
to water.  Organics  in retort water are relatively  nonvolatile and indications
are  that  less  than 20% will  be removed  in a column  stripping 99% of  the
ammonia.  Organics  in gas1 condensates, such  as the TOSCO II  foul  water,  are


                                      226

-------
significantly  more  volatile,  and bench-scale  tests  have  shown  that  up  to  85%
of  the organics  are  removed along with  the  ammonia.   The volatile organics
may  then  be incinerated, along with  the  other stripped gases,  or may  be  ad-
sorbed  from  the gas  stream  prior  to  ammonia  recovery (Hicks  and  Liang,
January 1981).

     Cooling tower.  The cooling  tower may be  regarded  as a water  treatment
systara.   As such,  its  main function  is  to concentrate  the dissolved  salts,
w-Tich  may then be  removed  at  lower cost in a sidestream or blowdown  treat-
ment stage.  When using  process wastewaters as  cooling tower makeup, upstream
removal of ammonia and  organics  need not be  as  efficient (and therefore as
axpensive)  as  when the  wastewater is discharged.   It  has been demonstrated
that  refinery  phenolic  wastewaters can  be  used in  a cooling  tower and that
faic-oxidation  of  phenol  will  occur  with  very  high   efficiencies   (Hart,
June 11,  1973).   Ttie conditions  necessary  for  successful  bio-oxidation  are
low  sulfide (below 2 ppm)  and small  variations in  pH  (between 7.8 to 8.3).
Chlorination  is  used to prevent  biological growth.  Corrosion of steel  has
been  low.  Ammonia  will  not  concentrate  in   a  cooling  tower, but it will
vaporize with the water.

     Solar evaporation.    Solar radiation incident  upon  the  surface  cf  an
open  evaporation  pond is  used as the energy  source.   Large,  lined, shallow
ponds  are feasible for  this  application.  The rate of  evaporation depends
on  humidity,  wind  velocity and  solar energy  absorbed.   Dyes  may  be  added
to  the  wastewater to  increase the energy absorption, with  a  consequent  in-
crease  in  the  rate of  evaporation.   Land  is  a major  cost,  and problems
re1atsd tc final  disposition' of  the concentrated  wastes may  arise.   Bio-
logical and slow  air oxidation  of  the  organics  may  occur.    Volatile  and
odoriferous components   must  be  removed  from  the  wastewater  prior _ to   its
evascra'cion.

     Pisfiosal  and centalnment.   Wastewater can be "controlled"  with a minimum
of treatment by  some  disposal  or containment  options.   These options include
processed  shale  wetting as part  of  the  disposal  procedure.   The  water  and
contaminants are  either  "cemented"  or  adsorbed into  the  processed  shale.
Provision   of  an  impermeable lining under the  shale pile can  prevent  water
from percolating through to the  ground if the shale does not cement.   Water
used  for  processed shale wetting  should not  contain  any volatiles.   Since
water used  for revegetation and  leaching of processed shale piles  will con-
tribute to runoff, it may have  to  be of considerably higher quality than that
used for moistening.

     Wastewater may  be  injected  underground  (deep well  injection),  as  in
disposal   of some  oil  well  brine wastes  (Mercer, Campbell  and  Wakayima,
May 1979).  However,  costs for  underground   injection   may be significant
because deep  wells  are  required  to   prevent  contamination of upper  level
aquifers.    Legal   and  environmental   probTems  associated  with  underground
injection  have not been  clarified.   Reinjection of mine drainage waters  may
be a possibility  for disposal  of  this stream when excesses  exist.   Geologic
ar-d hydrologic effects  may require  evaluation.
                                     227

-------
     Corttro 1 Techno 1 ogl es Analyzed--

     The primary  stream  .which may require  control  of dissolved organics is:

     *    Excess Mine Water  (stream 75).

     Aeration  of  the excess mine water  by bubbling  air  through  it was ex-
amined as a dissolved organics control technology.  Aeration serves many pur-
poses; for example,  it provides oxygen for biological activity in the water,
carries  out  oxidation  of  chemically  oxidizable  organics,   oxidizes  some
inorganics and removes  odorous  compounds.   Two  examples,  reflecting slight
changes in the water distribution in  the plant,  were analyzed to obtain the
cost and design information for the treatment, as presented in Table 5.2-21.
A cost curve for the aeration pond is  shown in Figure  5.2-20.

               TABLE 5.2-21.  DESIGN AND  COST OF AERATION POND

Item
Excess Nine Water Rate
Retention Time
Pond Depth
Surface Area
Capacity of Aerator
Fixed Capital Cost
Land preparation
Aerators
TOTAL
Direct Annual Operating Cost
Maintenance @ 4%
Labor, 10 hr/day @ $30/hr
Electricity @ 3$/kW-hr
TOTAL
Total Annual Control Cost
Unit
9P«n
day
ft
10s ft2
ftVmin. of air
$103
$103

$103
Example I
8,330
1
10
160
7,950
224
206
430
14
99
_4_Q
153
262
Example IIa
8,149
1
1C
157
7,340
•*•)- «n>
It'U
410
14
99
JIZ
150
—

  In Example II, more of the mine water is i^sed for processed shale imrstur-
  izing; therefore, a lower amount is available for treatment and disposal

  Maintenance is based on the fixed capital cost less contingency.

c See Section 6 for details on computation of the total annual control cost.
  No cost is given for Example II as it is not part of the case study.

Source:   WPA estimates.


                                     228

-------
             000
         1*1

          2  600
          4*
          in
          O
          O
             400
          a.
          O
          Id
          X
             200
                          T~T
                      T~—n~"
2000        4000
                                               6000       BOOO

                                             FLOW RATE, gpm
                                                                                       180
                                                              160
                                                                                           CO
                                                                                           O
                                                                  ID
                                                                  tE
                                                                  1JJ
                                                                  Q-
                                                                  o
                                                              140
                                                                                           3
                                                                                           Z
                                                                                           Z
10,000      12,000
                                                              120 £
                                                                  O
                                                                                       100
SOURCE:  WPA
                                   FIGURE 5.2-20  COST OF AERATION  POND

-------
      Other Control  Technologies Analyzed"

      Reinjection of the excess  mine  water back Into  the  aquifers was analyzed
 as  a viable  alternative to  surface  discharge.   This approach has been men-
 tioned  for Tract C-a in  the  event that excess mine water  remained after the
 process  needs (Gulf Oil Corp. and Standard  Of! Co. [Indiana],  March 1976).  A
 combined dewatering rate of 16,500 gptn was  calculated from  the published data
 for  the  two aquifers under  the  tract,  and approximately  8,300  gpm  of the mine
 water were  estimated  to remain after  fulfilling the process requirements.
 This  value was  used in  determining the essential  criteria for reinjection.

      The reinjection option  has an  interesting  feature built in:  that is,
 reinjection of the  excess mine  water back into the aquifers will increase the
 flow at  the  dewatering  wells.   Even more  water will  now be available for
 reinjection which,   in  turn,  will again increase the  dewatering  rate.   The
 extent  of the flow  increase  is dependent upon the reinjection distance from
 the  pit—the  farther  the  reinjection  point, the  smaller the  influence on
 dewatering.   The increases  in  dewatering rates at equilibrium, as a function
 of  the   distance  from  the  pit  center,  have  been determined  by an iterative
 process  for the two  aquifers and are  presented in Figures  5.2-21  and 5.2-22.
 Figure 5.2-23 represents reinjection  pressure as a  function  of distance.  A
 distance of  50,000 feet from  the pit  center was  finally selected  for the
 reinjection  into  the  upper  aquifer  after  taking  into  consideration the
 pressures,  flow  increases, etc.,  involved.   At equilibrium, approximately
 15.000 gpm  of the  excess mine  water  will   need  to  be reinjected, causing a
 flow-back  of  7,000  gpm at  the  dewatering wells,  for a total   dewatering rate
 of  23,500 gpm.  The  design and- cost  details  for the reinjection system are
 given in Table 5.2-22,  and  a  cost curve is  shown  in Figure  5.2-24.

      If  the use of wastewaters  with  high organics  loading is not acceptable
 for  processed shale moisturizing or  reuse  in  the plant, additional organics
 removal  efficiency  can be  achieved by several technologies,  such as reverse
 osmosis  and carbon  adsorption.   These  technologies have  not been proposed for
 the  Lurgi-Open Pit  plant,  but  they  have been analyzed based  on their poten-
 tial  for application  in oil shale wastewater treatment.

      Reverse  osmosis  affords  simultaneous removal of the dissolved inorganics
 and  organics.   This  technology  has  already  been discussed  under Dissolved
 Inorganics  control.   Under  optimum  conditions,  high  removal of dissolved
 compounds  is  obtainable with  RO, but  the permeate  from RO may still contain
 some  low molecular weight organic compounds.   This stream can  be subjected to
 organics polishing  by adsorption on activated carbon.  With this technology,
the wastewater is  allowed  to pass through  a bed  of activated  carbon on which
the dissolved organics  are  adsorbed and  a  cleaner water emerges.   The spent
carbon  is  regenerated  periodically  by  steam  or  hot gas  stripping,  and the
desorbed material is incinerated before  it  is vented to the   atmosphere.  If
the  bulk organics  and  inorganics have  been  removed  previously  (e.g.,  by RO
treatment), the  carbon  adsorption treated water  can be used for high quality
water needs (e.g.,   as  a makeup  to  the cooling tower).   Figure 5.2-25 shows
the  process  flow  diagram  for  carbon  adsorption  (a  flow  scheme for the
technology,  when  applied  to   the  gas  liquor,  was  already presented  in
Figure 5.2-17).  Table  5.2-23 indicates the composition of  the treated water,


                                     230

-------
JS3 •
UJ
             1

             —*  3
              ft
              LU
              CC
              I
                              J_
"0            I

SOURCE' SWEC
                                                        _i
                                                                     i
                                                        3456

                                                 DISTANCE  FROM PIT CENTER TO REINJECTIOM WELL
                               FIGURE  5.2-21  UPPER AQUIFER DEWATERING RATE INCREASE WITH REINJECTION DISTANCE

-------
   6r
n_
19
LU
X
la
C3
LU
a:
UJ

5
LU
(/I
                                          LOWER  AQUIFER
   °0
j

0
    SOURCE' SWEC
12            3456

              DISTANCE FROM PIT CENTER TO REiNJECTION WELL

                               (FT x 10,000)

RSURE 5.2-22 LOWER AQUIFER DEWflTERINC RATE INCREASE WITH REINJECTION DISTANCE

-------
          o
8
s
OK
a.


1  2
*»
3g
a>


§  I
                                                 O  UPPER  AQUIFER

                                                 O  LOWER AQUIFER
                             _L
            J_
                                                             j_
    •'O            !
     SOURCE .SWEC
2           3            4           S           6           7

   DISTANCE FROM PIT CENTER TO  RDMJECTIOM WELLlFT » 10,000)
                         FIGURE 5.2-23  REfNJECTION PRESSURE AS A FUNCTION OF DISTANCE

-------
              TABLE 5.2-22.   DESIGN AND COST OF REINJECTION  SYSTEM

Item
Excess Mir>e Water Flow Rate
Pipeline Pumps
Flow rate (each)
Capacity (each)
Discharge pressure
Motor (diesel driven)
Carbon Steel Pipe
Length
Diameter
Design pressure
Insulated Carbon Steel Pipe
Length
Diameter
Design pressure
Reinjection Pumps
Flow rate (each)
Capacity (each)
Discharge pressure
Motor (diesel driven)
Reinjection Wells
Carbon steel casing diameter
Depth
Das i go pressure
Valves
Diameter
Valves
Diameter
Diesel Storage Tank
Capacity
Fixed Capital Cost
Pipeline pumps
Pipe (30")
Pipe (10")
Reinjection pumps
Reinjection wells
Valves (30")
Valves (10")
Diesel tank
TOTAL
Direct Annual Operating Cost
Maintenance
Utilities
TOTAL
Unit
gpn
—
gpra
gpni
psig
HP

ft
in
psig

ft
in
psig
—
gpm
gpffl
psig
HP
—
in
ft
psig
—
in
--
in

gal
$103









$103



Quantity
15,330
3
5,100
7,500
150
1,000

50,000
30
200

5,000
10
1,500
30
510
750
1,200
750
10
10
450
1,500
5
30
60
10

50,000

160
15,620
655
5,853
685
79
308
49
23,409

123
2.898
3,021

Source:   SWEC estimates.



                                      234

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             5.0
              2000
3000
4000        5000         6000

       FLOW RATE, gpm/PUMP
7000
SOURCE;  OKI based on information provided  by  SWEC


                          FIGURE 5.2-24   COST  OF EXCESS NINE WATER REINJECTION
  0.6
8000

-------
w
01
        STB1PPED\


r






,|
A






£—
i




SPENT
CARBON
STORAGE




AFTER
k BURNER
FEED
TANK
\ /


»*

SCRUBBER
^,,

	 '



                                                                                                                                —»J FLUE GAS    \
STREAM
IDENTITY

FLOW I03ACFM
HATE I03ll>/ltf
jpm
TEMP,°F
ngree .
, flSly
FUEL
GAS


N.D

AMB
H n

STRIPPED
GAS
LIQUOR

261 6
562
1 10
• HO
~*
MAKEUP
CARBON


004

AMB


AIR



NO.

AMB


SCRUBBER
DISCHARGE


ND

NO


SPENT
CARBON


004

NO.


CA TREATED
PTIR


281 6
562
AMB


SCRUBBEB
FLUE 5AS


H.p

HE-


PROCESS
WAKfUR
WAtfS

'< P

AMP
«- 2UH

        SOURCE WPfl
                                                FIGURE  52-25  CARBON ADSORPTION PROCESS FLOW SCHEME

-------
Table 5.2-24  gives the  design specifications  and  cost information  for the
carbon adsorption technology, and Figure 5.2-26 presents a cost curve for the
techno:ogy.


        TABLE 5.2-23.   MATERIAL BALANCE AROUND CARBON ADSORPTION UNIT

Component
NH3
(NH4)2S03
Organics (TOC)
H20
Before
Mass %
0.0021
0.15
0.06
99.79
Treatment
Ib/hr (gpra)
S
429
170
281,049 (562)
After
Mass %
0. 0021
0.15
0.03
99.82
Treatment
Ib/hr (gpm)
6
429
85
281,049 (562)
     TOTAL          100.00      281,654            100.00      281,569


Source:  WPA estimates.


5.2.5  Water Requirements

     Steam Production—

     Approximately 1 million  Ib/hr of  550 psig  steam are produced  by waste
neat recovery  in the Lurgi retorting  system.   The steam is  of  high quality
because  only  clarified  mine  water  is  used.   A small  portion  of  the  high
pressure steam  is reduced to  60 psig by driving  the retort gas  compressor
turbines.  The  low pressure steam thus generated  is circulated  to  various
areas  of the  plant  to  meet  other  requirements.    This low  pressure steam
condenses upon use and is returned to the boilers without treatment.   Since a
large  portion  of the high  pressure steam  is  not  used,  it is available for
power generation.

     Table 5.2-25  presents  the  steam  balance  for  the plant; as  indicated,
approximately 866,000 Ib/hr, or  over  80%,  of the total steam  is  available as
a  net  product.   This  amount is  equivalent to  120 MW of electricity.   The
power  requirement  for the  lift  pipe air compressor  is estimated to  be about
150 HW;  thus,  the excess steam  can satisfy about  80%  of this  requirement.

     A  0.5%  loss  factor and  IX  blowdown  is  assumed  for the  total  steam
produced.  This  loss  is made up with additional clarified water.   Both the
feedwater and the  makeup water  undergo boiler  feedwater  treatment by zeolite
softening ami  demineralization.   Estimated  water quality parameters  for the
boilar feedwater are  indicated in Table 5.2-26.
                                    •237

-------
        TABLE 5,2-24.  DESIGN AND COST OF ACTIVATED CARBON ADSORPTION
                             FOR PROCESS .WATERS
•
Item
Stripped Gas Liquor Flow Rate
Organic Loading
Grgarn'cs Removed
Carbon Capacity
No. of Beds (1 standby)
Bed Diameter
Bed Depth
Carbon Volume/Bed
Carbon Regeneration
Regeneration Period
Carbon Loss in Regeneration (5%)
Furnace Area
Fuel
Steam
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 4%*
Labor, 12 hr/day @ $30/hr
Regeneration and carbon replacement
TOTAL
Unit
gprti
mg COD/1
Ib COD/hr
1b COD/1 b C
—
ft
ft
ft3
Ib/day
days
Ib/day
ft2
Btu/lb C
Btu/lb C
$1Q3
$103

Quantity
562
1,600
800
0.6
2
12
6.5
3,350
18,000
1
900
180
3,000
1,450
2,500

81
118
882
1,081

* Maintenance is based on the fixed capital cost less contingency.

Source:  WPA estimates based on information from Cheremisinoff and
         Ellerbusch, 1978.
                                     238

-------
           3.0
           2.5
        8
g»
        o

        o
            i.5
            '200
                300
                                    A.
400        500        600


      FLOW RATE, gpm
                                                                         1.50
                                                                         tag
                                                                                  1.00
                                                                                      DC.

                                                                                      UJ

                                                                                      Q.

                                                                                      O
                                                                              13
                                                                              Z
                                                                              z
                                                                              
-------
      TABLE 5.2-25.  STEAM  PRODUCTION, USES AND BOILER FEEDWATER MEEDS

Parameter
Steam Production
Waste Heat Boiler
Steam Uses
Ammonia Recovery
Stretford Gas Treatment
Naphtha Recovery
DEA Treatment
Net for Power Generation
TOTAL
Net Steam Circulated
Feedwater Makeup Requirements
Losses (0.5% of circulated)
B 1 owdown
Softener Regeneration Waste
TOTAL FEEDWATER MAKEUP
Unit '" '' Quantity
. 10s Ib/hr
1,060
103 Ib/hr
53
1
10
130
866
1,060
gpm 2,120
gpm
11
21
11
43

Source:  WPA estimates.
        TABLE 5.2-26.  WATER QUALITY PARAMETERS FOR BOILER FEEDWATER

Parameter
TDS, mg/1
Total Alkalinity, rag/1 CaC03
Total Hardness, mg/1 CaC03
Iron, mg/1 Fe
Copper, mg/1 Cu
Silica, mg/1 Si02
Specific Conductance, pmhos/cm
Low Pressure
0-300 psi
2,300*
470*
0.3
0.1
0.05
100*
4,700*
High Pressure
600-750 psi
1,300*
270*
0.2
0.025
0.02
20*
2,700*

* For a boiler concentration factor of 1.5.



Source:  WPA estimates based on data from Krisher, August 28, 1978.




                                     240

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     Cooling Water—

     Typical  cooling water  requirements  for  the  Lurgi-Qpen  Pit  plant a^e
summarized  in  Table  5.2-27.   Treated mine water could  be  used as the makeup
to the cooling tower.  The water quality parameters for the cooling water are
indicated  in  Table 5.2-28.  The  cycles of  concentration  are  kept  low; the
relatively  large  amount of  blowdown is used, after  equalization with other
streams,  far   processed ' shale  quenching and  moistening.   Sulfuric  acid is
added to the makeup water to control carbonate scaling.


               TABLE 5.2-27.   PLANT COOLING WATER REQUIREMENTS
Water Use                                     Unit             Quantity

Evaporation                                    gpm
  Second and Third Condensation Towers                            325
  Naphtha Recovery                                                  5
  Gas Compression                                                   8
  Amine Absorber                                                   66
  St^etford Gas Treatment                                           2
  Ammonia Recovery                                                 27
  Steam Condensing, Plant Drives                                  450
     TOTAL EVAPORATION                                 '           883

Cooling Tower Drift                            gpm
  (1% of evaporation)
Slowdown                                       gpm

     TOTAL COOLING TOWER MAKEUP
Cycles of Concentration
Source:  WPA estimates.
     Processed Shale Hoi stem ng—

     The hot processed  shale leaving the Lurgi  retorting area must be cooled
and moistened  with water  in the processed  shale  moisturizing mixer  before
being sent to  the  disposal area.  The hot shale is first quenched, resulting
in evaporation of approximately 1,984 gprn of water.   The steam generated from
the quenching  operation  is combined  with the Lurgi  flue  gas  before entering
the electrostatic  precipitator.  The  quenched  shale is then moisturized to a
final moisture content  of  approximately  19%  to  facilitate compaction  and
stabilization.   The  optimum  moisture content  and the  extent  to which  the
wastewaters should be treated  have  not yet been determined.   The falowdowns
from the cooling tower,  boilers, and clarifiers could  be  used  for quenching
and  isoistening.   These  water streams should  not  contain  volatile  material

                                     241      "    -

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    TABLE  5.2-28.  WATER QUALITY PARAMETERS FOR COOLING TOWER RECIRCULATIQN"

Parameter
Langelier Saturation Index
Ryznar Stability Index
PH
Calcium, Big/1 as CaC03
Total Iron, mg/1
Manganese, mg/1
Copper , mg/1
Aluminum, mg/1
Sulfide, mg/1
Silica, mg/1
(Cs)-(S04), product
TDS, mg/1
Conductivity, micromhos/cm3
Suspended Solids, mg/1
TOC mg/1
HH3 mg/1
CN" mg/1
Limits
Minimum Maximum
+0.5 +1.5
+6.5 +7.5
e.o s.o
20-50 300
400
0.5
0.5
0.08
1
5
150
100
500,000
2,500
4,000
100-150
600
100
5
Remarks
N&nchromate treatment
Nonchromate treatment

Nonchromate treatment
Chromate treatment





For pH < 7.5
For pH > 7.5
Both calcium and
sulfate expressed
as njg/1 CaC03







a
  concentration.

  The  limits  for the  Langelier Saturation Index  (an indication  of  CaC03
  saturation) presume  the  presence  of precipitation inhibitors in nonchromate
  treatment programs.   In  the  absence of such additives,  the  limits would be
  reduced to 0 and 0.5.

Source:  WPA estimates based on data from Hart, June 11,  1973.
                                     242

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which  would  be  released  upon  contact  with  the hot  shale.    Table  5.2-29
indicates the water  flow  rates (gpm)  for quenching and moisturizing.
            TABLE 5.2-29.  WATER REQUIREMENTS FOR PROCESSED SHALE
                            DISPOSAL AND OUST CONTROL
                                   Water Required    Shale Rate   Water  Rate
Water Use                          Mass % of Shale   103 Ib/hr       gpm

P"g_cessgd_Sha1e Disposal
    Quenching                           12.5           7,913*       1,984
    Moistening                          23.0           7,913        3,640
    Processed Shale Dust Control         2.9           7,913          459

    Revegetation                         4.1           7,913
Raw Shale Dust Control
At Mine
Crushing
At Plant

3.2
1.4
1.0

9,916
' 9; 915
9,916

634
285
190

* Dry processed shale rate.

Source:  WPA estimates.



     Processed Shale 01 sposal—

     At  the  disposal  area,  water  is  needed  for  dust suppression  and for
revsgetation.  Table  5.2-29  also  includes  the water  requirements  for these
needs.   The  water required for dust  control  is  2.9 mass percent of  the dry
processed  shale   rate,  and  the  requirement  for  revegetation  is  4.1  mass
percent.  Any water  used  in  revegetation at the disposal area should be of a
quality acceptable for agricultural use.

     Oust_Co'ntro1--

     The water requirements  for mining, crushing, and  fugitive  dust  control
are also  summarized  in Table  5.2-29,   These requirements are given  as  flow
rates  (gpm),  as  well  as  mass percents  of  the  raw  shale  rate.   The  mass
percents are  3.2%,  1.4%,   and  1.0% for mining,  crushing, and fugitive  dust
control, respectively.
                                     243

-------
     Water  used in  confined mining operations  should  be low in volatile or
toxic  materials  because mining  personnel• will  be directly  exposed to it.
Also,  the water should  contain low amounts of  suspended  and  dissolved, sol ids,
to  reduce clogging and  scaling in  spray nozzles.  The water  used  in  Brining,
crushing, and  fugitive dust  control operations  cannot be  recovered.

     Miscellaneous Requirements—

     These  include potable  and  sanitary needs,  as well  as service and fire:
water  requirements.   Table  5.2-30 summarizes  these  water  requirements  in
terms  of makeup,  discharge  and  overall  water  consumption.   Any treatment
necessary for  these waters  is standard  practice and  not a pollution  control
activity and,  therefore,  is  not discussed in depth.
            TABLE 5.2-30,  POTABLE AND SERVICE WATER REQUIREMENTS
                       Usage      Consumption  Employees  Makeup  Discharge
Water Use          gal/Man-Shi ft       %          No.      gpm       gpm

Sam' tary/Potabl s

     At Plant           33             28         950       16       10

     At Mine            33             28         580       10        8
Service/Fire Water
At Plant
At Mine
66
50
33
100
950
580
29
14
19

Source:  WPA estimates.
5.3  SOLID WASTE MANAGEMENT

     The Lurgi-Open  Pit processing facility will  be  a source of large quan-
tities  of  plant wastes  which will  require disposal.  Table 5.3-1 indicates
the makeup of the waste material that will be discarded from the plant over a
period of 20 years  (project life).  Sections 3  and 4 give information about
the origin and composition of these streams.

     The waste  material  disposal   approach and  the   practices  used  in  the
disposal can  have a  long-lasting  impact on the  atmosphere  and hydrology of
the area as well  as on the  local  aesthetics and  habitat.  The primary areas
of environmental concern in this regard are;
                                     244

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        TABLE 5.3-1.  MAJOR WASTES PRODUCED OVER A PERIOD OF 20 YEARS

Stream
Number Stream Description
2
3
28
29
59
70
88
90
91
92
93
95
96
102
103
104

105
109

111
Subore
Overburden
Slowdown from Waste Heat Boiler
Processed Shale
Spent Amine
Stripped Gas Liquor
Humidified Air Cooler Slowdown
Water for Dust Palliatives
Processed Shale Revegetation Water
Raw Shale Leachate
Storm Runoff
Service and Fire Water
Mine Water Clarifier Sludge
Treated Sanitary Water
Sanitary Water Treatment Sludge
Boiler Feedwater Treatment
Concentrate
Cooling Tower Slowdown
Clarified Mine Water to Processed
Shale Moistening
Aerated Pond Sludge
TOTAL
Material Quantity
Quantity, as a Percent of
106 tons Total Waste Quantity
78.21
408. 00
0.83
623.86
N.D.*
22.05
26.06
61,81
25.58
N.D.
5,91
0.75
6150
0.71
N.D.
0.43
.
44.27
86.41

N.D.
1,391.38
5.62
29,32
0.06
44.84
N.D.
1.58
1.87
4,44
1.84
N.D.
0,42
0.05
0,47
0.05
N.D.
0.03

3.18
6,21

N.D.
99.98

* N.D.  = Not determined.

Source:  ORI estimates based on information from Gulf Oil  Corp.  and Standard
         Oil Co.  (Indiana),  March 1976, and Rio Blanco Oil Shale Co.,
         February 1981.
                                     245

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      »    Surface Hydrology

      *    Subsurface Hydrology                          ~  "

      »    Surface Stabilization

      •    Hazardous  Wastes.


      This   section  briefly  describes  the  disposal  approaches that  may be
 applicable to  the wastes  produced  from an  abovegrourvd retorting facility
 (e.g.,  Lurgi-Open Pit) involving surface mining  of the oil shale.  In addi-
 tion,  a discussion of control  technologies  available to mitigate the poten-
 tial  impacts in  the areas  mentioned above  is presented.  The applicability
 of  these technologies should  be  determined  on a site-specific, case-by-case
 basis.   Specific  information for the  facilities  involving underground mining
 and  aboveground retorting can  be found in  the TOSCO II PCTM,  while specific
 information for  the  combined  Modified  In Situ-aboveground retorting opera-
 tions  can  be found in the MIS-Lurgi  PCTM.

 5.3.1   D1sposal Approaches

     The following discussion  applies  to  the basic  methods for  handling solid
 wastes  produced  by  the Lurgi-Open Pit processes.   Generally,  the  mining
 method,  geography and hydrology  of  the  area,  and the waste characteristics
 influence  the applicability  of  a  disposal approach.   The key features of each
 approach  are summarized  in  Table 5.3-2.   A discussion  of the control tech-
 nologies  applicable  to  these  disposal  alternatives is  presented  later in
 this section.  •

     landfills—

     A  landfill  basically entails placing the  waste  material  as a compacted
 fill  in a  suitable  location.   The  wastes  from  the  processing facility are
 transported  to  the  disposal  site by conveyors or  trucks  and  then hauled to
 the  active portion  of the  landfill.   Usually, the  solids  are laid down in
 lifts  of  9-18  inches and  compacted to  a  suitable  in-place  density.   The
 compacted  fill  may  be  built with  a proper slope to a  vertical  height of
 40-50  feet  and  then  flattened,  or benched,  to provide  a passageway for the
 disposal equipment and to facilitate  runoff collection.  The overall landfill
 can be  constructed gradually in this  fashion, using a multiple-bench arrange-
 ment.

     Depending  upon  the  geography of the disposal  site,  the landfill  may be
 built  on a level  or  nearly  level surface, in the head of  a valley, or across
 a valley.   The  applicable control technologies will  vary somewhat with site
 topography  but  still  will  be designed  to protect the surface  and subsurface
waters.  Applicable  control technologies include  runon  and runoff catchment
ponds,  embankments  and diversion  systems,  liners  and covers,  and revegeta-
tion.   Provision  for  structural  stability  of  the  fill is also a  major con-
 sideration.

     A  surface  landfill  of  some  type  will   need to be included in  most
oil   shale   developments.   This  results  from  the  shale undergoing  a  volume


                                     246

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                       TABLE 5.3-2.  KEY FEATURES OF SOLID WASTE  DISPOSAL  APPROACHES
	 	 	 	 __«,_«,.«„ _ . 	 	 ,. . 1 !___ .11 . 1 1 . r ..... 1 11 II Illl I. _ ,
Disposal
Approach
Principle
Advantages
Disadvantages
Landfills
Open Pit
Backfill
Hazardous Waste
Lagoon
Place wastes as fin in
a convenient surface
location and isolate
from the surrounding ,
environment.
Place wastes as fill in
the inactive parts of
the pit.
Place hazardous wastes
in a lined pond and
isolate them.
Relatively simple placement
and isolation of wastes.
Does not .interfere with
production.
Decreases size of necessary
surface landfill.  Restores
original contours.
The oil shale developer
can maintain absolute
control over the waste
disposition.
Dust and erosion control and
reclamation/revegetation are
relatively labor-intensive
operations.  Occupies a
significant amount of land
surface.

Difficult to isolate the
wastes from the surrounding
environment.  Placement is
relatively difficult, complex,
and interferes with produc-
tion.

Design, construction, and
reclamation may be complex.
Requires a relatively level
site.
Source:   SWEC.

-------
expansion  upon  mining, crushing, and processing, which  precludes  all  of the
shale being'returned to .the mine,     • •-• '•-     .--•-..

     Open  Pit Backfill—

     In  many respects,  the  procedures  and  technologies used  in  open  pit
backfilling  would  be  similar  to  those  used  in  surface  landfills.   That
is,  the wastes  would  be transported  to the  pit,  compacted, and  built up
to  the  desired  elevation.    Stable  slopes  must be  maintained  during  the
simultaneous  production  and  disposal  activities   and   during  reclamation,
unless the final contour  is level with the ground surface.

     Runon  and  runoff collection  systems may be necessary  to keep  the fill
and production  areas  as dry as  possible.  Permanent groundwater and leachate
collection  systems  may be impractical because the collected water would need
to be pumped  to the surface and treated for discharge long after the project
is shut down.  Use of  bottom and side liners may be a consideration to reduce
the  interaction between any leachate produced  and  groundwater.   Placing the
wastes in  layers  to restore the geologic and hydrologic  system may also be a
consideration.

     The pit may be filled below, level with, or above the surrounding ground
surface  depending  upon  the  quantity of  the waste  material, site-specific
conditions,  development  plans   for  the  future  and  permit  requirements.   A
major advantage  of  backfilling  the open pit  is  that the original contour of
the  land  surface can  be more closely restored.  Space  requirements for the
production and  disposal  activities  may be a  limiting  factor for backfilling
small pits.

     Hazardous Waste Lagoon—

     A hazardous  waste  lagoon  would be  a  permitted facility  either  on the
project site  or  off site.  It would  likely  consist  of a lined pond designed
to be suitable  for  the containment of hazardous wastes.   The major consider-
ations in  the  design  of such a  pond  would include  a runon diversion system,
an  embankment,   one or  two  impervious  bottom  liners  with  a drained  sand
layer below or  between them,  a  slurry wall beneath the embankment, a surface
seal  layer,  and  provisions  for  reclamation  and  revegetation  (U.S. EPA,
September 1980).

     Once  the lagoon  is  filled to  its  capacity, wick  drains could  be  in-
stalled  to facilitate evaporation,  allowing quicker  consolidation  of  the
sludge.   Gravel  could also be  added to  aid consolidation.   An  impermeable
surface seal  may then  be added on  top  and joined with  the  bottom  liner to
isolate the wastes from the surrounding environment.   The final aspects would
include placing subsoil  and topsoil  over the  seal,  followed by revegetation
of the surface.

5.3.2  Surface Hydrology Control Technologies

     Solid waste  management practices  in the area of surface hydrology en-
tail  the   handling  of surface  waters on and  around the  disposal  facility.

                                     248

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 Specifically,  surface streams  and precipitation  are prevented  from  running
 onto  the waste pile  and  contaminated waters  (runoff, leachate)  are kept from
 mixing  with  the  natural waters.

      The technologies  discussed  below  are  those that are  applicable to  a
 surface landfill,  and they are  summarized  in Figure  5.3-1.   The key features
 of  the  technologies  are  highlighted  in  Table 5.3-3  and  a  more  detailed
 description  with cost data  is presented  in  the text.

      Runon Dj vers 1 on  System—

      A  runcn  diversion  system  will   generally be needed with  any  surface
 landfill  to  prevent  surface  water from flowing  onto the  waste material  and
 becoming contaminated or causing  erosion.    The  system may  include ditches,
 lined channels,  conduits,  and  embankments  arranged to direct  the flow of
 surface  water  around  or away from the waste  material, and energy dfssipators
 to moderate  the impact of the flow.

      The complexity and extent  of the system will vary widely  based on  the
 amount  of  water  to  be diverted  and the  arrangement of  the site.   For a fill
 on  a relatively level  site,  runon  diversion may  require only  a  system of
 channels  and small  embankments  to deflect surface flow away from the  land-
 fill.   In  the case  of a head-of- valley fill  or a cross-valley fill, runon
 diversion  might  include  an  embankment  dam  to  retain  peak flows from  the
 design  storm until  they  can  be passed  through a  conduit beneath or around
 the  fill.    Alternatively.,  the  system may  consist of a conduit  or channel
 large enough to  pass  the design  flow without an embankment  (without reten-
 tion).
         design  of  a runon diversion system will  be influenced by: tne size
of the drainage area and topography which affect the runon rates, retentions,
and  embankment  material   quantities;  the  size,   length,  and  complexity  of
controlled  release  structures and  channeling  systems; and the need for and
extent of  energy  dissipators  and/or drop structures.  For example, the runon
from a site with a large  drainage  area  in  a gently sloping topography could
be diverted quite efficiently  by an unlined canal  or  channel; another site
with small  runoff  rates,  but  highly erodible steep  topography, may necessi-
tate  cost-intensive  lined  channels,  flumes  or conduits,  as  well as  drop
structures or energy dissipators.

     Ryngff_Col1_ecti on System— -

     A runoff  collection   system  usually consists  of  a system  of  channels,
ditches,  and  conduits  arranged to  prevent the  surface water  that has  con-
tacted the  waste material  from  leaving the site.   Another  purpose of  this
system is to drain the surface water from the wastes to limit the erosion and
infiltration potential.   Collected  water may  also  be  used to  meet process
needs,

     The  basic  elements  of this  system are backs! oped benches on the  face
of the landfill  and a means  of collecting  the  water from  the  fill surface.
Generally,   half-round  pipes,  impervious membranes, or  highly compacted  soil

                                   '""249

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RUNON
DIVERSION
SYSTEM


                                            —  WITH RETENTION
                                            !-  NO RETENTION
junrHvt
HYDROLOGY
CONTROL
rcruunr nflicc




RUNOFF
COLLECTION
SYSTEM
                         RUNOFF/LEACHATE
                         COLLECTION PONDS
SOURCE-' SWEC
  FIGURE 5 3- I   SURFACE HYDROLOGY CONTROL TECHNOLOGIES

                            250

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                    TABLL 5.3-3.   KEY FEATURES OF SURFACE HYDROLOGY CONTROL TECHNOLOGIES
Control
Technology
Principle
Runon Diversion
System
  With Retention
  No Retention
Runoff Collection
System
Runoff/Leacnate
Collection Ponds
Uses channels and embank-
ments to prevent surface
water from contacting
the waste material.
Embankment dam holds
peak flows for controlled
release, evaporation, or
percolation into the
ground.

Channel or conduit is
sized to convey peak flow
with no retention of
water.
Drained benches collect
and remove precipitation
falling on the disposal
site.

Lined ponds are used to
retain leachate and
runoff.
Purpose
Reduces erosion and
increases site stability.
Reduces the amount of water
contacting the waste
material, thereby reducing
the potential for surface
water pollution.
Reduces erosion of fill and
infiltration into fill.
Collects water for reuse or
discharge.

Prevents release of contami-
nated waters.
Comments
Reduces the amount of water
contaminated, thereby reducing
treatment costs.
Requirements for the channel
or conduit are greatly
reduced.  Provides flexibility
in the use of the collected
water.

Eliminates the need for runon
retention structures and
associated maintenance.  More
expensive than using an
embankment for retention and
controlled discharge of the
peak flow.

Decreases erosion and
infiltration.  Requires main-
tenance.
Collects water for reuse,
treatment and discharge.
Source:   SWEC.

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or  wastes are used  to  line ditches which collect  the  runoff from the bench
and  the segment  of  the  landfill  slope 'afeoye  it,  as shown in Figures 5.3-2
and 5.3-3.  The ditches empty into central conduits leading to a "containment/
evaporation  pond  at  the  toe of  the landfill." On larger  piles  or in areas
with  extensive  rainfalls, small embankments on  the crest of the landfill or
on  the benches might be used  to retain the runoff  and  thus limit the peak
flows  into tne rest  of the  drainage  system.

     A  problem  with  limiting  the peak  flows using embankments  on the waste
pile  is that the water  ponded  on the  landfill  will  have a greater tendency
to  infiltrate the waste material.   This  increased  infiltration  could have a
detrimental  effect on the  stability of  the  slope  and will somewhat increase
the amount  of  water  which  must be  handled by the leachate collection system
(discussed under  subsurface hydrology).

     The  costs  for a variety of  runoff  collection system designs for surface
landfills were  estimated and  these are  plotted in Figure 5.3-4.  Example 1
used  shaped  benches  with unlined ditches for lateral conveyance and concrete
weir  collectors  and  corrugated  metal  pipe  with  energy  dissipators  for
vertical conveyance.   It  also incorporated some  temporary retention of runoff
on  the  waste pile surface,  which reduced  the  necessary capacity and cost of
the vertical  conveyance  portion  of the  system.  Example 2  used  split cor-
rugated  metal  pipe  to  line  the  collection ditches  to  facilitate  lateral
conveyance,  and  concrete  weir collectors  and corrugated  metal  pipe  with
energy dissipators for vertical conveyance.  Example 3 used the lined ditches
for  lateral  conveyance,  with  a  concrete  flume  and a  stilling  basin  for
vertical conveyance.

     The cost data,  as  can be  seen  in  the plot, are highly dependent on the
particular design, and no single cost curve relationship can be drawn through
the data  points.   Example 1,  which  assumes a more modest design^ defines the
lower  boundary  of the  cost envelope,  and Example 3 defines  the  high end of
the cost envelope.

     The  design  of   the  runoff  collection  system  for  open pit  backfills
would  differ from that  for surface  landfills  because the  runoff  has  to be
pumped to the surface for  its  disposition.  Hence, a system for an open pit
project might consist of a  series of collection  sumps located at the junction
of  the  pit wall  and landfill, from which the  collected water  is pumped to
the  surface and  probably  used for  processed   shale  moistening.  Both  the
sumps  and  pumps  require  only  operating  expenditures,   as  any associated
capital expenditure  is considered to be a part of the mining plan.  The total
annual  operating  costs  for the  sumps  and  pumps  for an open pit mine,  as
described in Sections 2,  3  and 4, were  estimated  to  be $63,000 and $16,000,
respectively, while  the  total  annual  control   costs were  estimated to  be
$64,000  (0.3 cents/bbl   of  oil)  and  $16,000   (0.1 cents/bbl  of  oil).   The
details of cost computation are presented in Section 6.

     Runoff/Leaehate Collection Ponds—

     At the  outlet of the  collection system for surface  runoff,  a structure
is needed to contain the collected water for reuse, treatment and discharge,

                                     252

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             HIGHLY COMPACTED SOIL     HALF-ROUND PIPE
PAVED INVERT SECTION
                                                 COLLECTOR DRAIN DETAIL
SOURCE- SWEC bosedon Colony Development Operation, March  1980
                        FIGURE 5.3-2 TYPICAL  RUNOFF COLLECTION SYSTEMS

-------
          UNDERGROU
NO COLLiCTOft DRAIN PIPE
SECTION
                PLAN
     SOURCE: SWEC based on Colony Development
             Operation, March 1980
                                                    SECTION
                            FIGURE 53-3 RUNOFF COLLECTION AND CHANNELING

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 or  for evaporation.   The structure would consist  of  an embankment across a
 former  stream channel to  form  a pond,-  and 'the pond may fee-lined or unlined
 depending  upon the nature of the  impounded  material.   If a liner is needed,
 it  would  be protected from wave  action,  as  necessary, using rip-rap, a sand
 layer,  soil  cement or similar  materials.  Since the pond would be located at
 the  base  of the landfill, it might also be  used to collect the leachate from
 the  fill.

     Cost  data  for four  examples of  runoff/1eachate  collection  ponds  for
 surface  landfills  are presented  in  Figures 5.3-5 and  5.3-6.   Figure 5.3-5
 presents  the total  cost  of the  embankment  and liner as a  function  of the
 construction   material  quantities  used  in  each   case,  while  figure 5.3-6
 isolates  the cost  of  the liner as a function of  the  liner material quanti-
 ty  only.    Examples 1,  2  and   3  utilized compacted  processed shale  as  the
 liner, while  Example 4 used Mancos Shale as the  liner.   The relatively hign
 cost of using  an  off-tract material  (Example 4)  is evident  in  the figures.
 The  cost  increase  is  incurred due  to the source development,  processing
 and  hauling  of  Mancos   Shale.   Slight  cost  differences  may  be  observed
 between  similar  systems,  and  these  can  be attributed  to  site-specific
 features,  such as  the  arrangement and configuration  of the  embankments  and
 ponds,

     A  runoff  collection  and  containment  system for a  pit  backfilling
 approach differs  from that for the surface  landfills.   Instead of an embank-
 ment and  pond  downgradient  from the landfill, a  series of collection sumps
 and pumps would be  used, as discussed under  Runoff Collection System.

 5.3.3  Subsurface Hydrology Control Technologies

     The  technologies  and practices  in  the area  of  subsurface  hydrology
 involve  the  handling  of  groundwater  seepage  under   a  landfill  to  prevent
 infiltration  of the pile  and the  control  of water from  the  pile  to prevent
contamination  of   the  groundwater.   The  technologies,  as  summarized  in
 Figure 5.3-7,  are  applicable to  a surface  landfill,  and their  key features
 are  presented  in  Table 5.3-4.    Detailed  descriptions of  the  technologies,
along with cost information, are presented below.

     For open pit  backfilling,  subsurface  hydrology  control may  consist of
aquifer dewatering.   Since this  operation would  be an  integral part  of  the
mining plan, additional costs for backfilling would not be incurred.

     Liners and Covers—

     A  liner  is essentially a  material with  low water  permeability that is
 installed at the bottom of a landfill  or pond.  Its purpose is to prevent the
contaminated  waters from  the wastes  from mixing  with the groundwater.   It
also prevents  groundwater from  infiltrating  the bottom  of the  landfill.

     A cover is also made up of a low-permeability material  and it is used as
a surface  sealer  for the landfill.  It prevents the runoff from infiltrating
the  pile,   thereby   reducing  the  quantity  of the  leachate  and  minimizing
stability problems.


                                     256

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O

4A>
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     O
     O
     J-

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     <
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     lu
     X
                                J_
                                           O
                                        _L
                    O.i          0,2          0.3          0.4


                CONSTRUCTION MATERIAL VOLUME ,  106 yd3
                                                                0.5
NOTES:


  All Examples include cost of embankments and pond liners.


  Examples 1, 2 & 3 Include pond liners constructed of processed shale.


  Example 4  includes  a  liner  constructed  of Mancos  Shale  (off-tract
  material);  cost is increased due to processing  and transport.


  See  Section 6.2.3 for  details on  the  solid  waste  management cost
  methodology.
SOURCE:   SWEC
                  FIGURE 5.3-5  RUNOFF/LEACHATE POND COSTS
                                  "  257

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       1000
       800
       600
    V)
    O
    O
£L
4
O
       400 -
       200 -
                                O,
          0                      (00                     200

                       LINER  MATERIAL  QUANTITY,  I03 yd3



NOTES:

  Examples 1, 2 & 3 include liners constructed of processed shale.

  Example 4  includes a  liner  constructed  of  Mancos Shale  (off-tract
  material); cost is increased due to processing and transport.

  See  Section 6.2.3 for  details  on  the  solid waste  management  cost
  methodology.
SOURCE:   SWEC
               FIGURE 5.3-6  RUNQFF/IEACHATE POND LINER COSTS
                                     258

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LINERS
AND
COVERS



    SUBSURFACE
    HYDROLOGY
    CONTROL
    TECHNOLOGIES
 LEACHATE
COLLECTION
  SYSTEM
                                             I— SYNTHETIC

                                                 OFF-SITE
                                                 NATURAL MATERIAL

                                                 COMPACTED
                                                 PROCESSED
                                                 SHALE
                         GRQUNDWATER
                         COLLECTION
                         SYSTEM
SOURCE^
    FIGURE 5.3-7  SUBSURTACE HYDWL06Y CONTROL TECHNOLOGIES

                             259

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                        TABLE 5.3-4.  KEY FEATURES OF SUBSURFACE HYDROLOGY CONTROL TECHNOLOGIES
     Control
     Technology
                  Principle
Purpose
Comments
     Liners and Covers
                  Low permeability layer
                  severely restricts
                  seepage.
ISi
en
o
       Synthetic
Off-site Natural
Material

Compacted
Processed Shale
     Leachate
     Collection System
     Groundwater
     Collection System
                  Collects leachate at the
                  base of the landfill and
                  drains Into the pond.
                  Collects groundwater
                  seepage beneath the
                  landfill and drain.
Reduce formation of leachate.
Prevent contamination of
the groundwater by leachate
from the fill.  Prevent
grtfundwater invasion of the
fill, which might produce
instability and additional
leachate.
Reduces groundwater con-
tamination by effectively
removing the leachate.
Prevents loss of fill
stability due to saturation.

Prevents loss of fill
stability due to buildup
of groundwater pressure
beneath the liner.
Provide the lowest permea-
bility but have the highest
cost.  Long-term durability
is questionable.

High cost.  Advantage is
long-term durability.        '

Lowest cost.  Small particles
may infiltrate adjacent
drains.  Advantage is long-
term durability.

Collected water may be used
for process needs.
Collected water may be used
for process needs.
     Source:   SWLC.

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     There are  several  materials which can be  considered  for the liners and
covers.   Probably  the least expensive material would  be compacted processed
shale.   It has  the  advantage  of  being  readily  available  at the  site.   A
similar  Dining  could  be made of processed shale or clay from off site if the
quality  of the processed  shale from the site  is  unsuitable;  however, these
options would be  relatively expensive due to the  extra handling and hauling
costs.   There   is  also  a  variety  of synthetic liners  which could  be  con-
sidered.   High-density  polyethylene,  for  example,  would range  upward from a
price  simi'ar to  that for the off-site materials,  depending upon the thick-
ness  used.   This  would make  it  very  expensive  for use  in a processed shale
landfill  and  it may have questionable long-term durability.   Another option
that  could be  considered,  particularly  for a hazardous waste  lagoon,  is
simply  a  combination  of a  synthetic liner  with  one  of  the other liners
mentioned above.

     Linings made  of  natural materials will  dry  and crack  if  they  are  left
exposed to the weathering elements for long periods.  Therefore, if a pond is
not  expected  to remain  at  a relatively consistent level, a synthetic liner
mignt  be  considered.   Hazardous waste lagoons  sometimes have  double liners;
howevers  the  catchment and evaporation  ponds presumably will  need  only one
liner  or no liner  since they will  not  contain hazardous  materials.   If  a
combination of  two liners  is used,  the  synthetic  liner may be  placed above
the  latural  material   liner to  prevent  its drying  and cracking.   In  cases
where  a.  synthetic  liner is  used, it  should be  covered by a  layer of sand or
g»*ave"  to protect  it  from  traffic and wave .action.   Also, because  of the
weight of the  fill and because  the  fill  may be placed  above  an  underground
mine,  the  liner must  accommodate a certain amount  of subsidence and stretch-
ing and still  function properly.

     Tiie  cost  of  liners and  covers  depends  on  the  quantity  and  type  of
material  used.   Figure  5.3-8  presents the  costs for three separate liner and
cover  systems  for  surface  landfills.   Examples 1  and  2 assumed  the use  of
highly  compacted   processed  shale  for construction  of the  liners, while
Example 3  assumed  the use  of  Mancos Shale.  The  compacted processed  shale
represents the  lowest  material  cost  option, while Mancos  Shale is a  more
expensive  natural   material  since  it has  associated  source  development,
processing and  hauling costs.   The cost curve  in  the  figure may be  used  to
obtain  an  "order-of-magnitude"  estimate   of   liner  cost  utilizing  highly
compacted  processed shale as  the construction material.  The  estimated  cost
fa**  other liner materials would fall  above this curve to a degree  which  is
dependent on the source development,  processing, and hauling  costs associated
with delivering these  materials  to the disposal  site.

     LeachateCol 1ection System—

     The  purpose  of a  leachate  collection  system  is to collect  water which
infiltrates a  landfill  and drain  it efficiently  in  order to  prevent  the
saturation of the landfill  and contamination of  groundwater beneath the waste
p":is, as well  as to facilitate handling of  the leachate.

     Leachate collection systems typically  consist of  blankets,  or zones,  of
highly  pervious sand  and  gravel.    In some  cases  this is augmented  with

                                     261

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             25J~
          g 15
          O
          ca
          z
          o I0
          a

NOTES:
                           4           8           12

                         MATERIAL QUANTITY,  10s yd3
16
  Examples 1 & 2 utilize 3 feet of highly compacted processed shale  for  liner
  paterial.

  Example 3 utilizes 3  feet  of  compacted Mancos Shale (off-tract material)
  for liner  material;  cost  of  processing  and  hauling this material makes
  this option more expensive than the others.

  The costs indicated are cumulative for the project life.

  See  Section 6.2.3 for  details on  the  solid waste management  cost
  methodology.
SOURCE:   SWEC
                          FI6UIE 5,3-8  LINER COSTS
                                     262

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 embedded  perforated pipe  to increase the  capacity,  and it may also  include
 collector  ditches where  the  system  emerges  onto  a  broad  level  area.  The  sand
 or  gravel  layer would be  located just above the  bottom liner and it may  be
 wrapped  in filter  fabric  or surrounded  by carefully graded sand filters  to
 prevent  infiltration  by  the processed shale  particles.   In either case, the
 collection system  should be designed  so  that movement and settlement do not
 -esuit  in  discontinuity  of the  gravel   layer  or  impede drainage  to the
 collection or  evaporation  ponds.

      Tne  costs  for four  distinct   leachate  collection  systems  for  surface
 landfills  were  estimated  and   these  are  presented  in  Figure  5.3-9.    In
 Examples 1  and 2,  due  to  the  valley shape  of  the disposal  site,  only the
 drain material  was necessary  for   the  collection system.  The  leachate  in
 ~hese two  cases was  drained in  the runoff/leachate  collection pond  located
 downstream  from the landfill.   In   Example 3, a toe  ditch was necessary  to
 collect the  leachate  due to the  presence of the broad valley area at the toe
 of  the  landfill.   The  ditch was  then drained into the common runoff/leachate
 collection  pond.   Example  4  also required  a toe ditch which was drained  into
 a  leachate collection  pond, while the  runoff  was  impounded  separately  in
 evaporation ponds  on  the waste pile  surface.  Examples  3 and  4 required the
 same  drainage  material   quantity.    The  cost  difference  between  the  two
 examples is due to the  inclusion of a separate collection pond in Example  4.
 Data  point 5  on the figure  represents the cost of drainage material only for
 Examples 3  and 4.   The cost of the toe  ditch may be obtained by subtracting
 data  po^'nt 5 from 4.

      The costs for similar  systems should be proportional  to  the volume  of
 drainage material  used,  but  slight  deviations may be  encountered  due to the
 site-specific conditions.

      For open  pit  mining and backfilling operations,  some leachate is likely
 to  be collected in the  pit along  with  the  runoff  and  it may be  used  for
 processed shale moisturizing.  Controlling the leachate after the backfilling
 operations  have been  completed  would not be  practical.   Therefore,  emphasis
 snou1d be  placed on minimizing  the  production of  leachate.  Some  considera-
 tions  in   this  regard  would be  to reduce the  overall  permeability  of  the
 backfilled mass  and to minimize penetration of  surface  water  by  utilizing a
 cover.

     Grgundwater Col1ection System—

     The purpose  of a groundwater  collection system is  to relieve  pressure
 from the seeps and springs  beneath a landfill.  This  situation  is most likely
 In the cases of cross-valley or  head-of-valley landfills.  The  system will be
 essentially identical  to the leachate collection system except it  would be
below the bottom liner rather than above  it.

     Groundwater collection  systems typically consist  of blankets  or  zones
of  pervious  sand and gravel  drained beyond  the perimeter of  the  landfill.
This  fpay be augmented  with embedded perforated pipe to increase capacity  and
with collector ditches.   The  sand or gravel  layer would be lined as necessary
with  filter fabric  or  surrounded  by properly graded sand  filters  to prevent


                                     263

-------
       100
     CO
     o
     o
    h-  50

    tC.
    U!
    CL
    O
    h-
    o
    Ui
NOTES:
                     04



                     03
O,

                                5,000                    10,000

                      VOLUME OF DRAIN MATERIAL, yd3
  Examples 1 & 2  require only  drain material due  to the  valley shape;
  leachate containment is performed by the contaminated runoff catchment pond
  of which the leachate is a negligible component.

  Example 3 includes  cost  of toe ditch for collection due to  broad  valley  at
  waste pile toe;  containment is also by  the  contaminated runoff catchment
  pond.

  Example 4 includes  toe ditch  collection and separate  containment pond
  because, in  this case,  contaminated runoff is contained in  evaporation
  ponds on the waste pile surface.

  Example 5 includes only the drain material cost of Examples 3 & 4.

  The costs indicated are cumulative for the project life.

  See  Section 6.2.3  for  details  on the  solid   waste  management  cost
  methodology.
SOURCE:   SWEC
                   FIGURE 5.3-9  LEACHATE COLLECTION COSTS
                                     264

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infiltration  of  smaller particles from adjacent  materials.   The system must
also  be  designed to  maintain its continuity  despite  possible subsidence or
setfement of the landfill.

     The  costs  of two  groundwater collection  systems  for surface landfills
were  estimated  and these  are plotted  in  Figure 5.3-10.   Both  systems used
gravel  blankets   under   the  pile  to  collect  the  groundwater  seepage.   In
Example 2  the gravel  blankets were  used  only above the  seeps  and springs,
while  in  Example 1  an   extensive  network  of  the  blankets  was  considered,
resulting  in a  higher  cost.   The cost of the  collection system  should be
proportional to the quantity of the drainage material used.

     The  use of  a groundwater collection system under an open  pit backfill
does  not  appear  practical,  especially in areas like Tract C-a where a large
amount of groundwater exists.   A control over the groundwater flow in the pit
during active operations is  achieved  by  dewatering  the   aquifers,  which is
performed  to  keep  the pit as  dry as  possible to facilitate mining; hence, it
is net considered  a  solid waste management technology.   At the completion of
the  project, the  dewatering   wells  are shut  down and original  groundwater
levels are reestablished.

     Some conceptual  controls, such as hydrologic barriers and bypass, may be
applied  to reduce  the groundwater interaction with  the backfilled material.
These are discussed in the MIS-Lurgi  PCTM.

5.3,4  Suriface_Stab11 Ization Technologies

     The  activities  and  technologies  in the  area of surface stabilization
involve  the  treatment  of the disturbed  land  surface and the  problems  as-
sociated  with the disposal  and  reclamation  of  the waste material.   These
technologies  are  outlined  in  Figure 5.3-11   and  their  key  features  are
presented in Table 5,3-5.

     Dust Control—•

     The  purpose of  dust suppression  is to  limit  pollution from  airborne
dust,  particularly  during  the placement  of the  waste material  in  a  fill.
Dust  suppression can be accomplished  by  spraying the haul  roads and  fill
surface with  water or  a combination of water and a chemical binder.   Haul
roads could, alternatively, be paved.

     Use  of  water  alone  for dust  suppression  would  necessitate  repeated
aoplications, often more than one per day, to  be effective.  Water with  a
chemical   binder  should necessitate  only  a  few applications  to  a  given
surface to stabilize  it for a year or more unless it receives heavy traffic.
Finally,   vegetation would provide perhaps  the most permanent means  of dust
control,  but  this would not be practical except  on  surfaces  which would not
be disturbed for  a number of years.

     The dust suppression  technology  assumed in developing the cost data for
two examples  consisted  of  routine  spraying of  the processed  shale  pile with
water and  additives  to  minimize -the,.,dust  generated  tiue  to the wind  and  the

                                     265

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          w
          O

          •«#.  4
           o
           o
           e
           u
           0.
           o
           o
           u

           £  2
           Q
                                                          ff,
                    /
                     /
                      /
                          I
                                     I
                    0.1    0.2    0,3    0.4    0.5    0.6   0.7    0.6


                          VOLUME OF DRAIN MATERIAL, I06 yd3
0.9
NOTES:


  Examples 1 & 2  consist of  gravel  blankets for  collection of groundwater

  from springs  and seeps; extent  of blankets dictated  by  the  existence and

  extent of such conditions.


  The costs indicated are cumulative for the project life.


  See  Section 6.2.3  for details  on  the  solid  waste  management  cost

  methodology.
SOURCE:  SWEC
                 FIGUEE 5.3-10  GROUNDWATER COLLECTION COSTS
                                     266

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                            DUST
                           CONTROL
   WATER AND
   BINDERS
   PAVE HAUL
  '

<— REVEGETATtQN
aunrm^c
STABILIZATION
CONTROL
TECHNOLOGIES




EROSION
CONTROL



                                             i— MULCH
                                             <— REVEGETATIOM
                         STABLE
                            DESIGN
SOURCE' SWEC
     FIGURE 5,3-II   SURFACE STABMJZATIQN TECHNOLOGIES

                           267

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                      TABLE 5.3-5,  KEY FEATURES Of SURFACE STABILIZATION TECHNOLOGIES
Control
Technology
Principle
Purpose
Comments
Dust Control
  Water and
  Binders


  Pave Haul Roads
  Revegetation
Erosion Control
  Mulch
  Revegetation
Stable Slope
Design
                           Prevents or  limits dust
                           pollution  from wind blowing
                           across exposed surfaces or
                           from vehicular traffic.
Fluid sprayed on the
surface binds the fine
particles together.

A hard surface on the
haul road prevents
generation of dust by
vehicular traffic.

Vegetation prevents dust
caused by wind.
                           Simplifies reclamation,
                           prevents blockage of the
                           drains, and prevents contam-
                           ination of surface waters by
                           eroded material.
Various materials are
placed on the slope to
limit erosion.

Plant growth is started
on the slope to limit
erosion.

Design slope to minimize
stability problems and
maintenance.
Makes erosion control,
revegetation, and drainage
easier.  Restricts waste
material to a definite,
predefined area.
                               Well  developed  technology
                               that  is  commonly  used  in
                               mining operations.

                               Should improve  traffic
                               conditions on the road.
                               Not useful  in areas with any
                               equipment traffic or where
                               the surface is being disturbed
                               by other activities.
                               Quick and easy to accomplish
                               but  is only a temporary
                               measure.
                               Permanent control but slow  to
                               achieve.
Source:   SWEC

-------
waste  hauling and  placement activities.   Depending  on the  processed shale
characteristics, this  operation could either  be  continuous or intermittent.
The  cost curve  in  Figure 5.3-12 is  based on  the  assumption that  both the
manpower and equipment operation requirements are continuous.  Theoretically,
these requirements could differ depending on the rate of waste production and
the  surface  area of the particular waste pile; however, both cases estimated
were assumed to be equivalent in this respect.

     Erosion Control—

     The purpose of erosion control  is to keep the waste material in place so
that the surface drains remain free flowing, the slopes remain stable, eroded
material does  not  pollute surface streams, and reclamation and  revegetation
efforts are  not  hampered.   Some means of limiting erosion include contouring
the  surface  with  short and  gentle  slopes,  providing  for drainage  of  the
slopes  at  frequent  intervals,  using mulch or filter  fabric to  dampen  the
impact  of  water flow,  and  revegetating  the completed   faces.   Of  these
measures, grading  and drainage  are  essential, take effect immediately,  and
last as  long as  they are maintained.  Mulch or filter fabric also provide a
quick control, but  they  are of a temporary nature.   Revegetation provides a
permanent control,  but it is generally slower to take  effect.

     A  major  consideration in  planning  erosion  control  measures   is  tne
severity of  rainfall in the  area.   A  large  proportion of the water  from a
high-intensity  rainfall  would  run  off  the  surface,  thus  increasing  the
erosion.

     Reclamation and  revegetation  consist  of  placing a subsoil  and  topsoil
strata  of  sufficient -thickness to  support vegetation, and then  seeding  the
disoosal area with native or introduced species.   The^greatest contributor to
the  nagnitude  of cost for  this control  technology is the thickness  of  the
soil strata  and  the costs  associated with the  delivered soil  material, i.e..
tne  source   development,  processing  and  hauling  costs.    Soil  and  subsoil
stripped from  the disposal  site may not be available  in  sufficient quantity
to meet the  reclamation needs.   The cost curves presented  in Figure 5.3-13
illustrate   fi^e  examples.    Examples 1  and 5 included  2 feet  of  subsoil
(sane-gravel  material) and  30 inches  of  topsoil,  both of which were  brought
in from off-site sources  and thus  had additional  costs involved.   Examples 2
and 3 alsb  used  the same  thicknesses,  but the  soils were available  on  the
site.   Example 4 used  no   subsoil  and  only  6 inches of  topsoil which  was
available on the  site;  therefore,  additional material costs were not  in-
volved.   All  examples included  the  cost of revegetation.   It is  evident from
the figure that  the cost  of erosion control can vary  significantly depending
or» the  factors considered; however,  in  any category,  the costs  are  propor-
tions!  to the area reclaimed and revegetated.

     Stable Slope ...Design—

     The purpose of designing  the  slopes to be stable  under  prevailing
conditions   is to  minimize  the maintenance of the  landfill and  to  avoid
hampering of the reclamation  and revegetation efforts.  The  techniques  used
in designing stable slopes are  a well  developed  part of soils  engineering.

             " " '   -               ,269        ....•-••••••--

-------
         50
         40
     «e
      O
      0}

      8  30
      —

      <
      E
      u
      &
      O  20
      O
      LlJ
      cc
         10

                             I
                                               I
                             10                20


                             PROJECT LIFE,  YEARS
30
NOTES:


  Example 1  assumes a  30-year project  life,  while Example 2 assumes  a
  20-year life.


  The Lurgi-Open Pit Case Study has a project life of 20 years.


  The costs indicated are cumulative for the project life.


  See  Section 5.2.3 for  details  on  the  solid waste  management cost
  methodology.
SOURCE:   SWEC
                      FIGURE 5.3-12  DUST CONTROL COSTS
                                     270

-------
          (0
          O
              60
             50
h-
OT

8  40

O
2


<  30
K
uJ
Q.


°  2°
O
Ul
cc
5  10
                                             X
                                               X
£L
                                        i
O
 I
                500         1^300         1,500


                  RECLAIMED AREA, ACRES
                                                      i
                                                              2,000
NOTES:


  Examples 1 & 5  include  2 feet of subsoil and  30 inches of topsoil, both
  obtained off site.


  Examples 2 & 3  include  2 feet of subsoil  and 30 inches of topsoil obtained
  on site.


  Example 4 includes  no subsoil  and  only 6 inches of topsoil  obtained  on
  site.


  The costs indicated are cumulative for the project life.


  See  Section 6.2.3 for  details  on  the  solid  waste  management  cost
  isethodology.
SOURCE:   SWEC
              FIGURE 5.3-13  RECLAMATION AND REVEGETATION COSTS
                                     271

-------
To  arrive at the most  advantageous slope,design, other factors besides basic
stability,  such as erosion, ease of placement, reclamation "and revegetation^
must  be  considered.   However,  the  physical  characteristics  of  the  waste
material  will  dictate  a  limiting  slope  angle.    The  costs of  achieving a
stable  slope design are incidental  to  the  placement and revegetation of the
fill material;  hence, additional costs  are not  involved.

5.3.5   Hazardous Waste  Control Technologies

     The  control  of hazardous waste involves  its  permanent impoundment in a
permitted disposal  facility.   This  facility may be  built on the project site
or  the  wastes may be sent to an existent, off-site permitted facility.  These
options are  outlined in Figure 5.3-14 and their key  features are presented in
Table 5.3-6.

     On-site Disposal—

     Hazardous  waste lagoons are  a well developed and accepted approach to
solid waste  management.  They are actually an  integration of several control
technologies discussed  in  Sections  5.3.2,  5.3.3 and 5.3.4.  Some  of the in-
cluded  technologies would  be  an embankment  surrounding  the  lagoon, a runon
diversion system,  one  or two bottom liners, a  surface cover, reclamation and
revegetation, and monitoring.

     There are  certain  advantages to building  a  hazardous  waste facility on
site.   This  option automatically assumes  segregation  of  the  hazardous and
nonhazardous wastes and,  hence,  their separate  disposal.   An  advantage of
this approach  is  that  much of the material necessary for the lagoon would be
available  on site  or  it  already would have  been  brought in for  the non-
hazardous  waste landfill.   Furthermore,  transport  of  the  wastes  beyond the
property  boundaries will  not  be required.   A significant advantage  may be
that the  producer of the hazardous wastes (the  oil shale developer) will have
complete  control over the disposal of the wastes.

     There   are  also   certain  disadvantages   to  on-site  disposal  of  the
hazardous  wastes.   To  be  efficient in evaporating  the  liquids  and consoli-
dating  the  sludge,  the  lagoon should be located  preferably on a level site,
which may not  be  readily  available.    Rugged,  uneven terrain  would increase
the cost  of  site  preparation, runon control  and  reclamation.   There is also
a possibility  that  the lagoon  may interfere  with  other  ongoing  activities
and the resource recovery.

     Off-site Disposal-°

     0 f f - s ite exlstent  f ac11ity.   This  would  be an  already existing facility
where the wastes  can_ be disposed of  on an "as needed" basis.   A  payment is
required  for every  shipment,  but the cost may  be lower than that of building
and  maintaining a  new  facility.   Also,  a significant  amount of  time and
effort  involved" in  the  licensing, design, and  construction of a new facility
can be  saved.   The capacity and distance of  the  existent facility must also
be considered in selecting the disposal approach.
                                     272

-------
     HAZARDOUS
     WASTE
     CONTROL
     TECHNOLOGIES
                             ON-SITE
                             DISPOSAL
                             OFF-SITE
                             DISPOSAL
 SOURCE^  SWEC
FIGURE 5.3-14  HAZARDOUS WASTE CONTROL TECHNOLOGIES

                       273

-------
                     TABLE 5.3-6.   KEY FEATURES OF HAZARDOUS WASTE CONTROL TECHNOLOGIES
Control
Technology          Principle                  Purpose                        Comments

On-site Disposal    Dispose of hazardous       Dispose of hazardous wastes    The oil  shale developer has
                    wastes in a lagoon         produced by processing of      complete control  of hazardous
                    established on site.        oil  shales.                     wastes produced by the
                                                                              facility.

Off-site Disposal    Establish lagoon off       Dispose of hazardous wastes    Provides a broader selection
                    site or pay for disposal    produced by processing of      of sites,  although the waste!
                    in existing permitted      oil  shales.                     must be transported.   Poten-
                    facility.                                                  tially less involvement with
                                                                              the wastes.


Source:  SWEC,

-------
                                  SECTION 6

                           POLLUTION CONTROL COSTS
     This  section provides an analysis of  estimated pollution control costs
for  the Lurgi-Open  Pit  case study  analyzed in  this  manual (see Sections 2
and  3  for  a  description  of the  case study).   Section  6.1  presents fixed
capital  and direct annual  operating costs  for  each  control and explains how
they were  developed.  These costs are referred to as the "engineering costs."

     Section 6.2  explains  the cost analysis methodology used  to develop the
total  annual  and per-barrel pollution control  costs.  These  costs combine
capital  and annual operating costs, allow for taxes, and incorporate a return
on investment.  This is an approach similar to that which a private developer
mignt use  to determine costs or assess the economic feasibility of a project.
Section  6.2 also  aetails  the economic assumptions that are incorporated into
the  calculation of total annual control costs.

     Section 6.3 presents estimated total  annual control costs and per-barrel
costs for  each  control  using a set  of  standard economic assumptions.  These
costs are  assembled  into  total  per-barrel costs  for  air and water pollution
control  for  the  case  study examined  in  this manual.   This  section  also
examines  the  sensitivity  of the  per-barrel control  costs  to a  series  of
changes  in the engineering costs and economic assumptions.

     Section 6.4  provides  more  detailed information supporting Sections 6.1,
6.2  and  6.3.   Section 6.4.1  provides  the algorithms that  were  used  to
determine  total  annual  control  costs  and per-barrel  control  costs,  and
Sections 6.4.2 and 6.4.3 provide examples, respectively, of fixed charge rate
calculations and cost levelizing calculations.

     Section 6  uses  a  large  number  of cost and economic  terms.  The inter-
re"! aticnships among  the  more important  of these  terms  is illustrated  in
Figure 6.0-1.   Each  term  is  explained  when it  is first used in the  text,  but
the  reader may  find it  helpful  to  use this figure  to provide  an  overview
while  reading  the  various  sections.   In  addition,  Table 6.2-4,  presented
later  in  this  section,  indicates  the estimated  relative magnitude of  the
components of per-barrel control cost  for a typical  major  pollution control,

6.1  ENGINEERING COST DATA

6.1.1  Bases of  Engineering Cost Data

     Throughout  this manual  a distinction  is made between  capital costs  and
annual  operating  costs.  There are  two types of capital cost,  fixed capital


                                   - 275

-------
ENGINEERING COSTS
rsj
~j
cr>
DIRECT ANNUAL
OPERATING COSTS
(DOC)
« Maintenance
• Operating Supplies
• Operating Labor
• Utilities
- Cooling Water
- Staam
- Electricity
(Tables 6 1-1,6 1-2)

SOLID WASTE
MANAGEMENT COSTS
(Year-by-Year Cash Flows)
(Table 6 1-3)

FIXED CAPITAL
COSTS (FCC)
(Tables 6 hi, 6 1-2)

<^

COST ANALYSIS METHODOLOGY
INDIRECT ANNUAL OPERATING COSTS
(IOC)
» Annual Property TDK and Insurance
Allowance (TIA = f [FCC J)
» Annuol Extra Start-up Costs
( ESC = f [FCC, DOC])
» Annual By-product Credit (BP,
Tobies 6 3-3,6 3-4)
• Annuol Severance Tax Credit
(STC = f [FCC,TIA,eSC,BP]>

DOC
DOC
BARRELS PER
STREAM DAY
(BPSD)

IOC ^
TOTAL
	 ,, ANNUAL
OPERATING
COST
	 ,. (TOC=DOC + 1OC)

,-"-"" •—— 	 — 	 ' 	
— ~-^ FCC


BPSD ^



PER- BARREL
CONTROL COST
(CPB * TC -f
BPSD X 328.5*)

TOC


FIXED CAPITAL CHARGE RATE
(RF- ft Economic Assumptions])
FCC



WORKING
CAPITAL "" 	
(WC - f C DOC, BP1 ) W°RKING CAPITAL CHAR6E RATE
{RW- ! [Economic Assumptions])

RF— »>


RW ^

TC
TOTAL
ANNUAL
CONTROL
COST
(TC*CC+TOC)
j

CC

TOTAL
ANNUAL
CAPITAL
CHARGE
(CC
*
RF X FCC
+ RW X WC) ,

 * 328,5 is the number of operating days in a normal year
SOURCE DRI
                    FIGURE 60-
                                      Note-  f means "a function of"
INTERRELATIONSHIPS  AMONG VARIOUS  COST  AND  ECONOMIC TERMS

-------
and  working capital,  and  two  types  of annual  operating  cost,  direct and
indirect.

     Fixed  capital  is  investment   in  construction  and  equipment,  whereas
working  capital  is money  that  is  required to operate  the plant,  e.g., that
which is tied up in inventories.

     Direct annual  operating costs  include  maintenance,  operating supplies,
operating  labor  and utilities  costs.   Indirect annual  operating  costs com-
prise additional  annual costs, i.e., property tax and insurance, an allowance
for  extra  start-up  costs,  a credit for severance tax not paid and by-product
credits.

     Section  6.1  only  considers   fixed  capital   costs   and  direct  annual
operating  costs.   Working  capital  and  indirect  annual operating  costs are
considered in Section 6.2.

     Assumptions Used to Develop Costs—

     All  costs  are  expressed in mid-1980  constant dollars.   The  following
data apply  to air  and  water pollution control costs.   Solid waste  management
costs were  developed on  the basis  that these  activities  are contracted out,
sines they are all  construct!on-type activities (see discussion later in this
subsection),

     Fixedcap1tal  costs.   Fixed  capital  costs  are  of  'the  "preliminary
estimate"  category.   Physical  plant costs  for a1r~ emission  controls  were
developed by Stone  and Webster  Engineering Corporation (SWEC)  and  for water
pollution  controls  by  Water Purification  Associates (WPA),   Actual  vendor
cuotes were used for major items of equipment; costs for other equipment were
obtained from data files  maintained by SWEC and WPA.  Total  pbysica'  plant
costs were  developed from  the  equipment costs by  adding  appropriate  allow-
ances for the following:

     ®    Site preparation, excavation and foundations

     *    Concrete  and  rebar
     ®    Support structures
     *    Piping,  ductwork, joints,  valves,  dampers, etc.
     •    Duct and  pipe insulation

     »    Pumps  and blowers
     »    Electrical
     *    Instrumentation and controls
     •    Monitoring equipment
     »    Erection  and  commissioning
     »    Painting

     *    Buildings.


                                     277

-------
      To  arrive at  the total fixed  capital•cost,  the following factors were
 added to  the physical  plant  cost:        - .  '  '

      Engineering  and
      construction overhead;        25% of physical plant cost.

      Contractor's fee:             3% of bare module  cost {physical plant
                                   cost plys engineering and construction
                                   overhead).

      Contingency:                  20% of bare module cost.


      For  an explanation  of  this method  of developing  estimates  of fixed
 capital  costs, see Uhl  (June  1979).   A  20% contingency  factor  was chosen
 because  there  are  only  pilot  plant  data  for  the  Lurgi  retorting process.

      It  is considered  that  the  accuracy  of these  cost  estimates is within
 ±30 percent.   Although  the  accuracy  of  a preliminary  fixed  capital  cost
 estimate  is  normally  regarded  as  ±20 percent,  uncertainties  about stream
 magnitudes  and  composition  decrease  the  accuracy  of  these  estimates  to
 ±30 percent.

      Directannual  operating costs.   There are two  components which make up
 the  total annual  operating  cost.   The direct  annual  operating  cost can be
 regarded  as  the  basic  (or engineering)  cost,  while calculation  of the in-
 direct annual operating cost makes some adjustments to this cost.  By-product
 credits  are included  in the  indirect  annual  operating  cost.  Data  on the
 bases  of  direct  annual operating costs are given below, while the bases of
 indirect  annual operating costs are  outlined in Section 6.2.

      Direct annual  operating costs are  made up of the following components:

      •    Maintenance

      •    Operating supplies

      *    Operating labor

      •    Utilities

          —Cooling water

          —Steam

          --Electricity.

     Maintenance  costs  include  maintenance  labor  and  replacement  parts,
consumables used for maintenance, etc.

     Operating  supplies are  consumable  items  (such  as  chemicals)  used  in
the regular  operation of  the  control  (as  opposed to  use  for maintenance).
                                     278

-------
     Operating  (and  maintenance)  labor  is  costed  at  $30/hr.   This  is a
"loaded" rate, meaning that it incorporates some overhead-type costs tc avoid
developing them separately.  The  rate is made up as follows:

       A.  Wages for direct labor                    $11.00/hr

       8.  Fringe benefits (45% of A)                  4.95

       C.  Field supervision (15% of A + B)            2.40

       D.  Overhead (50% of A + B + C)                 9.20

       E.  General & administrative charge
           (9% of A + B + C + D)                       2.45

               Total                                 $30.00/hr


     In  mid-1980,  examination of  union  agreements showed  that  oil refinery
direct  operating  labor  was  receiving  approximately  $10/hr  in  Colorado.
However, it  is  anticipated that when oil shale development occurs, this will
bid up  local  labor rates,  so $ll/hr, which was used for  the oil  shale PCTMs,
is  a  reasonable   value.   The  multiplier  factors,   used to  arrive  at  the
"loaded'1  labor  rate  of  $3Q/hr,  were  suggested  by  SWEC  based  on  project
experience in the western U.S.A.

     Cooling water  is costed  at  11.3 cents per 103  gal  circulated (3f/m2).
This is only a charge for the use of the cooling tower.  The cost of treating
the makeup water is included under water pollution control.

     Drocess steam is charged at $3.00 per million Btu.

     Electricity is charged at 3 cents per kW-hr.*

     There is no  contingency  factor in the direct annual operating costs for
air and water pollution controls.

     So"Hd Waste Management Costs--

     Son' d waste management costs  in the form of year-by-year cash flows were
developed  by SWEC  using  company  cost  data  files.    They  include the  same
engineering  and construction  overhead,  contractor's  fee,  and  contingency
factor (20%) as the  fixed  capital costs  discussed earlier.   The  use of a 20%
contingency factor is appropriate  since  all  solid waste management costs are
of a construction  nature,  subject to uncertainties similar  to those inherent
in fixed capital  costs.
* To be consistent among the three oil  shale PCTMs,  electricity is charged at
  3 cents per  kW-hr,  whether purchased  or generated on  site.  This  figure
  represents a  compromise  between the  value of  electricity  sold by  plants
  that will  have surplus on-site generated power and the higher cost  of power
  purchased from a utility.   . ,.  >-t    ^_,


                                  " " 279

-------
 6.1.2  PetalIsof Engineerlng Costs

      Tables 6.1-1 and 6.1-2  present  details  of-the fixed capital  and direct
 annual  operating costs for each  air  and water pollution control.  The oper-
 ating costs relate to a year  of normal  operation,  i.e.,  full  production.  For
 the  start-up period^ direct  annual operating costs  are  modified  to an appro-
 priate  level  by the cost  analysis methodology.

      Table  6.1-3 details  the  solid waste  management costs  on a  year-by-year
 basis.  These costs are allocated to  fixed capital or direct  annual operating
 categories   in  Section 6,2   (Table 6.2-3).    Insufficient   information  was
 available  to develop a complete  plan for solid waste management operations.
 Consequently,  the solid waste management costs  presented here are for certain
 items only and  do not represent  the total pollution  control cost for solid
 waste.

 6.2   COST ANALYSIS METHODOLOGY

      In  the cost  analysis,  engineering cost data are  transformed into two
 primary  measures—the total  annual  pollution  control   cost  and  the control
 cost  per  barrel of  shale oil.   These  costs  incorporate both  capital  and
 annual  operating costs and consider  project  timing, taxes, and the necessary
 return on investment.

 6.2.1 Overview  of Cost AnalysisMethodology

      In private  industry, one of  the most widely  accepted  methods of evalu-
 ating the  economics of a project is  the discounted cash flow (OCF) approach.
 Using this  approach,  a  project  must  be  able to  demonstrate   that  it can
 produce  some established minimum rate  of  return  on investment—known  as  a
 "hurdle" rate—to  be acceptable.

      One method  for applying  the  DCF  approach to a complete oil shale project
 is to determine  the selling price  which would provide the revenue required to
 produce a  minimum acceptable   rate of return  (DCF  ROR).   With this method, a
 selling price  for oil can be  established by distributing the  required revenue
 uniformly over every barrel of oil produced.

      The same technique  can  be  utilized  to  determine  the  total annual  and
 per-barrel   costs  of  pollution control.   In  practice,   pollution control  is
 not  a separable aspect  of an oil shale  project.  Consequently,  a private
 developer  will  require  the  same DCF ROR on< pollution  controls as  for the
 entire project.

      If  the  revenue  necessary  to  provide  the   required  DCF ROR  for  each
 control  (expressed in constant  dollars)  is  distributed uniformly over each
 barrel of shale  oil produced,   then this also  implies a constant total revenue
 requirement  in  each year  of normal  (full)  production.   However, in  the
 start-up years,  less oil  is produced,  with the  result that the annual revenue
 requirement  is prorated.   Additional  costs  incurred in the  start-up period
were  spread over  all production in  order to  produce  a uniform per-barrel
 control cost.


                                     280

-------
                                                TABLE 5.1-1.  DETAILFO ENGINEERING cosrs  FOR  MR  POLLUTION CONTROLS
00
Control
(No of Units)
Participate Controls
Fabric Filters (2)
Fabric Filter (1)
Fabric Filter (1)
Fabric Filters (3)
Fabric Filters (2)
Fabric filters (8)
Fabric Filters (8)
Fabric Filters (9)
Fabric Filters (9)
Fabric Filter (1)
Fabric Filters (2)
Fabric Filters (3)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (4)
Fabric Filters (2)
Fabric Filters (2)
Water and Foam
Sprays
' Fabric Filters (4)
Fabric Filters (13)
Flue Gas Treatment
Fixed
Capital Cost
Control Location ($000' s)
Primary Crusher (ore)
Primary Crusher (subore)
Primary Crusher (overburden)
Raw Shale Conveyor Transfer
Points
Conveyor to Stockpile
Secondary Crushers
Secondary Screens
Tertiary Crushers
Tertiary Screens
Fine Ore Storage
Processed Shale Conveyor
Transfer Points
Processed Shale Load-out
Hoppers
Conveyor to Secondary
Crushers
Conveyor to Secondary Screens
Conveyor to Tertiary Crushers
Conveyor to Tertiary Screens
Conveyor to Fine Ore Storage
Conveyor to Retort Fead
Hoppers
Open Stockpiles, etc
Retort Feed Hoppers
Conveyor to Retorts

987
105
552
1,051
628
4,828
4,828
5,432
5,432
249
559
569
348
348
348
696
348
348
909
1,837
2,059

Components of Direct Annual
Operating
Maintenance Supplies
19
2
11
21
12
94
94
106
106
6
11
11
~J _„
"? „_
7
14
7
7
117 1,065
36
40

Operating Cost flOOO's/yr)
Operating
Labor Electricity
44
4
23
44
73
203
203
228
2ZS
10
23
23
15
15
15
30
15
15
274
77
87

Total Direct
Annual Operating
Cost ($000's/yr)
63
6
34
65
85
297
297
334
334
15
34
34
22
22
22
44
22
22
1,456
113
127

           Electrostatic
             Predpltators (13)
Flue Gas  Discharge  System
50,734
                                                                                 330
1,814
2,144
                                                                                                                                  (Continued)

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                                                                        TABLE  6 1-1  (cent.)
• • - - 	 --" •• — • • • ' 	 • ' 	
Control
(No. of Units)
Miscellaneous Controls
Stretford (1)
Ammonia Storage
Tank (1)
Floating Roof 011
Storage Tanks (2)
Proper Maintenance
Catalytic Converters
Control Location
DEft Unit
Ammonia Recovery
Product Storage
Valves, Pumps, etc
Diesel Equipment
Fixed Components of
Capital Cost
($000' s) Maintenance
6,860 134
466
300
61 55
170 60
Direct Annual Operating Cost <$000's/yr) Totai Direct
Operating Operating Annual Operating
Supplies Labor Electricity Cost <$000's/yr)
164 350 121* 769
6 — 61
so
        * This Includes $24,000 for steam.


        Source-  DRI estimates based on Information provided by  SWEC.
ro
CO
ISJ

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                          TABLE 6.1-2.   DETAILED ENGINEERING COSTS FOR WATER POLLUTION CONTROLS
.
Control
Ammonia Recovery
Unit
API Oil/Water
Separator
Fixed
Capital Cost
($000' s)

3,627

161
Mine Water Clarifier* 2,560
Cooling Water
rs> Treatment*
00
U)
Boilef Feedwater
Treatment*
Equalization Pond
Runoff Oil /Water
Separator
Aeration Pond
TOTAL

—



122
181

41
430
7,122
Components of Direct Annual Operating Cost ($000's/yr)
Maintenance

118

4
84

—



4
3

1
14
228
Operating
Supplies

428

--
235

51



14
„

--
--
728
Operating Cooling
Labor Water Steam Electricity

237 60 1,565 11

--
—

—



40 — — 11
„_

--
99 — — 40
376 60 1,565 62
Total Direct
Annual Operating
Cost ($000's/yr)

2,419

4
319

51



69
3

1
153
3,019

* These technologies could be considered as part of the process rather than pollution control.
Source:   DRI  estimates based on information provided by WPA.

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                                 TABLE 6.1-3
                    ENGINEERING COSTS AND TIMING OF  SOLID WASTE MANAGEMENT ACTIVITIES
                                  (Thousands of Dollars)
Activity
SURFACE HYDROLOGY
Runoff Collection Sumps
Runoff Collection Pumps
Deep Monitoring Wells
Shallow Monitor ing Wells
Piezometers
SURFACE STABILIZATION
Dust Suppression
Revegetation
Topsoil
Seed
Project Year ->
123456789 10
58 58 58 58 58 58 5B 58 58 58
15 15 15 15 15 15 15 15 15 15
858
26
432
6,204 9,196 11,079 11,079 11,079 11,079 11,079 11,079 11,079 11,079
1X3
00
•I*
Activity
SURFACE HYDROLOGY
Runoff Collection Sumps
Runoff Collection Pumps
Project Year -»
11 12 13 14 " 15 16 17 18 19 20 21
58 58 58 58 58 68 58 58 58 58
15 15 15 15 15 15 15 15 15 15
Deep Monitoring Wells
Shallow Monitoring Wells
Piezometers
SURFACE STABILIZATION
Dust Suppression
Revegetation
Topsoi1
Seed
11,079
11,079
11,079     11,079     11,079
11,079     11,079     11,079
11,079
   183
    46
    11
11,079
   185
    46
    12
Note   Year 1 is the first year of production.   This is  subsequent to the 30-year open pit development period
Source.   DRI estimates  based on information provided by  SWEC
                                                                                                                 185
                                                                                                                  46
                                                                                                                  11

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     The  total  annual  required  revenue  is  utilized to  satisfy  two major
components:  the  total  annual  operating cost, and  a component that provides
the  necessary  return  on investment, called the  total  annual  capital  charge.
Note  that  with  the  DCF  approach,  profit  is  based  solely  on  investment;
operating  costs  are passed  straight through  as one component  of the total
"evenue requirement, without addition  of any profit element.   This is normal
practice for industrial project assessments.

     To relate  an  annual  capital  charge to  the corresponding investment, a
"capital charge rate"  was  used.   In practice, there are two types of  capital
investment:  fixed  capital  (i.e.,  physical  equipment)  and working   capital
(which  is  nondepreciable  investment).   The "fixed charge rate" is defined as
the  proportion  of  investment  in  fixed capital  that must  be  recovered in a
year  of normal  production  in  order to provide the required  DCF ROR.   The
"working capital  charge rate"  performs  a  similar  function for  the  working
capital.  The total annual capital  charge for a pollution control is  the sum
of  the  annual  fixed  capital charge and  the annual  working  capital   charge.

     Fixed  charge rates have several economic assumptions  embedded in them.
Some  o* these  assumptions  are  common to  all pollution controls,  i.e.,  the
project life  and operating  (stream) factors, the  income  tax  rate,  and the
*"equirad DCF ROR.

     Other  assumptions  vary according to  the pollution control  or group of
controls.    These  are:   the  timing  of the  investment in fixed  capital,  the
depreciation peridd,  and the investment  tax" 'credit  details.   Consequently,
different  fixed   charge  rates are  used for  different  groups of  pollution
controls.*  (These rates, as well  as-the underlying standard economic assump-
tions, are listed later in Table 6.2-2.)

     The working  capital  charge  rate  depends only  on  the project life  and
operating  factors,  the timing of  the  investment in working capital  and  the
required DCF ROR.   Since none of these  assumptions varies among controls,  the
same working capital charge rate is used for each control.

     As already indicated,  the  total annual cost for a control is the sum of
the  total  annual  capital  charge  and the  total  annual   operating cost.   The
total annual  operating cost comprises  two components.   The  "direct  annual
operating cost" consists of  maintenance,  operating supplies,  operating labor
and  utilities.   The  "indirect  annual  operating cost"  comprises  an  annual
allowance for  property taxes and  insurance,  any annual by-product credits,
and an  allowance  for  extra start-up costs,  i.e., those  that are  in excess of
the direct  annual operating  cost  prorated  in  accordance  with  production.   It
also includes a credit  reflecting a reduction in the Colorado severance  tax
  The  use  of  several  different  fixed charge  rates  in the  same oil  shale
  PCTH  may  appear  complex.   However,  since   the  manuals  examine  several
  alternatives  for  pollution  control,  an  accurate  evaluation  of  capital
  charges  is  needed,   A less  accurate approach, such  as  assuming a single
  capital  expenditure  profile  for all  controls,  could  conceivably  affect
  the per-barrel cost  ranking of pollution control alternatives.

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that  must be  paid,  because  the  cost of-each  pollution control  reduces the
severance  tax liability.*  Extra start-up costs and the severance tax credit
are  "levelized" to  distribute them uniformly  over each barrel  of shale oil
produced  since they' do not  vary  in proportion to  production.   (Levelizing
takes  a cost  that does  not  vary in  proportion  to production  and  finds an
economically  equivalent  cost that  has  the  same  time-profile MS production
[see Sections  6.2.3  and 6.4.3].)  To summarize:

     Total Annual  Control Cost = Annual  Fixed Capital Charge + Annual
     Working Capital  Charge + Direct Annual Operating Cost + Indirect
     Annual Operating Cost.

     For air  and water pollution controls, direct annual operating costs are
specified  for  a normal  year  of production and  are implicitly prorated during
the start-up  years.   In practice, operating costs during the start-up period
will  be  higher,  but  this   is  allowed  for  via  the  extra  start-up  costs
discussed  in  Section 6.2.2.   The solid  waste  management costs are developed
in  the form  of  a year-by-year  cash flow  (see  Table 6.1-3) which  must be
converted  into  equivalent  fixed capital  and  direct annual  operating  costs
for a full production year (see Section  6.2.3 and Table 6.2-3).

     The per-barrel  control   cost  is obtained  by  dividing the  total  annual
control cost  by the  production in  a  normal (full  production)  year.   (Per-
barrel  operating  costs and  capital  charges can  be  calculated  in  the  same
way.)   The detailed  algorithms for  these calculations and  for determining
fixed and working  capital charge factors are given in Section 6.4.1.

6.2,2  Economic Assumptions Used in  Total CostCalculations

     To transform  engineering cost data provided in Section 6.1.2 into total
annual  capital  charges,  total  annual  operating costs,  and total annual  or
per-barrel  control costs,  a  number  of economic assumptions  were made.   Most
of these  assumptions are  listed in Table 6.2-1,  and  Table 6.2-2 summarizes
those assumptions  that vary  from control to  control.   The  values  given in
these two  tables  are  the standard  values,  known as  the  "standard  economic
assumptions,"   which  have been  used for the cost analyses  presented  in the
oil shale  PCTMs.   Some  of these are varied in the sensitivity analyses which
are used to show how control  costs change in response to alternative  economic
assumptions and to changes in the engineering costs.
  The distinction  between the  two components of operating cost  is  made for
  convenience  in  performing  the calculations and  is not  fundamental.   The
  direct annual operating cost is comprised of  basic  cost  elements, whereas
  the indirect annual  operating cost comprises a series  of adjustments that
  are influenced  by other  factors,  such as tax  assumptions.   Direct annual
  operating  costs  for  each  control  are  given   in  Tables  6.1-1, 6.1-2  and
  6.2-3.   Indirect  annual  operating costs  for  all  controls  are calculated
  using a  standard  algorithm  (see Section 6.2.2), except for  any by-product
  credits which are given in Tables 6.3,3 and 6.3.4.


                                     286

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                       TABLE  6 2-1.   SUMMARY  OF  STANDARD COST AND ECONOMIC ASSUMPTIONS
                                                 Assumptions
COST iSSUMFTIQNS

*    Sase Year   Mid-1580 dollars

»    Direct  Labor  Rate-  $11.00/br*

*    ''Loaned" Labor Rate*:  $3Q.OO/tir

«    F-"xed Capital Costs   25% engineering and construction overhead  and  3%  contractor's  fee Included*

»    Contingency Allowances:  20%, all fixed capital costs*
                               0%, fnost operating costs*
                              20%, solid wasta direct operating costs

ECONOMIC ASSUMPTIONS

•    Project Life:  20 years*

o    No»-ma1 Output.  63,140 Barrels per Stream Day (8PSD)

«    Operating (stream) Factors:  Year 1      -  50%
                                  Year 2      -  75%
                                  Years 3-20  -  90%*

 of a normal year's direct
     operating cost

•    Working Capital:   30 days'  total  operating cost (excluding by-product credit), plus 60 days'
     by-product credit

•    Annual  Allowance for Property Taxes  and Insurance:   3% of fixed capital

«    Colorado Severance Tax:   Credit allowed

•    Timing of Investment:   Initial  fixed capital  expenditures can occur in Years -3 through +1,
     expenditures and tax considerations  for each control  are phased in accordance with the construction
     and initial  operation of each control  (see Table 6.2-2 for schedules)

•    Corporate Financing:   Tax credits and allowances can be passed through to a parent company that can
     benefit from them •urate.diataly,  without watting for the project to become profitable*

•    Fadaral  Depletion Allowance:   Does not affect pollution control costs


* These ipethods  and factors are in accordance with the recommendations, dated April 22, 1980, of EPA's
  ad hoc synfuels cost coiwltte*.

Source:  OKI



                                                   287

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                                        TABLE 6.2-2.  ECONOMIC ASSUMPTIONS THAT VARY FROM CONTROL TO CONTROL

Retort Timing
Controls associated with retorting:
certain fabric f filers, electrostatic
precipitators, Stretford, ammonia
recovery unit, API oil/water
separator, boiler feedwater and
cooling water treatment
H1ne Timing
Controls governed by mine and project
start up most fabric filters, water
and foam sprays, ammonia and oil
storage, Maintenance of valves, pumps,
etc-
Early Water Management
Controls associated with mine and
site water treatment- mine water
" clarifier, equalization pond, runoff
oil /water separator, aeration pond
Ca ta ly 1 1 c Converters'"
(on dlesel equipment)
Solid Waste Management (Year 1)
Deep monitoring wells
Solid Waste Management (Year 10)
Shallow monitoring wells and
piezometers
Capital Expenditure
Profile
Year -2: 10%
Year -1: 30%
Year 0: 60%
Year -1- 30%
Year 0 70%
Year -3: 100%
Year 0 100%
Year +7- 100%
Year +14 100%
Year +1. 100%
Year +10: 100%
Investment Tax Credit Depreciation Fixed Charge Rate8
RatP % Profile Life (years) Starts Percent
20 Same as. 16 Year -fl 16 17
capital
20 Sane as, 16 Year +1 15.61
capital"
20 Year -2: 100% 16 Year -2 21 64
13 l/3d Year +1: 100% 5 Year +1: 100% 23,36
Year +8: 100% 5 Year +8: 100%
Year +15- 100% 5 Year +15: 100%
20 Year +2: 100% 10 Year +2 12 49
20 Year +11: 100% 10 Year +11 4. 51
  For standard economic assumptions  (see Table 6 2-1).



  Qualifies for investment tax credit progress payments,



c Capital Is replaced twice during project life.



  Investment tax credit is reduced because equipment life  is  less  than 7 years



Source   DRI

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     Where  appropriate,  the  standard  economic  assumptions  are  discussed
below.  Others  are  discussed in connection with  the  sensitivity analyses in
Section 6.3.2.

     lining of Control Capital Expenditures —
           6.2-2  includes the  fixed  capital  expenditure profiles  for each
category of control.  Although a number of developers and other organizations
have  published  construction schedules  for oil shale  plants,  no schedule is
available  that  is  appropriate  to  a  Lurgi-Open  Pit plant  of  this  size.
Instead, the  schedule  was based on data for a 51,500 BPSD TOSCO II plant for
which  comparatively  good data  are  available  (Nutter  and  Waitman,  1978;
telephone  interview with  C. S. Waitman,  Tosco Corp. ,  February 1979;  Colony
Development Operation,  1977).   Engineering judgment was  then  used to deter-
mine  when  the pollution  controls  would be procured and  installed, incorpo-
rating  the  impact  of payments  made during off-site fabrication.  In general,
sxpendi tyres  on  pollution controls tend to be  incurred  later  than those for
nost  retort construction activities, since the controls are usually among the
last  items to be installed.

      Part of  the water pollution  control  system  constitutes an exception to
the above discussion.  Basic site water management facilities must be instal-
led and operational before most other activities can commence.   Consequently,
these  iteras  were  assumed  to be installed in Year -3  (i.e.,  4 years  before
production  commences)  and  placed  into  service  in Year  -2  for depreciation
purposes.  The  mine water  treatment system was  given the  same timing,  but
this  is somewhat arbitrary since the mine is assumed to be fully developed at
the commencement of this case study analysis.   Also, because no mine develop-
ment  is  included in this case study analysis, it was assumed that the mobile
diesel equipment was purchased in Year 0 and placed into service in the first
year of crocfuction, Year 1.

     Assumptions for Taxation*--

     Oeggecj j t i o n .    All  oil  shale  PCTMs used a  16-year  depreciation period
for  most  assets.    This  corresponds  to  the  mid-point  of  the  IRS1  Asset
Depreciation  Range (ADR) guidelines  for oil   refineries.   In  practice^ many
companies  would  use  the  lower  end  of the  ADR   range,  which  is  13 years;
however, H  nas  been  found  that  this  would  make  very  little difference in
the results of the analysis.
  A]1 analyses were conducted prior to enactment of the Economic Recovery Tax
  Act o^ 1981  (PL  97-34).   As far as an  oil  shale project is concerned, the
  main  impact  of  this  act is  to  permit very  rapid depreciation  under the
  Accelerated  Cost Recovery System (ACRS).   Using ACRS,  most property would
  be depreciated over  5 years and  mobile equipment would be depreciated over
  3 years.   A  rough  estimate  of the effect of the provisions of the Economic
  Recovery  Tax  Act  of  1981  on  the  pollution  control  costs  is  given  in
  Section 6.3.1.


                                     289

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      Some  equipment  clearly qualifies  for  a  shorter  life.   Capital  items
 associated  with  processed  shale  disposal,  i.e.,  the  monitoring wells  and
 piezometers,  were regarded  as  mining  equipment,  for which a 10-year  depre-
 ciation  period  was  used.   A  5-year  depreciation  period was  used for  the
 mobile diesel  equipment, and it was assumed  that this equipment was  replaced
 twice during the  project life.

     The  depreciation  method  used for  all  taxation  calculations  was  the
 Sum-of-the-Year's Digits method.

     Investment Tax Credit (ITC).   A  basic 20% ITC was used for all  items  in
 accordance with the Energy Tax  Act  of  1978  (PL 95-618).  The mobile equipment
 has  a depreciation  period  of  only  5 years, so  the  credit  is  reduced  by
 one-third, to 13  1/3 percent.

     Where payments  for  a  control  extend  over  more than one year, the  tax
 credit can be  taken as  the  capital  is expended,  in  accordance with  the  IRS1
 progress payments rule.   Otherwise, it  is taken when  the asset is  placed  into
 service.

     Incometax rate.  A combined State and Federal tax rate of 48% was used.
 In  practice,  CoTorado has  a 5%  tax  rate, so the  effective percentage  rate
 should be:  5 •*• ([1 - 0.05]  x 46) = 48.7%.  The error introduced by using 48%
 is negligible.

     Depletion allowance.    The  Federal  depletion  allowance   has  not  been
 incorporated into the calculation of taxes.  The justification for this is  as
 follows.   The  percentage depletion  allowance is 15% on  the  "gross income"
 from an oil  shale property.   In this case, since the sales or transfer price
 of shale oil  (and,  hence, gross income)  is  independent of pollution control
 costs, the depletion  allowance  will not affect those costs.   However, there
 is a  limitation  that the percentage depletion allowance cannot exceed 50%  of
 the taxpayer's  taxable income  from the property,  computed without allowance
 for depletion.   Since pollution control costs reduce the taxable income, they
 could affect the  depletion allowance if it was limited under the above rule,
 and this would  then  be  a cost attributable to pollution control.  While this
 might well  be  the  case   in  a  start-up year,  it  appears  that this  limit  is
 unlikely  to  apply  during a normal  year's operation.   This  is  because the
 complete  project's   total annual  operating  costs  are  a  comparatively  low
 proportion of  its total  annual  costs, including capital-related costs (based
 on  data   for  an  open  pit  mine with unspecified   type  of  surface retort
producing  100,000 barrels   per   day  [Peat,   Marwick,   Mitchell   &  Co.,
September 1980]).

     Hence,   the   impact   of  the  Federal  percentage  depletion allowance  on
pollution control costs has  been disregarded.   This  may introduce  minor
errors during start-up years, but complete project cost data are not publicly
available to  permit  the effect to be calculated.   Cost depletion, which might
at times be taken instead of percentage depletion,  is  clearly irrelevant to
pollution control costs.
                                     290

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     PCF MM.   Twelve percent  (per year) was  used as a standard assuasption
 (see Section 6,3.2).

     Project life.  The expected project  life (measured fro®  the comaencewent
 of  production)  will  be determined  by exhaustion of the oil shale reserves or
 by  technological obsolescence.  Planned project lives  used for evaluations of
 oil shale  developments range from  18 to  30 years.   Twenty years is a coason
 period  to  use  for   economic  evaluations  and  was  used  in  this
 Increasing the life has a very small effect on the  results at nornal DCF
 (i.e., 12% or more).

     Sjtart-ypprpfjle.  The start-up profile and normal year  operating factor
 are        on projections  for a  TOSCO  II plant (Nutter  and Waitnan, 1978).
 Lyrgi  representatives consider that  a  Lurgi plant should achieve  a better
 start-up profile than a TOSCO  II  plant,  but they  feel  that  a 90%  operating
 factor «ay  be  slightly optimistic  for a  normal year (interview with H. Weiss
 awl  J. Arnhold of Lurgi Kohle und  MineralBtechnik  GmbH, in Denver,  Colorado,
 January 1981).    The   operating  (stream)  factors   used  (i.e., Year 1: §d»,
 Year 2: 75%,  Years  3-20:  90%)  are considered  to  be the most appropriate
 assumptions that can be made at this time.

     Caaponents of Annual Indirect  OperatingCosts—

     Tiie annual indirect operating  cost is composed as follows:

          Annual property tax and insurance allowance

          *• Extra start-up costs (levelized)

          - Severance  tax credit (levelized)

          - Annual by-product credit (if any).

     grgg_erty__tax _and  Insurance allowance.   The  annual  indirect   operating
cost includes 3%  of  the fixed capital cost  as  an  allowance  for property tax
 and insurance.   This value was selected by DRI after review of a wide variety
 of sources.

     Extra start-up cost.   The total extra start-up cost (which is treated as
an operating cost, as  opposed to being capitalized)  is derived froa the fixed
capital and direct annual  operating costs.  The capital-related cosponent is
3% of the  fixed  capital  cost as an allowance  for  "fix it" costs.  The oper-
ating  cost-related  component   which  is  20%  of  a  normal year's  direct
operating cost,  allows for  hiring  and training employees  before production
          and for  higher unit costs during the start-up  period.   This value
for the extra start-up cost for surface  retorting plants with a 2-year start-
up  period  was  selected by  DRI  after  a  review of  several  sources,  including
estimates for TOSCO II (Nutter and Waitman, 1978) and Paraho  (Pforzheiner and
Kur»chaT,  March 24, 1977) plants.   The extra start-up  cost was  assumed to be
 incurred during  the  first year of  production but  is  levelized  to  spread it
uniformly over every  barrel  of  oil  produced (see  Sections 6.4.1 and 6.4.3).


                                     291

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              ..-    •     Under  Colorado   HB 1076,  enacted   in   1977,
severance tax  is  levied on the production of a commercial oil shale facility
at the  rate  of 4% of the  "gross  proceeds"  for surface retorted oil.  "Gross
proceeds" is defined  as the value of the oil shale at the point of severance
arid  is  calculated  by  subtracting costs (e.g., retorting and mining) from the
gross sales  income.   Since pollution controls add  to  costs,  they reduce the
gross proceeds  by  a  corresponding amount.  Hence, a credit for severance tax
not psid should be deducted from the pollution control costs.

     tffiile  operating  costs  are  clearly  allowable  in  calculating  gross
proceeds,  return  on  capita]  does not  appear to be  (the statute  refers  to
allowing   "...costs,   including   direct   and  indirect   expenditures   for:
(a) equipment  and  machinery....'').  Hence,  when  this  credit  Is calculated,
the capital  charge must be replaced by some  form of amortization.   For this
analysis,  tne   severance  tax credit  calculations  are based  on direct  and
indirect annual operating costs, plus 5% of the fixed capital  cost to provide
capital  amortization over the 20-year project life.

     In applying this credit,  allowance was also made for  exemptions  to the
tax  for the  first 10,000  barrels  per  day of production  and  for  plants that
have not achieved  50% of their design  capacity,  together with reduced rates
of tax  in  the  early  years.  The  credit  is levelized  in order  to  achieve a
uniform  per-barrel  cost.   The methodology  utilized  (LFAC2  in Section 6.4.1}
is not precise, but since the severence tax correction, is typically less than
2%  of  the   total  annual  or per-barrel  control  cost (see  Section 6.2.4),
further refinement is not justified.*

     8ya*groductL.credits.  The by-product  credit  (if any) for each control  is
shown  in Tables 6.3-3  and 6.3-4.   (The^e are  no  salable by-products ^roro
solid waste  management.)   By-product  values of $110 per ton for ammonia. $30
per long ton for sulfur, and $32 per barrel  for oils were used.

     At  present,  there  is no  significant  market  for  sulfur in  the  Rocky
Mountain Region;  in  the past,  shipping costs to move  recovered  sulfur to a
chemical complex could  have been greater than its delivered value.   However.
the price of high  Quality  sulfur  has gone  up  substantially in recent years.
reaching values as high as $129 per long ton (U.S.  DO!,  August 1981).   High
demand  for  sulfur is projected  through the year 2000 (Rangnow  and Fasullo,
September 28S 1981).   Hence, a nominal  $30 per long ton has been included for
recovered  sulfur.   However,  if  in the  future  a  sulfuric  acid  plant  and
fertilizer complex are developed in the area, the values of by-product sulfur
and ammonia would be raised.
* Sines this analysis was conducted, the Colorado Legislature has amended the
  severance tax  legislation pertaining  to  oil shale.  While  the  basic rate
  for  aooveground  retorting is  unchanged,  the various  exeffptions discussed
  above are reduced.   This  will  result in plants paying slightly more sever-
  ance  tax,  which  marginally  increases  the  severance  tax credit,  thereby
  marginally (much less than 1%)  reducing the pollution control cost.


                                     292

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     The  by-product  value  of  $32 per  barrel  for  light  oils  recovered by
pollution  control  activities  is  higher than  the selling  price  assumed for
snale oil,  which is $30 per barrel.  Light oils  are more valuable than  heavy
oils, and  it is the  lighter fractions  that  would be prevented from evapora-
tion  by  the pollution  controls.   Consequently,  a higher  value is justified
for recovered shale oil as opposed to whole shale oil,

     Working Capital-"

     The working capital  associated with a control was  taken as one month's
total operating cost plus  three  months' by-product  credit.   This is equiv-
alent tc be  one  month's  total  operating  cost  disregarding  the by-product
credit,   plus  two  months'  by-product credit.   Two months'  by-product credit
represents  one  month's  inventory and one month's receivables.   These values
were selected by DRI after review of a variety of data sources.

     Working capital  is  advanced  in accordance with  the direct annual  oper-
ating cost plus the extra start-up cost, as follows:

              Operating      Output as        Operating Cost        Working
             (Qn-Stream)     % of Full       Relative to Full       Capital
               Factor        Production         Production         Increment

     Year I     50%              56%                76%               76%

     Year 2     75%              83%                83%                7%

     Year 3     90%             100%          '     100%               17%

                                                                     100%

     Seventy-six percent of the working capital is advanced in Year 1 because
this includes the  20% extra start-up cost (56% + 20% = 76%).  In Year 2, the
operating cost  increases from  76% to 83%  of normal, hence  7% more worldng
capital   is  required.  A  similar argument applies to  Year 3, leading to a 17%
working  capital  increment.  All  working  capital is  recovered  in  Year 20.

     The working capital  charge rate (RW) is calculated in  a similar way to a
fixed charge rate (see Sections 6.4.1 and 6.4.2).  For 12% DCF ROR and normal
project-timing assumptions, RW = 20.83%.

6.2.3  Solid Waste Management Costs

     Throughout this manual a distinction is  made between fixed capital  costs
and annual  operating costs.   The importance  of this distinction is related to
the treatment for  determining  income tax liability.   Operating costs can be
claimed as an expense in the year in which they are incurred, whereas a  fixed
capital   cost must  be depreciated  over the  period  for which the asset  is
expected to be  used.  The  effect of classifying  a cost  as  an operating cost
ratner than a capital cost is  to reduce the  tax liability  in any given  year.

     For air and  water  pollution  controls,   the distinction between  fixed
capital  and annual  operating costs is unequivocal.   For solid  waste  manage-
ment  costs   which   are  developed  in the  form of year-by-year  cash  flows


                                     293

-------
 (Table  6.1-3),  the distinction  is less--dear.   The cost.of deep monitoring
 wells,  which  occurs-only  in  Year 1 (the  first year  of production in this case
 study  analysis)»  was treated as a,fixed capital  cost, while costs that occur
 throughout  the  project life were  considered  as  operating costs.   Costs that
 occur  at the end of  the project  (e.g.,  revegetation)  were also treated as
 operating  costs,  since  there  is   no  remaining  project life  over  which to
 depreciate  them.   In the Lurgi-Qpen Pit case study, there are  two costs, the
 shallow monitoring wells  and piezometers,  that  occur  only in'Year 10, i.e.,
 halfway through-the  project's  life.    Although  by  no  means a  clear-cut
 decision,  these  costs were  designated  fixed  capital  costs since  there is
 still  sufficient  time over which  to depreciate  the assets before the project
 ends.

     Since the  solid waste management operating  costs are not proportional to
 production,  they were  "levelized" to transform them into equivalent direct
 annual  operating  costs that are proportional to production, so that they can
 be  treated  in  the same way as  other direct  annual operating  costs.   Level-
 izing involves  determining the annual cost  that  is  proportional to production
 and which  has the same present  value  (for a given  DCF  ROR) as the irregular
 operating cost  stream.   Further explanation and an example are provided in
 Section 6.4.3.  Costs  designated as fixed capital were not levelized.

     Table 6.2-3  presents  the   solid  waste management  fixed  capital  costs
 and direct  annual  operating costs (levelized  at  12% DCF ROR) derived from
 Table 6.1-3.

 6.2.4   Control  Cost Exaftple

     Table 6.2-4  provides  an  example   of  the  composition  of  the  various
 elements of per-barrel  control cost for  a single  major pollution control, the
 electrostatic precipitators.   Per-barrel costs  follow identical proportions
 to annual costs.

     It  can  be seen  that the  fixed  capital  charge amounts  to 68.4% of the
 total   cost,  whereas  the  working  capital  charge is  only 0.5% of  the total
 cost.    It  is interesting to note that the  fixed  capital  charge  is almost
 entirely return on equity, as the  investment tax  credit  (20% of fixed capital
 cost) almost offsets the  income tax liability over  the project  life when both
 are discounted  at 12%, which is the specified DCF  ROR.  This illustrates the
 effect  of the time-value  of money, as the  tax credit is given  before produc-
 tion  commences,  whereas  the regular  tax  liability is weighted  toward the
 later years of the project.

     The direct operating cost for the  electrostatic  precipitators  is 17.8%
 of the total cost.  Electricity (15.0%)  is  the largest component, followed by
maintenance.   This particular  pollution control has  no operating  labor or
 supplies.

     The indirect operating  cost amounts to 13.3%  of the total  cost for this
control, of which 12.6% results from the cost of property tax  and insurance.
The extra  start-up  costs and the severance  tax credit are 2.1%  and 1.4%,
 respectively, of  the total.

                                     294

-------
        TABLE 6.2-3.  FIXED CAPITAL AND DIRECT ANNUAL OPERATING COSTS
                         FOR SOLID WASTE MANAGEMENT
                                     Fixed                Direct Annual„
                                  Capital Cost           Operating Cost0
Activity                            ($000's)               ($000's/yr)

SURFACE HYDROLOGY

   Runoff Collection Sumps                                       63

   Runoff Collection Pumps                                       16

   Deep Monitoring Wells              858

   Shallow Monitoring Wells            26C

   Piezometers                        432°


SURFACE STABILIZATION  .

   Dust Suppression                                          11,079

   Revegetation                                                   8

   Topsail                                                        2

   Seed                                                           1


3 The direct annual operating costs are 1 eve!ized with respect to production
  at 12% DCF ROR.
b
  Spent in first year of production, Year 1.

c Spent in tenth year of production, Year 10.

Source;  DRI.
                                     295

-------
   TABLE 6.2-4.  PEt-BARREL COST BREAKDOWN FOR ELECTROSTATIC PRECIPITATORS
                       (Standard Economic Assumptions)
Cost Category
Cents/Barrel
Percentage of Total
Fixed Capital Charge
     Equity Return (12% ROR)
     Income Taxes Paid
     Investment Tax Credit

Working Capital Charge
Direct Operating Costs
     Maintenance
     Operating Supplies
     Operating Labor
     Cooling Water
     Steam
     Electricity

Indirect Operating Costs
     Taxes and Insurance
     Extra Start-up Costs
     Severance Tax Credit
     By-product Credit

       TOTAL COST
 37.4
  9.6
 (7.4)
  1.6
  8.7
  7.3
  1.2
 (0.8)
         39.6
          0.3
         10.3
          7.7
         57.9
     2.8
    15.0
    12.6
     2.1
    (1-4)
            68.4
             0.5
            17.8
            13.3
           100.0
Source:  DRI.
     These  cost proportions  for the  electrostatic precipitators  are  typi-
cal of  those for  air pollution controls.   However,  for  some  controls,  the
indirect  operating  cost or  even  the  per-barrel  control  cost can  become
negative where there is a significant by-product credit.
     Water  pollution  control  costs  tend to  be  less capital-intensive,  i.e.,
the ratio  of the  total  annual  capital  charge to the total  annual  operating
                                     296

-------
cost  is  lower.   This  is because some controls  have  high operating supplies
and utility costs.

     Solid waste  management costs  are different  in  that they are basically
either a  fixed  capital  cost or  a direct  annual  operating cost, but not both
for  &  given control.   This  reduces working  capital  and  indirect  annual
operating costs, respectively, to essentially zero.

6.3  COST ANALYSIS RESULTS

     The  methodology  used to  develop the data  presented  in  this  section is
identical to a  complete discounted  cash flow  evaluation;  that is, it solves
for the annual  or per-barrel revenue required to provide the specified return
on tne investment (DCF ROR) associated with a control.  This revenue require-
ment  is   known  as the  total  annual  or per-barrel  control  cost.   The  cost
metnodology is  outlined in Section  6.2,  and further  details  are  provided in
Section 6.4.1.

     Two  control   items—proper  maintenance  of  valves  and  pumps  and  the
floating  roof  oil  storage  tanks—have  relatively large  by-product credits
which lead to negative  total annual  costs (i.e., total annual cost credits).
Although these items might consequently not be considered pollution controls,
their costs  have  been  included  in  the total  cost of air pollution  control.
The net credit associated with these items represents a very small  proportion
(lass than  0.6%)  of  the  total  air  pollution  control  cost  using  standard
economic assumptions,'and :even less  using the sensitivity analyses.

5.3.1  Results  for Standard Economic Assumptions*

     The term "standard economic assumptions"  is used to describe the normal
economic  assumptions  presented in* Tables  6.2-1  and  6.2-2.   The majority of
these  assumptions are   in  reasonable  accord with   normal  engineering  and
economic evaluation practices.   The  most  critical economic assumption is  that
* As "already mentioned, this analysis was developed prior to enactment of the
  Economic Recovery Tax Act of 1981.   The rapid depreciation (ACRS) permitted
  fay  this  act  would  significantly  reduce the  values  of the  fixed  charge
  factors,   especially  for  normal  ("pass through")  financing as  opposed  to
  stand-alone financing.

  For standard  economic assumptions,  very  rough estimates of the  changes  in
  total  annual control  costs are as follows:

          Air controls:       1085 decrease on  aggregate.
          Water controls:      5% decrease on aggregate.
          Solid waste mgt.:    0-15% decrease,  depending orr item.

  As an alternative assumption, If the energy  portion (10%) of the investment
  tax credit were  allowed  to expire at the end  of 1982, the combined effect
  of this and ACRS would  be to cause small  increases in total  annual  control
  costs.


                                    -297

-------
 of  12% required  DCF  ROR.  This  figure was adopted  for the oil shale PCTMs and
 would be appropriate  for a  mature  industry, but  it  is probably  low for a
 pioneer plant at,this time  (see  Sections 6.2.1 and 6.3,2 for a discussion of
 factors influencing  the  selection of a DCF  ROR).

      Table  6.3-1 provides a  detailed summary of  pollution  control  costs, by
 control group, developed using  the standard economic assumptions for the case
 study considered in this manual.  Table 6.3-2 details  the specific controls
 included in each  control  grouping.   Note  that total  costs  for solid waste
 management  are not provided.  A  complete solid waste management plan  for the
 Lurgi-Open  Fit plant has not been proposed.   As a result, cost estimates are
 available  for particular  items only,  and  no estimate  of  total  solid waste
 management  cost  can  be made  at  this time.

      Table  6.3-1 shows   that  the  total   fixed capital  cost for  all  air pol-
 lution  control   equipment   is  approximately  $91 million,  while  the total
 per-barrel  control  cost  is  $1.14.  The total fixed capital  cost for water
 pollution   control  is  approximately $7 million,  and  the total  per-barrel
 control  cost is  19 cents.

      Table  6.3-1 also compares  the per-barrel  cost of pollution control to an
 assumed $30 per-barrel   value for shale oil.*   For air  pollution control,
 the  proportion  is  3.8  percent.   The   total  water  pollution control  cost
 represents  approximately  0.6%  of the  $30 per-barrel   value  of  shale  oil.

      The  works-gate value  of  $30 per   barrel  (mid-1980 dollars)  for Lurgi
 retorted  shale  oil  was  based on  two sources:  a developer's estimate of $29
 for  a  light shale  oil   (Cathedral Bluffs Shale Oil  Co., November 14,  1980),
 and  a study by  Peat, Marwick,  Mitchell  & Co.  (September 1980)  which  derived
 current values for shale oil.  This study concluded that the per-barrel value
 of  shale oil  (at the project  site)  was approximately  $31.50  to  $32.50" for
 surface retorted oil.  In no  case  was upgrading involved.

      It is  generally anticipated that the  real price of oil will increase in
 the  future.   Hence,  the value  of  $30 may be considered to be a conservative
 estimate because it  does not include any element  of future escalation rela-
 tive  to the general  level  of  prices.   For  example,  if oil prices  were to
 escalate at only 2% per annum  relative  to  general cost levels (which can be
 expected  to include pollution  control   costs), the  real value  of  shale oil
would  reach almost  $45  per  barrel  (in  mid-1980  dollars) by  the  year 2000,
 i.e., at the end of the 20-year project  life.

     Cost..Details--

     Full  cost  details   for each air  and  water  pollution control  (using
 standard  economic assumptions)  are presented  in Tables  6.3-3  and  6.3-4.   As
already  noted,   two  items—proper maintenance of valves  and pumps and  the
floating  roof  oil storage  tanks—were   found  to  have negative  total  annual
* Other  prices  for the  value of  shale  oil  are used  in  the  other oil shale
  PCTMs, reflecting quality differences.


                                     298

-------
                             TABLE  6.3-1.   POLLUTION  CONTROL  COSTS,  BY  CONTROL  GROUP,  FOR  THE
                                                STANDARD  ECONOMIC ASSUMPTIONS
co
' " 	 ^ ' ~


Control Group
Air Pollution Control
Particulate Control
Flue Gas Treatment
Miscellaneous Air
TOTAL AIR
Water Pollution Control
Retort Water
Miscellaneous Water
TOTAL WATER


Fixed ,
Capital Cost
($000' s)
32,451
50,734
7.857
91,042
3,788
3^334
7,122

Total Annual
Capital
Charge0
($000's/yr)
5,168
8,269
1,310
14,747
685
727
1,412

Total Annual
Operating
Cost
($000's/yr)
4,471
3,747
795
9,013
1,745
701
2,446


Total Annual
Control Cost
($000's/yr)
9,639
12,016
2,105
23,760
2,430
1,428
3,858


Per- barrel
Control Cost
(cents/bbl)
47
58
10
115
12
_7
19
Per-barrel
Control Cost as
a Proportion .
of Oil Value0
1.5
1.9
0.3
3.8
0.4
0,2
0.6

        Refer  to Table 6.3-2 for a  listing of the  items that are  included  in each  control group.

        Does not include working capital

     c  Includes charge for working capital.

        Assuming shale oil is valued at ISO/barrel

     Source:  DRI.

-------
                       TABLE 6.3-2.  CONTROL GROUPINGS
Group  Designation
Specific Controls
Air  Pollution  Control

   Participate Control:

   Flue Gas Treatment:

   Miscellaneous Air:
Fabric filters, water and foam sprays.

Electrostatic precipitators.

Stretford, ammonia storage, floating roof
oil storage tanks, proper maintenance of
valves and pumps, catalytic converters.
Water Pollution Control
   Retort Water:
   Miscellaneous Water:
Ammonia recovery unit, API oil/water
separator.

Mine water clarifier,* boiler feedwater
treatment,* cooling water treatment,*
equalization pond, runoff oil/water
separator, aeration pond.
*  These technologies could be considered as part of the process rather than
   pollution control.
                                                   \
Source:  DRI.
costs.   In these  cases,  the annual by-product  credits  were  large enough to
more  than  offset the total annual capital charges and total annual operating
costs.   These  items were, nevertheless,  incorporated  into  the air pollution
control cost total.

     Table 6.3-5 presents the costs of nine solid waste management items.  Of
the  nine,  dust  suppression  is  by  far  the most  costly item—$11.3 million
total annual control  cost, or 54 cents per barrel.  This item is entirely an
operating  expenditure  (zero  fixed capital cost).  The only solid waste man-
agement  items  with fixed  capital  costs  are  the deep monitoring wells, the
shallow  monitoring wel1ss  and  the piezometers,  which  total  $1.3 million.

     It  should be  remembered that these costs do not represent the full cost
associated with  a  complete  solid waste management  operation.   Even so, the
per-barrel  control cost  associated with  these  nine solid waste management
items  is significantly greater  than the  total  per-barrel  control  cost for
water pollution control.

                                     300

-------
                                            TABLE 6 3-3   DFTAILS OF AIR POLLUTION CONTROL COSTS, STANDARD ECONOMIC ASSUMPTIONS
U>
3


Control Identification
(No of Units)
Fabric Filters (2)
Fabric Filter (1)
Fabric Filter (i)
Fabric Filters (3)
f-abric Filte s (2)
Fabric Filte s (8)
Fabric Filte s (8)
Fabric Filte s (9)
Fabric Filte s (9)
Fabric Filter (1)
Fabric Filters (2)
Fabric Filters (3)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (2)
Fabric Filters (4)
Fabric Filters (2)
Fabric Filters (2)
Water and Foam Sprays
Fabric Filters (4)
Fabric Filters (13)
Fixed
Charge
Factor
(*)
15.61
15 61
15 61
15 61
15 61
15 61
15.61
15 61
15.61
15 61
15.61
15.61
IS 61
16 61
15 61
15.61
15.61
15 61
15.61
16 17
16 17
Subtotal Participate Controls
Stretford {!)
Ammonia Storage (1)
Floating Roof Storage
Tanks (2)
Maintenance of Valves, etc.
Catalytic Converters
16 17
15.61

15.61
15 61
23 36
Subtotal Misc. Air Controls
Electrostatic
Precipitators (13)
TOTAL AIR POLLUTION CONTROLS


8 Includes fixed and working
Includes annual by-product
c For sulfur at $30/Iong ton

16 17



Fixed
Capital
Cost
($000 '&)
987
105
552
1,051
628
4,828
4,828
5,432
5,432
249
559
559
348
348
348
696
348
348
909
1,837
2,059
32,451
6,860
466

300
61
170
7,857

5JL_?J4
9JL042


capital charges RW =
credit




Working
Capital
($000' s)
8
1
4
a
9
38
38
42
42
2
4
4
3
3
3
6
3
3
124
14
IS
375
94
1

27
26
5
153

312
840

20,83%


Total Annual
Capital
Charge*
($000's>/yr)
156
1?
87
166
100
762
762
857
857
39
aa
88
55
55
55
110
55
55
168
300
336
5,168
1,129
73

52
15
41
1,310

jy>§9
iiiMZ





Direct
Annual
Op Cost
(1000's/yr)
63
6
34
65
85
297
297
334
334
Ib
34
34
22
22
22
44
22
22
1,456
113
127
3,448
769
—

—
61
60
890

2,144
6^482





Annual Indirect
By-product Annual ^
Crpdit Op Cost
($QOQ's/yr) ($000's/yr)
31
-._ -5
17
33
20
152
152
172
172
8
18
18
11
11
__ "1 1
22
11
11
27
58
65
1,023
72C 146
15

155^ (141)
126° (120)
5
353 (95)

— Ii32
353 2,531





Total
Annual
Op Cast
<$OOfl's/yiO
94
9
51
98
105
449
449
506
506
23
52
52
33
33
33
66
33
33
1,483
171
192
4,471
915
15

(141)
(59)
65
795

3^747
iiQ13





	 	
Total Annual
Control tost
(lOQO's/yr)
250
26
138
264
205
1,211
1,211
1,363
1,363
62
140
140
88
88
88
176
88
88
1,651
471
528
9,639
2,044
«8

(89)
(44)
106
2,105

ULfili
23,760






Per-barrel
Control Cost
(cents)
1 2
0 1
0 7
1 3
1.0
5 8
5 8
6 6
6 6
0.3
0 7
0.7
0.4
0 4
0 4
0 8
0,4
0 4
8.0
2.3
2 6
46 5
9 9
0.4

(0:4)
(0.2)
- 0 5
10 2

-ill
114 6





d For light shale oil at $32/bbl.
Source DRI estimates based
on data provided by SWEC

-------
                                           TABLE 6 3-4   DETAILS OF WATER POLLUTION CONTROL COSTS, STANDARD ECONOMIC ASSUMPTIONS
o
_ 	 ~ 	 . 	


Control Identification
Ammonia Recovery Unit
API Oil/Water Separator
Subtotal Retort Water
Mine Water Clarifier" .
Cooling Water Treatment d
Boi ler Feedwater Treatment
Equalization Pond
Runoff Oil/Water Separator
Aeration Pond
Subtotal Misc Water
TOTAL WATER POLLUTION CONTROLS
Fixed
Charge
Factor
(%)
16.17
16.17

21 64
16.17
16.17
21 64
21.64
21.64


Fixed
Capital
Cost
($000 's)
3,627
161
3,788
2,560
—
122
181
41
430
3,334
7,122


Working
Capital
($000 's)
349
1
350
33
4
6
1
<1
14
58
408
	 __ 	
Total Annual
Capital
Charge
($000's/yr)
659
26
685
561
1
21
39
9
96
727
1,412

Direct
Annual
Op, Cost
($000's/yr)
2,419
4
2,423
319
51
69
3
1
153
596
3,019

Annual
By-product
Credit
(lOOO's/yr)
816C
—
816
..
—
—
—
—
—
-
816

Indirect
Annual .
Op Cost
($000's/yr)
(683)
5
(678)
81
(<1)
4
6
1
13
105
(513)

Total
Annual
Op Cost
($000's/yr)
1,736
9
1,745
400
51
73
9
2
166
701
2,446


Total Annual
Control Cost
($000's/yr)
2,395
as
2,430
961
52
94
48
11
262
1,428
M5S


Per -barrel
Control Cost
(cents)
11 6
0.2
11,8
4.6
0.3
0.5
0 2
0.1
1 3
7,0
18-8 •
         Includes fixed  and  working capital  charges.   RW = 20.83%.



         Includes annual  by-product credit.



         For ammonia  at  $110/ton.



         These technologies  could  be considered  as  part  of the  process rather than pollution control.



       Source-   DRI estimates based on data  provided  by  WPA.

-------
                                TABLE 6.3-5.   DETAILS  OF SOLID WASTE MANAGEMENT COSTS,  STAKOARD ECONOMIC ASSUMPTIONS
Fixed Fixed
Charge Capital
Factor Cost
Control Identification (%) ($000' s)
SURFACE HYDROLOGY
Runoff Collection Sumps
Runoff Collection Pumps
Deep Monitoring Wells 12.49 858
Shallow Monitoring Wells 4,51 26
UJ Piezometers 4. SI 432
o
SURFACE STABILIZATION
Dust Suppression
Revegetation
Topsoll
Seed
Total Annual Direct
Working Capital Annual
Capital Charge* Op Cost
($000's) ($000's/yr) ($000's/yr)

5 1 63
1 <1 16
2 108
<1 1
1 20
923 192 11,079
1 <1 8
<1 — 2
.»..- w— t
Indirect Total
Annual Annual Total Annual Per-barrel
Op Cost Op Cost Control Cost Control Cost
($OQO's/yr) ($QOO's/yr) (lOOO's/yr) (cents)

(<1) 63 64 0.3
— ' 16 16 01
27 27 135 0 7
112 <0.1
14 14 34 02
(14) 11,065 11,257 54 3
— 88 <0.1
2 2 <0 1
1 1
* Includes fixed and working capital  charges   RW = 20 83%
Note   There are no by-product credits.
Source:   ORI estimates based on data  provided by SWEC

-------
6.3.2  Sens1ti vi ty Analyses

     This  section explores the sensitivity of  the results to changes in the
engineering costs and  economic assumptions.   In general, only a single change
from  the  standard economic  assumptions was  made  in  each  case,  enabling the
impact  of this change to be  isolated.   Table 6.3-6  summarizes  the changes
made  for each case,  while Table 6.3-7 displays the fixed  and working capital
charge  rates used  to calculate  per-barrel   control  costs.   Per-barrel  pol-
lution control costs,  expressed as a percentage of a $30 per-barrel shale oil
value, are given  in  Table 6.3-8.   Table 6.3-9 provides additional detail for
the  absolute  per-barrel  control  costs and  includes  percentage  changes from
the  standard  economic  assumptions.   Comparative results  for  the  various
sensitivity analyses are  presented graphically in  Figure 6.3-1.  No sensitiv-
ity analysis  has  been performed on the solid waste management costs, as only
partial  cost estimates  were available.   Each  sensitivity analysis  is dis-
cussed below.

     Twenty Percent Increase in Fixed Capital Costs—

     Cost  escalation  is  always a problem with  pioneer plants because of tne
numerous  uncertainties (Merrow,  September 1978; Merrow, Chapel and Worthing,
July 1979).   A 20%  increase is not at all unreasonable despite the inclusion
of a 20% contingency in fixed capital cost estimates.

     Table 6.3-9  shows that  a 20%  increase in  fixed  capital  costs  has  a
moderate effect on pollution control costs.  As would be  expected,  the more
capital-intensive  air pollution  controls  show the  greatest  increase.   The
total  air pollution  control  cost  increases by  15%  (16  cents  per  barrel),
while the total  water pollution control cost  increases by  8% (only 1 cent per
barrel).

     TwentyPercent Increase in Operating Costs—

     Operating costs  are often better defined than  capital  costs,  which is
why  an  operating cost contingency  is not normally  included in  the direct
annual operating  costs.   However,  there are  many  reasons why operating costs
could be higher than anticipated.   For example,  regional shortages of skilled
labor could  result in  higher  wages and  reduced  productivity.   Also,  labor
costs may escalate  faster  than  other costs.   Maintenance  costs could  be
higher than  expected,  and  both  utility requirements  and  utility unit costs
could deviate from expectations.

     For air  pollution controls,  the overall effect of an increase in direct
annual operating  cost  is  much  less than that of the same percentage increase
in fixed capital  cost.   For a 20% increase,  the  total air pollution control
cost  increases  by only 6 cents per  barrel  (a 6%  increase).   The  more oper-
ating cost-intensive total water  pollution control cost increases by 3 cents
per barrel (a 16% increase).   This is a reversal of the results obtained for
a 20%  increase  in fixed  capital  costs,  and  confirms  that the air pollution
controls are  much more capital-intensive than  the water pollution controls.
                                     304

-------
                                                     TABLE 6 3-6   ASSUMPTIONS FOR SENSITIVITY ANALYSES*







g
tn

Sensitivity Analysis
+20% Fixed Capital Costs
+20* Direct Operating Costs
+66 T% Utilities Costs
60% of Planned Output
Delayed Start-up
15* DCF ROR
Stand-alone Financing
Stand-alone Financing
»t 15% DCF ROR
+20JS Fixed Capital Costs,
DCF ROR
m
12%
12X
12%
12%
15*
m
15%
15*
Fixed Capital
Costs
Increased 209!
SEA
SEA
SEA
SEA
SEA
SEA
SEA
Increased 20%
Direct Operating
Costs
SEA
Increased 20%
UtiUty portion
increased 66 7%
Decreased 10%
SEA
SEA
SEA
SEA
SEA
Byproduct
Credits
SEA
SEA
SEA
Decreased 20%
SEA
SEA
SEA 7
SEA J
SEA
Comments




A 2-year delay was incorporated into the RC
and RW calculations by halting production in
Years 2 and 3 and resuming in Year 4 Project
life was Increased to 22 years

For RC and 8VJ calculations, investment tax
credit and depreciation earned in or before
Year 3 were accumulated and taken as a lump
sun 1n Year 3. The schedules after Year 3
remained unchanged
A 2-year delay was incorporated into the RC
  Delayed Start-up and
  15% DCF ROR
+20X Fixed Capital  Costs,
  Delayed Start-up, 15%
  DCF ROR and Stand-alone
  Financing      "
                                  15%
                                              Increased 20%
                                                                         SEA
                                                                                              SEA
and RW calculations by halting production in
Years 2 and 3 and resuming in Year 4   Project
life was increased to 22 years

A 2-year delay was incorporated into the RC
and RW calculations as above, and the
investment tax credit arid depreciation were
accumulated to Year 5
* SEA indicates that the costs are the same as  those used  for analysis  based on  standaid  economic  assumptions

Source-   DRI.

-------
                                                      TABLE 6 3-7   CHARGE RATES F0« SENSITIVITY ANALYSES
w
o
Sensitivity Analyses
Standard +20% Fixed +20* Direct +66 7% 80% of
Economic Capital Operating Utilities Planned Delayed 15% Stand-alone
Assumptions Costs Costs Costs Output Start-tip OCF ROR Financing
Hxed Charge Rate
Retort Timing 16 17 16.17 16.17 16 17 16 17 19 52 20 92 18.52
Mine Timing 15 61 15 61 15 61 15 61 15,61 19 23 20 06 17,81
Early Water
Management 21 i4 21 64 21.64 21 64 21 64 26 66 30 01 26 82
Catalytic
Converters 23 36 23 36 23 36 23 36 23 36 26 46 27.03 25 14
Working Capital
Charge Bate 20.83 20 83 20 83 20 83 20 83 20 96 25 58 20 83

Contained
Stand-alone Assumptions »*ith
Financing at Combined Stand-alone
15S DCF ROR Assumptions3 Financing
24.31 26 94 33 92
23.23 25 82 32 S3
37.62 38,63 51 89
29 53 31 91 38.91
25 58 25 80 2S.80
  Combined assumptions ara 20%  increase In  fixed capital costs, 15% DCF ROR and delayed start-up



  Refer to Table 6,2-2 for pollution controls  included  in each category



Source   DRI

-------
               TABLE 6.3-8.  SENSITIVITY ANALYSES EXPRESSED AS
                       A PERCENTAGE OF SHALE OIL VALUE
                                           Per-barrel Control Cost as a
                                       Percent of ISO/Barrel Shale Oil Value
Sensitivity Analysis
Standard Economic Assumptions
20% Increase in Fixed Capital Costs
20% Increase in Direct Operating Costs
66.7% Increase in Utilities Costs
80% of Planned Output
Delayed Start-up
15% DCF ROR
Stand-alone Financing
Stand-alone Financing at 15% DCF ROR
Coirbined Assumptions*
Air
3.8
4.4
4.0
4.2
4.7
4.4
4.5
4.2
5.0
6.3
Water
0.6
0.7
0.7
0.8
0.7
0.7
0.7
0.7
0.8
0.9
Combined Assumptions with Stand-alone
  Financing*                                  7.5                1.0


* Combined assumptions are  20% increase in fixed capital costs, 15% DCF ROR
  and decayed start-up.

Soiree:   DRI.
     66.7%Increase inUtilities Costs—

     Operation of various controls  requires  inputs of electricity and steam.
Under  standard  economic assumptions,  electricity is  valued  at  3 cents  per
kW-hr, and it is  assumed that steam is generated at a cost of $3/MMBtu.   The
electricity charge  of 3 cents  per  kW-hr may  very likely  underestimate  the
true cost of  power  purchased from the grid  (should  this  prove necessary) as
it  is  a  compromise value between plants  that  can sell power  and those  that
must purchase power  (see Section 6.1.1).   Since the  Lurgi-Open  Pit  plant is
likely to require electricity  from  outside sources,  a 5 cents per kW-hr  rate
(a 66.7% increase) was  considered.   At the same time,  the cost of  steam was
also increased by 66.7%, as  the standard rate  for this input  of $3/MMBtu may
also prove  to be conservative.  Three  dollars per million Btu  is a typical
1S80 value used for  heat inputs in  engineering studies, but no detailed  cost
evaluation was  conducted for  this  manual.  Hence,  the  steam cost pust  be
considered uncertain.
                                     307

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                TABLE 6.3*9.  SENSITIVITY ANALYSES BY MEDIUM

Air Pollution
Control
Sensitivity Analysis
Standard Economic Assumptions
20% Increase in Fixed Capital
Costs
20% Increase in Direct Operating
Costs
66.7% Increase in Utilities
Costs
80% of Planned Output
Delayed Start-up
15% DCF ROR
Stand-alone Financing
Stand-alone Financing at
15% DCF ROR
Combined Assumptions*
Combined Assumptions with
Stand-alone Financing*
cents/bfal
115
131
121
126
140
131
136
125
150
188
224
% change
—
+14.8
+5.6
+10.2
+22.0
+14.3
+18.5
+8.8
+31.2
+64.2
+95.9
Water Pollution
Control
cents/bbl
10
20
22
24
22
20
21
20
23
26
30
% change
--
+8.1
+16.0
+28.6
+20.2
+8.1
+12.9
+6.7
+22.7
+39.4
+61.1

* Combined assumptions  are  20% increase in fixed capital costs, 15% DCF ROR
  and delayed start-up.

Note;  Percentage changes may  not agree with  figures  calculated  from cents
       per barrel due to rounding.

Source:  DRI.
     The  results  indicate that utility costs  constitute  a moderately impor-
tant component of pollution control costs.  The total water pollution control
cost increases by  28% (5 cents per barrel).  This increase can be attributed
to the  large  quantities  of steam required by the ammonia recovery unit.   The
effect  on air  pollution  control  costs  is less  significant  (although  the
absolute  increase  in  costs  is  greater).  The  66.7% increase  in utilities
costs causes  the total  air pollution control  cost to rise  by 10% (11 cents
                                     308

-------
o
ID
             2 50
             2.00
              I SO
              !00
               SO
        8

        2*
        o
                       us
                                               I 21
                                               0.50
                                                            1.26
                                                            055
140'
                                                                        051
            131       , _ 1.36 _L
                      \77~77Tt       "25
                                                                                     043
                                                                                                 044
                                                                                                              0.43
                                                                                                                          I 50
                                                                                                                          044
                                                                                                                                      188
                                                                                                                                      0.4T
                                                                                                                                                   2.24
                                                                                                                                                  0.4T
               .50 r
n IQ A 9ft (K22
g-yy-7-* I/1 y y > / A KS/.S^
1 0»2 1 | 012 1 1 015
SWOARD 20%1NOJEASE 20%INCREASE
ECONOMC INFIXED INDIRECT
ASSUMPTIONS CAPITAL OPERATING
COSTS COSTS
024
s..s's_jf i
017 1
66.7%
INCREASE IN
UTILITIES
COSTS
Q22~-
014
PLANNED
OUTPUT
" 020 0,21 020 °-2J
1.012 1 1 012 I 1 012 1 1 012
DELAYED 15% STANO- STAND-
START- OCF ROR ALONE ALONE
UP FINANCING FINANCING
AT 15%
OCF ROR
026
j 012

030
////
012
COMBINED , COMBINED
ASSUMPTIONS ASSUMPTION
WITH
STAND-ALON
FINANCING
                 L/J TOTAL CAPITAL CHARGE


                 |   [ TOTAL OPERATING COST


                    * COMBINED ASSUMPTIONS ARE 20% INCREASE IN FIXED CAPITAL COSTS, 15% OCF fiOR AND DELAYED START-UP

          SOURCE: Dftl
                                   FIGURE 6 3-1  SENSITIVITY ANALYSES   TOTAL PCR-BARREL AIR ANDWATFR POLLUTION CONTROL COSTS

-------
per  barrel).   This  increase  is  due -largely  to the  significant  amounts of
electricity  requ-ired"to  operate  the electrostatic  precipitators  and fabric
filters.                         '   •-'*    ' -         - '  '  '

     E1ghty  Percgnt of  PIanned Output—

     A  frequent  problem  with pioneer  process  plants  is that  they  fail to
achieve  their planned output.   Occasionally they produce more.  When a plant
fails to reach its planned output,  the  annual  fixed capital charges must be
spread over  reduced output, and the  direct annual operating costs decrease by
a  lesser proportion  than the output because  some  components (such as main-
tenance) are virtually  unchanged.

     For the case  of a  plant that achieves only  80%  of planned output, it was
assumed  that direct annual operating costs fall  to 90% of the full production
costs.   Production in the start-up years and by-product credits were prorated
to 80% of the  standard  values.

     Overall,  the  results  are  relatively  severe,  with the more capital-
intensive  air pollution  controls  showing the  greatest increase.   Total  air
pollution control  cost  increases  22% (25 cents  per  barrel),  while the total
water pollution control cost increases 20% (3 cents  per barrel).

     De 1 ayed _Sta_rt-_up—

     Because of the  time-value  of  money  implicit  in the discounting proce-
dure,  anything  that delays   or  curtails production raises  annual  capital
charges  and,  hence,  the per-barrel  control  cost;  conversly, anything that
accelerates  or extends  production reduces the costs.

     For  this analysis,  production  is  halted for two  years  (Years 2 and 3)
and  then follows  the  normal  build-up profile displaced  by  two  years.    (The
project  life is extended by 2 years to  22 years.)   This  profile corresponds
to  the   scenario  that  the  plant  initially starts  production  according to
schedule;  then,  at  the  end   of  Year I,  the  plant  is closed  down because
serious  operational  problems  have developed and must be  solved, which takes
two years.

     The effects  of  this  case are only  moderately  severe.   Total  air pollu-
tion control cost increases  14% (16 cents per  barrel).   The less capital-
intensive  total  water  pollution  control  cost  increases by 8% (1 cent  per
barrel).

     Fifteen Percent DCF ROR--

     The minimum  acceptable DCF  ROR used in a  project feasibility study is
normally  not  divulged  by developers  and,  in  any  event,  is influenced by
alternative  investment  opportunities and  other factors.   However,  there is
broad confirmation that  a  rate  between  12%  and 15% per annum  (in constant
dollars) is  appropriate for evaluating oil shale investments  (Denver Research
Institute, et al., July 1979;  also  see  Merrow, September 1978).   This ROR,
which is  called  a "hurdle  rate,"  is  higher than the  return that a company

                                     310

-------
 actually  earns  on its  capital  for  a number  of reasons.   First,  it  is  an
 unfortunate fact  of   life  that many  projects  earn  less  than the  projected
 "ate  because  things  do  not work  out  as  expected.   This  is  only  partly
 offset  by the few that  do  better than anticipated.  Second,  project evalua-
 tions  do  not usually  include  such costs  as  R and D,  exploration,  and reserve
 acquisition;  also, they  may not  include recovery of some  general  corporate
 expenses.

     The  single  most  important  factor  that influences the  required  DCF ROR  is
 the  perceived riskiness of the project.   A  high risk project  is expected  to
 pass a  higher ROR  hurdle  than a low risk  project.   Some  of the  types of risks
 that might be subjectively taken into account  in selecting  a  minimum accept-
 able 30R  for a mining  project in  the U.S. include:

     »     Unproven technology (and, hence, uncertain  equipment  costs);

     «    Geologic uncertainty;

     «    Very large  investments  in relationship  to total  corporate  assets;

     «     Rapid  inflation in some cost components;
     «     Long construction and start-up  periods;

     «    Narket uncertainty;

     •    Regulatory uncertainty  (leading to delays or added costs);  and

     *    Difficult working 'condition's"or adverse,socioeconomic impacts
          leading to manpower problems.  .'


     For any first generation commercial  synfuef plant,.: all 'the -above  factor's
 are  present,  with the  possible exception of geologic  uncertainty.   At this
 time, most  of  these  factors are strongly present in  oiil shale projects.  The
 standard  economic  assumption is  12%  DCF ROR,  which  is probably  the  lowest
 acceptable  ROR for a' private enterprise  shale'oil plant with proven technol-
 ogy.  For a pioneer  plant,  industry  is  likely to  require at least 15% ROR,
 unless  it  wishes to  "buy into"  a new  industry.   Of course,  if another  party
 (e.g.,  the  Federal government)  were  prepared to share the risk in some way,
 the  required ROR  would  be reduced.   Even  though  spine  of the  risks listed
 above do not apply to'pollution controls,  Industry does: not perceive environ-
 menta"   costs to  be separable from the  total project.'  Hence,  all  components
 o* a project, including  pollution controls,,must earn the specified DCF RQR.
                                                      i
     Increasing the required  DCF  ROR  from 12 to 15% has a substantial effect
 on  pollution control  costs.   Once  again, air pollution controls  show the
 greatest  increase.  The total  air  pollution control  cost increases  by 19%
 (21 cents per barrel), while th« total  water pollution control cost increases
 by 13% (or 2 cents per barrel).

     Stand-alone Financing—

     The  term "stand-alone  financing"   is  used  to  describe  a  project  in
which  investment  tax credits  and  allowances   for  depreciation  cannot  be
passed  through  to a  parent company  (or  companies)  which can benefit from


                                     311

-------
them  immediately.   {These  benefits  are  treated  as  negative Income  tax in
conducting the alternative "pass-through" form of prdject evaluation which is
used  under  standard economic assumptions,)  Instead,'it is necessaryfor the
project  to  become  profitable before the tax benefits can be obtained.  It is
difficult to  determine when this might occur  because it requires a detailed
knowledge of  the overall  project economics; in  any  event,  the timing of the
benefits will be affected by the selling price of the shale oil.   However, it
is  known that some of the developers  are  assuming stand-alone financing for
their  evaluations  since it  more closely  reflects their tax  positions  than
does pass-through financing.

     To  'determine   the  approximate  effect   of  substituting   stand-alone
financing for pass-through  financing,  it was assumed  that  no investment tax
credit or depreciation could be claimed until  the third year of production,
i.e., the first  year  of full output.  This assumption was  based on examina-
tion  of  the  cash flow analysis  for an open pit  mine with  surface retorting
presented in  a  recent oil  shale tax  study (Peat, Warwick,  Mitchell  &  Co.,
September 1980).   It  must be  emphasized  that  this  assumption is  very  sim-
plistic  (and  probably conservative),  since the relevant details  in  the tax
study  were  significantly different  from  those  assumed in  this  manual.   As
expectedj the effect  was  larger for the more capital-intensive air pollution
controls, although the overall effect for both control groups is  fairly mild.
Total  air  pollution  control  cost  increases 10 cents  per barrel  (9%),  while
the total water  pollution  control  cost increases  1 cent per  barrel (7%).  A
more   refined calculation   might   yield   substantially  greater  Increases.
especially  if a  low,  value  was used for  the  price of shale  oil,  thereby
reducing profitability,

     The effect  of  stand-alone financing  was also evaluated  at  15% DCF RQR,
using  the same -assumptions  as above.  This probably comes closer to a devel-
oper's evaluation.  The resulting  increases in  costs  are quite  substantial,
with  the total  air  pollution  control cost  increasing 35 cents  per barrel
(31%)  and  the  total   water  pollution control  cost  increasing  4  cents  per
barrel (23%).

     Combined Cases—

     Two  combined  cases  were evaluated  using  the  components  already  dis-
cussed.  However, it  is  not sufficient to construct these analyses by simply
combining the results  from  the earlier findings, so new analyses were devel-
oped.   The two cases are as follows:

     Combined assumptions


     *    20% increase in fixed capital costs
     *    Delayed start-up
     »    15% DCF ROR
     »    Everything else as standard economic assumptions.
                                     312

-------
     Combined assumptions with stand-alone financing

     *    20% increase in fixed capital costs

     ®    Delayed start-up

     «    15% DCF ROR

     *    Stand-alone financing

     •    Everything else as standard economic assumptions.

     These combined  cases  are  intended to be quite plausible adverse scenar-
ios  (i.e., 20%  increase  in fixed capital costs  and  delayed start-up) looked
at  *rom industry's  viewpoint (i.e, 15% DCF ROR, with  or without stand-alone
finarcing, depending on the company),

     The  results  indicate  that these cases would  impose significant burdens
on  industry.  The more capital-intensive air pollution  controls increase in
cost by  64%  (73 cents  per barrel) for regular ("pass-through") financing and
by  96%  ($1.09 per barrel)' for stand-alone financing.  Total  water pollution
control   cost  rises  approximately  39% (7 cents  per  barrel) for  the regular
case and 61% (11 cents  per barrel)  for the stand-alone case.   The absolute
level of pollution  control  costs  reaches  $1.88 per barrel for  all  air cen-
tre's and 26 cents  per  barrel  for water pollution controls  for the regular
(pass-through)  case.   For  combined  assumptions with  stand-alone financing,
absolute  pollution  control  costs  are  $2.24 per  barrel for  total   air  and
30 cents  per  barrel 'for total  water.   -These  results  represent an almost
doubling of tha absdlute- cost of air pollution controls.
     Returning  to  Table 6.3-8, it  can be  seen  that the  total  cost  of  air
pollution control is roughly 4% of the assumed $30 per-barrel value for shale
oil  under  the   standard  economic  assumptions.   The  total  water  pollution
contra", cost is roughly 0.6% of the value of the oil.

     With respect  to air  pollution controls,  only the two  sets  of combined
assumptions produce  major  increases in cost.   In these two  cases,  the total
control cost  reaches 6.3  and  7.5% of  the  assumed $30 value  for  shale oil.

     Water  pollution control  costs  have  proven to  be  less sensitive  to
changes in the engineering costs and economic  assumptions.   Only the last two
sensitivity analyses  (the  two  sets of combined assumptions)  produce  notice-
able increases  in total water  pollution control costs.  From  a  base  of 0.6%
of the  shale  oil value under  the standard economic assumptions, water pol-
lution  control  cost  rises no  higher than  to 1.0%  of the oil value  (for
combined  assumptions with  stand-alone financing).  When  compared with  air
pollution control costs, water  control costs are more  sensitive to changes in
direct operating costs and utilities,  as opposed to changes that affect fixed
capital charges.   Increases in direct  operating  costs and  utilities  costs,
however, do not  produce significantly larger  increases in  total  water pollu-
tion control costs  than those sensitivity analyses which affect fixed  capital
chs^ges.


                                     313

-------
     Figure  6,3-1  sftl'its  the pollution control costs  Into'a per-barrel total
.capital  charge and  a per-barrel  total -operating cost.  This  figure effec-
tively  illustrates  the  response  of capital-intensive  controls  (air)  vs.
operating  cast-i-ntensive  controls   (water)   to  the   different  sensitivity
analyses.

6.4  DETAILS OF COST ANALYSIS METHODOLOGY

6.4.1  CostAlgorithms

     This  section  provides the algorithms  used to calculate total annual and
per-barrel control costs and capital  charge factors.

     Calculation of  Total  Annual  and  Per-barrel Control Costs—

     The totalannual Control cost (TC) of  each item considered for pollution
control  is the sura  of the  total annual operating cost  (TOC)  and the total
annual capital charge (CC).  That is:

               TC  = TOC + CC

     and       TOC = DOC + IOC

     where:           DOC = Direct annual operating cost
                      IOC = Indirect annual  operating cost

     and       CC  = (FCC  x RF) + (WC x RW)

     where:           FCC - Fixed  capital cost
                     WC  = Working capital
                      RF  = Fixed  charge factor
                      RW  = Working capital  charge factor


     The cost per barrel (CPB) is  the total annual cost divided by the normal
annual production, i.e.:

               CPp = TC -r  (BPSD x 328.5)

     where:          BPSD  = Barrels per stream day

The factor, 328.5, is the  number  of normal  operating days per year.


     The derivation  of each cost  component  is explained below.

     Direct annual operating cost.   DOC  is a  data input  derived  from  the
engineering  cost  analysis.  It is  the  annual  cost for a normal  year and is
taken from one of the data Tables 6.1-1, 6.1-2 or 6.2-3.

     Indirect annual operating cost.   The  indirect  annual  operating  cost
(IOC) is calculated  as follows:


                                     314

-------
                IOC = TIA +  ESC  -  STC  -  BP

     where:          TIA =  Annual  property tax and insurance allowance
                     ESC =  Annual  extra start-up costs  (levelized—see below)
                     STC =  Annual  severance tax credit  (levelized--see below)
                     BP  =  Annual  by-product credit

BP  is an  input  generated from stream  data  and shown In  one of the tables in
Sectien 6.3, and:

                TIA = 0.03 x FCC

                ESC = (0.03  x FCC  + 0.20 x  DOC) x LFAC1

                STC = 0.04 x [(DOC + ESC +  TIA - BP) + 0.05 x FCC] x LFAC2

     LFAC1 and  LFAC2 are levelizing factors  that spread ESC and STC uniformly
over all  units  of production*   LFAC2  also  makes adjustments for the severance
tax  exemptions  allowed for low  production.   These factors  are as  follows:


                              (1 -f r)-1
          LFAC1 = 	•	•	
                   0-56  ,   0.83    .  ^20    1
                        "** > ^  ,  v o "*"
                  1 + r   (l^F   nf3  (1 + r)n
                                 (1 + r)"1

                   0.56     0.83     (1 + r)~2 - (1 + r)"20
                  1 + r   (1 + r)2             r
          LFAC2 = BPSD - 10,000
                      BPSD
          1 v   0-83 _ .  1 v    1     .  3 „    1      . (1 f r)-4 -  (1 +
          4 x (1 + r)2   2 x (1 + r)3   4 x (1 + r)4             r

                    0.56     0.83     (1 -t- r)"2 - (1 -t- r)'20
                   1 + r   (1 + r)^             r
     where:          r = Discount rate = DCF ROR
                  BPSD = Barrels per stream day (i.e., normal daily output)

A  numerical  example of  a  levelizing calculation is  giv«n  in Section 6.4.3.

     Capital costs.   Fixed capital  cost (FCC) is an  input  taken from one of
the data tables.  Working capital (WC) is calculated as follows;

            ... .WC * 1/12 x TOC + 1/4 x BP

                                     315

-------
     Capital.ChargeFactors*- '  ,   ,  * '

     The'fixed charge factor equation is:
0C S

N
2 [(1 + r) x (K - T x 0
n=J n n
N
(1 - T) I [(1 * r)"n 0 ]
n=l
-cn)]

     where:          K  = Capital expenditure in year n (I K  = 1.000)

                     C  - Investment credit in year n

                     0  = Depreciation in year n

                     0  = Operating income in year n (0  = 1.000 in a normal
                      n   year)                        n

                     r  = Discount Rate = DCF ROR

                     T  ~ Tax rate

                     N  = Last year of project

                     J  = First year of project (i.e.,  -3)

Note that the first year of production is Year 1.

     The same equation is used to determine the working capital charge factor
(RW), except that the D  and C  terms are omitted,

6.4.2  ExampleCalculation of a Fixed Charge Factor

     Table 6.4-1 provides  an example  of the calculation  of a  fixed charge
factor.   The  data  used  are  for  retort  timing,  using  standard  economic
assumptions (see Table 6.2-2).

     The  following  is  an  explanation  of  the   calculations  in the  table.
Expenditures are  shown negative,  while  income (and taxes  avoided)  is shown
positive.  Column  [2]  is  a schedule of  capital expenditures to be made over
a  three-year period.,  totaling  an  arbitrary $1,000.   (Unit  value  is  used
instead  of  $1,000  in  the  equation above.)   Columns  [3],  [4],  and  [5] deal
with allowances  associated with  this  capital expenditure.   Column  [3] is a
schedule of  depreciation,  commencing  in Year 1 when the asset is placed into
service.   Column  [4]  gives the  value  of the  depreciation allowed  to  the
company.  This value is  the income tax  not  incurred  as a consequence of the
depreciation deduction, and  it is 48% of  Column  [3].   Column [5]  is the 20%
investment tax credit  available  in each year a capital  expenditure is made.
(This  is  a direct  credit against  tax  and does  not have to  be  multiplied by
the tax rate,)

     Column [6]  represents  the  income  stream  resulting   from  the  $1,000
investment  (Column  [2]).    Income  in  a  normal,  full  production  year  is

                                     316

-------
                                                TAB1C 6,4-3    EXAMPLE OF FIXED CHARGE FACTOR CAICUIATTOH
                                                     (Standard Fcftnomlc Assumptions,  Retort Timing)
Year
[11
-2
-1
0
1
2
3
4
5
e
7
8
9
10
11
12
13
14
15
1$
17
18
19
20
Gross
Capital
[2]
(ioo. oo)
(300.00)
(600.00)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0,00
0 00
0.00
0 00
0.00
0,00
o.oo
0 00
0.00
d oo
(1,000 00)
	
Depreciation
Amount
[3]
0.00
0.00
0.00
117.65
110. 29
102 94
95.59
88.24
80.88
73.53
66.18
58.82
51 47
44.12
36.76
29,41
22.06
14.71
7.35
0 00
0 00
6 00
8 00
l.QOO 00
Allowances

Depreciation Investment
Value @ 48% fax Tax Credit
[4] [b]
0 00
0.00
0.00
56.47
52.94
49.41
45.88
42.36
38.82
35.29
31 77
28 23
24.71
21 18
17,64
14.12
10 59
7,06
3 53
0.00
0.00
0 00
0.00
480.00
20.00
60.00
120.00
0.00
0.00
0.00
0 00
0.00
0.00
0.00
0.00
0.00
0.00
0,00
0.00
0 00
' 0.00
0.00
0 00
0 00
0 00
0 00
0 00
200 00
Operdtj
Gross
[6]
0 OOx
O.OOx
0 OOx
O.S6x
0 83x
l.OOx
l.OOx
1 OOx
l.OOx
l.OOx
l.OOx
1 OOx
l.OOx
l.OOx
1 OOx
l.OOx
l.OOx
l.OOx
1 OOx
l.OOx
1 OOx
1 OOx
1 OOx
jig_ Income
Net After
48% Tax
[7]
0 OOx
O.OOx
O.OOx
0 291x
0 432x
0 520x
0.520X
0 520x
0 520x
0. 520x
0 520x
0 520x
0 520*
Q.5ZOX
0 520x
0 520x
0 520x
0 520x
0 520x
0 S20X
0.520X
0 520x
0 520x
Net Present Values
Discount Factors After-tax
at 12% Income*
[8] [9]
1 2544
] 1200
1 0000
0.8929
0 7972
0,7118
0 b355
0 5674
0 5066
0 4523
0 4039
0 3606
0 3220
0.2875
0 2567
0 2292
0 2046
0 1827
0 1631
0 1456
0. 1300
0 1161
0 1037
0. OOOOx
0. OOOOx
0 OOOOx
0.2600X
0 3441x
0.3701X
0.3305X
0 29Slx
0.2634X
0 2352X
0 2100x
0 1875x
0.1674X
0 1495X
0.1335x
0. 1192X
0 1064x
0.0950X
0.0848X
0 0757x
0 0676x
0 0604X
0 0539x
3 6093X
Depreciation
Allowance
[10]
o.oo
0.00
0.00
50.42
42 20
35.17
29.16
24 03
19.67
15.97
12.83
10.18
7.95
6.09
4 53
3.24
2 17
1.29
0.58
0.00
0 00
0.00
0.00
265.48
Investment
Tax Credit
[11]
26 09
67 20
120. 00
0.00
0 00
0 00
0 00
0 00
0 00
0 00
0.00
0.00
0 00
0.00
0.00
0.00
0 00
0.00
0 00
0.00
0 00
0 00
0 00
212.29
Capital
C123
(125 44)
{336 00)
(600 00)
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0 00
0.00
0 00
0 00
0,00
0 00
0 00
0 00
0 00
0 00
0 00
(1,061 44)
'
* After-tax Income  is  before  depreciation  allowance  and  investment  tax  credit

Sourc.e   DR1

-------
 designated  by  1ll,Q0x, " •  Since  income 4s  proportional  -to  production,- and
 production in the startup years  is Jess- than full  production, the  first two
 years of income  are  appropriately  reduced',  f;e.,  0.56x  in Year 1  (0.56  is the
 50% operating factor  in Year  1  divided by  the 90%  factor  for a  normal year)
 and 0.83x  in  Year 2,   Column £7]  shows  the  residual  income to the company
 after income tax is  paid on the  income in Column  [6].

      The 12% discount factors in  Column  [8] are  used to generate the present
 values in  Columns [9],  [10],.  [11] and [12].  After summing the columns of
 present values  of  after- tax   income,  depreciation  allowance, investment tax
 credit, and capital  expenditure,  an equation is  constructed  to determine the
 gross income, x,  which must be generated by the $1,000  of invested capital to
 achieve a 12% DCF RQR; thus:

               3.6093x = 1,061.44  - 265.48  - 212.29

                  [9]   =   [12]    -  [10]   -  [11]


      therefore:     x  =           =  161.71


      (x  represents  the gross  income in   a  full   production  year  that is
      necessary  to provide the  specified  DCF  ROR,  12%,  on  $1,000  of fixed
      capital.)
     hence:    RF =     '   = 16.17%
6-4,3  Cost Level i zing Calculations

     While  most direct  operating  costs vary  in  proportion to plant output,
the  operating Costs  for solid waste management do  not.   A prime example of
this  is  the cost of  surface reclamation, which only occurs at the end of the
project.   To   spread  these  costs  in  a pattern consistent with -production,
these operating costs are transformed into an annual figure which can then be
applied  to  each barrel  of shale oil produced.  This is done by calculating a
"levelized cost" for a normal year's production.  This technique is also used
to  spread the  extra  start-up  cost  and severance tax  credit uniformly over
shale oil production.

     A  "levelizing  factor"  is  used to  make  this transformation.   The fol-
lowing equation  shows how a levelizing  factor  is  used  to arrive at a level-
ized cost (i.e. 5 a stream of payments having the same profile as production),
given the present value of a nonuniform  stream of payments:

               i   -]•,!/.+_ I(Present Values of a Cost Stream)
               Level! zed Cost -- Levelizing Factor - ~

By dividing the  levelized cost by a normal year's output, a cost per unit of
production is derived.

                                     318

-------
     The equation for calculating the 1 eve!izing factor (LF) is;


               LF = PVFA(r,N)  -


     where:          LF ~ Levelizing factor

                     PVFA,  N^ = Present value factor of a uniform series of
                         ^r> '   payments for N years
                     PVF,   ^  = Present value factor of a single payment in
                        tr'nj    year n
                     r  = Discount Rate = OCF ROR
                     N  = Number of production years

                     S  = Number of years in the start-up period
                     n  - Any specific year in the start-up period

                     L  - The proportion of normal  output during any given
                      n   start-up year; the series of L  values constitutes
                          the "start-up profile"

     The  second  term  on the  right-hand  side  of the  above equation  is  an
adjustment to the  uniform  series  represented by the first term.  The comple-
ment of  the  L   figure  (i.e., that  portion of each start-up  year  which  is
less than  full  production)  is discounted, summed, and then' subtracted from
the uniform  series.  Since  the start-up years have high  present values, the
effect of  subtracting  this  term  has  a substantial impact on  the levelizing
factor.  Because  the  levelizing  factor  is the denominator  in  the  equation
which determines the levelized cost (and,  hence,  the unit cost), this adjust-
ment term raises tne per-barrel cost.

     Cost_ Levelizing Example—

     To illustrate the concept of cost levelization,  calculation of  the 12%
OCF ROR levelizing factor used in  this manual  is  presented below:
                  Proportion of
     Year       Normal  Output (L )        PVF i  12%       (1~Ln) * PVF

       1              0.56'                 0.8929             0.3929
       2              0.83                 0.7972             0.1355
       3              1.00       ^

                                  >        5.7793             0.0000
                                  I
      20              1,00       '         	.             	
                                           7.4694             0.5284

     Hence:     LF(r=12%>  ^ yrs)  = 7.4694 -  0.5284 = €.9410

(Note that all  present  values are  expressed with respect to Year 0)


                                   • 319

-------
     This factor is. the same as the denominator "in the .levelizlng expressions
LFAC1 and HFAC2.  '

     As   an   illostration   of   a  levelizing  calculation,   consider   the
revegetation   costs  shown  in  Table 6.1-3.   These  costs are  incurred , as
follows:-

          Year 19:       $185,000

          Year 20:       $185,000

          Year 21:       $185,000

     The present  value of these costs, expressed with  respect to Year 0, is
calculated as  follows:

          Year     Expenditure      PVF § 12%      Present Values

           19        $185,000          0.1161

           20         185,000          0.1037

           21         185,000          0.0926
     Thus,  $57,794  is the  present value of all  the  revegetation  costs.   To
turn this  into  a cost that  is  distributed  uniformly  with respect to output,
it must be divided by l^r=12%t N=20 years).
                                 C7 704
     Therefore, Level ized Cost = g 9410 = $8>326

     Thus, $8,326 (rounded to $8,000 in Table 6.2-3) is the annual cost, in a
normal  production year,  that  is  equivalent to  the irregular  cost profile
given  above.   This direct  annual  operating cost can be  used  in conjunction
with  the  algorithms given  in Section 6.4.1 for  calculation of  total  annual
control cost  and per-barrel  control  cost, whereas  the  irregular  stream  of
expenditures  from which it was  derived could not be used  with  the standard
methodology.

     In summary,  cost  levelization  redistributes a cost series  that  is not
proportional  to  production in  such  a  way  as to yield  an  equivalent  series
that is proportional to production and has the same economic value.
                                     320

-------
                                  SECTION 7

                     DATA  LIMITATION AND RESEARCH NEEDS
     A  number  of  limitations  associated with  stream  characterization  and
 pollution  control  technology performance were  identified in  the data  base
 during  the  preparation of  the Pollution  Control  Technical  Manual  for  the
 Lurgi  oil  shale  retorting  process combined  with  open pit  mining.   It  is
 important  that users  of this manual  be aware  of  these limitations.  It  is
 also important  that these limitations be addressed prior to development of  an
 oil  shale  facility   of  the  magnitude  analyzed   in  this   manual  (e.g.,
.119,000 TPSD   oil  shale  mined,   193,000 TPSD  total   solids  mined,  and
 63,1*0 BPSD  shale oil produced).

 7,1  DATA  LIMITATIONS

     The description of  the  Lurgi retorting process and  information regarding
 applicable  control  technologies,  performance,  and costs used to prepare  this
 manual,  were obtained  from  reports  on the operation  of  pilot Lurgi  retorts,
 vendor  descriptions,  and engineering  calculations  used  in  conjunction  with
 experience  transferred  ,from  analogue  industries  such  as   the  petroleum,
 utility,  , and  -mineral   mining  industries  which  utilize  similar  control
 technologies.   Until  "hands  on" experience is obtained from commercial-scale
 oil  shale  operations,  these  sources constitute the best available data base.
 However,  the  limitations  of  this  data base  should be  clearly understood.
 Pilot retorts were  built and operated primarily to improve process design and
 not  for demonstrating operation of a commercial~sized retort with attendant
 pollution  control  systems.   Many pollution  control  systems  have  never  been
 pilot tasted with an  oil shale retort.  Even  for those  control systems  that
 were pilot tested,  often the data collected have been very limited.

     The  primary  experience  with  Lurgi  retorting involves  two pilot plants
 (5 tons/day and 25  tons/day) and several laboratory-scale retorts operated  in
 West Germany during the past few years.  Shales from Tract C-a,  Tract C-b,
 and  the  Colony  mine   in  Colorado  have  been processed  recently,   and  the
 available  data  from these tests have been used in this manual.  A full-sized
 Lurgi retort is expected to  process 8,800 TPSD of raw shale, and 13 of these
 retorts will be needed to produce 63,140 BPSD of shale oil.   This represents
 an  enormous  scale-up  of the pilot retorts;  therefore,  improvements  in  the
 retort design  and operating  parameters  may be inevitable, resulting  in some
 uncertainty  about  the  stream  compositions   and  performance  of  control
 technologies.

     Variations in the grade of the shale also introduce  modifications to the
 operating  parameters  and,   hence,   the  data.   This is  evident  from  the


                                     321

-------
 retorting   tests  on  the  oil  shale  from Tracts C-a  and  C-b»  from which
 significantly  different results were obtained.   Thus,  a> Tinea-r extrapolation
 of  the  data  from  these  operations may  not be entirely  applicable  to the
 processing  of  shales  from  other  locations,  and  a direct  transfer  of the
 information to other  development sites  must be made  with  caution.

      It  should  also  be  noted  that,  to  date;  the Lurgi  pilot plants have
 consisted' of  the retort  and'  flue gas  discharge   system  only;"  Other unit
 processes   
-------
regarding characterization of  streams  and control technology performance, as
revealed during  preparation  of the  Lurgi-Open Pit  PCTH,  are  identified in
Table 7.1-1.   The  status of the  information  is  presented according  to  the
development  stage  of  the  source  and  technology.   The  specific  information
sources are also identified.   A reliability or confidence ranking is assigned
to i.he data  for  each stream and technology  based  on a subjective evaluation
of the direct applicability  of the data to a commercial-scale Lurgi-Open Pit
facility.   Some  salient  features  and  caveats in  the information base  are
noted, and  specific  research  needs  are  identified  to overcome  some  of the
data 'imitations.
                                    323

-------
                                                      TABLE 7,1-1.   BATA LIMITATIONS AND RESEARCH NEEDS
Streams, and Control
Technologies
(Hgure No.)
                   Pollutant
                   Controlled
Information
  Status"
Information
        >
Sources'5    Reliability1
Parti culate EIBIssions
TFFzT 3 3-10)
     Baghouses
     (3 3-2)
                   Participates
                   (point source)
                                    fi,H
                                                     10,U
Water and Foam     Participates
Sprays             (fugitive)
(3 3-2, 3 3-10)
                                        G,H
                                                10,11
Retort Gas
(3 3-3,"3"3-4,  3  3-5)
                                                    Remarks

                                          The partleulate emission estimates
                                          have been calculated by using 
-------
                                                                          TABIE 7.1-1  (cent.)
      Streams and Control
      Technologies
      (Figure No )

           Stratford
           (3.J-6)
Pollutant
Controlled
             Information  Information
Status"
Sources'*    Reliability0
H,S
                G.H.I
              10,11
ro
      Lurgl FlueGas
        ~=
                                                                 Remarks
                           In this manual, the technology is
                           used to treat the acid gases obtained
                           during the retort gas purification

                           The operating experience with the
                           Lurgi retort gas is not documented

                           The technology has been tested
                           recently with the retort gas from a
                           pilot Modified In Situ retorting
                           experiment, but the data are not yet
                           available

                           The technology Is used commercially
                           in other industries at a scale
                           necessary to treat the Lurgi acid
                           gases

                           Non-BaS sulfur compounds (nay not be
                           recovered efficiently with the
                           technology

                           Excessive amounts of heavy organics
                           tend to deteriorate the reagents and
                           the quality of the sulfur product
                                                                                     Non-NHs nitrogen compounds may also
                                                                                     degrade the reagents
                                                                                                         Research Needs
                                                       Excessive amounts of C02 in the feed
                                                       may have an adverse affect on the HZS
                                                       removal  efficiency.

                                                       According to the vendor information,
                                                       an H2S renoval efficiency of 30 pprav
                                                       in the treated gas Is achievable with
                                                       a single absorber

                                                       The flue gas data have been obtained
                                                       from a pilot-scale experiment with the
                                                       Tract C-a oil shale
                                                                                                                             The operating data from actual source
                                                                                                                             testing need to be obtained

                                                                                                                             The pilot plant data need to be
                                                                                                                             obtained and the transferability of
                                                                                                                             the information to the Lurgi acid
                                                                                                                             gases needs to be verified.  Scale-up
                                                                                                                             data may also need to be obtained

                                                                                                                             Tiw technology transferability needs
                                                                                                                             to b« verified.
                                                                                The control efficiencies for COS,
                                                                                CS2, nercaptans,  etc ,  need to be
                                                                                determined.

                                                                                The impact on the efficiency of HaS
                                                                                removal due to the presence of
                                                                                condensable organics in the feed
                                                                                needs to be quantified

                                                                                The Impact of organic amines, HCH,
                                                                                etc., on the Stretford cheuicals
                                                                                needs to be quantified.

                                                                                The impact on the efficiency of H2S
                                                                                reatoval due to excessive amounts of
                                                                                COZ needs to be quantified.
                                                                                Scale-up data need to be obtained
                                                                                                                                       (Continued)

-------
                                                                           TABLE 7.1-1  (cent.)
       Streams and Control
       Technologies
       (Figure No )
Pollutant
Controlled
Information  Information
                      b
  Status0
                            Sources
                                        Reliability
CO
ISi
            Electrostatic
            PrecipHator
            (3  3-3)
                               Particulates
                                               G,H
                             10,11
                                                                 Remarks
                                                                                                         Research Meeds
                                          The S02 content of the flue gas is
                                          reported to be 30 pprav   This amount
                                          appears to be too low based oft the
                                          material and elemental balances.
                                          Adsorption of the SOg on the processed
                                          shale to form calcium and magnesium
                                          sulfates is given as the explanation
                                          for the low SOZ emission.

                                          Tfle NOx content of the flue gas is
                                          reported to be 300 ppmv.   Based on
                                          the material and elemental balances,
                                          this amount appears to be too low.

                                          Only 10% of the fuel-based nitrogen in
                                          the processed shale 1s reported to be
                                          converted to NOx, while 90% Is
                                          converted to elemental nitrogen.
                                          Approximately 50% of the fuel-based
                                          mtrogan is normally converted to NOx,

                                          Data on trace elements and several
                                          criteria pollutants are not
                                          documented.

                                          An electrostatic precipitator to
                                          remove the particulates from the flue
                                          gas has been suggested in the modified
                                          DDP for Tract C-a

                                          The operating experience with the
                                          Lurgi  pilot plant has been obtained.

                                          The technology is used commercially
                                          in the utility Industry at a scale
                                          necessary to treat the Lurgi flue gas

                                          The particulate removal efficiency
                                          depends upon the resistivity of the
                                          processed shale and the temperature
                                          of the flue gas stream

                                          Moisture in the flue gas  generally
                                          decreases the resistivity, thus
                                          increases the control efficiency.
                                                                                                                              The efficiency of SQ2 adserption on
                                                                                                                              the processed shale needs to be
                                                                                                                              determined.
                                                                                                                              The actual  NOx content of the flue
                                                                                                                              gas needs to be determined.
                                                                                                                              The conversion of th« fuel-based
                                                                                                                              nitrogen to NOx needs to be
                                                                                                                              quantified.   Also, the extent of
                                                                                                                              thermal  fixation of the atmospheric
                                                                                                                              nitrogen needs to be determined
                                                                                               The data on traci elements arid
                                                                                               criteria pollutants need to be
                                                                                               obtained from actual source testing.
                                                                                                                              Scale-up  data need to be obtained.
The technology transfarability needs
to be verified^
                                                                                                                              the  effect of variations -In the shale
                                                                                                                              grade  on  the resistivity of ttie
                                                                                                                              particulates needs  to  be quantified,
                                                                                                                              The relationship between the sioisture
                                                                                                                              content  of  the flue gas  and control
                                                                                                                              efficiency  needs to be studied.
                                                                                                                                        (Continued)

-------
                                                                          TABIE 7,1-1  {cent }
       Streams  and Control
       Technologies
       (Figure  No )
  ,.         Information  Information

Controlled     Status^      Sources
                                        Reliability4
            Fiberglass  Fabric   Participates    G,H,I
       Fugitive
       Hydrocarbons
ro
-4
            Floating Roof
            Tanks
            Maintenance
            Catalytic
            Converters
Hydrocarbons      I



                 G,H


Hydrocarbons     G,H
Hydrocarbons,    G,H
CO
       Gas  liguor
            Oil/Water
            Separator
            O.3-4)
Oils and
Greases
                G,H,I
                             10,11
                              10



                              10



                             10,11


                             10,11





                             10,11
10,11
                                                                 Remarks
                                                                                                         Research Needs
 (he fiberglass baghouses have a
 much higher temperature 1it«1t than
 conventional baghouses, but the
 operating experience with the Luigi
 flue gas is not documented

 The technology 1s used in other
 industries,  ft participate control
 efficiency comparable to that obtain-
 able vith conventional baghouses
 appears to be achievable

 The fugitive hydrocarbons are
 estimated from the properties of the
 oil products.

 Oouhle^sealed, floating roof storage
 tanks have bten provided for volatile
 product storage.

 Floating roof storage tanks are used
 commercially for oil storage

 Routine maintenance of valves,
 pumps, etc , is a commonly used
 operational practice to control the
 hydrocarbon leakage.

 All diesel-powered machinery is
 equipped with catalytic converters
 to control hydrocarbon and CO
 emissions   The catalytic converters
 are a commonly used technology.

 ThB'compasition of the gas liquor has
 been deterained from the pilot
 experiment with the Tract C-a shale

"The operating experience with the gas
 liquor is not documented
                                                                                     Ttip technology is used commercially
                                                                                     in other  Industries.
                                                                                               The feasibility and efficiency  of the
                                                                                               technology for the flue gas need to
                                                                                               be determined   Also,  the effect of
                                                                                               temperature needs to be studied.
                                                                                                                             The technology transferability needs
                                                                                                                             to be verified
                                                                                               Scale-up data need to be obtained
The feasibility and efficiency of
the technology for removal of oils
and greases from the gas liquor need
to be evaluated

The technology transferability needs
to be verified
                                                                                                                                       (Continued)

-------
                                                                           TABLE 7.1-1   (cont.)
        Streams  and Control
        Technologies
        (figure  No.)
            Ammonia Recovery
            Unit
            (3  3-9}
Pollutant
Controlled
Information  Information

  Status8      Sources'1    Reliability0
                                                                 Remarks
                                                                                                         Research Heeds
NH3
                4,10
            Carbon
            Adsorption (CA)
            (5 2-17, 5.2-25)
Dissolved
Organics
   G.H.I
6,10,11
Co
W
Ot>
            Cooling Tower      dissolved
            (3 3-11, 5 2-17)   Solids
                G.H.I
                            6,10,11
Oil emulsions may not be controlled
by the separator.  Addition of
chemicals or heating the water nay be
necessary to break the emulsion.

The operating experience with the oil
shale process waters is not docu-
mented.

The technology Is used commercially
in other industries.

Dissolved organics in the gas conden-
sate may have a detrimental impact on
the efficiency of ammonia recovery
and the quality of the product.

The technology Is used eoramercially
in the treatment of industrial and
municipal wastewaters.  The operating
experience with oil shale effluents
Is not documented.  In this manual,
the technology is used for polishing
the stripped gas liquor before it can
be used in the cooling tower.  A 50%
reduction in the organics appears to
tie achievable with this technology.

The cooling tower 1s a cownonly used
technology.   It can be used to control
the dissolved solids in the process
waters if the volatile components have
been removed previously and the water
quality is suitable as the makeup to
the cooling tower   In this manual,
first the volatile components in the
gas 1tquor are removed by steam strip-
ping in the ammonia recovery system,
then the organics are removed by
adsorption on carbon.   The water thus
treated is evaporated in the cooling
tower and the dissolved solids are
concentrated in the cooling tower
blowdown,
                                                                                                                              The potential of  forming oil emulsion
                                                                                                                              in the gas liquor needs to be  ,
                                                                                                                              evaluated.                     ,  ,"
The feasibility and-efficiency- of the
technology for the  Lurgi gs& liquor
need to be evaluated.

The technology transferebi IHy needs
to be evaluated

Dissolved organics  in the gas
condensate and their Impact on the
efficiency of the technology need io
be estimated                       ~   "

The feasibility and efficiency of the
CA treatment for the lurgl gas liquor
need to be evaluated and/or the
technology transferability needs to
be verified.                     ;'.
                                                                                  The feasibility and efficiency of the
                                                                                  cooling tower for the stripped gas,
                                                                                  liquor need to be evaluated and/ot*.
                                                                                  the technology trafwferabllity"needs
                                                                                  to be verified.
                                                                                                                                        (Continued)

-------
                                                                           TABIE 7 1-1  (coot )
       Streams and Control
       Technologies
       (Figure No )
            Solar
            Fvaporation
            Pond
            (5.2-17)
Pollutant
Controlled
Dissolved
Sol Ids
Information  Information
                      b
               Status
   G.H.I
                            Sources
                                                             10
                                        Reliability
       Hi lie Water
       "(3 3-2)
CO
l\>
CO
            Reverse Osmosis
            (RO)
            (5 2-11, 5.2-12)
Dissolved
Organics and
Inorganics
   G,H,I
7,10
                                                                                                               ch Needs
The technology Is commonly used ft»r
concentrating the wastewaters.  Solar
energy Incident on an open evaporation
pond is used to evaporate the water
The precipitated salts may be removed
periodically.  In this manual, the
stripped gas liquor after the carbon
adsorption and cooling tower treat-
ments is concentrated further in the
solar evaporation pond.  Sufficient
storage capacity and surface area are
provided to hold the water without
overflowing during the low-evaporation,
high-precipitation months

The composition of the water from the
upper and Tower aquifers has been
determined from the drilling and
pumping tests on Tract C-a.  Based on
the storage coefficients and
transmissivity data, it was estimated
in this manual that 43% of the total
nine water was contributed by the
upper aquifer and 57% was contributed
by the lower aquifer.  The average
mine water flow rate was estimated
to be 16,50(1 gpm, although the flows
frofc both aquifers are quite variable
The water quality also varies
considerably within an aquifer and
between the two aquifers

The operating experience with the mine
water is not documented, but the
technology is used commercially in
other applications   In this manual,
the technology 1s applied to the
excess mine water for the removal
of bulk dissolved solids
Approximately 90-99* of the dissolved
Inorganics can be removed by the
technology   The removal efficiency
for organics may be somewhat lower
The treated water is rleaned further
so that it can be discharged and the
rejected material 1s used for processed
shale moisturizing
                                                                  Characterisation and disposal
                                                                  approaches for the precipitated salts
                                                                  need to be evaluated
                                                                                               Additional data on the aquifer water
                                                                                               quality and flow rates may need to be
                                                                                               obtained to assess potential reuse,
                                                                                               treatment, and disposal options for
                                                                                               the excess mine water
The feasibility and efficiency of the
technology for the mine water need to
be evaluated and/or the technology
transferabi1ity needs to be verified
                                                                                                                                        (Continued)

-------
                                                                           TABLE 7.1-1  (cont.)
        Streams and Control
        Technologies
        (Figure No.)
                   Pollutant
                   Contro11ed
                                Information  Information
               Status"
Sources     Reliability0
                                                                                    Remarks
                                                                                                                            Research Needs
            Boron Adsorption
            (5 2-11, 5 2-13)
                               Boron
                                                             10
            Phenol Adsorption
            (5 2-11, 5 2-13)
                               Phenol
                                                             10
Co
CO
o
Aeration Pond
(5.2-11)
Organics and
Alkalinity
                                                 10
            Reinjection
            System
                                                8,10
                           This 1s an Ion-exchange technique
                           Involving a resin which 1s specific
                           for boron   The operating experience
                           with mine water is not documented
                           In this manual, the technology is
                           applied to the RO treated water to
                           remove the boron in order to meet
                           discharge criteria.

                           This is also an ion-exchange
                           technique involving a resin which is
                           specific for phenol   The operating
                           experience with the mine water is
                           not documented   In this manual,
                           the technology is applied to the
                           excess mine water after it has been
                           treated by the RO and boron
                           adsorption technologies.   The treated
                           water is then discharged on the
                           surface.

                           Kith this technique, the wastewater
                           is aerated by passing air or pure
                           oxygen through it.   This process
                           affords decomposition of the
                           chemically oxidlzaole organic matter
                           as well as provides the oxygen for
                           the biological growth to carry out
                           biooxidation.   Some oxidizable salts
                           of heavy metals can also be precipi-
                           tated out.   In this manual, the
                           technology is applied to the RO
                           treated excess nine water   The
                           aerated water is discharged on the
                           surface.

                           The technology is used for the deep
                           well injection of some oil brine
                           wastes, but the operating experience
                           with the excess mine water on
                           Tract C-a is not documented.   In this
                           manual, the excess  mine water is first
                           clarified in an enclosed clarifier,
                           then injected into the upper aquifer.
                                                                                                                  The feasibility and efficiency of th*
                                                                                                                  technology for the tilrte watef need to
                                                                                                                  be evaluated.
                                                                                                                  The feasibimy and efficiency- of  the
                                                                                                                  technology for tine mine water need to
                                                                                                                  be evaluated.
The feasibility am* efficiency of th*
technology for the mine water need t*
be evaluated.                   '    ,!
                                                                                               The feasibility and efficiency of the
                                                                                               technology for the mine water _a't
                                                                                               Tract C-» need to J»e evaluated" and/or
                                                                                               the technology transf«rabUity needs
                                                                                               to be verified.                  *    <
                                                                                                                                        (Cootinued)

-------
                                                                    fABLt 71-1  (cont )
Streams and Control
Technologies
(Figure No )
Pollutant
Controlled
Information  Infotmatior*
                      b
  Status1
                            Sources
                                        Reliability
Solid Wastes
(17FM)	
                                                    2,10
                                                     10
     Open Pit
     Backfilling
     (3.3-W)
                             1,10
                                                                 Remarks
                                                       The  Lurgi  processed  shale  composition
                                                       has  been derived  from the  pilot plant
                                                       information on the Tract C-a  shale  and
                                                       the  material  and  elemental  balances.

                                                       Some physical  properties of the turgi
                                                       processed  shale from Tract C-a have
                                                       b«en measured in  laboratory testing

                                                       The  quality of the leachate fron  the
                                                       Lurgi processed shale has  been
                                                       determined in a laboratory experiment

                                                       Large quantities  of  the overburden  and
                                                       subore are produced  during mining.
                                                       The  physical  and  chemical  character-
                                                       istics of  these solid wastes  have not
                                                       been determined.  The wastes  are
                                                       disposed of along with the processed
                                                       shale.

                                                       Cooling tower blowdovm, boiler blow-
                                                       down, boiler feedwater treatment
                                                       regeneration waste,  mine water
                                                       Clarifler  sludge, storn runoff,
                                                       service and fire  water, etc., are
                                                       coi-hii'.ei! to form  the processed shale
                                                       moisturizing water
                                          Backfilling of the open pit with the
                                          solid wastes,  after the pit has  been
                                          developed to a sufficient size,  is
                                          mentioned in the original DDP for
                                          Tract C-a,  but the design details
                                          are not given.
                                                                                                         Research Needs
                                                                                  Scale-up  data  need to  be  obtained
                                                                                                                      Scale-up data need to be obtained
                                                                                                                      Scale-up data need to be obtained.
The physical and chemical properties
of the overburden and subore need to
be determined.  If these wastes are
to be mixed with the processed shale,
then the Impact on the properties of
the processed shale should be
evaluated

Th« extent to which the process
wastewaters need to be treated before
mixing with the processed shale needs
to be determined.  Changes 1n the
physical and chemical properties of
the solid wastes due to the mixing of
various plant wastewaters also need
to be determined.

The issues associated with pit
configuration, fill slope, logistics
of simultaneous mining and back-
filling, etc., need to be addressed
by a detailed engineering analysis
specifically tailored for the
development site

Careful procedures for waste disposal
and project shutdown need to be
developed, keeping in perspective the
potential of resuming open pit raining
in the future
                                                                                                                                (Continued)

-------
                                                                           TABLE 7 1-1  (cent.)
        Streams and Control
        Technologies
        (Figure Ho )
Pollutant
Controlled
             Information  Information
Status"
                            Sources
                                        Reliability"
U!
IVJ
            Runoff Diversion
            Sua>ps and Pumps
teachable
Compounds
                                                             10
            Dust Control
                               Participates
                                                             10
                                                                 Remarks
                                                                                      Placement of the wastes in the path
                                                                                      of the two intercepted aquifers roay
                                                                                      create the potential for groundwater
                                                                                      contamination after the mine
                                                                                      dewatering Is stopped
                                        During the backfilling operation,
                                        the runoff from the waste pile and
                                        the pit walls  is gathered in the
                                        collection sumps located at the
                                        junction of the fill  and walls   It
                                        is  then pumped to the surface for
                                        eventual use in processed shale
                                        nolsturizimj.   After the project
                                        shutdown, the  runoff is allowed to
                                        flow into the  pit.

                                        The control  of fugitive dust
                                        generated during waste transport
                                        and placement  is achieved by water
                                        and foam sprays and by paving the
                                        haul  roads
                                                                                                                                        Research Needs
                                                                                               The groundwater contamination
                                                                                               potential needs to be assessed.
                                                                                               The effectiveness of tiner materials
                                                                                               to isolate the waste from the ground-
                                                                                               water needs to be evaluated.

                                                                                               The advantages and disadvantages of
                                                                                               mixing the wastes versus keeping them
                                                                                               segregated need to be evaluated from
                                                                                               the operational as well as environs,
                                                                                               mental viewpoint.

                                                                                               Means of reestablishing the aquifers
                                                                                               need to be Investigated

                                                                                               Long-term Impacts of combining the
                                                                                               aquifers in th« pit need to be
                                                                                               evaluated on the basis" of water
                                                                                               quality, recharge rate, regional ,
                                                                                               usage, etc.                       *
                                                                                               Alternate systems for dust control,
                                                                                               such as application of chemical
                                                                                               binders and aspfralt-ic- emulsions,
                                                                                               need to be evaluated.
                                                                                                                                        (Continued)

-------
                                                                           TABLE 73-1  (cont,)
Streams and Control
Technologies
(Figurs No, )
Reclamation and
Revegetation
Pollutant Information
Controlled Status
teachable I
Gam pounds,
Particulates.etc
Information
Sources
10
                                                                       Reliability
                                                                                                Remarks
                                                                                                                                        Research Needs
                                                                                      Grubbing, stripping, and clearing of
                                                                                      the area is performed as part of the
                                                                                      raining activities.  The completed
                                                                                      surface of the landfill is covered
                                                                                      with soil and vegetated   The oper-
                                                                                      ating experience with revegetating
                                                                                      the Lurgi processed shale is not
                                                                                      documented
                                                                                                                       Reestablishment of the vegetation on
                                                                                                                       the landfill  needs to be studied on
                                                                                                                       a long-terra basis
OJ
Wk
OJ
  Information Status:
  A  Conceptual analysis.
  B  Laboratory, bench-scale studies—oil shale or similar Industry,
  C  Pilot plant studies—oil shale or similar industry
  D  Semi-warts studies—oil shale or similar industry
  E  Cortraerdial'scale studies—oil shale or similar Industry.
  F  Pilot-scale studies—related industries.
  G  Commercial-scale studies—related Industries.
  H  Vendor provided Information,
  I  Engineering calculations.

  Information Sources (detailed source information can be found in Section 8, References)
  1  Gulf Oil Corp  and Standard 011 Co  (Indiana), March 1976.
  2  Rio Blanco Oil Shale  Co.,  February 1961
  3  Gulf Oil Corp. and Standard Oil Co. (Indiana), May 1977.
  4  U.S.S.  Engineers and  Consultants, Inc , April  1978.
  S  Cheremisinoff and Ellerbusch, 1978.
  6  Hart, June 11, 1973.
  7  Hicks and Liang,  January 1981.
  8  Mercer, Campbell  and  Wakayima,  May 1979.
  9  Woodward Clyde Consultants, October 13, 1980
 10  Engineering calculations (DRI,  SWEC, WPA).
 11  Vendor estimates,

c Reliability:

  \  Information is Judged to be applicable, no problems  envisioned
  2  Information applicable, but some design or scale-up  problems may be encountered
  3  Information appHcabla, but significant design or scale-up problems nay be encountered
  4  Information may be applicable,  but both design as well  as scale-up problems (nay be encountered.
  5  Information may not be applicable without major design  and ^cale-up modifications
       Source   OKI based on the references listed in footnote b.

-------
                                  SECTION 8

                                  REFERENCES
Adams,  C.E.  and W.W.  Eckenfelder, eds.  1974.  Process Design Techniques  for
     Industrial   Waste   Treatment.    Associated   Water  and  Air   Resources
     Engineers, Environmental Press, Nashville, Tennessee.

American  Petroleum  Institute.   1969.   Manual on Disposal of Refinery Wastes,
     Volume on  Liquid Wastes.  API, New York.

American  Petroleum Institute.  March 1978.  A New Correlation of NHs, C02  and
     H2S  Volatility  Data  From  Aqueous  Sour Water  Systems.   Publication
     No.  955.  API, New York.

Barduhn,  A.J.   September 1967.   The Freezing  Processes for Desalting Saline
     Waters. Progress in Refrigeration Science and Technology, Proceedings of
     the  International   Congress   of   Refrigeration,  12ths   Madrid.   Vol. 1,
     37-55.

BatteH e,  Columbus  Laboratories.   October 1978.  Control of NOx Emission by
     Stack  Gas  Treatment.   EPRI  FP-925.   Final  report  prepared  for  the
     Electric Power Research Institute, Palo Alto, California.

Beychok,  M.R.  1967.   Aqueous Wastes from Petroleum and Petrochemical Plants.
     John Wiley and Sons, Surrey,  England.

Calmon, C.  and  H.  Gold.   1979.   Ion Exchange for Pollution Control.  2 vols.
     CRC  Press, Boca Raton, Florida.

Cathedral Bluffs  Shale Oil  Company.   November 14, 1980.  Proposal  for Finan-
     cial Assistance in  the Form of a Loan Guarantee, Volume V.   Submitted to
     U.S. Department of Energy in  response to Solicitation DE-PS60-81RA50480.

Che^emisinoff,   P.N.  and  F.  EHerbusch.   1978.   Carbon  Adsorption  Handbook.
     Ann Arbor Science,  Ann Arbor, Michigan.

Colony  Development  Operation.   1977.   Prevention of  Significant  Deteriora-
     tion; Application to  U.S. Environmental  Protection Agency,  Region VIII.

Colony  Development  Operation.   March  1980.   Application to Colorado  Mined
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Denver  Research  Institute/Water  Purification  Associates/Stone  and  Webster
     Engineering  Corporation.   July 1979.  Predicted Costs  of  Environmental


                                     335

-------
      Controls  for a Commercial  Oil  Shale Industry.   U.S.. fJef*artment of-Energy
     .Report_NQ.  CQO-EO.07-2'.         -''"'.'    '   '    •   "" '  ,

Dravo Corporation^  February. 1976.   Handbook of Ga-sifiers and Gas Treatment
      Systems.  " FE-1-772-11.   Final  Report, Task Assignment No. 4,  engineering
      Support Services..   Submitted to the 0.S.  Energy Research and  Development
      Administration.

Electric  Power Research Institute.    April  1980.   Economic and Design Factors
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Fox,  J.P., D.E.   Jackson  and  R.H.   Sakaji.   1980.   Potential  Uses of  Spent
      Shale  in  the Treatment  of Oil Shale  Retort   Waters.   13th Oil  Shale
      Symposium  Proceedings,  Colorado   School  of  Mines,  Golden,  Colorado.

Fox,  J.P.,  K.K.  Mason and J.J.  Duvall.   1979.   Partitioning  of Major,  Minor
      and  Trace Elements During  Simulated  In  Situ Oil Shale  Retorting.   12th
      Oil  Shale  Symposium  Proceedings,   Colorado School  of  Mines,  Golden,
      Colorado,

Girvin,  D.C.,  T.  Hadeishi  and  J.P.  Fox.  June  1980.   Use of Zeeman Atomic
      Absorption  Spectroscopy for  the  Measurement  of  Mercury  in Oil  Shale
      Gases.  Oil  Shale  Symposium;  Sampling, Analysis  and Quality Assurance,
      March 26-28,  1979,  Denver,  Colorado.   EPA-60G/9-8Q-022.  U.S.  Environ-
      mental Protection Agency.

Gulf  Oil  Corporation and  Standard  Oil  Company (Indiana).  March 1976.   Rio
      Blanco  Oil   Shale  Project:    Detailed   Development  Plan,   Tract C-a.
      4 vols.   Submitted  to  U.S.  Department  of  the  Interior,   Geological
      Survey, Area  Oil Shale Supervisor.

Gulf  Oil  Corporation  and  Standard  Oil  Company  (Indiana),   May 1977.    Rio
      Blanco Oil Shale Project:   Revised  Detailed  Development  Plan, Tract C-a.
      4 vols.   Submitted  to  U.S.  Department  of  the  Interior,   Geological
      Survey, Area  Oil Shale Supervisor.

Hart, J.A.  June 11,  1973.   Waste Water  Recycled  for Use in  Refinery Cooling
     Towers.   Oil  and Gas Journal.   71(24):92-96.

Hicks, R.E.,  et  al.   June 1979.   Wastewater Treatment  in Coal   Conversion.
      EPA-600/7-79-133.  U.S. Environmental Protection Agency.

Hicks,  R.E.  and  L.  Liang.   January 1981.  A  Study of  Reverse  Osmosis  for
     Treating  Oil  Shale In Situ Wastewaters,  Final   Report.   DOE/LC/10089-5.
     U.S. Department of Energy.

Hicks, R.E. and  I.E.  Wei.   December  1980.  A Study   of Aerobic Oxidation and
     Allied Treatments   for  Upgrading  In Situ Retort  Waters, Final  Report.
     DOE/ 10097-1.  U.S. Department of Energy.

Humenick,  M.J.   1977.   Water  and   Wastewater  Treatment:   Calculations  for
      Chemical   and  Physical Processes.  Marcel Oekker, New York.


                                      336

-------
Jones, B.M.,  R.H.  Sakaji  and  C.G. Daughton.   August 1982.    Physicochemical
     Treatment  Methods  for Oil   Shale  Wastewater:   Evaluation  as  Aids  to
     Biooxidation.   15th Oil Shale Symposium Proceedings, Colorado School  of
     H-'nes, Golden,  Colorado.

Kohl,  A.L. and  F.C.  Riesenfeld.   1979.   Gas  Purification.   3rd  ed.   Gulf
     Publishing Company,  Houston, Texas.

Krisher,  A.S.   August  28,  1978.   Raw Water  Treatment in the CPI.   Chemical
     Engineering,  85(19):78-98.

Marnell,  P.   September 1976.   Lurgi/Ruhrgas  Shale Oil Process.  Hydrocarbon
     Processing.   55(9):269-271.

HcWhorter,  D.B.   1980.   Reconnaissance Study  of Leachate  Quality from Raw
     Mined  Oil  Shale—Laboratory Columns.   EPA-600/7-80-181.   U.S.  Environ-
     mental Protection Agency.

Mercer, 8.W., A.C.  Campbell  and W. Wakayima.   May 1979.   Evaluation  of  Land
     Disposal  and  Underground  Injection of  Shale Oil Wastewaters.    U.S. De-
     partment of Energy Report No. PNL-2596.

Marrow, E.W.   September  1978.    Constraints on  the  Commercialization of Oil
     Shale.  R-2293-DOE.  U.S.  Department of Energy.

Merrow, E.W. ,  S.W.   Chapel  and C.  Worthing.   July  1979.   A  Review of  Cost
     Estimation in New Technologies:  Implications for Energy  Process  Plants.
     R-2481-DOE.   U.S. Department of Energy.

North-Monson Company.  August 11, 1980.   Communication with Stone and  Webster
     Engineering Corporation, Denver, Colorado,  regarding baghouses.

Nutter, J.  and C. Waittnan,   1978.  Oil  Shale Economics Update.  Tosco Corpo-
     ration, Los Angeles, California.

Occidental  Oil   Shale,   Inc.  and  Tenneco  Shale  Oil Company.   April 1981.
     Prevention  of   Significant  Deterioration;  Application  to U.S. Environ-
     mental Protection Agency,  Region VIII.

Peabody Process Systems,  Inc.   February 1981.  Paid  study on  suitability of
     the  Holmes-Stratford Process  for  Oil  Shale  Projects.   Prepared  for
     Denver Research Institute, Denver,  Colorado.

Peat, Marwick, Mitchell  & Co.   September 1980.   Final Report:   Oil  Shale Tax
     Study.  Prepared for the  Committee on Oil  Shale, Rocky Mountain  Oil and
     Gas Association.  Washington, D.C,

Peters, M.S.  and K.D.  Timmerhaus.   1980,   Plant Design and  Economics  for
     Chemical  Engineers.  3rd ed.   McGraw-Hill.
                                     337

-------
 Pforzheimer^  H.  and S.K. Kunchal.   March"24,  1977.   Conmercia]  Evaluation, of
   ,  an Oil Shale Industry  Based  on the Parana Process.,   Paper presented to
     the American Chemical   Society  National Meeting* New Orleans,  Louisiana.

 Rangnow,  O.G.  and P.A.  Fasullo.  September 28,  19&1.   Rapid Growth  is  Outlook
     for Recovered Sulfur.   Oil  artd  Gas Journal,   7S( 39):242-246.

 Research and  Education  Association.   1980.  Modern  Pollution  Control  Tech-
     nology.,  Vol. I:   Air  Pollution Control.   New York.

 Rio  Blanco Oil Shale  Company.   February 1981.   Modification to  the Detailed
     Development  Plan,  Tract C-a:  Lurgi  Demonstration Project.   Submitted to
     U.S.  Department of the Interior,  Geological  Survey,  Deputy Conservation
     Manager  - Oil Shale.

 Rio  Blanco Oil Shale  Company.  March  1981.   Modular Development  Phase  Mon-
     itoring  Report  Seven;  December 1979  - November 1980, Year-End  Report.
     4  vols.

 Schmalfeld,  I. P.   July 1975.   The Use  of the  Lurgi-Ruhrgas Process  for the
     Distillation of Oil  Shale.  Quarterly of  the Colorado School  of Mines.
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