oEPA
         United States
         Environmental Protection
         Agency
          Industrial Environmental Research
          Laboratory
          Research Triangle Park NC 27711
EPA-600/7-79-228a
October 1979
Coal Conversion Control
Technology Volume I.
Environmental
Regulations;  Liquid
Effluents

Interagency
Energy/Environment
R&D Program  Report

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                  RESEARCH REPORTING SERIES


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

    1. Environmental Health Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental  Studies

    6. Scientific and Technical Assessment Reports  (STAR)

    7. Interagency Energy-Environment Research and Development

    8. "Special" Reports

    9. Miscellaneous Reports

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

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                                       EPA-600/7-79-228a

                                             October 1979
 Coal  Conversion  Control Technology
Volume I. Environmental Regulations;
                Liquid  Effluents
                           by

           LE. Bostwick, M.R. Smith, D.O. Moore, and O.K. Webber

                       Pullman Kellogg
                 16200 Park Row, Industrial Park Ten
                     Houston, Texas 77084
                    Contract No. 68-02-2198
                  Program Element No. EHE623A
                EPA Project Officer: Robert A. McAllister

              Industrial Environmental Research Laboratory
            Office of Environmental Engineering and Technology
                  Research Triangle Park, NC 27711
                        Prepared for

              U.S. ENVIRONMENTAL PROTECTION AGENCY
                 Office of Research and Development
                     Washington, DC 20460

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                            ABSTRACT

Information has been gathered on coal conversion process streams.
Available and developing control technology has been evaluated in
view of the requirements of present and proposed federal, state,
regional and international environmental standards.  The study
indicates that it appears possible to evolve technology to reduce
each of the components of each process stream to an environmen-
tally acceptable level.  The conclusion has also been reached
that such an approach would be costly and difficult of execution.

Because all coal conversion processes are net users of water,
liquid effluents need be treated only for recycling within the
process, thus achieving essentially "zero discharge."  Further,
with available technology gaseous emissions can be controlled to
meet present environmental standards, particulates can be con-
trolled or eliminated and disposal of solid wastes can be managed
to avoid deleterious environmental effects.

Volume I focuses on environmental regulations for gaseous, liquid,
and solid wastes, and the control technology for liquid effluents.
Volume II deals with the control technology of gaseous emissions
and solid wastes.

Volume III includes a program for economic analysis of control
technology and includes the appendix.
                                ii

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                        TABLE OF CONTENTS
         (Tables of Contents for Volumes n and m start on
         pages iv and v, respectively.)                       Page
Abstract                                                  ii



List of Figures                                           vi

List of Tables                                            x

Acknowledgements                                          xv

1.   Introduction                                           1

2.   Management Summary                                     4

          Definition of the Problems                        4
          Establishment of Objectives:  Environmental       6
            Standards
          Liquid Effluent Treatment                        10
          Gaseous Emission Treatment                       16
          Solid Waste Control                              25
          Economic Analysis and Program Emphasis           29

3.   Conclusions                                           30

4.   Recommendations                                       34

          For Projection of- Future Environmental Goals     34
          For Studies of Liquid Effluent Treatment         37
          For Studies of Gaseous Emission Control          44
          For Solid Wastes Disposal and Management         48

5.   Current Technology Background                         50

          Development of the Data Base                     50
          Development of Gasification Process Emission     69
            Stream Models
          Coal Liquefaction Processes and Data. Gathering   85
          Development of Liquefaction Emission Stream      92
            Models
                               111

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                    TABLE OF CONTENTS (Cont.)
6.   Current Environmental Background :  Environmental     101
        .  Regulations

          Introduction                                    101
          Objectives of the Survey                        101
          Basis for Jurisdictional Selection              102
          Jurisdictional Selection                        104
          Method of Information Acquisition               106
          Specific Environmental Areas Covered.   Comments 107
          Summary of Most Stringent Water Quality         112
            Standards
          Summary of Most Stringent Air Quality           122
            Standards

7.   Development of Environmental Objectives              163

          Comparison of Most Stringent Regulations        164
            with MEG Criteria
          Recommendations for Projection of Future Goals  173

8.   Environmental Data Acquisition : Control of Liquid   179
          Effluents

          Development of Conversion Process Effluent      179
            Stream Models
          Literature Survey and Data Gathering            191
          Target Pollutant Residuals                      194
          Development of the Recycle Philosophy           199
          Commercial Water Treatment Methods              201
          Costs of Water Treatment                        387
          Integrated Schemes for Wastewater Treatment     462
          Efficiency of Wastewater Treatment Schemes      498
          Need for Demonstrating of Commercial Processes  516
          Need for Further Study                          519
Volume II.  Gaseous Emissions; Solid Wastes

Abstract                                                   ii

Table of Contents                                          ill

List of Figures                                            vii

List of Tables                                             xii

9.   Environmental Data Acquisition : Control of          523
          Gaseous Emissions

          Development of Conversion Process Emission      523
            Stream Models
          Literature Survey and Data Gathering            550
          Target Pollutant Residuals                      550

                                iv

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                    TABLE OF CONTENTS (Cont.)
          Commercial Emission Control Methods
          Integrated Scher.es for Emissions Control
          Costs for Control of Gaseous Emissions
          Need for Additional Data,  Information
            and Development

10.  Environmental Data Acquisition  : Control of Solid    784
          Wastes

          Literature Survey and Data Gathering            785
          Target Pollutant Residuals                      787
          Dust Control                                    792
          Costs of Dust Control                           824
          Solid Waste Disposal and Management             830
          Cost of Solids Disposal                         868
          Need for Further Study                          885


Volume III.  Economic Analysis

Abstract                                                   ii

Table of Contents                                          iii

11.  Program for Economic Analysis of Control Technology  889

          Treatment of Liquid Effluents from Coal         890
            Conversion
          Treatment of Gaseous Emissions from Coal        900
            Conversion
          Treatment of Solid Wastes  from Coal             905
            Conversion
          Basis for Economic Studies                      909
          The Capital Cost Model                          911
          The Operating Cost Model                        913
          Use of the Cost Models                          915

12.  Technology Transfer                                  916

          Reports Completed                               916
          Symposia and Meetings                           917


Appendix.  Project Bibliography, Pullman Kellogg          A-l
             Reference File
           Arrangement of the Project Bibliography        A-2
           Subject Index                                  A-15
           Accession Number Index                         A-69
           Title Index                                    A-201
           Author Index                                   A-238
           Corporate Author Index                         A-305

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                             FIGURES
                                                            Page
5-1   Emission streams from coal gasification                 71
        processes
5-2   Flow diagram for SNG production by Lurgi                82
        gasification of low sulfur coal
5-3   Emission streams from coal liquefaction                 94
        processes
5-4   Coal liquefaction.  SRC II block 'flow                   98
        diagram and material balance
7-1   Charts for MEGs                                        171
8-1   Effluent model:  Lurgi (p/o/t) gasification            180
8-2   Effluent model:  Bi-Gas (no p/o/t) gasification        182
8-3   Effluent model:  SRC liquefaction                      183
8-4   Submerged tube multiple effect evaporator              230
8-5   Multistage flash evaporation                           231
8-6   Vapor compression evaporator                           233
8-7   Cost and energy for multistage flash                   237
      evaporator
8-8   Electrodialysis                                        240
8-9   Capital investment for electrodialysis                 243
8-10  API oil-water separator                                246
8-11  API Separator:  effect of operating level and          248
        plant capacity on operating cost
8-12  Module of steeply inclined tubes                       249
                                vi

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                             FIGURES   (Cont.)



                                                            Page

8-13  Corrugated plate interceptor                           250

8-14  CPI separator:  effect of operating level and          251
        plant capacity on operating cost

8-15  Correlation of effluent oil content with operat-       252
        ing factors

8-16  Study comparison of covered oily water separator       254
        with air flotation

8-17  Phenosolvan process                                    256

8-18  Phosam-W process for ammonia separation                265

8-19  Jar test results                                       271

8-20  Coagulation of raw sewage with alum                    272

8-21  Optimum pH for metal removal                           276

8-22  Optimum pH valves for metals rempval  in  the            277
        pressure of ammonia

8-23  Lime  requirements for pH  11 as a  function  of           279
        wastewater  alkalinity

8-24  Bethlehem multitreatment  scheme                        284

8-25  Conventional  flowsheet for  ammonia  distillation        285

8-26  Flowsheet for ammonia distillation  according  to  re-    286
        designated  process

8-27  Dissolved air flotation system                         298

8-28  Influence of  air-to-solids  ratio  on  float  solids      303
         content
                                 VII

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                             FIGURES   (Cont.)

                                                            Page
8-29a Flow diagram of Gas Council Apparatus biological
        oxidation test apparatus                            313
8-29b Flow diagram of National Coal Board Apparatus         313
8-30a Effluent treating system at Refinery B, Chevron USA   321
8-30b Simplified flow scheme of RBC treatment of petroleum
        refinery wastewater                                 322
8-31a BOD removal rate vs. concentration                    324
8-31b Reciprocal BOD removal rate versus reciprocal BOD
        concentration                                       325
8-31c Accuracy of RBC model: predicted versus actual BOD    327
8-32  Relationship of oxygen transfer rate in the first     328
        stage of the RBC pilot unit versus rotational
        speed
8-33  Ammonia nitrogen removal versus hydraulic loading     329
        in the RBC treatment unit
8-3*1  Comparison of soluble COD removal versus hydraulic    330
        loading through the RBC unit
8-35  Soluble BOD removal efficiency for the RBC unit       332
8-36  Soluble COD removal efficiency for the RBC unit       333
8-37  Unit processes in sludge processing and disposal      35*1
8-38  Montana char isotherm : Synthane biox effluent        359
8-39  Breakthrough curve for Plant B bio-treated wastewater 361
8-40  Color and TOC breakthrough with Montana char          370
8-41  Block flow diagram of demonstration plant             371
8-42  Pullman Kellogg chemical plant direct materials       390
        and construction labor costs
8-43  Engineering News Record skilled labor index           392
                                viii

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                        FIGURES (Cont.)

                                                           Page

8-44   Cost indices maintained by EPA                       393

8-45   Flowsheet for Case I (Lurgi gasification)             406

8-46   The Chevron WWT process                              425

8-47   Schematic W.A.O. (wet air oxidation)  for stream      436
         #1

8-48   Schematic for WRS streams #2 and #3                  439

8-49   Schematic for LPO and filter press for streams       443
         #4 and #5

8-50   Typical UNOX System layout for Case I                448

8-51   Typical UNOX System layout for Case III              450

8-52   Phenosolvan process                                  452

8-53   Reverse osmosis:  budget prices without pre-         458
         treatment

8-54a  Integrated scheme for treatment of Lurgi wastewaters 463

8-54b  Integrated scheme for treatment of Lurgi wastewaters 464

8-54c  Stream compositions for integrated scheme for        465
         treatment of Lurgi wastewaters

8-55a  Integrated scheme for treatment of wastewater from   466
         gasification processes producing no p/o/t

8-55b  Integrated scheme for treatment of wastewater from   467
         gasification processes producing no p/o/t

8-55c  Integrated scheme for treatment of wastewater from   468
         gasification processes producing no p/o/t

8-56   Liquefaction base case water balance                 469

8-57   Lurgi gasification.  Base case and alternate         473
         disposal and water recovery

8-58a  Integrated scheme for treatment of liquefaction      489
         wastewaters

8-58b  Integrated scheme for treatment of liquefaction      490
         wastewaters

8-58c  Stream compositions for integrated scheme for        491
         treatment of liquefaction wastewaters

                                ix

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                             TABLES
                                                          Page
5-1   Available Information on Effluents, Emissions
        and Wastes from Coal Gasification Process          72
5-2   Categorization of Coal Gasification Processes        73
5-3   Available Information on Effluents, Emissions
        and Wastes from Coal Liquefaction Processes        95
7-1   Comparison of Most Stringent Standards Criteria
        with MEG Criteria for Emissions/Effluents          166
7-2   Comparison of Most Stringent Standards Criteria
        with MEG Criteria for Ambient Bodies               168
8-1   Representative Water Analyses                        187
8-2   Target Pollutant Residuals for Discharge Water       197
8-3   Miscellaneous Water Standards                        198
8-4   Operating Constraints for Recirculating Water
        Quality                                            205
8-5   Control Limits for Cooling Tower Circulating
        Water Quality                                      206
8-6   Removal of Heavy Metals by Lime Coagulation
        and Settling and Recarbonation                     209
8-7   Removal of Heavy Metals by Lime Coagulation and
        Settling                                           210
8-8   Metals in Solution after Lime Coagulation            211
8-9   Removal of Heavy Metals by Ferric Chloride
        Coagulation and Settling                           212
8-10  Metals in Solution after Ferric Chloride
        Coagulation                                        213

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                    TABLES  (Cont.)

                                                          Page
8-11  Operational Constraints for Reverse Osmosis          216
8-12  Typical Rejections by Reverse Osmosis Membranes      218
8-13  Typical Solute Rejection, High Selectivity           219
        Cellulose Acetate Membranes
8-14  Guidelines for Water Quality for Water Tube          223
        Boilers
8-15  Water Treatment of the Same Raw Water by
        Different Processes                                225
8-16  Some Present Applications of Multiple Effect
        Evaporation to Waste Treatment                     234
8-17  API Separators for 4 Mr~> Wastewater Design
        Flow                                               245
8-18  Characteristics of By-Product Coke Plant Wastes      259
8-19  Refinery Sour Water Stripper Operation               261
8-20  Utility Requirements for a Typical Phosam-W
        Plant                                              267
8-21  Reactions in Chemical Coagulation                    274
8-22  Suspended Solids Removal Performance for Chemical
        Coagulation Applications to Phosphate Removal      280
8-23  Relative Costs of Common pH Adjustment Reagents      282
8-24  Analysis of Sour Water from H-Coal PDU               288
8-25  Analysis of Sour Water from SRC I Pilot Plant        289
8-26  Average Analyses for Sour Water in SRC II Pilot
        Plant                                              291
                               XI

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                    TABLES   (Cont.)


                                                          Page

8-27  Estimated Economic Advantages of the Bethlehem
        Ammonia Removal System                            293

8-28  Air Flotation.  Major Process Equipment
        and Utilities Summary                             300

8-29  Biological Oxidation System Efficiencies            30?

8-30  Analyses of Samples of Dephenolated Lurgi
        Liquor                                            311

8-31  Average Results of Treatment                        315

8-32  Representative Coke Liquor Treatability
        Studies                                           319

8-33  Estimated Energy Requirements for Indicated
        Design at 1000 GPM                                334

8-3*1  (a)  Effluent Requirements, Initial RBC Performance
       and Initial Clarifier Performance at Refinery B,
       Chevron USA                                        337
      (b)  Initial RBC Performance at Refinery B,
       Chevron USA                                        338
      (c)  Initial Transfer Performance at Refinery B,
       Chevron USA                                        338

8-35  Pilot Biological Tests at Refinery A, Chevron USA   339

8-36  Pilot versus Full-Scale RBC Units at Refinery C,
        Chevron USA                                       3^1

8-37  Relative Amenability to Adsorption of Typical
        Petrochemical Wastewater Constituents             362

8-38  Summary of Unstripped Foul Water Characteristics,
        H-Coal                                            365

8-39  Analysis of Foul Process Condensate, Solvent
        Refined Coal                                      366
                                xii

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                         TABLES   (Cont.)


                                                            Page

8-40  Summary of Treatability Results, H-Coal
        Wastewaters, Biological Oxidation                    367

8-41  Typical Analyses of Char-Treated Effluents,
        Synthane                                             368

8-42  Content of Main Impurities in Decanter Wastes
        and Removal by Adsorption                            372

8-43  Design Data for the Demonstration Plant                372

8-44  Characterising Values of Compounds from Coking
        Plant Effluents                                      373

8-45  H-Coal Wastewater Treatment:  Carbon Isotherm
        Constants                                            37^

8-46  Water Treating Costs from Water Purification
        Associates Reports                                   395

8-47  Pullman Kellogg Coal Conversion Study (Envirotech)     402

8-48  Estimated Investment for Activated Sludge Treatment
        System                                               408

8-49  Operating Costs of Selected Wastewater Treatment
        Processes                                            417

8-50  Operating Costs for Biological Oxidation with Powdered
        Activated Carbon                                     420

8-51  Investment and Utility Estimates for the Chevron       427
         WWT Process, Pullman Kellogg Case 1

8-52  Product Compositions and Conditions for the Chevron    428
         WWT Process, Pullman Kellogg Case 1

8-53  Investment and Utility Requirements for the Chevron    429
         WWT Process, Pullman Kellogg Case 3

8-54  Product Compositions and Conditions for the Chevron    430
                              xiii

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                    TABLES   (Cont.)
                                                            Page
8-55  Capital and Operating Costs for Biological Oxida-      435
        tion with Powdered Activated Carbon and Wet Air
        Oxidation
8-56  Capital and Operating Cost for Low Pressure Oxida-     442
        tion and Filtration of Conventional Biological
        Oxidation Sludges
8-57  The Union Carbide "UNOX" System in Wastewater          444
        Treatment
8-58  "Quick Estimate" Documentation for Case I (UNOX)       449
8-59  "Quick Estimate" Documentation for Case III (UNOX)     451
8-60  Estimated Capital Investment for Removal of Inorgan-   455
        ics from Raw Water
8-61  Pullman Kellogg Gasification Study:                    461
        Evaporator Costs
8-62  Estimated Capital Costs for Wastewater Treating        472
8-63  Specifications for Makeup Water                        475
8-64  Problem Compounds in Cooling Water Systems             476
8-65  Effect of Reverse Osmosis in the Lurgi Flowsheet       478
8-66  Capital Cost of Zero Discharge System for Liquefac-    493
        tion
8-67  Operating Costs of Integrated Systems                  496
                               xiv

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                        ACKNOWLEDGEMENTS
The contributions of P.  C.  Chan,  W.  C.  Chen,  C. N. Click,  N.  S.
Gonzalez, R.  T.  Darby,  L.  N.  Do,  H.  Garcia, T.  C. Holtzberger and
D. E. Whittaker  who, as  members  of  the  Pullman  Kellogg  organiza-
tion, at various times  and  in various  ways participated  in the
development of this report,  are  gratefully  acknowledged.

The advice and guidance of C. A. Vogel,  W. J. Rhodes  and  T.  K.
Janes of the Fuel Proces-  Branch of the Environmental Protection
Agency are deeply appreciated.
                                 xv

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                           SECTION  1
                         INTRODUCTION
Proposals  for development of America's  natural resources  to  help
satisfy America's energy needs invariably  give coal high priority
consideration.  Unfortunately, coal is  by  no means a  direct and
satisfactory replacement for oil and natural  gas, but  conversion
of coal into clean synthetic liquid or  gaseous fuels promises to
solve most of the problems of  end  use  in  industrial  processes.
This promise has spurred the  development  of numerous  processes
for production  of synthetic fuels.   A  few of them have  reached
commercial status while the rest are in Various stages of devel-
opment in laboratories, pilot  plants and demonstration plants.

The primary advantage of synthetic fuels is the transfer of the
environmental problems that  are  associated with direct use of
coal from  the individual, and often small,  end users to the  con-
version processes.  Further,  control technology for  conversion
processes  may differ considerably  from control technology for
conventional combustion.

The objective of synthetic fuels development is to maintain and
improve the quality  of life  through supply of energy from our
natural resources without unacceptable  deterioration  of  the en-
vironment.  The Environmental Protection Agency  (EPA)  is  respon-
sible  for  the  assessment of  environmental factors  of energy
technologies and  for aid in  the  development of  controls to

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protect the  environment.  EPA has adopted a rational  approach in
following the development of energy systems  that  begins  with a
low level of environmental concern during the  bench  scale phase
of the process  investigation and continues with  increasing
awareness to realization of a comprehensive program during pilot
plant and larger operations.   Control technology  development thus
keeps pace with conversion process development.

The Fuel  Process  Branch of EPA's Industrial  Environmental Re-
search Laboratory at Research Triangle Park,  North Carolina, is
responsible  for the environmental factors in  the  production and
utilization  of synthetic fuels from coal.  EPA has projected the
course of the fuel conversion industry and  has planned environ-
mental programs  through earlier contractual  arrangements that
sponsored the most  progressive environmental  research  in the
synthetic fuels  area and that used the available data base to
indicate  areas  of  the synthetic fuel  industry that require
further study.  The broad survey considered all  applications of
the synthetic fuels technology and all proposed research and
projects  in  control  technology to ensure  consideration  of all
predictable  environmental impacts and  to  group  together those
areas of environmental  importance  common to a  number  of
processes.

The EPA  synthetic  fuels program that  is  now in operation is
directed  toward environmental assessment and  control technology
development  in low Btu gasification, high  Btu gasification and
liquefaction, including long-term contracts that  emphasize data
acquisition from  fundamental studies, supported by  research
grants, and  test programs at commercial  facilities.  Subprograms
in synthetic fuels research are coordinated in the Fuel Process
Branch with related programs in physical  and  chemical  coal
cleaning  and studies of fuel contaminants.  Coordination  within
the Energy Assessment and Control Division,  of  which the Fuel
Process Branch is a part, is maintained in the  area of conven-
tional and advanced coal combustion systems.

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In the  course  of the Pullman Kellogg study,  available  information
concerning  quantity and composition of the various emission,
effluent  and waste streams  from  coal conversion  processes was
gathered  by  literature searches and by contacts  with  conversion
process operators.  The study defines in as  much  detail  as  possi-
ble the problems that must be solved if conversion  processes are
to operate  successfully without unacceptable deterioration  of the
environment.

To apply  emissions control technology efficiently,  goals must be
set for  the pollutant residuals.   A major part  of the  total
effort in  the Pullman Kellogg program was the  gathering and
synopsizing of the present and proposed environmental  regulations
and standards for federal,  state,  regional and  international
jurisdictions.  A  summary of  the most stringent  of  these regula-
tions  was  developed for us   as  a standard for  comparing the
efficiencies of emissions control processes  on  the  premise  that a
conversion plant with  emissions equal to or  lower  than the most
stringent standards  could be  built anywhere  in  the  United States,
Mexico,or Canada.

With problems  scoped  and  objectives defined, information and data
were gathered  on available and developing control  technologies.
The goal  was to define  in as  much detail as  possible the  effec-
tiveness  and costs of  controls that may be applied  to conversion
process streams so that  the final streams  leaving the process
site will meet environmental  standards.

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                            SECTION  2
                       MANAGEMENT  SUMMARY
DEFINITION OF THE PROBLEMS

Information and data on the liquid  effluents, gaseous  emissions
and solid wastes from coal conversion  processes  were  gathered and
evaluated from literature surveys,  from  ••.ommunications  with oper-
ators of conversion processes at  bench scale,  process demonstra-
tion units and pilot plants,  from licensors  of commercial conver-
sion processes, from conceptual engineering  designs of  full scale
conversion plants and from Environmental  Protection Agency (EPA)
and Department of  Energy (DOE)  contractors.   Of the  many con-
version processes that were in various stages  of development, few
were found to be evaluating the composition and  quantity of the
effluent, emission and waste   streams:  the  emphasis.was  primari-
ly on operation of the process  and data  gathering on the outputs
was, apparently, a secondary  consideration.

Since real data on many of the conversion process output  streams
were lacking, incomplete or judged to  be of doubtful value in
attempting to scale up to full commercial operation, three pro-
cess types were chosen to represent coal  conversion processes:

   o  Low temperature gasification,  where the  maximum  reactor
      temperature is below the fusion  temperature of  the  ash and

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the reactor  offgas  contains p.henols, oils  and tars.  The
Lurgi process  was  chosen  for  this  category.  There was
available a  considerable  body of data  and  information on
commercial  operation and  the  composition of the  output
streams.   The liquid  effluents, in particular,  constitute a
type of  "worst  case"  for application of control technology.
Therefore the conclusion  might be drawn  that, if control
technology could  be successfully applied to Lurgi  gasifica-
tion liquid effluents,  the principles of the technology
would probably  be successful in application to control of
liquid effluents  from any of the low temperature gasifica-
tion processes.

High temperature  gasification, where  the maximum reactor
temperature is  above  the ash fusion temperature,  the  ash is
discharged as a molten slag and the  reactor offgases  con-
tain little or  no phenols,  oils and tars.  The Bi-Gas  pro-
cess was chosen for this  category.   The data and informa-
tion available  on process  effluents,  emissions and  wastes
were gathered  from literature and  from a conceptual en-
gineering design executed  by  C.  F.  Braun Company.   These
data were supplemented with those from  commercial operation
of the Koppers-Totzek process.

Liquefaction processes,  which  operate at  temperatures lower
than the low temperature  gasification  processes and  which
produce  phenols,  oils and tars.   The H-Coal  and  SRC II
processes were  chosen as  being  representative of liquefac-
tion processes.  Data and information on the emissions,
effluents and wastes  were  drawn from  the literature,  from
the SRC II conceptual engineering design assembled  by the
Ralph M.  Parsons Company  and  from other  contractors.

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Tabulations and references  for  data  found on emissions, effluents
and wastes for other processes  are included  in the text.   These
data are used, in some  cases,  to supplement  the available  in-
formation on the three types  of conversion  processes.  Included
in the discussion of the total  body  of  data  and on the applica-
tion of control technology  are  descriptions of data gaps and data
variability together with discussions of problems in sampling and
analysis of samples  that have made  difficult  the scaling  up of
data to represent operation of  full  scale commercial processes.
ESTABLISHMENT OF OBJECTIVES:   ENVIRONMENTAL STANDARDS

Present and currently proposed environmental  restrictions  rele-
vant to contaminants in the  effluents,  emissions and wastes from
coal conversion processes were assembled  to serve as the measure-
ment standard in evaluating available  and  developing  control
technology for such  processes.  The  environmental restrictions in
Federal and state rules and  regulations  were reported  together
with selected regional, Canadian and Mexican  regulations.

The prime objective  of the survey was to  assemble a single source
reference document of applicable  environmental regulations for
use in considering both present control  technology capabilities
and necessary future technologies for controlling pollutants from
the conversion of coal to gaseous or liquid fuel.

A second objective  was to summarize the most stringent  of the
environmental regulations so  that a  single source of environmen-
tal requirements representing the most  restrictive of present and
proposed regulations would be available.   A coal conversion faci-
lity built to meet the requirements  in  this  most stringent sum-
mary would, by definition, meet the  requirements of  any  indivi-
dual state,  region  or bordering country.   The summary  was  by
                               •6

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necessity limited primarily to those regulations  of  a quantita-
tive (numerical) nature and did not include ordinances below the
state jurisdictional level, since these were beyond  the scope of
the project.   Special requirements  introduced  by  individual
states'  permitting authorities were also beyond  the  scope of  this
project  and  were not included.

A third  major  objective was to provide an in-depth survey of the
regulations  of the selected states which had not  been available
previously to  the extent presented in the survey.   An example of
the wide coverage of this survey is the inclusions  of the  U. S.
EPA regulations applicable to  Fluid  Catalytic Cracking Units,
Petroleum Refining category, upon reasoning  that  giving a  broad
definition to  Petroleum Refining, as some  states  do, makes such
regulations potentially relevant to expected further on-site
processing of  coal liquefp'tion products.

The  first phase of the survey was concerned  with  Federal and
state environmental  regulations.   As such  regulations are con-
tinually being amended they can only be reported current as of a
given cut-off  date.  The cut-off date for  the Federal and  state
material in this report was 31  October 1977.   The  second  phase
supplements the first  with a  survey of regional  and  international
regulations.   Cut-off date  for  the second phase  was 15  April
1978.

On the premise that  the survey  should be as broad  as  possible, it
was decided that expanding the material considered relevant would
be preferable to restricting  it.  Consequently,  whenever it
appeared that  a particular standard or regulation might have at
least some present or  potential relevance, it was  included  in the
survey.   This  approach was also advantageous with  respect to use
of the survey  by project personnel as a source  of guidelines to
demonstrate  the type  and degree  of restrictions placed on .en-
vironmental  contaminants.

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The coverage of the survey  was  intentionally made  as  broad as
possible to present  the  widest and most divergent  restrictions in
effect at both the Federal and state levels.  As  the  commercial
coal  conversion facilities  which  are the underlying subject
matter of this project are all yet to be built, only  regulations
pertaining to new  facilities, as opposed to existing  facilities,
were considered and  included.

Selection of the states  to be included in the  survey  was based on
the reported availability of coal  deposits within  the  states,
since economic factors favor  sites near coal deposits  for  possi-
ble coal conversion  plant locations.  Accordingly, the  environ-
mental  laws, regulations and standards for the  following 22
states were included with the federal restrictions:
          Alabama                      Nc "th Dakota
          Alaska                      Ohio
          Colorado                     Oklahoma
          Idaho                       Pennsylvania
          Illinois                     Tennessee
          Indiana                      Texas
          Kansas                      Utah
          Kentucky                     Virginia
          Missouri                     Washington
          Montana                      West Virginia
          New Mexico                   Wyoming

The requirements  as established  by the  U.  S.  Public Health
Service Drinking Water Standards, 1962, and the Interim  Primary
Drinking Water Regulations were  synopsized and included  in the
survey together with a review of standards and guidelines  esta-
blished  by  the Delaware  River  Basin  Commission, since  the
authority of this regional commission extends  over geographical,
rather than political,  areas .and  therefore considers  the area
environment unconfined by artificial boundaries.  It  was  found

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that the standards and guidelines, adopted by the  Susquehanna
River Basin  Commission are those  of the states affected  by the
Commission.

Further  consideration of the argument that  environmental  effects
are not  limited by  political boundaries led to the  inclusion in
the survey of  the standards and guidelines that have been esta-
blished  by Mexico and Canada.  The Mexican regulations  are fed-
eral actions,  while in Canada both the Dominion  and  the pro-
vincial  governments  have enacted standards  and  guidelines.  There-
fore, Mexican  federal standards, Dominion of Canada  standards and
guidelines,  and the  standards and  guidelines of the  provinces of
Alberta  and  British  Columbia became part of the survey.   The two
provinces were chosen because  their boundaries are continguous
with those  of  Montana,  Idaho  and  Washington,  where much of the
U. S.  western coal reserves are located.

Finally, the rules  and  guidelines established  by  U.  S.-Canadian
International  Joint Commission were  included in the  survey,  since
these are primarily concerned  with the Great  Lakes and the St.
Lawrence River areas and  thus complete the regulatory coverage of
the northern U. S.  border.

The listings of the most  stringent environmental standards and
guidelines  were compared  to  the Multimedia Environmental Goals
(MEGs) wherever possible.  The MEGs are being developed  by EPA as
estimates of desirable ambient and emission  levels of control
and, as  such,  are an integral part of EPA's environmental  assess-
ment approach.  Concentration  categories  for contaminant sub-
stances  in  water effluents, water ambient  bodies, air effluents
and air  ambient bodies  were compared wherever numerical  informa-
tion was available.  Comparisons were developed   for  43 sub-
stances.  Provisions of other regulations,  although  relevant and
important to  coal  conversion, were  stated  only   in  terms, of

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allowable rates,  were  thus not  comparable to MEG  concentration
data and were not included in the comparison.  Solid  waste media
comparisons  could not be made  because few of the  solid waste
synopses contained numerical  standards that could  be  used for
comparison.

The value of  the  comparison of the most stringent  air  and water
environmental standards with MEGs lies in the  establishment of a
basis for recommendations for future environmental  goals.
LIQUID EFFLUENT  TREATMENT

In discussions with  water treating process licensors  and equip-
ment vendors the listing of most  stringent standards for water
quality was presented as the  target for pollutant  residuals.
Most licensors and vendors felt that the most  stringent standards
were attainable, but none could make firm statements without ex-
perimentation on actual, representative samples.   All  the licen-
sors  and  vendors appeared desirous of participating  in  some
arrangement, such as a  contract with DOE or a  subcontract with a
DOE prime  contractor,  in which samples could be  tested or the
performance of their rental treatment units  in  pilot or demon-
stration plants  could be monitored.

All the licensors and  vendors  agreed that treatment of liquid
effluents  for recycling to the  conversion process unit as  process
water would be easier and cheaper than treating the  individual
streams to meet  the  standards for discharge to receiving  waters:
specifications  for  reuse of  water as cooling tower  makeup and
boiler feedwater makeup are  much less stringent  than  drinking
water standards. The general opinion was that treatment  methods
for recycling would  be the same  as, or similar to,  commercial
treatment  procedures, but that  experimentation would be  required
for confirmation.

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Based on  the  statements and  opinions of the  treatment process
licensors and  equipment vendors, supplemented by Pullman Kellogg
commercial experience in  the  field, tentative  water treatment
flowsheets were  assembled  in  which maximum  reuse  of water was
projected. Water quantities  for  the flowsheets  were obtained
from conceptual  designs published  by DOE sponsored contractors
C.F. Braun (Lurgi  gasification, producing phenols,  oils,and  tars,
and Bi-Gas gasification, producing no phenols, oils,and tars) and
Ralph M.   Parsons  (SRC II  liquefaction).  In these  flowsheets no
discharge of  water would be practiced; water losses  would  be from
cooling tower evaporation,  the water associated with quenched ash
or  slag  and  the water  in wet  inorganic  sludges  from water
treatment.  Provision would be included  for  collecting leachate
and runnoff from the  solid waste disposal area and  returning the
liquid to the conversion plant for ash quenching or  treatment for
recycling.  These provis:  ~iS  in effect close the loop and  promote
the concept of "zero discharge."    It should be noted that the
term  "zero discharge" only  describes  the  effect of avoiding
discharge of treated  water to  receiving  bodies and  does not  imply
that there is no liquid  leaving the  conversion plant.

Commercial methods for  treatment of  raw  water and wastewater were
investigated in detail  for capability,  efficiency,  limitations,
case  histories,  wastes produced  from  the  treatment process,
possible  problems and possible  improvements.  Methods  included:

     o  Chemical Precipitation  (Softening)
     o  Reverse Osmosis
     o  Ion Exchange
     o  Evaporation
     o  Electrodialysis
     o  Oil Separation
     o  Phenol Extraction
     o  Stripping and Ammonia  Recovery
                               11

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     o  Chemical Coagulation and  Flocculation
     o  Flotation
     o  Biological Oxidation
     o  Filtration of Biological  Oxidation Effluent
     o  Biological Oxidation Sludge Handling
     o  Carbon Adsorption
     o  Chemical Oxidation (chlorine,  ozone,  hydrogen peroxide,
        etc.)

Capital and  operating costs for these  processes are often  stated
in the literature as "typical" or "classical."  It was found that
use of these stated costs in economic  evaluations could lead  to
gross errors because these costs  may  be in  error due to  infla-
tion,  incomplete  data,and unclear or confusing presentation.
Correspondence and discussion  with treatment process licensors
and equipment vendors was found to be  most productive of reliable
costs, based on Pullman Kellogg1s best estimates of quantities
and compositions  of the feed  streams to treatment and desired
contarainent  levels in the treated streams.  Process licensors  in
general  furnished  complete  information on equipment  costs,
installed costs  and operating  costs, while equipment vendors
usually furnished only  cost of equipment "knocked down,"  f.o.b.
factory.

Data on various methods of measuring the effect  of inflation  or
equipment and construction costs were  assembled  into curves for
use in updating costs reported in the  literature.  Factors were
developed for  estimation of  total capital  cost when  only the
vendor's equipment cost is available.   With use  of the curves and
factors  the published capital  costs  of  treatment  processes
proposed by, among others, Water Purification Associates,  Bechtel
and Associated  Water and Air  Resources (AWARE) and for  plants
installed by Pullman Kellogg,  were  tabulated  and  compared.
                              12

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A Pullman Kellogg  budget estimate- for  a biological oxidation
system,  preceded by flash mixing,  flocculation, and dissolved air
flotation, was  developed with the  aid  of Envirotech  Process
Equipment  personnel in Houston and Salt Lake City.  Feed  to  this
system had previously undergone (by calculation) oil separation,
phenol extraction, stripping,and ammonia  recovery.

Good,  recently-published cost  data were gathered for side  stream
softening of  cooling  tower  blowdown,  oil separation  and
regeneration  costs of granular activated  carbon.  Also  included
were  costs for  a  system installed  by Pullman Kellogg for  a
Peoples Gas SMG  plant that included ion exchange, evaporation,and
spray  drying  of  final solids for disposal.

Operating  costs  of water treatment processes were explored as far
as time permitted.

Best  data were those received from process licensors  such as
American Lurgi (Phenolsolvan),  Chevron Research and  U.S.  Steel
(Stripping and Ammonia Recovery), and Zimpro (Wet Air Oxidation).
Values  used  for utilities,  labor,  and  chemicals  are clearly
stated so  that all  operating costs are on a common basis.  Zimpro
furnished  operating  costs for biological  oxidation using powdered
activated carbon  and  wet   air oxidation of  circulating
carbon-sludge.   Partial operating costs were tabulated for
flotation, biological oxidation, evaporation, demineralization,
and reverse osmosis, as  supplied by equipment  vendors.

Budget cost estimates for treatment processes  were received  from
the following licensors  and vendors:

     o  Stripping and Ammonia Recovery:
        Chevron  Research WWT Process (2 cases)
                              13

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     o  Stripping and Ammonia Recovery:
        U.  S.  Steel Phosam-W Process (2  cases)

     o  Biological  Oxidation with  Powdered Carbon and  Wet  Air
        Oxidation Regeneration:
        Zimpro, Inc.  Wastewater Reclamation System (2 cases)

     o  Wet Air Oxidation of Raw Wastewater:
        Zirapro, Inc. WAO Process

     o  Disposal of Biological Oxidation Sludge:
        Zimpro,  Inc. LPO  (Low  Pressure Oxidation)  system  for
        thermal conditioning of sludge.

     o  High Purity Oxygen Activated Sludge:
        Union  Carbide UNOX process (2 cases)

     o  Phenol Extraction:
        American Lurgi Phenosolvan process

     o  Raw Water Treatment Process:
        L*A/Water Treatment (division of Chromalloy)
        Lime softeners, gravity  filters,  clear  wells,  Zeolite
        softener, demineralizers, condensate  polisher,  BFW
        deaerators, and  reverse  osmosis  preceded  by pressure
        filtration.

     o  Evaporator-Crystallizers:
        Goslin division of Evirotech, Inc.
        Forced circulation, six-effect evaporator-crystallizers

Integrated  wastewater flowsheets  were  assembled for the three
coal conversion processes(Lurgi and Bi-Gas gasification  and  SRC
II liquefaction) with utilization of developed  information on
                              -14

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the efficiencies of wastewater treatment processes.   Sour  water
analyses were selected  from  the available data  sources  that  were
considered to be  representative:  Lurgi  for low  temperature
gasification, Koppers-Totzek for  high temperature  gasification,
and H-Coal for liquefaction.  The influent  and  effluent  analyses
for the several water streams were evolved  from best  engineering
judgement of in-house experts,  licensors and  vendors,  who
considered them generally  reasonable in lieu of actual  treatment
tests.

Capital cost for  the  Lurgi wastewater  treatment scheme  was
estimated at $42,000,000.   An  alternate case  that included
reverse osmosis showed  a small  saving  in capital cost,  but
substantial operating cost savings.  Several  alternatives  were
considered as were the effects of possible additions  which  might
be necessary, particularly for coals of high  chlorine  content.
Many possible  alternate methods for  organics  removal  were
suggested, such as  anaerobic digestion, wet  air oxidation,
various schemes for  powdered activated carbon  use  in biological
oxidation  and side stream cooling tower blowdown  variations.

For the Bi-Gas  flowsheet,  the wastewater  treating scheme is
simpler and capital  cost is estimated at about $23,000,000.  Some
alternates and  possible problems or additions are discussed as a
critique  of this integrated system.

Two versions of wastewater  treating  were  compared for the
liquefaction flowsheet.  The first was the simple low cost scheme
used by Parsons in  their conceptual  design,  where  stripped
wastewater was recycled directly to the waste heat boiler  system
for the process (Bi-Gas)  gasifier, thus destroying any phenols,
oils and tars.  Only  raw water was treated, and 3,000  GPM of
treated wastewater was discharged to  the river.
                              15

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The second scheme was  a  more conservative, higher cost system for
zero discharge which  is  recommended by Pullman Kellogg.

Parsons water treating capital cost, exclusive  of that  incurred
in the  waste heat boiler  system, was  $26,220,000.   Pullman
Kellogg's wastewater  treating system capital  cost was  estimated
at $33,500,000,  not  including raw water treating.   If  raw water
treating  costs were  included,  the total cost  for  the  Pullman
Kellogg scheme became  $49,270,000 compared to $26,220,000 for the
Parsons scheme which  did not  include the unknown costs  due to
injection of wastewater  into the waste heat boiler system.

Partial operating costs  for the integrated schemes, including the
major units, were developed, ranging from $17,000/day for  lique-
faction to $31,000/day  for Lurgi  gasification,  for wastewater
treatment only,  not  including raw water treating.

Water treating technology which  is  under development or  not
widely used at present was  listed and  references noted.  Time did
not permit pursuit of  efficiency or cost data on any  of these.
GASEOUS EMISSION  TREATMENT

Gaseous emissions include entrained particulates.   Technology for
control of these gases  and  solids involves  in  most  cases
application of a  single control process or a single  assembly of
control equipment,  in  contrast  to  the systems approach  that is
needed in water treatment.

The list of most  stringent standards was used as  the  criterion
for selection  of  control technology and evaluation of  efficien-
cies of  the various alternatives.   Discussions  with control
process licensors and  equipment vendors supplemented  information
gathered from  literature searches and in-house  information.

                              16

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Essential information on emissions from recovery of products and
byproducts in coal  conversion plants  was to  be supplied  to
Pullman  Kellogg  as their  starting point  for efforts  on
application of control  technology of such  efficiency that the
final gaseous streams  reaching the atmosphere  would be  of a
quality  equal  to or  better than the  most  stringent  of
environmental standards.   Because  this information was not
supplied, Pullman  Kellogg  were forced to  develop process flow
sheets  and material balances  from  published information in order
to estimate compositions  and quantities  of  gas streams  from
recovery  processes.  The time required for this effort shortened
the time  available for investigation of  control  technology and
therefore the  investigations take the form  of general descrip-
tions of control  technology, examples  of  application  of the
technology,  evaluation, wherever possible, of means of increasing
control process  efficiency, and cost  information.

The Lurgi Dry  Ash  process was selected as the  base gasification
case for study of  integrated schemes  for  emissions control.  The
flow diagram and material balance, assembled from the conceptual
designs of  C.  F. Braun, Cameron Engineers and  Pullman Kellogg  for
operation of the Lurgi  process on western,  low  sulfur coal, were
primarily directed toward establishment of  the  operating charac-
teristics of the sulfur recovery unit,  the composition of the
offgas  stream  from sulfur recovery  and  the required operating
characteristics  of the  unit for control  of  the sulfur emissions
from the coal  conversion plant.  As  an  alternate case, a flow
diagram and  material balance  were.developed  for eastern, high
sulfur  coal.

The Lurgi Dry  Ash  process produces phenols, oils and tars that
are separated  from the  gas stream and either  processed further
for  sale or sent  to an incinerator/boiler.  Because  of the
quantity of materials that must be disposed of by incineration,
                               17

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the  incinerator/boiler is an  important part  of the  coal
conversion plant,  its operation is  closely integrated with  the
sulfur recovery unit and treatment of its offgases provides  a
second source of product  sulfur.

On the other hand,  the high temperature gasification processes,
exemplified by the  Bi-Gas process, produce  little or no phenols,
oils and tars and  the importance  of the incinerator/boiler as  a
means of waste disposal is reduced.   Process steam  is raised more
from coal and less  from waste, the overall  sulfur balance changes
and the  demands  on the  sulfur recovery and  emissions control
units change.  The  overall sulfur balance  for Bi-Gas operation
was based on the C.  F. Braun conceptual design  for  operation with
low sulfur coal and  was recalculated to demonstrate the changes
with use of high sulfur coal.

For liquefaction,  the Ralph M. Parsons conceptual design for  the
SRC II  process was selected as representative.   As  in  the
gasification processes, calculation of the  material balances  was
primarily  directed  toward determining the operating
characteristics of  the sulfur recovery unit,  the  offgas stream
composition and the  demands on the unit for control of the  sulfur
emissions.

Control technology  proposed by others in the conceptual designs
and pertinent reports was reviewed and compared to  the most
stringent environmental standards, with the conclusion that most
of the proposed techniques and methods would  not  meet the most
stringent standards.

The commercial emission control methods that were  considered to
be most important  for application  to coal conversion processes,
and that were investigated, are:
                               18

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     o  Processes and  techniques for control  of  nitrogen oxides
     o  Processes and  techniques for control  of  sulfur dioxide
     o  Processes for  control of hydrogen sulfide
     o  Techniques for control of particulates
     o  Control of cooling  tower drift
     o  Other control  techniques  applied to hydrocarbons,  lock
       hopper vent  gas, ammonia, ash  quench  vent gas, and
       miscellaneous  leaks.

Capability, efficiency,  limitations,  case histories, wastes
produced, costs, possible  problems,and possible  improvements were
determined  for the commercial  processes that may  be  applied to
emission control.

Nitrogen Oxides Control

In Lurgi gasification of both eastern and western  coal  the  waste
gas streams and  the  liquid byproduct and waste  streams have a
heating value  equivalent to about 58 percent of the  total  plant
energy  requirement and may be  fed to an  incinerator/boiler with
coal providing the  remainder.   Either  boiler  modifications or
liquid fuel denitrogenation were  shown  to reduce emissions
sufficiently to meet present environmental standards.   Both may
be applied  if  further reduction is required.   If still further
reduction  is  needed, there  are  flue gas denitrogenation
processes,  both dry and wet,  that may be applied.

With Bi-Gas gasification,  combustible liquid byproduct and  waste
streams are eliminated,  the  waste gas  streams are reduced
drastically and  the  steam generator operates primarily  as a
coal-fed boiler.  Boiler modifications appear to be sufficient to
reduce nitrogen oxides to  meet  present  most  stringent
environmental  standards.
                              19

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In liquefaction,  the conceptual design uses a slagging gasifier
to produce fuel  gas for boiler fuel.  With  staged combustion  and
low excess air the expected nitrogen oxides emissions are  esti-
mated to be less  than the most stringent  standards.

Sulfur Dioxide Control

Sulfur in the feed coal may be reduced physically, chemically, or
with  a  combination  of both.  Sulfur dioxide formation in  the
boiler  may be reduced by fluidized bed  combustion.   Sulfur
dioxide in the flue gases may be reduced  by scrubbing or by  dry
absorption or reaction.  Combinations of  these may be selected by
economic  analysis  and consideration of the marketability  of
recovered sulfur.

For this study,  the western and eastern coals were assumed  to  be
fed without prior treatment. Sulfur was recovered from conversion
process  streams  by  the Claus process followed by  the Beavon
offgas  treatment process.  Sulfur dioxide  was removed from
incinerator/boiler flue gases by the citrate process which used
part of the Claus process feed as  a source of hydrogen sulfide
and recovered more  sulfur.  Final  process offgases would meet
present most stringent environmental standards.

Hydrogen Sulfide  Control

In the acid gas separation step of the conversion processes  the
carbon dioxide stream, contaminated with hydrogen sulfude,  was
sent  to  the  incinerator/boiler,  while  the  hydrogen  sulfide
stream,  joined by streams from sour water stripping, was fed  to
the Claus process and to the flue gas desulfurization scrubber.
Offgas from the  Claus  process was  treated in a Beavon process
unit to reduce the level of sulfur compounds in the final offgas
low enough to meet the most stringent environmental standards.
                              20

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Splitting the hydrogen sulfide stream reduces the required  size
of the  Claus and Beavon units, supplies the citrate process  unit
with its needed hydrogen  sulfide and  increases  the overall
marketable sulfur yield.

Particulate Control

Assuming that 80 percent of  the ash content of  the  coal  fed  to
the incinerator/boiler  became  flyash, then a  combination  of
cyclones and electrostatic  precipitators was  shown  to  reduce
particulate emissions to levels well below the most  stringent
standards.  It  was  noted,  but  not evaluated,  that the spray
coolers that precede the flue gas  desulfurization scrubber  will
remove  nearly all particulates remaining after  the  cyclones and
the electrostatic precipitator may possibly be  eliminated.

Control of  Cooling Tower Drift

Droplets of cooling tower water,  entrained in the  air flowing
through the tower, may be hazardous,  toxic, or  a nuisance due to
the content of dissolved  or suspended chemical compounds,
particularly when  the  cooling tower basin  is used  as a catchall
for boiler  blowdown  and miscellaneous  waste waters.   Commercially
proved  designs  of drift elimination systems  have been developed
that reduce by over 90  percent  the drift  that  is  normally
experienced with conventional two-pass  eliminators.

Other Control Techniques

Calculation of possible  emissions  of hydrocarbons,  carbon
monoxide,and ammonia from  the  incinerator/boilers  of  coal
conversion  processes indicated that  these  emissions were well
below the most  stringent environmental  standards.
                              21

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Coal lock hopper vent  gas  cannot  be  sent  directly to the  atmos-
phere  because of its high  content of hydrocarbons and  sulfur
species.  The recommended  procedure  involves bleeding the  pres-
surizing gas from the  empty  lock  hopper into the fuel system or
the reactor gas system, displacing residual gas in the  hopper
with carbon dioxide  or nitrogen and  directing the purge stream to
incineration.

Vent gases from ash  quenching are principally steam with  en-
trained ash particles, but some hydrocarbons may be formed from
organic materials in the quench water and unreacted carbon in the
ash.  The recommended  sequence  is separation of solids in  a  wet
cyclone, scrubbing by  direct contact with water and incineration
of the noncondensables.

Emissions from storage vessels  may be controlled by incineration,
by refrigeration to  condense vapors, by  scrubbing systems that
use low volatility solvents  or  by adsorption  systems.  Choice of
method depends on type and quantity  of emission and, finally, on
economics of the control systems.

Costs of Control Techniques

Processes selected for investigation were considered to be repre-
sentative of the best  available technology.   The developed  costs
are simplified hypothetical  cases,  intended to demonstrate  the
types of studies that  would  be  required for  more rigorous  treat-
ment, and cannot be  interpreted or used as definitive estimates.
In-depth studies would be  needed  in  order  to make specific pro-
cess recommendations.

Capital costs and, wherever  possible, operating costs were  devel-
oped  as follows:
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Particulate control:   installed cost vs.  capacity for
cyclones,  wet  scrubbers, fabric filters,and  electrostatic
precipitators.  No operating costs.

Coal desulfurization:   capital and operating  costs for
processing 25,000 tons per day of coal  through a heavy
media plant  and  through the  Meyers  chemical  cleaning
process  were  developed.  The heavy media  process showed
lower capital  and operating costs than the Meyers  process
but removed only 75  to 85 percent of  the  pyritic sulfur
in  contrast  to the 95 percent  removal  in the  Meyers
process.  In  terms  of  sulfur removal  cost, then, the two
processes are nearly equivalent.

Sulfur dioxide control during combustion:   capital and
operating costs of  f"idized bed combustion (FBC)  of coal
with capture of sulfur dioxide by limestone was contrast-
ed  with  those for  combustion in a conventional boiler
followed  by flue gas desulfurization.   Cost of operating
with two coals at  two  capacities in  a single  boiler
installed in a coal fired  power  plant, in a single boiler
installed in an oil fired  power  plant and in a grassroots
boiler  plants with backup were developed.   Where no
sulfur  dioxide controls  are  needed, the  conventional
boiler has lower costs than the  FBC.   For high  sulfur
coals, the FBC appears to  be the better choice.

Flue gas  desulfurization:  capital and operating costs
were developed for  limestone slurry,  lime slurry, magne-
sia slurry,and catalytic oxidation processes.   Capital
investments for the three  throwaway processes  are lower
than the  product recovery  process, with lime slurry being
the lowest.   Operating costs of magnesia slurry are
highest,  followed by catalytic oxidation and lime slurry,
                       23

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   with limestone slurry  the  lowest.  In a comparison of
   limestone slurry and the  citrate process,  the  citrate
   process with  credit for sulfur sales  is  a close  competi-
   tor of limestone slurry.

o  Sulfur dioxide control  by  citrate process  FGD  alone or
   with pyritic  sulfur removal plus FGD:  the comparison of
   operating costs of FGD alone and of removal  of 80 percent
   of pyritic sulfur by heavy media washing followed by FGD
   as required to meet most stringent standards showed that
   costs for FGD alone were  about 60 percent  of  those for
   coal cleaning plus FGD.   A similar comparison  for oil
   firing showed that hydrodesulfurization  of the  feedstock
   is more economical than FGD.

o  Nitrogen oxides control:   operating costs  for  flue gas
   denitrification alone, fuel hydrotreating alone  and com-
   bined 100 percent hydrotreating plus  flue gas denitrifi-
   cation were developed for control of  nitrogen oxides  from
   combustion of tar and oil  wastes from  coal conversion.
   Flue gas  denitrification alone was  shown to be far
   superior to the other methods, with fuel hydrotreating
   alone  next highest  and the combustion method  costing
   nearly three  times flue gas denitrification  alone.

o  Combined sulfur dioxide  and nitrogen  oxide control by
   fuel oil hydrotreating:   capital investments and  operat-
   ing costs for gas oil and residual oil  hydrotreating to
   remove 92 to 97  percent  of  the sulfur and  80  to 90
   percent of the nitrogen were developed.  Operating  costs
   for hydrotreating alone, hydrotreating most  of the  oil to
   meet sulfur dioxide standards then treating  the  flue gas
   with the UOP/Shell process to remove  nitrogen oxides, and
   using the UOP/Shell process to remove  both oxides from
   the flue gas  with prior  hydrotreating  were calculated.

                         24

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       To meet the  nitrogen  oxide  goal of 150 ppm per million
       Btu, hydrotreating  alone  is superior.  If the goal  is
       lowered to 90  ppm, the combined processes are  superior,
       although it is possible  that boiler modifications  and
       hydrotreating  would  suffice.   The  case  without
       hydrotreating  does not appear to be competitive.

    o  Combined sulfur dioxide  and nitrogen oxide control  for
       coal fired  boilers:   flue  gas treatment by  removal  of
       sulfur by the  citrate process with nitrogen  removal  by
       the UOP/Shell  process was  contrasted with simultaneous
       removal of both oxides with the UOP/Shell process.   To
       meet the most stringent  standards for both  oxides  the
       first case shows  a lower operating cost.

    o  Hydrogen sulfide  control:   capital and operating  costs
       for the Claus-Beavon  combined recovery  and offgas
       treatment were developed as  functions of capacity.   Time
       did not permit full  evaluation of- the effect of variables
       and costs and the  economics  of the various process
       combinations.
SOLID WASTE  CONTROL

Fugitive Dusts

Fugitive dusts are generated when a stream  of  dry solids falls
freely in  air as at a conveyor  transfer or discharge point, when
the stream of solids  is  agitated as at railcar  dumping or re-
claiming from pile storage and when wind blows  across piles of
solids.  There is little  information on fugitive dust generation
and therefore it was necessary  to  attempt to  define the problem
by a series  of compilations and extrapolations  of coal crushing
                              25

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data and  other  applicable information.  From  this study  the
conclusion was reached that on the  order of  0.5  to  U  percent of
the coal feed to a conversion plant could reach the  ground  500
feet from the storage pile with a 20 MPH crosswind,  or 75 to  700
tons  per day of  coal  feed to a 250 billion Btu  per  day
gasification plant.

Water sprays, particularly when  a wetting  agent  is included,
applied  at rates of about 2 gallons per ton,  are fairly  effective
in suppressing dust as it is generated at  car dumping stations,
transfer points, stackers and reclaimers, and for a  short time in
suppressing fugitive dust evolution from the  storage pile.  Use
of larger quantities of water in flooding type sprays  may help to
alleviate the immediate problem  but this  does not solve  the
long-term storage problem.

Total  wetting of the  coal as it is received is suggested as a
means  of increasing  the efficiency of dust  suppression.  From
1_,300  to 3,900 gallons of water are estimated to be required  for
flooding a 100 ton car of coal,  depending on the coal  type.

Chemical binders for use on coal in "dead storage" piles and  also
for use on coal  during  rail transport were evaluated  for
efficiency and cost.  Physical binders, such  as  asphalt or road
tar, and compaction  were investigated as means of suppressing
dust.

The concept of  dust  elimination—instead  of  suppression—is
advanced as a means of dealing with the dust problem by curing
the cause,  rather  than treating the symptoms.   Dust particles
less than 500 micrometers in diameter are  separated from the
larger coal particles at or near  the point  of  creation of the
dust by  dry or wet means then these particles  are  agglomerated
into masses that  are 500 micrometers in diameter and larg-er.
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Agglomeration may be by compaction,  by  briquetting or by granula-
tion in a pan  or  drum granulator.  Binders will  probably  be
needed,  such as tars and oils  from  coal conversion,  asphalts,
tars or  waxes from petroleum refining,  bentonite clay, or  starch.
Evaluation of the agglomeration means is needed to  equate  effi-
ciency  with capital and operating  costs.   Dust  elimination
according to this  concept eliminates most or all  of the  dust
suppression methods  and  equipment,  with their associated
operating  costs.

Collection and  disposal of coal dust is discussed, together  with
means for  control  of such other process dusts as ash/slag,  lime-
stone and  spent catalysts.

Cost are  developed for dust  suppression by water sprays  and
chemical binders.   Insuffic ~;nt data and information were avail-
able on methods of dust elimination to evaluate their  economics
and efficiencies.

Solid Waste Disposal and  Management

Solid inorganic wastes from  coal  conversion plants consist of  ash
or slag from  the gasification reactors,  ash  or slag from  the
boilers or incinerator/boilers, FGD sludge  if  the process is
used, inorganic salts in solution and  suspension and spent cata-
lysts,  of which the ash/slag  composes  on the order of 99  percent.
For this study the organic  wastes from  biological  treatment of
wastewaters were assumed  to  be  sent  to  the incinerator  or to  the
gasifier reactors.  Depending  on  coal  type and conversion process
operating characteristics,  the  total solids  volume  was shown to
range from 10.4 to 25  million  cubic  feet per year.

The overall water treatment  schemes  that were  developed  in this
study required recycling as  much  water  as  possible  or  practical
                              27

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and minimizing or concentrating the wastewaters  that could not be
recycled but which carried inorganic salts.   This minimum  stream
was finally combined  with dewatered quenched ash into  a  mixture
containing 70 to 80 percent solids:  damp enough to be  dust  free
and dry enough to be  handled in trucks, on conveyors or by aerial
tramway to the disposal area.   These methods of transport  were
evaluated for conversion plant solids by extension of information
on transport of chemically stabilized FGD sludge, with  the know-
ledge that the conversion plant  solids present fewer and  less
severe problems than do FGD sludges.  Means of increasing the
solids content of the waste stream by oil-fluidized evaporation
of inorganic sludges were investigated and found to be worth
considering.

The economics of construction of solids disposal areas were in-
vestigated to demonstrate that the dimensions of pits constructed
partly above grade and partly below grade can be optimized  with
regard to plan area occupied and interior surface area.

Interposition of an impervious  membrane between the  solids and
the environment offers an attractive  means  of  avoiding the
environmental damage  that could be caused by leachates from the
disposal area reaching ground or subsurface waters.  The  perfor-
mance and  installation costs  of  a number of membranes  were
evaluated through extension of  data that were  originally  devel-
oped  for sanitary waste disposal.

Chemical stabilization of the wastes will reduce the permeability
of the mass to a level comparable  to that of hard packed clay.
The operation and economics of  three commercial systems  were
evaluated as an alternative to the installation  of a membrane to
prevent leaching.

Recognizing that leaching will take place, means were  evaluated
for collecting leachate for return to the conversion  process

                             26

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plant  for reuse as ash  quench water or, following  appropriate
treatment, for recycling to  process.
ECONOMIC ANALYSIS AND PROGRAM  EMPHASIS

Existing and developing  control technology was  examined  to
determine applicability  to  the problems surrounding  coal  con-
version.  The individual  control processes were  examined  to
determine the possibilities  for increasing efficiency,  the
probability that the process would be used, the  availability of
adequate information  to  permit economic  evaluation and  the
availability of alternate  control technology,  then  a  list of
candidate processes was assembled  for economic evaluation.

A program was proposed for economic evaluation of those processes
selected from the  list  of candidates.  The program included
assembly of cost models to reflect required control efficiency,
size and location, with the intent that the cost  models could be
used as modules and be added to various combinations to yield the
total cost of environmental control for the conversion  processes.
                              29

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                           SECTION 3
                          CONCLUSIONS
Lack of definitive  information and data on the  compositions and
quantities of the liquid  effluents   gaseous  emissions  and solid
wastes from operation  of  coal conversion processes  required the
development of estimates  of  the  streams in order to  assess the
efficiency, operating  characteristics and costs  of  commercially
available and developing  control technology.   The  estimates of
compositions and quantities, developed from literature  searches,
personal communications and application of best  engineering  judg-
ment, were vital to the success  of the Pullman  Kellogg project.
The estimates cannot however,  substitute for data  derived from
actual process operation.  Consequently, the treatment schemes
and the projected results of these schemes may  be considered as
near approximations of expected  results, but  cannot  be  considered
as being definitive.

Real data and information on the effluents, emissions, and wastes
from coal conversion processes  are  being developed through ef-
forts in EPA programs, such as  "Level 1 Environmental Assess-
ment," and in the programs of  others.  These data  must be com-
pared to the estimated values used in this project  to  determine
whether  or not changes  are required in the proposed  control
technology or in the control philosphy.

A simple compilation of Federal, state, regional,  Canadian and

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Mexican  regulations and standards,  existing  and proposed, is an
unwieldy tool  for  measurement of  the efficiency of  control
technology  as it is applied to the  conversion process streams.
By synopsizing  the regulations and  then,  as far as possible,
listing  the most stringent of the  regulations  for each potential
pollutant, a measurement standard is  established  such that  a
conversion process plant in which the  effluent, emission, and
waste streams are controlled to meet the  standards in the master
list will  meet  standards anywhere  in the U. S., Canada, and
Mexico.

EPA's programmed development of "Multimedia Environmental Goals"
must be  included  in future evaluations  of control technology
versus  environmental impact, and  wherever bases for possible
future environmental  standards or  goals are  considered.

Technology appears  to exist for control of the  components of  most
of the effluent, emission,and waste streams  from coal conversion
plants,  according  to the best  estimates of control technology
licensors and vendors of  control equipment,  such  that treatment
of the  streams for  release  to receiving bodies of  water, in
accordance with the most  stringent environmental standards, might
be possible.   Such  an approach  to the control  problem is, in
general terms,  difficult  and uneconomical.  Pullman Kellogg  have
developed a sound,  practical engineering approach  to the  problem
from the viewpoint  of the conversion  process  operator  and  have
concluded  that, for easiest  and  most  economical  operation,
control technology  appears to be available to:

     o  Treat liquid  effluent  streams only  enough to allow the
        treated  water to  be recycled to the  conversion  process:
        control  technology required is much  less severe,  effluent
        to receiving  bodies of  water  is drastically reduced or
        eliminated,  treatment costs are attractively reduced and
        raw water  usage  is significantly decreased.   Only the
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        irreducible minimum of inorganic  salts remain for final
        disposition

        Wherever possible, gather gaseous  emission streams  for
        collective treatment and application of emissions control
        technology and treat individual  streams only when com-
        position or quantity demands  it.   Recover usable bypro-
        ducts,  such  as sulfur,  to reduce  control and  disposal
        problems and expense and to  increase revenues

        Suppress or eliminate dusts,  particularly coal dust,  from
        handling, transportation, storage and  reclaim operations.
        Dispose of solid wastes by isolating them from the envi-
        ronment or by chemically treating  them so that  environ-
        mental  impact, such as by leachates penetrating  adjacent
        soil, is reduced below that  allowed in the most stringent
        standards
The treatment  methods proposed and  developed in  the Pullman
Kellogg study are best estimates of  the performance of  control
processes  on estimated stream compositions and  quantities.
Sampling of conversion plant effluents,  emissions, and  wastes  is
needed  to  supply  the licensors of  control technology  and the
control equipment vendors with sufficient feedstock for  testing
in their proposed  process schemes to assure that  real  results
will meet the present environmental  standards.

Development of  technology so that  conversion process effluents,
emissions, and wastes can be controlled  to meet or  to  be better
than possible  future environmental  goals requires  supply  of
adequate quantities of representative  materials to technology
developers.
                              32

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Investigation  into stream  treatment  processes is  needed  to
determine  the maximum  practicable process efficiency in compari-
son to  present  and  proposed  environmental standards as an aid  to
defining areas  for  development of new control technology.

Since the  streams or the  components of  the  streams can be  ren-
dered harmless  to the  environment in several ways (e.g.,  contain-
ment, recycling, separation  and destruction, conversion), choice
of the  treatment methods  finally devolves  to  the efficiency and
economics  of the methods  based on sound  engineering decisions.
                               33

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                           SECTION 4
                        RECOMMENDATIONS
FOR PROJECTION OF FUTURE ENVIRONMENTAL GOALS

A thorough  study is needed of the  health  and  ecological effects
of possible contaminating substances.  There are a number of good
sources that should  be utilized to gather  data on criteria,
including MEG related studies and  charts, Threshold Limit Values
(TLVs)  of various organizations such as ACGIH, NIOSH studies and
recommendations,  OSHA  regulations and  reports, U. S. Public
Health  Service studies,  guidelines and standards, NAS/NAE  Water
Quality Criteria,  Chemical Industry Institute  of Toxicology
reports,and reference compilations such  as  "Industrial Hygiene
and Toxicology," by Interscience Publishers.  Such a study  would
also be helpful  in  better evaluating the  current and  proposed
environmental regulations, since the basis  on which the regula-
tions were  established is generally not known.   This is one of,
or possibly the highest of, priority recommendations,  provided
resources permit such an approach. The MEG  comparison  that was
made in this report  was a preliminary  or  first step  in  this
direction  and could  also be expanded  on as  a  more  detailed
study.

Current and proposed applicable regulations  of jurisdictions
other than  those  selected in this project  should be reviewed.
These could include other highly developed  countries, such jas
                             34

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Germany, Japan, France, United Kingdom, and  Sweden, other  states
with either newly discovered or potential coal deposits  or  known
to have very  stringent regulations,  such  as California  or  Los
Angeles County,  and  other possible  international  bodies  of
regulations (the latter not likely to  be highly fruitful).

Complete process  designs of  several  favored conversion  plant
configurations should be assembled with different scenarios  for
various coal  feeds coupled with the use of  programmed modelling
techniques to determine ambient concentrations of pollutants in
the areas outside of facilities  and  at  different altitudes or
depths.  This would  allow complete analyses and comparison of
different regulations regardless of their bases or units or their
presentation as an equation.   Ambient  media and effluent
regulations could  be analyzed equally  well.

A thorough  study  could be accomplished of applicable  substances
as carcinogens, mutagens or teratogens and  the limitation levels
dictated  thereby.  Studies of  the concept  of "zero threshold pol-
lutants,"  as  referred  to in the MEG report,  would  be  recommended
here.

A "best future  technology" approach could  be developed,  based on
a study of  estimates,  forecasts and reports  on developing tech-
nology.  National and  international economic considerations could
also be studied  and analyses made both with and without them
factored  in.   Projected energy,  fuel  and transportation avail-
ability as  possibly  affecting  such concerns  as national  security
and utility  reliability might  also be  considered.

With regard  to  establishment of future environmental  goals, note
should  be  taken that some of the regulations already  in  operation
are more  indicative of future standards than others.   The  New
Mexico air regulations for  gasification plants  are  probably
                             35

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close to five  year levels and  possibly somewhat beyond.   British
Columbia water regulations and International  Joint Commission
proposed water  regulations are probably close  to five  year
levels.   Various Water Act mandates  are very good indicators for
the level of  future water standards.  "Fishable, swimmable,
navigable waters" are mandated by July 1, 1983 and  zero  discharge
of pollutants  to navigable waters by 1985.  Toxic  pollutants in
toxic amounts  are  already prohibited.  A  closer  review of the
existing and  proposed laws and of  the regulations presented
herein is highly recommended as an  aid in  projection of future
regulations.   A  review of the  synopses under  a different set of
guidelines might  produce different levels  for  current  most
stringent regulations for some substances.  Discretion is neces-
sarily involved  in the most stringent regulation selection pro-
cess and philosophy  or guidelines used probably resulted in  close
to the lowest  allowable levels possible from such an analysis.

Regardless of  other  approaches or methods pursued,  a continuation
of the review  and updating of  applicable Federal and state legis-
lation  and regulations as promulgated  and  published  in the
Federal  Register and other timely periodicals or issuances of the
jurisdictions and  new bases  for closely  related regulations
should also be followed for further insight.   Mandates of new
environmental laws  as they are passed must  be identified and
interpreted in the light of possible effects  on regulations or
regulation of  new parameters.   Following new  regulations yet to
be promulgated under current legislative mandates, such as for
more ambient air criteria substances and more industries under
new source performance standards, also will be a necessity.

In air pollution control the effect  of the prevention of signifi-
cant deterioration (P.S.D.) and emission offset regulations, as
these control  methods mature,  on point source regulations  for air
criteria substances will have to be  taken into  account.
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These new regulatory concepts might have a major  effect  on future
regulations of the point source, fugitive emissions,  and ambient
media type.  Mandated changes in state implementation  plans due
to lack of progress  in attaining  criteria substance  ambient
standards must also be reviewed and analyzed for  probable effects
on other  future regulations.

Water regulations based on use of specific  supply  objective re-
quirements  (as in Section VI of Canada Federal  Water  synopses)
in various  jurisdictions might be used to aid in  forecasting re-
ceiving water and emission levels regulations.   If brought into
more  general use,  this type  of regulation might control the
setting of  receiving water standards just as these  generally con-
trol point  source effluent  concentration allowables.   Drinking
water  standards  are the best  example of  water use standards
already commonly  in effect.

Study of  relevant  substances in  the light of elimination of dis-
charge (EOD)  type emission level goals,  another  concept  being
used in MEG studies,  is needed.  These  goals  would be  the most
stringent and would  be  based on the premise that ambient pollu-
tant concentrations  should  not  exceed  natural background concen-
trations.  Dilution  factors are used  to  put ambient concentra-
tions  in  terms  of effluents.   Rural air  atmospheres and  drinking
water  and seawater are  frequently  used  in  studies to aid in  the
study  indication of  natural background  concentrations.
FOR STUDIES OF LIQUID EFFLUENT  TREATMENT

Recommended Laboratory Verification  of  Available Treatment
Schemes	

Actual coal conversion process  wastewaters should be supplied .to
licensors and vendors for testing in their  own laboratories  or
                               37

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rental  treating equipment supplied by the vendors should  be
operated directly  in  the pilot plants.

For oil separation, laboratory investigations  are  needed  to more
clearly determine  whether or not there are emulsion  problems and,
if problems are  apparent, the best means to break  the emulsions.
Reports of pilot plant operations  have not included in  clearly
usable form the  concentrations of fly ash, char, unconverted coal
fines, or other insoluble solids that may be present in  the sour
water.  Information and data are needed from which any effects of
the solids on oil separation may  be ascertained  and  the best
means  to  deal with the solids  may be determined.  Equipment
vendors could be of great help in this respect.

Although there are indications that single stage steam stripping
will drive off carbon dioxide and hydrogen sulfide to sufficient-
ly low levels, and ammonia to  the  level needed  for biological
oxidation, a laboratory program of confirmation is  recommended.
The amount of ammonia actually required for biological oxidation
must be established for use as a guide for the stripping  investi-
gations.  (Our theory is that  the  biological pond  need  have no
more ammonia than  can be stoichiometrically used  by phenols and
other easily biodegradable compounds in the first  stage.  Cyanates
apparently do not  begin to degrade until these compounds  are gone
and when cyanates  degrade they produce ammonia.  Residual  ammonia
from the final biolgical stage  will be hard to  control unless
long sludge age  is used, probably with powdered  carbon.)

The problem of obtaining low  ammonia residuals when biological
oxidation is not used can be  solved, we believe,  by two-stage
stripping with lime clarification between  the  stages.   Lime
addition to pH 9.5 to 11 will  be  beneficial in  many ways:  it
precipitates tars, suspended solids,and trace metals as  well as
freeing "fixed" ammonia from  ammonium salts of  acids,  such as
                              38

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ammonium  chloride.  Early simulation  of this method  on  process
condensate derived from coal conversion processes  operating at
high temperature  and containing  no  phenols, oils, or tars is
recommended.

In flotation it is recommended that pH adjustment  before  flota-
tion with carbon  dioxide and with  sulfuric acid  be compared
economically and operationally by experiment,  including additives
to obtain best oil separation, with vendor participation.

Piloting  of biological oxidation processes,  using  actual  conver-
sion process waters,  is most  strongly recommended  in  order to
determine the actual  residuals of ammonia, cyanide,  thiocyanate,
and other compounds.  High surface area powdered activated carbon
should be evaluated to establish the improvement in  the  lowering
of residuals at different le\ -Is of sludge age and  carbon content
of sludge.

Granular carbon beds following  biological effluent  filtration
should be piloted  or  tested  in the laboratory to  clearly estab-
lish  the residuals of  contaminants that may  be reached by  this.
method in comparison to  the use of powdered  activated carbon.
Regeneration  of powdered  activated carbon in biological  sludge by
wet oxidation  is  another  variation which merits investigation.

Since  inorganic  and organic  removal  is possible by  reverse
osmosis,  it  it  recommended  that removal of  organic residuals,
such as soluble oil,  phenols,  cyanides, and cyanates be investi-
gated as well  as  removal  of  such inorganics as chlorides, boron,
ammonia,and  others.

The Parsons  and COGAS Development  Co.design concept of injecting
stripped liquefaction wastewater into a high temperature  gasifier
which  produces no phenolics, in order to destroy the organic
                               39

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impurities,  should be tested in an integrated liquefaction pilot
or demonstration plant.  Investigation  should include evaluation
of possible  problems from the inorganic  components of the waste-
water,  such  as  catalyst plugging or poisoning and scaling in  heat
exchangers or pipes.

Long term experimentation, probably  on  the demonstration plant
scale,  is recommended for study of the  effects on cooling tower
operation of residual amounts  of ammonia, cyanides, cyanates,
sulfides,and various inorganic or organic  compounds that may  not
be removed from the wastewater  that is used for tower makeup.
Supplying cooling tower vendors and  specialists with actual
samples from pilot plant operation would allow certain  tests to
be made in their laboratories.  Certain  parts of the  problem  are
amenable to  calculation such that recommendations on  programs for
prevention  of  corrosion  and  scaling could  be made  for  the
demonstration plant.

The possibility of establishing joint water treating  programs be-
tween DOE and EPA  at the DOE pilot plants  should be investigated.
Laboratory treatment studies,  such  as that being conducted by
Carnegie-Mellon  University  under DOE sponsorship,  might be
extended. In the  H-Coal demonstration plant, where the  waste-
water is to  be  treated and discharged  without reuse, recycling
schemes could be  piloted.  The water treating facilities  at  the
rebuilt Conoco  plant in Cresap,  W.   Va., although  not  clearly
defined, may offer opportunities  for experimentation.

Continuation of  the EPA program at the  University  of North
Carolina for treatment of conversion plant effluents is  recom-
mended, since the  program is expected to yield  useful information
on  the  effects in treatment  processes of specific substances
found in conversion  plant effluents.
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Plans are needed for demonstration  of the  individual commercial
water treating processes and the  integrated schemes that use the
processes.  Treating results of virtually every step should be
verified by actual  testing on wastewaters  from the processes
involved.   Although some of the steps may  be sufficiently verifi-
able on  wastewaters from pilot plants,  the ultimate confirmation
should come from integrated operation on  a demonstration plant.
The demonstration plant presumably  would be large enough so that
operations  would be directly relatable  to  a  commercial plant in
every respect.

Demonstration of "zero discharge" water treating schemes employ-
ing recycle of treated water should be  incorporated in demonstra-
tion  plant designs.   Specialists  in  cooling tower and boiler
operations  should be given subcontracts  to  participate in  the
design of  these systems and also to monitor  the systems during
demonstration plant operation.  In  this  way  the best additives
and  conditions  for control of scaling, algae,  foaming, and
corrosion  could  be established in the  particular plant to be
operated.   Different plant locations, different raw water and
coal compositions, and the different coal conversion processes,
may  present  unique problems  which could dictate  additional
equipment  or  different additives to control corrosion,  scaling,
algae,and  foaming.

Study of efficiencies and costs  for  the following  alternate
commercial  control technology for operation and  actual corrosion
process  effluents is recommended:

     o  Reverse  osmosis on sludges with evaporation of reject
        stream.  Treated water to cooling  tower

     o  Reverse  osmosis on sludges with evaporation of reject
        stream.   Treated  water  to demineralization  for high
        pressure steam boiler feed  water  use

                              41

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o  Study of stage-wise-water  condensation to concentrate
   inorganic materials- with a minimum  of  organic materials

o  Establish best side-stream treatment system"for cooling
   tower

o  Establish best system for biological oxidation.  The many
   variations  offered include  trickling filters, rotating
   biological  disc contactors,  fluidized  sand beds, and  High
   Purity Oxygen Activated Sludge.   Licensors for  the  above
   have been documented and could be given  samples and  sub-
   contracts sufficient  to  establish efficiency, capital
   cost, and operating costs on a firm-bid basis

o  Anaerobic  digestion as  a  first  stage in  biological
   oxidation,  followed by an aerobic second  stage.   One
   licensor of this  technology has  been identified  and
   others are  available

o  Powdered activated carbon addition to  activated  sludge
   systems. High surface area carbon and  long sludge  age,
   without regeneration, is one alternate.  Regeneration by
   wet air oxidation and higher PAC rates is another.   This
   system definitely enhances nitrogen compound  removal as
   well as BOD and COD  removal vs. conventional  activated
   sludge with no carbon addition

o  Thermal oxidation of wastewater (Zimpro) and  catalytic
   oxidation of wastewater should both be tried.   The  final
   cleanup step following  these must be established  (pro-
   bably biological oxidation  at second stage conditions,
   preferably  with powdered active carbon  addition) .   High
   Purity Oxygen Activated Sludge (UNOX) is another  candi-
   date for the cleanup  stage
                         42

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     o  Establish the role, if any, of chemical  oxidants  such as
        ozone, chlorine, or hydrogen peroxide

Investigation into the efficiencies and costs  of  the  following
processes operating on actual  conversion  process effluents is
recommended:

     o  Biological oxidation in fluidized bed (Ecolotrol, Inc.)

     o  Oil  fluidized evaporation (Dehydrotech Corp.)

     o  Heavy metal  removal by SULFEX process (Permutit)

     o  Ultraviolet  irradiation with ozone

     o  Lime sludge  recovery 'Dorr-Oliver and others)

     o  Catalytic  sludge precipitation (Perrautit)

     o  Freezing (Fluor)

     o  Thermal  incineration in  reducing  atmosphere  and recycle
        to process of purge liquors from redox systems such  as
        Stretford  and  Takahax  (Nittetu Chemical Engineering,
        Ltd.)

     o  Coalescence  of emulsified oil-water mixtures in solid
        beds.   Substitute  for  API  separator

     o  Lindraan precipitator  (Precipitator, Inc.).  Uses  SO  ,
        lime and iron to remove suspended  solids, BOD, oil and
        grease

     o  Super bacteria  strains for  greater  cleanup in biological
        oxidation  (Polybac Corp.)
                               43

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     o  Mercury removal  processes  (Japanese  "re-elixirization,"
        FMC, Georgia-Pacific)
FOR STUDIES OF GASEOUS EMISSION  CONTROL

Sulfur Recovery vs.  Sulfur  Discard

Studies are recommended to  develop data  for economic  decisions
on:

     o  Reduce sulfur by physical  coal cleaning and recover the
        rest of the  sulfur  in  the  coal conversion plant

     o  Reduce sulfur by physical  coal cleaning, recover  part in
        the conversion plant and discard  the rest as FGD sludge

     o  Reduce sulfur by chemical  (Meyers process) coal cleaning,
        recover or  throw away the sulfur  and recover or throw
        away the remaining  coal  sulfur in the  conversion plant

     o  Recover all  sulfur  in  the  conversion plant

     o  Recover part of the sulfur in the  conversion  plant and
        throw away the rest

Particulates

Further study and evaluation  are needed on the quantities and
compositions, including particulates, of  gases released from coal
feeding devices such as lock hoppers.
                               44

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Ash Quench

Much data and information are available  on  gases evolved from
quenching in Lurgi  Dry  Ash gasification,  but  little real data
have been collected on the gases evolved  from  other processes.
Data are needed  on  quantity and composition of the ash quench
streams from the various conversion processes and the variations
for any one process as the quench water composition varies.

Acid Gas Removal

Removal of hydrogen sulfide and carbon dioxide  from the process
gas stream is not usually considered  to be an emissions problem,
but the composition of the hydrogen  sulfide  stream affects the
performance of the  sulfur recovery  system,  and  thus affects the
treatment that must be applied so that the final vent gas stream
will meet environmental  standards.   In a like manner, the
composition of the  carbon dioxide stream affects the performance
of  downstream  process  steps and  thus affects the  vent gas
treatment  step.

Recommended studies in several of the acid  gas removal processes
are:

     o  Selexol:    Study effect of  feed  acid  gas composition  on
                   removal  efficiency  at  various operating
                   temperatures and pressures

     o  Rectisol:   Determine the solvent  retention of heavy hy-
                   drocarbons and the composition and quantity  of
                   the  fugitive carryover from the process  at
                   high pressures
                               45

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o  Monoethanolamine  (MEA):  Study the effects  of  operating
              conditions on the formation of non-regenerable
              compounds, on excessive  solvent losses,  on
              corrosion and on foaming

o  Diisopropanolamine (DIPA):  Study the effect of operating
              pressure on hydrogen sulfide  removal  effici-
              ency

o  Diglycolamine  (DGA):  Study the effects of operating con-
              ditions on  the formation  of  non-regenerable
              compounds and the  effect  of feed acid  gas
              composition on removal  efficiency at  various
              operating temperatures and pressures

o  Diethanolamine (DEA):  Study means of removal of  the fine
              particles that cause foaming,  as removal effi-
              ciency vs. operability vs. cost.  Data  are
              needed on utilities requirements vs. operating
              temperature and pressure

o  Fluor Solvent:  Determine utility requirements  and study
              effect of feed gas composition on  removal
              efficiency at various operating temperatures
              and pressures

o  Sulfinol:   Determine  solubility of  hydrocarbons in the
              sulfinol solvent and study process  economics
              vs.  operating parameters

o  Estasolvan:  Study the  effect of  operating pressure on
              acid gas removal efficiency.  Study  methods of
              treatment  for the blowdown stream
                          46

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     o  Benfield:  Study the process when it is operated  selec-
                  tively for the hydrogen  sulfide content in the
                  carbon dioxide stream.  Determine  the  extent
                  of COS hydrolysis vs. the requirements   for
                  Stretford process feed

     o  Amisol:    Determine utility requirements and study ef-
                  fect of feed gas composition  on removal effi-
                  ciency at various operating  temperatures and
                  pressures

Sulfur  Recovery  and Tail Gas Cleanup

Further study  of the sulfur recovery and tail gas  cleanup  process
should  include characterization of inlet and outlet  gas streams,
vent streams,  byproducts, sulfur removal efficiency  vs.  operating
parameters,and reactant degradation.  Suggested  areas  of investi-
gation  in examples of processes include:

     o   Claus  process:  Determine extent of  removal  of HCN and
                  ammonia  from the  feed gas  stream and fate of
                  CO and  hydrocarbons  in  the  feed gas.   Study
                  the  effect  on sulfur conversion of the pre-
                  sence  of  oxidizable  compounds in  the feed gas.
                  Determine the  economics of the process for
                  operation on various feed  gas compositions,
                  with particular  emphasis  on the  effects of
                  variations in hydrogen sulfide concentration

     o   Stretford and Beavon processes:  Determine conversion of
                  organic  sulfur compounds  in the presence of
                  high concentrations  of carbon dioxide.  Charac-
                  terize  oxidizer  vent gas  stream and solvent
                  blowdown  stream.  Determine degree of removal
                  of mercaptans and ammonia

                              47

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Sulfur Dioxide Control

Data are needed on the  effects on sulfur dioxide  removal and  on
the process economics of  changes in feed gas composition.   In  the
Wellman-Lord process data on HCN and ammonia  removal efficiency
are needed.  Data on composition and means  of disposal of  the
process products are needed for all processes.

Hydrocarbon Control

Study of reduction or elimination of hydrocarbons in waste  gas
streams  by incineration, absorption or adsorption is needed.
Incineration in a utility boiler may affect  boiler design  and
economics.   Absorption  into a solvent has been proposed but more
information on the process types, efficiencies and economics  is
needed as these are affected by stream composition and quantity.
The same information is needed for carbon adsorption.

Nitrogen Oxides Control

Studies of means of applying combustion modification, fluidized
bed combustion, hydrodenitrogenation of liquid fuels and flue  gas
cleaning are needed to  determine efficiency of removal and costs
in coal  conversion applications,  with particular emphasis  on
incinerator/boilers.  Investigations might be started in pilot
plants and  extended later to demonstration units.
FOR SOLID WASTES DISPOSAL  AND MANAGEMENT

Coal Dust Suppression vs.  Elimination

Determination of the size  distribution of coal  as it leaves  the
cleaning plant to determine the dust content, dust losses during
                              48

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transit  to  the coal conversion plant',  effectiveness and  costs  of
dust suppression in transit and effectiveness  and costs  for  dust
suppression at the coal conversion plant,  as these are  affected
by coal  type and source, should be carried out to establish the
base case for suppression.  The effectiveness and costs  of  dust
agglomeration should next be determined.   Then the costs and
efficiency  of dust control by  dust  agglomeration as  a  means  of
eliminating coal dust can be contrasted  with the present practice
of dust  suppression.

Solids Waste Disposal

Studies  on  application of impervious liners  to areas for disposal
of ash and  other inorganic coal conversion solids are  recommend-
ed.  Costs  for application of the liners can  then be  determined
as part  of  a recommended study on the economics of solid waste
disposal on level  ground, in  strip mines  or in valleys.  Long
term  investigations on  the  effect of  ash leachates  on the
proposed liners  is  recommended.

The  acceptability of chemical  stabilization of  solid  wastes
should  be  determined in view of present  and possible  future
environmental  standards.  Experimental work on ash/slag  and cost
development for  the  available  stabilization processes is needed
to establish process  viability.

Systems  for leachate collection and return to the  conversion
plant for reuse  should  be developed.  Finally, the  costs  of  liner
application can  be  contrasted with chemical stabilization  in view
of environmental standards.
                               49

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                          SECTION 5
                 CURRENT TECHNOLOGY BACKGROUND
DEVELOPMENT  OF  THE DATA BASE

Information  concerning quantity  and  composition of the various
emission,  effluent, and waste streams from coal conversion  pro-
cesses was gathered by literature searches and by contacts  with
conversion process operators in  order to define in  detail  the
problems that must be solved so that  the  conversion processes can
operate successfully without unacceptable deterioration  of  the
environment.   As they became available, data and information
developed  in the  EPA program "Level 1 Environmental Assessment"
were added to further define the problems of  control.

In a parallel effort, Federal,  State, regional, and international
environmental  standards were gathered  to serve as a starting
point for  objectives for application and evaluation of control
technology.  As  they became available, data and  information
developed  in the  EPA program "Multimedia Environmental  Goals"
were compared to  the present and proposed environmental standards
to aid in  defining possible future control technology needs.

In a second  parallel effort, information  and data were gathered
on  available  and developing  control  technology  to  define
effectiveness  and costs of controls that  may be applied  to
conversion process streams so that the final  streams leaving  the
process site meet environmental standards.
                              50

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Information  Procurement, Storage and Retrieval

Interrogation  of key word systems concerning the various aspects
of coal conversion yielded  abstract lists  from the  National
Technical  Information Service (NTIS), the EPA  library, Chemical
Abstracts  and  the  Franklin Institute.  These were supplemented  by
searches  through indexes of publications of the American Chemical
Society and  the  American  Institute  of Chemical Engineers.
Pertinent  articles and  reports ordered from  these abstracts and
indexes formed the nucleus of the project literature file.  The
annual, semi-annual, and weekly abstract publications of NTIS and
EPA and various technical journals were monitored in a continuing
effort to  expand and update the literature file.

A computerized system was established for information storage and
retrieval  to provide a  simp] ~ and efficient  means of  access  to
the literature according to an established keyword listing.  The
system operates  with  author,  title,and category and does not
include abstracts.

Subjects Monitored

The engineering personnel  assigned  to  the  project were divided
into three groups  with  emphasis on:

              Water Pollution Control
              Air  Pollution  Control
              Solids Disposal

Information on coal gasification  and liquefaction processes was
gathered in the initial stages of the  project  by  all groups  with
particular reference  to their assigned  areas.  Coordination was
maintained by exchanging  reports  daily  and  in  periodic  meetings.
Following the familiarization period,  the three  technical  groups
                               51

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evaluated the coal conversion  processes  for high Btu gasification,
low Btu gasification and liquefaction  in terms of status (concep-
tual, laboratory,  bench scale,  process demonstration  unit,  com-
mercial) , chances  for further  development if  less than commercial,
and availability of data at present or  forthcoming.  From  this
evaluation  the following  list of processes was  selected  for
particular attention:
High Btu Gasification:
C(>2 Acceptor
Bi-Gas
Battelle Agglomerating Ash
COGAS
Synthane
Lurgi Dry Ash
Lurgi Slagging Ash
Hydrane
Hygas Steam/Oxygen
Hygas Steam/Iron
Texaco
Low Btu Gasification:
Winkler
Koppers-Totzek
Westinghouse
Foster Wheeler
Combustion Engineering
Riley-Morgan
Wellman-Galusha
U-Gas
Babcock & Wilcox
AI Molten Salt
Morgantown*
Bituminous Coal Research
Woodall-Duckham
•Morgantown Energy Research Center
                              52

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Liquefaction:            COED
                        Clean Coke
                        SRC I and II
                        H-Coal
                        Donor Solvent
                        Synthoil

Published analyses  of  wastewater, ash,  char,  coal, and other
solids streams, and  gas streams released  to atmosphere, were
collected by each  group for their area  of  interest where data
were available  for  the various process  pilot or bench-scale
units.   Commercial scale conceptual designs  prepared for  many  of
the leading processes were collected  for  study.  Quality  of the
conceptual designs varied depending upon  contractor and degree  of
detail available  from  the licensor.  Only the latest  designs
appeared  to fully recognize the importance of  pollution control.

The water group  documented water treating  system design and cost
where available.   The  air and solid  groups assembled  similar
information.

Personal .Contacts, Trips and Meetings

The literature  survey  was supplemented by communication with
technical paper authors, EPA  and Department of  Energy (DOE)
project  managers,  operating  personnel, control process  vendors,
and EPA  and DOE  contractors.   A partial  list of these contacts
includes the  following:

      Carnegie-Mellon University
      C.  F.  Braun  &  Company
      Envirotech
                               53

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Pittsburgh Consolidation  Coal Company
Pittsburgh & Midway Coal  Mining Company
Bituminous Coal Research
Dehydro-Tech Corporation
Pittsburgh Energy Research  Center (PERC)
Dravo Corporation
U. S. Steel
Texaco Development Corporation
Exxon Research & Engineering Corporation
Davy Powergas
Combustion Engineering
City Public Service,  San  Antonio
Morgantown Energy Research  Center (MERC)
Poster Wheeler
Battelle
Institute of Gas Technology
EPA prime contractors:  Catalytic,  Radian,  Hittman,
     Battelle, Hydrocarbon  Research, Versar
Other EPA contractors in  the Fuel Process Branch:
     North Carolina State University,  University of North
     Carolina,  Research  Triangle  Institute,  Cameron
     Engineers, Illinois  State Geological Survey, and Water
     Purification Associates
DOE project managers for  SRC, Hygas,  Clean Coke, Bi-Gas,
     C02 Acceptor,  Donor  Solvent
National Conference on Treatment  and Disposal of Waste-
     water Residues
International Conference  on Coal Gasification, Liquefaction
     and Conversion to  Electricity
Pacific Chemical Engineering Conference
EPA Symposium on Environmental Aspects of Fuel Conversion
    Technology
Water Pollution Control Federation
Synthetic Pipeline Gas  Symposium

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      American  Institute  of  Chemical Engineers
      National  Coal  Association
      Purdue  Waste Conference
      Coal  Waste  Seminar
COAL GASIFICATION  PROCESSES  AND  DATA GATHERING

A total of 24  coal gasification  processes  was chosen  for  inves-
tigation on the  basis  of  their importance or stage of  develop-
ment.  Of  these, eleven  processes are  described as  "high Btu"
processes and  thirteen as "low Btu" processes.  Generally the low
Btu processes  are  so described because air instead of oxygen is
used;  however,  some  of  these do, or can,  use oxygen,  but the
product gas is not methanated  to  Synthetic Natural Gas (SNG) for
pipeline sale.  All the high Btu  processes produce SNG.

    High Btu                     Low Btu

    C02 Acceptor                 Winkler
    Bi-Gas                       Koppers-Totzek
    Battelle                     Westinghouse
    COGAS                        Foster  Wheeler
    Synthane                     Combustion  Engineering
    Lurgi Dry  Ash                 Riley-Morgan
    Lurgi Slagging Ash           Wellman-Galusha
    Hydrane                      U-Gas
    HyGas Steam/Oxygen           Babcock & Wilcox
    HyGas Steam/Iron             AI Molten Salt
    Texaco                       Morgantown
                                 Bituminous  Coal Research  (BCR)
                                 Woodall-Duckham
                              55

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These processes may also be classified  according  to  the design of
the gasifier as:
    Entrained Flow Gasifiers
    Fluidized Bed Gasifiers
    Fixed-Bed Gasifiers
     (high-velocity,  high carry-over  of
     solids)
     (low  velocity, such that a fluid
     bed is definable and solids carry-
     over is minimal)
     (large-particle coal feed,
     virtually no carry-over of solids)
Entrained Flow
Bi-Gas
Koppers-Totzek
Foster Wheeler
Combustion Engr.
Babcock & Wilcox
Texaco
Fluid Bed
CC>2 Acceptor
Battelle
COGAS
Synthane
Hydrane
HyGas (2)
Winkler
Westinghouse
U-Gas
BCR
Fixed Bed
Lurgi (2)
Riley-Morgan
Wellman-Galusha
Morgantown
Woodal1-Duckham
AI Molten Salt
Entrained Flow Gasifiers
In this design, finely-divided coal is fed into a rapidly moving
gas stream and remains suspended  in  cocurrent  flow through  the
gasifier.  Gasification is rapid  because of high reaction temper-
atures and ash is removed as molten slag.   The main advantages of
this gasifier type are the ability to process  all types of coal
and the absence of tars and hydrocarbons higher  than methane in
the product gas (methane content is usually less than one percent
by volume).  The  main disadvantages are the  necessity to pul-
verize the coal feed and the possible carry-over of molten slag.
                              56

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Bi-Gas—
The Bi-Gas  process  is funded jointly  by  DOE,  the American Gas
Association  (AGA),  Phillips Petroleum and  Bituminous Coal
Research  (BCR).  The 120 TPD  (ton  per  day)  pilot unit in Homer
City, Pa.   has  been  visited.  Operation  of the pilot unit has
been very sporadic and no environmental  data of consequence are
available.  Should  it successfully  operate, it will be  exten-
sively  sampled  by Penn Environmental  Engineers  (consultants hired
by BCR) and by  a team from Carnegie-Mellon University funded  by
DOE and AGA.  This  process contemplates  the highest operating
pressure  of all the gasification processes at 80 to 100  atmos-
pheres.   The  gas exit temperature is  about 925°C and the  bottom
temperature is  about  1,480 to 1,650°C.   Predicted  holding times are
2 seconds  in the  slagging ash  zone and  6  to 8 seconds  in the
entrained bed section.  Except for  molten  slag that is quenched
and removed  from  the bottom section,  all products, including
char, are carried overhead.

Char recycle  is planned, but has not  been  attempted so far in the
pilot unit.  The  slagging ash  section design is attributed  to
Babcock & Wilcox.  The glassy ash removed  is not expected to  be
leachable and discard to landfill is  planned.

Koppers-Totzek—
This process  is the  only one  of the entrained flow group that has
been extensively  commercialized.  Twenty plants, many including
more than one gasifier, have  been placed in commercial operation
in  1M countries since 1949.   Operation is at  substantially
atmospheric  pressure.   Temperature  of the gas  leaving the
gasifier is about  1.480°C. Temperature at the  bottom  (ash exit)
is  about 1,925°C.  Useful data are  available on  liquid  effluent
streams.

A 150 TPD pilot unit, designed to operate at pressures  up to  30
atmospheres,  is scheduled  for completion in late  1977.   Sited  in

                              57

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 Saarland,  West Germany, the pilot  plant  will be  funded and
 operated cooperatively by Shell Internationale Maatschippi j,  N.
 V. and Krupp-Koppers GmbH.

 Texaco—
 Another  major effort on high pressure  entrained gasifiers  is
 being carried out  by the Texaco Development Corporation in  a  15
 TPD unit at their Montebello, California research laboratory.
 Efforts  to obtain environmental  data have been unsuccessful,
 since this  work is privately funded.   It  is known that Texaco's
 primary  experience has been with heavy oil gasification and
 efforts  have only recently turned  to coal.  The gasifier  is
 reported to operate at pressures above 27 atmospheres and  with
 reaction temperatures of about  1.650°C.  Product gases leave a
 quench section at the bottom of the gasifier at 200 to 260°C.
 Texaco gasifier tests on residue from the Solvent Refined  Coal
 (SRC) process have been reported.

 A Texaco gasifier  was reported to have been under consideration
 for COALCON,  but COALCON itself, supposedly funded by DOE, has
 been cancelled.  A 100 TPD pilot  plant is being built in Germany
 by Ruhrkohle  and Ruhrchemie.  DOE  has awarded a contract  to  W.
 R. Grace for  development of a conceptual  design to supply gas for
 ammonia  synthesis.  The Tennessee  Valley   Authority plans  to
 build a  similar,  but  smaller, combined plant.  Other private
 organizations are  interested in the process to generate gas for
methanol synthesis and for power  generation.

 Foster Wheeler—
 The Foster  Wheeler gasifier is planned for operation on essen-
 tially the  same principle as the  Bi-Gas process, except that air
 is used instead of oxygen and the pressure is lower.  Estimated
 pressure is 24 to  31* atmospheres.  The gas exit temperature  is
 about 980 to  1,150°C  while the bottom temperature is about  1,370  to
                             58

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1,540°C.  A 480  TPD pilot plant  is planned in  association with
DOE, Pittsburgh  & Midway Coal  and Northern States Power for
completion in 1980, or possibly later.  DOE and  the University of
Minnesota have  awarded a contract for a gasifier to  generate
building  heating  steam.  No environmental data have been  reported
for the process.

Combustion Engineering--
The Combustion Engineering process is planned  for operation at
atmospheric  presure with a gas  exit temperature  of about 870° C
and a bottom temperature of  about 1,650°C.   A  pilot plant with
EPRI and  DOE involvement is scheduled for completion in mid  1978.
No environmental  data have been reported for the process.

Babcock & Wilcox—
Babcock  & Wilcox gasifier u^signs resemble those of  Koppers-
Totzek and Texaco.  It is reported that pressure experimentation
will be carried out in the range  of about 3  to 20 atmospheres.
Reported  temperatures are 980°C at the gas exit  and 1,870°C  at the
bottom.   Process  design data  have been published for a 480 TPD
pilot plant  that  was scheduled for completion late in 1979 at the
Seward Station of the Penn Electric Company.  Apparently,  funding
was not forthcoming and the  project was  cancelled.  No useful
environmental data  for the process have been reported.

Fluid Bed Gasifiers

The principal advantage claimed for fluid bed gasifiers  is  their
isothermal operation.  Oxygen consumption is reduced and, in the
case of high pressure operation,  the gasifier exit gas contains a
higher portion of methane. The higher methane content increases
the heating value as  a  fuel  gas  or  reduces  the extent of
methanation  facilities required.
                               59

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 C02 Acceptor—
 The CO  Acceptor process,  developed by  Consolidation   Coal Co.
 (CONOCO),  is designed to process  lignites and sub-bituminous
 coals.  Bituminous  coals cannot  be  used due to process limita-
 tions.  An unusual  feature is the use of recirculating  dolomite
 to supply  the heat for gasification reactions.   Dolomite is
 regenerated in a separate vessel, where char is burned  with air
 and the CO- absorbed in the gasifier is desorbed.   The  gasifier
 product gas contains substantial methane but no higher hydro-
 carbons or tars.  Water analyses are available  and the  Carnegie-
 Mellon University team is committed  to further water analytical
 effort for DOE and  AGA.  The 40 TPD  pilot plant is  no  longer in
 operation.   Pressure  was about 10  atmospheres.   The  exit gas
 temperature was about 8l5°C and the  regenerator temperature was
about 1,010°C.

Battelle Agglomerating Ash—
Battelle/Union Carbide have developed a gasifier operating near
slagging conditions that produces an agglomerated ash.   A 25 TPD
pilot plant began operation in mid  1977.  Two fluidized  beds are
used.  The  first  gasifies coal with  steam alone at  about 870 to
980°C, while  in the  second unreacted coal,  char  and  recycled
agglomerated ash  are partially burned with air at about 1,090  to
 1,150°C.  Operating  pressure is about 7 atmospheres.  Environmental
data are expected to be available during 1978.

COGAS—
Until recently,  COGAS was a privately-developed process.  A DOE
contract awarded to  the Illinois  Coal Gasification Group now
provides funds for  preparation of a  demonstration plant  design to
be located  in  Perry County, 111. to produce 18 MMSCFD1 of SNG
•Million standard cubic feet per day,
                             60

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plus  2,400  barrels per day of synthetic crude  oil  from 2,200 TPD
                        *      ._>    ,                    f
coal.  The design will be evaluated  against the Lurgi Slagging
Ash process to decide which process  will  receive matching DOE
funding for construction and operation of a  demonstration  plant.
COGAS coal gasification experimental  data were developed in  a  50
TPD pilot plant operating on char in  Leatherhead, England.   Very
little process data are available,  and there are virtually no ef-
fluent data.  The quality of available data  is good.  If a COGAS
demonstration plant is built, data  will then be available.   Some
conceptual design data will be available when the Environmental
Analysis Report is published, the date of which is not now known,
but which is not expected before  mid  1978.

Synthane—
Pittsburgh Energy Research Center (DOE/PERC) have developed the
Synthane process, currently operating in a 75  TPD pilot  plant  at
Bruceton, Pa.  Pullman Kellogg visited the   plant in  June, 1977.
There are some  process difficulties with char let-down valve
erosion and clinkering and build-up  of  fines.   The process
operates at about 68 atmospheres  pressure with a  top  temperature
of about 425 to 760°C and a  bottom temperature of  about  925  to
980°C.   The goal  is  production of  a  high methane gas.   The
process uses steam  and  oxygen.   In the original  design a
relatively large  amount of  phenols,  oils,and tars  (p/o/t) was
produced. P/o/t production has been sharply  reduced  by  injecting
feed  coal into the fluid bed  rather  than on  top  of  it.   Caking
coal  must be pretreated.  Residual char is  a  problem,  but it is
intended that this will be used for power production  and  fuel in
a commercial plant.   The Carnegie-Mellon University team  is
monitoring the process for DOE and AGA, and  PERC  has  published
much  analytical data  from a  smaller  unit,   including some water
treating data.
                              61

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Hydrane—
DOE/PERC is developing the Hydrane process  in a small PDU (pro-
cess demonstration unit).  In this process coal devolatilization
and pretreatment  are to be accomplished  in a free-fall dilute
phase section  of  the gasifier.   Char  residue  is used for hydrogen
production. The  methane content of the  gasifier product gas  is
reported  to be 35  to 55 percent, versus  10 to 15 percent for
Synthane.   Process operating pressure is about 68 atmospheres.

Temperature at the top of the reactor is  about 540 to 820°C and
about  980°C  at  the bottom.    Little has  been published  on
effluents  from the  process, but  phenols,  oils and  tars are
expected to be present.

HyGas—
Two HyGas  processes were developed by the Institute of Gas
Technology (IGT)  in Chicago:  steam/oxygen  and steam/iron.  The
steam/oxygen process is further advanced and  considerable efflu-
ent data from  the 75 TPD pilot  plant have  been published.  The
Carnegie-Mellon University team  is  sampling and analyzing the
effluents  for DOE  and AGA. Some  water  treatment data are near
publication.

The steam/oxygen  process is multi-stage  with temperatures in-
creasing from  the top zone at about 315°C  to the bottom zone  at
about 1,040°C. Operating pressure is  about 82 atmospheres.  Coal
is fed as  a slurry in recycled  aromatic tarry hydrocarbons.  Due
to the relatively low temperatures of operation, the process  pro-
duces phenols  from all coals and oils when processing non-agglo-
merating coals.   No tars are produced.

Other  gasification methods tried  were electrothermal char
gasification (abandoned) and steam/iron.   The latter  is in the
design stages  for a 50 TPD pilot plant.  This plant will also  be
                             62

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monitored by the Carnegie-Mellon University team for  DOE and AGA,
but no data are yet  available.   C. F. Braun  has completed a
conceptual  design  for a  commercial  steam/iron  plant,  but
evaluation shows substantially  greater product gas cost  than for
steam/oxygen.

Winkler—
The Winkler process  is  fully commercial, with 16 plants,  most
containing more than one gasifier, having been built  in  Europe
and Asia since the  process was  developed in  the 1920's.   Of
these,  four plants are  still   in  operation.   No  reliable
information on emissions  is  available.   Davy Powergas  are
currently conducting an  effluent  characterization study  on the
operating commercial plants.  The  results of the study  should be
available in 1978.   Davy Powergas have stated  that  the  process
does not produce phenols,  o:"-,and tars.  The  process operates at
substantially atmospheric  pressure with a gas  outlet  temperature
of about 705°C and  a bottom temperature of about 815  to  980°C.
Residence time in  the gasifier is about 2 hours. An  alternate
design for operation at  about 10 atmospheres is being developed.

Westinghouse—
This process was developed  primarily  to produce low  Btu  gas for
power generation.   A  12 TPD pilot plant is  operating  at Waltz
Mill, Pa.  A 120 TPD pilot  plant  is  planned.   A  1,200 TPU plant
for Dresser Station  in Terra  Haute, Ind. is  planned,  but no
completion dates have been  announced.  The process uses two beds,
recirculating limestone  or  dolomite  to remove  sulfur  and
volatiles,   and an  agglomerating ash char gasifier.   Coal is
pretreated by a slipstream  of fuel gas.  Operating  pressure is
about 12 atmospheres. The  desulfurizer operates  at  about 870°C
and the gasifier at about  1090°C.  Effluent data are  scanty.
                             63

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U-Gas—
U-Gas, developed by IGT, has  been  operated in a PDU  mainly 'on
coke  and char  feeds to  demonstrate  operability  of  the
agglomerating  ash  process.  The  PDU was modified for  coal feed
and started  in operation late  in 1977.   Developmental emphasis
will be on the process, not on the effluents,  until  later in the
program.  Operating pressure may be varied from 1  to  27 atmos-
pheres.  Coal  is pretreated, if necessary, at pressure and at a
temperature  of about 370 to 425°C.   Gasification in  the single
bed is at about 1,04u°C with 45 to 60 minutes residence  time.  The
design features  selective removal  of high-ash material, a high
carbon concentration in the bed,  reinjection and combustion of
elutriated fines and better than 95 percent carbon conversion.
Little reliable  emissions data are available.

W. R.  Grace  and  Memphis Light are ti< /eloping a conceptual design
and feasibility  study, under DOE contract, for production of 300
Btu per SCF  pipeline gas from  2,800 TPD of coal.

BCR (Bituminous  Coal Research)—
This 3-stage multiple  fluid bed process  has progressed  into a PDU
that has been  operable since 1976.  It is listed as  a  "major low
Btu project" in  DOE's  coal conversion and utilization program.
No reliable  emissions data have been found.  Operating condi-
tions:  pressures  up to 16 atmospheres,  first bed temperature 315
to 650°C, second  bed temperature  925  to 1,090°C and  third  bed
about  1,150°C.

Fixed  Bed Gasifiers

Fixed  bed gasification processes charge coal in lump  form on a
batch  basis.  During the reaction steam  and either oxygen or air
are charged  to the bottom and gases move upward countercurrent to
the slowly descending  solids.  This creates distinct temperature
                             64

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zones,  from coal entry at the top of the bed to  the  ash forming
zone at  the bottom grate.  Bottom  temperature  is  usually kept
below the ash fusion temperature of the particular  coal, with the
exception of the  Lurgi Slagging Ash gasifier, while  gas exit
temperature may  vary between 315  and 595°C, depending on coal
characteristics and design variations.

Lurgi Dry Ash—
The Lurgi Dry Ash  process best  represents the  commercial fixed
bed gasifier technology.  It  is the only commercial process
operating at higli  pressure.  Eighteen plants  have  been  built,
most with multiple gasifiers,  in nine countries.   The gasifiers
in Westfield, Scotland operate now only on a test  basis.   Oper-
ating pressure is  about 24 to 31 atmospheres.   Temperature  at the
top of  the bed is  about 370 to 5*»0°C, about 650  to  8l5°C  in the
middle  of the bed  and about 980 tol,370°Cat  the bottom.   Because
coal is  fed to the top of the  reactor and is  gradually  heated
through  stages of  devolatilization,  gasification and  combustion,
the gas  leaving the reactor contains phenols,  oils  and tars.

Advantages claimed for the Lurgi Dry Ash process are  high  carbon
conversion, low oxygen consumption,  high throughput  (due to high
pressure), and relatively high methane make (7  to  12 percent by
volume).  Disadvantages cited are phenol,  oil  and tar production,
top of bed clogging  with fines,  high steam  consumption and
difficulty with coals with low  ash  fusion temperature  or those
that cake or swell appreciably.   A  pretreatment for the  latter
(agglomeration) is available but consumption  of oxygen and steam
increase.

Virtually all the  tentative commercial projects  currently under
consideration for the United  States employ the  Lurgi Dry Ash
process. The following are the most widely publicized,  but none
have actually begun construction.  Generally  they are involved in
                              65

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the permit  stage with public hearings  on environmental  issues,
leasing agreement problems, etc.   It  is  rumored  that some  (e.g.,
the Powder  River Basin project)  have  been abandoned.

      El Paso Natural Gas, Four Corners, N.M.  Coal 28,250  TPD,
      SNG 288 MMSCFD (million standard  cubic  feet per day).
      Planning and feasibility studies  continuing.

      WESCO, Texas Eastern and Pacific  Lighting, Four  Corners,
      N.M., (4 plants).   Each 25,625 TPD coal, 250 MMSCFD  SNG.
      Environmental  impact statement  completed in early 1976.
      The latest report  on WESCO (Oil and Gas Journal,  March 6,
      1978) states that  the most  recent difficulty is  contract
      negotiations with  the Navajo Indians.

      Panhandle Eastern, Peabody Coal, Eastern Wyoming.  Coal
      27,700 TPD.  SNG 270 MMSCFD. Environmental impact statement
      in preparation.

      Natural Gas Pipeline of America,  Dunn County, N. Dakota (4
      plants).  Each 30,000 TPD Coal, 250 MMSCFD SNG.

      American  Natural  Resources Co.,  Peoples Gas  Co.  (North
      American Coal Gasification Corp.), Beulah-Hazen area, North
      Dakota.  First phase, 137.5 MMSCFD gas,  planned  for  1982
      completion.  Second equal phase to follow.  Environmental
      impact statement completed.

      Northern Natural Gas, Cities Service,  Powder River Basin,
      Montana (4 Plants).  Each 30,000  TPD coal, 250 MMSCFD SNG.

      Columbia Gas System (Illinois).   300 MMSCFD SNG.

      Texas Eastern (Southern Illinois).  250 MMSCFD SNG.
                              66

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The  Lurgi process is proprietary and  there  are no emission data
available for the gasifier itself.   For  the emissions from  the
total process, however,  stream compositions are  reported  in
conceptual designs,  which in turn are  based on real data.   In
addition, stream data were obtained  for  U  American  coals during
runs on  the commercial gasifier  at West field, Scotland.  An  EPA
sampling and analysis program on an  operating unit in Yugoslavia
is now in progress and should yield  useful  effluent  and emission
data.

Lurgi Slagging Ash—
This process, like the Lurgi Dry Ash,  is proprietary and  emis-
sions data have not been published.   The  possibility of obtaining
data from Conoco  Coal  Development  Co.,  the proposer of  the
demonstration plant,  appears  to be small at present, but  may
improve  later. DOE has award J  Conoco a contract to design  the
demonstration facility to produce 60  MMSCFD of pipeline  gas from
3,800 TPD  of  coal . The process is more efficient than the  Lurgi
Dry Ash, requiring less steam and producing  less aqueous  efflu-
ents. The tentative conclusion may  be drawn that because  of  the
higher bottom bed temperature the gasifier  exit gas  will probably
contain  less phenols, oils and tars  when operating on bituminous
coals.   (A gasifier operated  by DOE at similar conditions at
Grand Forks, S. D. with lignite feed shows  high  phenol,  oil  and
tar in the gasifier  product gas.)

Riley-Morgan, Wellman-Galusha—
These atmospheric pressure gasifiers have  been  fully commercial
for many years.   They may be operated to  produce  low  Btu gas,
using air,  or  medium  Btu gas,  using  oxygen.   Maximum  bed
temperatures range between  1,095 and 1,315°C.   Depending on coal
type, the  exit gas temperatures range between 425 and  650°C and
There are no  dependable stream analyses  available;  however,
                              67

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phenols, oils.and  tars  have been reported as  present  in  the
emission streams.  An EPA sampling and analysis  program that 'is
now in  progress  should yield  useful  effluent  and  emission
information.

Morgantown  (MERC/DOE)—
This 20 TPD day  pilot plant  at the  Morgantown,  Pa.  Energy
Research Center  (MERC)  is an extension of  the  Wellman-Galusha
design  embodying a stirred bed gasifier operating at  pressures up
to about 19 atmospheres.   There are  some published  data on
emissions from the  process.  There are conflicting reports of
water treatment facilities planned for the  pilot  plant, but no
treating data have been located.

Woodall-Duckham/Gas Integrale--
The Woodall-Duckham/Gas Integrale gr ^ifier parallels  the Wellman-
Galusha, having  been  commercialized for over  30 years by the
Italian firm Gas Integrale.  Over 100 air-blown gasifiers have
been successfully operated  in Europe,  South Africa,  and
Australia.  Twenty-four oxygen-blown gasifiers have been operated
in Europe.  A typical  air-blown unit has two  stages. Approxi-
mately  200  TPD of coal are gasified to produce fuel gas and fuel
oil (the fuel oil represents about 13% of the heating value).  No
analyses of tars or product water have been located.   The latest
reported activity concerns DOE negotiations with Erie Mining Co.,
Hoyt Lakes, Minn,  to gasify 500 TPD of high sulfur agglomerating
coals to produce fuel gas for iron ore furnaces.

Molten  Salt—
The most nearly commercially proven gasifier in this  category is
the Otto-Rummel "Entrained Flow Slag Bath Gasifier" licensed out
of West Germany.  Gasifiers processing up to 250 TPD  of coal were
operated in the  1950's and 1960's.   None are currently in
operation, but  a  demonstration plant  operating at  about 25
                             68

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atmospheres pressure was reported  under  construction in 1975.   A
clean gas is said  to  be produced, char is recycled and ash  is
disposed of by landfill.  Bag filters  for  particulates collection
and  treatment facilities for process water are planned, but  few
details beyond this are available.

DOE  is funding a 24 TPD molten salt gasifier developed by Atomics
International.  The plant is expected  to be operational by  early
1978 at  Atomic International's laboratory  in Santa  Susanna,
California.  Since Pullman Kellogg  has  piloted a molten salt
process of their own,  some information  has been exchanged with
Atomics International.

Sulfur compounds in the coal react with  the molten salt and  the
exit gas contains  only about 5 ppm  of total sulfur.   Ash  is
removed  as a moist filter cake and  is washed free of soluble
salts before it is carted to landfill.   The melt bed operates  at
about 985°C.  Exit  gas temperature is  about 925°C.  Operating
pressure may be varied from atmospheric to 19 atmospheres.   No
water is produced  since no steam is  fed to the  process.   No
usable data on emissions have been published.

DEVELOPMENT OF GASIFICATION PROCESS EMISSION  STREAM MODELS

The  generalized block flow diagram of  Figure 5-1 includes  the
major conversion process steps for production of  high Btu gas.
Since the concern is with emission, effluent, and  waste  (e/e/w)
streams, recycle directly within the process  is omitted and only
those streams that would be expected to  leave  the process battery
limits, or that must be treated before recycling, are indicated.

In the  foregoing  sections the efforts  to collect  data  and
information on the compositions and quantities  of  the  e/e/w
streams  from the gasification  processes were described  and  the
                              69

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lack of information for many processes and  for  streams within the
processes was  pointed out in the narrative.   These results of the
literature search and data gathering efforts  become more apparent
in the summarization shown in TABLE 5-1.

Inspection of  the tabulation shows that for any one process there
is insufficient  information on the compositions and quantities of
the e/e/w streams to allow specification  of treatment methods for
the streams.   However,  for most of  the  streams  there  are
analyses, either real or derived from conceptual process designs,
from one  or more  processes that could  aid  in defining  the
quantity and composition of the streams.

Gasification Process Categorization

The premise that conversion processes fed with  the same  coal and
operating under  the same or similar conditions  will have the same
or similar emissions was  applied to  the  coal gasification
processes. The  groupings that  resulted  allowed application of
emissions information among  processes within  each group in an
attempt to close the information gaps.

Coal gasification processes were divided  into processes  in which
little or no phenols, oils,and  tars (p/o/t)  are produced, and
processes that produce p/o/t.  The effect of  the grouping  on the
availability of  data within each group is shown in TABLE 5-2.

Those  processes for  which emissions data do  not exist  or are
unavailable (Foster Wheeler, Texaco, COGAS, Westinghouse,  U-Gas,
BCR, Slagging  Lurgi, Riley-Morgan, Woodall-Duckham) are omitted
from the  group  lists.   Although some doubt  exists  concerning
future availability  of usable  information on  some  processes
(Bi-Gas, Combustion Engineering, Battelle,  Hydrane) these  are not
excluded from the categories.   The AI  Molten  Salt  process is
                             70

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 COAL
 STORAGE
                    DUST
                    COAL PILE RUNOFF
                    NON-OILY WATER  RUNOFF
                    O..LY WATER RUNOFF
                                             ^
                                             in;
                                             H£
 COAL PREPARATION
 AND FEEDING
                    VENT
                    SLURRY
                                              4^
         GAS(17)
    •*-
                   SCRUBBER
                             VENT
                             SCRUBBER WATER
        COAL
        PRETREATMENT
\GASIFICATION!ASH SLURRY  (8)
                              ASH
                              PILE
                                             (18),
                                     RUNOFF    (2)
                                               (8)
HEAT RECOVERY
AND SCRUBBING
   I
                   SOUR WATER
                   QUENCH SLURRY
                                              (9)
                                             (10)
  SHIFT
  CONVERSION
                  SOUR WATER
         SULFUR
         RECOVERY
                   VENT
                   SULFUR PRODUCT
 ACID GAS
 REMOVAL
                CO   VENT
                SOUR  WATER
                  ABSORBENT PURGE
                                              (12
 (13),
liii,
 IMETHANATION\
1 '
DRYING
VENT
PRODUCT GAS
(16)^

Figure 5-1.  Emission  streams  from coal gasification
             processes.
                       71

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                                               TADLC 5-1. AVAILABLE INfORMATlON ON EFFLUENTS, EMISSIONS
                                                     AtlD WASTES FnOM COAL GASIFICATION PROCESSES	
                                                                           Stream Analyses*
10
                                                3456
                                                                                   10    11
                                                                                               12
                                                                                                     13
                                                                                                                       10    17
                                                               A    A
Bi-Gas
Koppers-Totzck
Foster Wheeler
Combustion Engr.
Babcock C. Wilcox
Texaco
C02 Acceptor
Battelle
COCAS
Synthane
ilydrane
llyGas  (Steam/Ox.)
ilyGas  (Steam/iron)
Winkler
Wcstinghouse
U-Gas
BCR
Lurgi  (Dry Ash)
Lurgi  (Slagging)
Riley-Morgan
Wellman-Galusha
Morgantown
Woodall-Duckham
AI Molten Salt
               *A » Analysis, either real or from conceptual design.
                p = Partial analysis.
                Q • Quantities
                                                                         P         P     P
                                                                         P    A    A     A
                                                                                   A
                                                                                   P
A
P
A


A
A


P
P

P
A
A
P
P
A

A
P

A

A
P

A

A
P

                                                                                                                 Q
                                                                                                                 Q
A
P
                              A
                              A
                                                                                                                 Q

                                                                                                                 Q     0
                                                                                         P

                                                                                         P

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                                TABLE 5-2. CATEGORIZATION OF COAL GASIFICATION PROCESSES

i
Processes Producing
Ho P/O/T
Bi-Gas
Koppers-Totzek
Combustion Engr.
Babcock & Wilcox
CO- Acceptor
Winkler
U-Gas
CONSENSUS
Processes Producing
P/O/T
Battelle
,j Synthane
00 Hydrane
HyGas (Steam/Ox.)
HyGas (Steam/Iron)
Lurgi (Dry Ash)
Riley-Morgan
Welltnan-Galusha
Stream
23456789


P
A A A A A
Q
A
A P A
A P
Q P
A (2) (2) (2) A A P A


P
A PA
A
P A A
A P P
A A A
P

Analyses (1)
10


P
A

P
A


A


P
A

A
P
A


11 12 13 14 15 16 17 18


P P P
A

A
A A

Q Q
A (2) (3) (2) A A


P P P
A A

A Q Q A A
P Q A
A Q Q Q
P
P
  CONSENSUS
(2)   (2)   (2)
                                               A
                                                                                    (3)
(2)
(1)  A =  Analysis,  either real or £rom conceptual design.
    P =  Partial analysis.
    Q =  Quantity only.
(2)  Data available from sources other than process descriptions.
(3)  Stream 13 may be combined with Streams 9, 10 and 11.

-------
excluded because  its operating principles  and e/e/w are complete-
ly different  from those of the other processes.

Classifying gasification processes according to their  production
of p/o/t is useful because these components eventually  appear in
the waste water streams.  Their presence  requires the use of add-
itional treatment units (for  example,  biological oxidation or
phenol recovery)  while their  absence  means significantly less
intense water  treatment will be needed.   In addition,  production
of these contaminants generally reflects  gasifier operating con-
ditions, which in  turn  determines the  form of  solid  waste
produced (slag, agglomerates, or dry ash).

Phenols, oils, and tars may be formed during the gasification of
coal.   However,  by  increasing  the gasifier temperature,  the
residence time or the average  bed  temperature (for  example, by
operating in  the  entrained flow mode or injecting the  coal feed
into the hot  bottom part of the gasifier),  production of phenols,
oils and tars  is  reduced or eliminated.

It is noteworthy  that the processes producing little  or no  p/o/t
have either  entrained flow or  fluidized  bed gasifiers  that
operate at temperatures of l,035°Cor higher and produce ash as a
slag or as agglomerates.  In contrast,  the processes  that produce
p/o/t have either fixed bed or fluidized  bed gasifiers  operating
at temperatures below about 1 ,OUO°C.

There  are several  exceptions  to  the  generalization.   The CC>2
Acceptor gasifier  operates at  less than 1.035°C but produces
little p/o/t  because the feed coal is injected  into the bottom of
the gasifier  to yield a higher average bed temperature.   Little
is known at this  time concerning the Battelle Agglomerating Ash
process; however,  sources indicate that no tars  or oils are
                              74

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produced but that  some  heavy organics may be present in the
gasifier exit gas.

An attempt was made in the  early stages of the  project  to derive
approximations of the quantities and compositions  of  the process
streams in  each  of the  two general  process  categories  by
averaging, or by exercise of  best engineering  judgement on, the
available published  data for the  streams.  It was  conjectured
that, used with  caution,  the deduced  stream quantities and
compositions would  serve  as a basis for evaluating  means  of
application of available  and  developing control technology to the
pollutants in the streams.

Analysis of the results of  the attempt at deduction led  to  these
conclusions:

      o   Data and information for coal storage,  preparation, and
         feeding (streams 1 and 3 through 7)  were, in  most
         cases, fragmentary  or derived from sources other than
         coal gasification.

      o   The consensus of  the other streams from  processes pro-
         ducing no phenols,  oils,and tars  (p/o/t)  was derived
         almost entirely from Koppers-Totzek reports with  a few
         additions from  C02  Acceptor and Bi-Gas.

      o   The consensus of  the other streams from  processes pro-
         ducing p/o/t were derived principally  from  Lurgi Dry
         Ash, with some  additions from HyGas and  Synthane.

      o   Much information  for all streams was  based on concep-
         tual  engineering  designs for  commercial  plants
         operating with particular  gasification  processes.
         Material  balances in  these  process designs   were
                             75

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          developed, in most cases, from  laboratory,  bench, and
          PDU  data with attendant  difficulties in scaling up the
          data and analyses to be representative  of commercial
          operations.  Combining  stream analyses from  different
          processes compounds  the  problem  of  deciding  on stream
          compositions that can be considered to be  typical for
          the  processes within a  category.

      o   The  deduced stream compositions are at best only order
          of magnitude estimates  or  estimates of ranges of con-
          centrations of the various constituents.   Thus, if a
          design or evaluation of  control  technology happens to
          be especially sensitive  to a  precise concentration
          value,  use of averages  or  ranges  in the design or
          evaluation could result  in errors.

Liquid Effluent Streams—
Consideration  of the liquid effluent streams  from processes pro-
ducing p/o/t led to the general conclusions that data from Lurgi
Dry Ash,  possibly supplemented with  Synthane  and HyGas, designs
may be used to characterize the  streams  and that control pro-
cesses prescribed for treatment of the Lurgi, Synthane  and HyGas
streams will be applicable to  similar streams from other conver-
sion processes in  the category.   These  conclusions  are valid
because Lurgi  effluents contain  most, if not all,  of the con-
taminants to  be  found  in  effluent  streams  from any  of the
conversion processes  in the category, and  streams from other
processes may differ  from Lurgi streams  in concentration or
quantity but not widely in their  components.

The same line  of reasoning led to  the conclusion that, for con-
version processes producing no p/o/t, data from Koppers-Totzek
operation, possibly supplemented  by applicable CC^  Acceptor or
Bi-Gas data,  could be used to  characterize  liquid  effluent
                             76

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streams from this conversion process  category.  Accordingly,  a
block  flow diagram was assembled to  represent the liquid efflu-
ents from those processes producing  p/o/t  and a similar one was
assembled to represent the liquid effluents  from those processes
producing no p/o/t.  Both flow  sheets  show  quantities and com-
positions of effluent streams.   Assembly of  these flow sheets and
their  uses are discussed in detail in  Section 8 of this report.

Gaseous Emission Streams—
The characterization of the gaseous  emission  streams from the two
categories of coal gasification  processes was more complex for
the following reasons:

      o   In order to specify the design characteristics of tech-
         nology for control of tail gas emissions from the sul-
         fur recovery section  of the  conversion process plant,
         the composition of the tail  gas  must  be specified.   It
         was EPA's intention  that the  tail  gas   composition
         would be developed by another contractor,  but this was
         not done.   Therefore,  it was  necessary  for  Pullman
         Kellogg to start at the acid  gas purification step  of
         the conversion process and determine its  operation  in
         high Btu gas production from  low and high sulfur coal
         in order to ascertain  the variations in  the composi-
         tions of the feed gas  to  sulfur recovery and thus  to
         determine the composition  of sulfur  recovery tail gas.
         Lurgi Dry Ash operation on low sulfur coal was taken  as
         the base case.  Alternate  cases  chosen were Lurgi
         operation on high sulfur  coal  and Koppers-Totzek
         operation,  supplemented  by C02 Acceptor and Bi-Gas
         data, on low and high sulfur coal.

      o   For the same reason as outlined  above it was necessary
         for Pullman Kellogg  to  develop  the  variations in the
                             77

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          composition  of the  vent gas  stream from  acid  gas
          purification  that  may be anticipated with changes in
          conversion process and changes in coal feed in order to
          specify the  technology required to  control  the
          emissions.

      o    Incineration  of phenols, oils,and tars separated  from
          the  quench streams  of those  conversion  processes
          producing p/o/t, and  of the hydrocarbons in  the  acid
          gas  purification vent stream,  may be  utilized  to
          provide much  of the  heat required to raise steam for
          gasification.   Accordingly, for these processes  stack
          gases from operation  of the incinerator  as a  utility
          boiler must be considered for specification of  control
          technology, including final stack gas scrubbing.   In
          those  conversion  processes producing no p/o/t,  the
          incinerator requirement is greatly reduced and the heat
          is not available for  process steam generation. There-
          fore, the steam must be raised by an offsite boiler
          fired with feed coal  or product gas.

          Although development  of control technology for boiler
          stack emissions is not considered to be  part  of  this
          project, the  assumption is made in the overall sulfur
          balances  that sufficient H2S  is sent  to  the power
          boiler to react with  the S02 in the  boiler stack  gases
          in a sulfur recovery  scheme.

The flow  sheets  for the  gaseous emissions base  case  and  the
alternate  cases, together with  detailed discussion  of similari-
ties and differences in the emission streams and the prescribed
control  technology, are contained in Section 9 of this report.
                            .78

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Solid Wastes--
Solids  handling  problems in coal  conversion processes may  be
divided into two areas for attention,  with the realization  that
these problems are, in the main,  common  to both gasification and
liquefaction processes.  The two  areas of  concern are the control
of airborne dusts  and the management of  solid process  wastes.
Consideration of the paucity of  data  concerning quantities and
compositions of  such important streams  as fugitive dusts and
runoff  waters, and  of data concerning possible  interactions
between coal refuse  and conversion process ash when these are
mixed in a single disposal area,  led to  several conclusions:

     o   The fugitive dust problem may  be solved by  suppression
         of the dust or by collection and disposal of the dust.
         Lack of actual data,  for  example,  on  the  amount of dust
         escaping from coa? handling operations is no deterrent
         to investigation of means of controlling  the dust.

     o   The hazardous and toxic properties of the runoff waters
         from coal storage piles,  from  piles of ash  or  ash  plus
         coal refuse,and from dust scrubber slurry holding ponds
         can be dealt with by containment and recycling of the
         waters to prevent their entering the  environment.

     o   Solid waste disposal may  properly be  considered as sol-
         id waste management.   This change in viewpoint  takes
         into account the means of adding  solid  wastes to the
         environment and  the means of  avoiding  deleterious
         environmental effects.

Section 10 of this report develops  the philosophies  of  control,
containment and  management of  the solids  in coal  conversion
                              79

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processes into real solutions  for the problems  that  minimize or
eliminate environmental deterioration.

Base Case Flow Sheet and Material Balance

As pointed out in  the  foregoing discussion,  the  Lurgi Dry Ash
process operating with a low sulfur coal feed,  as  described  in
the C.  F. Braun 1976 report, (294, 295, 296),  was  chosen as the
base case for determination of effluents, emissions, and wastes
and the  technology  required  for control of  the pollutants.
Supplemental information was derived  from the Cameron Engineers'
1977 report (552) to  close the material balance for  the gas
liquor  separation,  phenol extraction,and gas  liquor stripping
process steps. The block flow  diagram of the process  is shown in
Figure  5-2.  Discussion of the quantity and  composition of the
various  process and effluent, emission and  waste  streams and
their treatment, and comparison of alternate  cases to this base
case, will be undertaken later in the report.

The Lurgi  plant design in the Braun report  produces pipeline
quality gas from a Western subbituminous coal.   Coal from the
mine is  received  in the coal handling section.   The  coal is
crushed to less  than 1-1/4 inches and is  then  screened with the
greater  than 3/16-inch fraction being sent  directly  to the
gasification section while the less  than 3/16-inch  fraction is
used as fuel in the main boiler.

Coarse coal in a size range of 1-1/4  inches x 3/16 inch is fed  to
the gasification section where it is gasified  at  a  pressure of
450  psig with oxygen  and high pressure steam.   Ash  from the
moving-bed gasifiers  is quenched with water.   The  total ash
leaving  the gasification section contains  about 12.7 percent
carbon.
                            80

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The raw synthesis  gas  leaving the gasifiers  is  quenched with
water  and cooled in a waste heat  boiler to  produce low pressure
steam  at about 100 psig.  Condensed tarry gas  liquor is sent to
the Phenosolvan unit.

Cooled synthesis  gas is next sent to the  shift  conversion and
cooling  section  where  the H^ to  CO  ratio  is adjusted  in
preparation for methane synthesis.  A cobalt-molybdenum catalyst
is employed which  is activated by  H_S and  which also aids
hydrogenation.  Carbon monoxide  is converted to hydrogen via the
water  gas shift reaction:
                   CO + H20 =  C02 + H2

Also some COS is converted to H2S via the reaction:
                   COS +  H2S =  CO + H2S

Small  quantities  of higher phenols and heavy tars are hydro-
genated to lighter  products.  Some desulfurization of naphtha
also occurs. >.It is necessary to  by-pass about M5 percent of the
gas around the shift converters to control  the H2/CO  ratio.
After  shifting, the gas is cooled in waste heat boilers  where low
pressure steam at  125  to 150  psig  is  produced.  The  gas is
further cooled in boiler feed water heaters and finally  cooled in
air- cooled and water-cooled exchangers.  The condensed oily gas
liquor is combined  with  that  condensed in  the gasification
section and sent to the Phenosolvan unit.

In the Phenosolvan unit tars and tar oils  as  well as expansion
gas are separated from the aqueous streams and routed to the main
boiler.  Clean and contaminated gas liquor  streams from separa-
tion are sent to  the extraction section.   Phenols in the gas
liquor from the  gasification and  gas  cooling sections are
extracted from the  water with isopropyl ether as the solvent.
The solvent is distilled from the phenols  and returned to the
                           81

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oo
ro
                                                                                                                     499.-I

                                                                                                                     SOLUTION PURGE
                                      (CONTAMINATED GAS
                                         1IQUIO
                                         1969.6
          _^ TO DEMATBRIMG t TRAHSFBR
                    3016.9
I CLEAN GAS LIQUOR
1    12316.6

   PHENOLS	
    135.1

   DEMENOLIZED CLEAN
                                                             LIQUOR 125.25
                                    DEPHrNOiriED COBTAX IBMEO
                                     GAS LIQUOR  1C S.I
 STACK GAS

 81386.6


 SULFUB
~>3Ti
                                                                                        12056.5
       Figure 5-2.-  Flow  diagram for  SNG production by Lurgi  gasification of  low sulfur  coal.

-------
extractor.  The dephenolized water is  then  stripped with steam  in
the deacidifier column to remove C02 and H-3.  Acid gas from the
top of the column is sent to the boiler  and the bottoms flow  to
the ammonia stripper.

An aqueous ammonia stream is removed  overhead from the ammonia
stripper column  and sent to storage.   The  bottom  stream  is
relatively clean water which goes to further processing.

The cooled, shifted synthesis  gas is  heat  treated  to  remove
naphtha.  This removal is effected by  either chilling followed  by
vapor-liquid separation and reheat  or by  absorption  of the
naphtha (CH   and  higher)   in a lean  oil  followed   by
            6 6
distillation.

The synthesis gas is next -recessed in two  separate Selexol gas
purification units.  The first  removes  H_S, CS. , and a  small
percentage of the COS.  The second removes  CCL and the  remaining
COS.  The Selexol  units use organic solvent at medium to low
temperatures.

The Selexol H_S removal unit employs four  absorption  trains and
two stripping trains to accomplish essentially complete removal
of H-S (1 ppm H S remains in the absorber overhead gas).  Rich
solvent from  the absorbers flows through a  series  of flash  drums
to remove C02 and produce a concentrated H2S stream.   Flash gas
is compressed and returned to the bottom of the absorbers  after
cooling.  Rich  solvent, now depleted in C02, is pumped to the
strippers.  H2S is removed overhead and  routed to  the Claus plant
for sulfur recovery.   Lean solvent  from  the  bottom of the
strippers is  pumped  through heat exchangers and  coolers before
returning to  the  absorbers.  Low pressure  steam  provides heat  for
reboiling the strippers while air and cooling water remove heat
in the overhead condensers.
                           83

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The Selexol  C02 removal unit employs eight absorption trains and
four stripping trains to accomplish about 95  percent removal of
CO  and essentially  complete removal  of COS.   Chilled  lean
solvent contacts feed gas countercurrently in the absorbers.  The
lean solvent  temperature is optimized in  the  design for minimum
power requirements for the system.  Rich solvent flows through a
series of hydraulic  turbines (for power recovery) and  flash
drums.  Most of the  C0? (about 83.4 percent  of that removed)
along with all of  the entering COS is  released from the last
flash drum.   This stream contains  substantial quanties of CO, H2,
and hydrocarbons (CHn   and CpH,-) and therefore must be treated
before release to  the atmosphere.  Since the  heating value is
substantial,  the recommended treatment  is  incineration in the
main boiler.

Further in operation of the Selexol unit, semi-rich solvent is
pumped to the C0? stripper where the remaining 16.6 percent of
the CO 2 is removed by stripping  with nitrogen gas.  The presence
of combustibles in  this  stream similarly dictates  further
treatment.   Incineration in the  main boiler is  the method chosen
in this study.  Lean solvent from  the bottom of the strippers is
pumped back  to the absorbers.

The CO  Absorber overhead gas flows to  sulfur  guard beds which
use zinc oxide to  remove trace quantities  of sulfur-bearing
compounds.  The purified synthesis gas  proceeds to the methane
synthesis section where the CO and H  are catalytically converted
to methane via the following reactions:
              CO + 3H2 = CH4 +  H20

             C02 + ^H2 = CHjj +2H20

The conversion is  accomplished in  a  three-stage,  fixed-bed
reaction system where the bulk of  the methanation is done in .the
first two  stages  with recycle of effluent  gas for temperature

                             84

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control.  High pressure steam is produced in waste heat  boilers
following the methanators.  The final  heating value of the gas is
reached in the third-stage menthanator.   The gas at 970  Btu  per
SCF  is produced at 285 psig.  The wet  product gas is compressed
to 1017 psig, cooled to 100°F and sent to product gas drying.

Drying is accomplished in a conventional  glycol  dehydration unit.
Water is absorbed from the gas stream  and subsequently  stripped
out  in the regenerator column.   Overhead water vapor  from  the
column  contains  some  CH. and  the  stream must be incinerated.
                        4
Substitute natural gas (SNG) at 100°F  and about  1,000 to 1.U15 psiq
is delivered to the pipeline.

COAL LIQUEFACTION PROCESSES AND DATA GATHERING

As with coal gasification, several  coal  liquefaction  processes
have been proposed and have been carried  through some  or all of
the  usual stages  of development, as  laboratory scale,  process
development unit  (PDU) , pilot  plant,and demonstration plant.
Only two, the Bergius system that was  developed to produce fuel
oil  and gasoline and the Fischer-Tropsch system that  was devel-
oped to produce  a  wide range  of organic chemicals and fuels,
have been operated commercially, and of these only the  Fischer-
Tropsch system is still in operation.  Data and information on
the  emissions, effluents and wastes  (e/e/w) from coal  liquefac-
tion processes other than the Fischer-Tropsch  system  must there-
fore be derived from small scale operations in the  form of  re-
ports of operations, reports  of sampling and analysis  of e/e/w
and from conceptual process  designs  that were  prepared as
economic and, in some cases, environmental impact studies.

Review of published literature on development of  coal lique-
faction processes  revealed  that most of the available reports
were concerned principally with  progress  of process  development
                             85

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and operating  experience and that e/e/w  were  not treated in
detail.   Conceptual designs for commercial  scale plants made use
of as much  e/e/w data as were available and  calculated the
remainder of the  material balances.  The problem of securing  data
and information on the e/e/w of some of the developing processes
was further  complicated by the fact that  initial process deve-
lopment was  private, the process  information was considered  to be
proprietary  and there were  no  publications  of usable
information.

Published information is available  on  six  coal liquefaction
processes that  are judged to be of importance according to  stage
of development, schedules for construction and further develop-
ment, potential for commercialization,  probability of successful
development  and probable applicability of  the process.  In  these
processes operating conditions are chosen so that the residual
solid produced  can be  minor, as an ash concentrate, or major, as
low sulfur coal or metallurgical  coke.   All of these processes
employ hydrogen in  order to  increase  the yield  of  liquid
products.

The six processes may  be grouped according to  their general  type
of operation as either pyrolysis/hydrocarbonization  or  solvent
hydrogenation:

                    Pyrolysis/Hydrocarbonization
                    COED
                    Clean Coke
                               86

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                    Solvent Hydrogenation
                    Solvent Refined Coal (SRC)
                    H-Coal
                    Donor Solvent
                    Synthoil

In  general, coal  liquefaction  processes are more  nearly alike
than are coal gasification  processes.  For example,  since all
liquefaction processes produce hydrocarbon liquids,  it  is inevi-
table that there  will be effluent  streams containing phenols,
oils, and tars (p/o/t) and that these streams  will require  efflu-
ent control systems similar  to those applicable  to the  p/o/t-pro-
ducing gasification processes.

Hydrogen for coal  liquefaction  is generated  either  by  light
hydrocarbon reforming or by  C-sification of residue  or  char.  The
general  statement may be made that hydrogen production  by similar
methods  yields similar effluents and requires similar control
methods  for that  process step.  All conceptual  designs for com-
mercial  plants include gasification processes that produce  no
p/o/t, with operation at high temperatures and  discharge of ash
as  a slag.

Coal Liquefaction Processes

COED—
The process uses a four-stage  fluidized bed  reactor  usually
operating at a pressure less than 1 atmosphere.   The first stage
temperature is about 175°C,  the second is about 430°C,  the third
is  about 540°C and  the fourth is  about 815°C.   Oil,  gas,and char
are produced in the first three stages of pyrolytic  liquefaction.
The char is partially gasified in the fourth stage to produce the
hydrogen for the  process.
                              87

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 Early  studies on the gasification  of the COED char led to the
 development of the COGAS process which can operate with either
 the  char feed or with coal  feed.   With char  feed, COGAS may be
 considered to be combined with COED as the  fourth stage of the
 process.

 The  process was developed by FMC and others.  It was demonstrated
 in a 36 TPD pilot plant  in  Princeton, N.  J.   When testing was
 completed in 1975 the pilot plant  was dismantled.  Data  from the
 operation were used  in a  conceptual design for a 25,000 TPD  plant
 by Ralph M. Parsons  Co.   The COGAS process,  developed to gasify
 the COED char, occupies  the efforts of FMC and others.   The  pro-
 ject is now called the COGAS Development Company.  The  Illinois
 Coal Gasification Group  is at  present the main  supporter of the
 project, together with DOE.  Emissions data from COED are scanty
 and incomplete.   As  noted in  the  COGAS status  description,  al-
 though a DOE contract has been signed for development of a  con-
 ceptual  design,  completion  date  for the  design has  not   been
announced.

Clean Coke—
Dry coal is pulverized to minus  20 mesh, then  pyrolyzed in the
carbonization section in  a  fluidized bed at  about 705  to 760°C
and at a pressure of about 7  to  10 atmospheres.  In the hydro-
genation section, hydrogen and a slurry of  coal and oil are fed
and processed at about 200 to 300 atmospheres.  Char  from the
pyrolysis section is pelletized  with process-derived heavy oil
and is partly gasified to yield  hydrogen for  the pyrolysis and
hydrogenation steps  and the process product, metallurgical coke.
Fuel gas and medium  oil are other  products.

U. S. Steel developed the process.and operated  a 1,000 pound per
 day process development unit on Illinois No. 6 coal.  The project
 is now continuing with DOE participation.  No emissions data  have
                              88

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been published.   A  100  TPD pilot.plant  has  been announced as
planned  for Monroeville,  Pa. but  no completion date has been  set.
A conceptual design for a commercial  plant is in progress.

Solvent  Refined Coal (SRC)—
The SRC  process is  being developed  by  the  Pittsburgh & Midway
Coal Mining Company,  a subsidiary of Gulf  Oil,  in Fort Lewis,
Washington and is  operating in a 50 TPD pilot  plant with DOE
participation.   Dry  coal,  solvent,and hydrogen are  fed  to a
dissolver operating at 68 to 136  atmospheres at temperatures  from
about 425 to 495°C.  Final products from the dissolving section
are solvent refined coal, fuel  oil, and naphtha.  In a commercial
plant residue from the process  would  be gasified to produce  pro-
cess hydrogen and SNG.

Data from operation  of  the 50 TPD  pilot plant  at Fort Lewis,
Washington have been reported in  literature  and progress reports.
Unfortunately, much  of  the water treatment  data  is for the
combined total of wastewater from the process  plus once-through
cooling  water plus cooling tower and  boiler blowdowns plus the
plant runoff.  The reported  data  demonstrate the treatability and
biodegradability of the total,  highly diluted SRC wastewaters,
but do not allow consideration  of control  technology application
to the   individual  streams.  It is  understood that  plans are
underway for more  detailed analysis of  the  process  emission
streams.  The process  has been  changed  from  the  original,
designated SRC I,  to a  variant designated as SRC.II.   It is
understood that the process  change  will  not  significantly change
the wastewater composition.

DOE is the principal participant in  the Fort  Lewis operations,
with Pittsburgh & Midway operating  the pilot plant and performing
control  analyses.  Various DOE  subcontractors have been, or  are,
conducting environmental and toxicity studies.  Some  usable
                             89

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emissions data have been  collected and more information is being
developed.  SRC therefore appears to be one  of the best sources
of liquefaction information and  samples for evaluation of  control
technology,  provided DOE  decides to let contracts to licensors
and vendors  of control  technology and equipment.

H-Coal—
In Hydrocarbon Research's H-Coal process coal is hydrogenated
directly in  an ebullating bed of catalyst  at a temperature  of
about M55°C  and at a pressure  of about 200 atmospheres.  Liquid
products are either low  sulfur boiler fuel  or synthetic crude
oils, depending on the  degree  of hydrogenation.  Gaseous product
is SNG.  Residue, in some cases supplemented by coal or light
hydrocarbons,  is gasified to produce process hydrogen.

The H-Coal process was developed by Hydrocarbon Research Inc.
through bench-scale and  PDU  for production  of synthetic crude
oil.  Recent studies have been in the conversion of coal into  low
sulfur fuel  oil.   A 600 TPD pilot plant is now under construction
in Catlettsburg,  Kentucky, scheduled for 1978 completion and  for
operation into I960.  DOE is funding about 75% of the work, with
the remainder  coming from industry and EPRI.   Fluor is preparing
a conceptual  commercial  design.   Water  analyses  and  useful
treatment data have been  obtained.   Aware,  Inc. was engaged  to
perform treating experiments and reported some of the results  at
the recent Purdue Waste Conference.  The full  text of the Aware
report has been released  to Pullman Kellogg by DOE.

Donor Solvent—
The Exxon Donor Solvent process  requires coal ground to minus  30
mesh.  This  feed is slurried in  recycle solvent that carries  part
of the hydrogen for the process  and is mixed  with more hydrogen
in the liquefaction reactor that is operating at 99 to 172 atmos-
pheres and at  about 370 to 380°C.  Actual liquefaction conditions
                              90

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are dependent  upon  the coal being  processed and  the  degree  of
conversion desired.   No catalyst  is  used in the liquefaction
reactor.

Liquefaction product  is separated  by  vacuum distillation  into
liquids, gas, and a residue consisting of unreacted  coal  and  ash.
The raw coal liquids  are processed further as synthetic  crude
oil.   Spent solvent is catalytically hydrogenated at  (unspeci-
fied)  temperatures  and pressures  for  recycle to  liquefaction.
Gases  from distillation and solvent hydrogenation are  used for
fuel or for hydrogen generation.  The residual  still  bottoms are
used to generate hydrogen and,  in the course of  the gasification
reactions, produce more raw coal liquids.

Exxon  is operating a one TPD PDU at Baytown, Texas.  Proprietary
designs are being developed "or a 250 TPD pilot plant  and  for a
commercial plant.

DOE is now sponsoring  operation  of  the  PDU.   No emissions
analyses and little specific process data were  published by Exxon
prior  to DOE sponsorship.  Although Exxon is reporting  to DOE
monthly, to date these reports have not become  available through
publication services.  DOE is  providing  funding for  half the
construction and  operation of  the  pilot plant, with  Exxon and
other  industry sources providing the rest.  Construction  of the
pilot  plant in Baytown, Texas is scheduled to  start in mid 1978.

Synthoil—
In a turbulent, cocurrent, upflow packed bed reactor, a  slurry of
coal and recycle oil is catalytically hydrogenated into gas and
low sulfur fuel  oil products.   Operating  temperature is  about
^500C  and pressure is  about 136 to 271 atmospheres.   Residue from
liquefaction is used to produce the process hydrogen.
                              91

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The process  was  developed originally  by the U.S. Bureau of Mines
and development is now continuing  at  the Pittsburgh  Energy
Research  Center.   A 10 TPD PDU is  being  built  in Pittsburgh,
scheduled  for  1978  completion.   Foster Wheeler Energy Corporation
designed and is  managing the construction of the PDU.

Several reports  have been published by USBM and include process
material balances,  trace element distribution  among the various
process streams, evaluation of  the environmental  aspects of the
process, and  product analyses.   Since  most of the data concern the
process and  products, only a small portion  of the data is usable
for definition of  control technology requirements.  The trace
element determinations were preliminary and exploratory in  nature
but do indicate  that most of the trace  elements appear in the
residue and only  very small  amounts  appear in  the  process
effluent water.

DEVELOPMENT  OF LIQUEFACTION EMISSION  STREAM MODELS

The initial efforts in gathering data  and  information on the
compositions  and  quantities of the emission/effluent/waste
(e/e/w) streams from  the liquefaction  processes  were  not as
successful  as were those concerning gasification  processes,
principally  because most of the processes are proprietary, or
were until DOE participation began, and little usable process and
e/e/w information  was  published by  the  process  developers.  A
secondary reason  for  lack of information  is the  normal R&D
emphasis  on process development rather than  on process e/e/w
evaluation.  Construction and  operation of  pilot plants,  however,
requires provision  for treatment and  disposal of e/e/w, with the
added fact that  such streams are large enough in the pilot plant
operation  to allow meaningful sampling, analysis,and quantity
measurements to  be  taken.  The  future operations of the processes
therefore  should yield information usable in determining control
                              92

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technology needs designed  for specific streams  from  specific
processes.  Until this  information is available,  however,  the
compositions of most of  the  e/e/w streams from coal  liquefaction
processes must be estimated  from published data or  by  comparison
with similar streams in  other  processes.

The generalized block flow  diagram of Figure  5-3  includes  the
major process steps  in coal  liquefaction  processes.   Only those
streams  that would be  expected  to leave the  process battery
limits or that must  be treated  before recycling are  indicated on
the  diagram.  The  results  of the literature  search and data
gathering efforts are  summarized in TABLE 5-3.

Emissions, Effluents and Wastes from Liquefaction Processes

The gaps in the e/e/w stream  data that  are  shown  in TABLE  5-3
obviate any attempt  to derive  approximations of quantities  and
compositions of effluents,  emissions and wastes,  in  a  manner
similar to  the early  attempt  in the  gasification process
analysis, and for much the same reasons.

Because  of the similarities  of  the  e/e/w  from the various
liquefaction processes, and  because  the differences  in  the
streams between processes are  principally in concentration  and
quantity and to a lesser degree in composition,  the premise  may
be adopted that control  technology applied to  one  liquefaction
process should be generally  applicable to the  other  processes.
Accordingly, the Solvent Refined Coal (SRC II) process was chosen
as representative of liquefaction processes and became  the base
case for the investigation of  control of  effluents,  emissions, and
wastes.  Data from the Ralph M. Parsons Company conceptual design
for  SRC  II (814) was supplemented by analyses  and treating
results from H-Coal  to establish representative quantities  and
compositions of the  streams.
                              93

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COAL
STORAGE
DUST
(1)^
COAL PILE RUNOFF (2)
NON-OILY WATER RUNOFF (3).
OILY WATER RUNOFF
i
COAL PREPARATION VENT
AND FEEDING SLURRY
(4);
(5)
(6)
LIQUEFAC1

i
\
-»i
— »•
^••M




PRODUCT
SEPARATIC
i
CHAR

HYDROGEN
PRODUCT-
ION AND
PURIF-
ICATION
1
SULFUR
RECOVERY

GAS


PURIFICATION


CATALYST PURGE (7)_
FLUE GAS

WASTE WATER
VENT
(8)'
(9)*
(10)^
FUEL OIL PRODUCT .
CHAR PRODUCT _

AS
PI
I
ASH (12)

H RUNOFF (11)
LE

SPENT CATALYST (13)1
CO,, VENT
(14 )_
ABSORBENT PURGE (15)^
WASTE WATER
VENT
(16)1.

SULFUR PRODUCT __
ABSORBENT PURGE (!£)_
SOUR WATER
CO,, VENT
GAS PRODUCT
(19)'
(20)^

Figure 5-3.
Emission streams from coal liquefaction
processes.
                     94

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                                                      TABLE 5-3.  AVAILABLE INFORMATION ON EMISSIONS FROM
                                                                     COAL LIQUEFACTION PROCESSES
Stream Analyses*
123456
COED P
Clean Coke
SKC Q
Il-Coal
Donor Solvent
Synthoil
7 8 9 10 11 12 13 14
P P Q

A 0
Q A

Q A
15 16 17 18 19 20
PA PA

A A
A A


ui
           *  A = Analysis, either real or from conceptual design.
              P = Partial analysis.
              Q = Quantities only.

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 Base  Case Flow Sheet and  Material Balance

 The  block flow diagram  of  the  SRC II liquefaction process is
 shown in Figure 5-4  with  the weight flows of the various process
 and effluent, emission, and waste streams indicated.   Discussion
 of the composition of the streams and their  treatment, and com-
 parison of alternate treatment means to the  base treatment will
 be undertaken in Section  8 for  liquid effluents,  Section 9  for
 gaseous emissions and Section 10 for solid wastes.

 The SRC II plant design in the Parsons report  produces naphtha,
 fuel  oil,  pipeline  quality gas and other  gases  equivalent to
 liquefied petroleum  gases.  Coal from the mine is received  in  the
 coal handling section and ground to about 800  micrometers.   The
 ground coal is mixed with solvent, hydrogen is added  and the mix-
 ture is heated and fed to the dissoiver where, at 150 atmospheres
 pressure and at 455°C,  the coal  reacts  exothermally    and dis-
 solves.   The dissoiver product is separated into a gas phase  and
a slurry  phase.  The gas phase is cooled,  depressurized,and
separated into a gas stream, which is fed to the acid gas  removal
section,  and a liquid  stream, which is further separated into  a
hydrocarbon stream and a  sour water stream.

The slurry phase from the dissoiver, containing dissolved coal,
unreacted coal, char,and  dissolved gases,  is  cooled, depressu-
rized, mixed with recycled wash oil from the filtration unit, and
 fed to a fractionator for separation into light and heavy  distil-
lates and bottoms.  Light ends are stripped from the  distillates
and hydrogenated to  naphtha  at  about 50° API  gravity.  Some of
 the heavy distillate is blended with the light distillate  and  the
 filtrate from the filtration unit into fuel  oil  product.   The
 rest of the heavy distillate is used as wash  oil in  the filtra-
 tion  unit.   The fractionator  bottoms stream,  containing  all
                             96

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of the solid residue from liquefaction,  is cooled  and  divided,
with  part being recycled to the  coal  slurrying step  as process
solvent and the rest  being filtered  to  separate the solids as
filter cake from the liquid.  The liquid  is recycled  to  the coal
slurrying step.  The filter cake is dried and  fed  to  the fuel gas
gasifier.

The coal dissolver  gas phase,  after cooling, separation, and
treatment to remove  acid gases,  is  dried and  cryogenically
separated into a hydrogen-rich  gas  stream, a methane-rich gas
stream and a vapor-liquid stream containing ethane  and heavier
hydrocarbons. Part of the hydrogen-rich stream  is  recycled  to the
coal  disolver while  the rest  is  treated in a methanator,  to
convert its carbon monoxide to methane and water,  then dried and
sent  to naphtha hydrogenation.  The methane-rich  stream  is  metha-
nated, compressed,  cooled, dried, and  adjusted in  composition to
the SNG heating value of 1,050Btu per  SCF (HHV)»  by  admixture of
ethane and propane from the deethanizer in the  LPG fractionation
unit. In  the LPG fractionator  the  vapor-l.iquid  stream is sepa-
rated into ethane  for recycle  and  propane and  butane  as LPG
products.

In a  2-stage, entrained flow,  slagging gasifier,  operating at
1,000°C,  coal is converted to methane and synthesis  gas.   The slag
residue is quenched, partially separated  from  the  quench water in
hydrocycloneSj and  then sent  to  disposal as a slurry or as wet
solids.   The excess quench water is cooled and  recycled.   Product
gas is cooled, particulates are  separated  in cyclones and dust
filters and returned to the gasifier,  then  the clean gas reacts
with  steam over a sulfur-resistant catalyst to  hydrogen  and

•Standard cubic foot (higher heating value)
                             97

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                MCOV. CHA« 4H7.J j

                RECOVERED MATER 558.*
I CONDEMSATE TO STEAM SYSTEM
      174.5
    I COM- •
Figure 5-4.- Coal liquefaction.   SRC  II block  flow diagram and material balance,

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carbon dioxide.  An  acid gas removal step separates carbon
dioxide, hydrogen sulfide and other sulfur  compounds from the gas
stream, then the purified hydrogen is  fed  to  the  coal dissolver.

An air blown, slagging,  suspension-type gasifier is  fed  with
dried  filter cake, recycled char and fresh  coal.   Slag residue is
handled as previously described.  Hot  char  is separated  from the
product gas stream  and used to  dry the filter  cake.   A sulfur
removal step reduces the sulfur content of the gas  sufficiently
to permit use in steam generation and  process furnaces.

Sour water collected from the process  units is freed of  oil  in a
separator.  The oil is recycled to the fractionator in  the  coal
liquefaction section.  In a stripper column  ammonia and H2S are
removed from the  oil-free water  and  sent to  ammonia  recovery,
while  the cleaned  water is  sent  to the process gasifier steam
system.  Ammonia is separated from H»S in  the Phosam  (U.S. Steel
proprietary) process by selective absorption into a  monoammonium
phosphate solution.  The ammonia  is subsequently stripped  from
the solution, dried,  compressed, and  liquefied as  anhydrous
ammonia.   The overheads from  the absorber  are sent  to sulfur
recovery.

The Rectisol process, developed by the German Linde Company and
Linde  A.G., uses a  proprietary solvent to  absorb  CO  and H_S from
the process gasifier product  gas stream and then  selectively
desorbs the gases into an H^S-rich stream  that is sent  to sulfur
recovery and a C0?-rich stream.  The CO -rich stream,  containing
about 830 ppm of  carbon monoxide and about 10 ppm  of HO, is
incinerated in the  power generation boilers.

Sour gases  from the coal dissolving unit and vent gases  from the
naphtha hydrotreater are combined and  fed  to a  contactor  where
H S, COS and CO   are chemically absorbed  in monoethanolamine
                               99

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(MEA) solution.  Clean gas becomes part  of  the SNG and  LPG
production.   Regeneration  of the amine  solution yields an
I^S-rich stream that is sent to  sulfur recovery.
                            100

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                           SECTION 6

              CURRENT ENVIRONMENTAL BACKGROUND
                   ENVIRONMENTAL REGULATIONS
INTRODUCTION

A survey was made of present and currently proposed  environmental
restrictions relevant to contaminants in the   effluents, emis-
sions,and wastes from coal conversion processes  to  serve as the
measurement standard in evaluating available and developing con-
trol  technology for  such processes.  The environmental restric-
tions set forth in Federal and state rules  and  regulations were
reported together  with selected  international  and  regional
regulations.  The most stringent of the air and  water regulations
included herein have been summarized for convenience.
OBJECTIVES OF THE SURVEY

The prime objective of the survey was to assemble a single  source
reference document of applicable  environmental  regulations for
use in  considering both present control technology capabilities
and necessary future technologies for controlling pollutants  from
the conversion of coal to gaseous or liquid fuel.

A second objective  was to summarize the most  stringent of the
environmental regulations  presented herein so that  a  single
source of environmental requirements  representing  the most
                              101

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restrictive  of present  and  proposed  regulations would  be
available.  A coal  conversion facility built in the United States
to meet the requirements in this most stringent summary would, by
definition, meet the  requirements of any individual  state.   The
summary was by necessity limited primarily to  those  regulations
of a  quantitative  (numerical)  nature  and  did  not "include
ordinances below the  state jurisdictional level, since these were
beyond the scope of the project.  Special requirements introduced
by individual states'  permitting authorities were also beyond the
scope of this project  and were not included.

Another major objective was to provide an in-depth survey of the
regulations of the  selected states which had not been  available
previously to the extent presented in the survey.  An example of
the wide coverage of  this survey is the inclusion  of  the U. S.
EPA regulations applicable to  Fluid Catalytic Cracking Units,
Petroleum Refining  Category, upon reasoning that giving a broad
definition to Petroleum Refining, as some states do, makes  such
regulations  potentially relevant  to expected  further on-site
processing of coal  liquefaction products.
BASIS FOR JURISDICTIONAL SELECTION

The first phase  of  the  survey is concerned with federal  and state
environmental  regulations.  As such regulations  are  continually
being amended  they can only  be  reported current  as of a given
cut-off date.  The  cutoff date for the federal and  state material
in this report was  31 October 1977.  The second phase supplements
the first with a survey of regional and international regula-
tions.  Cutoff date for the second phase was  15 April  1978. On
the premise that the first phase activity should be  as  broad as
possible, it was decided that expanding the material considered
relevant would be preferable  to  restricting  it.   Consequently,
                              102

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whenever  it appeared  that a particular  standard  or regulation
might have at least some present  or  potential  relevance,  it was
included  in the survey.  This approach was also advantageous with
respect to use of the survey by project personnel as a source of
guidelines to demonstrate the type and  degree  of restrictions
placed on environmental contaminants.

The approach taken in the first phase was  to  collect, organize,
review, and synopsize environmental laws,  regulations, standards,
and other restrictions of probable  relevance.   The coverage of
this survey has intentionally been made as broad as possible to
present the widest and most divergent restrictions in effect at
both the  federal and  state levels.  No  local  jurisdictional
environmental requirements below  the state level  were included in
the survey.  As the commercial  coal  conversion facilities which
are the underlying subject r.atter of this project are all  yet to
be built, only regulations pertaining  to new  facilities,  as
opposed  to  existing  facilities, have been  considered  and
included.

To make  the initial  collection  and  review  of environmental
factors  as meaningful  as possible,  it  was  decided that  the
selection of the states to be included  in  this  environmental
survey would be based  on the reported  availability of  coal
deposits  within the various states.   This  basis  was  chosen
because  economic factors favor  sites near  coal  deposits  for
possible  coal conversion plant  locations.   Accordingly,  the
environmental laws,  regulations,and  standards for 22 states were
included with the federal restrictions in  the  first phase.   The
review of these state  and federal  requirements is broken down
into the following three main areas:

         Air Pollution Regulations
         Water Pollution Standards
         Solid Waste Requirements

                             103

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A preliminary screening was  carried out to determine most  of  the
common contaminants normally present and to examine the state  and
federal regulations in view  of  these contaminants.  The list  of
contaminants was extended  as the  work  progressed.

It  is  noteworthy that, of  all the states  surveyed,  only  New
Mexico has to date promulgated  regulations  which have specific
applicability to fuel conversion facilities,  and these regula-
tions cover only the air pollution control area.
JURISDICTIONAL SELECTION

In addition to the  federal  environmental restrictions and  guide-
lines included within  this  survey, regulations for the following
states were selected based  on the state's  potential for  future
plant siting:

          Alabama                    North Dakota
          Alaska                      Ohio
          Colorado                    Oklahoma
          Idaho                      Pennsylvania
          Illinois                    Tennessee
          Indiana                    Texas
          Kansas                      Utah
          Kentucky                    Virginia
          Missouri                    Washington
          Montana                    West Virginia
          New  Mexico                  Wyoming

In addition, the  requirements as  established by the U. S.  Public
Health Service Drinking Water Standards, 1962,  and the Interim
                              104

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Primary Drinking  Water  Regulations were synopsized  and included
in the survey.

Although California  was one  of  the states initially  selected for
inclusion  within the  survey,  because of time  limitations and
California's unique  method of establishing environmental  restric-
tions, California regulations are not being included.   California
also ranks quite  low among the  selected states  in reported coal
deposits.  North  Dakota,  which  has both  sizeable coal deposits
and projected conversion plants, was substituted for California.
The review of federal and state standards was  supplemented by a
review of standards  and guidelines established  by  the Delaware
River  Basin Commission,  since the authority  of this regional
commission extends  over geographical,  rather  than political,
areas and therefore  considers the area environment unconfined by
artificial boundaries.   It was found that  the standards and
guidelines adopted by the Susquehanna River Basin Commission are
those of the states  affected by the Commission.

Further consideration of the argument that environmental effects
are not limited by political boundaries led  to  the  inclusion in
the  survey of the  standards  and guidelines  that  have been
established by Mexico and Canada.   The Mexican regulations are
federal  actions, while  in  Canada both  the  Dominion  and the
provincial governments have enacted standards and guidelines.
Therefore,  Mexican federal  standards, Dominion  of Canada
standards and guidelines, and the standards and  guidelines  of the
provinces  of Alberta  and  British Columbia  became part of the
survey.  The two  provinces  were chosen because their boundaries
are  continguous with  those of Montana,  Idaho and Washington,
where much of the U.S.   western coal reserves are located.

Finally, the rules and  guidelines established by U.S.-Canadian
International Joint  Commission  were included in  the survey,  since
                              105

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these are primarily concerned with  the  Great Lakes and  the  St.
Lawrence River  areas and thus complete  the  regulatory coverage of
the northern  U.S. border.
METHOD OF  INFORMATION ACQUISITION

The information  required  for  the survey of environmental
regulations was acquired in a series of steps:

      A review of the  applicable Code of  Federal Regulations
      (CFR) to determine the relevant federal environmental rules
      and  regulations.

      A daily review of the Federal Register to  determine appli-
      cable rules and regulations promulgated subsequent to the
      CFR  edition, and additionally, any proposed rules,  regula-
      tions, or notices which would be of concern.

      An initial request,  prior to project inception,  to  the
      appropriate agencies of states selected requesting copies
      of their regulations.  A request  was also  made that  Pullman
      Kellogg be placed on mailing lists so as to be kept up-to-
      date on each state's activities in the environmental area.

      A subsequent request to all selected  states upon project
      inception for their current regulations to ensure  that the
      latest information would  be on hand.   Those states which
      had  indicated that they were either  revising  their regula-
      tions or considering doing so were again  contacted to de-
      termine the status and, where possible, draft regulations
      were obtained, reviewed and included within the  survey.

      A review of Canadian  regulations  and guidelines,  bath
                             10.6

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     Dominion and provincial, in Pullman Kellogg's domestic and
     Canadian files for rules pertaining to the environment.

     A  review  of the  actions of  the International  Joint
     Commission of the United States and  Canada, for relevant
     environmental rules.

     A  review of the appropriate Mexican regulations in the law
     library of the University of Texas in Austin.

     A  limited  environmental literature  survey  was conducted
     through NTIS and selected EPA data base searches, and var-
     ious technical periodicals were received  and reviewed for
     useful information concerning federal and/or  state environ-
     mental restrictions.
SPECIFIC ENVIRONMENTAL AREAS COVERED.  COMMENTS

Air  Emission Criteria

A review was conducted of the  Federal EPA  air emission regula-
tions with designated emission source categories therein, of  the
selected state regulations, of the regional and the international
regulations  and guidelines. The potentially  relevant air pollu-
tion standards were then synopsized for eventual inclusion  in  the
survey report.  As previously  stated, the  scope  of this survey
was  purposely kept broad so as to provide the most comprehensive
listing of existing and proposed regulations possible.

The  following are comments generally applicable to a large  major-
ity  of the jurisdictions surveyed:
                              107

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A permit is required  for construction, modification, or re-
vision prior to commencement of the construction, modifi-
cation, or revision  contemplated.

Exceptions to the regulations are generally available for
plant malfunction,  startup, and shutdown  so long as speci-
fied reporting requirements are complied with.

Dilution of any effluent or emission as a means of satisfy-
ing restrictions is prohibited.

Where there are several  rules or standards applicable  or
more than one interpretation is possible,  the most strin-
gent should be applied.

In most  jurisdictions, application for a variance from the
established emission  limits is possible, with discretionary
approval  authority in the jurisdiction's  air  pollution
control  agency.

Some states have specific  geographical areas or air pollu-
tion control districts (sometimes heavily populated  coun-
ties) which may have  individual standards more stringent
than the state-wide or "out-state" standards.  No  attempt
was made to  include  these "localized"  standards  in this
survey  although a few  of these  regulations  have been
included for comparison.

Emission limitations  applicable only to mobile sources were
not considered as these  types of regulations are not within
the scope of the project.

The various regulations  pertaining to  monitoring of  emis-
sions were not included  since these  regulations are also
beyond the scope of the  review.
                        108

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All the  selected quantifiable  standards as of the  aforementioned
cut-off dates were  compared  and the  most stringent set  of
limitations was assembled;  compliance with these  limitations
would presumably  satisfy any criteria.   The  comparison  of
standards was undertaken  as  to numerical or quantified values
only.  Other regulations  as found  in the synopses would have  to
be considered in the design of  proper control technology as  well.
These  other regulations are  primarily of a  descriptive nature,
sometimes  of considerable  length,  and cannot  readily  be
compared.

Water  Effluent Limitations, Guidelines.and Standards

The Federal EPA effluent  limitations and guidelines  for  specific
point  source categories and water quality standards  of the  se-
lected states were  reviewed  and synopsized.   As  in the air
pollution control area,  the  range of water quality criteria
surveyed was purposely kept broad  to provide  the most  comprehen-
sive listing of standards  possible.

A majority of the states and other  regulatory  bodies have
established water quality  standards which are applicable, for  the
most part,  to existing receiving waters  of the  state.   The
primary  state mechanism for controlling effluents  into  receiving
waters is enforcement  of  the  conditions imposed by  a  required
discharge permit.

An analysis was made  to determine the most  stringent  standards
whenever a numerical  comparison was possible, which  standards
would  then presumably satisfy any  jurisdictional criteria.  Again,
it should  be emphasized that  this was a comparison  of
quantifiable standards only, and other regulations would have  to
be considered.
                            109

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Solid Waste Disposal  Requirements

The Federal Guidelines  and  the selected states'  solid waste dis-
posal requirements  were  reviewed and these guidelines and stan-
dards were synopsized.   The  same policy as to scope and  relevance
of standards was used in this area as in the water and air regu-
lation areas.

The majority of the solid waste  disposal requirements are much
less definitive, with regard to establishing design requirements,
than  those  criteria  established within the  air and  water
regulatory areas.   The  regulations tend to establish requirements
directed more toward  the operation of a disposal facility  than  to
the design, such as adequate rodent control and proper compaction
and cover for solid waste.   Even though the operational criteria
should be considered beyond the  scope of this survey, some  of
these standards are presented for certain selected jurisdictions
as guidelines,  since  these  types of criteria are essentially the
same from area to area.   Also,  many of the  requirements are
applicable to  public authorities,  such as municipalities,  in
their solid waste  collection and disposal activities.

It should be expected that  the regulatory activity in this area
and especially  with respect  to hazardous wastes will continue  to
increase as a result  of  the  Solid Waste Disposal  Act as amended
by the Resource Conservation and Recovery Act  of  1976,  Title  II
Solid Waste Disposal  (42 USC 6901 et seq.).

One provision generally  common to the states reviewed allows for
solid waste disposal  on  one's  own property  without a permit  so
long as no nuisance conditions are created.

Texas, one of the  states surveyed,  has issued  Technical Gyide-
                             110

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lines for solid waste  disposal  and  indicates that by following
these guidelines all  solid  waste  disposal requirements will  be
satisifed.  These Technical  Guidelines are available from  the
Texas  Water Quality  Board,  which  has responsibility  in this
area.
                             Ill

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SUMMARY OF  MOST STRINGENT WATER QUALITY STANDARDS

Notes:   1.  The  following  compilation represents the  most
            stringent criteria as established  by the individual
            states,  regions, and countries  considered for  this
            project.

        2.   It must be emphasized  that this compilation represents
            an analysis based  on numerical considerations  only;
            compliance with these  criteria should, in all  probabi-
            lity, allow construction at  any  location.  However,
            engineering design based on the following criteria may
            result in over design, and this  should be considered
            for any  cost data developed  that  are based  on the
            criteria.

I.    GENERAL CRITERIA FOR RECEIVING WATERS

      A.  The following minimum water quality conditions should be
         applicable to all receiving waters, and such  waters
         should be:

         1.  Free from substances that will  cause the formation
             of putrescent or objectionable  sludge  or  bottom
             deposits.

         2.   Free  from floating  debris  or  other floating
             materials. (Alternate;  Free from floating debris or
                          other  floating materials in amounts to
                          be  unsightly or deleterious.)

         3-  Free from substances producing color, or odor to the
             water.
             (Alternate;   Free from substances  which  produce
                               112

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                    color or  odor  in amounts  to be
                    deleterious  or  to such degree as to
                    create a  nuisance.)

   4.  Free from substances in  amounts which would  impart
       an unpalatable flavor  to fish.

   5.  Free from substances which would  be harmful or toxic
       to human, animal,  plant, or aquatic life.
       (Alternate;   Free  from substances in amounts which
                    would  be harmful  or toxic  to  human,
                    animal, plant, or aquatic life.)

   6.  Free from substances or  conditions in concentrations
       which would  produce undesirable aquatic life.
       (Alternate:   Add  to  above,  "Free from  nutrients
       other deleterious  substances  attributable  to  sewage
       industrial wastes  or other wastes.
       (Alternate:   Add to above - in  amounts which would
                    affect public  health  or  the
                    desirability of the beneficial water
                    use.)

   7.  Free from toxic substances,  heated liquids, or any
       other deleterious  substances  attributable  to  sewage
       industrial wastes  or other wastes.
       (Alternate:   All to above - in  amounts which  would
                    affect public  health  or  the
                    desirability of the beneficial water
                    use.)

B.  Acid Mine Drainage Control Measures (Applicable to coal
   processing)
                        113

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          1.  Surface  and ground water  shall be diverted where
              practicable to' prevent  entry  or  reduce  the  flow into
              and through mine workings.

          2.  Refuse from the mining  and  processing of  coal shall
              be handled and disposed of  in a manner  so  as  to
              minimize  the discharge  of acid mine  drainage  to
              streams.

          3.  Discharge of acid mine  drainage  to  streams  shall be
              regulated to equalize  the flow of daily accumulation
              throughout a 2M hour period.

II.   SPECIFIC WATER QUALITY STANDARDS  - RECEIVING WATERS

      A.  The following specific water  quality criteria should
          apply to all  waters:
          Substance or
          Condition
          pH (range)

          Temperature
          Dissolved Oxygen
          Color

          Turbidity
    Limitation
7.0 to 8.8 (Br. Columbia)

£ 1°C Rise (Canada-Federal)
£ 60°F (Alaska and  Washington)
<_ 85°F (North Dakota)

 >^ 9.5 mg/1 (Fresh water)
 >_ 7.0 mg/1 (Marine water)
 >^ 5.0 mg/1 (probable average)

 None
 <^ 15 color Units (other criteria)
 No Increase
                               114

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Total Coliform
  Bacteria
  50/100 ml
Fecal Coliform
  Bacteria
Settleable Solids
Dissolved Solids
<^ 10/100 mg (Domestic water
supply)
£ 200/100 ml (Probable average)

None (Essentially free)
£ 200 mg/1 - (Pennsylvania)

_< 100 mg/1 (Br. Col., fresh
water)
Oil and Grease
Radioactivity
None
_< 10 mg/1 (Others)

Gross beta - _< 100 pCi/1
Strontium - _< 2 pCi/1
Radium 226 - _< 1 pCi/1
Alpha Emitters - 3 pCi/1
Odor and/or Taste
None
£ 3 Threshold Odor Number
(Probable average)
Total Dissolved
      Gas
       of Saturation
Hardness
£ 95 mg/1, max. 30 day avg.
(Delaware River Basin Commission)
(Delaware River Basin
Commission)
Persistent Organic
Substantially absent
                      115

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    Persistent Organic
    Contaminants (harmful
    to human, animal,
    or aquatic life)
  Substantially absent
  (North Dakota)
    Toxic Substances
Persistant Toxicants - £ 1/2 of 96
hr TLM
Non-Persistant Toxicants -
< 1/10 of 96 hr TLM
    BODs                  <_ 30 mg/1
      (Deoxygenating Waste)

B.  The following chemical pollutants should not exceed the
    specified concentrations at any time:
    Constituent
      Concentration
    Alkalinity

    Alkyl Benzene Sulfonate
      (ABS)

    Ammonia (as N)

    Arsenic
    Asbestos
    Barium
    Boron
    Cadmium
    Chloride

    Chlorine, residual

    Chromium (Hexavalent)
      20-100 mg/1 (Del. R. Basin,
       tidal waters)
      <. 0.5 mg/1
      £ 0.02 mg/1  (N. Dak; next
       value is £0.15 mg/1)
      £ 0.01 mg/1
      Lowest Practicable Level (IJC*)
      <: 0.5 mg/1
      _< 1.0 mg/1
      < 0.002 mg/1  (£0.01 Probable
      < 100 mg/1 (<. 250 probable
        average)
      £ 0.002 mg/1  (Proposed IJC)(Br.
       Col.: Below  detectable limits)
      _< 0.05 mg/1
                          116

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        Cobalt
        Copper

        Cyanide
        Fluoride
        HLS, undissociated
        Iron
        Lead

        Manganese
        Mercury
        Nickel
        Nitrates <_ 10  mg/1
        Phenols
        Phosphorus
        PCB (Polychlorinated
          biphenyl), total
        Selenium

        Silver

        Sulfate
        Uranyl Ion
         Zinc
_< 1.0 mg/1
_< 0.005 mg/1  (Proposed IJC;
 0.10 probable  average)
_< 0.005 mg/1
<1.0 mg/1
£0.002 mg/1  (Proposed IJC)
<_ 0.3 mg/1
£ 0.01 mg/1  (Proposed IJC,  Lake
 Superior;  Ohio =  <_ 0.04)
_< 0.05 mg/1
<_ 0.0002 mg/1 (Proposed  IJC)
<_ 0.025 mg/1 (Proposed  IJC)

_< 0.001 mg/1
_< 0.05 mg/1

_< 0.00 mg/1
_<  0.005 mg/1 (_< 0.01 prob-
  able  average)
_<  0.0001  mg/1  (Proposed IJC;
  <_  0.05  probable average)
_<  250 mg/1
_<  5.0 mg/1
 <  0.03 mg/1  (Proposed IJC)
III.  EFFLUENT STANDARDS
     (When Not Specified Differently  by  Discharge Permit)

     Except as otherwise noted,  compliance  with the numerical
     standards should be determined  on  the  basis of 24-hour
     composite samples, and  no  contaminant  shall exceed five
     times the numerical standards  at any time or in any one
     sample.
•IJC = International  Joint  Commission of United States and Canada
                               117

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A.  No effluent shall contain the following:

    1.  Settleable Solids.

    2.  Floating debris.

    3.  Visible oil, grease, scum, or sludge solids.

    4.  Obvious color, odor and/or turbidity.

    5.  Fecal coliforms, concentration greater than MOO/100
        ml.
B.  Additional contaminants, concentrations of which should
    not be exceeded in any effluent:
    1.  Constituent
        Aluminum

        Ammonia

        Antimony

        Arsenic
        Barium
        Boron
        Cadmium
        Chlorate

        Chlorides
        Chlorine, residual

        Chromium (Hexavalent)
        Cobalt
Concentration
 £ 0.2 mg/1 (Br. Col.,
  one industry category)
 1 0.5 mg/1 (Br.  Col,
  tentative)
 £ 0.05 mg/1 (Br.  Col.,
  one industry category)
 1 0.05 mg/1
 £ 1.0 mg/1
 _< 1.0 mg/1
 _< 0.005 mg/1 (Br. Col.)
 50 mg/1 (Br.  Col, one
  industry category)
 jC 250 mg/1
 0.2 mg/1 (Br. Col., one
  industry category)
 _< 0.05 mg/1
 0.1 mg/1 (Br. Col., one
                          118

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     Copper
     Cyanide
     Fluoride
     Iron
     Lead
     Magnesium
    Manganese
    Mercury

    Molybdenum

    Nickel
    Nitrites (N)
    Nitrogen

    Phenols
    Phosphorus
    Selenium
    Silver
    Sulfate
    Sulfides and Mercaptans  (S)

    Urea

    Zinc  (Ohio § hardness
          < 80 mg/1 as  CaCOo)
       industry  category)
     jC  0.05  mg/1  (Br.  Col.)
     <. 0.02  mg/1
     <. 1.0 mg/1
     1 0.3 mg/1
     <. 0.05  mg/1   (Br.  Col.)
     150. mg/1  (Br.  Col.,
       for fresh water;  one
       industry  category)
     1 0.05  mg/1  (Br.  Col)
     £ 0.001 mg/1  (Br.  Col,
       tentative)
     0.50 mg/1  (Br.  Col, one
       industry  category)
     <. 0.2 mg/1 (Br. Col)
     10.0 mg/1  (Br.  Col.,
       for several  industry
       categories)

     _<  2.5 mg/1 -  April - Oct.
     £4.0 mg/1 at other times
     1  0.005 mg/1
     £  1.0 mg/1
     1  0.01  mg/1
     _<  0.05  mg/1
     1  50 mg/1  (Br.  Col.)
     .011 mg/1  (Br.  Col., one
      industry  category)
     1.0 mg/1 (Br. Col., one
       industry  category)
     <_  0.075 mg/1  (Usual _< 0.1)
2.  BOD
_< 30 mg/1  (Deoxygenating
Wastes)
                       119

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 3.   COD
jC 125 mg/1
 4.  Temperature,  max,
 5.  Turbidity
 6.  Solids:  Total


     Dissolved (Total)

     Suspended

 7.  Oil

 8.  Odor


 9.  Persistent pesticides
10. Dissolved oxygen
     (nontidal streams)
11. Toxicity
90°F (Br.Col., several
 industry categories)

^ 10 J.T.U. (Br. Col.,
 several industry
 categories)

<, 1,500 mg/1  (Br. Col.,
 several industry
 categories)
£ 1000 mg/1 (Delaware
 R.3.C.)
£ 25 mg/1 (Canada-Federal)

£ 10 mg/1 (Delaware R.B.C.)

250 (threshold number)
 (Delaware R.B.C.)

Not to exceed 1/100 of
TL50 value at 96 hours
appropriate bioassay test
(Delaware R.B.C.)

Not to reduce dissolved
oxygen content of receiving
water by more than 5%
(Delaware R.B.C.)

50/6 max. mortality in 96
hours appropriate bioassay
                      120

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       12.  pH»
test with 1:1 dilution
(Delaware R.B.C.)

6.5 to 8.5  (Br.  Col.  several
industry categories)
IV.  OTHER CRITERIA

    A.  Waste Treatment Ponds

        Lagoons containing toxic  substances  or  petroleum
        product? must be  lined.   ( Oklahoma)

    B.  Non-Degradation

        Waters whose existing  quality is  better than the
        established standards  shall  not  be  lowered in quality.

    C.  Aesthetic values  shall not be reduced by dissolved,  sus-
        pended, floating,or  submerged matter so as to affect
        water usage.
        *The pH limitation  should  not be subject to averaging
         and should  be  met  at  all  times.
                               121

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SUMMARY OF MOST STRINGENT  AIR QUALITY STANDARDS

Based on the Federal  Standards, Selected States' Standards and
the Regional and International Standards Covered in the Synopses

General Notes and Comments on Application and Use

1.  The main objective of  this analysis was  to present the most
    stringent of the  air standards  covered in the synopses which
    could be compared  numerically.  Additionally, some  of the
    shorter narrative or design specification types of regulation
    representing most stringent (or unique) requirements are  also
    included. Topics  generally having narrative type regulations
    of considerable length were not included.   General fugitive
    dust emissions and storage and  handling of organic materials
    and organic solvents were  among  those falling  in this
    category.

2.  New Mexico is the only state  covered to have promulgated air
    regulations specifically  for  "Gasification Plants."   All  of
    these regulations have been included in appropriate sections
    in this compilation.   A number  of other  regulations  are in-
    cluded within this compilation  which are unique to a  certain
    jurisdiction and  therefore automatically the most  stringent.
    Many of these are for  non-criteria contaminants, however.

3.  Not all of the jurisdictions used the  same basis for their
    standards for given contaminants and sources.  Where possible
    conversion of all similar  standards to  a common base for
                              122

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    comparison was made but where this  was  impractical, the most
    stringent for each type of base remaining was presented.

4.   The  most general regulations  with respect to geographical
    area or "out-state" regulations  of the jurisdictions were
    synopsized and then compared.  A few more stringent  regula-
    tions for nonattainment areas (mainly heavily populated  and
    industrialized counties)  are shown in certain of  the  state
    regulations  in addition to the "out-state"  but were generally
    not  included in  the synopses.

5.   Only regulations pertaining to new facilities were  synopsized
    and  compared as  there  are  no  existing commercial domestic
    fuel conversion  plants  of the  type envisioned by  this  pro-
    ject.

6.   Applicable Federal  regulations found to be  most stringent or
    as stringent as  any jurisdiction covered  are shown  in  this
    compilation  in the  appropriate place or category.   Applicable
    but  not most stringent  Federal regulations  are also shown but
    in parentheses for  reference only.  For easier  reading  the
    proposed Federal regulations for Stationary Gas Turbines have
    been placed  together  in one  subsection of  that title.   They
    are  newly  proposed  and  the most stringent at present  because
    none of  the  states  covered  have  as  yet  promulgated
    regulations  for  such  a  source.

7.   Prevention  of  Significant Deterioration (PSD) and Emission
    Offsets.
    The Clean  Air  Act  Amendments of 1977 (enacted August  7, 1977)
    had  considerable  effect  in the  PSD area,  which mainly
    provides  the  scheme for protecting  areas  with
                              123

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air quality cleaner than the minimum  national ambient air
standards.   Final regulation revisions  for PSD were published
in the Federal  Register on June 19,  1978  at  U3  FR 26380.
State plans (SIP's) are required  to  reflect these  require-
ments with  revisions  to be submitted to EPA  by  March 19,
1979.  These regulations revise  40CFR Part 51 and Part 52 and
are quite long and complex.   As  the publication date is after
the April 15, 1978 cut-off date  for source material  for this
project,  a  complete synopsis will  not be made here of the PSD
regulations as revised.  However,  a discussion of  the  effect
and  highlights  of PSD follows  due to  the  potential  import-
ance of these regulations relative  to  this project  and the
other regulations presented.

While PSD  regulations apply primarily  to areas meeting
national ambient  regulations  for specified  pollutants,
Emission Offsets  regulations apply primarily to dirty  or
nonattainment areas (areas not  meeting  ambient regulations) .
Because of  the nature of the plants  to  be  built relating  to
this project, it is assumed  that  attainment areas  and thus
PSD regulations are  more  relevant to the project.  Two
important basic  requirements of Emission Offset  regulations,
where applicable, are:  1)  lowest achievable emission rate
(LAER)  shall be  attained, and 2)  no net increase in  emission
shall result from an affected new or modified source.   There
are both  significant similarities and differences  in PSD and
offset regulations.

A brief  summary of  the requirements set out in the PSD
section of  the 1977 Air Act Amendment (Section 165)  follows:
                         124

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  No major  emitting facility (as defined  in the Act) on which
  construction is  commenced after August 7,  1977,  may  be
  constructed unless:  1) a  permit has been issued  setting
  forth  emission limitations; 2) an air quality analysis  has
  been conducted; 3) a public hearing  has been held.   (This
  is a new  requirement which was not contained in earlier  PSD
  regulations); 4) certain specified allowables (increments)
  are not exceeded; 5) best available  control technology  is
  applied;  6)  the requirements for protection of pristine
  areas  (Class I) have been  met;  7)  there has been  an
  analysis  of any air quality impacts  projected for the area
  as a  result of  growth  associated with  the  proposed
  facility; and 8) monitoring will be  conducted to  determine
  the effect of the facility's emissions  on air quality.


PSD regulations  at  present apply  to areas not  exceeding

National Ambient Air Quality  Standards (NAAQS)  for sulfur
dioxide  and particulates  and establish allowable  increases

(incremental changes)  for  these  pollutants in three area
classifications above a defined baseline  concentration.   The

allowable increases follow:
                                           Maximum allowable
                                           increase (micro-
                                           grams  per cubic
Pollutant                                   meter)	

                        CLASS I

Particulate matter:
  Annual geometric mean                             5
  2M-hr maximum                                    10
Sulfur dioxide:
  Annual arithmetic mean                            2
  24-hr maximum                                     5
  3-hr maximum                                     25
                         125

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                                           Maximum  allowable
                                           Increase (micro-
                                           grams per cubic
Pollutant                                  meter)	

                       CLASS II

Particulate matter:
  Annual geometric mean                             19
  24-hr maximum                                    37
Sulfur dioxide:
  Annual arithmetic  mean                            20
  24-hr maximum                                    91
  3-hr maximum                                   512

                       CLASS III

Particulate matter:
  Annual geometric mean                             37
  24-hr maximum                                    75
Sulfur dioxide:
  Annual arithmetic  mean                            40
  24-hr maximum                                  182
  3-hr maximum                                   700
Class I through III  area  classifications refer to geographi-
cal areas differentiated by the amount  of incremental in-
creases to be allowed  in each.  Class I  increments permit
only minor air quality  deterioration;  Class II increments,
moderate deterioration; Class III increments, deterioration
up to the secondary  NAAQS.


Class I areas are  often referred to as "pristine." Redesigna-
tion of lands from one  classification to another  by the
states is allowed  under some circumstances through specified

procedures.  Certain lands are now permanently in Class  I.
Class  II  increments have  been changed and in  some cases
                          126

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have become more restrictive; Class III increments now are
specifically defined  and  procedures  for  reclassifying to
Class III are more rigorous.

In the near future, PSD regulations will be  extended to other
pollutants for which NAAQS's  are in effect  (to be promulgated
by  August  8, 1979,  and  taking  effect   one  year  after
promulgation).

It is now evident the  required  PSD air quality impact
analysis will also apply in certain cases  to nonattainment
(dirty) areas.  This  is  due to  the  possible  effects of
sources in nonattainment areas on air quality in clean areas.
(The reverse  can also be true so that the emission  offset
policy may have to be met  by  a clean area.)

A number of important and  sometimes lengthy definitions are
included in the current PSD regulations.   For PSD  purposes
"major emitting source"  under  Section 169(1)  includes 28
specified sources emitting, or having, the potential  to  emit,
100 tons per  year or more of any air  pollutant.   For  those
sources not specified only sources having emissions  of more
than 250 tons per  year  are  subject to PSD requirements.
"Baseline concentration" is defined as the ambient  concen-
tration level reflecting actual air quality as of  August 7,
1977, minus any contribution from major stationary  sources
and major modifications on which construction commenced on  or
after January 6,  1975.   Among  other definitions are  ones
covering  "major  modifications," "potential to  emit,"
"fugitive  dust,"  "commence,"  "best  available  control
technology,"  and "allowable emissions."
                         127

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The two primary  requirements that a  PSD permit applicant must
meet are:

    1)   Best  available control technology, and

    2)   Not causing nor contributing to air pollution  in  ex-
        cess  of  the maximum allowable increment or concentra-
        tion  for any pollutant more  than  one time per year.

Best available control technology is to be determined on  a
case-by-case  basis, taking into account energy, environmental
and economic  impacts and other costs. At a minimum BACT must
not result in emissions which  would exceed  the emissions
allowed by new source performance standards under Section III
or hazardous  emission standards under Section 112 of  the  Air
Act.

Of major concern is the likelihood  of eventually  consuming
all available increments.  The fuel  conversions necessitated
by the  present  energy situation in heavily industrialized
areas will likely cause the  sulfur  dioxide and  particulate
increments to be  exceeded, especially  if all sources  are
counted against the  increment.  If offsetting reductions
cannot  be  effected much of existing  industry could  be  forced
to curtail its  operations  and new sources  could  not be
constructed.

The revised  regulations  follow the outline of  the  earlier
regulations  but,  in  general,  are  more  comprehensive  and
restrictive.
                         128

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The possible effects of certain  general or catch-all pro-
visions in  the regulations  covered  must also be taken into
account.  Certain jurisdictions leave  discretion in their air
pollution  agencies  to  lower specific  numerical  and other
standards on the basis of "nuisance," for the "public wel-
fare," because  of  specific health hazards, or  where the
application of best currently  available control technology
might reasonably dictate a  more  stringent standard.  These
would most  often be applied on a case-by-case basis but  could
lower certain standards for an entire  plant site under con-
sideration.  Because of the lack  of specificity and  wide
variance  in historical interpretation  and  application of such
regulations among the jurisdictions,  such regulations were
not generally included in the stringency review.  (Considera-
tion  of best currently available  control technology with
consideration of  economic reasonableness and cost versus
benefits  is also a general requirement in  the promulgation  of
regulations.) Typical examples  of some of these general  or
catch-all provisions  follow:

a)  Nuisance -  Interference  with Enjoyment  of Life and
    Property. Compliance with  the  regulations herein not-
    withstanding,  should it  be  found after public  hearing
    that  any specific emission source  is, will be,  or  tends
    to be significantly injurious to human health or welfare,
    animal  or plant  life,  or property,  or is  or will  be
    unreasonably interfering with the  enjoyment of life and
                          129

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    property of any  inhabitant of the state, or will  inter-
    fere with the  attainment or maintenance of any  national
    ambient air standards, alternate standards or orders  may
    be issued to require additional abatement or control of
    certain emissions as deemed necessary  to effect  the  pur-
    poses of the Kansas enabling act.  (Kansas)

b)  Air Quality Degradation Regulated.  In areas of present
    high air  quality where measured or  estimated  ambient
    levels of controllable  pollutants are below the  levels
    specified by applicable  standards any emission of  pol-
    lutant to  the ambient  air must  be shown  to  result in
    pollution levels within applicable ambient air standards
    and will be prohibited  in any case unless shown to be
    controlled to afford the  highest efficiencies and  the
    lowest discharge rates  that are reasonable and practi-
    cable as  specified in [subsection B.2].  (Utah)

c)  Non-degradation.  The significant and  avoidable  deterior-
    ation of  air quality  in  any part of an area where  pre-
    sently existing air quality is equal to or better  than
    that required by Ohio ambient air quality standards shall
    be prohibited. (Ohio)

d)  More stringent requirements.  A greater  degree of control
    may be required to prevent a health hazard or a local
    nuisance  because of the particular properties of a speci-
    fic organic compound.  Determination of a health  hazard
    will be based upon such  factors  as threshold limit
    values, presence of  carcinogens,  and other  accepted
    health indicators. (Indiana)
                          130

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e)  "Best available  control  technology"  shall be determined
    on a case-by-case basis considering  the  following:
    (Virginia)

    1)  The process,  fuels and raw material available and  to
        be employed  in  the facility involved;

    2)  The engineering aspects of the application of various
        types  of control  techniques which have been adequate-
        ly demonstrated;

    3)  Process  and  fuel  changes;

    4)  The respective  costs  of application of all such  con-
        trol techniques,  process changes, alternative fuels,
        etc.;

    5)  Any applicable  emission standards; and

    6)  Location and  siting  considerations.

f)  Best currently available  control technology (BCACT).   Air
    contaminant  sources shall have installed and  utilize the
    best currently available  equipment and control technology
    for limiting emissions  of gaseous  air contaminants.
    (Tennessee)

g)  Particulate  Emissions -  General Process Standards: Parti-
    culate non-attainment counties.  In any county where one
    or more sources  are  emitting particulates  at  rates  in
                           131

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    conformity  with applicable maximum emission rates  and the
    ambient air quality  standard for particulate matter is
    being exceeded, the Board shall set an appropriate emis-
    sion standard  for each source contributing to the parti-
    culate matter  in the  ambient air of  the  county at such
    value  as the  Board may deem necessary to achieve the
    .desired air quality.  (Tennessee)

h)  Diluting and Concealing  Emissions. The installation or
    use of any  device,  contrivance or  operational schedule
    which, without resulting in reduction of the total amount
    of air contaminant  released to the atmosphere, shall di-
    lute or conceal an  emission from a source is prohibited.
    (Wyoming)

Specific limitations and  shortcomings in presenting this type
of analysis in  a conveniently brief manner  are discussed in
the last item of this section.   The  standards presented in
this survey were condensed from generally lengthy rules and
regulations. Numerical  standards seldom stand alone  and are
generally clarified, modified,  and limited by accompanying
definitions, exceptions,  calculation procedures and instruc-
tions, and other narrative forming the context in which  they
are found.  The synopses  herein attempted to retain the  key
points of such  narrative  but considerably less could  be in-
cluded in a reasonably  brief stringency survey.  Therefore,
this survey may be used  as a guide and  convenient reference
but not as a complete substitute for the synopses, the  regu-
lations, and other auxiliary sources such as court or  agency
opinions for in-depth regulatory applications.
                           132

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10. Limitations and precautions in application.   The following
   points indicate some of the  most  significient areas of poten-
   tial difficulty or inconsistency  with respect to the applica-
   tion of this most stringent  air standards  survey.  The full
   implication of several of the  points  will  probably only  be
   apparent to those who now have or formerly have had extensive
   involvement in the practical application of air regulations.

   a)  Although  fairly consistent,  the rules for adding like
       facility rates or capacities  within a given plant  before
       calculating  standards  vary  somewhat  among the  various
       jurisdictions and can lead to determination of different
       values  for  calculated  standards.   These rules  are  not
       always clearly spelled out in the written regulations  and
       are  often subject  to or  controlled  by custom, board
       discretion, and court or  agency  rulings within  a given
       jurisdiction.  When necessary to  add all units of a given
       source category within  a  plant  before determination of
       the standard (probably the most  common  procedural method)
       "smaller allowable emission values will generally result
       because percentage limitations  on contaminants always
       decrease  as capacity or  stream rate  increases where
       variable standards are specified.

   b)  As the most stringent regulations compiled are an artifi-
       cial body of rules, no  general  system exists  dictating
       controlling relationships  between these regulations where
       conflict, overlapping, or  the like might exist.   Such  a
       system does generally exist  for  any single jurisdiction
                             133

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        and  for  the Federal and other  jurisdictional regulations
        but  these systems vary somewhat  and  thus would produce
        some differences upon application.

    c)   Some of  the  most stringent standards are presented  by
        tables with standards at  several  specific stream rates  or
        plant capacity levels.   This was necessary  where the
        jurisdictions used a mixture of constants and/or formulae
        to cover the standards over defined ranges, generally  in
        terms of certain stream  rates or other plant capacity
        indicating factors.  To compare these for stringency  it
        was  necessary to solve any applicable formulae at  some
        stream rate or plant capacity  level within the relevant
        range.  The fuel conversion plants under consideration
        are  generally of very large throughputs and thus  one  or
        more points representing realistically high rates  or
        capacities were among those  selected in most  cases.
        Conversely, some included units or streams in  the  plants
        could be rather small and so required  other points  to  be
        determined  representing  rather  small streams or  capa-
        cities.  A wide variety of plants and  processes is  within
        the  project scope,  and  this  introduces considerable
        potential variation in flow rates and sizes of specific
        units or facilities within the over-all plants.

11.  Referring to the standards requiring tabular presentation  as
     mentioned in 10.c) above, the most stringent standards could
     only reasonably be shown  for a limited  number of selected
     points.  Interpolation between these selected points  would
     almost  never be proper because the points  used could  repre-
     sent either constants or solutions to one or more formulae
                             .134

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at relevant  capacities or  rates.   The  synopses  or the
complete  regulations would thus have to be referred to for
intermediate  standards  evaluation,  and in some cases care
might have to be taken  to  determine which jurisdiction's
regulation was most stringent at the new point in question.
                        135

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I.  Nitrogen Oxides (NOX, expressed as NC^).

    A.  Fuel Burning Equipment
        Facilities >. 250 MM Btu/hr heat input*
          Gas fired           0.2 Ib/MM Btu (Federal, most
          states) Liquid (oil) fired   0.3 Ib/MM Btu (Federal,
          most states) Solid (coal) fired 0.45 Ib/MM Btu (N.M.;
                                           Federal is 0.7 Ib/MM
                                           Btu)
        Facilities <250 MM Btu/hr heat input
          Any Fossil Fuel      Best Available Control Technology
                             (Ohio)
        Any size facility
          Gas Fired            0.2 Ib/MM Btu (Wyoming)
          Solid (coal) fired   0.7 l^MM Btu (Wyoming)
        Facilities >_ 1 MM Btu/hr heat input
          Liquid (oil) fired   0.3 Ib/MM Btu (Wyoming)
        Facilities < 1 MM Btu/hr heat input
          Liquid (oil) fired   0.6 Ib/MM Btu (Wyoming)
        Combined Fuel Firing (No Federal Standard but several
        states have a formula covering, Colorado's is shown
        below):

        E = (0.2X+0.3Y+0.7Z)/(X+Y+Z)

           Where: X is the % of total heat input from gaseous
                  fossil fuel;
                  Y is the % of total heat input from liquid
                  fossil fuel;  and
•Idaho incorporates the Federal standards here except that its
Dept. determines on a case-by-case basis whether a stricter
standard should be adopted after application of the best
currently available control technology with reasons to be stated
with the standard.
                               136

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            Z is the % of  the  total heat  input  from solid fossil
            fuel.

II.   Visible Emissions

     A.  Processes
          20% Opacity (#1  on Ringelmann  Chart),  (Kentucky)
     B.  General (Any Source)
          2Q% Opacity (#1  on Ringelmann  Chart),  (Alabama  and
          many  states)
          for >^ 100,000  acfm flue  gas  rate:  15/6  Opacity (Texas)
     C.  Fuel Burning Equipment
          10% Opacity (#0.5 on Ringelmann Chart),  (West Virginia
          Federal -  20%  Opacity)
     D.  Incinerators
          10$ Opacity (#0.5 on Ringelmann Chart),  (Montana)
     E.  Coal Preparation  Plants
          Thermal Dryers - 20% Opacity,  (Federal)
          Pneumatic  Coal Cleaning  Equipment:  10% Opacity
          (Federal)
     F.  Petroleum Refineries
          From  fluid catalytic cracking  unit catalyst
          regenerator or fluid catalytic cracking unit
          incinerator -  waste heat  boiler:  30% Opacity
          (Federal)
III,  Particulates

     A.  Processes
         1.   Standards  Based  on  Process  Weight Rate

         Process Weight  Rate.  Ib/hr     Emission Standard, Ib/hr
                 2.5 MM               54.2 (Alabama, others)
                 1.0 MM               46.8 (Alabama, others)
                 0.1 MM               20.5 (Illinois)
                 0.05 MM               14.2 (Illinois)
                              137

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    2.  Standards Based on Stack Exhaust Gas Rate

    Stack Exhaust Gas Rate,          Concentration
    	DSCFM	        Standard. gr/DSCF
           1 MM                       0.02 (Pa.)
         0.3 MM                       0.02 (Pa.)
         0.2 MM                       0.03 (Pa.)
         0.1 MM                       0.04 (Pa.)

    3-  Process emitting 100 T or more of particulates
        annually based on 0 control (excluding combustion
        products of fuel oil, LPG, or natural gas).
          85% control of emissions (based on 0 control with
          source at maximum operating capacity).   (Utah).

B.  Petroleum Refineries
    From fluid catalytic cracking unit catalyst regenerator
    or fluid catalytic cracking unit incinerator - waste
    heat boiler -
     1.0 lb/1000 Ib of coke burn-off (Federal), (incre-
     mentally higher emission rates are allowed for heat
     input attributable to auxiliary liquid or solid fossil
     fuels).

C.  Gasification Plants - General (Certain boilers and coal
    briquet forming facilities within these plants are
    covered later in subsection III.E.).
      Standard:  0.03 gr/scf exit gas

D.  Fuel Burning Equipment
    1.  Standards Based on Heat Input Capacity.
                        138

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                   (Fuels as  designated)
      Coal:
            >250 MM  Btu/hr in      0.05 Ib/MM  Btu  (H.H.V.)
                                     (New  Mexico); and
                                   0.02 Ib/MM  Btu  (H.H.V.),
                                     for particulates 2
                                     microns equivalent
                                     aerodynamic  diameter  or
                                     less  (New Mexico)
            <250 MM  Btu/hr in      0.1 Ib/MM Btu  (Illinois)
      Oil: >114 MM                 0.005 (New  Mexico)
           <114 MM                 0.1 (Illinois)
      Gas: >2500 MM                0.1 (Texas)

      Combinations Fuels:  E = SsHg  + 0.10 H-j
                           (Illinois)
          where: Ss  is applicable  solid fuel  particulate
                     emission, Ib/MM Btu  actual  heat input;
                 Hs  is actual heat input  from solid fuel,
                     MM Btu/hr;
                 H-j  is actual heat input  from liquid
                     fue-l, MM Btu/hr

      (Any Fuel - Specific Fuels are not  Designated)
      Heat Input, Btu/hr        Standard. Ib/MM  Btu
          10 MMM                0.1  (Federal,  Okla.)
           5 MMM                0.1  (Federal,  several states)
         500 MM                 0.1  (Federal,  several states)
          50 MM                 0.1  (Wyoming)
           5 MM                 O.M  (Ohio, other  states)

2.  Standards Based  on Exhaust Gas Rate
      Any fuel except coal or municipal waste: 0.05 gr/SCF
        (Alaska)
      Coal or municipal waste:  0.1  gr/SCF (Alaska)

                           139

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E.  Gasification Plants (Designated Facilities and Fugitive.
    Dust as per Respective Subsection Headings). (New Mexico)
    1.  Gas burning boilers (in conjunction with gasification
        plant)
          Standard:  0.03 Ib/MM Btu heat input (L.H.V.)
    2.  Boilers firing more than one fuel  (in conjunction
        with gasification plant).
          Formula for Standard:
          where ET is the total allowed emission in
          pounds per given period of time;
           EQ is the allowed emission from oil in  Ib/MM
               Btu1s;
           Ec is the allowed emission from coal in Ib/MM
               Btu's;
           Eg is the allowed emission from gas in  Ib/MM
               Btufs;
           Qo is the heat released by the oil based  on
               the higher heating value in Btu's per period
               of time;
           Qc is the heat released by the coal based on
               the higher heating value in Btu's per period
               of time;
           Qg is the heat released by the gas based  on
               the lower heating value in Btufs per  period of
               time.
        Additionally, maximum emissions of particulates two
        microns or less (equivalent aerodynamic diameter) are
        limited by:
           Ef = O.UO Ec (Q0 + Qc + Qg)
                           140

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            where  Ef is maximum emissions in Ib/given time
            period,  and other terms are as defined in 2.a) above.
       3.   Coal briquet forming facilities
              Standard:  0.03 gr/SCF exit gas (with particulate
                         emissions limited to stack outlets with-
                         in technical feasibility).
        4.   Stack Design.   All particulate emissions are to be
            through  stacks at least ten diameters in length with
            adequate platforms and parts for sampling.
        5.   Fugitive Dust.  No material shall be handled, trans-
            ported,  stored,or disposed of and no building or road
            shall be used, constructed, altered,or demolished
            without  taking reasonable precautions to prevent
            particulates from becoming airborne.

    F.   Coal Preparation,  Handling, and Mining
        1.   Standard for any thermal dryer:  0.031 gr/DSCF
              effluent gas (Federal)
        2.   Standard for any pneumatic coal cleaning equipment:
              0.018  gr/DSCF effluent gas (Federal)
        3.   Coal preparation plants.  All crushers, conveyors,
            screens, cleaners, hoppers, and chutes, which are
            designed for continuous transportation or preparation
            of coal  shall  be equipped with hoods, shields, or
            sprays where reasonably necessary to prevent airborne
            particulate matter.  (New Mexico)
        4.   Coal mines-roads.  Main coal haulage roads shall be
            sprayed  or otherwise treated where  reasonably
            necessary to prevent airborne particulate matter.
            (New Mexico)

G.   Incinerators
    1.   Standards Based on Refuse Charge Rate
                              141

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        Refuse Charge Rate, Ib/hr   Standard, gr/SCF  Exhaust Gas
                                    (vol. corrected to 12% C02)

            60,000                    0.05 (Illinois)
             5,000                    0.08 (Federal, Illinois)
             1,000                    0.10 (Montana, others)
              500                      0.10 (Montana, others)
              100                      0.10 (Montana, others)

        Refuse Charge Rate, Ib/hr   Standard, lb/100 Ib charged

              500 (and higher rates)    0.10 (Ohio)
              100                       0.20 (Ohio)

        2.  Emissions with an excess of 100 ppm total carbonyls
            in the exhaust gases are prohibited.  Operation  shall
            only be during daylight hours unless permission  for
            other operation is obtained from the Department.
            (Washington)

IV. Carbon Monoxide

    A.  General Sources
        1.  Emissions shall be limited so as to prevent ambient
            air standards for CO from being exceeded.
            Appropriate means are use of a direct flame
            afterburner or other Division approved means of  equal
            effectiveness.  (Wyoming)
        2.  All sources of CO shall control CO emissions by  use
            of the best currently available control technology
            (BCACT, Ohio).

    B.  Petroleum Refineries or Processes
                             142

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    1.  Any petroleum processing  facility.
        a)  A waste gas stream  shall be burned  in a direct
            flame afterburner or  CO boiler  so that a
            concentration of no more than 200 ppm (vol.,
            corrected to 5Q% excess air) CO is  emitted or
            shall be treated by other equivalent and Agency
            approved control technology.  (Catalyst
            regenerators of fluidized catalytic converters
            equipped for in situ  combustion of  CO may emit CO
            concentrations up to  350 ppm corrected to 50%
            excess air.  (Illinois) (The Federal standard and
            that of many states is 0.050$ (vol.) in effluent
            gas.)
        b)  Waste gas streams with CO from  any  catalyst re-
            generation of a petroleum cracking  system,
            petroleum fl-.id coker, or any other petroleum
            process must be burned atl,30U°Ffor 0.3 sec or
            longer in a direct-flame afterburner or boiler
            with indicating pyrometer. (Alabama, Ohio)
    2.  Any petroleum process.
        Emissions shall be reduced by complete  secondary
        combustion (93% removal of CO or more)  of the waste
        gas stream.  (Oklahoma)

C.  Fuel Burning Equipment
    1.  Facilities with >10 MM Btu/hr actual heat input.
          200 ppm CO (corrected to 5Q% excess air).
          (Illinois)
    2.  Effluent streams with CO  shall be burned in a
        direct-flame afterburner  or boiler  or controlled by
        other Board approved means.  (Indiana)
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    D.  Incinerators
        1.  Any incinerator
              500 ppm (corrected to 50$ excess air).  (Illinois)
        2.  Any effluent streams with CO shall be burned in a
            direct-flame afterburner or boiler or controlled by
            other Board approved means.  (Indiana)
V.  Odors
    A.  Odors from F^S or Mercaptans.
        Emissions containing HgS or mercaptans shall be inciner-
        ated at 1,200°F  or higher for at least 0.3 sec before
        discharge to the atmosphere or treated by alternate means
        shown to the Department to be at least as effective.
        (Pennsylvania)

    B.  Any source (some of the standards below represent similar
        requirements stated in slightly different ways by
        different states).
           Malodorous air from any source whatsoever, regardless
           of compliance with other odor standards [in these
           regulations] shall not be emitted such that any odor
           is detectable beyond the property line of such source.
            (Pennsylvania)
           Best available control technology as approved by the
           Board shall be used to limit odorous emissions from
           any odor emitting source.  No odor, except for
           accidental or other infrequent emissions, that would
           be objectionable to a person of ordinary sensibility
           shall be emitted from a facility.  (Virginia)
           The discharge of gases, vapors, or odors beyond the
           property line of an odor source so that a public
           nuisance is created is prohibited.  (Montana)
        -   No odor shall be detectable from a sample taken at the
           property line of an odor source after dilution with up
           to seven volumes of odor free air as determined by the
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           Barneby-Cheney Co.'s centometer or equivalent and
           approved method.   Effective odor control devices or
           systems shall be  installed and operated such that
           odors in excess of the above are not created in areas
           adjacent to the source property line.  (Wyoming;
           Missouri requires two separate tests not less than 15
           minutes apart each hour.)
           Handling and storage.  Odor producing materials shall
           be stored and handled so that accompanying odors do
           not create a public nuisance; accumulation of such
           quantities of these materials as to permit their
           escape or spillage shall be prohibited.  (Montana)

    C.   Incinerators
        1.   Incinerators, including all associated equipment and
            grounds, shall be designed and operated in such
            manner as necessary to prevent emission of
            objectionable odors.  (Ohio, Alabama, Missouri)

VI.  Sulfur  Dioxide and Sulfur

    A.   Fuel Burning Equipment - Sulfur Emissions Standards
        (Kansas)
          >250 MM Btu/hr: 1.5 Ib/MM Btu

    B.   Fuel Burning Equipment - S02 Standards
        1.   Specific fuels
            Gas fired - S02 Standard: 0.16 Ib/MM  Btu L.H.V.
              (N.M. - Gasification Plants)
            Residual oil fired« - S02 Standard: 440 ppm
                (vol.) S02 emissions concentration (Texas)
                >115 MM Btu/hr:  0.34 Ib/MM Btu (N.M.; Federal  =
                  0.8   Ib/MM Btu)
*(At very high rates the Kentucky S02 standard  formula will
 be more stringent.  This formula for oil  fired equipment  is:
 Y = 7.7223X-Oi*106.)
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        Distillate fuel oil fired - S02 Standard:
           >250 MM Btu/hr:  0.3 Ib/MM Btu (Illinois)
        Coal fired - S02 Standard:  >250 MM Btu/hr:  0.2
             Ib.MM Btu (Wyoming; Federal = 1.2 Ib/MM Btu)
          <250 MM Btu/hr:  1.2 Ib/MM Btu (Oklahoma)
    2.  Any fuel
        S02 Standard: 1.0 Ib/MM Btu (Ohio); also
        500 ppm (vol.)(Alaska)
    3.  Combination fuel fired.  Several states have heat
        input dependent formulae for the S02 standard for
        combination fuels.

          E = (0.8Y+1.2Z)/(Y+Z)
              where:  E is the maximum rate of emission,
                        Ib/MM Btu heat input (2 hr. avg.);
                      Y is the % of total heat input from
                        liquid fuel; and
                      E is the % of total heat input from
                        solid fuel

C.  General Standards
    1.  S02 Standards:
          250 ppm (vol.) (British Columbia)
          1,000 Ib/hr inexit gas (Mo.).  Exceptions (Mo.):
          where S02 concentrations in ambient air at
          occupied places beyond emitting source premises
          don't exceed 0.25 ppm (vol.), 1 hr.  avg., max.
          over once in a 4 day period; or
          0.07 ppm (vol.), 24 hr.  avg., max. over once in a
          90 day period.
    2.  Net S02 ground level concentrations  (Texas)
        0.4 ppm, 30 min.  avg., (allows exemptions when
        source meets Federal New Source Performance
        Standards, utilizes best available control
        technology, and doesn't cause or contribute to S02
                          3,46

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        primary and secondary ambient standards being exceeded in
        area.   Several non-attainment counties have a 0.28 ppm,
        30 min.  average maximum) .

D.   Processes
    1.   Gasification Plants - S emissions (New Mexico):
        .008 Ib/MM Btu heat input (HHV) in feed to plant
    2.   Sources other than fuel burning equipment and petroleum
        refineries - S02 Standards  based on effluent concen-
        trations.
        500 ppm (vol.) - current (Colo.)
        500 ppm (vol.) and emissions of not greater than 5T
          S02  Per day from any process unit (applies only to
          S02  concentrations of 150 ppm (vol.) or more
          effective on 1/1/85 and applies to new sources after
          1/1/80 (Colorado)
    3.   Process with >250 MM Btu/hr heat input
        Ep = 19.5P0-6? (Indiana)
          where Ep = S02 in Ib/hr
              P = total process weight input capacity in T/hr
          at  P = 500 T/hr, Ep = 1254 Ib/hr
    4.   Ground level concentrations limits (if emitting >10
Ib/hr S02)  (Indiana) :
                 75
                 ah
                 -40 SnP 0.75 0.25
                      P      n
                             s
            where Cmax> = max. hourly ground level cone, with
            respect to distance and at the "critical wind speed
            for level terrain" resulting from the point source.
            Cmax< shall not exceed 900 ug/m3 in areas
            where ambient air quality is better than applicable
            S02 secondary ambient air quality standards.

    5.   Regardless of the specific emission standard applicable
        in this regulation, emission sources shall utilize the
                             147

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        best available control technology as deemed
        appropriate by the Board.  (Tennessee)

E.  Sulfur Recovery Plants
    1.  S02 Standards - basis of Ibs/lb S entering any
        size facility:  .01 Ib/lb S. (Ohio, Okla.)
    2.  S02 Standards - basis of Ib/hr S02 allowed
        Texas formulae:
        >4000 SCFM effluent gas rate
           E = 0.614 qO.8042
        < 4000 SCFM effluent gas rate
           E = 123.4 + 0.091 q  (q = effluent gas rate; SCFM)
        Texas Standard at Rate Shown:
          § 1 MM SCFM, E = 41,055 Ib/hr
          §.237 MM SCFM, E = 6449 Ib/hr
          0 3 M SCFM, E = 396.4 Ib/hr
    3.  S. recovery plants in conjunction with natural gas
        processing: 100 Ib S02/nr| max.  2 hr. avg. (Okla.)
    4.  Also see VII D.5. - H2S from sulfur recovery
        plants in conjunction with petroleum processing
        facilities.  (New Mexico)  That provision will
        generally be more stringent where applicable.

F.  Sulfuric Acid Producing Facilities (Wyoming)
    Processes producing H2SOjj by the contact method
    burning elemental sulfur, hydrogen sulfide, organic
    sulfides, mercaptans, or acid sludge shall limit S02
    emissions in all effluent streams to:
        not over 4 Ib/T of acid produced, max. 2 hr. avg.

G.  Petroleum Processing Facilities
    1.  Definition.  "Plant processes" includes but is not
        limited to hydrogenation sweetening units, hydro-
                          148

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cracking units, fuel burning equipment including
flares and incinerators, sweetening system regener-
ation units, sour water strippers, and similar sulfur
releasing systems.  Catalyst cracking regeneration
units other than hydrocracking units, boilers, or
process heaters are not included  if total emissions
from them are less than 2.5T of S per day. (New
Mexico)

Refinery plant processes  (New Mexico)
avg. S released per day >5T<30 T:
  .10 Ib of S/lb S released in plant processes
avg. S released per day >_30 T:
  .02 Ib of S/lb of S released in plant  processes
Fuel-gas burning equipment (New Mexico)
    Ib of S in effluent gas not to exceed a  quantity
    equivalent to an S content of fuel gas entering
    of 10 gr/100 SCF of gas.
Fuel gas combustion devices in petroleum refineries
(Federal).
    Fuel gas  containing H2S in excess of 0.10
    gr/DSCF shall not be burned in any fuel  gas com-
    bustion device.  However, the combustion  exhaust
    gases may alternately be treated so  that  the
    S02 emissions control is the  equivalent  with
    respect to S02 of compliance  with this H2S
    content regulation.
Alabama regulations, which cover  petroleum facilities
handling natural or refinery (process) gas containing
more than 0.10 gr H2S/SCF of gas  could be more
stringent in certain isolated cases.  These
                  149

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            regulations have an increment correction factor
            (additional S02 emission allowed) dependent on
            mol % H2S in the dry acid gas up to 60 mol %
            H2S.  Alabama also has a requirement that a
            demonstration be made that the S02 emitted will
            not cause or contribute to non-attainment of any
            primary or secondary ambient air standards.  For
            reference only the basic uncorrected Alabama
            regulations are as follows:
            >10 Lt <50 LT available S per day:  560 Ib/hr
            >50 Lt _< 100 LT available S per day: 0.10 Ibs/
             S02/lb of S processed
            >100 LT available S per day:  0.08 Ibs S02/lb S
             processed

     H.  Standards for Sulfur Content of Fuels (as S). (Montana)
         1.  Liquid or Solid Fuel
             a)  Max.  S in Fuel:  1 Ib/MM Btu fired
         2.  Gaseous Fuels
             a)  Max.  S in Fuel (calculated as H2S):
                 50 gr/100 SCF of fuel
         3.  Exceptions and exemptions to the standards in 1. and
             2.  are listed.

VII.  Hydrogen Sulfide

     A. Any source-general (Texas)
        1.  Max. net ground level concentration.
            a)  Where residential, business or commercial
                property downwind of H2S source is affected
                  0.08 ppm, 30 min. avg.
            b)  Where H2S source affects only downwind pro-
                perty used for other than the purposes listed in
                l.a) above (such as industrial, vacant tracts,  or
                range lands not normally inhabited.)
                0.12 ppm, 30 min. avg.
                              150

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 B.  Gasification Plants (New Mexico)
    1.   100 ppm (vol.) in effluent gas, to any combination of
        H2S, carbon disulfide, and carbon oxysulfide, and
    2.   10 ppm (vol.) in effluent gas, max. H2S component
        in combined effluent gas.

C.  Processes
    1.   H2S emission rate  (or rate to any combustion
        device) (Kansas):
        10 gr/100 ft3 of gas emitted  (or fed to combus-
        tion device); except combustion of fuels where the
        gaseous
        products are used as other process raw materials.
    2.   Limits on H2S in ambient air  in inhabited areas
        beyond the source premises where concentrations are
        attributable to r .^h source.   (Missouri)
            0.03 ppm (vol.), 30 min.   avg., not more than
              twice in any 5 consecutive days
            0.05 ppm (vol.), 30 min.   avg., not more than
              twice per year
    3.   Effluent gas from H2S process  sources shall  be
        vented, incinerated, flared or otherwise disposed of so
        that ambient H2S and S02 standards are not.
        exceeded.  (Wyoming)

D.  Petroleum Processing Facilities
    1.   Fuel combustion devices (Federal):
        Fuel gas containing H2S in excess  of 0.10 gr/DSCF gas
        shall not be burned.  The exhaust  gases may  alterna-
        tively be treated so that equivalent S02 emission
        control is obtained upon such showing to the satisfac-
        tion of the EPA Administrator.
          Exceptions.  Flaring of process  upset gas  or of the
          process or fuel gas from relief  valve leakage  is
          exempt from the above.
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Maximum H2S concentration in refinery process
gases emitted or combusted:    150 ppm  (Alabama)
Ground level H2S concentration beyond source
premises for facilities handling natural or refinery
(process) gas containing more than 0.10 gr
H2S/SCF.  (Alabama)
Stream shall be burned to maintain a 20 ppb
concentration, averaged over a 30 min. period.
(Determination of such concentration from waste
gas or emergency flaring to assume only 75% of heat
of combustion is used to heat products of
combustion).
H2S emissions shall be controlled by removal of
H2S from exhaust gas or H2S oxidation to
S02 in a system insuring complete oxidation of
H2S at all times.  H2S limits in either type
of control system shall be:  (Oklahoma)
  0.3 Ib/hr of H2S, 2 hr.  avg.; and 95% removal
  of H2S in exhaust gas Any oxidation system
shall utilize a stack at least 50 feet in height.
Such system shall not be allowed to emit over 100
Ib/hr of SOX (expressed as S02 2 hr. avg.)
unless there is a prior removal step meeting Oklahoma
SOX limitations.
H2S from petroleum processing facilities includ-
ing sulfur recovery plants in conjunction with such
facilities (New Mexico).  Either:
a)  10 ppm (vol.) max. in effluent gas; or
b)  the effluent gas shall be passed through suit-
    able equipment to oxidize the H2S to S02
c)  Flares which may flare gas with over 10 ppm  of
    H2S shall utilize alarms to signal non-combustion
    of the gas.
                  152

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        6.  Glaus Sulfur Recovery Plants.  No  discharge  shall be
            allowed of any gases to the  atmosphere  containing in
            excess of:
            a)  0.025? (vol.) of S02 at  0.0% 02,  dry
                basis, where emissions are controlled  by an
                oxidation control system, or a reduction control
                system followed by incineration,  or
            b)  0.03056 (vol.) of reduced  sulfur  compounds and
                0.001? (vol.) of H2S calculated  as  S02,
                at 0.0% 02 on a dry basis, if  emissions  are
                controlled by a reduction control system not
                followed by incineration.

VIII.  Sulfur Content of Fuels

       A.   Maximum Sulfur Content (wt %  S or as  noted)
           Any fuel oil             1.5?  (Utah)
           Distillate fuel oil
                  #1                0.3?  (Idaho)
                  #2                0.5?  (Idaho)
           Coal (Solid)             1.0?  (Idaho)
                                    1 Ib S/MM  Btu input
                                     (Montana)*
           Gaseous fuel             50 gr (as  H2S)/100 SCF of
                                    fuel  in (Montana)*

IX.  H2SC>4, Sulfuric Acid Mist, S03
    A.   Emissions of H2SOij or SO^ (or combination)
        1. 35 mg (as H2SOij)/in3 of effluent gas
           (Missouri)
•Montana allows higher sulfur content  fuels with  proper  approval
where such fuels are mixed with lower  sulfur-containing  fuels  so
that the mixture doesn't exceed the standard.   Montana also
allows S02 emission control in the alternative  if such
control will be equivalent in terms of sulfur emitted  (in Ib/hr),
                               153

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        2. Process sources not including sulfuric acid
           manufacturing sources (Illinois)
             equivalent sulfuric acid usage <1,300 tons per year
             (100$ acid basis)
               0.10 Ib in any 1 hr period
             equivalent sulfuric acid usage >^ 1 ,300 tons per year
             (100$ acid basis)
               0.50 Ib /T of H2SOjj used
    B.  Concentration of I^SOij or SO^ (or combination)
        in Ambient Air in Inhabited Areas beyond Source Premises
        (Missouri)
          0.03 mg (as H2SOn)/m3f 30 min avg., not
            over once in 48 hrs.
          0.01 mg (as H2SO]|)/m3f 24 hr avg., not over
            once in 90 days
          100 ug/m3 of air (std) at any time
    C.  Net Ground Level Concentration (Texas)
          15 ug/m3 of air (std), 24 hr avg.
          50 ug/m3 of air (std), 1 hr avg., measured more
             than once in any 24 hr period.

X.   Other Miscellaneous Sulfur Compounds
     A.  Mercaptans
         1.  Petroleum processing facilities:
             Emissions of mercaptans shall be either: not greater
             than 0.25 Ib/hr (total mercaptans), or controlled by
             passing through a combustion device which will
             achieve complete combustion or any other equally
             efficient device for control of mercaptans.  (New
             Mexico)

XI.  Gasification Plants - Other Contaminants
     A.  HCN Standard.
           10 ppm (vol.) in effluent gas (New Mexico)
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     B.   NH3 Standard.
           25 ppm (vol.) in effluent gas (New Mexico)
           Additionally any stationary tanks holding NH3
           shall be:
             A pressure tank capable of maintaining working
             pressures sufficient to prevent loss of NH? to
             the atmosphere, or
             Equipped with other equally effective control
             equipment to prevent loss of NHo to the
             atmosphere.  (New Mexico)

     C.   Hydrogen Chloride/Hydrochloric Acid Standard.
           5 ppm (vol.), any combination of hydrogen chloride and
           hydrochloric acid in effluent gas.  (New Mexico)

XII.  Hazardous Air Pollutan,^
     A.   Definitions.  "Hazardous air pollutants" means an air
         pollutant to which no ambient air quality standard is
         applicable and which in the judgement of the Adminis-
         trator causes or contributes to air pollution which may
         reasonably be anticipated to result in an increase in
         mortality or an increase in serious irreversible or
         incapacitating reversible illness.  (Federal)
     B.   Mercury (Federal)
         1.   Definition.  "Mercury" means the element mercury,
             excluding any associated elements, and includes
             mercury in particulate, vapors, aerosols, and
             compounds.
         2.   Emission standard.  Emissions from sludge incinera-
             tion plants, sludge plants, or combinations of these
             that process wastewater treatment plant sludges
             shall not exceed 7.05 pounds of mercury per 24-hour
             period.
                               155

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C.  Beryllium
    1.  Federal Standard.
        Affected facilities.  Extraction plants, ceramic
        plants, foundries, incinerators, and propellant
        plants which process beryllium ore, beryllium,
        beryllium oxide, beryllium alloys, or
        beryllium-containing waste.

        Emission Standard.  Emissions from stationary
        sources subject to this provision shall not exceed
        10 grams of beryllium over a 24-hour period.
    2.  Texas Concentration Standard
          0.01 ug/mB, 24 hr avg. (To be measured by the
          difference between upwind and downwind
          concentration levels fo" the source premises, or
          by stack sampling, calculated to a downwind
          concentration (details in appendices of Texas Air
          Regulations.)
D.  Hazardous Pollutants - General
    1.  The utmost consideration shall be given to the
        potential harmful effects of and effective control
        methods for discharages to the open atmosphere of
        hazardous matters including, but not limited to,
        antimony, arsenic, asbestos, beryllium, bismuth,
        lead, mercury, silica, tin, and compounds of such
        materials.  Evaluation of these sources and the
        control methods designed and proposed will be made
        on a case-by-case basis by the Department.
        (Kentucky)
E.  Two of the selected states, Virginia and Colorado, have
    chosen to incorporate into their hazardous contaminants
    category extensive lists of elements and compounds from
                         156

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        sources outside the EPA which  are  aimed  primarily  at
        protecting humans  from  excessive exposure levels  of
        these  contaminants.  Virginia has  incorporated  the  OSHA
        air contaminants list in  29CFR 1910.1000 while  Colorado
        has incorporated  the  ACGIH's  published  list  of
        "threshold Limit Values"  (TLV's) as adopted at  the ACGIH
        35th Annual  Meeting in May 1973.   The method each  of
        these states utilizes to  determine standards and  to
        enforce  such levels for  these substances is described  in
        their  respective synopses,  which also include copies  of
        the complete lists.   No attempt has been made  to
        identify relevant  compounds  on these lists  for  this
        project  as this falls in  line with other work projected
        for the  future work.

XIII. Other Non-Federal Contaminant  Regulations Unique to One  or
    Only a Few States
    A.  Ice Fog  (Alaska)
        1.  Any person proposing to  build  or  operate  an
            industrial process, fuel burning  equipment,  or  an
            incinerator in  an area  of potential ice fog may  be
            required to reduce  water emissions and to obtain  an
            operating permit.

    B.  General  Gaseous Emission  Standards
        1.  Non-process  (Tennessee)
            a)  Definitions.  "Air  contaminant source"  for
                subsection B.I.  means any  and  all  sources  of
                emission of air  contaminants, whether privately
                or  publicly owned.   Without limiting the
                generality of the foregoing, this term includes
                all types of business,  commercial,and indus-
                trial plants, works,   shops,  and stores,  and
                heating  and  power  plants  and stations,
                buildings  and  other structures of  all types,

                            157

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            incinerators of all types (indoor and  outdoor) ,
            refuse dumps and piles,  and  all  stack  and  other
            chimney outlets from any of  the  foregoing.
        b)   Standard.Air contaminant sources shall  install
            and utilize the  best  currently available
            equipment and control technology.

    2.   Process (Tennessee)
        Gaseous air  contaminant  sources shall utilize
        equipment and  technology  deemed  reasonable  and
        proper  by the Board for control  of emissions of such
        contaminants.

C.  Mineral Acids - Nitric Acid Mist or  Vapor,  Hydrochloric
    Acid Mist,or Vapor
    1.    Allowable  stack  gas  concentration  from  any
         stationary sources.
          Nitric Acid Mist and/or Vapor:   70 mg/DSCM
          (West Virginia)
          Hydrochloric Acid Mist and/or  Vapor:  210 mg/DSCM
          (West Virginia)

D.  Fluorides
    1.   Inorganic fluoride compounds
          6 ppb (vol., 3 hr avg., expressed  as  HF), (Texas)

    2.   Fluorine, fluorides (Idaho)
        It is prohibited to discharge such quantities (in
        combination with all other sources  of  fluorine and
        fluorides, both  natural and man-made) that the total
        fluoride content in vegetation for feed  or  forage
        resulting from contact with the  ambient air exceeds:
        a)   400 ppm (dry) - annual arithematic  mean
                        158

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            b)  60 ppm (dry)  - monthly  cone,  for 2  consecutive
                months
            c)   80 ppm  (dry)  -  monthly  cone, never to  be
                exceeded
     3.   Phosphate, phosphorite,  or  phosphorous processing
         equipment and other fluoride  processing or treating
         equipment.  (Montana)
         a)  Any phosphate rock or  phosphorite or phosphoric acid
            processing  equipment,  or equipment processing
            fluorides enriched  wastewater  or fluorides  in
            gaseous or particulate form or combinations.
              0.3 lb/T of ?205 introduced (fluoride re-
              leasing processes)
         b)  Pond emissions.   Any  fluoride emissions from  storage
            ponds, settling  basins,  ditches,  liquid holding,or
            conveying tan., or device associated with facilities
            in 3.a) above.
              108 ug/cm2/28  days  (calcium formate method)

XIV.  Stationary Gas Turbines  (Federal -  Standards of Performance
     for  Stationary Sources)
     A.   Affected facilities:  This subpart  shall be applicable
         to all stationary gas turbines  with a heat input  at peak
         load  equal to or greater  than 10.7 gigajoules per hour,
         based on the lower heating value of the fuel fired.
     B.   Definitions
         1.  "Stationary gas  turbine" means any simple cycle  gas
            turbine, regenerative  cycle gas turbine, or any  gas
            turbine portion  of a  combined  cycle steam/electric
            generating system that  is  not  self-propelled.  It
            may,  however,  be  mounted  on a  vehicle  for
            portability.
                             159

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2.  "Simple  cycle gas turbine" means  any  stationary gas
    turbine which does  not  recover heat from  the gas
    turbine exhaust  gases to  preheat  the inlet
    combustion air to the gas turbine,  or which does not
    recover  heat from the gas turbine  exhaust  gases to
    heat water or generate steam.

3.   "Regenerative cycle  gas  turbine"  means  any
    stationary gas turbine which recovers heat  from the
    gas turbine exhaust gases  to preheat the inlet
    combustion air to the gas turbine.

4.  "Combined cycle  gas  turbine" means  any stationary
    gas turbine which recovers heat from  the gas turbine
    exhaust  gases to heat water o^ generate  steam.

Emission Standards for Nitrogen Oxides  (NOX)
1.  Gas turbines with heat rate at peak load ^14.4
    kilojoules per watt hr (lower heating value of
    fuel).
      NOX emissions, E, in exit gases not to exceed:
        E =  0.0075 + F
      where:
        E =  maximum NOX emissions in  %  by volume
            (at 15$ 02 and on dry basis)
        F =  NOX emission allowance for  fuel  bound
            nitrogen as defined in subpart C.3. below.

2.  Gas  turbines  with heat  rate  at peak  load <  14.4
    kilojoules per  watt hr  (lower heating  value of
    fuel).
      NOX emissions, E, in exit gases not to exceed:
        E =  0.0075 i1*'4   + F
                    Y
                    160

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      where:
        E = maximum  NOX  emissions in % by volume
           (at  15%  02 and  on  dry basis)
        Y = manufacturer's  rated heat duty at peak load
           in kilojoules per  watt hour.
        F = NOX  emission allowance for fuel bound
           nitrogen as  defined in C.3. below.

3.   The term  F shall be  defined according to the
    nitrogen  content of  the  fuel as follows:

    Fuel Bound N*                        F
    (% by Wt)                      (NOyJt by vol.)
    N £ 0.015                             0
    0.015 < N _<  0.1                       0.04  (N)
    0.1 < N _<  0.25                0.004 + 0.0067  (N-Oil)
    N < 0.25                              0.005

    *N = Weight  % nitrogen  in  the fuel

4.   Exemptions  from  NOX  Emission Standards
    a)  Stationary  gas turbines  with a heat  input at
        peak  load of 107.2  gigajoules per hour (100 MM
        Btu/hr)  or less  (lower heating value  of fuel) -
        exempt  for not more  than  5  years from  proposal
        date  of  these rules.
    b)  Stationary  gas turbines  using water  or steam
        injection  for control  of NOX emissions  -
        exempt when  ice  fog  is deemed a traffic hazard
        by turbine owner or  operator.
    c)  Emergency  standby  gas  turbines, military gas
        turbines other  than  at garrison facilities, and
        fire-fighting gas turbines.
                    161

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D.  Emission Standards for Sulfur Dioxide  (S02)
    1.   Maximum Emission Rate in Exit  Gases
        0.01556 S02 (by vol., at 1556  02 and on dry
        basis)

    2.   Use of fuel  sulfur content  in determination  of
        compliance with  subpart D.I.  This method  may  be
        utilized in the  alternative with a maximum  sulfur
        content of 0.856  by weight in any fuel  burned by a
        gas turbine under  such circumstances.
                         162

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                            SECTION 7

             DEVELOPMENT OF ENVIRONMENTAL  OBJECTIVES
The compilation of present and proposed environmental  standards
and guidelines for  federal,  state,  regional,and  international
jurisdictions, and the summarization of these regulations into a
listing of most stringent standards, provides a  set  of criteria
against which the engineering designs for control  of effluents,
emissions and wastes from proposed coal conversion  plants may be
judged.  The statement ma^ be made that a coal conversion facil-
 ity  designed to meet the most stringent standards  could  be built
anywhere in the United States, Canada,or Mexico.

By definition, the most stringent standards are  summarizations of
existing legislation and reflect the opinions and best  judgement
of the legislators at the time of enactment.  As more  knowledge
accumulates concerning the great variety of organic and inorganic
compounds that may be formed  during conversion of coal, and more
data are gathered on  the  effects of  these compounds on the envi-
ronment and its inhabitants,  the possibilities arise  that exist-
ing standards may be right, or too stringent or  not sufficiently
stringent.  There is the additional possibility  that  the  existing
standards are not sufficiently comprehensive and, in  the future,
should be extended to include more materials.

Assistance in evaluating present standards against present  needs,
and in indicating possible future goals for legislative improve-
ment,  is provided by EPA through the establishment of Multimedia
                              163

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Environmental Goals  (MEGs).  The MEGs are estimates  of  desirable
ambient  and emission levels  of  control and, as  such,  are an
integral part of EPA's environmental assessment approach.  The
program to assemble  a master list of chemical contaminants, com-
plex effluents and mixtures and then to develop a methodology  to
establish meaningful values that will serve as MEGs  is  described
at length in "Multimedia Environmental Goals  for  Environmental
Assessment" by J. G. Cleland and G. L. Kingsbury,  EPA-600/7-77-
136a(Vol. 1) and -136b(Vol. 2), November 1977.
COMPARISON OF MOST  STRINGENT REGULATIONS WITH MEG CRITERIA

The stringency criteria developed from the  synopses  of air and
water regulations were compared with the criteria  for like con-
taminant substances  shown  in MEG  charts in  the  MEG  report pre-
viously noted.  Four categories of concentrations were compared:
Water Effluents,  Water Ambient  Bodies, Air Effluents, and Air
Ambient Bodies.

Values were not  always available  for all of the  categories for a
given substance.   Further, since many important regulations
relevant to the  project were stated only in  terms of allowable
rates, and were  thus not comparable to MEG  concentration data,
their provisions were not  included in the comparison.   A total of
43 relevant substances were compared, with the following results:
  Water Effluent
  Water Ambient
  Air Effluent
  Air Ambient
 More Stringent
MEG  Regulations
 7      12
 8       4
12       1
28
                           18
Same Value
 For Both
   14
    8
    0
   _3
   25
  Total
Comparable
    33
    20
    13
    _5
    71
                              164

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 The comparison  for emissions/effluents is  shown  in TABLE 7-1.
 The comparison  for ambient bodies is shown in TABLE 7-2.

 The primary  purpose of  this comparison and study was to  determine
'the relative level of stringency represented  by the most strin-
 gent of the regulations synopsized as compared  with  the most
 stringent  of a  body of  criteria known to be,  as MEG criteria are,
 primarily  based on actual effects  on human  welfare and/or the
 environment  (such  criteria as might be expected to  be utilized by
 major regulatory agencies in the formulation  of new anti-pollu-
 tion standards or in updating  existing standards).  With the
 criteria available in the MEG charts it was possible to   compare
 criteria for contaminants developed for air  and water  effluent
 streams and  ambient (receiving) air and water bodies.

 Similar solid waste media co  arisons were not  made because the
 solid waste  synopses  contained  few of the  numerical standards
 that are needed for such a quantitative analysis or comparison.

 The values used in the comparisons for most  stringent air ami
 water standards came  from the summaries of the most stringent air
 and water  quality  standards in  this report  and from the report
 section covering ambient air quality standards.

 The methodology described in "Multimedia Environmental Goals for
 Environmental Assessment" makes use of charts for emission level
 goals and  ambient  level goals as shown in Figure 7-1. Both  goals
 were considered in the  comparision with most stringent standards.
 Emission  level goals are those  associated  with  effluent or
 discharge streams from  point  sources  and/or with  fugitive
 emissions.   These  goals may  be  based on  technology factors or
 ambient factors; however, technology based emission criteria were
 not addressed by the  MEG report and, therefore, ambient factors
 only served  as  the MEG  criteria used in comparisons of  emission
 level goals.

                            165

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  TABLE 7-1.   COMPARISON OF MOST STRINGENT STANDARDS CRITERIA
           WITH MEG CRITERIA FOR EMISSIONS/EFFLUENTS
Comparision of Most Stringent Water and  Air  Effluent Concentra-
tions with Multimedia Environmental Goals  (MEGs)  for Emissions.
MEGs Based  on Ambient Factors Rather Than  Best Technology
Available,
                 Maximum Effluent Concentration
In Water^
MEG
Pollutant MATE**
Alkyl benzene
sulfonate (ABS)
Aluminum 0.073
Ammonia 0.05
Antimony 0.2
Arsenic 0.05
Barium 2.5
Beryllium 0.03

Boron 25
Cadmium 0.001
Carbon Monoxide 0.06

Chlorate
Chloride
Chlorine,
residual
Chromium 0.25
Cobalt 0.25
Copper 0.05
CyanideCas HCN) 0.025
Fluoride (as HF)

Hydrogen chloride,
HC1 (acid), HC1
(mist)
Hydrogen
sulfide 0.01
Iron
Lead 0.05
Magnesium 87.0
Manganese 0.1
Mercury 0.01
Molybdenum 7.0
mg/1
Most
Stringent

-
0.2
0.5
0.05
0.05
1.0
-

1.0
0.005
—

50
250

0.2
0.05
0.1
0.05
0.02
1.0



250

-
0.3
0.05
150
0.05
0.001
0.50
In
MEG
MATE**

-
0.0126
0.35(0
0.5
0.002
0.5
0.002

3.1
0.01
40(35)

-
-

-
0.001
0.05
0.2
11.0
-



-

15(10)
-
0.15
6.0
5.0
0.01
5.0
AirL mg/m-3*
Most
Stringent

-
—
.49) (25)
-
6.9
-
0.00001
(24 hr)
—
6.9
(200X93*
removal)
-
-

-
-
7.0
6.0
—
0.006
(3 hr)


210

(100)
-
6.9
-
—
6.9
—
                               166

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TABLE 7-1.   COMPARISON OF MOST STRINGENT STANDARDS CRITERIA
          WITH MEG CRITERIA FOR EMISSIONS/EFFLUENTS  (CONT)
                       Maximum Effluent Concentration
  Pollutant
Nickel
Nitrates
NitritesUs N)
Nitrogen
Nitrogen oxides
Ozone
Phenols
Phosphorus
Polychlorinated
 biphenyl (PCS),
 total
Selenium
Silver
Sulfate
Sulfides and
 mercaptans
 (as S)
Sulfur
Sulfur dioxide
Urea
Zinc
In
MEG
MATE**
0.01
Water, mg/1
Most
Stringent
0.20
10.0
2.5
In
MEG
MATE**
0.015
Air, rag/m0*
Most
Stringent
140

0.005
0.0005
0.000001
0.025
0.005
15.0

200

0.1
0.005
1.0
            0.01
            0.05
            50
            0.011
            1.0
            0.075
                           9.0
                           0.01
                           19.0(5)
                           0.1
               0.5
               0.2
               0.01
               1.0(0.5)

               13

               4.0
                                      100(26)
                                        250

                                        6.9
* Concentrations in parentheses are  ppm(v)
"MATE = Minimum Acute Toxicity Effluent  value  from  the
         applicable MEG charts.  The  value  shown  is  the  more
         stringent of health or ecological  effects criteria.
                              167

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TABLE 7-2.  COMPARISON OF MOST STRINGENT STANDARDS CRITERIA
          WITH MEG CRITERIA FOR AMBIENT BODIES
Comparison of Most Stringent Water and Air Criteria for Ambient
(Receiving) Bodies With Multimedia Environmental Goals (MEGs)
for Ambient Bodies

                        Maximum Effluent Concentration
                   In Water, mg/1
  Pollutant
Alkyl benzene
 sulfonate (ABS)
Aluminum
Ammonia
Antimony
Arsenic
Barium
Beryllium

Boron
Cadmium
Carbon Monoxide
 MEG
MATE**
 1.0
 0.010
 0.007
 0.01
 0.5
 0.000075

 0.043
 0.0004
 (fresh)
 0.0002
 (sea)
 0.03
Chlorate
Chloride
Chlorine,
 residual
Chromium         0.05
Cobalt           0.0007
Copper           0.01
Cyanide
 (as HCN)        0.005
Fluoride
 (as HF)
Hydrogen chloride,
 HC1 (acid), HC1
 (mist)
Hydrogen sulfide 0.002
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
 0.010
 0.083
 0.020
 0.002
 0.070
  Most
Stringent

  0.5

  0.15

  0.01
  0.5
  1.0

  0.005
           100.0

             0.002
             0.05
             1.0
             0.005

             0.005

             1.0
  0.002

  0.3
  0.01

  0.05
  0.002
                               In Air,  mg/mj*
 MEG
MATE**
           Most
         Stringent
 5.2
 0.035
 0.0012
 0.000005
 0.001
 0.00001
 (30 day)
 0.074

 0.00002
                             0.00001
                             (30 day)
                  10(9)(8 hr) 10(9)
                              (8 hr)
                  0.000002
                  0.0001
                  0.0005

                  0.026(0.024)  -

                             (0.001)
 0.036
(0.024)

 0.00036
 0.014
 0.012
 0.00001
 0.012
            (0.003)
            (1 hr)

             0.005
                           168

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TABLE 7-2.   COMPARISON OF MOST STRINGENT STANDARDS CRITERIA
	WITH MEG CRITERIA FOR AMBIENT BODIES    (CONT)
                        Maximum Effluent Concentration
                   In Water, mg/1
 Pollutant
Nickel
Nitrates

NitratesCas N)
Nitrogen
Nitrogen oxides
(as NO )
Ozone
Phenols
Phosphorus
Polychlorinated
 biphenyl (PCB),
 total
Selenium
Silver
Sulfate

Sulfides and
 mercaptans
 (as S)

Sulfur, total
 reduced

Sulfur dioxide
Urea
Zinc
 MEG
MATE**
 0.0006
  Most
Stringent
  0.025
  10
 0.001
 0.0001
 0.000001
 0.005
 0.005
 0.0138
 0.02
  0.001
  0.05
  0.00
  0.005
  0.0001
  0.030
                               In Air, mg/m^*
 MEG
MATE**
 0.000035"
  Most
Stringent
 0.16
 (0.08)
 (1 hr)
 0.045(0
 0.00024
    0.10
    (0.05)
   (annual)
    0.16
    (0.08)
    (1 hr)
,01)   -
 0.0012
 0.00003
 0.000024
                                          0.004
                                        (annual)
                  0.0024
                  (0.001)
                                         (0.003)
                                         (1 hr)
                                          0.365
                                          (0.14)
                                         (24 hr)
 0.0095
* Concentrations in parentheses are  ppm  (v)
**MATE = Minimum Acute Toxicity Effluent.  Values  shown  are  the
         most stringent of the ambient level  MEGs  for  (a)
         health or ecological effects based on  current or  pro-
         posed ambient standards  or  criteria  or (b) health or
         ecological effects based  on toxicity based estimated
         permissible concentration
                           169

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Within the  ambient factor category  the effluent regulations could
be compared with minimum acute toxicity effluent  (MATE)  values,
considering  both  health and ecological effects,  with  ambient
concentration  goals,  considering both health  and ecological
effects or  with elimination of discharge values,  based  on natural
background.  The latter criterion was generally not  available so
it was not  used.  Ambient concentration goals  require dilution
factors if a comparison  is to be  made  with  other effluent
criteria such as the most stringent regulations  values reported
herein.  Therefore,  the comparison was confined  to the  MATE
criteria for  water and air.   The more stringent  value for this
MATE  criterion,  regardless of  whether based on  health or
ecological  effects, was selected.

Ambient level goals were compared wherever  data  were available.
Most stringent  receiving water standards in the synopses  summary
and the most  stringent ambient air  quality  standards from the
ambient air section of the report were compared with MEG  criter-
ia.  As seen  in Figure 7-1, the MEG criteria in the  ambient level
goals chart are based on three main categories  of ambient level
goals.  The ambient standards category and  toxicity based cate-
gory (toxicity  based  estimated permissible  concentrations, or
EPCs)  take into account both health and  ecological effects.
Criteria for  the third category,  zero threshold  pollutants, are
based only  on health effects.  Criteria in this category  were not
generally available  for the  pollutants involved and thus this
category was  not used in this  analysis.  The ambient standards
from the MEG charts were presumed to  be drawn from  a wider body
of standards than those  synopsized  and therefore would be
expected to be  supported by data on health or ecological  effects
substantiated as well, if not better, than that data on which the
most stringent  summary standards are  based.  Regardless,  most of
the lower MEG values used for  comparison were from category II
(toxicity based).
                               170

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MULTIMEDIA
ENVIRONMENTAL
GOALS
                     EMISSION LEVEL GOALS
 Air. itg/m3
 IppmVoll
         1. Bwd an Bwt T«**olo«y
        **
                 **
                                II. Bw«d on AmtxwM Factor*
AMBIENT LEVEL GOALS
IppnVtfJ

(porn'mi
(ppmWtl
1. Currant or rVopoMd Ambient
AH—-




JijrtL.




II. Teiwitv BiMd EttintBWd
fwmwbt* CenflMtication
JL!!7I^.




tx^.rr-*m




III. Zero Thmhold ^olluUmi
rtnwud ^•rmiMAI* ConeMflrMien
^.H^.,^

**


  Figure  7-1.  Charts for  MEGs.

  (From  "Multimedia Environmental  Goals for
   Environmental  Assessment" EPA  600/7-77-136)


  **Not  used in  comparison
                       171

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The MEG charts  now  encompass  216  substances with  over 650 pro-
jected for coverage.  Each of these substances  is  also  within one
of the 85 categories of substances which EPA has  designated for
its MEG  studies.   Work is continuing on MEG charts  for many
substances now  listed in these categories but for  which published
charts are not  yet  available.  Hazardous substances are added to
the designated  categories on a  continuing  basis.  The EPA has
ranked the 216  substances that are now addressed  by MEG charts by
two methods to  indicate the relative degree of hazard of the sub-
stances:   a number  system from 30 to U, with the  higher numbers
more hazardous,  and a symbol  system using X, XX,  and XXX,  with
XXX substances  the  most hazardous.  Both indicators are shown on
the MEG charts.  A  number of  relevant substances,  some important
and some  minor, were found  to  be addressed by  the stringency
summaries but not by synopsis in the MEG charts  then available.

Several significant limitations briefly mentioned  above should be
emphasized relative to the comparison and analyses made.  This is
true as to air  contaminants where many of the jurisdictions state
effluent  regulations in terms  of allowable rates (weight or
volume per unit of  time or per unit of feed entering or Btu input
to the facility) as"opposed to terms for effluent  concentrations
as in the MEG criteria.  Among others, such is the case with NOX
and SO ,  two important substances for which there are criteria
within the National Ambient  Air  Quality Standards (NAAQS) .  As
seen in TABLE 7-1,  the most stringent regulation effluent concen-
trations are also available for S02, but these  values  are  inde-
pendent of allowable  rate regulations which are  more  common to
the jurisdiction studied.  Two other NAAQS  criteria categories,
particulates and non-methane  hydrocarbons, encompass a variety of
substances and  thus are too broad  to have  comparable substances
covered by MEG  charts.  This  is also true  of the  NAAQS category
for photochemical oxidants although some comparison was possible
through  consideration of ozone  concentration  criteria only.
                              172

-------
Similarly many of the  regulations synopsized,  especially  in the
water  area,  cover physical  conditions  such as  temperature,
turbidity, color, or biological criteria such  as BOD   and total
coliform bacteria not  addressed by MEG criteria,  which  cover only
elements and substances that  can be  defined by a chemical
formula.  Considerable discretion was necessarily  exercised in
selecting the most stringent  criteria for certain  contaminants
and thus a different  result  would have been  obtained in these
cases with the use of  slightly different selection  guidelines or
philosophy.  As already stated, and as can readily  be  seen on the
charts herein, there are relevant substances  for which one type
of criterion, either MEG or most stringent  regulation,  is
available but not both.

Finally, several other MEG factor categories such as elimination
of discharge (under emission  goals) and zero theshold  pollutants
estimated permissable concentration (under  ambient  goals) are
still being developed  and there generally was not sufficient data
of this  type available for comparison with  the most stringent
regulations.
RECOMMENDATIONS FOR PROJECTION  OF  FUTURE GOALS

Federal, EPA, state,  regional,and international environmental
standards, present  or proposed, have  been  surveyed and synop-
sized.  From them has been compiled a summary of the most strin-
gent of the air and water regulations.   Concentration standards
from the stringency analyses have been  compared with criteria
available for like compounds  in the  EPA-sponsored  study on
"Multimedia Environmental Goals  for Environmental Assessment"
(EPA-600/7-77-136,  November 1977, referred  to hereinafter as
MEG).  The stringency study and MEG comparison were limited to
the media of air and water as the  solid waste synopses contained
                            173

-------
very few numerical standards for  quantitative analysis  or  compar-
ison. For  the  same  reason the following  discussion somewhat
emphasizes  the  air and water media  areas; however,  much of what
is indicated will be indirectly or  at least partly applicable to
the solid waste category as well.

When the project  scope was reduced, planned  work to  determine
projected 2, 5,and 10 year environmental goals, to correspond to
the current and proposed standards  reported, could not  be accom-
plished. Nevertheless, recommendations can be made as  to  further
work or  work methods and approaches to estimate at what level
these future goals might be set.  The following recommendations
are made in an  attempt to satisfy this objective.  They are not
in any order of priority.  There  would be overlapping between
some of  the items listed, and it  is unlikely that it would be
necessary or desirable to pursue  all of the approaches.

  1.  A  thorough  study of health  and ecological effects of appli-
      cable substances.  Here any number of good sources should
      be utilized to gather data  on criteria including, to name  a
      few,  MEG  related studies and  charts,  Threshold Limit Values
      (TLVs)  of various  organizations  such as ACGIH,  NIOSH
      studies and recommendations,  OSHA regulations and reports,
      U.  S.   Public Health  Service  studies,  guidelines and
      standards,  NAS/NAE  Water  Quality Criteria,  Chemical
      Industry Institute  of  Toxicology reports and  reference
      compilations such as "Industrial Hygiene and Toxicology,"
      by Interscience Publishers.  Such  a study would also be
      helpful  in better  evaluating the current and  proposed
      regulations presented herein, since their controlling basis
      is generally not known.  This is one of, or possibly the
      highest  of, priority recommendations  listed here if re-
      sources permit such an approach.  The MEG comparison made
      was a preliminary or first  step in this  direction and could
      also  be expanded on as a more detailed study.
                            174

-------
Review  and analyses of current  and proposed applicable
regulations of  jurisidictions  other than those selected.
These could include other highly developed countries  such
as Germany,  Japan, France,  United  Kingdom,and Sweden,  other
states with  either  newly discovered  or potential  coal
deposits or known to have very stringent regulations  such
as California (or Los Angeles  County)  and other  possible
international bodies of regulations (the  latter not likely
to be highly fruitful).

Complete process designs of  several  favored conversion
plant configurations with different scenarios  for various
coal feeds coupled with  the use  of programmed modelling
techniques to determine  ambient concentrations of pollu-
tants in the areas outside of facilities and at different
altitudes or depths.  This  would  allow  complete  analyses
and comparison  of different regulations regardless of their
bases or units  or their  presentation  as an equation.  Am-
bient media  and effluent  regulations could be   analyzed
equally well.

As part of or in addition  to Item 1,  a  thorough  study of
applicable substances as  carcinogens, mutagens,  or  tera-
togens and the limitation levels dictated thereby.  Studies
of the concept of "zero threshold pollutants"  as  referred
to in the MEG report would be recommended here.

A "best future technology"  approach,  based on a  study of
estimates, forecasts,and reports on developing  technology.
National and international  economic considerations  could
also be studied and  analyses made  both with  and without
them factored in.   Projected  energy,  fuel  and
transportation availability  as  possibly affecting  such
concerns as national security and utility reliability might
also be considered.

                      175

-------
 Some of  the  regulations  already  included  are  more
indicative of future standards than others.  The  New Mexico
air regulations for gasification plants are probably close
to five  year levels and  possibly somewhat beyond.  British
Columbia  water regulations  and International Joint
Commission proposed water regulations  are probably  close to
five year  levels.  Various Water Act mandates are very good
indicators for the  level  of future  water standards.
"Fishable, swimmable, navigable waters" are mandated by
July 1,  1983 and zero discharge of pollutants to navigable
waters by  1985.  Toxic pollutants in toxic amounts are
already  prohibited.   A closer review of the existing and
proposed laws and of the regulations presented herein is
highly recommended  as  an  aid in  projection  of future
regulations.  A review of the synopses under a different
set of guidelines might  produce  different levels for
current  most  stringent  regulations for some substances.
Discretion is necessarily involved in the most stringent
regulation selection process and philosophy or guidelines
used probably  resulted  in  close to the lowest allowable
levels possible from such an analysis.

Regardless of  other approaches  or  methods pursued,  a
continuation of the  review and  updating of applicable
Federal and state  legislation and  regulations  as
promulgated and published in the Federal Register and  other
timely periodicals  or issuances of the jurisdictions would
be necessary.  Additional regulations either directly for
coal conversion facilities  or for other closely related
facilities may be promulgated  at  any  time by  various
jurisdictions and new bases for closely related regulations
should also be followed  for  futher insight.  Mandates of
new environmental  laws as  they are  passed  must  be
identified and interpreted in  the  light of possible
                      176

-------
    effects  on  regulations or regulation  of new parameters.
    Following new regulations  yet to be  promulgated  under
    current  legislative mandates  such  as  for  more ambient air
    criteria substances and more industries  under new source
    performance standards also will be a necessity.

    In air pollution control the effect  of the prevention of
    significant deterioration  (P.S.D.)  and emission  offset
    regulations,  as these  control methods  mature,  on  point
    source regulations for air criteria substances will  have to
    be taken into account.  These new  regulatory concepts  might
    have  a  major effect  on  future regulations  of  the  point
    source,  fugitive emissions,   and ambient  media type. Man-
    dated changes in state implementation plans due to lack of
    progress in attaining criteria  substance  ambient standards
    must also be reviewed and analyzed for  probable effects on
    other future regulations.

8.   Water regulations based on use  or  specific supply objective
    requirements (as  in  Section VI  of Canada Federal  Water
    synopses) in various jurisdictions might  be used to aid in
    forecasting receiving water and  emission levels regula-
    tions.   If brought  into  more  general use,  this  type of
    regulation  might control the  setting  of receiving  water
    standards just  as  these  generally control  point  source
    effluent concentration allowables.   Drinking water  stan-
    dards are the best example of water use standards already
    commonly in effect.

9.   Study of relevant substances  in the light of elimination of
    discharge (EOD) type emission level goals, another concept
    being used in MEG studies.   These  goals would be the most
    stringent and are based on the  premise  that ambient pollu-
                           177

-------
tant concentrations should  not  exceed natural  background
concentration.  Dilution  factors are used to put  ambient
concentrations in terms  of effluents.  Rural  air atmos-
pheres and  drinking water and seawater are  frequently used
in studies  to  aid in the study indication of natural back-
ground concentrations.
                         178

-------
                          SECTION 8
                ENVIRONMENTAL  DATA ACQUISITION
                  CONTROL OF LIQUID EFFLUENTS
DEVELOPMENT OF CONVERSION PROCESS  EFFLUENT STREAM MODELS

From the  study of  available information,  it  was  apparent  that
coal conversion proces_ s could be conveniently  divided  into
three  basic types:   gasification  processes operating  at
relatively low temperature, gasification  processes  operating at
relatively high temperature and liquefaction processes.

Almost  all  of the  gasification  processes  that operate at
relatively low temperatures (1,035°C or  lower)  produce phenols,
oils,and  tars (p/o/t).  These  processes are best typified by the
commercial Lurgi  Dry Ash process  (143*) since this  process
produces p/o/t in large quantities, and  since more data are
available on this  process than on  any other gasification  process.
Accordingly, it has been adopted as  the base case process for the
study of  control technology applications.  Figure 8-1 illustrates
the liquid effluent streams to which control  technology must be
applied.
•Reference  numbers are Kellogg File Numbers  in the  project
 bibliography.
                             179

-------
                                       RAW
                                     WATER
                        MAKG-UP
                                                                     COAL
                                                       TO STEAM I
                                                       HATER SYSTEMS
                                                           STEAM
                TO
              DISPOSAL
                               TREATING
                               CHEMICALS
00
O
OILY WATER FROM
PROCESS AREA
                                               SLUDGES FROM
                                               1.  Lime Treaters
                                               2.  Clarlfiers
                                               3.  Cooling Tower
                                               4..DEIONIZER  .
                                               5.  BOILERS
                        TO INORGANIC
                        CONCENTRATION AND
                        WATER RECYCLE.
                        INORGANIC CONCEN-
                        T1WTE TO DISPOSAL
                                                          OXYGEN^
                                                                               RAH
                                                                               GAS
                                                                             QUENCH
                                                                 SHIFT
                                                                CONVERSI01
                                                           TARRY
                         TO SOLIDS
                         DISPOSAL
                         SYSTEM
                                                      GAS
                                                    COOLING
                                                                     WATER
                                                                                      GAS
                                                                                    LIQUOR
                                                                                  SEPARATION
    ACID
    GAS
  REMOVAL
                                                                                     PUF
                                                                               SOUR
                                                                               WTER
                                                                              PHENOL
                                                                              RECOVERY
   METI1-
  ANATION
          DRYING
SNG
                                                                                                           CLEAN
                                                                                                      TO RECYCLE
                      RUtf-OFF FROM
                      CLEAN AREAS
                       SANITARY
                       SEWAGE
 TO OIL SEPARATION
 AMD RECOVERY OR FUEL
 - WATER RECYCLED TO
 '  RAW WATER TREATING

- TO IMPOUNDMENT AND
  RECYCLE TO RAW
  WATER TREATING
                       - .TO PACKAGE SEWAGE
                        PLANT  t DIOXIDATION
                       - SLUDGE TO INCINERATOR/
                        BOILER
                                            'TARS, OILS
                                             TO SALES OR
                                             FUEL
CRUDE
PHENOLS
TO SALES
OR FUEL
                                                                                                          IF
                                                                                                     STRETFORD
            STRIPPING
               t
            NH3 RECOV.
                                                                                                                WATER
                       AMMONIA
                       TO SALES

                        CO-, II,S
                                                                                                                       TO
                                                                                  UNIT
 TREATMENT SYSTEMS
 AND RECYCLE

 OILS, PHENOLS,  RESIDUAL
 Nil,, CYANIDES,  CYANATL'S,
 RESIDUAL SULFIDE, FATTY
 ACIDS,  INORGANICS.
 INORGANIC CONCENTRATE
 TO SOLIDS DISPOSAL
"SYSTEM.   ORGANICS NOT
 RECOVERED ARE DESTROYED
                                        _ POTABLE
                                       "^ WATER
                                    Cl,
                                                                                          TREATED WATER TO COOL-
                                                                                          ING TOWER, BOILER
                                                                                          SYSTEMS OR RECYCLE TO
                                                                                          RAW WATER TREATING
                 ftTED
              WATER
                       Figure  8-1.   Effluent  model:    Lurgi  (p/o/t)  gasification

-------
The  gasification  processes that  operate at  relatively high
temperatures produce little or no p/o/t.  These are the entrained
flow, slagging ash processes, such as Koppers-Totzek,  Bi-Gas  and
Texaco.  We have elected to use the C. F. Braun conceptual design
(295) for Bi-Gas, for consistent definition of stream quantities,
and  the analyses of contaminants from Koppers-Totzek (315), since
these are the only available analyses.

Figure 8-2 illustrates the liquid effluent  streams that  must be
treated.

Liquefaction processes are  best  illustrated by the conceptual
design of Ralph M. Parsons for SRC II (814).  This design employs
the  Bi-Gas Process to gasify coal in order to make hydrogen, both
for  the liquefaction reactors and also  for  hydrodesulfurization
of the liquefaction distillate products  (LPG and naphtha) .   Fuel
gas  is manufactured by the Texaco process, gasifying liquefaction
residue and coal.  Stream quantities from  the SRC II design are
used in our treating study, but stream  contaminant analyses are
taken from H-Coal  and Koppers-Totzek  data,  since these latter
were more complete than the data from SRC  II, Bi-Gas, or  Texaco.
Effluents to be treated are illustrated  in Figure 8-3.

Sour Water Analyses Located

Analyses of contaminated  (sour)  water  have  been collected and
tabulated for the  following processes and are included as part of
this section of the report.
Process
Lurgi
Process
 Type

Gasification.
P/o/t Producer.
 Number
Analyses

   18
     Remarks

Good data from com-
cial plants.  Four
different coal feeds,
                            181

-------
                                      HATERS/
                                                   TO STEAM
                                                   WATER
                                                   SYSTEMS
                                              COAL
                                              0
                                      PAHP.TRB
                                                             WATER
                                                           STEAM
                                                           OXYGEN
             TO MINE
00
NJ
                                  TREATING
                                  CHEMICALS
OILY WATER
  FROM
PROCESS AREA
                       RUN-OFF FROM
                       CLEAN  AREAS
                                                                  CASIFIERS
                                             SLUDGES  FROtl
                          LINE  TREATING
                          CLARIFIERS
                          COOLING TOUER
                          DEIONIZER
                          BOILERS
                                                                    SLAG
                                                       RAW
                                                       GAS
                                                     QUENCH
                                                                    SLAG
                                                                   QUENCH
 TO INORGANIC
 CONCENTRATION 	
 -WATER RECYCLED

•»- TO  OIL
 SEPARATION
 - OIL  TO FUEL
 - WATER TO RAW
   WATER TREATING
                                                                    [WATER
                                                                     MAKEUP
                                                                                        SHIFT
                                                                                     CONVERSE POOLING
                                                                                                GAS
                                                                                            SOUR
                                                          SOLIDS
                                                         DISPOSALS
SOLIDS DISPOSAL
SYSTEM CONTAINS
SIEVES,  THICKENER,
VACUUM FILTER, AND
SAND FILTER
                                                                 ACID
                                                                 GAS
                                                              REMOVAL
                                                                                                    WATER
                                                   METHA-
                                                   HATIOW
                                                                                                                         >RYING
                                                                                                                                 SNQ
                                                       STRIPPING
                                                       AND N1I3
                                                       RECOVERY
                      TO IMPOUNDMENT AND
                      RECYCLE TO RAW
                      WATER TREATING
 SOLIDS
 TO MINE

—*- COAL
   CARRIER
    WATER
                                               COAL FEED
                                               PREPARATION
                                                PURGE TO
                                                SOLIDS DISPOSAL

                                                	^-AMMONIA
                                                     TO SALES
          CLEAN
             WATER TO
             STEAM
             SYSTEM
                                                                                             H S to SULFUR
                                                                                              '     PLANT
.TO COOLING TOWER
 (TREATMENT REQUIRED)
 CYANIDES, RESIDUAL
 NH-,  SULFATES,
 INORGANICS
                        SANITARY
                        SEWAGE
              ©
              TREATED WATER
           Id,
                     • TO PACKAGE SEWAGE
                      PLANT 4 BIOXIDATION
                      - SLUDGE TO INCINERATOR/BOILER

                      POTABLE
                      WATER
                         Figure  8-2.   Effluent model:   Bi-Gas  (no p/o/t)  gasification,

-------
                                              RIVERA
                                              WATERS'
                                MAKE-UP
                        COAL
                     PREPARATION
                _LItAE_
             COAL
             TO

             PROCESS
                                                                                     -STEAM
                                                        TO STEAM &
                                                        WATER SYSTEMS
    RAW WATER
    TREATING
TREATING
POND
                SLUDGE
                TO
                MINE
TREATING
CHEMICALS
                                                                        LIQUEFACTION
                                                      SLUDGES FROM
CLARIFIERS
COOLING TOWER
DEIONIZER
BOILERS   '
                                                      5. LIME TREATERS
                                   PROCESS
                                   GASIFIER
                                                                               RESIDUAL CHAR, OIL
    FUEL GAS
    GASIFIER
                                                                              If
                                                                                                       LAG
CD
U)
                       TO INORGANIC CONCENTRATION
                       AND WATER RECYCLE.
                           INORGANIC CONCENTRATE TO
                           DISPOSAL
                                                                                       ASH
                                                         HIGHLY CONTAMINATED
                                                         SOUR WATER TO
                                                         STRIPPING
                                                           a. Oils
                                                           b. Phenols
                                                           c. NH
                               OILY WATER FROM
                               PROCESS  AREA
                              SLAG SETTLING
                              BASIN OVERFLOW
                  SLAG TO
                  MINE   —*•
                TREATEp-x
                WATER W
                 Cl.
        RUN-OFF  FROM
        CLEAN AREAS
                             EANITARY SEWAGE
                                - TO OIL SEPARATION
                                  AND RECOVERY
                                - WATER TO SLAG QUENCH
                               •TO BIOLOGICAL TREATMENT
                                AND RECYCLE
          TO  IMPOUNDMENT AND
         _. RECYCLE TO RAW WATER
         "" TREATMENT

           TO PACKAGE SEWAGE TREATING,
           BIOXIDATION WATER RECYCLED.
           SLUDGE TO BOILER OR FUEL
           GAS GASIFIER
                                         nil K
                                      d.  Cyanides
                                      e.  Cyanates
                                         US
                                         Other  organics
                                         Trace  metals  (low)
                                                                                                                             SLAG
                        f.
                        g.
                        h.
                                                                                                             LIGHTLY
                                                                                                             CONTAMINATED SOUR
                                                                                                             WATER TO STRIPPING
a. Nil,
b. Cyanides
c. Sulfates
d. Inorganics
e. C02
                                                                                   IFROM GAS
                                                                                    TREATING
                                                   TO TREATMENT SYSTEMS AND
                                                   RECYCLE TO PROCESS.   INORGANICS
                                                   TO CONCENTRATION AND DISPOSAL.
                                                   ORGANICS RECOVERED FOR SALE OR
                                                   DESTROYED.  AMMONIA RECOVERED.
                                                   PIIEHOLS RECOVERED.  CO, and H,S
                                                   TO SULFUR PLANT.
                    POTABLE
                    WATER
                        Figure 8-3.   Effluent  model:    SRC  liquefaction.

-------
Synthane
Gasification.
P/o/t Producer.
12
Analytical data good,
but samples from
bench scale unit.
Wide range of results
partly explained by
wide variation in
process steam.  At
least 6 different
coal feeds may
explain other
variations.
Hygas
Gasification.
Phenols, no tars.
16
75 T/D pilot plant
data.  Analyses
reported by
Carnegie-Mellon team.
Three coal feeds.
Contaminants related
to coal quantities.
 co2
 Acceptor
Gasification.
No p/o/t.
          Samples from 40 T/D
          pilot plant.
          Carnegie-Mellon team
          and Radian to report
          more (Radian work was
          for CONOCO).
 Koppers-
 Totzek
 Gasification,
 No p/o/t.
           Good commercial data,
           Organic contaminants
           low due to high
           temperature.
                             184

-------
U-Gas
Gasification,
No p/o/t.
         Inadequate analysis.
COED
SHC
SYNTHOIL
Liquefaction
Liquefaction
Liquefaction
8
Analyses indicative,
but not adequate.

Pilot plant operation
Samples from full-
scale treating sys-
tem. More analyses
are expected to be
forthcoming.

More analyses are
available, but all
are from bench scale
operation.
Coal Pile Run-off and
Ash Pond Water
                      13
DOE/MERC
H-Coal
Gasification.
P/o/t Producer,
Liquefaction
         Coal-fired power
         plant data.

         Good data from pres-
          surized  Wellman-
         Galusha process.

         Good analytical  data
         from bench scale.
         Treating information
         available.
                             185

-------
 GFERC*       Gasification.         1+       Fairly good data.
              P/o/t Producer.                Carnegie-Mellon team
                                            providing more data
                                            plus  treating infor-
                                            mation.  Soon to be
                                            published.  Process
                                            similar to Lurgi
                                            Slagging Ash.
The above are  indicative of the licensors and developers who have
published water  analysis data.  More is expected,  especially from
the Carnegie-Mellon project  sponsored by DOE/AGA  for  high Btu
gasification processes.  Exxon is said to have acquired  good data
for their Donor  Solvent Process  and the probability  for  future
publication appears to be good.   We expect  that more  SRC data
will be published.  Data from proprietary processes  and  from low
Btu gasification processes were not  available  in time  for
consideration  in this project.   Pilot plants  near  to operation
(e.g.,  Bi-Gas  and Battelle) were expected to publish useful data
within  our project  time frame, but publication was delayed.

In TABLE 8-1,  entitled "Representative Water Analyses",  are shown
the best of the  water analyses which have been located.

Water Analysis Data Gaps
Among the analyses  not located are those from processes  now being
considered for large scale demonstration plants.  These include
COGAS,  which is  an extension  of the COED liquefaction work to
gasify  the char to make hydrogen for  the liquefaction,  and
BCC/Lurgi (Slagging Ash).   Both  of  these were developed  by

* Grand Forks  Energy Research Center/DOE.

                             186

-------
                                                                              TABLE H-l.  REPRESENTATIVE WATER ANALYSES
H
03
Kopprrs-
Totzck CO,, Acceptor
Stream
Datn Source
Reference (1)

ROD imj/1
COO
TSS
TUS
pll
Phnnol s
Ammon io
Cyanide
Thiocyjnnte
Chloride
Nitrate
Phosphate
Sol fide
Su) f ite
SuUate
Total S
Carbonate (2)
Alkalinity (3)
Hnrdness
Fatty Acid (as Acetic)
Oil
Tar
Fixrd Solids
Total N (K)eldahl)
Trace Elements Reported
Total Oxyqen Demand
Coals Included (4)
Quench
Scrubber Quench Scrubber
Comm.
36,115
Average

128
5084
831
8.5
0.01
184
12.5

96
13.7
1.21
0

155


650
630

0
0


Limited

1
(1) Pullman Kellogq reference file
(2) As Ca.CC" except Lurqi, which
Pilot Plant
342
Range

120-300
1290-4825
426-1210
7.7-8.7
<0. 001-0. 05
11HO-1505
0.02 «•

42-70
0.03-0.07
3.1-11 .4
'0, 01-04.1
10.7-33.3
56-335

400-1998

240-2000







2
number s
is as CO,
(3) As CaCO except Rynthane, which is as ftco,
Lurgi which is HCO
as CO


Ave.

173
2705
748
8.2
0.02
1312
0.02

Sf,
0.05
6. 1
28.4
IB.'J
150

1200

880

0
0


Yes



and

Synthane
Ganlfinr Conelonsate
Bench Scale
36,230
Range Ave .

170O-430OO 22600
23-600 151

7.9-9.3 8.8
200-6600 . 3500
2500-11000 8050
0.1-0.6 0.4
21-188 101
500





1400
6000
HCO, 11000



Present


Yes

2,3,4,5,6,10



HyGas .
Gasifier Condensate
Pilot Plant
342
Range Ave .


20-52 35
1352-2168 1782
7. 1.3 7.9
I1 -2680 2055
29HO-5000 4170
< 0.001 CO. 001
270-780 510



120-138 127











Yes

7
(4) 1 - Unknown
2 - N.D. Lignite
3 - Wyo. Subbit.
4 - 111. Liqnite
Lurgi Dry Ash
SW
Tar Recycle
Scrubber Oil Separator Process
Comm. Commercial Pilot PI.
143 141
Ave. Ranqo
7200 5200-1S200
13000 7500-20800

18SO
H.S 8.2-9.8
3100 1900-4HOO
13000 13970-17650
8 4-14
260 16-193
266 30-210





506 265-J030
6000 6550-33930
11 000 (HCO, as CO,)
3 2
560

21000 500-2200


No

6,8,9,10
5 - w. Ky.
6 - Pittsbdrg Se^ro
7 - Mont. Liqnite
8 - Rosebud
480
Ave. Ave.
SHOO 32500
.12950 4300Q


8.6
3233 5000
15090 7900
ft 10
139
116


10500


804
19250




1228

8300
No Yes

11,12
9 - J 1 1 . No . 5
10 - 111. No . 6
11 - Ky. NO. 9
12 - Ky. No. 14
H-Coal
Liquefac.
Condensate
Bench
r,7n
Ave.
52700
£8600
2
5300
9.5
6BOO
144UO
(3.7)




29300







6 on

330

Yes
13200
10




-------
private funds  and only recently  are being funded  by DOE.  Nothing
has been  published  on  the emissions or sour water from  these
processes  to  date,  but it is known that treating systems  are
being currently designed.

Missing analyses which would be  most helpful  would include  those
before and after stripping out C02, H2S,and NH3.  Analysis should
always include BOD, COD, all anions and cations, fixed  solids,
alkalinity, TDS,  total  nitrogen (Kjeldahl)  , cyanide, cyanate,
TSS,  phenols, pH,  sulfides,  sulfates,  TOD, NH3-N,  N03-N ,
hardness,  oil, tar, and grease.  As can be seen  from TABLE 8-1,
many of the investigators omit some of these  important  analyses.
Water  treating vendors must have all these analyses in order to
make reasonable  judgments in estimating efficiency  of  their
processes.  If they are to actually design and guarantee treating
systems they insist on samples for bench scale tests in their own
laboratories and, in  some cases, pilot plant  trials of  their
equipment  on the stream(s) to be treated.

A word should be included on the limitations  of  some  of  the
analytical methods.   For  instance,  there has  always been
controversy over  the BOD  analysis.   Certain  interfering
substances must be removed or suppressed if  this analysis  is to
represent  the amount  that is  biodegradable in an  activated sludge
system.  The five day  BOD analysis may  not be sufficiently
accurate and it  is  possible that twenty day analyses  should
always be  used.  Further,  investigation is required to  determine
whether TOC or TOD analyses should be adopted instead of  the  BOD
analysis.

Cyanide analyses are  said to be  subject to interference  from
polysulfides.  Phenol  analyses do not include all the phenol
forms  (e.g. para-cresol)  and gas-liquid chromatography,  which
yields more accurate  results, is not widely  used.  Presence of
                            188

-------
oil,  tar,and grease interferes- with  several  analyses  and
reporting of oils has been spotty.   Soluble and  insoluble oils
exist but have not been reported to any extent.
Our study does not consider treatment of non-aqueous  liquids such
as the oils and tars from gasification processes  and  the naphtha,
distillate and fuel oil from liquefaction processes.   Since all
these contain sulfur compounds  and  phenols,  for  automotive use
these would have to be removed by extraction, hydrodesulfuriza-
tion,or hydrogenation and for  heavy fuel oil usage the  sulfur
would have to be reduced to 0.3  to  0.5 percent.   The treatment
procedures are considered to be beyond the scope  of this project.

References—

1.   Massey, M.J.,  Dunlap, R.W. , and Luthy, R.G.   Environmental
   Assessment in the ERDA Coal Gasification Development Program.
   ERDA Contract No.  E(49-l8) 2496.  1977.    699*

2.  Symposium Proceedings:  Environmental Aspects of Fuel  Conver-
   sion Technology.  May 1974, St.   Louis,  Missouri.   EPA-650/2-
   74-118.  1974.                               36*

3.  Woodall-Duckham Ltd.  Trials  of American  Coals in a Lurgi*
   Gasifier, Westfield, Scotland. ERDA & AGA, FE-105. 1974. 143

4.  Symposium Proceedings:  Environmental Aspects of Fuel  Conver-
   sion Technology, II.  Hollywood, Florida,  1975.   EPA 600/2-
   76-149, 1976.                                  230*
"Pullman  Kellogg Reference number
                            189

-------
5.   Massey,  M.J., Dunlap, R.W., and McMichael, W.J.,  "Characteriza-
     tion of Effluents  from the Hygas and  C0_  Acceptor Pilot
     Plants." Interim Report to ERDA  Contract No.  E(49-l8)-2496,
     FE-2496-1.  1976.                    342*

6.   Davis, G.M., Koon, J.H.,  and  Reap, E.J.  "Treatment Investiga-
     tions and Process Design for the  H-Coal  Liquefaction Waste-
     water." Aware, Inc.  for Ashland  Oil  Co.  1976.678*

7.   Forney, A., Haynes, W., Gasior,  S., Johnson, G.,  and Strakey, J.
     "Analysis of Tars, Chars, Gases,  and  Water Found  in Efflu-
     ents from the Synthane Process."  PERC-ERDA.  1975.384*

8.   Attari, A.  Fate of Trace Constituents of Coal During Gasi-
     fication.  IGT.  PB 223-001.  1973.384*

9.   McMichael, W., Forney, A., Haynes,  W., Strakey, J., and Gasior,
     S., "Synthane Gasifier Effluent  Streams." PERC-ERDA.  1972.
                                                     503*

10.  Sinor, J.   Evaluation of  Background Data Relating to  New
     Source  Performance  Standards  for Lurgi Gasification.
     EPA-600/7-77-057.  1977.552*

11.  Environmental Assessment of the  Hygas Process.  Monthly  and
     Quarterly  Reports,  July  1976  - June 1977.   IGT-ERDA.
     FE-2433.                                        591*
                             190

-------
 12.  Goldstein,  D.J.,  and Yung, D.,  "Water Conservation and Pollution
     Control in  Coal  Conversion Processes."  Water Purification
     Assoc.   EPA-600/7-77-065,  1977.            480*

 13.  Moore,  A.,  "Cleaning  Producer Gas  from MERC Gasifier."  MERC/
     ERDA.   BOM  RI-7644.   TPR 77.  1974.   Pressurized Wellman-
     Galusha.616*

 14.  Glazer, F., et  al.,"Emissions from Processes Producing  Clean
     Fuel."  Booz-Allen-Hamilton.  1974.  Koppers-Totzek.315*

 LITERATURE SURVEY  AND INFORMATION GATHERING

 The modus  operand!  of  the project literature survey has  been
 previously described in  Section 5 under the headings "Information
 Procurement, Storage and Re'rieval" and "Subjects Monitored".

 For water treating,  several publications were monitored  which
 apply specifically to this subject,  including "Journal of the
 Water Pollution  Control  Federation", "Environmental Science and
 Technology", "Water and  Wastes Engineering", and "Industrial
 Water Engineering".   Franklin Institute monitors 4,000 publica-
 tions for EPA and  publishes annually  abstracts from  these that
 concern municipal  water  treating systems.

 A number of pertinent articles were found  during a  survey of the
 collection of water treating literature compiled by the Pullman
'Kellogg Chemical Engineering Development Division.  Textbooks on
 coal technology  and water treating were acquired or were used at
 the Pullman Kellogg Research Library.   These  were supplemented by
 brochures from water treating process  and  equipment vendors.
                              191

-------
The lag in  obtaining reports through NTIS  was considerably
reduced by  personal contacts with Oak  Ridge National Library
(which publishes DOE reports)  or  with  authors  of DOE reports and
their DOE  project officers.  DOE  reports  are of prime interest,
since most of  the pilot plant work in  progress on coal conversion
processes  is sponsored, at least  partially,  by DOE funding.   Most
of these reports concern progress in operability of the various
processes  and  contain process information  with generally small
emphasis on  analysis or treatment of the  wastewater streams.

As mentioned in Section 5, conceptual  designs  prepared for  many
of the leading processes were collected for  study, especially  of
the water  quantities involved and the  treating systems applied  to
reduce contaminants.

Personal Contacts, Trips,and Meetings  by  the Water Group

In Section 5 a partial list of contacts and  meetings attended was
presented.  In the  list that follows are  shown those contacts
that yielded water analyses or water treating  information.

     Two  personal  visits with Carnegie-Mellon  University
     representatives regarding their work on an AGA/DOE contract
     for  high Btu  processes (Mike  Massey, Dick  Luthy, Bob
     Dunlap),  supplemented by a  number  of telephone contacts,
     correspondence  and exchange  of reports.

     The Pittsburgh  Energy Research Center (PERC) at Bruceton,
     Pa. was visited and the Synthane  and Synthoil pilot plants
     were  inspected.   Personnel contacted were Ralph  Scott,
     Richard Santore, James Mulvihill, Lloyd Lorenzi, Tom Torkos,
     and Dr. Sayeed  Akhtar.  Several reports were acquired at the
     time  and  later  by telephone  contacts with W. P. Haynes and
     Glenn Johnson.
                            192

-------
    Through Don Larsen  and  Robert Culbertson  of Dravo Corp. we
    were permitted  to visit  the  Bi-Gas pilot  plant  at  Homer
    City,  Pa.   and talk  to Bob  Grace  of  Bituminous  Coal
    Research.

    Contacts and correspondence with Russell Perrussel of the
    Pittsburgh & Midway Coal  Mining Co. resulted in our visiting
    the 50  TPD SRC  pilot  plant at Fort Lewis, Washington and
    discussing the water treatment system in operation there.

A number of  contacts  were made  with licensors and vendors through
attendance at the Water  Pollution Control Federation Conference
in Philadelphia, October 2-6,  1977.

Telephone contacts (TC),  correspondence (C) and personal meetings
(PM) were held with the  following:

    o  Hygas-Lou Anastasia  (TC)
    o  COGAS  Development  Co.  -  L.D.   Friedman,  Ralph Bloom
       (TC)
    o  Illinois Coal Gasification Group - Richard McCrary   (TC,
       c>
    o  H-Coal, (HRI) -  John Kumesh  (C),  Raymond Shutta,  S.L.
       Morris (TC)
    o  Bi-Gas (Stearns-Roger)  E.B. Warnock (TC)
    o  Argonne National Laboratory -  Shern-Yann  Chiu (PM)
    o  DDE-Washington,  D.C. -  John Nardella (TC, C)
    o  Arthur G. McKee  Co.  -  Dr. Parsons (TC)
    o  Davy Powergas,  Lakeland, Fla.  - I.  Marten (TC)
    o  Chevron Research Co.  - J.D. Knapp  (TC,  C) supplied  cost
       data on wastewater  stripping
    o  George A. Hormel & Co.,  Minnesota- (TC,  C) on  cost
       information on rotating disc contactors
                            193

-------
     o  Calgon Environmental  Systems Division, Houston -  Janet
        Thomas (TC, C)  on  design and cost information on granular
        carbon clean-up
     o  Infilco  Degremont, Inc.,  Richmond,  Va. -  Charles
        Thornborg,  Paul Blue  (TC,  C)  on design and  cost
        information on  biological systems,  filters, ozonation,
        etc.
     o  Zimpro,  Inc, Rothschild,  Wis.  -  Claude Ellis (TC,  C)
        supplied design and  cost information on PACT  (Powdered
        Activated Carbon Treatment) and Wet Air  Oxidation
     o  Dupont, Wilmington, Del. - F.L. Robertaccio  (TC) referred
        us to Zimpro, Inc. on PACT
     o  Union Carbide,  Houston  R. W. Oeben (TC,C) on design  and
        cost information on UNOX and ozonation
     o  L-A  Water Treatment, division  of Chromalloy - Robert
        McCharen,  Houston representative and  Mike Brunelle of
        California office (TC, C, PM) supplied  design  and cost
        information on  ion exchange, reverse osmosis,  lime  and
        zeolite softening,and BFW deaerators.  Above were for raw
        water treating  but use of wastewater also discussed.
     o  American Lurgi, Hasbrouck Heights, N.J.  Adam Warsh (TC,
        C) on design and cost information on Phenosolvan  process
        to extract phenols.
     o  Betz Co.  -  Don Reed, Houston (TC,  C,  PM)  on  necessary
        treatment  and  cost  to use wastewater  as cooling  tower
        make-up.
     o  U.  S.  Steel, Pittsburgh,  Pa. - R.D.  Rice (TC,  C)  on
        design and cost of the Phosam-W process.
TARGET  POLLUTANT RESIDUALS

In the  discussions with water  treating licensors  and vendors, the
summary of most stringent  water regulations,  as developed by
                            194

-------
Pullman Kellogg,  for discharge to a receiving body of water was
always  included.  In  addition,  the  generally less  stringent
requirements  for  water reuse as cooling  tower makeup or as  boiler
feedwater for high  pressure (1,450 psig)  steam systems or lower
pressure (150-600 psig) steam systems  were supplied.  Obviously,
there  are  other  water uses such  as  fire  water, ash  or slag
quenching,  revegetation of piles of ash  or  slag or mine refuse,
and  dust control which do not  require  high quality  water if
leaching to ground  water is properly  prevented by the drainage
systems.  With the  exception of ash/slag  quenching, storm water
run-off from "clean"  (non-process)  areas  may be utilized for
these  purposes.   This water would be  impounded and generally
worked back into  the coal conversion  plant  as a substitute for
raw water if  the  quantity is in  excess  of  the uses for revege-
tation and  fire water.  In some areas  evaporation would account
for a substantial part of th^ work-off of the storm water.

Most licensors, vendors, and process developers of water treating
technology take  the attitude  that total  water  reuse  is the
desirable  route, since the environmental  standards for water
discharge  are so stringent that  such  water would probably be
better  than  any  raw water  makeup  supplies  available.
Nevertheless, licensors,and vendors have  been asked to state
whether they could meet  the  most  stringent standards for
discharge and the costs involved.   The general reply has  been
that this could not be determined without receiving samples for
treatment and experimentation.   All  stated that  they are  most
anxious to  receive  wastewater samples.  Pullman Kellogg was not
in a position to  supply such samples  in the shortened time for
this  project; however, the Department of Energy  is  in this
position and is  urged to proceed  with  contracts  which could
                            195

-------
result in the necessary  experimentation by licensors and vendors
by supplying them with  wastewater samples  or allowing them 'to
bring test equipment  directly  to  the various DOE pilot plants.

TABLE 8-2 shows the target  pollutant residuals that were used  in
discussions with the licen  ors and vendors. TABLE  8-3  lists
additional "most stringent"  state environmental requirements,
Federal Standards for coal  mining and cleaning and U.  S.  Public
Health Drinking Water Standards.  It is of interest to note  that
several state standards  are more stringent  than drinking water
standards, particularly  in  chlorides and nitrates.
There are non-numerical,  unusual, or abstract standards  in  the
laws of some states that  are noteworthy  because they could be
troublesome in obtaining discharge permits.  For example:
     Toxic Substances
     Unnatural sludge  and
       bottom deposits
     Floating debris
     Visible oil,  grease,or
       scum
     Substances harmful  or
       toxic to human, animal,
       plant, or aquatic life
     Taste, flavor

     Settleable solids
     Radioactivity
       (many states)
1/20 of 96-hour median toler-
ance limit (MTL) for persistent
toxicants to sensitive indige-
nous species (Tex.,  Okla.).

None
None

None
None
Not offensive or unpalatable
(Ind.)
None
Gross beta <_ 100 PCI/1
Radium 226 <_   1 PCI/1
Strontium 90 _< 2 PCI/1
Dissolved Alpha Emitters £ 3
PCI/1
                             196

-------
    TABLE  8-2.  TARGET POLLUTANT RESIDUALS FOR DISCHARGE WATER
  ITEM
Total  Dissolved
  Solids
Cyanide  (Free)
Total  Suspended
  Solids
Phenols
Ammonia
Biological
  Oxygen  Demand
Chemical  Oxygen
  Demand
Sulfate
pH
Alkalinity  (as
  CaC03)
Oil, Grease,  Tar
Chlorides
Copper
Iron
Chromium
Zinc

Nitrates
Phosphorus
Manganese
Arsenic
Barium
Beryllium
Boron
Cadmium
Fluorine
Lead
Mercury
Nickel
Selenium
Silver
                           EFFLUENT  STANDARD
MOST STRINGENT (STATE)     (Used  for Discussion)
            (In mg/1  unless  noted)
750 (India--.)
0.005 (Ohi  i
   1,000
   0.02
15-37                       37
0.001 (Va., Ohio, W. Va.)   0.005
0.15 (Kans.)                2.5-4.0
15-37 (111.)

125 (N. Mex)
250 (Wyo., Va., Mo.)
7.0-8.5 (Wash)

500 (Va.)
None visible
100 (W. Va.)
0.02 (Several)
0.3 (Ohio, N.  Mex.)
Total 0.01 (Ohio)
0.075 @ 80 hardness
(Ohio)
10 (Mo.,  N. Mex.)
0.05
0.05 (Ohio, others)
0.01 (Wyo., W. Va.)
0.5 (W. Va.)
0.5 (Mo.)
1.0 (several)
0.005 (Ohio)
1.0 (Okla., Ky.)
0.04 (Ohio)
0.0005  (Ohio,  111.)
0.8 (Mo.)
0.005 (Ohio)
0.001 (Ohio)
   30

   125
   600
   6-9
   5.0 (Hexane Soluble)
   250
   0.1
   0.3
Hex. 0.05 Tri 1.0
   0.1

   10  (as N)
   0.1
   0.1

   1.0

   1.0
   0.01

   0.05
   0.002
   1.0
   0.01
   0.05
                              197

-------
                              TABLE 8-3*  MISCELLANEOUS WATER STANDARDS
vo
CD
          ITEM
                              MOST STRINGENT
                                 (STATE)
                            FEDERAL
                         (Coal Mining)
                                            (In mg/1 unless noted)
                                as
Alkyl Benzene Sulfonate (ABS)
Arsenic
Chloride
Copper
Carbon Chloroform Extract (CCE)
Fluoride
Iron (Fe)
Manganese (Mn)
Nitrate (NO-)
Cyanide (CN7
Phenols
Sulfate (SO )
Total Dissolved Solids
Zinc (Zn)
Barium (Ba)
Cadmium (Cd)
Chromium (Hexavalent)
Lead (Pb)
Selenium (Se)
Silver (Ag)
Mercury (Hg)
Total Suspended Solids
Turbidity - Jackson Units
Color
Threshold Odor
Coliform Bacteria
Temperature Rise
Dissolved Oxygen
     0.5 (Wyo.)
     0.01 (Wyo., W. Va.)
     100. (W. Va)
     0.02 (several)
     0.15 (Va.)
     1.0 (OK.,  Ky.)
     0.3 (Ohio,  N. Mex.)
     0.05 (Ohio, others)
     10 (Mo., N. Mex.)
     0.005 (Ohio)
     0.001 (Va., Ohio)
     250 (Wyo.,  Va., Mo.)
     750 (Ind.)
   low as 0.075  (Ohio)
     0.5 (W.  Va.)
     0.005 (Ohio)
total Cr 0.001  (Ohio)
     0.04 (Ohio)
     0.005 (Ohio)
     0.001 (Ohio)
     0.0005 (Ohio, 111.)
                                     None -
                                     None -
                                     None -
                                     10/100
                                     2°F
                                     5-6
            10 (several)
            15 (Alaska)
            3 (Ky., others)
            ml (Idaho)
                                                               3.5
                                                               2.0
                                                               35
       1962
  Drinking Water
(U.S. Public Health)
   0.5
   0.01-0.05
   250
   1.0
   0.2
0.6-2.4* Temp, dependent
   0.3
   0.05
   250»
   0.01-
   0.001
   250
   500
   0.5
   1.0
   0.01
   0.05
   0.05
   0.01
   0.05
   0.002*

   1*-5 units
   15 units
   3 units
   1-U/100 ml
     •Interim Regulations  propose Nitrate  (as N) <10,  Others note  interim  (not  1962).

-------
     Nitrogen-mg/1  (Illinois)

     Uranium
     Residual  chlorine
     Total  dissolved  gas
     Accidental  spills  (IdaF

     Dilution  (several  states)

     Methylene blue active
       substances
     Anti-degradation (Va.)

     Foaming Agents (Ohio)
< 2.5 April-Oct.
<_ 4.0 other times
1 5.0 (Va., N. Hex.)
<. 0.5 mg/1
<_ 110$ of saturation (several)
Contain to prevent pollution
(notify department)
Not acceptable as treatment
substitute

_< 0.5 mg/1 (Va.)
"Water better than standards
maintained"
<. 0.5 mg/1
Effluent  limitations  established  for  refineries are difficult to
relate  to coal  conversion,  since  they are  expressed  in  terms of
pounds  of contaminant per 1,000barrels  of  feed stock.   However,
these are as  follows:
     BOD               3.1
     TSS               2.5
     COD              21.0
     Oil  &  Grease      0.9
     Phenolics         0.02
     Ammonia as N    3.0
     Sulfide         0.017
     Total Chromium  0.049
     Hexavalent Cr   0.0032
     pH              6-9
DEVELOPMENT  OF  THE  RECYCLE  PHILOSOPHY

Consideration  of the  number  of  effluent  streams from  coal
conversion processes,  the  flow  quantities  involved  and the levels
of contaminants in  these streams,  in  view of the  stringency of
                              199

-------
environmental  regulations concerning  release of effluents to
receiving bodies of water, led to several conclusions:

     o  Proven  technology appears to  be  available for treatment
        of conversion process effluent  streams for reduction of
        contaminants to  3  /els  required  by environmental
        standards for release of effluents to  receiving waters.

     o  The application of treatment  technology to the effluent
        streams from the conversion  processes on an individual
        basis leads to maximum capital  investment and operating
        costs for effluent treatment, maximum  raw water usage and
        maximum problems in disposal  of  the residual sludges  and
        inorganic salt concentrates from the treatment processes.
        All of  these effects eventually  contribute to increasing
        the manufacturing  costs  of  the conversion  process
        products.

     o  Problems in meeting environmental  regulations ,  both
        present and future, can  be avoided if there  are no
        effluents from the conversion processes, either by direct
        discharge or by percolation into subsurface waters.

A simple two-fold philosophy was evolved from  these conclusions:
Water treatment shall be considered as  a means of preparing  the
individual conversion process  effluent streams for recycle as
process water within the conversion process battery limits;  only
the irreducible minimum of water shall  be  released to receiving
bodies of waters.

Among the many  advantages associated  with  the amplification  and
application of  this philosophy the following may be cited:
                            200

-------
     o   Severity of water treatment  is  minimized,  since the
        treated  water must now  meet only  the standards for
        process  consumption,  instead of human (or  fauna and
        flora) consumption.

     o   Water treatment costs are minimized.

     o   Raw water usage is minimized.

     o   Problems associated with disposal  of water  treatment
        process residuals are minimized.

     o   Problems associated  with  meeting possible future, more
        stringent, environmental standards are  minimized.

There appear to  be  no disadvantages  in  adoption  of  this
philosophy.  Accordingly, water treatment methods for application
to conversion process  effluents are not considered individually
but rather as parts  of a complete  treatment scheme  with the
single objective of minimizing problems,  either environmental  or
economic.
COMMERCIAL WATER TREATMENT  METHODS

Commercial water treatment  methods are defined  as  those processes
that have been demonstrated in full scale applications.   These
methods are offered  by treatment process licensors and  by
treatment equipment vendors.

The commercial treatment processes that have been  investigated
and that  are considered  to  be applicable to  the treating
requirements in coal conversion processes are:
                           201

-------
      For Raw Water
    For Wastewater
(In general these processes
deal with inorganic consti-
tuents only.  Reverse os-
mosis is an exception.)

Chemical Precipitation
  (Softening)
Reverse Osmosis
Ion Exchange
Evaporation
Electrodialysis
(In general these processes deal
more with organic constituents
than with inorganic consti-
tuents, even though both are
present.)

Oil Separation
Phenol Extraction
Ammonia Recovery (including
   stripping)
Chemical Coagulation/Floc-
   culation
Flotation
Biological Oxidation
Filtration
Biological Oxidation Sludge
   Handling
Carbon Adsorption
Tertiary Treatment (includes
   disinfection and addition of
   ozone, chlorine, and hydrogen
   peroxide)
The individual  treatment processes are  presented in  a  general
format that includes:

     o  Description
     o  Capability, efficiency,and limitations
     o  Case histories
     o  Wastes  produced
     o  Cost data (Classical costs only.  Later in this section
        of the  report the attempt is made to bring all  costs to
                              .202

-------
        the same basis and year  so  that  comparisons on an equal
        basis are possible.)
    o    Possible problems
    o    Possible improvements
    o    References

It should be understood  that there may  be  an  overlap  in
applications of the treatment  processes, in that some of the raw
water  processes will be used on wastewater  when it is recycled
for reuse  in the process.

An excellent illustration of the  effects  of variations in raw
water quality on  treatment methods required  and on treatment
costs  is found in "Water Conservation  and  Pollution Control in
Coal Conversion Processes,"  D. J. Goldstein and David Yung  (Water
Purification Associates, Cambridge, Mass.),  EPA-600/7-77-065,
June 1977  (480*).  Selected  sites  in New Mexico,  North Dakota,
and Wyoming illustrate the wide variation  in raw water quality
and supply at probable locations for  coal  conversion plants.
Three types  of processes  were  investigated at  each  site:
liquefaction, gasification to  produce SNG,  and  gasification for
power  production.  Amortized capital costs  plus  operating costs
for total  plant water treatment varied  from as  low as $185 per
hour to  as high as $835 per  hour.   Highest cost was for electric
power  production in North Dakota and lowest  for  liquefaction in
New Mexico.  Additional references  will  be made to this report.

In most of the  treatment processes pH is  quite important and
adjustment of pH with acid,  alkali, or  CO   is  often necessary.
The importance of pH adjustment  and the  means of pH control are
discussed  in "Integrated Schemes  for  Wastewater Treatment" in
this section of the report.

•Kellogg file reference number
                            203

-------
Chemical Precipitation

The presence of calcium and  magnesium  salts  in  cooling and boiler
waters can produce scaling.   TABLES 8-4  and 8-5 show  limits on
the composition of circulati   cooling water.   Boiler water com-
position limits are shown  i   "ABLE  8-14 in the  description of ion
exchange processes.

Softening involves the  removal  of calcium and magnesium  salts by
the formation and removal  of insoluble precipitates.   Lime in-
duces softening as shown in  the following reactions  (3*):

     Ca(HC03)2 + Ca(OH)2 = 2CaC03  + 2H20
     Mg(HC03)2 + Ca(OH)2  = Mg(OH>2
     MgS04     + Ca(OH)2  = Mg(OH)2
Soda ash or phosphate may be added  to  remove  noncarbonate  calcium
hardness as shown in the following  reactions:

     CaS04  + Na2C03  = CaC(>3  + Ma2SO
     3CaS04  + 2Na3P04  =  Ca3(P04>2 + 3Na2SO

Lime-soda or lime-phosphate softening  may be used  either as  a
cold process or as a hot process.   The hot  process takes advan-
tage of the reduced  solubility of CaCO  at  higher  temperatures.

Capability,  Efficiency,  Limitations —
Generally,  the concentrations of  calcium  and magnesium in the
effluent of lime or  lime-soda softening will be  35  ppm each as
CaCCkj  equivalent.  Iron  will be reduced  to  less than  0.1 ppm and
C02 will be zero.
• Item 3 in the reference  list  for  this  description
                               204

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              TABLE  8-4.   OPERATION CONSTRAINTS FOR
                  RECIRCULATING WATER QUALITY*
Characteristic

Calcium Carbonate
    Constraint
    Remarks
Calcium Phosphate
Calcium Sulfate



Silica

Magnesium & Silica

Suspended Solids

Chloride
Langelier Saturation
Index = 0.0 to 1.0
Ryznar Stability Index
  =  6.0 to 7.0
                        =  0.06
            = 577'°°°
         (csio2> - 8'540
C   = 400
 ss
Langelier Satura-
tion Index = pH -
PH
Ryznar Stability
Index = 2pH  - pH
(pH=measurea pH
pH =pH at satura-
tiSn with CaCO3)

GC  = concentra-
tion of Ca in mg/1
as Ca
CD_  = concentra-
 P04
tion of PO. in mg/1
as P04
 SO. = concentra-
tion of SO. in mg/1
as PO
Csio2 in mg/1
CMg in mg/1

Css in mg/1
C   = 3,000              C , in mg/1
(For Stainless Steel only)UJ- as Cl
 •From Item  6  in  reference  list
                               205

-------
          TABLE 8-5.   CONTROL LIMITS FOR COOLING TOWER
                 CIRCULATING WATER COMPOSITION
                       Conventional at
                           low pH»
PH
Suspended Solids (mg/1)
Ca x C03 (as CaC03>
Carbonates (mg/1)
Bicarbonates (mg/1)
Silica (mg/1)
Mg x Si02 (mg/1)
Ca x S04 (as
Chlorides***
NH3 (mg/1)
6.5 to 7.5
200 - 400
 1,200
   5
 50 - 150
 150
35,000
1.5 x 10* to
2.5 x 10
                Suggested at high pH
                with high concentration
                and dispersants*	
    7.5 to 8.5
    300 - 400
     6,000**
        5
    300 - 400
    150 - 200
    60,000
2.5 x JO6  to
8 x 10*
"*From Grits and Glover, "Cooling Tower Slowdown in Cooling
     Towers", Water & Wastes Eng., April 1975
**   More data neded to confirm (footnote from reference above)
***  The chloride limit has been reported as low as 100 mg/1 and
     as high as 3000 mg/1
                              206

-------
Other  metals may be precipitated as shown in the following list.
The presence of other ions may  reduce the  removal  efficiencies
reported.
     Aluminum

     Antimony
     Arsenic

     Barium

     Cadmium

     Chromium


     Copper
     Lead
     Manganese

     Mercury

     Nickel
     Phosphorus
      Selenium

      Silver
Precipitates as the hydroxide  at  pH  5.5-7.
Halides may cause problems.
90$ removal by lime coagulation.
Ferric hydroxide flocculation  yields £0.05
mg/1 arsenic levels.
Ferric and sodium sulfate at  pH 6.0 produces
precipitation to 0.03-0.27 mg/1 levels.
Ferric hydroxide at pH  10 precipitates to
levels of 0.1 mg/1.
Lime precipitates trivalent  chromium at pH
8.5-9.5.   Solubility  of the  trivalent
chromium is <0.1 mg/1.
Lime precipitation at pH 8.5-9.5 produces an
effluent  of 0.5 mg/1.  Cyanide and ammonia
may interfere.
Lime precipitation will remove lead.
Significant  removal is achieved above pH 9.4
by lime precipitation.
Na2S  and  NaHS  precipitate mercury  as  HgS.
H2S generation is  avoided at pH 10.
Lime  precipitation  removes nickel.
 <0.1  mg/1  in the effluent  can  be produced by
 two stage lime precipitation  at  pH 11.
 Single stage units  produce effluents  of <2
mg/1.
 Removal may be accomplished by reduction to
 the insoluble elemental  form.
 Precipitation with other metal hydroxides  in
 alkaline  conditions gives <0.1 mg/1 efflu-
 ents.
                              207

-------
     Zinc         -  Lime precipitation reduces effluent con-
                    centrations to <1 mg/1.

More data are shown in TABLES  8-6, 8-7, 8-8, 8-9,  and 8-10.

Case Histories--
Lime softening has been used for years to soften water for cool-
ing towers and as  partial treatment for boiler feed water makeup.
Lime addition is also  used  to  adjust pH and induce precipitation
of dissolved solids.   Ferric .salts are also commonly used to  aid
metal precipitation.   Other additives for flocculation,  etc.  are
discussed later in "Coagulation and Floccuation".

Wastes Produced—
The wastes  produced  by lime  softening  are  the precipitated
sludges.  Softening  sludges may contain calcium carbonate, magne-
sium carbonates and  hydroxides, and calcium phosphates.

When other metals  are  removed  by  precipitation,  sludges of  the
various metal hydroxides will  be formed.  If coagulation aids  are
used, these will be  included in the sludges.

The waste sludges  will contain between 0.5  and  5 percent sus-
pended  solids which  can be concentrated  to  10  to 15  percent
solids by hydraulic  thickeners.  Filtration,  centrifugation, and
evaporation may be used to  further dewater sludges.  Oily sludges
that cannot be de-oiled economically may be incinerated.

Possible Problems—
The presence of ammonia and cyanides inhibits  the precipitation
of some metals.  Since precipitation of  the  individual metals
usually occurs at  varying pH's, the optimum pH for metals removal
                               208

-------
         TABLE 8-6.   REMOVAL  OF  HEAVY  METALS  BY  LIME
          COAGULATION,  SETTLING  AND  RECARBONATION*
            Concentration Range (mg/1)            Removed
Metal
Ag
As
Ba
Cd
Co
Cr+6
Cu
Hg
Mn
Ni
Pb
Zn
Influent
0.
7.
0.
0.
0.
0.
0.
3.
1.
0.
0.
7.
24-
1
00-8
36-
54-
42-
45-
60-
26-
37-
75-
41-
34-
1
5
1
1
1
4
2
1
1
9
.51
.40
.08
.78
.29
.40
.47
.45
.26
.36
.21
.61
Effluent (%)
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
01-0.
20-0.
04-0.
01-0.
04-0.
30-1.
04-0.
29-0.
01-0.
11-0.
04-0.
12-0.
02
30
14
19
09
25
23
61
02
20
05
18
96-99
96-97
87-89
95-99
90-96
11-33
84-93
86-91
99
85
90-96
97-99
*From:   Argaman, Yerachmiel,and Clark L. Weddle, " The Fate of
Heavy Metals in Physical-Chemical Treatment Processes," pre-
sented at the 75th National AIChE Meeting  (June  1973)
                              209

-------
                     TABLE 8-7.  REMOVAL OF HEAVY METALS BY
                         LIME COAGULATION AND SETTLING*

Descrip .
Metal
Ag
+5
As
Ba
to
H Cd
o
Co
4-f\
Cr
Cu
Mn
Ni
Pb
Zn

Pilot Plant
% removal
M.

—
35

0

0

87
75
83
49
45
85
Bench
Pilot Plant Lab.
mg/1 % rem. mg/1
0.05 97

23.0
— — _

0.016 95

12.0

0.05 9 3.0
15.0
_
16.0
17.0
17.0
Scale Industrial Wastes
Tests Plant
%rem. mg/1 % removal
_ _ ~

54
_ _ —

_ _ >

89

0 7630** 99.9
79 15700 99.9
_
63 183 99.9
97
97 7900 99.9

Pilot
mg/1
0.013

—
0.43

—

-

0.17
0. 14
0,33
0.015
0. 13
—

Plant
% rem.
85

— '
100

—

-

59
64
94
67
100
—
* From Item 4 in reference list
**Cr+J
  NOTE:  Concentrations shown are in the influent wastewater

-------
     TABLE  8-8.  METALS  IN  SOLUTION  AFTER  LIME  COAGULATION*
         Calculated Maximum    	Experimental
etal
Ag
Ba
Cd
Co
Cu
Mn
Ni
Pb
Zn
pH 11.5
0.007
0.02
0.002
0.002
0.06
0.003
0.02
1.6xlO~5
1.60
pH 9.6
0.007
0.02
1.42
0.06
0.001
5.50
0.74
5xlO"5
0.007
Run 1
0.01
0.04
0.01
0.04
0.04
0.02
0.11
0.04
0.12
Run 2
0.02
0.14
0.02
0.05
0.23
0.001
0.20
0.05
0.18
Run 3 Run 4
0.06
0.06
0.19 0.19
1.58
0.32 0.31
1.27
1.27
0.25
1.58
Run 5
-
-
0.13
-
0.20
-
-
-
™
*From Item 4 in reference list
 HOTE:   All concentrations in mg/1 as the metal
                              211

-------
                                               TAHLE 8-9.  REMOVAL OF IIEAVt  METAI.S  BV

                                             FF.HSIC ClltORIDE COACULAT1PN AND SETTLING*
NJ
H
NJ



*6
As
Ba
Cd
Co
Cr
Cu
HR
Mo
Nl
Pb
Zn
Run
In

o.ot
..
0.04
0.01
0.04
0.30
0.04
_
0.02
0.11
0.04
0.12
1
Out

0.01
_
0.03
0.01
0.017
0.07
0.03
•
0.02
0.09
0.04
0.13
Run 2
*
Ren.
.
_
25
m
58
72
2}
_
^
18
_
-
In

0.02
-
0,14
0.02
0.05
1.2S
0,2}
_
.0.01
0.20
0.05
0. 18
Out

0.01
_
0.07
0.01
0.02
0.63
0.02
.
0.01
0. 15
0.023
0.04
Z
(tern.
50
-
50
50
60
50
56
_
_
25
54
78
Run 3
In

0.06
-
0.06
0.19
1.58
2.53
0.32
_
1.27
1.27
0.25
1.58
Out

0.02
-
0.09
0.01
0.49
0.65
0.29
.
0.19
0.66
0.12
0.53
X
Ren.
67
-
_
95
69
If
9
-
85
48
52
66
Run 4 Run 5 Run 6
In Out X In Out X In
Ken. Ren.
_ ... J.30
O.JO 0.01 97 0.20 0,01 95
2.30
0.19 0,04 79 0.13 0.03 77 3-9°
3.30
. ' - - 6.60
0.31 0,32 - 0.20 0.23 - I-*0
0.61 0.28 54 0.29 0.03 90
3,90
4.60
2.30
_ ... 9.90
Out

0.09
-
0.23
0.29
HO
3.40
0.17
—
2.30
1.10
0.23
1.0
I
Rcm.
97
~
90
92
58
48
87
™
41
76
90
90
       *Frora  Item  4  In reference list
        NOTE;   In  and  out concentration* In ng/1

-------
             TABLE  8-10.   METALS IN SOLUTION AFTER
                 FeCl3  COAGULATION.   RUN 6.»

Metal
Ag
Ba
Cd
Co
Cu
Mn
Ni
Zn
Calculated Max.
at pH 8.6
0.007
0.02
142
6.0
0.1
550
74
0.07
Experimental
Run 6
0.09
0.23
0.29
1.40
0.17
2.30
1.10
1.0
*From Item 4  in reference list
 NOTE:   All concentrations in mg/1 as the metal
                               213

-------
must be  determined  for each  of  the chemical precipitation
systems.

References—

1.   "Development Document  for  Effluent Limitations Guidelines
     and  New Source Performance Standards  for  the Steam Electric
     Power Generating Point Source  Category",  USEPA 440/1-74
     029a, October 1974. *6?6

2.   AWARE, Pretreatment of Industrial Wastewater for Discharge
     into Municipal Sewers, October 1, 1977.   *643

3.   Water Quality and Treatment,  American Water Works Assn.,
     Inc., Third Edition, 1971.

4.   "Water - 1973", AIChE, Argaman and Waddle, No. 136, Vol. 70,
     1974.

5.   "Water Conservation and Pollution Control in Coal Conversion
     Processes", Water Purification Assoc.,  EPA 600/7-77-065,
     June 1977.  «480

6.   "Optimal Water Reuse in Recirculating Cooling Water Systems
     for Steam Electric-Generating  Stations",  Chen, Y.S.,
     Petrillo, J.L., and Kaylor, F.B., Second  National Conference  on
     Complete Water Reuse,  Chicago, 1975.
•Kellogg Reference Number
                              214

-------
Reverse Osmosis (1)*

Reverse Osmosis is  a  process which utilizes  a semipermeable
membrane and a pressure differential  to separate relatively pure
water  from solutions containing salts, dissolved organics, and
colloids.   Water  is driven through the  membrane by  pressure
leaving behind a concentrated solution of  impurities.  In order to
achieve a separation, the driving  force pressure must  be greater
than the osmotic  pressure  of the  concentrated solution of
impurities.

Capability, Limitations, Efficiency—
Operating pressures for reverse osmosis  membranes and membrane
supports are limited.  Spiral wound  and  hollow fiber membranes
cannot withstand more than 600-800 psi.   Tubular membranes are
limited to about 1,000  psi.  Therefore, to allow for sufficient
driving force  for  the  separation, the osmotic pressure of the
concentrated solution generally cannot exceed 400 psi.

The membranes  are  limited with regard to  pH and  temperature, and
can be destroyed by high concentrations of chlorine  and  other
oxidizing agents.  For example, cellulose acetate membranes are
limited to a pH range of 5 to 8 and  to a  chlorine concentration
of 5 mg/1 for  15 minutes.  Polyamide  membranes are limited  to  a
pH range of 4  to 11 and chlorine  concentrations of 0.1 to  0.25
mg/1.  Both membranes  are limited to  a  maximum  operating
temperature of 95°F.  The solution cannot be  concentrated beyond
the solubility of  the least soluble  salt  in  solution, or fouling
and plugging will  occur.  TABLE  8-11  is a list of operational
* Numbers refer  to  the short list of pertinent  references  at  the
  end of this  description.
                              215

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   TABLE 8-11.  OPERATIONAL CONSTRAINTS FOR REVERSE OSMOSIS
Characteristics	
pH and Hardness

Suspended solids
Residual free chlorine
Total iron and manganese
Temperature
            Constraint
SiO.
CaS0
(Cs04)
Total dissolved
 Solids
            Function of makeup water quality:
            (1)  to control possible chemical deposits
            (2)  to achieve optimal membrane performance
               <10y in size - in feed water
               <0.1 mg/1    - in feed water
                            - in feed water
                            - in feed water
                            - in feed water
<0.3 mg/1
<95° F
>35° F
<200 mg/1
                             <3,077,000
            <20,000-
             40,000 mg/1
- in rejected brine with
  polyphosphate addition
- in rejected brine with
  polyphosphate addition
             - in rejected brine
  From Item 3 in reference list
                               216

-------
constraints for  reverse  osmosis..    When used  within  these
limitations, reverse osmosis  can  be an effective separation
process.  TABLES 8-12 and 8-13  show  some typical  ion and group
rejections that may be achieved by reverse osmosis.

Pertinent Case Histories—
Reverse  osmosis has been used successfully to produce  boiler feed
water  and potable water from brackish water, and  as a pretreat-
ment before  deionization.

Wastes Produced—
The primary  waste produced by reverse osmosis is the concentrated
solution of  impurities.  Another possible waste stream includes
the solids  from  a  pretreatment  filter.   Water  in  the  reject
stream can be high  (20 to 40 percent of the water treated).

Cost Data—
The following relation is given for determining capital cost  for
treatment of industrial wastes.

    C = 1.7 x 106  (Q)°-8
                   C = Capital Cost  (1975)
                   Q = Throughput, MGD (Million Gallons per Day)

However, some sources state  that  capital  cost is a  function of
impurity level and  not flow  rate.

Operating Cost—
The following operating  cost data is given for municipal waste
treatment units:
                             217

-------
  TABLE 8-12.  TYPICAL REJECTIONS BY REVERSE OSMOSIS MEMBRANES*
Species
Ca
  2+
Mg
NaH
  2+
Ni
  2+
Cr6+
Copper

F~
Cyanide
                                              Rejection (%)
                                                  99
                                                  99
                                                9U-96
                                                  98
                                                95-97
                                                > 99.5
                                                94-95
                                                  90
                                              (pH dependent)
                                                  30
                                                  99.9
                                                  25
                                                 0-60
                                              (pH dependent)
H BO
 3  3
Sugars
Formaldehyde
Phenol

Benzyl alcohol                                       0

Rejection =
  (concentration at membrane)-(concentration of product water)
                  concentration at membrane
* From Item 2 in reference list
                              218

-------
     TABLE 8»13.
TYPICAL SOLUTE REJECTION HIGH-SELECTIVITY
    CELLULOSE ACETATE MEMBRANES*
      Solute
                Percent Rejection
      Maximum       Minimum         Average
Calcium Ca2
Magnesium, Mg'2"1"
Sodium, Na
Potassium, K+
Iron, Fe2+ and Fe3+
Manganese, Mn2"1"
Aluminum, A13+
Chromium, Cr6++ pH 2.6
4.2
7.6
Ammonia, NH
Bicarbonate HCO,.-
Sulfate, SO 2-
Chloride, CI~
Nitrate, NO -
Fluoride, F*3
Boron (at pH5)
Silica (at pH5)
Orthophosphate, PO
Polyphosphate
Total dissolved solids
(TDS)
COD - secondary effluent
- sulfite liquor
BOD - secondary effluent
- sulfite liquor
Lignin sulfonates
Sucrose
Proteins
Phenol
Acetic acid
Glucose
Color
Turbidity
99.7
99.9
97
97
100
100
99.9



95

100
97
86
98
60
95
100
100

99
97
97.5
94
92.2
99.4







96.3
93
88
83
99.9

97.3



77

99
86
58
88
38
80



89
94
94.9
81
85.8
98.1







>99
>99

100
100
>99
92.6
97.2
98.6

80-98
>99





>99
>99







99.9
98 to 100
Rejection
Rejection
99.5
100
100
* From Item 1 in reference list
                               219

-------
$0.37
0.22
0.12
$0.36
0.21
0.19
$0.73
0.43
0.31
            Operating Cost [$  per  1000 gallons] (1975)
                                    Operating &
    Size (MGD)    Debt Service	  Maintenance Cost   Total
         1
        10
       100

Care should be taken when applying these  numbers, as  costs  are
dependent on the specific application.

Possible Problems—
Irreversible fouling is often  the  limiting factor on the membrane
life, caused by suspended solids in the  feed and precipitation of
salts.  Pretreatment with activated carbon, deep sand filtration,
and others may be used.  Addition  of acid or chelating agents may
prevent precipitation in some  applications.

The low tolerance of the reverse  osmosis  membranes to  chlorine
may represent a very real problem  when treating coal conversion
plant wastewater.

Possible Improvements—
Determination and  development of effective  reverse osmosis
pretreatment systems would be  helpful.   Development of  pretreat-
ment methods for removal of chlorine or  development of  chlorine
resistant membranes may also be  worthwhile.  Tests on actual coal
conversion streams are required to evaluate  the suitability of
reverse osmosis for this application.
                             220

-------
References

1.   "Innovative Technologies for Water Pollution Abatement" by
    Water Purification Asociates, Prepared for National  Commis-
    sion Water Quality, December  1975.  NTIS No.  PB-247 390.
    •612

2.   "Physico Chemical Processes for Water Quality Control," by
    Weber, Walter J.,  1972. (Published  by  Wiley-Interscience)
    pp. 310-329.

3.   "Optimal Water Reuse in Recirculating Cooling Water  Systems
    for  Steam Electric-Generating Stations" by Chen,  Y.S.,
    Petrillo, J. L., and Kaylor,  F.  B. , 2nd  National Conference
    on Complete Water Reuse, 1975,  Chicago.
    •Pullman  Kellogg Reference File Number
                             221

-------
Ion Exchange

Ion Exchange  is a process by which  ions in solution  are reversi-
bly exchanged with ions of an insoluble  substance  (generally a
solid).  No  significant change in the  structure  of the solid
takes place.  The  solids range in composition  from naturally
occurring green sands and bentonite clays  to  synthetic organic
resins and  inorganic compounds.

Ion exchange  can  be used for demineralizing  and purifying in-
dustrial wastewaters  for reuse or discharge,  purifying waste
liquors for reuse by removal and recovery of metals,  and demin-
eralization of raw  waters for  boiler water makeup.   The water
quality requirements for boiler  feed waters are  given in TABLE
8-14.

In ion exchange,  a  given species  of ion is displaced from the
exchange material by ions in solution.  The  exchange material
gradually loses  its activity and  must be  regenerated.  During
regeneration, the  original species of  ion is  replaced in the
exchange material  and  the  displaced  ions  are removed  as a
concentrated  waste solution.

In essence  ion exchange purifies the process stream by producing
a regenerant  waste stream concentrated with the removed ions.

Capability/Efficiency—
Ion exchange  may  remove cations, anions or both depending on the
exchange resins used.  Ion exchange may be used in water soften-
ing to replace Ca and  Mg ions  with Na ions.   Ion exchange may
also be used  to produce ultrapure water by replacing cations  with
hydrogen ions and  anions with  hydroxyl ions.   A water with a
conductivity  of  0.2 to 0.5 micro-mhos per  centimeter and 0.02 to 0.05
ppm SiO  can  be produced on a commercial  scale.
                             222

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                       TABLE 8-14.   GUIDELINES FOR WATER QUALITY
                        IN MODERN INDUSTRIAL WATER TUBE BOILERS
                            FOR RELIABLE CONTINUOUS OPERATION*
                                                                 Boiler Water
NJ
NJ
ui










1
1
urura
Pressure
(psig)


0 -300
301-450
451-600
601-750
751-900
901-1,000
,001^1,500
,501-2,000


Iron
(ppm Fe)
0. 100
0.050
0.030
0.025
0.020
0.020
0.010
0.010


Copper
(ppra Cu)
0.050
0.025
0.020
0.020
0.015
0.015
0.010
0.010

Total
Hardnes s
(pptn CaCO_)
0.300
0.300
0.200
0.200
0.100
0.050
0.000
0.000


Silica
(ppra Si02)
150
90
40
30
20
8
2
1

Total
Alkalinity***
(ppm CaCO_)
700**
600**
500**
400**
300**
200**
o****
o****

Specific
Conductance
(micromhos/ cm)
7,000
6, QUO
5,000
4,000
3,000
2,OOU
150
100
          *Frora  Item  6  in  reference  list.
         **Alkalinity not  to  exceed  10%  of  specific  conductance.
        ***Minimum  level of OH  alkalinity  in  boilers below 1000  psi must  be individually
           specified  with  regard  to  silica  solubility and  other  components  of  internal
           treatment.
       ****Zero  in  these cases  refers  to free sodium or  potassium hydroxide alkalinity.
           Some  small variable  amount  of total alkalinity  will be present  and  measurable
           with  the assumed congruent  control or  volatile  treatment employed at  these
           high  pressure ranges.

    Private  Communication;   Pu1Iman Kellogg  Source
     Maximum  60  ppb TDS,  20  ppb  Na,  20  ppb  Si02  in  saturated  steam,

-------
TABLE 8-15 shows the performance  of  ion exchange in different
applications on  the  same water.  Ion exchange may also be used to
remove phenols,  ammonia, and heavy  metals.   Anions are  removed
based on the following preference:

    S04~  >CNS~  >C104~ >I >N03~ >Cr04~ >Br~ >CN~ HS04~ >N02~ >C1~
    >HC03~ >CH3COO~  >.DH~ >F~

Ion exchange resins  have several limitations.   Cation  exchange
resins  cannot  withstand temperatures greater than 120-150°C.
Anion exchange  resins are limited to 30-60°C.   Strong oxidizing
agents,  including nitric acid,  chromic acid,  chloric acid,  and
hydrogen peroxide, will degrade the resins.  Iron, manganese,  and
copper in the presence of oxygen may slowly  degrade the  resins .
The resins will  become fouled  by precipitation or irreversible
adsorption  of  suspended  matter,  oils, and  other  dissolved
materials.

Rapid exposure  to alternating high  and low electrolyte concentra-
tions induces osmotic shocks resulting in resin breakage.  Remov-
al of a  given trace  element is not  possible without first  remov-
ing all  preferentially exchangable  ions.

Case Histories—
     o  Coke Oven Liquor—Coke oven liquor  was  treated  by acti-
        vated sludge and then ion exchanged.   The ion exchanger
        feed contained 1200-1300 mg/1  ammonia.   96-97/6   removal
        was  consistently achieved.   Ninety  percent thiocyanate
        removal  and  some color removal also  resulted.   Gel  type
                             224

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      TABLE 8-15.
WATER TREATMENT OF THE SAME RAW WATER
 BY DIFFERENT PROCESSES*
                         Raw
                        water   Softening
                       Partial   Full
                       desalin- desalin-
                        ation    ation
Total hardness,  °dh
Carbonate hardness,
                °dH
Noncarbonate hardness
                °dH
Bound HC03~, mg/1

S04", mg/1
Cl", mg/1
Si02, mg/1
Evaporation residue,
               mg/1
                          15
              0.1
  0.1
                           6
                         196

                          51
                         115
                           7
                         426
               196

                51
               115
                 7
               426
  5-10   5-10  0
mg/lC02 mg/l/C02
    51   0     0
   115   0     0
     7   7     traces
   273  nearly  prac-
        exclu-  tical-
        sively  ly 0
        Si02
•From Item 4 in reference list
                               225

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        resins  cracked but macro-reticular resins  did not.  Costs
        (1975)  were estimated for a 400,000 gpd  flow.   Installed
        cost  was $700,000 and included ion exchange,  neutraliza-
        tion  and  coagulation equipment.  Operating cost (less
        amortization) was $1.28/1,000 gal.of which $.94/1,000 gal,
        was for regeneration.

     o  Acid  Mine Drainage—Potable water was produced  from acid
        mine  drainage containing sulfuric acid and  ferrous and
        other ions.  The  (1975)  capital cost for a  500,000 gpd
        plant was $2,140,000.  Operating cost for  a 5 million gpd
        plant was $2.18/1,000 gal.  Amortization accounted for
        50 to 60%  of  the  operating cost.

Wastes Produced—
The primary waste  stream  produced in ion  exchange  is  the rege-
nerant waste  stream.  The quantity of regenerant is  a function of
resin  utilization.   Regenerant required can  be theoretically
calculated from anion and  cation analyses.  See Item 4 in the
reference list. The regenerant  chemicals vary from  NaCl  in water
softening to  HC1 and NaOH in  demineralization.   The  regenerant
waste contains, in addition to the desorbed ions from  the resin,
iron and manganese oxide  precipitates, silica,and  resin fines.

The other waste stream produced is the periodic spent ion ex-
change material when change-out  is required.

Cost Data—
Costs  are dependent on  the  application.  As  shown  in "Case
Histories", capital cost  of ion  exchange  for  acid mine drainage
was more than that for coke oven liquor.

Possible Problems—
Most problems in  ion  exchange are due to dirty or fouled beds or
improper regeneration.  Fouling  can be caused by suspended solids
                             226

-------
in the  feed,  precipitation of iron, manganese,  or copper oxides,
dissolved  organics,and silica.   Presence of these  materials in
ion exchange  feeds could produce problems.  Disposal of  regenera-
tion wastes could pose a disposal problem.

Use of  feed pretreatment units may be required.  Evaporators may
be needed  to  handle regenerant wastes.

One source indicates  that for  solids concentrations over 1,000
mg/1, economics  tend to favor reverse osmosis and electrodialysis
over ion exchange.  Some applications for over 500  mg/1 justify
reverse osmosis  pretreatment before ion exchange to  reduce  solids
feed for ion  exchange to 500 mg/1.

Possible Improvements—
Developments to reduce regenerant chemical  requirements are
desirable. Tests on wastewaters from coal conversion plants are
necessary  to  determine suitability of ion exchange.
References—

     1.   Innovative Technologies for Water Pollution Abatement.
         Water  Purification  Associates, National Commission on
         Water  Quality report.  PB-247 390, 1975.  «612.

     2.   Physicochemical Processes for Water Quality Control.
         Weber,  W. J., 1962.

     3.   Water  Quality  and Treatment.   American Water Works
         Association, Inc.   Third Edition.  1971.
                              227

-------
     4.  Ion Exchangers, Properties and Applications.   Dorfner,
         Konrad.   1972.

     5.  Manual  on Disposal of Refinery Wastes:  Volume  on  Liquid
         Wastes.   American Petroleum Institute.   1968.  *808

     6.  Feedwater  Quality in Modern  Industrial  Boilers  -  A
         Consensus of Proper Current Operating Practice.   Simon,
         D.  E.   Proceedings 36th International Water  Conference,
         Pittsburgh.  1975.
* Pullman Kellogg  reference number
                              228

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Evaporation

Evaporation may be used to separate water  and  nonvolatile solids.
Evaporation finds  application in  wastewater treatment,  boiler
feedwater treatment, and solids dewatering.

Several systems may be used in evaporation.  They are  1)  solar
evaporation ponds, 2) multiple effect evaporation, 3) multistage
flash evaporation, 4) vapor compressor evaporation, and  5)  oil
fluidized evaporation.  Oil fluidized evaporation  is discussed in
another section and will not be covered here.

Solar evaporation involves ponding the  water and  solids  and
allowing solar radiation to induce evaporation.  The  vaporized
water may be collected by covering the pond  with a clear glass or
plastic roof.  The evaporated water condenses  on the underside of
the roof and runs  down to a collection system.

Multiple effect evaporation is a fired evaporation system where
the heat required  for evaporation is reused.  See Figure 8-4.
The vaporized water is condensed against evaporating water that
is at a lower pressure.  This water vapor, in  turn, is  condensed
in another effect  causing more evaporation.   Many  effects  may be
used in a system  which optimizes operating costs and capital
costs.

Multi-stage flash evaporation  (see  Figure 8-5)  reduces  the
problem of fouling heat exchange surfaces,  a major  problem in
other fired evaporation systems.   Pressurized  water  is  heated to
just below the point  at which boiling occurs.  The hot water is
then depressured  in stages,  resulting in vaporization  of the
water.  The water vapor is  then condensed in the  feed preheat
exchangers.
                              229

-------
to

-------
                                        1st
                                       STAGE
 2nd
STAGE
 3rd
STAGE
NJ
U)
STEAM
WENSATE


<
<
<
4
4
4


FEED
HEATER
>
>
>
>P
f
1


™ A /> A Ar._,
fl' '» 6«^
//I 666^
( J FLASH
' ' VAPOR,
1 P^ ^
T,-




j /
yT^r
YX/
N )
1 <•!«;(



-*—
.;„_ A A A A...,
'A'1'1'1
- / V ^
^ i Sy
1^5 ^Tz.
1
HEATED
FEED





-AA/VA,-


PROOUCT
WATER
*— HEAT
EXCHANGER
CONCENTRATE

                Figure 8-5.  Multistage flash evaporation.*
                                                                                I
                                                                              WASTE
                                                                              FEED
                 *From Item 1 in reference list

-------
Vapor compression evaporates  and  recovers water by  the  use of
mechanical energy.  A vapor compression system  is shown in Figure
8-6.  The heat  required for evaporation is provided by compress-
ing steam formed  in the evaporator.  The temperature and pressure
are increased.  This steam is then condensed against water in the
evaporators to  produce more steam.

Capability/Efficiency/Limitations—
Evaporation systems are capable of handling  a wide  variety of
wastewaters and can concentrate the solids to virtually any level
desired.   However, evaporation is not to be used on wastewaters
containing volatile impurities.

Generally,  evaporation systems tend  to be  extremely  energy
intensive.  The exception is solar evaporation where  the  energy
source is free.  Solar evaporation has only limited application
when  distillate recovery is  desired.   Large  surface  area
requirements, on  the order of 10 to 12 square feet  per gallon per
day, result in  high capital costs.

Energy-wise, vapor compression evaporation is the most efficient
of the fired evaporation systems.  However, it  requires a higher
capital investment.  Vapor compression evaporation  can produce 27
to 40 Ibs.  distillate/1.000 Btu heat incut.

Multiple  effect evaporation can produce N Ib. distillate/1,000 Btu
where  N  is  the number of effects.   Energy efficiency  must be
balanced  against  capital cost  to produce  the  optimum number of
effects.   Some  rule of thumb  figures for  number of  effects are
given in  TABLE  8-16.

Multistage flash  evaporation generally makes N/3 Ibs.  distillate/
1,000 Btu where N is the number of stages.     Multistage  flash
systems require large recirculation rates to maintain  the energy
efficiency level.  Due to precipitation considerations,  multi-
                              232

-------
           COMPRESSOR
SUPERHEATED
VAPOR
P$v > I aim
T8tf > 212° T
    CONDENSATE  TSV>TC> 212" F

    w	^	__	
     CONCENTRATE 212° F
                                     SATURATED
                                     VAPOR
                             i  EVAPORATOR
                             •      I otm \  \
                             I [   212°  F   / f
                                HEATED FEED
                     •wvwvwvvw-
                      WWWVWWW
                                    CONCENTRATE
                                    PRODUCT WATER
          HEAT
          EXCHANGER
L
                             WASTE
                             FEED
    Figure 8-6.   Vapor  compression evaporator.*
    *From Item 1 in reference list
                       233

-------
    TABLE 8-16.  SOME PRESENT APPLICATIONS OF MULTIPLE EFFECT
                 EVAPORATION TO WASTE TREATMENT*
                                               Usual number
         Process                               of effects (N)
Metal finishing recycle and recovery                 1-2
Caustic soda concentration                            3
Concentration of cane sugar liquors                   4
Concentration of paper pulp waste                     6
Industrial or municipal salt water                   6-20


•From Item 1 in reference list
                             •234

-------
stage  flash evaporation is most efficient  on high flow, low IDS
applications.  The number of stages  for  sea water desalination
for 0.1  to 4 MGD (million gallons  per  day)  is is N = 19 + (Q),
where  N  = number of stages and  Q =  distillate  flow rates in MGD.
Sea water desalination plants can  currently produce  12  Ibs.
distillate/ 1,000  Btu.

One important limitation of  fired  evaporation systems is the
fouling  of heat exchange surfaces.   Multistage flash avoids this
problem  by using no exchanger surfaces  in  boiling service.  The
other methods require  the use  of antiprecipitant  agents,
injection of seed solutions which provide  alternate precipitation
sites, or operation at levels of concentration not exceeding the
solubility limit.   Therefore  heat  transfer coefficients  of
exchanger surfaces have an important  effect  on efficiency.

The temperature difference driving  force  is  often limited by the
solubility limit of the solids  in solution.

The use  of falling film heat exchangers  yields coefficients  of
 5,000 Btu per hour per square  foot per  degree Farenheit vs. 300
for conventional tube heat exchangers.

Case Histories—
Vapor compression evaporation has been  used  to concentrate  cool-
ing tower blowdowns.   Recovery of  purified water is 91  to  98
percent  from  feed  streams containing  1,500 to  10,500 mg/1 dis-
solved solids.

Evaporation has  been used  to  treat sea water,  plating bath
solution, sugar cane liquors, paper pulp  waste, and heavy  metal
wastewaters.
                              235

-------
Wastes Produced—
Evaporation  produces pure water and  a  concentrated solution  of
dissolved solids.  This concentrated  stream requires disposal  or
additional treatment.  Precipitation of solids may result  in a
solids disposal  problem.  Any precipitation inhibitors added will
appear in the  concentrate solution.   Some  manufacturers  offer
evaporators  with crystallizers to  facilitate  waste handling and
disposal.

Costs--
For streams  of 0.5 to 3.0 MOD, capital costs are around $2 per
gallon  per  day.  Operating  costs are shown in Figure 8-7 for
multistage flash units.

Vapor compression evaporation units  have lower operating  costs
and higher capital costs.  Solar evaporation (when used to pro-
duce purified  water) has capital costs of $10 to $25 per gallon
per  day if  provided with covers  and collection means for the
water (1).

Possible Problems—
The primary problem  with fired  evaporation systems  is  the high
energy  requirement.  Evaporation does not eliminate a  waste
stream but merely concentrates it.  The concentrated stream may
pose a disposal  problem.  Other problems are  fouling  and scaling,
especially when  high recoveries are desired.

References—
(All unreferenced material was taken from Reference 1.)

1.   "Innovative Technologies  for Water Pollution  Abatement,"
     Water Purification  Associates.  NTIS PB-2H7 390, Dec.   1975.
     •612
                             236

-------
K- />
to 2
O
O
                                            ni
                                            z
                                            PI


                                            o


                                          3^

                                            o
                                            o

                                            CD
                                            O
                                            o<
0
           THROUGHPUT (I06 GAL/DAY)
 Figure  8-7.   Cost and energy  for  multistage

               flash evaporation.*
 *From Item  2  in reference list
                 237

-------
 2.    "Water  Conservation  and  Pollution Control in Coal Conversion
      Processes," Water  Purification Associates, EPA 600/7-77-065,
      June  1977.
•Kellogg Reference Numbers
                              238

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Electrodialysis

Electrodialysis utilizes a DC electric  field and semipermeable
membranes  to remove ions from water.   An  electrodialysis unit  is
shown  in Figure 8-8.  A series of parallel membranes separated  by
channels  is used.   The parallel membranes alternate  in type
between cation-permeable membranes and anion-permeable membranes.
The electric  field  causes the  ions  to migrate toward  their
oppositely charged  electrodes.   The   ions pass through the
adjacent  membrane  into the next channel  where a concentrated
brine  solution of  the ionic impurities is formed.   Purified
product water  is therefore produced  in every other channel    This
series of  channels and membranes is  referred to as a "stack."   A
stack  may  have as many as 100 to  750  channels between a  single
pair of electrodes.   Stacks may be  used  in series to produce
better effluents.

Capability/Efficiency/Limitations—
Electrodialysis is capable of removing  only charged ionic  par-
ticles.  Unlike reverse osmosis, little  or no effect on uncharged
dissolved particles  and suspended matter  is observable.  The
process is very energy efficient with  energy costs proportional
to impurity of the feed.  The primary  economic consideration  is
membrane cost  and maintenance.   Membrane fouling, particularly
the anion-permeable membrane, is a problem.   Since the membranes
are ion exchange resins made in sheet  form,  removal of particular
contaminants by pretreatment may be  required as in ion exchange.

For desalting brackish waters,  it  has been determined  that
treatment  to not less than 500 mg/1  of salts in the product water
is economically  optimal.  Additional stages should be used  if
lower  salt contents are desired.  The  power  consumption required
                              239

-------
SALINE_
 FEED"
BRINE
POSITIVE
ELECTRODE
PRODUCT WATER
                       POSITIVE   ION
                       PERMEABLE MEMBRANE
                                                     NEGATIVE
                                                     ELECTRODE
                                                  NEGATIVE  ION
                                                  PERMEABLE
                                                  MEMBRANE
                Figure 8-8.  Electrodialysis.*
                 *From Item 1 in reference  list
                             240

-------
for desalting  brackish water  to  500 mg/1 is  shown  in  the table
below.    Pumping  power required is about 2 Kwh/1,000 gal.

The concentration of the brine solution  is  limited  by  the
possibility of precipitation onto the membranes.   Chemical agents
may be  added to help  prevent precipitation.
       Calculated  Power Consumption for Desalting Brackish
                   Waters by Electrodialysis
       	(excluding internal pumping power)	

       Feed  Concentration                  Power Consumption
       	(mg/1)	                   (Kwh/ 1,000 gal)

          4,900                                   19
          4,000                                   14
          3,000                                   10
          2,000                                    5

Case Histories--
Electrodialysis  has been widely used to desalinate brackish
waters.   Electrodialysis has  also been used  to treat  metal
finishing wastes  to 500 mg/1  IDS.   Ion exchange was  used for
polishing.

Wastes Produced—
The primary waste stream produced is the  concentrated  brine
stream.  Chemical  cleaning of the membranes may produce wastes of
low pH.

Cost Data—
Power costs  for electrodialysis are not high.  Power requirements
for treating brackish water were  given previously.  Capital costs
for desalting brackish water to 500 mg/1 TDS are given in  Figure
                             241

-------
8-9.  The operating  cost  for a 1.5 MGD plant is  about  $0.29/1,000
gal. (1975).

The capital cost  for a 7000 GPD unit treating waste  pickle liquor
from a  steel  plant was  $245,000  with  an operating cost of
4.5
-------
 1 -



 3 -

 4 -
     One Stage, approximately 502 demineralization

     Two Stages, approximately 752 deralneralization

     Three Stages, approximately 87.52 demineralization

     Four Stages, approximately 93.82 demineralization
M
£
|
a
D.
a
     1.2
     1.0
     0.8
     0.6
     0.4
     0.2
    0.0
           n-l
        0.5
                                            extrap
                                                   1ft id
                            A   6  8 10     20     40  60  80 100
                        Capacity  (10  gal/day)
  Figure  8-9.  Capital  investment  for electrodialysis
                as  a function of capacity  and of number
                of  stages.*
  *From Item 1 in  reference list

                          243

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Oil-Water Separation

Oily materials  may  be free,  emulsified, or dissolved in  the
wastewater but only free and emulsified oils can be separated and
removed by physical-chemical methods.

API Separators—
The American Petroleum Institute (API) sponsored studies  and
published design methods (1*)  for  oil-water  separators  based on
the  rise-rate  (Stokes  velocity)  of  oil droplets  of  150
micrometers diameter.  The API reference should be studied  for
specific  design  details and  their derivation.   In general,
application of methods yields long, rectangular, multichannel
separators. A Stanford Research Institute  report (2) shows  the
effect  of oil specific gravity and system temperature on  a 4
million  gallon  per  day (MGD) design API separator.   Data  are
shown in TABLE 8-17.  In TABLE 8-17 all of  the designs  for oils
with specific gravity greater  than 0.9 (room temperature  API
gravity of about 25°) are 100  or more feet long.  Figure 8-10 is
a drawing of an API separator  showing some details of construc-
tion.  The SRI report describes API Separator construction:

     "The walls of the chambers  are 7  feet high  for a 5 foot
     water depth.  The preferred material of construction is
     reinforced  concrete,  although  steel separators have been
     built. The separator chambers include a covered  5 foot x 22
     foot preseparator, a floating oil skimmer  section 12 feet x
     25 feet, a forebay 12  feet  x  30 feet and twin settlers 15
     feet x 130 feet."
•Item 1  in reference list
                            244

-------
  TABLE 8-17.   API SEPARATORS FOR 4 MGD WASTEWATER DESIGN FLOW
   Oil in Feed                     API Separators
                  Rise Rate
Specific  API     (Stokes Vel-  Num- Dimensions,ft  Residence
Gravity  Gravity  ocity), fpm   ber   W    D    L   Time, min


                    68°F, 0.01 Poise Pure Water
0.9659     15       0.085        220  f75   180    146
0.9340     20        0.16        2    15    5   130     53
0.9042     25        0.23        2    13    5   100     35
0.8762     30        0.30        2    13    5   75     26
0.8498     35        0.36        2    13    5   60     21

                    4Q°F. 0.0154 Poise Pure Water
0.9042     25        0.14        2~^  Tf  575130     66
                              245

-------
                 Working
                 Plorform
      TroihRock      \ Floating Oil
                TrajK |   Skimmer
Covered      \  Pan
                                                                                                    SECTION A-A
Separator Pumps NOTE 2

  Flight Scraper Chain Sprocket

      Flight Scraper Chain
               Inlet Sewer;
                        | Water Level
Covered Preseparator Flume 	*•

              Canvas Curtain
                                                                    Separator
                                                              Trash •-» Channel *4
                                                               Pan
                                                        Diffuifon Device
                                                        (Vertical Slot
                                                        Baffle)

                                                      Sludge-Collecting
   Sludge Pump       ,     .
   Suction      Diffusion Device
             (Vertical Slot Baffle)}.
                                         Preieparatof
                                           Section
                                                                              Gateway Piert
                                                   ^ Wood Flight
                       Separator	
                       Channel  Rota-fable Oil-
                                                                                     Effluent
                                        .  _                  Skimming Drum          {
                                     Flight Scraps    F(, h, S           \Oil-Retent5oni «* «"d Wall
                                    Chain Sprocket       a
-------
Figure 8-11 shows  the  effects  of design flow rate and actual  flow
rate on operating  costs.

Tubular Separators—
In ideal flow,  settling  is  related to flow per unit surface  area
and is independent of  liquid  depth.   Thus,  closely spaced  sur-
faces decrease  the separator  length  needed  for  collection  of a
given size particle (2).  Tube settlers are  a  successful design
based on this  theory.  Figure 8-12 shows a  cutaway of a steeply
inclined tube  settler  that  might be used in wastewater treatment.

CPI Separators—
The Corrugated  Plate Interceptor  (CPI) separator was developed
for the removal of oil as well as solids and has performed  well
in this service.   Corrugated fiberglass reinforced plastic (FRP)
plates are stacked with  about 0.8-inch spacing and slanted  at 45°
(2) as shown in Figure 8-13.  For oil separation the main flow is
downward  with  coalescing  oil  droplets gathering on the upper
surfaces and rising to flow countercurrently  and exit near  the
inlet of the CPI.

Figure  8-lU shows the effect  of  design flow rate  and actual
flowrate on operating  costs.  In addition to a gross reduction in
required land area, CPI  separators are estimated to require  2Q%
less capital cost  than comparable API separators (2).

Efficiency—
Based on  the  theory that  settling  efficiency is  related to
flow-per-unit surface  area, Thompson (3) presented the graph of
effluent oil concentration  versus the reciprocal of flow per  unit
area that is shown in  Figure 8-15.  In the figure, operating  data
with influent  waters containing  more than 1,000 mg/1  oil were
plotted as effluent oil concentration versus the area-to-flow
                              247

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     5  r
o
o>

o
o
o
o
u

o



!    *
a:
LU
o_
o

U
LU
—    I
        DESIGN POINT
     0.5
                       0.6           0.7        0.8     0.9   1.0


               OPERATING LEVEL, fraction of design capacity
   Figure  8-11.   API Separator:  effect of  operating level

                  and plant  capacity on operating cost.*




   *From Item 2  in reference list


                           248

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Figure 8-12.  Module of steeply inclined tubes.*
*From Item 2 in reference list
                  249

-------
Figure 8-13.  Corrugated plate interceptor.*
*From Item 2 in reference list
                   250

-------
o
D)

O
O
o
l/l
o
U

O
O
I—
u
      0.5
        0.6           0.7       0.8     0.9   1.0

OPERATING LEVEL, fraction of design capacity
 Figure 8-14.  CPI  separator for  150y drops:  effect  of

               operating level  and plant capacity on

               operating cost.*

 *From Item 2 in  reference list
                             251

-------
PO
en
ro
                    468
                                  !

              is
10  2   4  C  8  100  2  *4 6  8 1000 2

 SURFACE AREA/FLOW (SQ. FT./CFM)
                                                                         &0.84-0.86 Sp.  Gr.

                                                                         Oo.87-0.U9 Sp.  Gr.
46    8  QO.93-0.95 Sp. Gr.
            Figure  8-15. Correlation  of effluent oil content with operating factors,
            *From Item 3 in reference  list

-------
ratio, with oil specific gravity as  a  parameter.  Calculated API
designs are indicated for several area-to-flow ratios by vertical
dashed lines.  Although Figure 8-15 was developed  from API
separator data, a CPI claim of 25 mg/1 oil in the effluent for a
0.094 MOD unit checked the predicted  figure  of 30 mg/1 quite
well.

Costs—
Thompson concluded that Figure 8-15  applies to separators of any
shape  and he developed the cost curve  relationship for the capi-
tal  costs of API separators versus required effluent oil concen-
tration- that is shown in Figure 8-16.   For  a  reduction  from 150
to 10  to 15 mg/1 in the effluent, the additional API separator
area required was 432,000 square  feet,  valued  at $1.55 million
(Oct.  73).  In contrast, an air flotation unit was stated to  cost
$270,000 for the same job.

References—

1.   "Manual on Disposal of Refinery Wastes,  Volume  on Liquid
     Wastes," American Petroleum Institute, 1969, chp 5. 803*

2.   "Treatment of  Petrochemical  Wastewaters," E.D.  Oliver,
     Stanford Research  Institute  Process  Economics Program
     Report, No. 80, September 1972.  804»

3.    "Data Improves  Separator Design,"  Thompson,  S.J.,
     Hydrocarbon Processing, Oct. 1973.   882«
•Pullman Kellogg Reference File number
                               253

-------
      2.00__
            OILY WATER SEPARATOR
  W
  w
                 I
                  I
          200   175
          150    100     75
               EFFULENT PPM
50
                                                      25
Figure 8-16,
Study comparison of covered oily water separator
     With air flotation.
(From Item 3 in reference list)
                            254

-------
Phenol  Extraction

The  Phenosolvan process typifies phenol  extraction methods.   It
is a liquid-liquid extraction process  which  removes phenols  from
aqueous liquors.  The process was developed  by Lurgi and has  been
commercial since 19^0.

A diagram of the Phenosolvan process  is  shown in Figure  8-17
(2*).   The aqueous liquor feed is first  filtered through a gravel
bed  to  remove solids,  free tar,  and  oil.   The filtered  liquor
then passes through a multistage extractor countercurrent  to the
isopropyl  ether solvent.   Dephenolized liquor  leaves  the
extractors and may be gas stripped  to remove residual  solvent.
The  phenol-rich solvent is first  distilled,  then stripped  to
remove  the crude phenols and finally recycled to the extractors.

Capability/Efficiency/Limitations—
The  Phenosolvan process removes  monohydric phenols as  well  as
polyhydric phenols and other organics.  Extraction recoveries for
coal gasification liquors of 99.5 percent for monohydric phenols,
60 percent for polyhydric phenols and 15 percent  for other
organics have been  estimated in  the  literature (1).   For  coal
gasification liquors, BOD  (5-day BOD  analyses) reductions of 84
percent have been  estimated.   The composition of  the crude
phenols extracted from coal gasification liquors has been assumed
in the  literature  to be,  on a  water  free basis,  95 percent
phenols, and 5 percent other organics,. with  the phenols  being  85
percent monohydric and 15 percent polyhydric.  It should be noted
that the Phenosolvan process is a licensed process, and  the
licensor (Lurgi) always includes  it as  an  integral part  of the
Lurgi Gasification process.
•Item 2  in  reference list

                              255

-------
to
in
CTi
                CLEAN GAS
                LIQUOR
                               FILTER
               EXTRACTOR
                FRESH
                SUbVENT
               CONTAMINATED
               GAS  LIQUOR
FILTER
                                            EXTRACTOR
                                                                                           DEPHEHOLIZED
                                                                                           CLEAU
                                                                          SOLVENT

                                                                        DISTILLATION
                                                                 RECOVERED
                                                                 SOLVENT
                                           SOLVENT
                                           RECOVERY
                                           STRIPPER
                                                                                           GAS LIQUOR
                                                         BOTTOMS
                                                                                                    CRUDE
                                                                                                    PHENOLS
DEPHENOLISED
 CONTAMINATED
                                                                                               GAS LIQUOR
                              Figure 8-17.   Phenosolvan  process.
                               (Prom Item 2  in reference  list)

-------
Case Histories—
The Phenosolvan process was  originally developed  to  dephenolize
coke oven liquors.   Since 19^0, 32 commercial units  have  been
built ranging in size from 2 to 1000  GPM of aqueous liquor
throughput.

Costs—
American Lurgi has communicated  capital and operating costs to us
by telephone in  response to our letter request.   These  data
appear  in a later section entitled "Information Received  from
Licensors and Vendors".

Possible Improvements—
The use of alternate  solvents is  the  most  obvious area  for
possible improvement.

References—

1.  "Coal Gasification and the Phenosolvan  Process,"  Milton R.
    Beychok, 168th ACS Conference,  Sept.  1974, Vol.   19, No.  5,
    Division of Fuels Chemistry.   830*

2.  "Evaluation  of Background Data  Relating  to New  Source
    Performance Standards  for Lurgi Gasification,"  Cameron
    Engineers Inc., EPA-600/7-77/057, June 1977.  552*
    •Pullman Kellogg Reference number

                             257

-------
Stripping and Ammmonia Recovery

 Stripping process design depends on the sour  water source.   The
 sour waters generated by gasification are  high  in CO , whereas
 those generated by the liquefaction dissolver contain little  or
 no  C02.  Some gasifier and  liquefaction waters  contain phenols
 and phenols interfere with  ammonia separation.  This description
 assumes phenol extraction has removed simple phenols.

 After the removal of phenols,  sour waters  containing H S,  HCN,
 C02,and NH_ can be steam stripped to remove these gases.   High pH
 stripping  favors NHj  removal  and low  pH favors IL S  and HCN
 removal.  If steam stripping is carried out  in  two stages  with
 clean water reflux to the first stage, it is possible  to take H S
 and C02 overhead from the first stage and  recover NH3 overhead
 from the second stage.   Two-stage steam stripping will provide
 good H2S-NH3 separation only if adequate C02 is present.

 Because the proprietary United States Steel (USS) Phosam process
 is  said  by  some sources to be more economical than two-stage
 stripping,  and does  not require the presence  of  C02,  it appears
 to  be the process of choice in  conceptual designs for  recovery of
 H2S and NH3.

 The proprietary Chevron WWT two-stage stripping process may  be
 desirable for installations producing CO^-laden sour waters.

 Steam Stripping—
 Gasification processes  producing  p/o/t like Synthane (1)  and
 liquefaction processes  like SRC (1) and H-Coal  (2) may have  H2S
 concentrations in sour  waters in  the ranges of 1000 mg/1  and
 10,000 to 15,000 mg/1,  respectively.  Both p/o/t  gasification and
 liquefaction processes  may  have NH3 concentrations in  sour  waters
 in  the range of 8,000 to 14,000 mg/1, as shown in TABLE 8-18.
                              258

-------
       TABLE 8-18.  CHARACTERISTICS OF  BY-PRODUCT COKE PLANT

      	WASTES.  NET PLANT RAW  WASTE  LOAD*
Characteristics

Flow, liters per
metric ton coke
Ammonia, mg/1
BOD, mg/1
Cyanide, mg/1
Oil & Grease, mg/1
Phenol, mg/1
Sulfide, mg/1
Suspended Solids
            mg/1
I
580
1,900
1,500
1,020
—
450
—
II
530
1,380
1,280
110
240
350
1,380
III
154
7,330
1,120
91
101
910
187
IV**
19,200
39
12
7.7
2.1
6.1
4.2
A
390.
143
4,140
4.
25.
1,160


9


6
3


36
421
23
                                  609.2
                                  110
                                2,050
                                    3

                                  430
341
* Item 3 in reference list.
*Concentrations are low due to the addition  of  the  final once-
  through cooler stream which contained  significant  cyanide.
                                 259

-------
Coke oven gas liquors and sour waters are usually  stripped of H2S
and NH  before wastewater treatment.  However,  as  shown  in TABLE
8-18, two unstripped  waters from plants without  once-through
cooling  dilution were 187 and 1380 mg/1 H2S and three  unstripped
waters varied from 1,380 to 7,330  mg/1 NHV  Refinery  wastewaters
are reported to range from 50 to 10,000 mg/1 H2S and 50-7000 mg/1
NH3 (4); however, these figures reflect refinery  composite
wastewaters, not just sour waters  alone.   TABLE 8-19  summarizes
conventional refinery sour water/composite wastewater stripping
experience.

Except  for Lurgi gasifiers, few coal  conversion wastewater
stripping operations  are reported in the literature.   Lurgi
operators can expect 98 to over 99 percent NH3  removal with  a
feed containing 11,000  to 16,000 mg/1 NH  and a 200  mg/1  residual
(6).  Modern ammonia  stills  at coke  liquor operations are
designed for a residual of 50  mg/1 NH   (7) or 96.5  to over 99
percent  removal.  Conventional  oil refinery single-stage steam
strippers remove 90 to  97 percent  of the NH  and 98  to 99  percent
of the H J5 from refinery sour waters (U).
The proprietary  two-stage Chevron WWT  process  is designed  to
recover NH, and ^ S separately and  has residuals of <50 mg/1 NH3
and <5  mg/1 H2S (8).   -

Stripping  costs  and a sketch of this process  were provided  by
Chevron Research  and  are included in a  later  section entitled
"Budget Cost Estimates Received From Process Licensors".   Ammonia
recovery is included in this presentation.
•item 1  in  reference list
                              260

-------
                                TABLE 8-19.   REFINERY SOUR WATER  STRIPPER OPERATION*
        f "ample:
                IA** IB    2A  20  3
                                                • A  IK  9A  91)   IDA   IOB   IOC   II   II   I1A
                                                                                           M  15  16
   CONDITIONS
Raw frrJ:
Flow, ppm
Temper .time, tlet V .
llCilroprn st'lfWc. Pnm
Ammonia, ppm
Refill* :
Flow, ppm 	
Tempfr.ilwf, drt F. ...
Tn»er (red: r
Flow, ppm 	
Tempera lure, dee F. .
Tower r>oHnn«:
Mn*. rpm 	
Ycmrcrahtre. dc| F 	
P>e*Mirc, r*is 	
HyOrnpcn wlfidr, prm
Ammonia, ppm
Sttippins Mram, 1h r« hour
Sirippinr steam, Ib pef
fnMonl 5 	
llyunn'cn Milt'ide removal,
pcU'crH . 	
Ammnn'nt removal, percent
Tf»y» (or packing) 	
References:
IMI

in.nno
S.noo

*l
?«>

1*2
2m

w
2f*
.10
50
JkO
IS.MKJ

1 41
994
940
1)
1 5
200

ft.noo
3.000

33


233
200

250
261
22
10
200
16,700

11
99.9
950
13

V.

1.500
1.000

none


60
195

62
110
6
2
300
1,400

039
999
690
(12 ft)

CO

1.176
1,410

none


60
(9J

61
230
6.J
0
194
2,400

.067
1000
M.S
(12(1)
• •

104

5.000
3.000

10
1IH!

114
240

llll
230

JO
(.00
4.»70

0.11
9»9
17.3
6

„
11.1
4.MIO
3.100

J
216

.11
IrVI

41
2411
15
39
217
1,400

061
99,0
930
6
157

19

3.000
1.500

II


ion
135

103
220

1

4.700

O^f*
99..

12
i •

41
ion
7.MO
9.JOO

7.7
140

41.7
207

52.7
240
10
tract
790
4.500

1 54
UX) 0
I9.(.
12

230
240
J.I100
5,000

none


J30
240

233

II
3
200
10,000

067
99.73
96.0
10

125
:oo
1,1*0
1.4)0

none


.125
190

.144
240

32
5»0
7,000

0.36
91.3
57.3
4

131
CIO
.1.110
1.5 Ml

none


:5«
190

174
240

36
490
9,200

O.M)
990
670
4

10
ll0
1.310

none


10
no

19
215
7
0
124
2,200

046
1000
19.0
(13 (i)

in
no
.140
1.310

none


10
no

19
215
7
0
64
5,300

1.13
1000
95.0
(15(1)

75
100
6.550
3.700

21
110

96
210

91

7.5
16
47
14.100

2.52
99.7
91.3
(isru

17
ion
12.010
3.620

9
HO

96
210

91

7.3
19
7«
14.000

243
991
97.6
(13 (1)

i«n
100
s.6on
J.641

)
I75

1 5J
210

156

IS
II
121
11.900

1.3(1
997
930
(15(1)

95 40
100 ino
3. »''0 3.500
5.500

none nnnr


95 40
100 230

106 40
214 260

310 50
750
.'."! 2. IW

0.10 017
«9.0 990
164
1 (20(1)

JJ
IS
1.00
2.640

none


i)
IS

31


Ira
14
2,l»0

106
1000
915
(1511)

26 73 1411
»5
2.910 7.500 3.000
4.620 S.flOO

none none none


26 US I4R
»3 220 2nn

JO, «6 151
MO
5-7
(i i 211 2ns
1:0
910 1.550 2.5'W

062 n) o :•
10(10 962 931
9TO
(15(1) 6 »

IJ5

I.IIO
1.740

17
115

132
190

151
2J1

1
'ii
>.1W

II>1
99 9
98 0
1
1 1

   Item 4 in  reference list
** A, B, and  C  examples are different  operating conditions  for  the same stripper
i  Tower feed is  raw feed plus reflux
4  Pounds of  steam per gallon of tower feed
§  Does not include the heating steam  required to heat the  tov/er  feed to the tower bottoms temperature

-------
 David  G.  Rodriguez'  article on Atlantic  Richfield stripping
 experience (9)  is interesting for its  general design description
 and, particularly, its insights  into system design for reliable
 operation.  Rodriguez states that the  gathering system should  (a)
 provide  good  oil/water interface controls  at  each sour water
 source, (b)  have adequate feed  equalization to prevent hydro-
 carbons from entering the stripper, (c) provide good skimming  in
 the  feed  equalization  and (d)   smooth or  absorb feed pressure
 variations in  feed equalization.

 The  stripper  equipment should  be designed  for the  flow and
 quality of composite feed expected  and the  desired concentrations
 of H2S and NH3 in the stripped waters.   Desired composition  of
 the stripped waters  will depend on the  downstream process  se-
 quence.  Consideration must be given  to  operations with varied
 NH3 residual in  the stripper bottoms.

 Stripper  downtime other than that due  to  hydrocarbon carryover  is
 caused by corrosion and  salt   deposits.   Careful materials
 selection reduces corrosion.   Salt  deposits  are minimized  by
maintaining  temperatures above 150°F.

The stripper overhead  gas may be processed  for separation and
recovery  of  ammonia,  flared,or incinerated.

Stripping  Applications—
Stripping  H2S results in 98 to 99 percent recovery of the sulfur
values in some  waters  without  exceeding  biological oxidation
 (biox)  sulfur nutrient requirements,  in-plant  recycle require-
ments, or  effluent discharge limitations.   Stripped waters  may
contain  0 to 10 mq/1 residual H2S.  Biox requirements are about
(1/3/000)  x  BOD  or 5  to 10 mg/1 H2 S  for  p/o/t  gasification  or
liquefaction waters.   The remaining H£ is  oxidized to sulfates
before  reuse or  discharge.  Treating processes for cooling tower
                             262

-------
sidestreams or boiler  feed  waters can handle  the  residual sul-
fates.  The most  stringent  U.S. sulfate discharge  regulation is
250 mg/1 and is readily met.

By stripping,  ammonia can  be  removed from  wastewaters down to
biox nutrient  requirements  but not to recycle  or most stringent
discharge requirements.   Stripping can produce wastewaters con-
taining  50 mg/1  NH3 or  less.   Biox nitrogen requirements are
about (1/33) x BOD or (1/14)  x  phenol,  thus  about 100 to 1,000
mg/1 NH3 is needed  for undephenolized wastes.  Ammonia stripping
prior to biox  treatment must be controlled to  leave enough  nitro-
gen for the phenol/BOD load or NH 3 from Nl^recovery returned to
supply adequate nutrients.  Biox  removes  the nitrogen (ammonia or
nitrate)  needed for biomass growth and good  biomass separation,
and subsequent treatment  should produce an  effluent with NHj
sufficiently low  to meet  either recycle or discharge limits.

Gasification processes producing  no p/o/t with low biox potential
require special handling  after conventional ammonia stripping.
This special handling  can be simple second-stage ammonia  strip-
ping and/or breakpoint chlorination or other treatment.   Recent
articles from American Petroleum  Institute  (12,  13) have  an ex-
cellent discussion  of  "ammonia fixation"  in  refinery strippers,
which  explains the variability of performance shown in TABLE
8-19.  Ammonia can  be  freed for stripping by addition of lime or
caustic to pH 9.5 to 11.

Case History of Atlantic  Richfield Stripping Experience—
The Atlantic Richfield stripper embodies  the principles described
in Rodriguez1  article  (9).   Its operation  reduced combined re-
finery waste COD  from  277 to  114  mg/1 with (calculated) composite
H 2$ and  NH3 sour  water  concentrations  of  5,360 and 1,850  mq/1,
respectively.   Thus, although sour waters  may be only 5 to 15
percent of the combined  refinery  water  flow, stripping sour water
reduced refinery  COD almost 60 percent.
                              263

-------
 Case History of Chevron WWT Process—
 Chevron's WWT process has been operating  in Richmond, Cal.  since
 1969.  It recovers NH, and H,S in two  stages  similar to conven-
                    •3      ^
 tional  two-stage steam  stripping  with most of  the  H2 S and
 associated C02 removed in the first  stage  (8).  The residuals
 from the second stage are <50 mg/1 NH3  and  <5 mg/1 H2 S and are
 suitable  for refinery reuse.   An ammonia  scrubbing system  is
 required on the second stage overheads  to remove H2S and  other
 impurities.

 Phosam-W—
 Phosam-W is US Steel's designation  for an  adaptation of  their
 Phosam  process to  coal gasification and other non-coke oven
 processes.

 The Phosam-W process requires three major vessels, the "super-
 still,"  the ammonium phosphate stripper  and the  ammonia fraction-
 ator.   Figure 8-18  is a simplified  block  flow diagram  of the
 Phosam-W  process (1).  In operation,  sour  water  feed  to the
 superstill is heated to the bubble point and fed to the  top  of
 the stripper (lower) section of  the  superstill at 2.8 N/cm   (4
 psig).

 The superstill is heated indirectly  with 41.4 N/cm2  (60  psig)
 steam at 150°C and, at 2.8 N/cm2  ( 4  psig) ,  the stripped  water
 contains less than 200 mg/1 free  NH ,.    The upper section  of the
 superstill is an  ammonium phosphate absorber  with a spray section
 topped  by  a tray  column.  Acid vapors  from the stripper section
 of the  superstill pass upward through  a  sprays-and-tray absorber
and exit at 2.1 N/cm2 (3 psig).   Superstill  acid vapors consist
largely  of H J5 and whatever C02 was in the sour  water feed.  Rich
ammonium phosphate from the absorber  section  is  pumped, via heat
exchange  with the  overhead vapors,  to  the  ammonium phosphate
stripper.
                             264

-------
                        OFF GAS TO
      SOUR
      WATER FEED
KJ

-------
The ammonium phosphate stripper is operated at elevated pressure
                               2
with heat  provided by 414 N/cm   (600 psig) steam  at 249°C to
strip NH-  from the rich  ammonium phosphate.   The hot  lean
ammonium phosphate is cooled  before entering  the  superstill
absorber as the scrubbant.  The stripper vapors,  containing  10 to
20 percent  NIL  in water vapor, are condensed  with  heat recovery
and enter  the  ammonia fractionator  feed tank.   The  ammonia
fractionator column strips anhydrous NH_  from the water and is
operated at elevated pressure.  Product NH  leaves  the  top of the
fractionator via heat exchange with cooling water and refluxes to
the column.  The hot water from the bottom of the fractionator is
flashed  in  the  bottom of the  superstill to  provide  the rest of
the required heat  and for recovery of some NH- .   The ammonia
fractionator bottoms may contain up to 500 mg/1 NHL  (10).

The NH-  content of the stripped wastewaters depends on  the design
of the stripper section of the superstill but has been  100 to 200
mg/1 (10) in designs up to 1975.

Utility  requirements for Phosam-W are given  in TABLE 8-20.   The
unusual  features of the process are that it  will absorb ammonia
out of a mixture of acid gases such as H-S,  CCL   and  HCN without
co-absorption of acid gas and that it can operate on  liquid, gas,
or vapor feeds.

References--

1.  EPA-600/7-77-065 "Water Conservation and Pollution  Control in
    Coal Conversion Processes".  Water Purification  Associates.
    June 1977.  P. 257, 260, 265,  267.  480»

2.  Reap, E.J., Davis, G.M., Duffy, M.J., and Koon, J.H..  "Wastewater
    Characteristics and Treatment Technology for  the  Liquefaction
    of Coal Using H-Coal Process," Proceedings of the 32nd Purdue
    Industrial  Waste Conference, May 1977.  65M*
                             266

-------
    TABLE  8-20.   UTILITY REQUIREMENTS FOR A TYPICAL PHOSAM-W
              PLANT  INCLUDING WASTEWATER STRIPPING*
                                                    Per Pound
                                                    of NH
       Steam at 550  psig,  Ib                            12
       Steam at 25  psig,  Ib                              8
       Cooling Water,  gal                                40
       Electrical  Power,  KWH                             0.03
       Chemicals
         H3P04 Makeup  (as  10056 H3P04) ,  Ib                0.002
         NaOH (as. 100$ NaOH),  Ib                         0.003
•From Item 1  in reference list
                               267

-------
3.  Adams,  C.E., Jr.,  Stein,  R.M.,  and  Eckenfelder, W.W. ,  Jr.,
    "Treatment of Two Coke  Plant Wastewaters to Meet  Guideline
    Criteria", Proceedings  of  29th Purdue Industrial Waste
    Conference, May 1974.   P. 864-880.

4.  "Manual on Disposal of  Refinery Wastes, Volume  on  Liquid
    Wastes", American Petroleum  Institute,  1969.  Chp.  10.  803*

5.  Sylvester, N.C.,  "Sour  Water Treatment, A State-of-the-Art
    Review".  University of Tulsa Technical Report Number 74-1.
    641*

6.  EPA-600/7-77-057  "Evaluation of Background Data  Relating to
    New Source Performance Standards for Lurgi Gasification" .
    Cameron Engineers,  Inc.,  June 1P77.  P. 126-129.  552»

7.  Parsons, W.A.,  and Nolde, W.,  "Applicability of Coke Plant Water
    Treatment Technology to Coal Gasification".  Presented  EPA
    Symposium, Hollywood, Florida, September 1977.  958*

8.  Klett, R.J., "Treat Sour  Water for Profit",  Hydrocarbon
    Processing.  October 1972.

9.  Rodriguez, D.G.,  "Sour  Water Stripper:  Its  Design  and
    Application".   AIChE Symposium Series: Water-1973, No.  136,
    Vol. 70.  774«

10.  FE-1772-11 (ERDA) "Handbook of Gasifiers and Gas  Treatment
    Systems", Dravo Corporation, February 1976.  P. 142-144.  266*

11.  Armstrong, T.A.,  "There's Profit in Processing Foul Water".
    Oil and Gas Journal,  June 1968.
                            268

-------
12.  Gantz,  R.G. "API-Sour Water Stripper Studies",  40th  Midyear
    meeting of Division of Refining, API,  Chicago  1975.  Preprint
    No.  0375.

13.  Bomberger, D.C., and Smith, J.H., (Stanford Research Institute)
    "Evaluation of  Ammonia Fixation  in  Actual  Refinery  Sour
    Waters",  API Report 954, January 1978.          «843
    *Pullman Kellogg Reference  File number
                              269

-------
 Coagulation and Flocculation

 Coagulation and flocculation  (C&F)  are,  respectively, chemical
 and physical means of clarifying wastewater  and are usually  used
 in conjunction  with either flotation  or  filtration.  Flotation
 and wastewater  filtration are described separately.

 Coagulation and flocculation occur by  a  combination of chemical
 and physical factors (1, 2*) and may or may  not be accompanied by
 chemical precipitation.  Coagulation  is  used for removing  sus-
 pended solids or colloidal particles from water and precipitation
 is used for removing some dissolved solids,  mainly  hardness and
 trace metals.   After coagulation  and/or  precipitation,  floccu-
 lation follows  before subsequent solids removal.

 Coagulation requires the destabilization  of  colloids,  usually by
 charge modification coupled with bridging or enmeshment processes
 (1).   The two principal means of  determining optimum doses for
 C&F are the jar test  and zeta  potential measurement.   The jar
 test  is a lab method of C&F followed by  sedimentation.   For the
usual jar test, coagulant is added to  wastewater at several  dose
 levels and/or  floe  times using  six  stirred jars.   Mixing and
 flocculation are  followed by  a  settling  period after which
samples of supernatant liquid are examined for turbidity.   Figure
8-19  shows the  results of tests  at several doses and settling
times with ferric sulfate.  Doses and  times  are chosen to provide
desired effluent quality at least cost.   Zeta potential requires
a special apparatus that measures the  velocity of floe migration
across a fixed  electrical potential field.   The zeta potential
 for best  C&F results  is used  for process control.  Figures
8-20(a)  and 8-20(b)  show the  zeta potential and residual
turbidity, respectively, as functions  of  alum (aluminum sulfate)
•Items 1  and 2 in reference list
                             • 270

-------
|x

 I
                100
                 50
                 20
             5   10
             r i
                                                            Q—24 mg/1
                                                         Ferric  Sulfat
                               SETTLING TIME, MIN


                    Figure 8-19.   Jar test results.*

                    *From Item 1  on reference list
 -V,26 hg/1


      I
   -28 mg/1
0-30 mg/1

 I-	
                                                           •~E-32 mg/1
                                                               34  mg/1

-------
+10
         100      200      300

               ALUM DOSAGE, (mg/1)
400
                                         500
  Figure  8-20.   Coagulation of Raw Sewage
                 with Alum.*

  *From Item 1  on reference list
                         272

-------
 dose.  The zeta potential,  Figure 8-20(a),  corresponding to the
 best alum dose in Figure 8-20(b) is -2 to -4 millivolts.

 Charge modification can result in restabilization if coagulant
 overdose occurs.  Figure  8-20(b) shows  the  effects  of alum
 overdose as turbidity passes  through  a minimum at 150 mg/1 then
 begins to rise at higher alum rates.

 As the solubilities of the  chemicals  added  for treatment are ex-
 ceeded,  precipitation  occurs and the precipitates form  floes.
 The usual C&F chemicals are alum,  ferric  or ferrous sulfate,and
 lime.  The precipitation reactions depend on the  chemical  treat-
 ment and the water characteristics.   TABLE  8-21(a) summarizes  the
 important reactions of alum in water  treatment.   Generally  C02
 is released from the waters and alkaline  carbonates and  aluminum
 hydroxide, Al(OH)o, precipitate.   Various alkalis may be used  to
 maintain pH.  TABLE 8-21(b) shows  the similar reactions of ferric
 sulfate, Fe (SO. L .   TABLE 8-21(c)  shows  that  ferrous sulfate
 reacts with only 1/3 the amount of lime  of  either alum or  ferric
 sulfate.  TABLE 8-21(d) summarizes the  reactions  of lime with
 calcium  and magnesium  hardness in the  wastewater (as  bicarbo-
. nates) and with soda ash added to increase pH (alkalinity)  and
 calcium carbonate  precipitation.   Note  that  only  insoluble
 carbonates form and gases are not  evolved.

 In addition to the usual raw water coagulants  (alum, lime,and  the
 iron salts) other  compounds may  be  used as supplements  or  en-
 hancers.  Flocculating agents, i.e.,  polymers  or polyelectro-
 lytes, may be added to alum or iron  floes to  increase  floe  size
 and  strength.  Soda ash may be added  to  increase alkalinity  for
 lime processing while a strong acid  or  base may be  used  for pH
 adjustment.
                               273

-------
             TABLE 8-21 (a).  REACTIONS OF  ALUMINUM  SULFATE*


          Ab (SCh)3 + 3 Ca (HC03)2— 2 Al (OH)3} + 3 CaSOa + 6 0)2)

          Ab (SCX03 + 3 NazCCh + 3 FhO—- 2 AL (OH) 3\ -f 3 CCX>t

          Al2 (S04)3 + 3 Ca (OH):— -2 AI (OH)3| + 3 CaSCh



               TABLE 8-21 (b) .   REACTIONS OF  FERRIC  SULFATE*
           Fc2(SOa)3 + 3 Ca(HC03)2— ~2 Fe(OH)3J + 3 CaSOa + 6 CO2
           Fe:(S04)3 + 3 NasCCb + 3 H2O-*2 Fe(OH)3{ + 3 NaiSO^ + 3 COrf
           Fe2(S04)3 + 3 Ca(OH)2—-2 Fc(OH)3| -f 3 CaSO4
                TABLE 8-21 (c).  REACTIONS OF FERROUS  SULFATE*
                      + Ca(HCO3)2— -Fc(OH)j|  + Ca SO4 + 2COcJ
                FeS04 + Ca(OH)2— - Fe(OH)?f + Ca SO4
                4 Fc(OH)2 + O2 + 2H2— »• 4 Fe (OH)3 {
                    TABLE 8-21 (d) .   REACTIONS  OF LIME*
           Ca(OH)2 + Ca(HCO3)2-^2 CaCO3J + 2H:O

           2 Ca(OH)2 + Mg(HCOj)2— ^ 2 CaCOj} + Mg(O!i)2 1 + 2H:O
           Ca(OH)2 + NarCOj— - CaCOj { + 2 NaOH
*From Item 1 in  reference  list
                                     274

-------
Alum and iron salts  release  the  appropriate cation, Al   or Fe   ,
and these form insoluble  hydroxide  floes whose charge depends  on
the pH.   At or near  the floe  isoelectric point (near neutral for
alum and iron) floes aggregate and  settle.  Alum's solubility  as
hydroxide is also  pH dependent  in  the  range  of interest  and  it
passes  through a minimum  near  pH 7 (2).  Lime acts to  remove
suspended solids  by  precipitating  calcium  carbonate, CaCOo , and
to do so carbonate  or bicarbonate alkalinity must be present.
Fortunately the high pH required  for  effective lime coagulation
(9.5-11.5)  also helps to  remove  many  heavy metals.  These  metals
will precipitate  with the  lime  sludge.   Figures 8-21 and 8-22
show, respectively, the optimum  pH values  for various metal
removals singly and  in the  presence  of ammonia.  See "Chemical
Precipitation" for further  discussion of lime  treatment to remove
calcium and magnesium hardness and  various heavy metals.

Chemicals Required—
Quantities of chemicals required  for  C&F treatment depend  on  the
characteristics of  the wastewater,  including pH, temperature,
hardness,and concentration  of suspended solids.  With reference
to equations in TABLES 8-21(a) and  8-21(b), there  are the  follow-
ing relationships  for chemical equivalency:

         ALKALINITY  EQUIVALENCY  FOR CHEMICAL TREATMENTS*

                             Chemical Treatment  Addition of 1 mg/1
Reactant Equivalent           Alum Ferric Sulfate Ferric Chloride
Alkalinity, as CaCC^         0.50    0.57            0.92
95* Hydrated lime as Ca(OH)2  0.39    0.44            0.72
Soda ash as Na~ CO            0.54    0.62            1.00
              £•  -J

•Item 1 in reference list.
                               275

-------
NJ
-J
                       1.2
                       1.0 _
                       0.8  ._
                       0.6  _
                       0.4  _
                       0.2  ._
0 	I	I	)	L	I
                                                       I 	1     I   I    I
         7.5      8.0      8.5      9.0
                             P"
                                                                  9.5     10.0     10.
                          Figure 8-21.  Optimum pH values for metal removal.*
                          *From Item 12 on  refererice  list, p. V-B/125

-------
to
                                                         A Ni
                                                         O Cu
                                                         D Co
                                                            NH3~N=500 mg/1
                          7.5
8.0
8.5
9.0
9.5
10.0
       Figure 8-22.   Optimum pH values for metals  removal in the presence of ammonia.*
       *From Item 12,  p.  V-B/125,  on reference list

-------
These  amounts of alkali  will  just maintain the  alkalinity
unchanged  when 1 mg/1 chemical  is  added.  For example  if no
alkalinity is added 1 mg/1 alum  will reduce the alkalinity 0.5
mg/1 as CaC03.

Water softening by lime addition to  a given pH is widely used.
The lime dose required depends on both the final pH  desired and
the carbonate-bicarbonate alkalinity.  At pH 11  virtually all
hardness will precipitate and be removed.   Figure 8-23  shows the
lime required to achieve pH 11 as a function of alkalinity; for
example, if alkalinity is 100 mg/1 (as CaCO )  a  lime  dose of 200
mg/1 is needed.   Many municipal phosphorus removal operations (1)
require 200 to 600 mg/1 lime  to  achieve pH 9.5 to 11.5.  TABLE
8-22 summarizes this municipal experience  and  also includes some
alum, iron  salts and polymer data.

Eckenfelder (2)  reports that activated silica  is added  to toughen
alum or iron floes at 2 to 5 mg/1.  Anionic or non-ionic  polymers
are added to aggregate floes at 0.2 to 1.0 mg/1.  The EPA report
on suspended solids removal (1) gives examples  of polymer usage
of 0.08 to  1 mg/1.  This EPA report also includes in  Chapter 5  a
thorough description of equipment design for handling and storing
chemicals.

Costs—
Treatment costs for coagulation and flocculation include cost  of
treatment chemicals, costs for storage and handling of treatment
chemicals and capital and operating costs  for  the C&F equipment.
The chemical sludges produced by settling, filtering,or flotation
require  processing  for disposal.   The related costs  will  be
greater than for non-chemically produced sludges: more sludge  is
produced, since more suspended solids are  removed, and  some  of
the added chemicals also precipitate.
                              278

-------
  500
o
u
  400
-
_
I
-
-
tfl
C
   300
200
      0
            100        200         300        400


              WASTEWATER ALKALINITY mg/1 -CaCO3
500
 Figure  8-23.   Lime requirement  for  pH>  11 as a function

                of wastewater alkalinity.*
 *From Item  1  in reference list
                           219

-------
                                                     TABLE  8-22.   SUSPENDED SOLIDS  REMOVAL PERFORMANCE  FOR
                                                     CHEMICAL  COAGULATION APPLICATIONS  TO  PHOSPHATE  REMOVAL*
tv>
00
O
svsrrnnra SOLIDS
LOCATION PROCESS

Lebanon, Ohio IPC
EPA, Blue Plains 1PC
Plant, Nash-
Ington, D.C.
Ely, Minn. Tertiary


S.Lake Tahoe,. Tertiary
California
Lebanon, Ohio Tertiary
Nassau County, Tertiary
New fork
Salt Ukt City, IPC
Utah




Leetidale, Pa.

PLANT
SIZE
«td
0.1
0.1


I.S


7.S
0.1
O.i

0.04'
0.1
0.05-
0.09
0.03-
0.18
0.6

AVERAGE
CHEMICAL FEED
«!/l
Line — 250
time 460t*) .
•FeClj 5(b)

Line 2SO-350(t>
«Poly«i«r .2
-------
The  costs of chemicals vary with the market  but a recent com-
parison  is shown in TABLE 8-23  for the relative costs (1977) of
chemicals for pH adjustment. Lime and soda are included  in TABLE
8-23 since they  are  used extensively in  coagulation and water
softening.  Current costs from  "Chemical Marketing Reporter" for
alum,  ferric sulfate, and quicklime  are about $137, $99,  and $25
to 45, respectively,  per dry ton,  bulk,  FOB  factory.  Lime is
produced locally throughout much  of  the U.S.  and may have lower
shipping costs than either alum or ferric  sulfate.  Thus  compared
to high  calcium  quicklime, relative costs  for alum and ferric
sulfate  are respectively about  4X and 2 to 3X.

Total costs are difficult to  ascertain for  coagulation and
flocculation except as they add to such other processes as either
air  flotation or sedimentation.   Somewhat  dated (1972) costs are
given in Stanford Research Report No. 80  (13)  for petrochemical
wastewater treatment.

Application to High P/O/T Gasification—
Processes like  Synthane and Lurgi that  produce high phenols,
oils,  and tars, (p/o/t) may have  as-formed alkalinities of 7,000
to 16,000 mg/1, expressed as CaCO (3, 4).  Even  so, calcium and
magnesium hardness may be low (15 to 20 mg/1) so  that most of the
alkalinity is associated with  ammonium  compounds.  Stripping
these waters for  H  S and NH removal, with  or without phenol
extraction, also  strips  C02  and  reduces  the high  original
alkalinity to low residual levels.   Coagulation and  flocculation
of these stripped waters to reduce suspended solids  and  oils may
require  alum treatment or addition of  carbonate alkalinity so
that lime treatment can be effective.

Limited  results  of C&F treatment of  gasifier wastewaters  were
found in the literature  (4) and some  coke-liquor (5, 7) and
refinery data  (6,  8, 9)  are  also available.  Synthane PDU
                              281

-------
   TABLE 8-23.
RELATIVE COSTS OF COMMON pH ADJUSTMENT REAGENTS*
              (1977)
Reagent
           Chemical Formula
Relative Cost
Alkaline
Caustic Soda
Soda Ash
High Calcium Hydrated Lime
Dolomitic Hydrated Lime
High Calcium Quicklime
Dolomitic Quicklime
High Calcium Limestone
Dolomitic Limestone
Acidic
Sulfuric Acid
Nitric Acid
Hydrochloric Acid
Sulfur Dioxide
Carbon Dioxide
NaOH
Na2C°3
Ca(OH)
Ca(OH) . MgO
CaO
CaO.MgO
CaCO
CaC03.MgC03
HNO
HC1
so2
co2
8.50
4.10
1.37
1.06
1.00
0.85
1.21
1.05
1.00
4.36
2.30
1.47
•Item 12 on reference list, page III, D-5
                                282

-------
wastewater studies (4) had total  influent  tar,  oils,  and grease
of 1,100 mg/1. Alum dosage of 100 to  150  mg/1,  coupled with pH
adjustment, reduced  this to a total of about 600 mg/1,  all
soluble.  Thus,  although only about  50 percent of total tars,
etc.  were removed,  no suspended tars, etc.  remained.   See the
case  history of the Synthane Gasifier.

One of  the coke liquor references (5)  is  an  interesting recent
development of a  patented process by  Bethlehem Steel.  Figure
8-24  shows that coke plant weak  ammonia liquor  (WAD  is treated
in a  still for ammonia recovery prior to combining with other
wastewaters for biological oxidation  (biox)  treatment.  Figure
8-25 shows the  conventional WAL  distillation  flowsheet.
Bethlehem's new process, shown in Figure  8-26,  involves liming
the WAL and clarifying it before ammonia stripping.  To apply
this  process to coal conversion  wastewaters, two-stage sour water
stripping would be required with  liming and clarification between
the first, or H  S,  stage and the second,  or  NH  stage.  More
details are given in the case history  of  the  Bethlehem process.
This  modification  should  be compatible with U.S.   Steel's
"PHOSAM-W" process for stripping and  ammonia recovery but will
have  the added costs of a separate H2S still.   Bethlehem claims
that  oil and tar  removal is accomplished without flotation or
filtering equipment  with oil, etc.   coming  down with the lime
precipitate.  One potential weakness  of this process is  suggested
(7) in  a discussion of biox treatment of  WAL where the authors
say that calcium  thiocyanate formed  during lime distillation is
about "four times more difficult to  (bio)  oxidize" than ammonium
thiocyanate.  Pilot  or bench tests  are  needed to  assess the
effect  of lime distillation on downstream  treatability.

Beychok (6), Ford (8) and Lin (9)  give summaries of refinery  sour
water oil C&F experience.  They did  not distinguish soluble from
"free"  oil.  Beychok reports that 30  to 150 mg/1 alum provided 75
                               283

-------
              TO COKE OVEN
                CAS USE
UEAK AWONIA
LIQUOR (WAL)
                  GAS
 AMMONIA
  STILL
                         LIQUOR
            TO INCINERATION
   FINAL
   COOLER  -
  CONDEKSATE
             TO COMBUSTION
  BENZOL
  PLANT
 UASTEVATERS
                 TOIL
  AIR
FLOTATION
  CELL
           LIQUOR
LIQUOR
                     BIOLOGICAL
                     OXIDATION
                       POND
BIOLOGICAL
 EFFLUENT
             Figure 8-24.   Bethlehem multitreatment
                                 scheme.*
             *From  Item  5  in  reference  list
                                 284

-------
AKtONIA VAPOR. >TTt . -..,
TJ SAIURATOR pi STILL CAS ,
COOLING 1
WATER } A T¥ A" /
— DEPHLECMATOR I
COOLING 	 t
WATER i •
CONDEN
LIME
LEG
tlO* LIME
SLURRY
V
SATE

*-•

' M
FREE
LEG
. j
^,
FIXED
LEG


, ?TILL
-TRAY NO. 20
UAL
STORAGE

-TRAY NO. 15
-TRAY NO. 14
,TRAY NO. 1
4 !
_^_ WASTE LIQUOR


EFFLL'EtlT SOLIDS SETTLING BASIN
L.P. STEAM 1 •(•^OOOir.g/1 S.S.)
Figure 8-25.  Conventional flowsheet for ammonia
              distillation.*
From Item 5 in reference list

                         285

-------
to
00
en
                         AMMOKU VAPOR
                         TO SATURATOR
        STILL CAS
                     COOLING
                      WATER '
                     COOL1HC
                      WATER
                                    DEFHLECKATOR
                                          CONDENSATE
                            LIMED
                             WAL
                           STORAGE
^-^Q
                                                        SECTION
                                                                 -RECTIFYIMC SECTION
                                                                 <50 mg/1
                                                                  s.s.
                                 J
                                                                           CLARIFIER/TH1CKENER
                                            SETTLED
                                            SOLIDS
                                                                                                           LIKE
                                                                                                        SLURRT
                                                                                                         VAL
                                                                                                  cfo
                                                                                                 Y
                                                                                                PREL1MINC
                                                                                                 VESSEL
                                                          , STILL EFFLUENT I" ------ T COOLED STILL BOTTOHS
                                                           
-------
to 85 percent  oil removal and 55 to 70 percent suspended  solids
removal.   Beychok states that the C&F process can  produce  refin-
ery waters with  no  more than 20  to 30 mg/1  oil.   Ford  reports
that chemicals (alum, most commonly) at 100  to 130  mg/1  reduced
oil in refinery  waters 71 to 93 percent when used  with  dissolved
air flotation  (DAF).  Lin and Lawson give 50 to  90 percent re-
moval of  refinery oil at 60 mg/1 oil influent for  C&F with DAF.

Application to Gasification Producing No P/O/T—
The Koppers-Totzek  process is a commercial gasification  process
producing no p/o/t  with a reported  (3) wastewater alkalinity of
700  mg/1 equivalent  CaC03  (calculated  from  the Ca  and Mg
hardness).  Such waters require softening before  final  stripping
to avoid  scale formation in the strippers.   Since li, S  stripping
is greatly reduced at elevated  pH, lime softening should be
performed between first-stage 1^ S and second-stage NH3  stripping.
Since CO,  will strip with H2S, carbonate alkalinity (soda ash or
recarbonation) may  have to be added  following liming to  provide
effective softening.  Because  this water  is low in BOD, down-
stream treatments are likely to be  physical-chemical rather  than
biox.

Applications to  Liquefaction—
Liquefaction processes will  produce essentially CC^-free  sour
water from the dissolver off-gas  condensates.  These sour waters
thus have ammonia associated  with  sulfides  and  phenols and  are
low  in hardness  and carbonate alkalinity.   TABLES 8-24 and  8-25
show analyses for unstripped H-Coal and SRC  sour waters obtained,
respectively,  from  a PDU (HRI,  Trenton, N.J.) and a 50 TPD  pilot
plant (PAMCO,  Fort  Lewis,  WA) .   Carbonate was not reported  for
either water,  calcium was  only 0.47 mg/1  for SRC and magnesium
was  0.13 and 0.7 for SRC  and H-Coal,  respectively.  Stripping
such waters after  dephenolization should produce  relatively  soft
water of low alkalinity  and hardness with good treatability.

                              287

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      TABLE 8-24.  ANALYSIS OF SOUR WATER FROM H-COAL PDU*
Parameter
 Value
 (mg/1)
BOD, Total
     Soluble
COD, Total
     Soluble
Organic N
Phenol
Sulfide
Oil and Grease
PH
Pb
Ni
Mo
Co
Cu
Cd
Fe
Al
Mg
Zn
52,700
51,200
88,600
88,000
14,400
    51
 6,800
29,300
   608
     9.5
0.06-2.90
0.10-1.70
0.01-0.50
0.01-0.50
0.02-0.40
     0.8
     1.2
     2.5
     0.7
     0.45
*Item 10 in reference list
                               288

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 TABLE 8-25.   ANALYSIS  OF  SOUR  WATER  FROM  SRC  I PILOT PLANT (a)

(mg/1 unless  noted)
Kentucky Coal Feed
Analyses by Water Purification  Associates  and  Pittsburg & Midway
                                pH=8.6          pH=8.2
Total Carbon                      9,000            8,160
Total Organic Carbon             6,600            7,390
Inorganic Carbon                 2,400  (b)         770  (b)
BOD (5 days)                     32,500
BOD (15 days)                   34,500
BOD (20 days)                   34,500
COD                             43,600          25,000-
                                               30,000
Phenol as C6H5OH                 5,000           12,000
Total Kjeldahl N                 8,300  (c)      15,000  (c)
Total Ammonia as N                7,900           14,000
Total Ammonia (meq/1)              465              824
Cyanide as CN                       10
Total Sulfur as S               10,500  (c)      16,200  (c)
Ca                                   0.47
Mg                                   P.13
Si                                 < 0.5
 (a) Item 11 on reference list.
 (b) By difference, see Appendix 1, Reference 3.
 (c) 22 analyses for N and S made between 10/5/75 and 12/9/75 were
    supplied by Pittsburg and Midway.  Four of these analyses had
    extreme values and were arbitrarily eliminated.  For  the re-
    maining 18 analyses the  average total  nitrogen was  12,600
    mg/1 with a standard deviation of 7,000  mg/1 which  is very
    random.  The  average ratio  (moles NH3/(H2S) was 2.0  with  a
    standard deviation of 0.17 which is quite reproducible.
                              289

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Lime distillation of ammonia may not  be  necessary after phenol
and H2S removal but it will aid in  removal of oils and tars.
A few limited undiluted sour water analyses  have recently  been
published for SRC II, as shown in TABLE 8-26.  These analyses are
similar to those for SRC I and H-Coal shown  in TABLES 8-24  and
8-25 in their content of ammonia, sulfur, and phenol.

Case History of the Synthane Gasifier—
A recent report of treatability studies made on the Synthane  PDU
waters includes C&F pretreatment data.  This report (8),  one of a
few published coal  gasification  wastewater  treatment studies,
describes Synthane gasifier wastewaters:   "(they) are generally
light amber in color initially but darken  on standing.  They have
a strong ammonia and cresol-like  odor,  resembling the odor of
coke-oven  byproduct waters.  Chemical   analyses of  Synthane
waters....are similar to coke plant wastes..."

This study found that good consistent oil  and  tar removals  were
obtained with 100 to 150 mg/1 alum.  Jar tests were used for  C&F
evaluation.  Initial concentrations of 22,000  mg/1 tar, oil  and
grease were reduced to 1,100 mg/1 by 3 to 6  hours settling at
ambient temperature.  Jar tests were made  with alum on the  1,100
mg/1 "feed" water,  with and without pH adjustment.  Best results
were 47  percent removal  (about  500  mg/1)  of oil and  tars,
obtained with 100 to 150 mg/1 alum and adjustment to pH 1.5 to
2.5 before alum addition (pH was  then adjusted back to neutral
before analyses were made).  Effluent oil  and  tars (authors  say
"all soluble") were thus about 600 mg/1.   Subsequent biotreat-
ability  studies proved  this effluent   was  amenable  to biox
treatment.
                             290

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         TABLE  8-26.   AVERAGE ANALYSES FOR SOUR WATER IN
         	SRC II PILOT PLANT. 1977*	
                      JULY      AUGUST     SEPTEMBER
                           (weight percent)

Nitrogen              3.56      4.00          4.33
Sulfur                2.55      2.51          2.97
Phenol                0.52      0.85          0.50
•Item 11  on reference list.
                              291

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Case History of Bethlehem's "Improved Process"  for Weak  Ammonia
Liquor (WAL) —
In a recent article (5) Rudzki, Burcaw and Horst  describe a coke
liquor pilot plant ammonia still  process development  program.
Conventional WAL treatment  for  coke wastewaters uses  lime
addition into a "lime leg" still fed from  the bottom  of  the upper
or "free leg" still.  Saturated  (scaling) slurry from  the lime
leg feeds the top of the "fixed leg" (bottom part of  the ammonia
still).  Plugging is common, design loadings are  low  (3  to 5 gpm
per square foot)  and steam rates are high (2  to 3 Ib/gal WAL) .
Bethlehem's process introduces a preliming vessel and a  clarifier
into this process between the treated WAL  storage vessel and the
ammonia still feed plant.  In  this proces  all  distillation is
"fixed-leg" but the feed is no longer a scaling slurry.   Figures
8-25  and 8-26  are schematics of *'ie  conventional  and the
Bethlehem processes, respectively.   The authors claim mechanical
design  improvements,  including oil and tar removal  without
flotation or filtration, lower capital and maintenance costs and
reduced steam consumption (0.8 to 1.1 Ib/gal WAL) as advantages
of the redesigned process.

TABLE 8-27 summarizes (1977) operating cost estimates for 0.2 MOD
WAL plants and  shows that the Bethlehem process saves $3^0,000/yr
in operating costs.  Although  actual data  are  not  given, lime
costs in TABLE  8-27 indicate 32 percent more lime is  used in the
new process than  in the old, increasing the  massive  lime dosage
from 10,000 to  13,000 mg/1 CaO  (assuming 365 days  operation).
The clarifier/thickener produces effluent  feed for the still with
only 50 mg/1 residual suspended solids and produces an under-flow
sludge with 30  percent solids.  Tar content in the sludge was 0.1
percent (dry basis) if WAL was stored prior  to use as feed, but
went as high as 10 percent when flushing liquor was used directly
as a feed. Tar  content of 0.1 percent sludge, dry basis, is  equal
to 26 mg/1 removed  from the 200,000 gpd assuming  all  CaO reacted
                             292

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   TABLE 8-27.   ESTIMATED ECONOMIC ADVANTAGES OF THE BETHLEHEM
   	AMMONIA REMOVAL SYSTEM*	

           Plant Capacity-757 cubic meters per day WAL
                        (200,000 gpd WAL)
   Utility
          Operating Costs, $ per year
Conventional     Bethlehem
   Process        Process       Savings
Steam at $7.727
  1,000 kcr  ($3.50/
  1,000 Ib)         639,000
Lime at $38.55/
  metric ton
  ($35/ton) 85*
  Available CaO     125,000
Cooling Water at
  8
-------
 to CaCO-j.   Of course,  10  percent  tar  content  implies 2,600  mg/i
 removed but the massive  lime  dosage  employed  apparently  was
 capable of handling it.   Note that tars and  oils not skimmed in
 upstream steps are lost to  lime sludge and  may  be difficult to
 recover.

 Case History of  an Integrated Refinery/Petrochemical
 Installation—
 In a study of the role of  industrial  pretreatment for organics
 removal from industrial  wastewaters (14),  Eller and  Gloyna
 followed bench scale studies with  pilot plant work.  Two streams
 were selected for study because of their  pH and oil and suspended
 solids  (ss) content  and  variability.  The  authors noted that
 after blending the two  streams  co-precipitated some  soluble
 organics when the pH was  increased.  Influent pH varied from 2 to
 10, averaging 6.0, whereas oil  and  ss  varied  from 200 to 700
 mg/1.  Bench scale  flotation was unsuccessful and  gravity
 operation after neutralization  was  marginal.   Above pH 8.0 a
 settlable  floe formed. A  comparison in the  pilot plant of lime
 and caustic for pH control  showed  that lime was more effective in
 forming settlable floes.   Lime doses of 250 to 900 mg/1 gave  pH 8
 to 11.  Optimum settling occurred with  350 mg/1 at 8.5.
Downstream biox reduced the  pH back to 7.0  and produced a
pH-stable  effluent so that  soda ash addition  was not necessary.

The authors varied clarifier overflow rates from 400 to  1,100 gpd
per square foot but  found 600 gpd per  square  foot  to  be  the
maximum rate at which excess oil and sludge  discharges could be
avoided when the sum  of  oil and  ss excursions  in the influent
rose to over 700 mg/1.   To prevent discharges  during influent
excursions it was necessary to  add powdered  limestone as a
weighting  agent.
                            294

-------
With 600  gpd per  square  foot  overflow  rate  and  limestone
weighting  as  needed, the sum of  oil  and SS in the  effluent was
consistently  less than 50 mg/1 even with influent  excursions over
700  mg/1,  representing 75 to 93/6 removal.   COD  (50%  probability)
was  about  4200 mg/1 in the influent  and about  2,500 mg/1 in the
effluent,  representing about 40$ removal.

References—

1.    EPA 625/l-75-003a "Process Design Manual  for Suspended So-
     lids  Removal," January 1975.  Chapters  4,  5.  873*.

2.    AIChE Today Series "Advanced  Wastewater  Treatment,"  W.  W.
     Eckenfelder, Jr., P. A. Krenkel  and C.  E.  Adams, Jr., AWARE,
     Inc., 1974.  Pages D-2, D-3.

3.    EPA 600/7-77-065, "Water Conservation and  Pollution  Control
     in Coal  Conversion Processes."   Water Purification  Asso-
     ciates.  480«

4.    PERC/RI-77/13 "Treatability Studies of Condensate Water from
     Synthane Coal Gasification," November 1977.   797*

5.    Rudzki,  E. M. , Burcaw, K. R. and J. R. Horst,  "An  Improved
     Process for the  Removal of Ammonia from Coke Plant  Weak
     Ammonia  Liquor."  Iron and Steelmaker,  June  1977.  777*

6.    "Aqueous Wastes from Petroleum & Petrochemical Plants," M.
     R. Beychok, 1967.  Page 248.  728*
•Pullman  Kellogg Reference File number
                              295

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7.   EPA-R2-73-167 "Biological Removal  of Carbon and Nitrogen
     Compounds  from Coke Plant Wastes," April 1973.  Page 30-33.
     800*

8.   Ford,  D.  L.  and F.  S. Manning, "Oil Removal from Waste-
     waters."   University of Tulsa Technical Report.  806*

9.   Lin, Y. H. and J. R.  Lawson,  "Treatment of Oily and Metal-
     Containing Wastewater."  Pollution Engineering, November
     1973.   Page 45-48.  807*

10.  Reap,  E.  J.,  Davis, G. M. ,  Duffy,  M.  J. and J.  H.Koon,
     "Wastewater Characteristics  and  Treatment  Technology for the
     Liquefactiion of Coal Using  H-Coal Process," Proceedings  of
     the  32nd Purdue Industrial Wastf Conference, May 1977.   654*

11.  FE/496-143 "Solvent Refined  Coal (SRC) Process," Qtr.  Tech.
     Progress Rpt., July 1 - Sept. 30, 1977.  January 1978.   Page
     27.   808*

12.  "Pretreatment of Industrial  Wastewater for Discharge into
     Municipal  Sewers," W. E. Eckenfelder,  Jr., C. E. Adams, Jr.,
     J.  H. Koon,  and R.  M.  Stein,  AWARE,  Inc.,  1977.   Page
     V-B/24/25.
13.  "Treatment of Petrochemical Wastewaters," E. D.  Oliver,
     Stanford Research Institute  Process  Economics Program Report
     No.   80, September 1972.  804*

14.  Eller,  J.  M. and E. F. Gloyna, "The  Role of Pretreatment  in
     the  Removal of Organics from Industrial Wastewater,"   Pro-
     ceedings of the 29th Purdue  Industrial Waste Conference, May
     1974.   801*
                              296

-------
 Flotation

 Flotation (1) is used to separate small amounts of fine particles
 or droplets from large quantities  of a liquid  stream or waste-
 water and to thicken some sludges.   Except for sludge thickening
 this description is based primarily on petroleum refinery experi-
 ence.  In flotation, very small gas bubbles are released beneath
 the liquid surface.  Rising bubbles adhere to the small particles
 and float them to the surface for collection.   Chemical floccu-
 lants and polymers may be added to enhance collection,  although
 in oil flotation it is desirable to avoid  inorganic flocculants
 so the floated oil can be directly recovered or burned.

 In practice, alum (2,3,4) or other coagulants are added at 25 to
 200 mg/1 together with < 1 to 40 mg/1 polymer (2,3,4,5,6).   Other
 appropriate design parameters are air-to-water or air-to-solids
 ratios of 0.01 to 0.1 Ib/lb, hydraulic loadings of 500 to 4,000
 gpd per square foot (2,3,4), air pressure of 25 to 70 psig
 (1,2,3), float detention time of 20 to 60 minutes (1,2,3),  re-
 cycle ratio of 20 to 50 percent (1,2,5) and,  for sludge thicken-
, ing, a solids loading of 1.3 to 7.7 lb/hr per square foot (4,7).

 There are three flotation systems in use:  dissolved air  flota-
 tion (DAF) with and  without recycle and  induced air flotation
 (IAF).  DAF with recycle is widely used for both particle separa-
 tion and sludge thickening (9).  IAF is preferred by Chevron (6)
 for particle separation.

 Figure  8-27 is a  flow schematic  of DAF  with  recycle  used for
 sludge thickening.

 The cleaned effluent is split  into "unit  effluent" and recycle
 streams and the recycle stream is pumped into an air dissolution
                               297

-------
to
10
00
                                           Ctmrtcsv Kninline-SatHlcnson
                 UNIT EFFLUENT
          AUX. RECYCLE CONNECTION
          (PRIMARY TANK OR
            PLANT EFFLUENT)
AIR FEED
                                            FLOTATION UNIT
                                       RECIRCULATION PUMP
                                              THICKENED SLUDGE
                                             	*-  DISCHARGE
                                   REAERATION PUMP
                                                   ^ UNIT FEED
                                                   ^SLUDGE
                                                    RECYCLE
                                                    FLOW
                                                              -RETENTION TANK
                                                              (AIR DISSOLUTION)
                                Figure 8-27.  Dissolved air flotation  system.*

                               * From Item 7 in  reference list

-------
tank under  pressure before joining the unit feed  sludge  stream.
Pressure  release  in the unit  allows  dissolved air  to  leave the
solution  and  float the solids.

Although  they differ physically and in capital  costs  DAF  and IAF
systems  rely  on the same principles for operation.   In  comparison
to DAF, however,  IAF has the  disadvantages of  large minimum
bubble size of about  500 to  1,000  micrometers versus  50  to 100
micrometers for DAF (1,8) and reshearing of the  oil  droplets and
floes by  the  rotor.  Although IAF capital cost  is  probably about
50 percent  of DAF capital cost,  DAF  with recycle  is considered
the system  of choice for oily waters and sludge  thickening since
it produces  fine bubbles and  thus  less float volume (1)  and
avoids emulsification of oils in dirty wastewater.

Oil Removal--
Oliver (2,  chapter 5) provides  an  equipment list  and  costs for
DAF for  oil removal.  Major equipment sizes and  utilities  for a 2
MGD capacity  DAF  operating on API separator effluent  are given in
TABLE 8-28.  Expected efficiencies are 85 to 95 percent  oil re-
moval and 70  to 75 percent solids removal.   Operating conditions
do not favor  extensive oxidation of BOD and COD  during  flotation.
Power requirements are estimated  at  less than one  hp/MGD.  The
design is  based  on  residence  times of 15 and 20  minutes for
flocculation  and  flotation, respectively.  Capital  and  operating
costs were  based  on  twin flocculation and flotation  chambers,
respectively  14 feet x 38 feet and 14. feet  x 60  feet, each  with a
single 4 foot exit  section.   Depth was  7 feet  with 2   feet
freeboard.  Walls were 8 inch reinforced concrete  and floors were
6 inch.

Chevron (6)  has  extensive experience  with IAF  for both oil
separation  (secondary de-oiling) and effluent polishing  (solids
                              299

-------
                   TABLE 8-28.  AIR FLOTATION.
         MAJOR PROCESS EQUIPMENT AND UTILITIES SUMMARY*
             Plant Capacity:  2 Million U.S. Gal/Day
                 Wastewater at 0.5 Stream Factor
                       (UMGD Design Flow)
         Name
                     Major Process Equipment
   Size
Special Equipment
Flooculation chambers
Flotation chambers
Scum skimmers  (2)
Precoat filter
Tanks
Alum

Vessels
Pressure retention vessel
Miscellaneous Equipment
Flash mixers(2)
Paddle mixers (6)
Screw conveyors  (2)
4 MOD
4 MOD
1M x 60 ft
25 sq ft

 Volume
  (gal)
2,500


3,600

   Size

2 bhp
1 bhp
15 ft
Material of
  Construction

 Concrete
 Concrete
 Carbon steel
 Carbon steel
 Rubber lined
 Carbon steel
 Carbon steel
 Carbon steel
 Carbon steel
Pumps
Feed - 4, including 2 operating, 2 spares,
  22 operating bhp.
Process - 4, including 2 operating, 2 spares,
  78 operating bhp.

                       Utilities Summary**

                       Battery Limits      Feed
                           Total	     Section
Electricity (kw)           100               26
                         Process
                         Section
                            71
«  Item 2 in reference list
** No peaks in utilities demands; generating facilities  are  sized
   for average consumptions
                               300

-------
removal).   At  one refinery,  oil  reduction experience  on  API
separator effluent was  as  follows:

          Flow,                Avg. Oil Content,  mg/1
          GPM                      In        Out*
     3,000-4,000 Actual          410          27
     3,000 Design                100          20
•Polyelectrolyto  dosage was 5 to 15 mg/1.

:Thus,  80 percent  removal  of secondary oil was  the  design basis
and over 90 percent  was achieved.

Sludge Thickening—
Sludge thickening by flotation  is  based primarily  on municipal
DAF studies reported in an EPA document (7).   In operation, unit
effluent is aerated  and pressurized and then  a controlled  flow  is
metered into a mixing chamber where it joins  incoming  sludge feed
and any polyelectrolytes  or other chemicals.  Sludge  is floated
as a blanket 8 to 24 inches thick where it thickens  by emergence
and drainage.   Thickened  sludge is removed by a  skimming device.
Bottom sludge collectors  are  provided to remove  grit and heavy
materials.

Air pressure depends on the unit design but  is  optimized in the
range  of about 40 to 70 psig,  by observing that  increases  in
pressure result in greater separation and solids concentration  up
to the pressure where further increases cause floe  destruction.
Recycle ratio is  optimized at about 40 percent.   Increasing the
recycle requires  larger equipment,  increases  capital  and
operating costs,  and dilutes  the influent sludge,  but dissolves
more air and thus increases the air-to-solids ratio. Float  solids
increase,  and effluent  SS decrease, as float  residence time

                              301

-------
 increases  up to,  but  not  over,  3  hours.   Finally  the
 air-to-solids ratio  influences  the  float  solids  obtained
 depending  on  the  sludge quality.   Figure 8-28 shows the float
 solids concentration versus  air-to-solids ratio for  several
 sludges.  Note that a sludge  viscosity index (SVI) below 100
 generally  indicates that the  sludge will flocculate and settle
 well.  Reference 7 also gives  operational results, details for
 integrating a DAF sludge thickener into the  wastewater treatment
 plant,  equipment lists, a  design example and generalized costs.

 Both API and DAF/IAF skimmings  and  sludges contain recoverable
 oils but treatment is required  to  separate them.  Chapter 8 of
 reference 10, the API Manual  on Disposal of Refinery Wastes,
 treats  oil recovery from flotation skimmings.

 References—

 1.   Eckenfelder, W.E.,  Adams,  C.E., Jr., Koon, J.H., Stein,
     R.M., "Pretreatment of Industrial Wastewater for Discharge
     into Municipal Sewers," AWARE,  Inc., 1977, p.  III-E/1-E/14.
     679*

2.   Oliver,  E.D., "Treatment of  Petrochemical Wastewaters , "
     Stanford Research  Institute  Process Economics  Program
     Report, No.   80, September 1972, p 98.   80M«

3.   EPA 625/1-75-003a,  "Process  Design Manual for Suspended
     Solids Removal," January 1975,  Chapter  7,  p 23-27.   873*

4.   Beisinger, M.G., Vining, T.S.,  and Shell,  G.L., "Industrial Ex-
     perience With Dissolved Air Flotation," 29th Purdue Indus-
     trial Waste  Conference, 1974.  886*
                             302

-------
  0.07


  0.06





  0.05





  0'04
CO
Q
O

S
E 0.03
<



  0.02




  0.01
             I
 CHEMICAL
WASTE WATER
  SLUDGE
SEWAGE SLUDGE
   SVI 400
**~
 PULP AND PAPER |
 WASTE WATER
 SLUDGE
         O
                                  HYPOTHETICAL
                                  EXTRAPOLATION
                         SEWAGE SLUDGE
                             SVI 85
                     234

                     SOLIDS IN FLOAT, (%)
      Figure  8-28.  Influence of  air-to-solids ratio
                     on  float solids content.*

      *From Item 7 in reference  list
                        303

-------
5.   Luthy, R.G., Selleck,  R.E.,  and Galloway, T.R., "Removal of
     Emulsified Oil with Organic  Coagulants and Dissolved  Air
     Flotation", JWPCF,  February 1978.  885»

6.   Davies, B.T., and Vose, R.W.,  "Custom Designs Cut Effluent
     Treating Costs.  Case Histories  at Chevron U.S.A.,  Inc."
     Presented at 32nd Purdue Industrial Waste Conference,  May
     1977.  653*

7.   EPA  625/1-74-006,  "Process Design  Manual  For Sludge
     Treatment and Disposal, " January 1974, Chapter U.  868*

8.   Byeseda, J.J., Chan, K.,  Sylvester,  N.D., "Induced  Air
     Flotation of Oil-Water Emulsions:  Preliminary Investigation
     of Operating Parameters," Tech. Rep. No.  76-7, University of
     Tulsa.  650*

9.   Gehr, R., Henry, J.G., "Measuring  and Predicting  Flotation
     Performance."  JWPCF, February 1978. 887*

10.   "Manual on Disposal of  Refinery  Wastes, Volume  on  Liquid
     Wastes,"  American  Petroleum Institute, 1969,  Chapter 8.
     803*
    •Pullman Kellogg Reference File number

                             304

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Biological Oxidation

Biological oxidation, the bacterial destruction of organic matter
in wastewater streams  under aerobic conditions,  is the  most
important and widely used of the wastewater treatment  processes.
Many variations of  the basic process have been developed for
treatment of specific types of contaminants in  waters,  for in-
creasing the efficiency of removal of organic  contaminants and
for decreasing costs.  Most of the variations  fall  into  the two
general categories of fixed film systems, in which bacteria grow
on a solid inert  substrate, and  suspended growth  systems,, in
which the bacterial  mass is flocculant and  suspended  in the
reactor liquid.  Fixed film systems include trickling filters,
rotating biological contactors and fluid bed reactors.  Suspended
growth systems include  activated  sludge processes  and  aerobic
sludge digestion.  Rotating biological contactors and activated
carbon enhanced activated sludge processes  will  be  discussed in
detail later in this section;  only conventional  and  pure oxygen
activated sludge systems are considered here.

Industrial biological wastewater systems usually include treat-
ment steps that precede the oxidation process.   Pretreatment may
include separation of light and heavy oils, flow equalization,
flocculation/flotation by dissolved  air flotation (DAF)  or
induced  air flotation  (IAF),  solvent  extraction and  gas
stripping.

Comparison of fixed film and suspended growth systems  shows that
each has certain  characteristic advantages and disadvantages.
For example, fixed  film  systems are  especially useful for
"roughing" operations and general  first-stage  biological treat-
ment because the attached bio-films are more  resistant  to phy-
sical and chemical shock than are  flocculant suspended growths.
Further,  the fixed  film systems  produce  less  excess  biomass
(sludge)  per unit of  BOD  removed  and the  sludges are more
                             305

-------
compact.   On  the  other hand,  suspended growth  systems  are
generally capable of reducing  the effluent BOD and  COD to lower
levels and have  higher  removal efficiencies for nutrients and
metals as well as for dissolved organics.  TABLE 8-29 compares
the two systems, with  the  trickling filter representing fixed
film and activated sludge representing suspended  growth.

Biological oxidation  systems have the advantages of low cost
installation and operation,  the ability to effectively oxidize
very dilute streams and great  operational flexibility.   They also
have many weaknesses such as susceptibility to  toxicity,  physical
and chemical upsets, hydraulic washout, organic  load variations,
and equipment failures,  any of which may interfere with bacterial
growth and the efficiency of BOD and COD removal.   In addition,
biological oxidation systems  cannot  achieve  BOD,  COD, and
suspended solids levels below their residual  limitations and
cannot effectively remove most metals and those materials that
are not readily biodegradable.

Application of Biological Oxidation to Coal Wastewaters—
The sour waters from gasification processes producing phenols,
oils and tars and from  liquefaction processes  are expected to  be
similar to coke waste liquors. After stripping  C02 completely,
and stripping H-S and  NH3 down to required bacterial nutrient
levels,  the sour water  will  be pretreated for oil  recovery and
flow equalization and will  then be introduced into  a fixed film
biological oxidation process.   A trickling filter is assumed for
this description.   Systems  with phenol recovery  will have
influent phenol concentrations below about 600 mg/1  and roughing
filters should readily  reduce  this by 30 to 60 percent (1-399*)
(4).
•Item 1  in reference list,  page  399
                              306

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                                        TftPlE 8-29.   BIOLOGICAL OXIDATION  SlfSTKM  EFFICIENCIES  (1)
U)
o
System
   (2)


   TF
   TF
   AAS
   PDAS
   AAS
   AAS

   AAS

   AAS

   TF


   AAS
        Influent
Flow    BOD    COD
HOP     mg/1   mg/1
1.8
1.4
3.9
4.4
 375
  77
 254
  84
4140
1890

2600

2070

3000
3070

4180

3180




 720
Effluent
BOD
raj/1
68
44
33
10
146
26
36
24
750
COD
mg/1
_
-
-
-
-
360
310
380
_
Removal
BOD
_%_
74*
43*
87*
88*
97
99
99
99
75
COD
-*-
_
-
-
-
-
88
93
88
_
                                                                       72
                                                                                    90
                                                                                                  Remarks
                                                                                             Low rate. Strong waste
                                                                                             High rate. Weak waste
                                                                                             Weak waste
                                                                                             Pilot test.
                                                                                             Pilot test.
                                                               Strong liquor
                                                               Food/mass =
                                                                    0.06
                                                    Pilot test. Food/mass =
                                                                    0.17
                                                    Pilot test. Food/mass =
                                                                    0.22
                                                    Pilot test. Candy waste on
                                                     Surfpac  (Dow filter
                                                     packing)
                                                    Permanganate removals of
                                                     commercial dephenolated
                                                     Lurgi wastewater in
                                                     pilot units
Ref.
CO

1, 4-4
1, 4-23
1, 5-3
1, 5-20
3, 873

4, 22

4. 22

4, 22
                                                                                                                        5. 890
                                                                                                                        6, 104
                        (1)  All  efficiencies include secondary clarification.  Those marked * also  include primary clarifiers at
                            30*  removal
                        (2)  TF = Trickling filter; AAS = Air activated  sludge; POAS ** Pure oxygen activated sludge
                        (3)  M =  Municipal; C = Coke oven liquor;  L =  Liquefaction plant; I = Industrial; G = Lurgi gasification
                        (4)  1, 4-4  refers to Item 1 in the reference  list, page 4-4

-------
 Units processing undephenolized liquor containing  perhaps 6,000
 mg/1  of  phenol  will  be oxygen transfer limited  (1-U01)  for
 economic height  to width ratios and must be designed and operated
 with forced  ventilation.  Although there is  some  concern that
 roughing filters will  have to  use effluent  recycle  for
 temperature  control (1-399)  rather  than dilution and seeding, it
 seems possible  that  the large equalization  basins anticipated
 (2-880) (3-35) will provide  all the cooling needed.

 Activated Sludge—
 Activated sludge  processes should be able  to  handle the same
 waters from coal  conversion processes with  or without  phenol
 extraction,  but  large equalization tanks will  be  required for
 reliable operation  (1-363) (3-35).  In the  activated  sludge
 process the  influent water stream mixes with a return stream  from
 the secondary clarifier in the system.  The return stream  is  part
 of the clarifier underflow and carries with  it actively growing
 biomass.   The mixed stream is retained sufficiently long in an
 aeration  basin, while air is bubbled through the liquid, to allow
 destruction  of the organic materials in the  influent stream and
 then flows to the secondary  clarifier.  The  clarifier overflow,
 devoid of biomass,  is  discharged for process  use or further
 treatment as required  in the plant process  flow  scheme.  The
 clarifier underflow  (sludge) is divided into return and waste
 activated sludge.  Clarifier underflow is so  dilute,  at  1 to 3
 percent solids, that no other recycle is usually required  and the
 return flow may equal the wastewater flow.  If phenol extraction
 is not used, it will probably be more economical to precede the
activated sludge  (AS)  units with roughing  filters  or other
pretreatment rather  than  attempt to  design  them  to  handle
concentrations of 6,000  mg/1 or more of phenol directly  (1-396).
•Item 1 in reference list,  page 399
                             308

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High Purity  Oxygen Activated Sludge (HPOAS) processes are modifi-
cations  of AS  systems with no conceptual  differences.  The econo-
mic advantages may be especially attractive  at coal conversion
plants using onsite oxygen generation for the gasifiers. Advan-
tages of HPOAS besides economy are  plant compactness,  lowered
effluent residuals and complete enclosure for good air emissions
control  and  weather protection.  The  advantage  of good control  of
gaseous  emissions from activated sludge processes is particularly
important because of possible  effects on health of polynuclear
aromatic compounds  in the emissions.   Weather protection  is
important in maintaining the optimum temperature for bacterial
growth,  particularly in the winter  months (3-35).

AS Costs—
The costs of biological oxidation  depend primarily on  the  flow
rate and concentration of the wastes  and  secondarily on the waste
variability.  Most  wastewater  treatment plant designs  include
equalization,  neutralization and flotation or other  pretreatment
as well  as  secondary clarifiers after the biological oxidation
stages.   Costs (1976) for 3 MGD capacity pJLants treating stripped
sour  water containing 6,300 mg/1  phenol  were estimated  at
$3.2/1,000  gallons for air activated sludge  (AAS),  $3.6/1,000
gallons for high purity oxygen activated sludge  (HPOAS) and
$3.1/1,000  gallons for active trickling filter  plus high purity
oxygen activated sludge (ATF-HPOAS)  systems (1-377,-295,-405) .
The'-HPOAS  and ATF-HPOAS systems  were  designed as  two-stage
systems.   The AAS was a one-stage  system scaled  up from  coke
plant weak  ammonia liquor data.  The costs included 7-day
retention time equalization tanks  for all plants.  Sludge age  or
solids  retention times were  11  days, 3  2/3 days and 3  2/3  days
for AAS, HPOAS,  and ATF-HPOAS systems, respectively.  Comparable,
i.e., one-stage air-activated sludge,  plants  for  several  coke
weak  ammonia  liquor wastes  had sludge  ages from 1 to  4.8  days
(1-367).
                              309

-------
 Case Histories of Biological Oxidation--
 Lurgi Wastewater—R.  Cooke and P. W. Graham  (6) performed pilot
 waste treatment studies  with  biological and lime treatment  on
 stripped dephenolated sour water  from a Lurgi high  pressure
 process in  the early-to-mid 1960's.  Conventional one and two
 stage air activated sludge (AAS) processes were used and removed
 up  to  91*  percent  of the phenolics  and 99 percent of  the
 thiocyanates.

 The sour water source was the spent liquor outlet of the ammonia
 still  from the Dorsten,  Germany Lurgi plant.  Five  batch
 deliveries  of about 1,000 gallons each were made by tanker, with
 half delivered to each of two labs.  Unfortunately, up to 7 days'
 storage may have occurred prior to  dephenolization and ammonia
 recovery.   The first  delivery showed visible changes between
 delivery of half the load (500 gallons) in London and  the other
 half subsequently in  Nottingham.   The liquor became  darker  in
 color and more difficult  to treat.  A "significant" reduction  in
 phenol occurred.   Subsequent  deliveries were  made  in  a
 two-compartment tanker.

Ten small  samples  were taken  over  a  period of a  month  to
determine sample variability.  There was an unfortunate  delay  of
4 to 7  weeks between sampling and analysis for these samples.

The dephenolized liquor  contained  only 5 to 10 percent of the
original phenol concentrations.   Dephenolization via the
Phenosolvan process preferentially  removed monohydric  phenols,
leaving catechol and resorcinol as most of the remaining "phenol"
content to be removed or treated.  TABLE 8-30 summarizes the
analyses of the feed liquor by batch and includes data  on small
samples taken to show feed variation.  Total  phenols were approx-
imately 10 times monohydric  phenols.   Biotreatability was
adequately shown in  that two  different bench scale biological
oxidation air activated sludge units were successfully  operated

                            310

-------
                                        TABLE  6-30._   ANALYSES OF  SAMPLES  OF DEPHEHOLATED LURGI  LIQUOH  (a)
U>
Batch

1
2
Unshifted Unshifted

Laboratory (b)
Free ammonia (Mil )
Fixed ammonia (MH.)
Monohydric phenols
(CgH5OH)
Total phenols
(CgH5OH)
Thiocyanate (CMS)
Thiosulphate (5,0 •>)
Sulphide (S)
Organic carbon (C)
Chloride (CD
Permanganate value
(4 hr)
pH value
Bacterial count
(thousands of
organisms per ml)

G.C.
220
1140

56

390
161
105
- ,
676
2400

710
7.1


620

N.C.B. G.C.
50 190
1190 1190

40 IB

263 284
164 222
23
Nil
555
2300 2340

607 686
6.9 8.0


450

N.C.B.
i
-------
 on Lurgi wastes.   Figures 8-29(a)  and 8-29(b) show flow  sche-
 matics, respectively, for the Gas Council and  National Coal Board
 units.  Results were quite similar despite differences  in  the
 units.  TABLES 8-31(a) and 8-31(b) summarize data for biotreat-
 ment performed, respectively, before and after ammonia  removal.
 Both units  achieved  approximately  99 percent removal  of  thio-
 cyanate  and about 91*  percent  total phenolics removal.   Lime
 treatment  was applied by boiling the  effluent  with  lime.
 Biotreatability was adequate when biological oxidation  preceded
 and also when it followed lime treatment.  In general pre-limed
 effluents  were easier to treat biologically than  un-limed
 effluents.  Many other studies were performed as a part of this
 work, including BOD removal, nutrient requirements and  toxicity
 and  bacterial tests.  The  authors  concluded that  biological
 treatment can be performed  with no great difficulty.

 Synthane Wastewaters—The Pittsburgh Energy Research Center of
 DOE is studying Synthane wastewater treatability.   In  a  recent
 report (7)  the wastewaters  from  Synthane, a producer of  p/o/t,
 were described as similar in  appearance and analysis to coke
 plant wastes, being dark colored and  odorous.   Laboratory
 pretreatment was used to prepare Synthane PDU wastewaters from
 Montana Rosebud coal  for biological oxidation  studies. Pretreat-
ment included settling,. pH adjustment, alum addition,and  air
 stripping to about  500 mg/1 residual NH ,.

Laboratory activated  sludge biological oxidation  units were
seeded with coke plant sludge to start them.   Studies were  based
on total  organic carbon (TOC) but COD and phenol were also mea-
sured.   Food to microorganism ratio (F/M) was varied by varying
feed dilution, an undesirable  technique  because  inhibitory
substances may affect treatability  variably, depending   on  the
degree of dilution.   Dilution was necessary  because the  supplies
                             312

-------
  'Nitrogen
1 OCL micro -pump Air flowmeter
JT- _-_"-_"•
1- - ~ 	 ~* 	 1 1 — *-
Alkali reservoir
V k -ir-
\ ]f
" Vfe
^ Xttfl '
-£l vife
ir blower actuated
y pH control unit
. t
Burette |i
Ml
Stirrer t3 jjj
nl y
- rJ|Vl
nil
*
1 •*
Oiffuser Scraper
L A/
Lr ki^
Aerated tank I Settling

-------
                                          TABLE 8-31.__AVERAGERESULTS_OF_TREATHENT»
                (a).   Biological Treatment followed by ammonia removal
u>
H




Total ammonia (NH, )
Monohydric phenols (C6H5OH)
Total phenols (CSH5OHJ
Thiocyanate (CNS7
Chloride (Cl)
Permanganate value (4 hr)
pH value
(b). Ammonia removal followed




Total ammonia (NH5)
Monohydrio phenols (C6H5OH)
Total phenols (C6H5OH}
Thiocyanate (CNS7
Chloride (Cl)
Permanganate value (4 hr)
pH value
Untreated
liquor

(ppm)
1110
27
281
151
2370
570
7.7
by biological
Untreated
liquor

(ppm)
mo
27
281
151
2370
570
7.7
Biologically- treated
effluent

(ppm)
1190
63
2
2110
127
7.1
treatment

Pre-limed

(ppm)
10
16
66
117
2320
293
8.0
Removal
(*)
89
78
99
--
78
* '"


liquor
Removal
(*>

11
77
5
--
19
—
Post-limed effluent
Removal
(ppm> (%)
90
3 89
18 91
1 99
2180
50 91
7.3

Biologically treated
pre-limed effluent
Removal
(ppm) <*)
101
2 93
23 92
2 99'
2130
57 90
7.7
                •From Item 6 in reference list

-------
of wastewater  from  the Synthane PDU were limited.  Nutrients were
supplied by phosphate-supplemented  settled primary  municipal
sewage.   Hydraulic  detention  time  was one day and  steady state
operation was  usually attained in four days.

Results  were  presented for  COD,  phenol, and TOC  for two  F/M
ratios and  are  tabulated below.   Note the relatively  high
effluent  residuals  for COD and TOC.

                SYNTHANE BIOLOGICAL TREATABILITY


COD
Phenol
TOC
COD
Phenol
TOC

F/M
0.71
0.71
0.71
0.20
0.20
0.20
Influent
mg/1
5,690
1,205
1,960
1,250
175
500
Effluent
mg/1
2.030
25
850
390
<1
150
In summary,  Synthane  wastewaters are clearly  amenable to treat-
ment  by  biological oxidation,  although dilution  and nutrient
addition via municipal  sewage may have affected results slightly.
High residuals from one-stage treatment may require  second stage
AS and/or tertiary treatment steps.

H-Coal Wastewaters—  The  H-Coal  liquefaction process hydrotreats
coal slurry in an ebullated bed  catalytic reactor at about 850° F
and 3000 psig.  Sour  waters are  produced from oxygen and residual
moisture in the coal  and  condense and separate  when the reactor
                             315

-------
effluent  gases are processed for product recovery.  AWARE, Inc.
(8)  designed an AS wastewater treatment plant  for a 600 TPD pilot
plant that  is under  construction  at Cattlettsburg, Ky.   Their
design was  based  on  the  piLot  plant design, combining various
blowdowns and runoffs so  the foul water constituted 22 percent  of
the total.

AWARE experimental work was carried out on foul water  from the
Trenton, N.J. PDU collected  during a mild hydrogenation run
appropriate for  fuel  oil  production.  Illinois No. 6 coal  is
inferred  to be the source of wastewater from  the statement that
coal pile runoff  was simulated  by contacting Illinois No. 6.  The
PDU sour  waters  were steam stripped with  reflux at  first high
(10.5), then low  (6.5) pH.   Stripped sour  waters were  combined
with actual and simulated  blowdc  ns  and runoff and then
pretreated  with  induced air flotation followed by  neutralization
for oil removal.  Stripping H2S from the sour water  reduced  the
COD from 88,600  mg/1 to 26,500  mg/1, essentially reducing  the COD
by 2 mg/1 for each mg/1 of H2S  removed.  Combined  wastewater  was
treated  in 20-liter plastic  AS  units  and studies  included
pretreatment for phenol removal  by  resin, startup/shutdown
simulations and F/M ratio  variations.   Many  other studies
addressed  IAF,  emulsion-breaking, neutralization,  stripping,
oxygen transfer,  sludge production, sludge handling and  carbon
adsorption. Representative  results for  H-Coal biological
oxidation are tabulated on the  following page.
                              316

-------
                H-COAL BIOLOGICAL  TREATABILITY
Influent
F/M
0.06
0.06
0.06
0.17
0.17
0.17
0.22
0.22
0.22
mg/1
3,
1,

4,
2,
1,
3,
2,

070
890
750
180
600
450
180
070
760
Effluent
mg/1
360
26
0.7
310
36
0.3
380
24
0.7
  COD
  BOD
  Phenol

  COD
  BOD
  Phenol

  COD
  BOD
  Phenol

This study  shows  that combined H-Coal wastewaters were  biologi-
cally treatable and that the low residuals  achieved  imply attrac-
tive economics for water treatment for reuse  or  discharge.

Coke Plant  Liquors— The literature contains  several  reports and
studies on  the application  of  activated sludge systems to coke
plant ammonia  liquors (3, 9, 10,11) and at least  one  paper (12)
describing the  application  of  this  technology  to  coal
gasification.   The  latter  paper by  Parsons and Nolde  (12)
describes  the  historical development of biological  wastewater
treatment  from coal gas  plants to coke plants  and  producer gas
plants.  They  observe that  recent refinements in bio-treatment of
coke plant  liquor will be transferable to p/o/t-producing coal
gasification processes.
                               317

-------
The paper by an AWARE team (3)  describes experiments  on  two coke
plant wastes  and  compares results with EPA Coke  Plant  "Best
Practical Control  Technology Currently Available"  guidelines.
The authors  give a summary of operating data from six  full  scale
activated sludge plants and state that equalization  and cooling
should be the  major  design considerations.  The AWARE studies
found that  effluent  ammonia concentration was difficult  to
control.  Low F/M ratios, below that needed for  BOD  removal,
enhanced  cyanide  and phenol  reduction  and improved sludge
characteristics.

A second  AWARE paper by  Carl  Adams (9) presented results  of
activated sludge treatment studies on a synthesized  waste  for a
coke plant flash evaporator condensate.  The condensate  was known
to contain concentrated ammonia and phenolics.  This  study  found
phenolics could be reduced from several thousand  mg/1 to less
than 0.5  mg/1  with adequate equalization and that above  F/M =0.3
nitrification  ceases.

Reference 10 is an early U.S. study of a coke liquor activated
sludge pilot  plant.   Successful results led  to design  and
construction of a full scale plant.  An EPA report  (11) details
pilot studies  made to achieve nitrogen removal via  a  two-sludge
system.   TABLE 8-32  summarizes  some of the results  of  these
studies.

Rotating  Biological Contactors—
Rotating  Biological Contactors (RBC) are  a form of  fixed film
biological treatment  process where the bio-solids grow attached
to surfaces of discs  that  are attached to a horizontal shaft and
that are  slowly rotating,  partly submerged,  in  a  treatment  tank.
RBC's therefore have  many of the characteristics  of trickling
filters,  including resistance to sudden overloads and  to slugs of
toxic material.
                              318

-------
                                        TAPLB  8-32.  HEPnESRHTATIVE COKE  LIQUOR TREATABILm  STUDIES
Ui

Ref.
3 Plant A



3 Plant B



9 Evaporator
Condensate


10 Activated
Sludge


COD
BOD
TOC
Phenol
COD
BOD
TOC
Phenol
COD
BOD
TOC
Phenol
Phenol**


I

0.24
0.24
0.24
0.21
0.21
0.21
0.21
0.174
0.174
0.174
0.174
0.73

F/H
II*

0.61
0.61
0.61
0.36
0.38
0.38
0.38
0.198
0.198
0.198
0.198
1.14

Influent, mij/l
III

1.05
1.05
1.05




0.286
0.286
0.286
0.286
1.42

I

4140
1400
1.16
1950
1880
530
430
7976
6170
2108
3316
3450

II*

4140
1400
1.16
1950
1880
530
430
8233
6368
2260
3266
3700

III

4140
1400
1.16




8341
6666
2260
3266
3500

Effluent,
I

146
334
0.17
263
65
87
0.08
87
26
26
1.0
0.2

II»

107
303
0.18
313
119
113
0.43
361
76
128
<0.1
0.4

ms/1
III

499
414
0.27




468
64
256
0.55
0.55

                       * For Reference 9, Case  II was the first stage of a 2 stage unit
                       **F/M values computed as 1.6 times the phenol loading

-------
Figure 8-30(a)  is  a  flow sheet for  a  Chevron  (13) refinery
wastewater treatment system incorporating RBC's.   The RBC's are
preceded  by  an  equalizing tank and followed  by  a clarifier.
Figure 8-30(b) is a schematic of this installation showing the
RBC in four stages and the clarifier following the  unit.

The feed  water enters a tank in which the  rotating surfaces or
discs are partially immersed.  Rotation is  1  to 2 rpm (13, 14,
16),  submersion  is about 40 percent and  head loss is  about 6
inches.   Units  with  200  discs 3/4 inch thick and 11  feet in
diameter  have a  surface  area of 38,000 square feet in a cell
about 12  feet x  25  feet.   Biological slimes  grow over  all the
wetted surfaces and the rotation oxygenates  not only the films
and adherent water but also the tank  contents.  Staging is
usually provided  by internal baffle** with  weirs.  Excess bio-
logical growth sloughs off the discs and leaves the RBC with the
effluent.   If suspended biological growth  is  avoided,  the RBC
sloughings will settle satisfactorily in the following clarifier.
The clarifier is usually designed for 700 to 800 gallons  per day
per square foot (13, 16) overflow rate and  an  underflow solids
content of 1  to 2 percent.  These solids are not recycled back to
the RBC in usual practice  because the discs almost  never  shed all
their growth  simultaneously and recycle is not needed.

RBC Capabilities—
RBC's have several  inherent advantages over  other  aerobic
biological treatment methods,  such as resistance  to upsets, low
energy needs, compactness, modular construction, easy staging and
weather protection.   The holding tank in each RBC  stage provides
a diluting and surge-absorbing reservoir which contributes  to its
stability.  Most other fixed film bio-reactors  do not have a
comparable reservoir.   Weather protection,  provided by a cover,
not only  enhances low temperature operations  and prevents ice
damage but also collects  aerosols  and mists  generated by
splashing  and permits  easy ventilation control.

                              320

-------
OJ
            NORTH PROCESS WEST AND
            ,SQUTH PROCESS WEST SEWER
            ,EAST VftRD FORCE
            SOUTH PROCESS EAST AND
            .WEST N.P.E. SEWER
            .EAST N.P.E. SEHEK_
                                                                                                         OFFSET RETURN
                                                                                                        NORMALLY NO FLOW
                                                                                                         3000 GPH MAX
                                                                                                            TO WOODBRJDGE CREEK
                                               TO
                                            RECOVERED OIL
                 Figure 8-30a.-  Effluent treating system  at  Refinery  B,  Chevron  USA.

-------
                   Influent
OJ
to
to
Effluent
                                           RBC Units
                                                                   Sloughed
                                                                   Biosolids
                                                                    Sludge
                 Figure 8-30(b).   Simplified flow  scheme of RBC treatment  of

                                   petroleum refinery wastewater.*
                 *From Item 13 in reference list

-------
RBC Applications—
RBC's have not been  used commercially on U.S. coal  conversion
plant  or coke oven  wastewaters  but recently they  have  been
evaluated and installed for several U.  S.  refineries (13, 14, 15,
16).   Applications  and case histories are therefore  based on
refinery experience.  For coal conversion  wastewaters  RBC's would
probably be used for second stage biological oxidation,  following
AAS or HPOAS treatment.

Chevron pioneered  the use of RBC's  for  refinery wastewaters.
Disc area is estimated by use of  McAliley's  (17) method  wh-ich
assumes that BOD removal is proportional to  BOD concentration in
each stage and that the stage acts as a back-mixed  reactor:

          R = M/A (BODInfluent - BODEffiuent>
            = P(BODEffluent)/(K + BODEffluent)

  where   R = specific BOD removal rate per unit area of medium,
              pounds per day per square foot
          C = concentration of BOD in an  RBC stage
              = BODEffluent
          M = wastewater flow, million pounds per  day
          A = area of an RBC stage, square  feet
          P = a constant = maximum value  of R at infinite BOD
          K * a constant = BOD at which R = P/2

Figure 8-31(a) is  a plot of  specific removal rate  versus BOD
concentration for a staged Chevron RBC pilot  plant.   The solid
curve  shown was obtained from McAliley's equation.   The  equation
can be  converted into an equation of a straight line by taking
the reciprocal and  separating  variables.   Figure 8-31(b)  is  a
plot of 1/R versus 1/C where the y-intercept  and x-intercept of
the best straight line through  the data represent 1/P  and 1/K,
respectively.

                             323

-------
 o
•»•»
 ra

CSS
03
>
o

S
G>
o
ea
CO
                      McAliley Model
                  BOD  Concentration  in an
                          RBC  Stage
            Figure  8-31(a).  BOD removal rate versus

                            concentration.*
*From Item 12 in reference list
                             324

-------
                                          Least Squares Fit
         Reciprocal BOD  Concentration
      Figure 8-31(b).   Reciprocal BOD removal rate versus
                       reciprocal BOD concentration.*

*From Item 13 in reference list

                             325

-------
Figure 8-31(c)  is a plot of measured  BOD versus BOD predicted  by
the equation.   The fit indicates that this model, similar to  the
Monod bio-kinetic model, represents the data well.

Chevron believes (13) that RBC units  for refinery service should
be designed  so  that:
     (a)   The overall BOD removal rate is  0.002-0.003 lb/day/
          square foot.
     (b)   The BOD loading applied to  the first RBC stage should
          not exceed 0.012-0.015 Ib/day/square foot.
Chevron states  that these factors, though tentative, should  avoid
excess and/or anaerobic bio-growth and mechanical overload.

Phillips  Petroleum (15) found oxygen  transfer to be essentially
independent  of  disc  rotational  speed above 1 to 2 rpm (Figure
8-32)  and found that supplemental in-tank aeration would only be
necessary if soluble COD exceeded  200  mg/1.   Phillips also
established  that hydraulic loading up to  1  gpd/square foot  was
low enough  to  meet  permit limits of BOD = 39, COD  =  190  and
phenols = 0.28 mg/1.  Whereas Chevron reported 0.002 to 0.003 Ib
BOD/day/square  foot  organic removal, Phillips found 0.0011 to
0.0042 Ib COD/day/square foot  organic removal.  Phillips also
found  that whereas nearly all soluble BOD could be removed  over a
wide range of hydraulic and organic loadings, at low loadings
nitrification resulted in up to 99 percent ammonia removal  but at
high loadings ammonia removal  fell to zero.  Figure 8-33  shows
the ammonia  removal efficiency versus hydraulic loading.

High hydraulic  and organic loadings  resulted in an increase in
COD in the  plant  effluent  even though soluble BOD  removal
remained  high.  Figure 8-34 shows soluble COD removal versus  RBC
stage for four pilot studies  and one full-scale study.    The
effect of higher loading is clear although  the full-scale  plant
(curve E) performance fell below the performance of the  pilot
                              326

-------
        ISO
        160
        140
    c
    o
    z:   120
    CO
    u
    c
    o
    o
    o
    o
        100
80
        60
        40
        20
                                     This Line Represents
                                     a Perfect Correlation-
                                                             I
               20    40     60    80   100   120    140

                    Actual  BOD Concentration, ppm
                                              160    ISO
             Figure 8-31 (c).   Accuracy of RBC  model:
                                predicted versus actual BOD*
*From  Item 13 in  reference  list
                                 327

-------
              OXYGEN TRANSFER RATE
                   IN STAGE 12
                 {mg O_/min/m )
U)
M
00
1 1 II 1
0 24 6 8 10
1 1 1 1 1
0 10 20 30 40
i 1 J 1 .1
1
12 (RPM)
(M/MIN)
                                               10      60       90      120   (FT/MIN)

                                                 DISC ROTATIONAL SPEED
              Figure 8-32.  Relationship of oxygen transfer rate in the first  stage  of
                            the RBC pilot unit versus rotational speed.*
              *From Item 15 in reference list

-------
u>
to
                 NH3 -N

                 REMOVAL, %
                             100
                              80
                              60
                              40
                              20
                                                                                      •6
                                         70
140
210
280
350
420
                                    HYDRAULIC LOADING  (LITERS/DAY/in  )
                     Figure 8-33.   Ammonia nitrogen removal versus hydraulic
                                   loading in the RBC treatment unit.*
                     *From Item 15 in reference list

-------
 OJ
• UJ
 o
                 ACCUMULATIVE
                 SOLUBLE COD
                 REMOVAL  (%)
                                50
                                40
                                30
                                20
                                10
        PILOT STUDIES
          A-155 L/DAY/m*; 129 SCOD FEED
          B-224 L/DAY/nu; 101 SCOD FEED
          C-411 L/DAY/nu;  97 SCOD FEED
          D-411 L/DAY/m  ; 205 SCOD FEED
        FULL SCALE OPERATIONS
          E-155 L/DAY/m; 127 SCOD FEED
RBC STAGE
          Figure 8-34.  Comparison of soluble COD removal versus hydraulic  loading.
                        through the RBC unit.*
          *From Item 15 in reference list

-------
plant (curve A) operating at the same loading.   Figures  8-35 and
8-36 show, respectively, soluble BOD and COD removal  efficiency
versus influent BOD and COD concentration.   Curves  are shown for
both pilot plant and full-scale operations.

Hormel(l6) reports on four selected pilot RBC refinery  studies,
including the Chevron  study in the case  history.   They  also
tabulate known refinery and pilot  RBC studies.   The tabulated
studies  had influent  phenol from  <1  to 500 mg/1 and  influent
ammonia from 1 to 200 mg/1.  Several were  intended  to  "remove"
ammonia.

The reported Hormel study for Vancouver, B.C. was designed for
side-by-side comparison of pilot air activated sludge (AAS) and
RBC units.  Three categories of wastewaters  were  compared:  oily,
high-soluble organic  and phenol-bearing.   Both  units satis-
factorily reduced 47 to 375 mg/1 oil influent  to  15 to 31 mg/1 in
the effluent.  AAS was more efficient  than  the  RBC  for soluble
organics, and both removed over 99  percent of  the 100  mg/1  inlet
phenol.  In another  study by Texaco in West Tulsa,  Okla.  on a
dilute refinery waste (BOD <100),  about 90 percent  oil and phenol
removals from average influent  concentrations  of  27 and  0.8 mg/1,
respectively, were reported.  Energy requirements for  1,000 gpm
(1.14 MGD) RBC, AAS and aerated lagoon  plants are  summarized in
TABLE  8-33.   RBC  at  71  hp  is about  one-half either of the
Others.

HBC Limitations—
BBC's are subject  to  several limitations  involving  mechanical
considerations, shock loading,  toxic substances  and oil  (13f 14,
16).

Care is required to ensure that the discs rotate  and are immersed
and that shaft bearings are lubricated.  Various  physical damages
can arise from weight shifts when  the  bio-mass  sloughs off the
                              331

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                     100
            SOLUBLE
              BOD
            REMOVAL
             (MG/L)
co
CO
N)
                      9C_
80

7

6C


5C

4C

3C

2C

1C

 C
                                       PILOT PLANT DATA
FULL SCALE
OPERATING DATA
                              10
              20    30    40     50     60      70     30
                 INFLUENT SOLUBLE BOD TO RBC   (MG/L)
                           100
                   Figure 8-35.   Soluble BOD removal efficiency for the RBC unit.*

                   *From Item 15 in reference list

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CO
CO
u>
        100

         90

         80


SOLUBLE  70
  COD
REMOVAL  go
(MG/L)
         50


         40

         30

         20

         10

          0
                                         PILOT PLANT DATA
                                                                    FULL SCALE-
                                                                OPERATING DATA
                             "20      40      60      80     100

                               INFLUENT SOLUBLE COD TO RBC (MG/L)
                                                            120
140
160
                  Figure 8-36.   Soluble COD removal efficiency for the RBC unit.*
                  *From Item 15 in reference list

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         TABLE 8-33.  ESTIMATED ENERGY REQUIREMENTS FOR
                  INDICATED DESIGN AT 1000 GPM«
           	(TEXACO. WEST TULSA, OKLA.)	
        Item
Influent Pumps
Equalization Basin
Air Flotation Unit
Rotating Disk Unit
Aeration Basin
Secondary Clarifiers
Multimedia Filters
Aerobic Digester
  Total Estimated
  Continuous Horsepower
                               Continuous Horsepower Requirements
                               Recommended   Alternate    Existing
                                Rotating     Activated    Aerated
                                  Disk        Sludge      Lagoon
 5
30

20«
15
71
  5
 30
 28

 40
  5
 20
 15

143
  5
 15
                        135
155
Note:  Operating horsepower may be slightly less than indicated
installed horsepower.
*From Item 15 in reference list
                               334

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disc  if  rotation  stops or the level  in  the  RBC treatment tank
falls too  low.

Although no refinery had observed  the  effects of a shock BOD load
(14)  on  RBC's, one chemical plant  operator reported that a rapid
sixfold  BOD increase raised the effluent to  15 to 20 mg/1 from
its normal 2 to 5 mg/1.  Recovery  was  reported  in 24 hours.

With regard to toxic  substances,  one refiner reported  that
several  weeks' caustic water accumulation  introduced into  the
oily  drain stripped  the growth from  the discs and 5 to 6 days
were  required for recovery.  Another refiner  found that 10 mg/1
sulfide  caused a white growth to  develop  on the  first two stages
of a  four  stage RBC and interfered with BOD  removal and biomass
settling.  Reduction of sulfide  to 1 mg/1 allowed recovery in  1
to 2 weeks.  A spill  of thousands  of pounds  of sulfuric acid
occurred (13) at Chevron's Refinery "B",  causing pH to  fall to  2
to 3  in  the biological system.  Although  the  RBC units sloughed
off tons of bio-solids and temporarily overloaded the clarifier,
the RBC's  recovered to nearly full phenol  activity in 24 hours.

Chevron  reports (14) two experiences with oil.   One refiner  fed  1
percent  oil to RBC's for two days  due  to  a skimmer failure.  Four
to five  days were required for recovery.   The second refiner  fed
100 to  200 mg/1  oil  for extended  periods.   Most of  this  oil
passed  through the  RBC's and caused settling problems in  the
clarifier.   In  studies  (16)  that  conflict with Chevron
experience, Hormel reported oil  reduction of  50 percent to over
90 percent in the range 12 to 375  mg/1 influent  oil.

RBC Costs—
Chevron  (14) found that activated  sludge could be cheaper than
RBC's if wastewater was concentrated (above about 600 mg/1 BOD),
if the  waste load  exceeded about  15,000 Ib/day BOD or if  the
activated sludge effluent requirement  did  not require
                               335

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 filters to satisfy  regulations.  Hormel (16) found  RBC  energy
 needs to be about half those for other bio-processes on  a com-
 parable basis  for a low-BOD 1.44 MGD design.

 RBC Case History at Chevron Refinery "B"—
 Refinery "B" is a 168,000  barrel per day plant that  has  fairly
 liberal  effluent requirements to meet although  they are more
 stringent in winter than the rest  of the year.  The RBC  system at
 refinery "B" is the largest installed RBC unit  treating refinery
 wastes.  TABLE 8-34(a)  shows the effluent requirements.   TABLE
 8-34(b) shows RBC performance for  BOD and TABLE 8-34(c)  shows the
 RBC clarifier performance for suspended solids  (SS)  for this
 installation.  The flow is up to  3,000  gpm or 4.3 MGD (including
 1,000 gpm storm flow)and .after flotation is equalized in  a tank
 of 12 hours' detention  time.   Pilot tests indicated  1.8 million
 square feet of RBC area  was needed and 18 standard  Autotrol
 100,000 square foot "Bio Surf units (manufactured  by Autotrol
 Corporation) were  employed in 5 parallel trains.  Chevron
 experience indicated  3 to 4 units in series provide  nearly
 optimum use of the area commensurate with the required removals.
 Each covered unit has  a 7-1/2 hp drive and one  train includes
weigh cells on each shaft  to determine  the weight  of  bio-mass in
each unit.  TABLE 8-34(b)  includes weigh cell  measurements.
These  are quite valuable  to detect toxic spill  bio-mass
destruction before it  becomes catastrophic.

The initial RBC inlet  BOD was 178 mg/1 (period  A)  or 86 mg/1
 (period B).  The combined  RBC-clarifier outlet BOD  was 34 mg/1
and 18  mg/1 for these  same periods and thus  combined removals
were about 80 percent  in each case.

Case History of Chevron Refinery "A" Pilot Tests—
Pilot tests were made  at refinery "A", a 40,000  barrel per day
refinery  with existing  API separator and pond system.   TABLE 8-35
                             336

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              TABLE 8-34(a).  EFFLUENT  REQUIREMENTS
                 AT REFINERY B,  CHEVRON  U.S.A.*
                                 10-Day Average (1)
BOD (5 day)

TOC

TSS

Phenol

NH3(As N)

Sulfide

Oil and Grease
December-March
ppm (2)
38
84
25
0.19
16
0.16
11
Lb/Day
1,362
2,995
892
6.9
578
5.6
403
April-November
ppm (2)
50
109
33
0.27
23
0.22
15
Lb/Day
1,772
3,900
1,166
9.7
805
7.8
525
                          6-9                      6-9
(1)  Requirements change according to  seasonal asphalt production.
    An allowance for 1,000 gpm of storm water is included in these
    figures.
(2)  ppm based on 2,970 gpm flow rate.
    *From Item 13 in reference list
                                337

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             TABLE 8-34(b).  INITIAL RBC PERFORMANCE
                 AT REFINERY B, CHEVRON U.S.A.*
Period
A
B
Design
Period
A
B
Values in

Flow Rate
gpm
3,000-4,000
3,000-4,000
3,000
Weigh

1
BOD Reduction
BOD (5-day), ppm


RBC Inlet Clarifier Outlet
178 (117-211) 34 (23-44)
86 (65-100) 18 (14-25)
165 38
Cell Measurements, Lb
Stage No.
2 3
40-50,000 30,000 25,000
27,000 25,000 23,000
parentheses show the range of data.

4
25,000
20,000
Flow Rate,
   gpm

3000-4000
   3000
  Design
          TABLE 8-34(c).   INITIAL CLARIFIER PERFORMANCE
          	AT REFINERY B, CHEVRON U.S.A*	

                    	Suspended Solids, ppm	
Clarifier Inlet

  130 Average
   (20-360)

     100
    Design
Clarifier Outlet

  26 Average
    (9-40)

      20
    Design
No. of data points - 52.
Values in parentheses show the range of data.
•From Item 13 in reference list
                                338

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               TABLE 8-35.   PILOT BIOLOGICAL TESTS
                  AT REFINERY A,  CHEVRON U.S.A.*
RBC Units

  A.   Autotrol Biosurf Unit

      15-In.  Dia.  Corrugated Polyethylene Media: 250 Sq. Ft.
      Surface Divided into Four Equal Stages

      Clarifier:   Hopper Bottom, 1.8 Sq. Ft. Overflow Area

  B.   Hormel  RBC  Unit

      48-In.  Dia.  Flat Polystyrene Foam Disks:  800 Sq. Ft.
      Surface
      Divided into Four Equal Stages

      Clarifier:   Hopper Bottom, 3.7 Sq. Ft. Overflow Area

Activated  Sludge  Unit

   1,000-Gal. Clow Package Unit  with Diffused Air Aeration

  Clarifier:   Hopper Bottom, 10 Sq. Ft. Overflow Area

                                            BOD  ppm(l)   BOD
Test  Unit         Operating Conditions      In    Out   Removal, %

Biosurf          2.0 Gal./Day/Sq.Ft.      103     60       42
                 85° F Inlet              (MO)   (11)     (73)
                 75° F Outlet

RBC Unit          Same as Biosurf          103     47        54
                                          (40)   (12)      (70)


(1) BOD values are averaged data for 5-day tests.  Values in
    parentheses are  soluble BOD's, others are for settled
    samples.
(2) Activated sludge unit never successfully started up.

•From Item 13 in  reference list
                               339

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 describes the two  pilot RBC units tested  and  compares conditions
 and pilot results  for Autotrol Bio-Surf and the Hormel RBC units.
 Chevron concluded  that the two RBC's  were essentially  equal in
 performance at 70  percent soluble BOD  removal.

 Case History at Chevron Refinery "C"—
 Refinery "C"  had ponds,  but  poor  winter performance made
 upgrading necessary.  Four 38,000 square foot Hormel RBC  units
 were installed downstream of pond number 1.  This RBC was  the
 first installation in the U.S. for refinery waste treatment.  Due
 to a decreasing waste load this system was underloaded and  slime
 growth was thin.   Side-by-side pilot  and full scale tests were
 made to check for  scale-up effects,  but such effects  were  not
 found with this dilute feed operation. TABLE 8-36 summarizes the
 results of these tests and shows that  approximately 30,  30 and MO
 percent  removals were  obtained for  BOD, TOC and  phenols,
 respectively.  Note that phenols  were only  about 130 parts  per
 billion in the  feed.

 Activated Carbon Enhanced Activated Sludge (ACEAS)—
 Activated carbon enhanced activated sludge  processes involve a
 synergism between  fluidized bed  activated  sludge and  ordinary
 activated carbon wastewater treatment.

 In ACEAS  processes,  aeration tanks  receive  primary  treated
wastewater,  powdered  activated  carbon  and  secondary clarifier
 return sludge.   In the aeration tank the  bio-mass grows  adherent
to the individual carbon particles similar to the growth in other
 fluidized bed  bio-reactors.  However,  the substrate is not inert,
like sand,  but  adsorbent carbon.   The  adherent bio-mass  exhibits
the chemical  and toxic shock resistance found in the other  fixed
film devices  (trickling filters,  fluid beds and rotating discs) .
                              340

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        TABLE 8-36.  PILOT VERSUS FULL-SCALE RBC UNITS
                AT REFINERY C. CHEVRON U.S.A.*
Full-Scale RBC
Feed
Effluent
Reduction, %
Pilot RBC
Feed
Effluent
Reduction, %
BOD,
ppm
47 (35-65)
32 (36-44)
32
47 (35-60)
33 (21-39)
30
TOC,
ppm
41 (35-53)
31 (21-44)
24
41 (35-48)
29 (18-39)
29
Phenol ,
ppb
130 (98-150)
76 (51-95)
42
134 (115-159)
80 (48-136)
40
Average values are shown, with data range  in  parentheses.

Operating Conditions - Hydraulic Loading:   6.8  Gal./Day/Ft2
                      Inlet Temperature:   55°  F  (Typical)
                      RBC Media:
                      Full-Size Unit:
                      Pilot Unit:

                      Peripheral Media
                       Speed
                       (Both Units):
4 x 38,000 Ft2,
11-Ft Dia. Disks
4 x 2,000 Ft2,
4-Ft Dia. Disks
51 Ft/Min.
*From Item 13 on reference  list
                               341

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 In addition,  the carbon may not only adsorb and desorb  various
 substances as  the  waste  concentration varies (18),  but  also
 serves to retain resistant organics in contact  with the bio-mass
 for  the  full  sludge age  (18,  19),  not just the  hydraulic
 retention time.   Finally,  in  the secondary clarifier  the
 carbon-weighted bio-mass settles readily where it is split  into
 return and waste activated sludge as in ordinary activated sludge
 systems.

 Waste sludge  from ACEAS processes may be sent  to disposal  or it
 may be processed to recover activated carbon.   DuPont stockpiled
 literally hundreds of tons of  carbon containing sludge fnom the
 PACT process  at their Chambers works while awaiting repairs to
 the reactivation furnace (summer/fall 1977) and experienced no
 difficulties  other  than those caused by  rain and ice.   Sludge
 settling, handling  and dewatering may be enhanced  by carbon
 (18).

 Both conventional dry thermal  (19) and wet oxidation (20)  carbon
 regeneration methods have  been used  for carbon  recovery.
 Regeneration  losses are 5  to 15 percent per pass.  Regeneration
 is an economic  necessity  for  systems with conventional  sludge
ages of 5  to  15 days and where the carbon makeup rates needed are
50 to 450  mg/1 to obtain aeration tank carbon levels of 500-5,000
mg/1.  Based  on refinery studies (21, 22), carbon recovery is not
an economic necessity for  systems with less than about  50  mg/1
makeup rates  based on influent flow rate.

The relationship between  aeration tank equilibrium carbon
concentration C, carbon dose rate C. , hydraulic retention  time
and sludge age is:
                              342

-------
             C = C± (SA/HRT)

  where     SA = sludge age
           HRT = hydraulic retention time

Thus aeration tank carbon levels of 500-5,000 mg/1,  comparable to
the conventional SA high dose  rate (50-450 mg/1) units  described
above, can also be obtained at much lower  dose  rates  if SA's  are
extended to 20 to 50 days.

The following table  shows the  variation  in equilibrium  car.bon
concentration for several carbon  dosage rates and  sludge ages.
The  hydraulic retention time  is  one day  in all  cases.   The
Assumption is made  that  carbon  losses  in the  effluent  are
accounted for and are lower than the dose  rate.

      Equilibrium Carbon Concentration (C)  at  HRT =  1  Day

      Dose Rate  	SA, days	
      Cit mg/1      10             25              50

        10                         -               500

        50         500            1,250           2,500

       200        2,000           5,000

Carbon doses as low as  10 to 15 mg/1 have  been used  in  some pilot
tests and full scale demonstrations (22, 23).  Analysis may show
that  systems designed for long SA's and with dosage rates below
about 50 mg/1 are economically attractive without  carbon
recovery:  the increased  capital required  for the  long  SA may be
more  than compensated for by the elimination of costs  of carbon
recovery.
                              343

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ACEAS Applications—
Some of the physical properties of activated carbon  are  important
in the application  of ACEAS processes.  The most  notable are  sur-
face area (21,  22)  and density (18, 23).  Reference  22  is an im-
portant report  by the API discussing the ACEAS process  applica-
tion to refinery and petrochemical waste treatment.   Reference  22
and reference 23, an oil company paper,  both discuss the advan-
tages of experimental high surface area  activated carbons (Amoco
PX Series).  The API study found that the high  area  carbon could
be combined with a  high SA to maintain  2,500 mg/1 carbon in  the
aeration tank and COD removals were obtained comparable  to those
from add-on granular carbon columns.  The study found incremental
costs for COD removal below that obtained with  filtered  activated
sludge were $0.6l/lb COD for powdered carbon versus  $3.19/lb COD
for granular carbon  (1977 costs  for a 1 MOD typical  refinery
activated sludge unit).

In some  contrast  to  these studies,  but with similar  results,
Adams and DeJohn  (24)  found carbon density to  be  important  to
ACEAS processes because high-density carbon so  reduced clarifier
(effluent)  losses that high SA's were feasible.  Reference 2U has
a good discussion  on  the benefits and mechanisms of  powdered
carbon in activated sludge units and presents four refinery  case
histories of ACEAS  operations.

ACEAS processes  have  shown great  promise with  refinery waste-
waters,  are especially applicable to toxicity and high concentra-
tion  problems, and  should be  tested  with coal conversion
wastewaters in  pilot and demonstration units.

References  for Biological Oxidation—

1.   EPA  625/l-71-004a, "Upgrading Existing Wastewater Treatment
                               344

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     Plants," October 1974.  P.   4-4,  4-23, 5-3 and 5-20.   870*

2.    EPA 600/7-77-065 "Water Conservation and Pollution Control
     in Coal Conversion Processes," Water Purification Associ-
     ates, June 1977.  P. 401,  399,  396,  393, 369 and 366.   480*

3.    Adams, C.E., Jr., Stein, R.M.  and Eckenfelder, W. W. ,  Jr.,
     "Treatment of Two Coke Plant Wastewaters to Meet Guideline
     Criteria,"  Proceedings  29th  Purdue Industrial  waste
     Conference, May, 1974.  P.  864-880.

4.    Reap, E.J., Davis, G.M., Duffy,  M.J. , and Koon, J.H., "Waste-
     water Characteristics and Treatment  Technology for  the
     Liquefaction of  Coal Using H-Coal Process," Proceedings of
     the 32nd Purdue  Industrial Waste  Conference, May 1977.  654*

5.    Gould, M.S., Roy, A.R., and Genetelli, E.J.. "Pretreatment, of
     Highly Organic  Industrial Wastewater - Case  History,"
     Proceedings of the 29th Purdue Industrial  Waste Conference,
     May  1974.  P. 889-896.

6.    Cooke, R., and Graham, P.W., "Biological Purification of Efflu
     ent  from a Lurgi Plant Gasifying Bituminous  Coals."  Inter-
     national Journal of Air and Water Pollution,  Pergamon Press
     1965, Vol. 9.  P.  97-112. 697*

7.    PERC/RI-77/13 "Treatability Studies of Condensate  Water  from
     Synthane  Coal Gasification."  November 1977.   797*

8.    Davis, G.M., Reap,  E.J., and Koon, J.H., "Treatment Investiga-
     tions and  Process Design for the H-Coal Liquefaction Waste-
     water."   Unpublished  report for  Ashland Oil  by Aware, Inc.
     December  1976.   678*

"Pullman Kellogg  Reference File  numbers
                              345

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9.   Adams,  C.E.,  "Treatment of a High  Strength Phenolic  and
     Ammonia  Waste  Stream by Single  and  Multi-Stage Activated
     Sludge Processes."  Proceedings  of  the 29th Purdue  Indus-
     trial Waste Conference,  May 1974.

10.  Kostenbader, P.D.,  and Flecksteiner, J.W.,  "Biological Oxidation
     of Coke  Plant  Weak Ammonia Liquor," JWPCF (41) 2  Part 1,
     February 1969.

11.  EPA-R2-73-167, "Biological Removal  of Carbon and Nitrogen
     Compounds From Coke Plant Wastes."  April 1973.  800*

12.  Parsons, W.A., and Nolde. W.. "Aoolicability of  Coke Plant Water
     Treatment Technology to  Coal  Gasification." presented at EPA
     Symposium, Hollywood, Florida,  September  1977.  958*

References for Rotating Biological Contactors—

13.  Davies, B.T., and Vose, R.W.,  "Custom Designs Cut Effluent
     Treating Costs.   Case Histories  at  Chevron U.S.A.,  Inc."
     Presented at 32nd Purdue Industrial  Waste Conference,  May
     1977.  653*

14.  Knowlton, H.E., "Why Not Use  a  Rotating Disc?"  Hydrocarbon
     Processing, September 1977,  p.  227-230.

15.  Godlove, J.W.,  McCarthy, W.C., Comstock, H.H.,and  Dun,  R.O. ,
     "Kansas  City Refinery's  Wastewater Management Program Using
     Rotating Disc Technology."  Presented at 50th Annual  WPCF
     Conference, Philadelphia, October  1977.   657*

16.  Flann, G.E., and Gerhard, R.E. , "Use of The Rotating Biological
     Surface  For Refinery Wastewater  Treatment."  Presented at
     69th Annual Meeting AIChE,  Chicago, November-December 1976.
     • 545
                              346

-------
17.   McAliley, J.E., "Pilot Plant Study of a  Rotating Biological
     Surface  for  Secondary Treatment of Unbleached Kraft  Mill
     Waste."  Tappi, Vol.  57, No.  9 (1974).   P.  106.  780*

References  for Activated Carbon Enhanced Activated Sludge—

18.   Flynn,  B.P.,  Robertaccio,  F.L.,  and Barry,  L.T. ,  "Truth or
     Consequences:  Biological Fouling and Other Considerations
     in  The Powdered Activated Carbon-Activated Sludge  System."
     Proceedings  of the 31st Purdue Industrial  Waste  Conference,
     May 1976.  931*

19.   Adams,  A.D.,  "Powdered Carbon:  Is It Really  That  Good?"
     Water  and Wastes Engineering, March 1974.   928*

20.   Flynn, B.P.,  and  Barry,  L.T.,  "Finding a Home For The Carbon:
     Aerator  (Powdered) or Column (Granular)."  Proceedings of
     31st- Purdue  Industrial Waste Conference,  May 1976.  931*

21.   Gitchel, W.B.,  Meidl, J.A., and Buvant,  W. , Jr., "Carbon
     Regeneration by Wet Air  Oxidation."  Chemical  Engineering
     Progress (71) No.  5, May 1975.

22.   Clar,  W.J.,  and Crame,  L.W. , "Pilot Studies on  Enhancement of
     The Refinery Activated Sludge Process."   API  Pub.  No.  953,
     October  1977.  849*

23.   Grieves, C.G., Stenstrom, M.K., Walk, J.D., and Crutch, J.F.,
     "Powdered Carbon  Improves  Activated  Sludge  Treatment."
     Hydrocarbon  Processing,  October 1977.  927*

24.   DeJohn,  P.B.,  and Adams, A.D., "Treatment of Oil Refinery Waste-
     water  With Granular and  Powdered Activated Carbon."    Pro-
     ceedings of  31st  Purdue Industrial Waste Conference, May
     1976.  931*
                              347

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 Filtration of Effluent  from Biological Treatment

 Although filtration is a fundamental unit operation with wide
 applications, this description  is  concerned only  with liquid-
 solid filtration as applied to the polishing of  coal  conversion
 wastewater secondary (biological) effluent.  The  main advantage
 of filtration in this use is that it provides  positive suspended
 solids (SS)  control following the secondary clarifier.   The EPA
 Process Design Manual (1) on upgrading existing municipal waste-
 water treatment plants  has a good discussion of effluent polish-
 ing techniques, including filtration, in Chapter  7.   The manual
 describes three filtration applications for polishing secondary
 effluents:

   o  Directly after the clarifier.   Biological floes  are  usually
      strong and multimedia or granular media filters that pro-
      vide  depth filtration perform well.
   o  After  chemical  clarification.  The  floes  are  frequently
      weak  and require  sand or uniform-media surface  filters for
      good  separation.
   o  Following in-line chemical injection.  As with chemical
      clarification, the floes are usually weak and  require sur-
      face  filters.

Mechanical  considerations necessary for all types of  biological
filtering include thorough backwashing facilities with air scour
or hydraulic jets plus normal  upflow wastewater  and periodic
shock chlorination.  Backwash flow equalization may be necessary
in small  plants.   Backwash should be returned  to  the  feed  equali-
zation tank  or directly to the aeration tanks of  the  biological
oxidation system.  If filter effluent is used  for backwash,  back-
wash storage tanks must be provided.

Because  of  the developing state of-coal conversion  plants and
                              348

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their wastewaters ,  pilot  plant  filtration studies  will  be
necessary for  economic design.   A  major  factor  influencing
efficiency and  economics will be  the  consistency of biological
treatment expected for these wastewaters  (poor stability has been
observed in  coke  liquor biological  treatment).  Piloting  will
provide the  needed information on effects of  variability as  well
as accurate  design data for the  effects  of influent solids  con-
centration on run length for various  loadings.

Reference 2  gives a good description  of  pilot filtration studies
made at the  Metropolitan Denver  AS plant.  Filterability studies
on filter effluent turbidity versus bed  depth profiles  are  pro-
vided for three  run  lengths for  each  of the three filtration
applications.   Effects of bed-depth,  media  type and media  size
were investigated as well.  The  media used  were coal,  sand and
garnet.  A second set of studies provided profiles for  turbidity
versus bed  depth with coal  and  sand in dual- and mixed-media
modes.  They concluded that dual coal/sand media filtered AS
effluents directly to 1 to 2 mg/1 SS  with runs over  20 hours long
at 6 gpm per square foot.  Alum  coagulation definitely  decreased
filterability,  requiring finer filter media for  removal.

In their paper  "Applying Coke Plant Water Treatment  Technology to
Coal Gasification," Parsons and  Nolde (3) say that  although the
present trend  at coke plants  is  to  AS treatment, limitations
include  inconsistent discharges  of SS, thiocyanates,and cyanides.
From coke plant AS experience they expect coal gasification sour
water AS plants to have 60 to 200 mg/1 SS in the  settled effluent
(about 5 times  higher than municipal AS  effluents).   These high
levels of SS will require that filters be  relatively  lightly
loaded to achieve reasonable  run times, and  a relatively large
flow of backwash  will be produced.   The  following table shows
some  examples  of direct filtered AS effluents  for municipal
wastes (1).
                              349

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          SELECTED MUNICIPAL ACTIVATED SLUDGE EFFLUENT
                  DIRECT FILTRATION EXPERIENCE*

Plant
Location
Louisville, KY.

Load
Rate
gpm/ft2
3.4

Influent
SS
mg/l««
27
(11-32)
Effluent
SS
mg/l«*
3
(1-4)
Run
Length,
hrs


Ann Arbor,  Mich.

Philomath,  OR.

Hanover Park,  IL.
5

2.2
42          5
(28-126)     (1-17)
165         5
(30-2,180)   (1-20)
14          7
(15-24)
* From Item 1,  pp.  7-20, in reference list
** Range shown  in parentheses

References—

1.  EPA 625/l-71-004a, "Upgrading Existing Wastewater Treatment
    Plants," October 1974. P. 7-12 to 7-23, 7-36 to 7-37.   870»

2.  Maxwell, M.  J.,  Linstedt,  K.  D.,  Work,  S.  W. and E.  R.
    Bennett, "Making Optimum Use of Filter  Media  in Wastewater
    Filtration," Water and Sewage Works.  Dec. 1977.

3.  Parsons, W.  A.  and W. Nolde,  "Applicability  of Coke Plant
    Water Treatment Technology to Coal Gasification," presented
    at EPA   Symposium, Hollywood, Florida, Sept. 1977.  958*
    •Pullman Kellogg Reference File number
                              .350

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Sludge  Handling and Disposal

Liquefaction  processes and gasification processes that  produce
phenols,  oils,and tars generate strong sour  waters with high  BOD
and COD.   These sour waters contain toxic and  organic  substances
that may  be economically treated for reuse or discharge  in  bio-
logical oxidation processes.

Generally, the sludge quantities produced by biological oxidation
are directly  proportional to the BOD or COD removed,  are higher
for more  degradable wastes, decrease with increasing  sludge  age,
and are less  voluminous for fixed  film processes than  for  sus-
pended  growth processes.

Coal conversion sour waters will  require treatment  both before
and after biological oxidation.  Pretreatment steps  anticipated
are degasification, API separation,  inert dissolved  gas flota-
tion, phenol  recovery, stripping,and equalization.  Primary   and
secondary oil removal by API  and  flotation, respectively,  are
included  in  pretreatment because of  the  adverse  effects of
mineral  oils on  biological  oxidation  and other  downstream
processes.  Sludge  production is  affected by oils  because the
oils coat and adsorb onto the sludge floes and  reduce their
settleability. Posttreatment  steps include  chemical  coagulation
and filtration plus various other processes  like  reverse  osmosis,
depending on  the  end use requirements.

All biological oxidation processes produce biomass  growth  in a
reactor system.   The excess growth leaves the reactor  with the
effluent  and  is  usually settled  out by gravity  in  a secondary
clarifier.  Clarifier underflow or solids flow is  usually quite
dilute, perhaps 0.5 to 1.5 percent solids for activated sludge
systems.   In  the  activated sludge system the clarifier underflow
is split  into the return sludge  stream and the  waste activated
                              351

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 sludge  stream (WAS).  The WAS  is  the sludge production  from
 biological oxidation  treatment and must be further  processed for
 separation and disposal.  Sludge handling is responsible for 30
 to 40 percent of the  capital cost of a municipal  treatment plant
 and about 50 percent  of the operating cost.

 Wastewaters from coal conversion processes that produce  phenols,
 oils and tars (p/o/t) may be  treated by biological  oxidation.
 P/o/t-producing conversion processes include all  low-severity
 operations such as Lurgi, Synthane and Hygas gasification  as well
 as SRC,  H-Coal and Synthoil solvent-based liquefaction processes.
 After proper pretreatment, wastewaters from these  processes may
 be processed by activated sludge biological  treatment.

 The amount of waste sludge produced from activated  sludge  systems
 may be calculated by (1,2):
           Net Sludge, Ibs = a(LR) - b(SA)
   where  a   = constant for yield
          b   = constant for endogenous respiration
          Lp  = pounds BOD removed by the process
          SA  = mass of mixed liquor volatile suspended
                   solids (MLVSS)
 Constants a and b may range from 0.3 to 0.7 and  0.03  to 0.14,
 respectively,  and thus for many systems the  net sludge production
 is <0.5  pounds per pound of BOD removed.

For gasification processes producing p/o/t, published  estimates
 (3) of biosludge production ranged  from a low of  29,000 Ib/day
for Lurgi with phenol recovery  to a high of 192,000  Ib/day for
IGT Steam/Iron HyGas without phenol recovery for  commercial size
 (250 billion Btu per day of product gas) designs.  Unrecovered
phenols were  destroyed by biological oxidation  in  the latter
case.  Unpublished  estimates  by  Kellogg and vendors  for Lurgi
gasification  ranged  from 17,000 to 24,000 Ib/day with prior
phenol recovery.
                               352

-------
For liquefaction processes,  a  published paper (4)  on  pilot
wastewater  treatment studies for H-Coal gave sludge coefficients
of a =  0.48 and  b = 0.03 on a  volatile solids  basis for conven-
tional  activated sludge.  Based on these coefficients, a commer-
cial plant  with  similar waters and about  40,000 Ib/day BOD re-
moval would produce 17,000 Ib/day waste activated sludge.

Handling  and Disposal—
Waste activated  sludge and other biological sludges are unstable
and must  be processed further to prepare them for storage and
disposal.

Biological  sludges  range from  93 to 99 percent water  (5) as  pro-
duced and  waste  activated sludge is 98.5 to 99.5 percent  water.
The dry solids  content of these sludges typically contain  about
2/3 volatile organics and will putresce if allowed to stand.  The
water must  be reduced and the  organic content must be stabilized
before  these sludges can be stored or land filled.   Figure  8-37
shows the  general process sequence in municipal  sludge  handling:
thickening, stabilization, conditioning, dewatering, heat drying,
reduction  and  final disposal.   Steps  with  the  dashed  lines
through the middle  may be bypassed for some sequences.

The most  common  stabilization  practice for refinery sludges  is
aerobic digestion (6), usually preceded by thickening  to  reduce
the hydraulic load.  Thickener supernatant is returned  to the
activated  sludge reactor or aeration  tank.  After  digestion the
stabilized  sludge is dewatered, prior to final  disposal,  by fil-
ters, centrifuges or presses.  Organic polyelectrolyte condition-
ers are usually  added for  most dewatering processes.   The EPA
"Process  Design Manual  for Sludge  Treatment and  Disposal," (5)  is
an excellent source of  information and design  data.
                              353

-------
CO
Ul






LAND
RECLAIM

SANITARY
SANDFILL

OCEAN
                 Figure  8-37.-  Unit processes in sludge processing and disposal.

-------
The most important  common  sludge characterization parameter  is
the Sludge Volume Index  (SVI),  defined  as  1,000 times  the volume
occupied  by  the sludge layer in a one-liter sample, after  30
minutes  settling in a  liter graduate, divided by the initial
solids concentration:

    SVI = (Volume of sludge  x 1,000)/(Initial  suspended solids,
           mg/1)

For activated sludge plants  a sludge with a SVI  less than 100  is
considered good settling whereas a sludge  whose SVI  is greater
than 100 is often troublesome.   Limited data from coal conversion
wastewater pilot studies show that  biosludges  from coal conver-
sion may be similar to  biosludges from  municipal and other indus-
trial processes. Synthane pilot activated sludge units produced
sludges with SVI's  of  20  to 55  for a  F/M  range of _< 0.1 to  0.9
(7).  H-Coal liquefaction  pilot sludge  had SVI's in the range  of
70  to  90 for F/M  from  0.03 to  0.23 (8).   Both these sludges
handled well.

Biological sludge can be thickened either  by gravity or by  air
flotation (6) to 2  to U percent solids.  Aerobic digestion will
reduce volatile organic solids  by  50 to 60  percent in 10  to 15
days' hydraulic detention.  Conditioning with  ferric chloride at
200-400 Ib/ton of dry sludge solids or  more will produce cakes of
10  to  16 percent  solids  from  vacuum  filtration, and up  to 50
percent  solids  from pressure filtration. Both cakes are suitable
for landfill.  The  pressure filtration  cake should  provide  a  net
heat on  combustion:  no fuel need be  added.

References—

1.   Wilkinson, J.B., "Predicting Sludge Production From Refinery
     Activated  Sludge Oxygen Uptake."
                               355

-------
      Purdue Industrial Waste Conference  May 1976, p. 605.  931*

 2.    Eckenfelder,  W.W.,  Jr., "Industrial  Water Pollution  Con-
      trol," McGraw Hill,  1966,  p.   162.  932«
                                     *

 3.    FE 2240-5 "Factored  Estimates For  Western Coal Commercial
      Concepts," Interim Report,  October  1976,  to DOE and AGA by
      C.F. Braun & Co., Alhambra,  Ca.  294*

 4.    Reap, E.J., Davis, G.M.; Duffy, M.J., and Koon, J.H.,  "Waste-
      water  Characteristics  and  Treatment Technology  For -The
      Liquefaction of Coal Using H-Coal Process," Proceedings of
      the 32nd Purdue Industrial Waste Conference, May 1977.  654*

 5.    EPA 625/1-74-006. "Process Design Manual  for Sludge Treat-
      ment and Disposal."   USEPA Technology Transfer, October  1974.
      868*

 6.    Adams,  S, C.E.,  "Sludge Handling Methodology  for Refinery
      Sludges," Proceedings  of  EPA Open Forum  on Management of
      Petroleum Refinery Wastewaters,  Editor F.S. Manning,
      University of Tulsa,  Tulsa, Oklahoma,  1976.  828»

7.    PERC/RI-77/13 "Treatability Studies of Condensate  Water  From
     Synthane Coal Gasification."  November 1977.  797*

8.   Davis,  G.M.,  Reap, E.J., and  Koon, J.H., "Treatment  Investiga-
     tions and Process Design for  the H-Coal Liquefaction Waste-
     water." Unpublished  report for Ashland Oil  by  AWARE,  Inc.,
     December  1976. 878*
•Pullman Kellogg Reference File number
                              356

-------
 Carbon Adsorption

 Activated  carbon  (AC) is a  powerful adsorbent  available  in
 granules or powders.   AC is commonly used in  wastewater treatment
 as a granular material  in packed beds.  When powdered  activated
 carbon (PAC)  is used it is in  suspended beds and  treatment  is
 followed by chemical or biological flocculation  and  settling.
 Granular activated  carbon (GAC) is roughly twice  as  costly as PAC
 on a weight basis and  thus GAC is commonly regenerated and reused
 whereas PAC is sometimes used once and discarded.

 There are three broad-use categories of AC in wastewater treat-
 ment: physical-chemical (PC),  activated  sludge  enhancement and
 tertiary treatment  or  polishing.  AC, usually in granular form,
 can be used in conjunction with such other physical  and  chemical
 means as chemical  clarification  and multi-media  filtration  to
 provide relatively  thorough wastewater cleanup via  PC  treatment
 (1).  For activated  sludge enhancement, PAC may  be  added to the
 aeration basins, as  in DuPont's proprietary "PACT"  system which
 is described  separately.  In tertiary treatment,  GAC may  be  used
 after  biological  oxidation  (biox)  to reduce residual  COD and
 trace organics.

 The most common wastewater applications of AC adsorption use
 granular material in a series of fixed beds.  Often  only  two beds
 in series constitute a "train"  and  therefore for  reliability a
minimum of  two trains must be  provided.  In use,  one bed  in a
 train is on standby while one  (or  the rest) is adsorbing.  At
 break-through,  flow  is switched to the standby and  the  spent bed
 is slurried or otherwise transported to regeneration.   The  empty
unit is  refilled with regenerated or  new  GAC and  placed  on
standby.  Fixed beds,  either upflow or  downflow,  have  both  an
advantage and a disadvantage in that fixed beds act as filters.
An advantage,  if suspended solids  (SS)  are  low,  is that  fixed
                              357

-------
beds will retain SS and thus act as  polishing filters as well  as
adsorbers.   A  disadvantage, if SS are  high,  is that physical
plugging can  precede carbon exhaustion and  thus require excess
carbon capacity and high backwash flows.   Fixed beds also  grow
bio-slimes in  many applications and either become plugged  or
generate  H2S or  both, and  both prob'lems  affect  design and
operation.

GAC can also  be used in upflow expanded bed  operations.  The EPA
manual on carbon adsorption (1,3-21*)  recommends  upflow expanded
bed operation for H_S problem control  if  the  applied BOD exceeds
5 mg/1, which  it  surely  will  for  coal  wastewaters.   The EPA
manual  is recommended for more design information  and  many
municipal applications.

Activated carbons and waste adsorbability  are characterized  by
batch isotherm  and continuous column studies.  Isotherm studies
are used to find constants K and n  in  the Freundlich equation  by
log-log plots of X/M versus Ce.  The Freundlich equation is:

           X/M = K(Ce) exp  1/n

   Where X/M  =  Weight adsorbate adsorbed  per  weight carbon
         Ce = Equilibrium  adsorbate  remaining, TOC or COD
   K,  1/n  = Empirical characterization constants.

Figure 8-38 is  a plot of the Freundlich equation with slope 1/n
and y-intercept K.  Although Freundlich  constants describe the
adsorbability  of  pure compounds they are  not very useful for
complex wastes.  They are  useful for comparing carbons and  have
limited use for judging AC treatment effectiveness (3).
•Item 1  in reference list, page 3-21.
                              358

-------
 U)
 en
 vo
rd
U

u
•r-t
C
(tf
    M-l
         . 10
         .09


         .08


         .07

         .06



         .05




         .04
          03
      O

      tn
      E
  (U
  cu

rt T(
  OJ
O JQ
  M
  O
      W
OR

tn
e
    X
          02
          01
            15
                Log  (X/M) = 0.917  log  C  -3.20
                                    O
                                         I
                                              •   Data from isotherm analysis #1

                                              O   Data from isotherm analysis #2
                                                     I
                        30
40
50  60
80  100
200
300
                C   Equilibrium Concentration of Total Organic  Carbon,  mq/1
                       Figure 8-38.


(From .Item 2 in reference list)
                                 Montana char  isotherm:
                                 Synthane biox effluent

-------
 Continuous column studies are used to determine  "breakthrough"
 curves  by plots  of effluent concentration  versus wastewater
 throughput (in  bed volumes,  BV).   Figure 8-39  is  a breakthrough
 plot for a bio-treated petrochemical waste  with  a variable feed
 concentration (COD) showing  the  results of  the column study and
 of a second column in series.   The figure is interesting because
 it shows a rapid loss in adsorbability from column 1 to  column 2.
 For example, at a flow of 50 bed  volumes (BV),  COD was reduced
 approximately 60 percent by  the first column (from 650 to 260)
 but only 20 percent more by  the second to  (210)  for an overall
 reduction of about 70 percent.

 Limitations-
 Adsorption  decreases with  decreasing  molecular weight and
 aromaticity and with increasing solubility and polarity (4).
 TABLE 8-37 shows a range of  7  to 97 percent removal (adsorption)
 of a variety of pure compounds with a dose of 5  gm/1 PAC.  The
 tabulated data show that residual  aromatics and phenolics  will be
 much more efficiently reduced than will residual low molecular
 weight acids and alcohols.   The effects  of pH  on adsorption
 depend on the adsorbate polarity:  non-polar substances will not
 be affected  by pH, adsorption  of phenols and other organic acids
 will be  enhanced by low pH and  adsorption of organic bases will
 be enhanced  by high pH. .

 Tests made  on bio-treated  petrochemical  wastes by Lawson and
 Fisher d)  showed that the first bed in a two-bed train removed
most of  the  readily adsorbable  COD and the  second column removed
 little  additional  COD.   See Figure  8-39.   Thus,  some COD
 constituents resist adsorption and may constitute a refractory
 residual  too large for release  or  use as boiler feedwater.

Suspended solids may foul  packed carbon  beds  rapidly if over
about 50  mg/1 including bacterial  (5,6).  Free oil and grease  foul
                             360

-------
UJ
               1000
               800
               600
               400
               200-
                                                           0.5 BV/hr
                                                       0.88 liters/BV
                                                           (2 col.)
                             50        100        150         200
                        Wastewater  Throughput,  bed  volumes (BV)
                       Figure  8-39.   Breakthrough  curve  for  Plant B
                                      bio-treated wastewater.*
        *From Item  6  in reference  list

-------
       TABLE 8-37.  RELATIVE  AMENABILITY  TO  ADSORPTION OF
        TYPICAL PETROCHEMICAL WASTEWATER  CONSTITUENTS (a)

                                             Percentage Removal
                                                of Compound
  Compound at 1,000 mg/1                         at 5 gm/1
Initial Concentration (b)                  Powdered Carbon Dosage

Ethanol                                            10
Isopropanol                                        13

Acetaldehyde                                       12
Butyraldehyde                                      53

Di-N-propylamine                                   80
Monoethanolamine                                   7

Pyridine                                           47
2-Methyl 5-ethyl pyridine                          89

Benzene                                            95
Phenol                                             81
Nitrobenzene                                       96

Ethyl acetate                                      50
Vinyl acetate                                      64
Ethyl acrylate                                     78

Ethylene glycol                                     7
Propylene glycol                                   12
Propylene oxide                                    26

Acetone                                            22
Methyl ethyl ketone                                47
Methyl isobutyl ketone                             85

Acetic Acid                                        24
Propionic acid                                     33
Benzoic acid                                       91


(a)  Item 4 in reference list.
(b)  Benzene test at near saturation  level, 420 mg/1.
                               362

-------
carbon at  10 to 30 mg/1 (5,6) and must  be  reduced by pretreat-
ment.   Ford  (3) states that sour waters  should not be treated by
AC without proper  pretreatment  because of their tendencies to
foul the  beds  by  slime growth  and  to  release  ^ S.    The EPA
"Process Design Manual for Carbon Adsorption" (1) states  that
for applied  BOD values substantially  above 5 mg/1, upflow ex-
panded aerobic beds should be used  for  H S  control.

Applications—
Processes like Synthane and Lurgi  that produce high phenols,
oils,  and tars (p/o/t) will require  complete treatment with
extraction,  stripping  and coagulation preceding biox treatment.
GAC will  be  a  useful tertiary treatment step to reduce residual
organics  but additional treatment  will be required before the
carbon beds, including  filtration and ozonation.  Ford  (3) says
ozonation  may  be a particularly  effective pretreatment  for ad-
sorption.  The Synthane PDU gasifier  wastewaters  have been
subjected to  a series of treatment processes culminating  in
adsorption with gasifier char (2).   The char had  a  surface area
of 325 square  meters per gram, about 1/3 to 1/2 that of  commer-
cial carbons (1) used  for wastewater treatment.  With  influent
TOC of 80  to 490 mg/1,  char TOC  removals were 88  to 97  percent.
TOC residuals  were 35  mg/1 or less.

Gasification processes like  the Koppers-Totzek  produce  few  or-
ganics and have low  COD (7).  They do have objectional quantities
of some inorganics including  cyanides, ammonia,  hardness,  SS  and
trace metals.   Treatment might  include chemical   softening,  fil-
tration and  ozonation  or  chlorination followed by GAC.

Liquefaction processes produce  essentially  C02-free  sour water
from dissolver off-gas condensates.  These  waters  have  ammonia
                              363

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 associated with  sulfides and phenols  and are low in hardness  and
 carbonate alkalinity.   TABLES 8-38  and 8-39  show analyses  for
 unstripped H-Coal and SRC sour waters.  These strong waters will
 be subjected  to  a series of .treatment steps including biological
 oxidation. TABLE 8-40 shows the  effects of biological oxidation
 on an H-Coal  PDU waste, yielding a residual  soluble COD of  360
 mg/1.  Filtration or coagulation-clarification could be used  to
 reduce SS from 60 mg/1 before AC  treatment but soluble COD would
 not be reduced by SS removal alone.   Thus, ozonation and AC  would
 be the next treatment processes after  biological oxidation  and
 filtration or clarification.

 Case Histories—
 A recent  report (2)  concerns treatability  studies  made  on
 Synthane  PDU  waters and describes char  adsorption of waters  after
 biological oxidation treatment.   The  Synthane char had a surface
 area of 325  square meters per gram,  about  1/3 to 1/2 that  of
 commercial AC used in waste treatment.  The  waters studied were
 produced  from a  decant tank following  the  gasifier condensers.
 All waters were  produced from a subbituminous  "C" coal, Montana
 Rosebud.   Pretreatment for biological oxidation included air-
 stripping  ammonia at  pH 11 to reduce  ammonia to less than  500
mg/1 and  removal of tars, oils and grease  (TOG)  with 100 to  150
mg/1 alum  at  pH  1.5-2.5.  Effluent from pretreatment contained
about 600  mg/1 soluble TOG and was then neutralized.  Biological
oxidation  was two-stage  air activated  sludge (AAS)  and  was
seeded with  a nearby  coke liquor waste  bio-solids.   A fixed
hydraulic  detention time of 24 hours  was used in 7-liter reactor-
settler AAS units.   Dilution was  used to vary the food-to-micro-
organism  ratio, F/M.   Bio-unit effluent  was applied to 45  mm
diameter char columns and char treatment resulted in 90 percent
removal of TOG  and  100 percent removal  of  color.  TABLE 8-41
summarizes the char treatment for F/M ratios from 0.2 to 0.8  and
shows that the maximum residual TOC  was 35  mg/1.  Although  the
                              364

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 TABLE 8-38.  SUMMARY 6F UNSTRIPPED FOUL WATER  CHARACTERISTICS,
 	H-COAL (a)
Parameter
                                                     Value  (b)
BOD
COD

TOD
                 (c)
    (Total)
    (Soluble)
    (Total)
    (Soluble)
    (Total)
Ammonia-Nitrogen
Nitrate-Nitrogen
Phenol
Sulfide
Oil and Grease
Total Phosphorus
Suspended Solids
Volatile Suspended Solids
Total Dissolved Solids
Total Dissolved Fixed Solids
pH (pH units)
Chromium (Total)
         (Hexavalent)
Lead
Niokel
Zinc
Cobalt
Copper
52,700
51,200
88,600
88,000
13,200
14,400
21,000
 6,800
29,300
   608
     6.25
     2
     1
 5,300
   330
     9.5
     0.10
    <0.01
    < 0.01
     0.06
     0.45
     0.01
     7.3
la)  From Item 8 in reference list.
(b)  Values shown in mg/1, unless otherwise  designated.
(c)  Values reported are considered unrepresentative.
                               365

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        TABLE 8-39.  ANALYSIS OF FOUL PROCESS CONDENSATE,
        	SOLVENT REFINED COAL (a)	

(mg/1 unless noted)
Kentucky coal feed
Analyses by Water Purification Associates and Pittsburg & Midway

                                       pH=8.6          pH=8.2
Total Carbon                            9,000           8,160
Total Organic Carbon                    6,600           7,390
Inorganic Carbon                        2,400 (b)         770 (b)
BOD (5 days)                           32,500
BOD (15 days)                          34,500
BOD (20 days)                         >34,500
COD                                    43,600          25,000-
                                                       30,000
Phenol as C H OH                        5,000          12,000
Total Kjeldahl N                        8,300 (c)      15,000 (c)
Total Ammonia as N                      7,900          14,000
Total Ammonia (meq/1)                      465             824
Cyanide as CN                              10
Total Sulfur as S                      10,500 (c)      16,200 (c)
Ca                                          0.47
Mg                                          0.13
Si                                         <0.5

a.  From Item 7 of reference list
b.  By difference
c.  22 analyses for N  and S made between 10/5/75 and 12/9/75 were
    supplied by Pittsburg and Midway. Four of these analyses had
    extreme values and were arbitrarily eliminated. For  the re-
    maining 18 analyses the average total nitrogen was 12,600 mg/1
    with a standard deviation of 7,000 mg/1 which is very random.
    The average ratio  (moles NHo)/(moles HpS) was 2.0
    with standard deviation of 0.17 which is quite reproducible
                               366

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          TABLE 8-40.  SUMMARY OF TREATABILITY RESULTS,
           H-COAL WASTEWATERS. BIOLOGICAL OXIDATION*
Influent, mg/1
    BOD, Total
    COD, Total
    Phenol
Period
A
1,890
3,070
750
B
2,600
4,180
1,450
C
2,070
3,180
760
Effluent, mg/1
    BOD, Total
    BOD, Soluble
    COD, Soluble
    SS
    Phenol
Parameters
    F/M, Ib BOD/lb MLVSS-Day
Percent Removal
26
13
360
60
0.7
36
15
310
40
0.3
24
12
380
50
0




.7
0.0 6
0.17
0.22
BOD Basis
COD Basis
99.3
88.2
99.4
92.6
99.4
88.1
*From Item 8 in reference list
                                367

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    TABLE 8-41.  TYPICAL ANALYSES OF CHAR-TREATED EFFLUENTS,
                          SYNTHANE (a)
TOC-to- Influent (b)
Reactor Biomass TOC,

C-4
C-3
C-1
C-2
Ratio
0.2
0.5
0.8
•
mg/1
80
300
490
250
pH Color(c)
7.5
7.8
8.0
8.3
0.32
0.64
0.88
2.00
TOC,
• mg/1
5
35
35
8
Effluent

pH(d)
10.3
10.6
11.2
11.5

TOC
Removal ,
Color(c) Percent
0.0
0.0
0.0
0.0
94
88
93
97
(a)  From Item 2  in reference list
(b)  Influent was effluent from biological unit
(c)  Absorbance of color measured at 579nm
(d)  Maximum pH value  prior to color breakthrough
                               368

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 ratio of COD/TOC is unknown for the'se  waters, ratios  for  a  few
 industrial wastewater effluents are  reported  (9) and range  below
 2.3:1.  Thus, COD residual may be  estimated at 80 mg/1.   Figures
 8-40(a)  and 8-40(b)  show color  and  TOC breakthrough curves
 respectively, for these studies.

 The physical-chemical treatment of coke liquor is illustrated by
 a German study (10) that used  isotherm,  column,and pilot  plant
 tests to design  a  demonstration  moving  bed  Granular  Activated
 Carbon plant for 25  m /hr (110 gpm)  flow.   Two years  of  pilot
 plant tests gave average removals of  99,  89.5, and 57.5  perc.ent
 respectively for phenol, COD/and  CN.   Average feed content  and
 removals for the pilot tests are given in  TABLE 8-42.  A  simpli-
 fied block flow diagram of the demonstration plant is  shown in
 Figure 8-41. The plant design data are given  in TABLE  8-43.  The
 demonstration plant was designed for the maximum TOC removal  (95
 percent) obtained in the pilot plant.   The authors include  TABLE
 8-44, an interesting comparison of  TOC,  COD, and BOD  for coking
 plant effluent components.  A fluidized bed thermal carbon regen-
'eration system  was  used.  The good  results on phenol  and  COD
 removal make GAC a potential option-to use in  a physical-chemical
 treatment train between NH  recovery and  tertiary treatment.

;An unpublished study by AWARE (8)  concerned treatment  investiga-
 tions and process design for the H-Coal liquefaction wastewater.
 This study included carbon isotherm tests  for pretreated  combined
xsour waters and  for effluent from biological  oxidation.   Powdered
;. Filtrasorb 400 activated carbon was used with 500 ml batch  waste
 .samples.  COD and phenol removals were obtained and  from  these
 the Freundlich  isotherm constants,  K and 1/n, were  evaluated.
 The results are  summarized in TABLE 8-45.  AWARE concluded that AC
 treatment was effective but would not be economically  attractive
 because of the low equilibrum concentration  (C ) values required
                                              c
 for discharge.
                               369

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  01
  r-
  m
  

  l-
  <
      1.0
      0.8
      O6
      1   I
                         I    I
     I   1
          Bed loading-O.I gpm/fl

          using 20 g char bed
      0.2
       0   100 200 300 400 500 600 700 800 900 1000   1200   1400

                    QUANTITY OF ADSORBATE PASSED, ml


 Figure 8-40(a).  Color  breakthrough with Montana char.*
       100
        eo
i
o-
o
        60
        20
                        I
        Bed loading-O.I gpm/f1z

        using 2Og char bed


        Influent TOC-SOmg/l
                 I
                   I
I
I
I
         0       20O     400    600    800    IOOO   I20O


                 QUANTITY OF ADSORBATE PASSED, ml
Figure  8-40(b).   TOC breakthrough with Montana char.*
*From Item  9 in  reference list


                           370

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00
                  CARBON MAKEUP
                 WASTEWATER
                             PREFILTER
                                                                                 TnrATr.n WATER
 CARBON
ABSORBER
                                           SLURRY
                                                   QUENCH
                                                            CARBON,
                                                            SLURRY
DEWATERING
  SCREEN
                                                             SOLIDS
                 REACTIVATION
                    UNIT
                                                                                                FLUE GAS
                       CYCLONE
                         AMD
                     AFTERBURNER
                 Figure 8-41.  Block  flow  diagram of  demonstration  plant,
                                 capacity 25 m  per hour.
                 (From Item 10  in reference list)

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   TABLE 8-42.  CONTENT OF MAIN IMPURITIES IN DECANTER WASTES
                   AND REMOVAL BY ADSORPTION*
                           Content               Removal
                    	(mg/1)                  (g)
Phenols                 650 - 1,400               > 99
Cyanide                   5 -    35             45 _ 70
Thiocyanate             120 -   450             30 - 80
Iron                     40 -   150                30
Solids                  300 - 3,000               > 99
TOC                     800 - 2,000             85 - 95
COD                   2,000 - 4,000             80 - 99
•From Item 10 in reference list
      TABLE 8-43.   DESIGN DATA FOR THE DEMONSTRATION PLANT
Waste Feed Rate
Average TOC Content
Flow Rate
Activated Carbon: Bulk Density
Grain Size
TOC Removal
Adsorbate Loading
Circulating Carbon
Carbon Loss
25
1,000
10
450
2
95
70
0.3
0.14
m3/hr
mg/1
m3/hr
g/1
mm
%
kg C/m3
m3/hr
kg/m3
                                372

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TABLE 8-4U.  CHARACTERISING VALUES OF COMPOUNDS
          FROM COKING PLANT EFFLUENTS
Compound in
solution
(100 mg/1)
NaCl
NH3C1
Nljj SCN
¥
HCN
phenol
o-cresol
m-cresol
pyridine
benzene
naphthalene
anthracene
Cl-ion
SCN-ion
SO, -ion
TOC
(mg/1)
0
0
11.3
15.8
0
70.5
76.6
77.7
77.7
75.7
92.5
93.6
94.5
0
20.7
0
COD
(mg/1)
3.3
9.1
1.8
64
190
0.2
238
173
172
0.6
0.8
23.4
16.2
5.5
77.6
19.7
BOD5
(mg/1)

—
-
187
0
178
164
170
115
0
0
0
-
-
-
                      373

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            TABLE 8-45.  H-COAL WASTEWATER TREATMENT:
                   CARBON ISOTHERM CONSTANTS*
                                   1/n

Raw Wastewater
•Item 8 in reference list
    COD Basis                     0.51              1.53 x  10~2
    Phenol Basis                  2.73              1.49 x  lO"8

Biologically Treated
    COD Basis                     1.12              7.06 x  10~4
    Phenol Basis                  3.41              7.60 x  10~3
                               374

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References—

1.    EPA 625/l-75-002a  "Process  Design  Manual  for Carbon
     Adsorption," October 1973, Chapters  2, 3.  871*

2.   PERC/RI-77/13  "Treatability Studies  of Condensate Water from
     Synthane  Coal  Gasification," November 1977.  797*

3.   Ford,  D.L., "Putting Activated Carbon in Perspective to 1983
     Guidelines," Proceedings 1977 National Conference Treatment
     and Disposal Industrial Wastewaters  and Residues, April 1977,
     Houston.   635*

4.   Lawson,  C.T.,and J.A. Fisher, "Limitations of Activated Car-
     bon Adsorption  for Upgrading Petrochemical  Effluents."
      AIChE Symposium Series:   Water-1973,  No.  136, Vol.   70.
     866*

5.   Hager, D.  G. ,  "Industrial Wastewater Treatment  by  Granular
     Activated Carbon,"  Industrial Water  Engineering, Jan-Feb.,
     1974.   877*

6.   Gibney,  L.C. (Ed)  "Inroads to Activated Carbon  Treatment,"
     Environmental  Science Technology, 8, No.  1,  Jan. 1974.  876*

7.   EPA 600/7-77-065,  "Water Conservation and  Pollution Control
     in  Coal  Conversion Processes."   Water  Purification
     Associates.  480*

8.   Davis, G.M., Reap,  E.J., and J. H. Koon,  "Treatment Investi-
     gations and Process Design for the H-Coal    Liquefaction
     Wastewater," Unpublished  Report for Ashland Oil  by  AWARE,
     Inc.,  Dec.  1976.   678*.
•Pullman Kellogg Reference File number

                              375

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9.   Davis,  E.M., "BOD vs COD vs TOG  vs TOD," Water  and Wastes
     Engineering, Feb. 1971. 878*

10.   Juntgeh, H.,and J. Klein,  "Purification of Wastewater from
     Coking  and Coal Gasification  Plants Using  Activated  Carbon,"
     Preprints 168th National Meeting  ACS, Div. Fuel  Chemistry,
     Vol.  19, Mo. 5, page 67.  Sept. 1974.  875»
                             376

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Chemical  Oxidation of Effluents

Chemical  oxidation is used primarily in disinfection  of municipal
water treatment  effluents and in removal of specific industrial
pollutants.   Ozone, chlorine,  chlorine dioxide, and hydrogen
peroxide  are  the  agents most applicable for chemical  oxidation of
wastewater  effluents from coal  conversion processes.   Phenols,
cyanides,  ammonia, residual  organics and some  heavy metals are
the specific  substances to be  treated by chemical  oxidation of
effluents.

There are  hazards associated with  storage, handling and use of
the chemical  oxidants:

   o  Ozone is an irritant and is toxic.  Reference  2 discusses
      precautions for handling and use on pages 23 to 25  and 199
      to  202.   Because ozone is a more powerful oxidant than  pure
      oxygen,  the rate of combustion of oil,  grease, and other or-
      ganics  in  ozone ranges from extremely rapid to  explosive.

   o  Chlorine is physically hazardous because  it is stored and
      handled  as  a liquefied gas under pressure and is  a toxic
      irritant.  Its  reactions with  organics  can  be violent.
      Precautions for handling and use are described  in detail by
      J.  S.   Sconce  in "Chlorine:   Its Manufacture, Properties
      and  Uses," Reinhold  Publishing  Co.,  New York  (1962).
      Safety  considerations in its applications to wastewater are
      discussed  in reference 1, pages 383 to  395.

   o  Chlorine dioxide is generated at the point of use by oxida-
      tion  of  sodium chlorite with chlorine.   Because it is un-
      stable,  and explosive under certain conditions,  it cannot
 :     be  stored  or shipped (1,  p.  399).  Both the reactants are
      hazardous  and  toxic as is the chlorine  dioxide  product.
                                377

-------
   o  Concentrated hydrogen peroxide is a skin and eye irritant.
      It decomposes  slowly by itself, and more  rapidly in the
      presence  of organics, some metals and  light,  into oxygen
      and water with the resulting  potential of pressure buildup
      in its  container to the point of rupture.   As a powerful
      oxidant,  its reactions with oxidizable materials may range
      from rapid to explosive.

Ozone--
Ozone  (0_) is  a powerful, relatively expensive and  unstable
gaseous oxidant.  The gas is generated onsite just prior to use
in high capital cost equipment.  Ozonation has been estimated (3)
to add as much  cost to tertiary  effluent treatment as does acti-
vated carbon, but this appears to be questionable.

Ozone is produced economically only in 1 to 4 percent concentra-
tions  in  air or pure  oxygen and  it is both unstable and only
slowly reactive with some residual  organics.   For these reasons
staged  cocurrent contactors are  required for  efficient ozone
utilization.  Eductor-injectors  were found (2, 3)  to  be efficient
high shear mixing devices for ozone-wastewater contacting.  Wynn,
et al,  (2), state that  ozone transference is  proportional to
liquid flowrate at constant mixing efficiency,  and  the optimal
gas to liquid volumetric ratio  was nearly 1.0  for   the 55 gpm
pilot  flow used.   Reference  2  discusses mixing  and  ozone
transference on pages  109 to 123 and  economic analysis  for
full-scale ozone treatment on pages 127 to 170.

In a study of ozonation treatment of hospital  effluents (4)  a
synthesized permeate from reverse  osmosis  (RO)  containing five
known organics, methyl,  ethyl,and isopropyl alcohols were found
to be sustantially reduced but acetone and acetic acid were not:
acetic acid concentrations increased  during  ozonation  and
acetaldehyde appeared.

                               378

-------
In another  study (5, 6) the secondary  effluent from an air acti-
vated sludge  (AAS) treatment was passed  through a membrane filter
having 0.45 micrometer pores.  The filtrate was then subjected  to
ultrafiltration  (UF)  where organics having molecular  weights
greater than  18,000 (humic acids)  were retained.   The ultrafil-
tration permeate was subjected to  reverse  osmosis (RO) to yield a
retentate  fraction containing  organics with molecular  weights
ranging from  150 to 18,000 (fulvic acids)  and a permeate fraction
containing  organics with molecular  weights less  than 150.  The
secondary  effluent from AAS, the UF retentate and the RO reten-
tate and permeate  were all subjected to  ozonation with  the  fol-
lowing results:

   o  Permeate analyses varied when the  parameter F/M in  the AAS
      system  was varied.
   o  Variation in ozonation results reflected the variation  in
      the  F/M parameter.
   o  Ozonation of the AAS effluent feed showed a high ozone de-
      mand  even without TOG reduction.
   o  Acetone and  acetic acid were destroyed  by ozonation.
   o  Acidic  pH enhanced the ozonation reactions.
                                   /
   o  Organics in  the RO retentate,  with  molecular weights
      ranging from 150  to 18,000, exhibited a greater ozone
      demand  than  did  those  in  the  UF retentate with molecular
      weights above  18,000 or those in  the RO permeate  with
      molecular weights below 150.

Chlorination of  the  UF and RO retentates  produced  volatile
halogenated organics, whereas  ozonation did not.   Ultraviolet
irradiation  of  the permeates  prior  to ozonation enhanced the
removal of organics.
                               379

-------
Research is needed to determine the changes in chemical species
produced in AAS effluents with changing F/M ratios and also  the
effects of ozonation of these compounds.

Ozone has been used for reduction of foaming, color, turbidity,
odor, and heavy metals  (3,  5, 7,  9) as  well as bacteria  and
viruses.  Limited  data (8)  indicate 10 to 30 percent BOD/COD
reductions at the  10  to 25  mg/1  ozone dosage used to achieve
disinfection, and little ammonia removal.  Diaper  (8) states that
a typical industrial  cyanide application destroyed 15 mg/1
cyanide with 80 to 88 mg/1 ozone.  An oil refinery used 20  to 40
mg/1 ozone to reduce effluent phenols to less than 0.015  mg/1.
Diaper found 1973 production costs were 8.0 and 3.5  cents  per
pound for ozone from  air and oxygen, respectively, apparently
exclusive of amortization costs,  and capital costs of $500 to
$1,000 per pound per day capacity.  Single units of  1,000  Ib/day
capacity are available.

A recent paper by Hardisty and Rosen (9) gives some details on
ozonating strong industrial wastes for removal of  cyanides,
phenol and COD.  Generally non-ferrous complexed cyanides, simple
cyanides and cyanates were readily destroyed with  1.85  to  3.8 mg
ozone per mg CN.  Ferrous complexed cyanides were  reduced but not
totally destroyed with 10 mg  ozone per mg total CN and residuals
were <2 mg/1 total CN . Complete oxidation of phenol to  C02  and
H-O would require 14  moles  ozone per mole  phenol  removed,  but
partial  oxidation  may be all that is needed.   At the  <1 mg/1
phenol  concentrations  in biological oxidation  effluents  the
intermediate organics formed  may  not be troublesome.   COD
reductions  were given for  raw wastewaters (9)  and showed
generally higher removals at  higher ozone doses.  Petrochemical
wastes required 2.5 mg ozone/per mg COD removed to reduce  COD
from 2,400 to 500 mg/1.

Ozone is more stable at acid pH  than at basic (5,  10),  but  the
                              380

-------
optimum ozone  treatment pH will  depend on the  waste and  the
desired  results.   Apparently  acid pH  is  also  good  for
disinfection  (5) but  basic pH  will enhance ammonia  removal (8,
10)  and organics  reduction (5) including phenols  (9).   Ozone
treatment  of  coal  conversion  wastewaters should be studied to
determine  applicability and optimization for metals removal (7),
cyanide, ammonia, and  COD reduction (5, 8, 9) and  enhancement of
follow-on  activated carbon treatment (11).

Chlorine--
Chlorination  with  elemental chlorine, chlorine  dioxide  or  various
chlorinating  compounds such as sodium and calcium hypochlorite is
the  most common  chemical oxidation method practiced for waste-
water treatment  at  the present time.  Nonetheless, chlorination
applications  to  coal  conversion wastewaters must  be   limited to
intermediate  treatment steps  to  avoid  formation of trihalometh-
anes   and chlorinated phenols in  final  effluents.  Cyanide and
ammonia destruction are two possible applications.  Pretreatment
for ammonia removal  after ozonation (12) and  before activated
carbon adsorption  (13) is another  possible application.

Alkaline chlorination of cyanide wastes, developed for treatment
of concentrated  metal plating  wastes  (14), is flexible and capa-
ble of treating  dilute or concentrated  wastes  to cyanide resid-
uals  of 0.2  mg/1.  In practice, about 8 parts chlorine by weight
plus 7.3 parts  NaOH are needed per part  cyanide destroyed.

In a discussion  of "breakpoint" chlorination for  ammonia removal,
it is shown that ammonia can  be   oxidized  to  nitrogen gas  with
about 8 parts chlorine per part ammonia  destroyed (13).   Sodium
hypochlorite (NaOCl)  is  recommended  instead of chlorine for ammo-
 nia oxidation because local  pH depression,  with its attendant
 problems,  does  not occur and less  TDS will be added  if neutral-
 ization is required.   Chlorine will  destroy  alkalinity  at  14.3
                                381

-------
mg/1  as  CaCOj  per mg/1 ammonia  oxidized.  If the  wastewater
alkalinity is  low, pH control will  be required using  lime or
NaOH.  Thus chlorine plus lime will add 12.2 mg/1, and NaOCl only
7.1 mg/1, of TDS  per mg/1 ammonia  oxidized.

Hydrogen Peroxide—
Hydrogen peroxide,  H202» is bulk transported as 70 percent  solu-
tion in water and as 35 percent and 50 percent solution in drums.
The concentrated  solution is diluted  as needed at the  point of
use.  Doses and usage are based on 100 percent ^0,.  The  major
wastewater uses of hydrogen peroxide are for destruction  of sul-
fide odors, correction of AAS sludge "bulking",  phenol  destruc-
tion and as a supplemental oxygen  supply for overloads or equip-
ment breakdowns.   Its advantages over  chlorination include oxi-
dation without TDS increase.  Acid to  neutral  pH's allow  the oxi-
dation of H2S to  elemental S.  Refining  uses  described  (15)  in-
cluded sulfide oxidation in sour waters during sour water strip-
per maintenance  and  supplemental  oxidation  of phenols and of
thiosulfate  effluents before discharge to a municipal  sewer
(16).

The literature describes several  applications of hydrogen per-
oxide to  the problems of rising  or  bulking sludge.   Rising
sludges  occur whenever nitrates present are reduced to elemental
nitrogen  at a rate sufficient for  the  entrapped nitrogen  to float
the sludge.  Ironically, underloading  AAS plants often results in
increased nitrification of ammonia, which is  desirable  per  se,
and thus  increases sludge rising potential.  Bulking  sludges  are
those  that will not settle due to  their density and  flocculant
nature.   The  primary cause of bulking  is low oxygen in the  aera-
tion tanks.  Hydrogen  peroxide has been used in the secondary
clarifier at  about 7  mg/1 for rising sludge  and in  the return
sludge lines  at 20 to 60 mg/1 for  bulking and  sludge  odors (16)
as well  as a means for increasing  the  dissolved oxygen  in  aera-
tion tanks.
                              .382

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Application Summary,  Doses  and Costs--
Ozone may be used  at  20  to  40 mg/1 for residual phenol reduction
and at 2  to 4  mg  ozone  per  mg  cyanide destroyed  to  achieve
cyanide residuals  of  £ 2 mg/1  total CN  .   COD reduction  in  raw
petrochemicals  wastes required 2.5 mg ozone per mg COD destroyed.
Ozone costs are estimated to be as follows in tertiary treatment
for a COD reduction  from 35 to 15 mg/1,  assuming 80 percent  uti-
lization  (3) of ozone produced from oxygen.

   Capacity,                                 Operating Cost,**
     MOD                    Capital Cost*        6/1000 Gal

      1                    $   556,000             54.4
      10                     3,025,000             31.6
      100                  20,900,000             22.4
»  Capital cost (3)  for  1969 updated  to 1977 by use of 2.8 multi-
   plying factor.
»* Operating cost  (3)  for  1969 updated  to  1977 by use  of  2.0
   multiplying factor.

These estimates agree reasonably well with Diaper  (8), whose 1973
rough estimate is  $500  capital  per  pound  ozone per day  capacity
for an oxygen-fed  plant.  The 20 mg/1 COD reduction would require
about  520 pounds ozone/day at 80 percent  utilization  per  MGD
plant flow.

Chlorine could be  used  in  intermediate  steps to  reduce  ammonia
and cyanide residuals.   Either  use  requires about  8 mg/1 chlorine
per mg/1 ammonia or  cyanide  destroyed.  Cyanide residuals  of  0.2
mg/1 are possible.  Chlorine is currently (1978)  $84-115/ton in
tank cars.
                               383

-------
Hydrogen peroxide could be used  for  biological waste treatment
plant sludge  control at 20 to 60 mg/1 in  the return sludge,  for
odor control  and to supply supplemental oxygen.  Current  bulk
costs are 40  to  44 
-------
    Organic Compounds Commonly Found-in Water," ES&T 11, No.  13,
    Dec.   1977.

7.   Shambaugh, R. L., and P. B.  Melnyk, "Removal of Heavy Metals
    Via Ozonation," JWPCF(50), Jan  1978, p. 113.

8.   Diaper, E. W. J., "Disinfection of Water and Wastewater  Using
    Ozone," presented  at  ACS,  Div. Env. Chem. ,  Chicago,  Aug.
    1973.

9.   Hardisty, D.  M.  and H. M. Rosen, "Industrial Wastewater
    Ozonation,"  presented at 32nd Purdue  Industrial  Waste
    Conference, May 1977.  813»

10.  "Pretreatment of Industrial Wastewaters  for Discharge Into
    Municipal Sewers," Seminar by  AWARE Inc,  Philadelphia, Pa.,
    Oct  1977.  Chp. V, pp A-1  to A-7, A-17, A-21.

11.  Guirquis, W., Cooper, T.,  Harris, J. and A. Ungar,  "Improved
    Performance  of Activated Carbon by  Pre-Ozonation," JWPCF,
    Feb.  1978.

12.  Personal Communication.  Mike  Mitchell of  Betz Laboratories,
    May  12, 1978.

13.  EPA  625/4-74-008, "Physical-Chemical Nitrogen Removal Waste-
    water  Treatment," July 1974, Technology Transfer.  498»

14.  "Alkaline Chlorination  of Cyanide  Waste  Liquors," Bulletin
    No.  102, Allied Chemical Co.,  Industrial Chemicals  Division,
    Morristown, N.J.  691*
                              385

-------
15.  Strunk, W. G., "Hydrogen Peroxide  for  Industrial Wastewater
    Pollution Control," Proceedings  1977 Conference on Treatment
    and Disposal of Industrial  Wastewaters and Residues,  pp. 119-
    125, April 1977,  Houston.   635*

16.  Ochs,  L. D. and  C.  W.  Cooke, "Industrial  Applications  of
    Hydrogen Peroxide" in Water - 1975, AIChE,  151, (71)  1975,
    pp. 59-63, edited by Bennett.  518»
                               386

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COSTS OF  WATER  TREATMENT

Basis for Development of Costs

As the quotations  of costs  in the  preceding presentations  on
individual water  treating methods  indicate,  there  are many
references to costs in the open literature.   These data require
updating  of investment and operating  costs and correlation  in
order  to obtain  a proper perspective.   Some of  the  short
references indicate a rather wide  variation  for the same process,
depending upon  the  feed stream  composition  and the residual  of
contaminants in the effluent,  and  all data that could be desired
are rarely present.  In some cases the  effective date of the cost
data is  not specified,  or the split  between amortization  and
operating costs is  not clear,  or  operating costs are based  on
outdated  figures and cannot be updated  due  to lack of detail  or
the influent and effluent compositions  are  either not specified
or apply  to wastes  far different  from  those in coal conversion
plants.  Most of these references  are to municipal plants.

We have  approached the problem  through correspondence with
process licensors or equipment vendors  and have requested  budget
cost figures based  on specific cases in which all available  data
on influent quantity and composition are supplied together  with
the required or desired residuals  of contaminants.  In order to
supply such data quantities from three  representative conceptual
designs have been used.  These are:

   o  Gasification  with p/o/t  production as exemplified  by  the
      Lurgi process in the  C.F.   Braun design for western  coal
      (294, 295, 296).

   o  Gasification  without  p/o/t production,  of which the  Bi-Gas
      process is an example, described  in the C.F. Braun  design
                              387

-------
      for  western coal (294,  295, 296).
   o  Liquefaction, as described in the SRC-II process  design by
      R.M.  Parsons for eastern  coal (814).

Compositions of wastewater  used  with the quantities from the
above designs were  those from  other  sources,  as  described
previously  in the section on  "Analyses of Waste  Streams."  For
gasification without p/o/t production, Koppers-Totzek analyses
were substituted, since no Bi-Gas data have been published.  For
liquefaction, H-Coal  data were  more complete  and these were
judged similar to those which would be obtained from SRC-II.

In order to develop the compositions of streams  intermediate in
the treating sequence,  it was necessary to  make  assumptions,
based on best engineering judgement, of  the  efficiency  of the
treating steps which  preceded the step  for  which costs were
requested.  Obviously,  this procedure must  eventually be
confirmed  by actual  testing  on wastewater from bench scale or
pilot plant operation or in a demonstration plant.  All licensors
and vendors quite  reasonably state that  data supplied must be
verified in this manner.

Equipment  vendors  usually supply only the cost of unassembled
equipment,  f.o.b. their supply  point.  Costs of freight,  assembly
and installation have been estimated  by  Pullman Kellogg, using
factors which we specify.  These are judgement factors that are
based on experience and on opinions of qualified personnel.

Licensors  usually supplied total capital cost directly, based on
actual installations.  These  included  Zimpro,  Inc. (wet air  oxi-
dation and  biological systems employing powdered carbon regene-
rated by wet air oxidation),  Chevron Research Co.  (stripping and
ammonia recovery), U. S. Steel  (stripping  and  ammonia recovery)
and American Lurgi (Phenosolvan phenol recovery).
                              388

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Licensors furnish process requirements  of  chemicals,  steam and
electric power  from  which operating  costs  based on up-to-date
utility values  can be assembled.   Equipment  vendors supply only
spotty data on utility requirements or none  at all  (e.g., no
pumping costs).  Time and manpower remaining in our project did
not permit detailed  estimation  of all  these  costs,  so  where
necessary we have resorted to the  use  of  estimated factors.

In order to update  costs reported  for  prior years we have ob-
tained cost indices  from Pullman Kellogg  (process plants) and
Engineering News Record (ENR), the  Water Quality Office-Sewage
Treatment Plant Index (WQO-STP) ,  and compilations by EPA of the
Large  City Advanced Treatment (LCAT) and  the Small City Conven-
tional Treatment (SCCT) indices.

The Pullman Kellogg cost index  is shown  in Figure  8-42. and
illustrates the sharp rise  in direct materials costs.  Direct
materials, as defined by Pullman Kellogg, includes all  furnaces,
exchangers, converters, towers,  drums  and tanks, pumps and  com-
pressors, special equipment,  utility conveying  and safety equip-
ment,  site preparation and foundations,  structural steel, build-
ings,  piping,  electrical,  instruments, paint, insulation,and
catalysts.  To  the direct materials costs  are added  operations
costs, which include construction labor  and supervision, design
Engineering, freight,  insurance,and  contractor's  overhead and
profit.  The sum of direct materials and operations  costs is the
total  "as built" cost of the plant.    An a/erage split of  these
two categories for  process type plants  (ammonia,  ethylene,
phenol, and crude oil distillation) is  60 percent  direct materials
and 40 percent operations  costs.  In  Figure 8-42 a line for
^construction labor is a representation of the  largest  component
(of operations cost and  it can be seen  that   this has  risen  at  a
lower rate than  direct  materials in  the 1970-1977 period.
Projections included beyond  this period  are speculative but are
                               389

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u>
vo
o
        w
        of,
        u
   3CO



   340




   320




   300




   280




   260




   240
«  220
        M
        a
        X
        111
        o
           200
           180
8  160

w
>
        c2

        a  120

        8
           100
                   MATERIALS INFLATION "60%

                   LABOR INFLATION    ~40%
                PHENOL



               AMMONIA,



       T—"BASE 1960=100
V?
     ETHYLENE
                i
               1967
                1969      1971      1973
                                                                     A * Ammonia Plants
                                                                     C » Crude Unit (Intcrmodiatc

                                                                         between Ethyl one and

                                                                         Phenol plants.)
                                                           CONSTRUCTION

                                                           LABOR
                                                                                  J	1
                                                  1975
                                                    1977
                                                                    1979
                                                                     1981
                                                                                     1983
              Figure  8-42.   Pullman  Kellogg  chemical plant  direct materials  and

                               construction labor costs.

-------
estimated  at  about 7.5 to 7.8 percent per year through  1980, with
labor costs at  the same escalation rate.  The Engineering News
Record (ENR)  index is shown for comparison in Figure  8-43.   This
is for skilled  labor and is generally used  more  for estimating
operating labor  costs than  for  estimating  construction labor
costs.

Indices specifically for  water treatment plants have  been
compiled  by EPA and its predecessor agencies  and  by  the Federal
Water Pollution  Control Federation (FWPCF).   These  are  for
municipal  water treatment plants, not industrial  water  treating.
Some of these indices are plotted on Figure  8-44  to illustrate
increases  of  costs over the period 1970-77  for  comparison with
the Pullman Kellogg  process  plant index.   One  illustration of
comparison is as  follows:
                 SCCT    LCAT (EPA)       Pullman Kellogg
(EPA)
190
273
44
Composite
100
138
38
Equipment
132
265
100
Labor
132
212
61
Composite
132
244
85
Factor for  1973
Factor for  1977
Percent increase
vThe inference  appears  to be that water treatment plant  costs have
;not risen  as  fast  as process plant costs.  Although this may be
true for municipal water treatment,  it must  be  remembered that
industrial water treatment is more complex than  municipal water
treatment, is  likely to be more costly than municipal  treatment
;and is  likely  to be less regulated.   We feel  that  the increase
probably lies  between  the two types of plants  compared  above, say
50 to 60 percent in the last four years.

Supporting cost data from open  literature are  those from Water
Purification Associates (480, 612), AWARE,  Inc. (643) and  Bechtel
(WateReuse-1975-AIChE).
                               391

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                          Figure 8-43.   Engineering News  Record  (ENR)skilled  labor  index.
                                                                                                              2


                                                                                                              r
                                                                                                              CP
                                                                                                              o
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vo
to
             3000
       o
       o
u
Q
55
       CS
       z
       u
     2000
                                          DJR INDEX
                                                                        NELSON REFINERY OPERATING

                                                                        INDEX  (includes Labor,  Fuel,

                                                                        Maintenance and Chemicals.)
             1000
                     I
                              I
                   1970
                      1971
                                      1972
                                         ..I	-

                                        1973
 J_
                                                         1974
1S75
1976
                                                                                      1977
                                                                                               1978
                                                                                                         300
                                                                                                         260



                                                                                                         240
                                      200



                                      100



                                      160



                                      140



                                      120




                                      100
                                                                                                       •1
                                                                                                       M


                                                                                                       W
                                                                                                       o
                                                                                                       TJ
                                                                                                       n
                                                                                                              O
                                   a
                                   o
                                   n

-------
UJ
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           300


           230


           200


           240


           220
         x 20°
         w
         Q
         2 180
to
8  160
            140
            120
            100
                 ,*— X—
                      o
                      o
                      01
                   (N
                   VD
                   cn
                                                           SEWAGE TRF.ATMLNT PLANT (STP)
                                                           CONSTRUCTION COST IHDKX
                                                                        NELSON REFINERY  CONSTRUCTION INDEX (1962=100)
SMALL CITY  CONVENTIONAL TREATMENT (SCCT)-
5 MGD


LARGE CITY  ADVANCED TREATMENT (LCAT)  -
50 t«.GD

Indices as  of  tliird ciunrtor 197J-100.
Separate components of index tracked arc:

- Labor
- Civil Materials
- Other Materials
- Equipment
- Construction overhead
- Buildings
                                              Figure 8-44.   Cost  indices maintained  by  EPA.

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From the Water  Purification Associates  reports, water  treating
costs, in rough ascending order, are shown  in Table 8-46.

The year basis  for the W.P.A. costs is  not clear in  all  cases,
but it appears  to be 1975.  Escalation of 10 to  15 percent should
probably be  added to bring the costs to  current  levels.

Bechtel presented  comparative  costs for  several types  of
evaporators,  ion exchange, and  reverse  osmosis in "WateReuse -
1975," published by AIChE.  For processing  810,000 Ibs/hr (2.33
MGD*)  of cooling tower blow-down,  the  following capital costs
were extracted  (an escalation of 30 percent was applied  to  make
the costs more  nearly current) :

                                                   Cost - $MM
Three  evaporator-crystallizers                         20.4
Two multi-stage flash (540,000 Ib/hr)
  plus Two evaporator/crystallizers
  (270,000 Ib/hr)                                     11.83
Two multi-stage flash units (700,000 Ib/hr)
  plus One evaporator-crystallizer (100,000  Ib/hr)      9.36
Four ion exchange units plus reverse osmosis
  plus Two multi-stage flash (326,000 Ib/hr)
  plus One evaporator-crystallizer (24,000  Ib/hr)       6.76

Comparison of the Bechtel figures with the  previous tabulation of
Water  Purification Associates figures leads to the conclusions
that:
    o  W.P.A.  figures are probably low  for evaporation.
    o  Combinations  of reverse  osmosis and ion exchange  with
        small evaporators for  their residues  is significantly
        cheaper than evaporator/crystallizers  alone.
        "Capitalized" operating costs   for one year  were  also
        included in  this article  and these supported  the  con-
        clusion that the fourth case above  is  to be preferred.
*Million  gallons per day        394

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          TABLE 8-46.  WATER TREATING COSTS FROM WATER
                 PURIFICATION ASSOCIATES REPORTS
   Process
Electrodialysis
Reverse Osmosis
Ion Exchange
Bioxidation

(Trickling Filter
plus High Purity
Oxygen Activated
Sludge)
Activated Carbon
Feed, Rate, Investment

Cooling Tower Blowdown
1  MOD  = $  600,000
10 MGD = $3,200,000

1  MGD = $1 ,700,000
10 MGD = $10,700,000

Boiler Feed Water
2.5 MGD =  $3,200,000
Wastewater (COD =
13,700 mg/1)
3.0 MGD« = $8,700,000
(incl. equalization,
sludge thickening &
filtration. Phenols
< 1 p pm)

Wastewater (COD = 2,000)
3.0 MGD = $4,200,000
Operating &
Amortization
Cost/ 1,000 gals

$0.56 (N. Mex.)
0.73
0.43

>$0.92
(Energy requirements
 not included)

$3.10
(Most cases of bio-
oxidation would be
lower.  Loading
selected is extreme-
ly high)
$2.00
                   Wastewater (COD =  10,000) $9.00
                   3.0 MGD = $11,400,000
Phenol Extraction
Wastewater  ( 6,000 ppm
phenols)
2.9 MGD = $9,000,000
(9456 phenol  recovery)
Gross  =  $3.57
Net  =  $2.57  (with
phenol sale  at 2 <
per  Ib)
Ammonia Recovery
Evaporation
Wet Oxidation
Wastewater  ( 6,000 mg/1
ammonia)
3.6 MGD  = $8,000,000
(200 ppm NH  residual,
9556 NH   recovery)

Wastewater
3.0 MGD  = $6,000.000
(95/6 recovery)

Wastewater  (95*  COD
removal)
3.0 MGD  = $22,000,000
 Gross  =  $4.03
 Net  =  $0.73  (with
 ammonia  sale at $140
 per  ton)
 $3.50-4.00
 $5.57
 (no credit  for  steam
 or power generation)
                                395

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This same Bechtel  article  also  gave the following  breakdown  of
cost which may have  general application:

 	   Item	           Percent of Purchased  Equipment
 Installation                               35-45
 Instrumentation                              13
 Piping                                       31
 Electrical                                 10-15
 Buildings                                    29
      Total add-ons  to obtain
        capital cost                        118-133

AWARE, Inc. (Associated Water and Air Resources,  Inc.,  Nashville,
Tenn.)  present a  course  on water  treating  (643)  in  which  an
equation for capital cost  of activated sludge in  municipal water
treatment is shown as:

   Capital Cost = 226 (MOD) + 45.6 (MGD)°-18

With this equation,  the capital cost (1969)  for  a 3.0 MGD plant
is $733,700.  When the Pullman Kellogg escalation factor of 2.52
is applied  for updating,  the  capital  cost  (1977)  becomes
$1,849,000.

It may be unfair to  compare this developed capital cost with  the
$8,000,000 cost developed  by Water  Purification Associates  for
activated sludge without equalization and sludge  handling, since
W.P.A.'s influent was much higher in COD and  their  effluent  was
much purer than municipal  practice.

For industrial waste capital costs AWARE presents the equation:

Cost = Qw(17(S0/Se)°-77+215)(l.05+(0.044)/kXv)
                               .396

-------
where   w   =  0.69 + 0.00019S0
       S0  =  Influent BOD, mg/1
       Se  =  Effluent BOD, mg/1
       Q   =  Flow rate, MGD
       k   =  Reaction rate, 1/mg/hr
       Xv  =  MLVSS,* mg/1

Applying the  quantities and  rates from  the  Water Purification
Associates  example:
       Se  =  1800
       S0  =  18,000
       Q   =  3.0
       k   =  0.000833
       Xv  =  4000
yields calculated capital  cost of $30,623,000.

The  installed cost calculated by the AWARE equation appears to be
excessively high, particularly in contrast to costs developed by
Braun for western coal  (29^,295,296) which in our opinion  gener-
ally appear to be on the high side. Braun, for example, shows the
equipment cost at $3,200,000  and  installed  cost at $19,000,000
for  an activated sludge system  fed with  Lurgi  wastewaters  from
which phenol  had previously been extracted.

We conclude that either the AWARE, Inc. equations for activated
sludge units  do not apply  to  the  cases under consideration, or
that the reaction rate  is  incorrect, since the equation for muni-
cipal plants  apparently yields low capital costs and the equation
for  industrial activated sludge  yields very  high capital  costs
when the quantities  and  compositions  employed in  the Water
Purification  Associates report, with no preceding phenol  extrac-
tion, are used.

•Mixed Liquor Volatile  Suspended Solids
                                397

-------
 Other cost equations given  by AWARE, Inc.  are as follows  for
 domestic and combined  wastes:
    Treatment Unit
  Pretreatment
  Primary Sedimentation
  Blower House
  Sludge Return Pumps
  Final Sedimentation
  Chlorination
  Anaerobic Digester
  Vacuum Filters
  Sludge Incinerator
  Control House
  Tertiary treatment (lime
   clarification, mixed media
   filtration)
  Carbon adsorption
                    1969  Capital  Cost  ($1.000)
                    .19  (Q)  °-63
                    17.3(SA)  + 6.7  (SA)°«1
                    13.6  +  7.6 (CFM/ 1,000)
                    4.6 + 1.45 Q
                    16.2CSA)  + 6.9/(SA)1-3
                    11.6  (Q)°.*7
                    V(1.34  +  13.8/V°-87)
                    16.5  +  48 (Area  in  sq.ft/100)
                    (S/24000)(170 +  7.15 S°-61)
                    51.6  (0)0.7
                    Cost  =  200  (Q)0.76
                    Cost  =  202  (Q)0.86
where  SA
        V
        S
        Q
surface area in 1,000 sq. ft.
volume in 1,000 cu. ft.
sludge production,  Ib/day
flow rate,  million  gallons/day  (MGD)
Formulas are  also  presented  for annual operating costs in  $/MGD
and curves for capital and operating costs  are presented  for
equalization,  oil separation,  neutralization (which includes
equalization,  oil  skimming,  chemical addition  and flocculation,
sedimentation,  and vacuum  filtration of  sludge),  primary
classification,  aerated lagoons, chemicals coagulation, dissolved
air flotation,  sand/mixed media filtration, chrome reduction, and
cyanide destruction.  All these cost equations and curves must be
converted from 1969 cost basis to  current  cost basis using  the
WQO-STP index  for  capital cost and ENR index for operating  cost.
                               398

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It should  be noted that EPA changed from use of WQO-STP to other
indices (LCAT,  SCOT, and CUSS)  in 1973.   Only the  SCCT is
considered applicable to the project.  In general,  this source of
cost information  was used only  to supplement  budget  costs
acquired from vendors and  licensors.
In order  to  convert purchased equipment costs  from vendors into
installed cost,  we  compared  the factors reported earlier by
Bechtel with  a  plant constructed in South America by Pullman
Kellogg.   This plant  was designed  by Engineering-Science,  Inc. of
Texas  and  costs  on a  Gulf  Coast basis were cited.  Also, the new
SCCT index adopted by EPA  has a breakdown which is included for
comparison:

                          Percent  of Purchased Equipment
Installation
Labor
Instrumentation
Piping
Electrical
Buildings
Buildings,
  including paving
Purchased equipment
Engineering-
Sciences, Inc.
306.8*
Included
14
22
17


1.6

Bechtel
35-45
-
13
31
10-15


29

SCCT (EPA)
252. 5»«
233.0
Apparently
included in
installation
and purchased
equipment
135.9
 17.9
100.0*
100.0
100.0
 •Purchased equipment in this  case  includes  some  installation
  costs
 "Civil and other material in  installation
                                399

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It is evident that there  is  a wide variation in  the  factors  that
could be  employed.  Part  of  this variation can be  explained by
defining  the differences  in  the  installations:
     o  The Engineering-Sciences,  Inc.  column  represents an
       impoundment basin of 13 million gallons, an  equalization
       basin of 3.3 million gallons, an activated sludge  system
       to  process  18.3  MGD (six 2,300,000 gallon basins)  and
       sludge  handling  consisting of  aerobic  digestion  and
       thickening.  It should be noted that a  labor component is
       included for installation of "purchased  equipment"  for
       this column.  Therefore  all other component percentages
       are low.
     o  The Bechtel column represents  such things as ion  ex-
       change,  reverse osmosis,and evaporators where  purchased
       packaged  equipment  is the nr in cost and little construc-
       tion  labor is required for installation  (minimum of
       earthwork, foundations, and piping).
     o The EPA Small City Conventional Treatment (SCCT)  column
       is  closely similar to the first column.   It  represents  a
       5 MGD municipal plant containing  bar screen,  grit cham-
       ber,  primary clarification,  conventional activated
       sludge,  chlorination, gravity thickening,and vacuum  fil-
       tration.  It indicates that purchased equipment could be
       only 11.3 to 20.3 percent of the  total  cost (average is
       1H.05 percent),  depending  on  location  in the  United
       States.

Development of Costs for  Activated Sludge Systems

Envirotech  Equipment Co.  (Division of EIMCO) supplied  equipment
costs for four hypothetical  cases for which we  provided  flows and
compositions.  The cases  are indentified  as follows:
                             400

-------
Case  No.  I:

Case  No.  II: -

Case  No.  Ill:

Case  No.  IV:
4.032 MGD of wastewater  from Lurgi gasification
(Braun design)
0.533 MGD of wastewater  from liquefaction  (Par-
sons design)
0.85 MGD of average  wastewater from p/o/t-pro-
ducing gasification
0.80 MGD of wastewater  from  liquefaction  (W.P.A.
basis)
TABLE 8-47 shows  the  size and  cost  of the  equipment  to be
supplied.   Flash mixing,  flocculation,and dissolved air  flotation
precede  the 2-stage activated sludge biological oxidation system.
Sludge is  thickened  by  dissolved air  flotation and aerobic
digestion.  Biological clarified effluent  is  filtered.   Total
equipment  costs are:
        Case  I
        Case  II
        Case  III
        Case  IV
          $1,120,000
          $  764,000
          $  467,000
          $1,288,000
In order  to  arrive  at  installed cost many other items need to  be
estimated:
Freight
Installation labor
Aerator platforms
Aerator basins
Surface preparation
 and painting
     Site preparation
      and drainage
     Pumps
     Instruments
     Piping
     Electrical equipment
Laboratory equipment
Foundations
Buildings
Engineering costs
Administrative costs
Contingency
Contractor overhead
 and profit
The Braun report  on  Western  coal  that was cited previously  shows
a factor  of 5.94 installed cost to equipment cost  ratio  for
                              401

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                                                        TAIH.r.  n-17.   1'UI.T.MAN  KKT.I.O<".r. COAL CONVERSION STUDY
                                                                                   (tJNVlROTECII.)..
O
K>
                          FLOW (GPM)

                          FLASH MIX - SIZE,  COST


                          FLOCCUL/TOR - SIZE,  COST


                          DAF-BR - SIZE, COST
CLARIFIER-C2S - SIZE, COST
1st Stage

AERATION - SIZE, COST
1st Stage

CLARIFIER-C2S - SIZE, COST
2nd Stage

AERATION - SIZE, COST
2nd Stage

DAF SLUDGE THICKENER -
SIZE, COST

DIGESTION SUBMERGED  TURBINE
AERATOR - SIZE, COST

BLOWER  - SIZE,  COST
                           TERTIARY  FILTERS  - SVG
                           SIZE,  COST
                             TOTAL EQUIPMENT
CASE I
GASIFICATION
2800
17' 0 X 8' SD
$13,000
38' 0 X 8* SD
$24,000
60' 0 x 8' SD
$105,000
130' 0 x 12' SD
$85,000
(8) 150 HP
$275,000
130'0 x 12 SD
$85,000
(2) 100 HP
$53,000
30' 0 x 71 SD
$64,000
(3) 150 HP
$121,000
(3) 75 HP
$45,000
(3) 22' 0
$250,000
$1,120,000
CASE II
LIQUEFACTION
370
T 0 x 7' SD
$8,000
5' 0 x 7' SD
$9,000
25 0 x 7' SD
$52,000
50' 0 x 12' SD
$48,000
(B) 150 lip
$275,000
50' 0 X 12' SD
$48,000
(2) 50 HP
$34,000
30' 0 x 7' SD
$64,000
(3) 150 HP
$121,000
(3) 75 HP
$45,000
(2) 10' 0
$60,000
$764,000
CASE III
GASIFICATION
590
9* 0 x 7' SD
$9,000
21' 0 x 7' SD
$10,000
30' 0x7' SD
$64,000
65' 0 x 12' SD
$53,000
(2) 125 HP
$57,000
65' 0 x 12' SD
$53,000
(2) 25 HP
$25,000
25' 0 x 7* SD
$55,000
(2) 40 HP
$42,000
(2) 25 HP
$18,000
(3) 10' 0
$90,000
$476,000
CASE IV
LIQUEFACTION
555
9' 0 x 7' SD
$9,000
(1) 21' 0 x 7' SD
$10,000
(1) 30' 0 x 7' SD
$64,000
(1) 65' 0 X 12' SD
$53,000
(16) 150 HP
$549,000
65' 0 x 12' SD
$53,000
(2) 125 HP
$57,000
45' 0 x 8' SD
$80,000
(6) 150 HP
$233,000
(6) 75 HP
$90,000
(3) 10' 0
$90,000
$1,288,000

-------
biological oxidation for Lurgi and 5.2  for  HyGas.  For  ammonia
recovery and stripping  for  Bi-Gas,  the ratio is 4.4.

Volume and depth of  the aeration  basins  was  supplied as  shown
below.  These will  be  assumed rectangular,  constructed  of one
foot thick reinforced concrete, with  3 to  4 feet projecting above
grade and the rest  below grade.  Costs  of these basins  are not
included in equipment costs.

   Case No.              I          II        III         IV
   1st stage basin
    Volume, CF      1,340,000   1,390,000  303,000     2,600,000
    Depth, ft.             20         20        15            20
   2nd stage basin
    Volume, CF        253,000     132,000    58,000       245,000
    Depth, ft.             15          12        9            15
   Sludge Digester
   Basin
    Volume, CF        150,000     160,000    78,000       303,000
    Depth, ft.             20          20        15            20

Because of the shortage of time and manpower it  was not  possible
to define the system in detail.  We therefore  resorted to  factors
to obtain the investment cost to  equipment cost  ratio.

One  approach is to use the EPA/SCCT  breakdown  for municipal
plants where equipment  cost averages 14.05 percent of total cost
for the U. S.  Investments obtained in  this  manner would  be:

        Case I            $7,971,530
        Case II           $5,437,720
        Case III          $3,387,900
        Case IV           $9,167,260
                                403

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The Water Purification Associates  report  (480)  on  page 374 shows
the following basis for obtaining  capital costs of air activated
sludge plants:

Aeration Basin   (Configuration as          $240  per cu  yd.
                illustrated on p.  372)
Aerators                                  $600  per installed  HP
Clarifiers      (Curve - p. 301)
DAF thickeners   (Curve - p. 375)
Vacuum filters   (Curve - p. 375)
Operating Costs
     Amortization      15 percent  of capital/yr.
     Maintenance        3 percent  of capital/yr.
     Electricity        2
-------
Also,  the EPA/STP index for the above was 250,  which  corresponds
to the  year  1975.  Costs should be increased for inflation alone
on the  order of 15 percent.  The other omitted  items  would pro-
bably increase the  costs at  least  to those obtained  by using
purchased equipment cost 4 0.1405  from the EPA/SCCT  breakdown.

If we  assume an overall relation, from the  Engineering-Science,
Inc.  work mentioned  earlier,  of  total cost =  3.12  (installed
equipment cost), the total costs  obtained  would undoubtedly be
high.   Items  not  included  in  "installed equipment"  in  the
Engineering-Sciences, Inc. method are mainly earthwork,  concrete,
control house,  electrical equipment,  connecting piping, and in-
direct  costs.   Indirect cost is 8? percent of installed  cost, or
39 percent of base  construction  cost or  40.9 percent  of  the
amount  added to "installed equipment" costs.  For aeration basin
costs  about half was stated as installed cost and half as earth-
work  and concrete.  The factor of 3.12 could be adjusted downward
for this.  Bemoving half of the aeration basin cost in the four-
case  tabulation and applying the 3«12 factor yields the  following
capital costs:
     Case I            $12,792,000
     Case II           $11,107,000
     Case III          $ 5,663,000
     Case IV           $18,907,000
These  figures  still appear to be excessive, although not as high
as those in  the Braun report.

Additional information was obtained  from  Envirotech, including
their  estimates of installed cost of supplied equipment and more
details on individual equipment,  in  order  to  determine the re-
mainder of the facilities to be installed  (mainly concrete basins
and foundations) and to ascertain which items were not supplied.
A process flowsheet for Case  I,  Figure 8-45,  was then prepared
                               405

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         17'D X 8"      3«'D X 8


                  J FLOCCULATOR
1.  AIL FLOWS ARE JUB/HR
   UNLESS SPECIFIED
   OTHERWISE
2.  EQUIPMENT SUES SUP-
   PLIED BIT EHVIBOTECH
   PROCESS EQUIPMENT
                           1,366,100 I/HR
                           + 11,000 I/HR
                            129,700 I/HR
                            + 1046 I/HR
                                                      23,100 I/HR
                                                      + 2,000 I/MR
                                                         SOLIDS
                                                                            / 49,500 LB/HR
                                                                             + 2000 LB/HR SOLIDS
Figure  8-45.- Flowsheet  for  Case  I  (Lurgi gasification).

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for  use  by  the Pullman Kellogg Cost Services Division in estimat-
ing  the  installed cost of the activated sludge  treatment  system.
Details  of  the estimate are shown in TABLE  8-48.

Qualifications given by the  Pullman Kellogg estimator  were as
follows:
     o   Site  is assumed clear and level with no  rock.
     o   Foundation quantities were estimated in-house  using  the
        equipment sketches furnished by Envirotech.
     o   Power  is  assumed to  be  available at battery  limits at
        required voltage.  No major substations or  switch gear
        are included.
     o   Bulk  commodities were ratioed from major equipment  using
        best  historical data.
     o   Contractor's  costs  (indirect  material,  engineering,
        insurance and  overhead and profit) were  based  on normal
        general contractor practices and percentages.
     o   No  forward escalation is included.
     o   No  estimate  accuracy is stated due to  the  preliminary
        nature of the  data and the limited time spent.   Estimate
        is  for budget  purposes only.

The  contingency  in  the estimate is an allowance  for  undefined
items.   The  contingency includes freight costs  that  are  not
otherwise estimated, although the  estimator feels  that  freight
could be considered  to be included with  the  ratioing factors.
The  contingency allows for unforeseen costs such  as additional
engineering requirements and additional equipment.

Startup  costs  are not  included in the estimate.   These  and  other
items such  as  interest during construction, working  capital  for
initial operation  and cost  of  land would increase the actual
capital  commitment required.
                               407

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              TABLE 8-48.  ESTIMATED INVESTMENT FOR
                ACTIVATED SLUDGE TREATMENT SYSTEM
                            Direct Material     Subcontracts*

Major Equipment               $ 1,025,000
Site Preparation                                  $  500,000
Steel Platforms, Walkways         100,000
Piping                            500,000
Electrical                        300,000
Instruments                       200,000
Misc. Sumps, Lift Stations                            50,000
Painting                                             100,000
Assembly,  Earthwork,
 Foundations                  	          1.9^5.OOP
  Total Direct Material       $ 2,125,000
  Total Subcontracts           $ 2,595,000

Construction Labor            $ 2,308,000
Indirect Material                 235,000
Engineering                       750 000
Sales and  Use Tax                 150,000
Insurance                      	50,000
  Total Bare Cost             $ 8,213,000
Contractor Overhead
 and Profit                     1,250,000
Contingency                     1,250,000
  Total Investment            $10,713,000
•Includes some assembly costs furnished by Envirotech
                               408

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The total  investment  cost  shown  for Case I may be rounded  off to
$10,000,000.   The  ratio  of purchased equipment cost (furnished by
Envirotech)  to total  cost  is  0.112, a  fair check with the average
ratio  in EPA's SCCT index  of  0.1405 in a range of 0.113 to 0.203.

Using  the  equipment costs  divided  by 0.112 for Cases II,  III  and
IV, their  investments  are:
    Case  II           $ 6,820,000
    Case  III          $ 4,250,000
    Case  IV           $11,500,000

Freight Costs

Since  relative locations of equipment  manufacturers'  facilities
and proposed  coal conversion plants  are  unknown and  variable,
some orientation  on freight costs is  provided by the  following
from Pullman  Kellogg1s Expediting  and  Traffic Department.

Freight costs are a  function of origin,  destination,  weight,
volume and commodity.  Equipment vendors generally quote costs of
equipment  "knocked down" so that it can  be  shipped to  the con-
struction  site by  truck  or rail  within the U.S.  Freight costs are
paid by the  buyer  in  addition to quoted price.

As an example, shipping  by  truck from  Los Angeles  to  Houston
{about 1,800 miles would cost decreasing amounts per 100 pounds as
the load neared a  full truck  load.  A  full truck load  would be
about  60,000  to 70,000 pounds as limited  by  highway  regulations.
Heavier haulers are available,  but might  be restricted  in some
states.
       Weight Range                  Cost  per  100 Ibs
      1,000  -  2,000  Ibs                  $12.00
      2,000  -  5,000  Ibs                    10.00
      5,000  - 10,000  Ibs                    9.00
     10,000  - Truck load                    7.50
     Full  Truck Load                         6.00
                                409

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Thus, the freight  cost on a 70,000 pound  shipment would be $4,200
by truck from Los  Angeles to Houston.   Shipping pipe  the  same
distance would cost about $1.00 per 100 pounds  less.

Depending on  dimensions of the shipment,  it  might be necessary to
use  rail  freight  beginning at 50,000 to 60,000 pounds.   Rail
rates are generally about $2.00 per  100  pounds higher  than the
truck rates cited.  Therefore rail shipment  of  the 70,000  pounds
of freight from Los Angeles to Houston would cost $5,600.

Ocean or barge freight would probably not prove practical  unless
the points of origin and destination were conveniently  located
along the same coast or navigable  stream.  For coal  conversion
plants these  circumstances appear to  be unlikely.

Costs for Side-Stream Softening of Cooling Tower Blowdown

An analysis of side-stream softening  of cooling tower  blowdown an
its effect on a refinery cooling  tower  system is  contained in
"Economic Attractiveness of Side-Stream  Softening,"  a  paper by
Marc Curtis,  Calvin Morgan Associates, Houston  that  was presented
at the Third Annual  Conference  in  Treatment  and  Disposal of
Industrial Wastewaters and Residues,  April 18-20, 1978.

Equipment cost  (presumably installed)  for a  600  GPM  (300,000
Ib/hr)  side-stream softening plant  operating  on cooling tower
blowdown was  presented as:
                              -410

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                                             Cost (1977)
     Chemical Storage,  handling and controls
     Softening reactor
     Sand filter
     Filter press
     Pump station (3-600 GPM pumps, foundation,
       controls and fittings)
     Contractor fees
     Engineering
     Piping ($3.00/in/ft, installed)
 $
 50,000
100,000
 20,000
150,000

 20,000
350,000
 93,000
230,000
       Total
$1,023,000
This installation would change the costs of operating the  cooling
tower as follows:
     Item
   Chromate
   Zinc
   Polyphosphate
   Chlorine
   Ca(OH)2
   Na2C03
   H2S04
   Raw Water costs
   Water Treatment costs
   Wastewater costs (1)
   Pumping
   Sludge disposal costs (2)
   Labor
   Maintenance (3)
     Total Annual Cost
                                Annual Costs (1977)

$













$1
Before
273,000
37,000
49,000
48,000
0
0
0
700,000
700,000
131,000
6,000
0
0
0
,944,000
After
$ 55,000
23,000
0
24,000
77,000
178,000
11,000
595,000
595,000
0
3,000
37,000
130,000
19,000
$1,747,000
See notes on following page
                                411

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   (1) $0.25/1000  gal  based on activated sludge with 20 mg/1  of
       Amoco PX-21  powdered activated carbon.
   (2) Estimated at $30 per ton.
   (3) Estimated at 2% of equipment cost.

API Separator Cost

An equation for  estimating the cost of API oil-water separators
is given in the  Stanford Research Institute report number 80 (804)
as:
     Cost (1969) =  $58,000 (MGD)°-81*

To this should be added 35 to MO percent for "associated facili-
ties and an escalation factor of 2.23 to yield:

     Total Installed Cost (1977) - $181,000(MGD)°-81*

The report states that operating costs are 1.2
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Typical  installed  costs  vs. capacity for multiple hearth furnaces
and rotary kilns are:
   Capacity,  Ib/day    Purchased Equipment      Installed Cost
        5,000            $  240,000              $  850,000
       10,000              360,000               1,270,000
       30,000              770,000               2,700,000
       60,000             1,200,000               4,200,000

Installation costs include  foundations,  structural equipment
setting,  electrical,  instrumentation,  site preparation,
engineering,  contractor  overhead and profit and indirect costs.
Utility and  offsite  facilities  are assumed  available at battery
limits.   The  authors of  the paper  further estimated time required
to design, procure,  install, and start  up  the furnace to be  two
years if 12-month  delivery time for equipment can be obtained.

Operating  costs  shown  for reactivating  spent  granular carbon were
shown as:
                             Annual Operating Costs ($1 ,000)
   Capacity,
    Ib carbon/day	   5,000   10,000    30.000   60,000
   Fuel: 8,000 Btu/hr  at
      $3.00/MM Btu             45       90       265       525
   Power at  3
-------
It is evident  that the main costs aside  from amortization  are
fuel, makeup carbon and maintenance.

Dry Discharge  Method - Cost Data

Dry solids  discharge was required at  the Peoples Gas SNG plant at
Elwood,  111. due to restricted  disposal alternatives.  This plant
was constructed by Pullman Kellogg.   The  water treating  system
was designed by a water technology consultant and Illinois  Water
Treatment Company.  Reference is  "Operating Experiences  with a
Zero Discharge Deionizer," by Krol, Jones,  Picht, and  Martin
(659).   The paper was presented  at the 38th  Annual Meeting of the
International Water  Conference, Engineers Society of Western
Pennsylvania,  and printed by Illinois Water  Treatment Company in
1977.

Components  of the  system are weak  acid cation treatment  to
produce  cooling water makeup, followed by  strong acid cation  and
weak base anion beds.   The treated water is  then joined  by  waste
evaporator condensate  and decarbonated  by aeration.   The
deaerated  stream  is  combined with  process condensate and  the
combined flow  is polished by two-bed  strong  acid, strong base ion
exchangers.  Regeneration wastes are  separately evaporated in two
3-stage evaporators to  about  20  percent  solids and then
spray-dried, using naphtha for  fuel.  A bag filter  follows  the
spray drier to collect the dry  solids. HC1  is used in regenera-
tion instead of HjSO.  to avoid  calcium sulfate scale formation
and consequent heat exchanger fouling in the evaporators.

Operating costs of the first set of ion exchangers, that  produce
cooling  tower makeup,  were (1977)  $1.057.1,000 gallons.   Operating
costs of the total  system, producing boiler feedwater  quality
water, were (1977) $2.69/ 1,000 gallons, consisting of (per 1,000
                              414

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gallons)  energy  charges at 45.3*, chemicals at 72.5*,  labor  and
maintenance  at  48.4*, salt  disposal at 4.1* and  capital  and
insurance charges  at 98.7*.

The basis for these operating costs was:
          Electricity                  2.17*/KWH
          Synthetic Gas                0.4*/CF
          Naphtha                      32*/gal
          HC1 (30?)                    2.8*/lb
          NaOH (100?)                  9.26*/lb
          W.A. Cation Resin            $86.00/CF
          S.A. Cation Resin            $40.00/CF
          W.B. Anion Resin             $102.00/CF
          S.A. Cation Resin (10?)      $45.10/CF
          S.B. Anion Resin             $112.00/CF

          Labor  and Maintenance        $12.00/hr
          Capital  Charges              $10?/year

The labor and maintenance figure  was  projected.   In actual
operation the spray dryer needed cleaning every three days, more
frequently  than  anticipated,  and increased the  labor  and
maintenance  charges.   The condition  is considered  to  be
correctable.

An interesting note: in operation it was  found to be unnecessary
to blow down  the cooling tower because of the efficiency  of  the
weak acid cation treatment.  Provision had been made in the plant
design for blow down  to be  fed  to one  of the evaporators  and
elimination of this stream reduced the evaporator load.

Operating Costs  of Water Treating Processes

The open  literature and government  reports contain many  refer-
ences  quoting operating costs for water treating processes.  Most
                               415

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of these costs  are presented as cents/thousand  gallons wastewater
treated.  Generally these costs purport to  include amortization.
As will be illustrated in this section, use of  such data is risky
since many  are out  of date, the  bases for utility costs  and
amortization are hazy at best, and they mask the wide  variation
that can  be encountered due to  capacity, feed, and  effluent
variations.

Complete Operating Cost Estimates—
The only truly  unassailable method of obtaining and portraying
operating costs is to proceed on a single case basis where feed
capacity and composition are known, all utility requirements are
stated,  values  of utilities are  stated and all capital-related
items are clearly identified.  Such a procedure was  possible on
several  processes where licensors supplied  data based on feed and
effluent compositions specified  by Pullman Kellogg.   The cost
analyses for Phenosolvan, Chevron Stripping and Ammonia Recovery
and Zimpro Wet  Air Oxidation are shown in Table 8-49.

Utility costs are based on a Pullman Kellogg article  in Chemical
Engineering, January 21, 1974, "Energy Conservation  in  New Plant
Design,"  by J.  B.  Fleming, J.  R. Lambrix,   and M. R.  Smith.
Utility  prices quoted in this  article were  projected  for the
period  1975-1980:

   Fuel            Natural Gas                 $0.80 /MM  Btu
                  Light Hydrocarbons          $1.50 /MM  Btu
                  No. 1 and No. 2 Fuel Oil    $1.30 /MM  Btu
                  Bunker C Fuel Oil           $1.20 /MM  Btu
   Steam          500 to 750 psig             $2.00 /I,000 Ibs
                  20 to 200 psig              $0.50 /I,000 Ibs
   Electricity                                 $0.015/KWH
   Cooling Water                               $0.04 /I,000 gals
                               416

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            TABLE 8-49.  OPERATING COSTS OF SELECTED
                 WASTEWATER TREATMENT PROCESSES
Capacity,  MGD
Capital Investment,
  $MM
    Phenosolvan

              3.6

             13.871

     288 to 972

          5,400
Steam, 1,000 Ibs/day
Cooling Water,
  1,000 gals/day
Electric Power,
  KWH/day          14,400 to 21,600
Labor,
  man-shifts/day
Isopropyl Ether,
  lbs/1,000 gal (1)
Caustic Soda (20%
  soln.), Ibs/hr (2)
Corrosion Inhibitor,
  cost per day

Cost of Utilities,
  Labor, Chemicals,
    per day
    per 1,000 gals

Credit for Steam
  Produced,
    per day
    Per 1,000 gals
Capital-Related Items  (3),
    per day
    per 1,000 gals
          N.A.


       0.6 to 1.2
$1,058 to 2,387
    $0.29 to  0.67
         $5,700
             $1.58
Total Treatment Cost,
    per day         $6,758 to 8,087
    per 1,000 gals       $1.87 to 2.25
                                         Chevron
                                         Stripping and
                                         Ammonia
                                         Recovery	
               Zimpro Wet Air
               Oxidation of
               Liquefaction
               Water
     3.6             0.533

    12.00           14.00

 8,760   (Produce  720)
 5,472

43,200

     0.5
                        2,500

                       $1,000
$9,050
    $2.51
$4,932
    $1.37
                      $13,982
                           $3.88
  2,160

138,700

      3
 $2,407
     $4.51
                                      ($1,440)
                                          ($2.70)
 $5,753
    $10.79
                $6,720
                   $12.60
 (1) At $0.19 per pound
 (2) At $0.23 per pound 100 percent NaOH
 (3) Includes amortization, maintenance,  insurance, etc.
                              417

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To this list should  be added the cost of boiler  feed water, which
we assumed at $0.10/1,000 gallons.

Although some of the utility  costs  may be open  to argument in
various  sections of the  U.S.,  they  are  being  used in  this
analysis  for the sake of consistency.   Local  values  can be
substituted, provided that the utility quantity  is  stated.

Operating labor  rate was taken as $80 per man  per  shift.

Chemical prices were  taken  from the  "Chemical Marketing
Reporter."

American Lurgi and Chevron furnished data from which  the  treat-
ment costs of smaller capacity plants were calculated:
   Capacity,  MGD
   Investment, $MM
                         Phenosolvan
0.533
 5.07
    Chevron
 Stripping and
Ammonia Recovery
    1.08
    6.00
                             per 1,000
                    per day     gals
   Operating
     Costs        $ 157-353   $0.29-0.67
   Capital  Costs      2.083   	3.91
   Total  Treat-
     ment Cost   $2,240-2,436 $4.20-4.58
                        per 1,000
                per day     gals
                $3.759
                $2.466

                $6,225
        $3.51
        $2.28

        $5.79
Comparison  of the total treatments costs in $  per  1000 gallons  in
the larger  plants and the smaller plants indicates the  variation
in costs  with capacity and emphasizes the danger  of  using the
undefined "typical" costs that  are  often quoted  in the litera-
ture.
                              418

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Adequate  data were supplied for operating cost calculations  for
biological oxidation  using powdered  activated  carbon  and
regeneration of the carbon with Zimpro's wet  oxidation technique.
Zimpro  supplied the basic figures and has cooperated  with  DuPont
on the  overall process.  The process will be referred to  by  the
DuPont  simplified  designation PACT (Powdered Activated  Carbon
Treatment).  Costs are shown  in  Table 8-50.   Note  that  phenol
was extracted from the larger flow prior to  biological oxidation.

The striking aspect  in comparison of the  two systems  is  that
despite the difference in capacity, each plant processes about
the same  total amount of BOD per day, the total treatment costs
per day are virtually the same and the treatment  costs  per 1,000
gallons are in about the same  ratio as are the  BOD's  in  the
feeds.  From this comparison the conclusion  may be  drawn that for
the PACT  process  with carbon  regeneration  the total treatment
costs are  directly proportional  to  the BOD  content  of  the  feed
and very  much less dependent on the volumetric  throughput.

Partial Operating Cost Estimates—
For other  water treatment processes only partial operating costs
could be  developed from  information received.   Comments  on these
costs follow.

Flotation—The electric  power  required  to operate the  air
compressor and pumps  can be calculated:

    Capacity, MGD                    4.03    0.85      0.53
    Electric Power,  per  1,000 gals  $0.004   $0.006   $0.005
                     per day        $17.30   $5.50    S2.90

The required alum and polyelectrolyte quantities would have to be
determined experimentally.  If pH adjustment were  necessary,  the
cost of the adjustment chemicals  would be chargeable  to  the
                               419

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      TABLE 8-50.  OPERATING COSTS FOR BIOLOGICAL OXIDATION
                 WITH POWDERED ACTIVATED CARBON
Feed Source
Prior Phenol
                      Capacity 3»6 MGD
                      Lurgi Wastewater
                                            Capacity 1.086 MGD
                                              SRC-II Combined
                                                 Wastewater
Extraction?
BOD, mg/1 1
Electric Power,
KWH/day 59
Labor,
man-shifts/day
Activated Carbon,
$0.28/lb, Ibs/day 3
Polymer, $2.50/lb,
Ibs/day
Phosphorus,
$0.235/lb, Ibs/day
per day
Cost of Utilities, $2,495
Capital-Related
Items* $4,110
Yes
,700

,000

6

,000

68

510
per 1,000
$0.69

1.14
No
5,800

54,000

6

3,000

18

526
gals per dav per l ^Jjno^ qals
$2,298 $2.11

$3,904 3.59
Total Treatment
  Cost
                   $6,605
                                $1.83
$6,202     $5.70
•At 15 percent of capital per year
                                420

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process.   As an example of these costs,  we  could  assume that 100
mg/1 of alum is used,  as at the Fort  Lewis, Wash.  50  TPD SRC
plant.   This cost  works out to be $205.50 per day  or  $0.051 per
1000 gallons for the 4.03  MGD plant.  This is  more than ten times
the cost  of electricity and it  is obvious that  chemical costs
will be controlling  in  the flotation  process.

Biological  Oxidation--Electric  power  to  operate the  aerator
motors  must be considered.  Envirotech furnished  the data  for the
four cases described earlier in  the report.   Power  requirement is
a direct  function  of BOD removed:
  Capacity, MGD
  BOD removed, Ibs/hr
    1st stage
    2nd stage
  Total
                                Lurgi
                        Combined
                      Liquefaction
                       Wastewater
4.03
1,720
181
1,901
0.85
480
51
531
0.80
4,230
212
4,442
0.53
1,880
94
1,974
  Electric Power Costs
    Per day
    Per 1,000 gals
    Per 1,000 Ib BOD
      removed
$358     $84       $676        $358
$  0.094 $ 0.096   $  0.85     $  0.678

$ 20.20  $17.31    $ 18.57     $ 20.88
Other  costs  of  biological  oxidation  are  better  illustrated in the
examples  furnished  by  Zimpro  for  the  PACT  process  and include air
compressor power, phosphorus  costs,  labor  and amortization.

Evaporation—Envirotech  (Goslin)  furnished  the  basis for develop-
ment of the  following  operating costs:
                              421

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   Feed Rate,  Ibs/hr      283.700          	315.580	
                     per     per 1,000      per      per 1,000
                     day       gals         day        gals
   Steam,  18 to 150
     psig,$0.50/ 1,000
     Ibs            $732      $0.90         $814      $0.90
   Electric Power,
     $0.015/KWH       2H       0.03           30       0.03
   Cooling Water,
     $0.0*t/ 1,000 gal  122       0.15          137       0.15
   Total Operating
     Cost            $878      $1.08         $981      $1.08

This is one process where  capacity  governs  operating  cost
directly,  since chemical reactions or additions are involved only
when it is necessary to control scale formation.

Demineralization—For demineralization  (ion exchange)  of  water
having the analysis used by  Braun for the  western coal  gasifi-
cation designs, L*A Water furnished the  basis for these costs:

     Capacity                 1,137 GPM  (1.64 MGD)
     Regenerations per day    6.82
     Sulfuric  Acid            $209/day     ($0.13/1,000 gals)
     Caustic                 $l605/day    ($0.98/1,000 gals)
     Electricity              $3.07/day    (0.003/1,000 gals)

Again  it  is obvious  that chemical  costs  are  governing in the
operating  costs.  Chemical costs vary directly with the necessity
for regeneration of the resin beds, which  in turn is a  function
of the  feed water composition (amounts of  anions and cations to
be removed)  and the size of  the resin beds.
                              422

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Reverse Osmosis--The operating cost  is governed  largely  by
pumping  cost.   L*A  Water  furnished  the  basis  for the  following:
     Effluent  Flow                           1,540  gpm (2.22 MGD)
     Electric  Power,  $0.015/KWH,  per  day      $244
                           per  1,000  qals    $0.11

Greater  costs  than  the  above  could  be incurred by  the  necessity
for filtration preceding  the  reverse  osmosis  unit.  No  costs were
supplied for  operating  the  filter unit.

Demineralization and  Reverse  Osmosis—Probably the  best operating
costs to use  are those  appearing in a Dow Chemical  advertisement
(Chemical  Engineering,  April  10,  1978).   Total operating costs,
including  capital factors,  are  shown  as follows:

   Feed  Rate                       	500.000 gals per day
   Total Dissolved  Solids
     (ppm  as  CaCCO               200         360          600
   Ion Exchange Cost, per
     1,000 gals                    $1.15       $1.60        $2.50
   Reverse Osmosis  cost,  per
     1,000 gals                    $0.32       $0.32        $0.34
   Reverse Osmosis  Preceding
     Ion Exchange Costs,  per
     1,000 gals                    $1-60       S1'60        $1'65
                               423

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Budget Cost Estimates Received  from Licensors and Vendors

Stripping and Ammonia Recovery  in the Chevron WWT Process—
Cost data for stripping of H  S,  CO ,and NH   and  ammonia recovery
were furnished to us  by  the  Chevron Research Company for their
licensed WWT process, based on  flows and compositions for three
cases:  (1) Lurgi  (p/o/t-producing gasification),  (2)  Bi-Gas/
Kopper-Totzek (non-p/o/t  producing gasification)  and (3) SRC-II
(liquefaction plus  non-p/o/t-producing gasification to  produce
fuel gas and hydrogen).  In Cases 1 and 3,  phenol  extraction was
simulated (by calculation)  preceding their  stripping process.
Compositions and flows are discussed in a following section of
this  report  entitled "Integrated  Schemes  for  Wastewater
Treatment."

Figure 8-46 is a block  flow diagram of  the Chevron Research
process.  The process description submitted was as follows:
   The Chevron Waste  Water Treating Process  (WWT Process) is  a
   patented process  for treating foul water streams from petroleum
   refineries, coal  processing  plants, and  synthetic  fuel plants
   to recover and separate high purity ammonia and hydrogen sul-
   fide and to recover clean  water for reuse or discharge.   It  is
   particularly applicable  to foul water  streams from  hydro-
   treaters and hydrocrackers.   Ammonia recovery from foul water
   effluents from FCC and  coking plants also can  be considered.

   The WWT process consists basically of two distillation  columns.
   Overhead product  of one column is ILS gas containing less than
   30 ppm by weight  of ammonia.  The overhead  product from the
   other distillation column  is ammonia containing less than 5 ppm
   by weight of ILS.  This ammonia can be  liquefied  and  sold as
   anhydrous  material or  sold in  aqueous  form.   It  meets  all
   agricultural grade specifications.  The  stripped water  contains
   less than 50 ppm  of NH3 and 5  ppm H2 S  by  weight.  It can be
                              424

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                                 HYDROCARBONS
                    SOUR WATER
(J\
                                            DEGASSER
                                                                        ACID GAS TO SULFUR
                                                             WATER
                                                              ACID GAS
                                                              STRIPPER
                                                                           RECOVERY
                                                                               AMMONIA
                                                                               STRIPPER
At-iflONIA PRODUCT GAS   ^
TO INCINERATION OI! SALES
    WATER PRODUCT
                                                                                             FOR REUSE OR DISPOSAL
                                CAUSTIC AS  NEEDED TO RELIEVE  NH- FIXATION
                             Figure  8-46.   The  Chevron WWT process.

-------
   recycled to refinery process  units,  except for a small  bleed
   stream which is normally taken  to  prevent  buildup  of  trace
   inpurities.  Reduction in refinery effluents  and clean make-up
   water demand have made the WWT  Process  attractive  in  several
   situations.

   Thirteen WWT plants are in operation  or under construction,  one
   of which has been in operation for about nine years.

TABLES 8-51, 8-52,  8-53 and 8-54 illustrate  investment and operat-
ing costs furnished by Chevron for  Cases 1 and  3.  It was  stated
that ammonia recovery  was not  justified for Case 2; however,  it
will be necessary to install the stripping towers for this  Case,
even if ammonia is  incinerated instead of recovered  for sale.

Stripping and Ammonia Recovery in the Phosam-W  Process—
An alternate for the Chevron WWT  Process is the  Phosam-W  process,
licensed by U.S. Steel Co.   Stripping,  separation of C02  and   H 2S
from NH-, and recovery of ammonia  by  ammonium phosphate  solvent
are included.

Costs for Phosam-W systems  have  been quoted  by  Water Purificaton
Associates (480)  and by Ralph  M. Parsons  (814).  C.F.  Braun
(294,295,296) also concluded  that  Phosam-W  was the  process  of
choice.  Cost data  from these references  follow.  The Braun cost is
pro-rated down from 7.3 MGD to 3.6 MGD using  a  0.6 exponent.

                                   W.P.A.     Parsons    Braun
   Capacity, MGD                 3.6   1.06       1.064     3.6
   Major Equipment Costs,  $MM     7.2   2.75       1.589     5.5
   Total Investment Cost,  $MM     Not Stated       5.553    24
   Royalty, $MM                  1.0
   Operating Cost, including
     amortization, $/ 1,000 gal   4.02  4.25
                              426

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      TABLE 8-51.   INVESTMENT AND UTILITY ESTIMATES FOR THE
           CHEVRON WWT PROCESS. PULLMAN KELLOGG CASE 1
Feed
  Nominal Sour Water Rate, gpm                          2,500
  NH-,  Wt %                                                 1.2
  H9S,  Wt %                                                 0.051
  C02,  Wt %                                                 1.68

Products (1)
  Acid Gas (H2S + CO?), Short Ton/Day                     260
  Ammonia, Short Ton/Day                                  180
  Water,  gpm (60° F)                                    2,lJ30

Investment (2)

  Total Installed Cost                            $12,000,000

Utilities (3)

  Steam (With Returnable Condensate)
    150 psig, Lb/Hr                                   195,000
     50 psig, Lb/Hr                                   170,000
  Electrical Power, kw                                  1,800
  Cooling Water, gpm                                    3,800
  Maintenance,  Cost/Year                             $360,000
  Operating Labor, Man/Shift                              1/2
  Onplot Area,   Sq. ft.                                14,000

Chemicals (*O

  Corrosion Inhibitor, Cost/Year                     $370,000
  Caustic (20$), Lb/Hr                                  2,500
 (1)  Product compositions and conditions are given in  TABLE 8-52
 (2)  Investment is based on current prices  for a U.S.  West Coast
     site.  Investment figure  does not  include a required feed
     tank, product handling facilities,  or  other offplot require-
     ments
 (3)  Utility consumption is based  on maximized use of air cool-
     ing.  Maintenance is based  on 3% of investment
 (M)  Caustic estimated from the  fatty acid  content of  the  feed
                                427

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TABLE 8-52.  PRODUCT COMPOSITIONS AND CONDITIONS  FOR  THE
      CHEVRON WWT  PROCESS. PULLMAN KELLOGG CASE 1
Acid Gas Product

The acid gas product (C02-H2S mixture) will consist  mainly  of carbon
dioxide and will  have a maximum ammonia content  of 250 ppm  by weight
(or 50 ppm at the expense of 70 gpm  deaerated condensate consump-
tion).  The acid  gas will be saturated with water  at 100°F and the
process pressure.  Conditions at plot limit are  a  maximum temperature
of 120°F  and a pressure ranging  from 10 psig up to  120  psig as
required.

Ammonia Product

The ammonia product  is  produced in  the anhydrous  liquid  form.  It
will have  a maximum hydrogen sulfide plus carbon dioxide content  of  5
ppm by weight and  a water content of 0.05 percent by weight. Condi-
tions at plot limit are a maximum temperature of 100°F and  a minimum
pressure of 200 psig.

Water Product

The water product is  essentially  pure water containing  traces of
phenols and salts  which entered with the feed.  The ammonia content
will be a  maximum  of 50 ppm by weight, and the free  acid gas content
will be a  maximum  of 10  ppm by weight.  Plot limit temperature is
                              428

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      TABLE 8-53.   INVESTMENT  AND  UTILITY ESTIMATES  FOR  THE
     	CHEVRON  WWT  PROCESS.  PULLMAN KELLOGG  CASE 3	
Feed
  Nominal  Sour  Water  Rate,  gpm                             750
  NHV  Wt  %                                                  2
  H2S,  Wt  %                                                  1.93
  CO  ,  Wt  %                                                  2.49

Products  (1)

  Acid  Gas (H2S +  CO,),  Short Ton/Day                     200
  Ammonia,  Short Ton/Day                                   90
  Water,  gpm  (60°  F)                                       700

Investment (2)

  Total Installed  Cost                              $6,000,000

Utilities  (3)

  Steam (With  Returnable Condensate)
   150 psig,  Lb/Hr                                   160,000
  Electrical  Power, kw                                   1,100
  Cooling  Water, gpm                                     3,500
  Maintenance,  Cost/Year                             $180,000
  Operating Labor, Man/Shift                              1/2
  Onplot  Area,  Sq. ft.                                  10,000

Chemicals  (M)

  Corrosion Inhibitor,  Cost/Year                     $140,000
  Caustic  (20$), Lb/Hr                                     740
(1)   Product compositions and conditions are given in TABLE 8-54
(2)   Investment is based on current prices for a U.S. West  Coast
     site.   Investment figure does not include a required  feed
     tank,  product handling facilities, or other offplot require-
     ments
(3)   Utility consumption is based on maximized use of  air  cool-
     ing.   Maintenance is based on 3% of investment
     Caustic estimated from the fatty acid content of the feed
                                429

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      TABLE 8-54.  PRODUCT COMPOSITIONS AND CONDITIONS FOR THE
             CHEVRON WWT PROCESS, PULLMAN KELLOGG CASE 3
Acid Gas Product

The acid gas  product (CO -H S mixture)  will have a maximum  ammonia
                       ^M  £•
content of 250 ppm  by  weight (or 50  ppm at the expense  of 60 gpm
deaerated condensate consumption) .  The acid gas will  be  saturated
with water at 100°F  and the process  pressure.  Conditions  at plot
limit are a maximum temperature of 120°F and a pressure  ranging from
10 psig up to 120 psig as required.

Ammonia Product

The ammonia product  is  produced  in the anhydrous liquid  form.  It
                                                *
will have a maximum hydrogen sulfide plus carbon  dioxide  content of 5
ppm by weight and a water content of 0.05 percent by weight. Condi-
tions at plot limit are a maximum temperature of  100°F and  a  minimum
pressure of 200 psig.

Water Product

The water product is essentially pure water containing  traces of
phenols and salts which entered with the feed.  The ammonia  content
will be a maximum of 50 ppm by weight, and the free acid  gas  content
will be a maximum of 10 ppm by weight.  Plot limit temperature is
140°F.
                               430

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These data are  not directly comparable,  since bases  are  not
clearly  understood  for the W.P.A.  costs.   Although described on
pages 319  of  Reference 480 as  "capital cost," on page 340  the
numbers  in the 3.6  MGD column are  stated as "total equipment."
W.P.A. costs  are  for 1975 (multiply by 1.12, minimum, for escala-
tion).   Parsons  costs are clearly stated as fourth quarter  1975
(multiply  by  1.04 to 1.112, where  1.04 is the Pullman Kellogg
process  plants escalation factor and 1.112  is  the EPA/SCCT muni-
cipal sewage  plant  correction).

The Braun  references (294, 295,  296)  give sour water stripping
and ammonia recovery costs for March 1, 1976 for Bi-Gas and  C02
Acceptor:

                                   Bi-Gas       C02 Acceptor
Capacity,  MGD                       7.14            0.98
Total Engineered  Equipment, $MM      8.4             2.65
Installed  Cost,  $MM                37.0            18.00

Above included  a separate stripper  plus a package cost  for
Phosam-W  ammonia recovery (which  presumably  includes paid-up
royalty).  Ammonia storage spheres  are also  included.   These
costs are  nevertheless difficult to reconcile with  the Parsons or
W.P.A.  costs  in  the previous tabulation.

Pullman  Kellogg  requested costs directly from USS  Engineers and
Consultants  for the three cases  described  in the  Chevron WWT
process  cost  analysis.  Capacity for Case 1  and Case  2 was 3.6
MGD. Capacity for Case 3 was 1.09  MGD.   Compositions  were the
same as  those sent  to Chevron.

USS Engineers and Consultants,  Inc. replied as follows:

   Our Phosam-W  process engineers have  reviewed  the  three sour

                               431

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 wastewater cases presented  in your letter  of April 21, 1978,
 and have concluded that  the Phosam-W process is applicable  to
 these feed streams.   However, to date, we have not designed  a
 Phosam-W plant which is preceded by a lime softening and
 stabilization step.   We  assume that the feed water stream  will
 be free of fouling agents  which may  cause a problem in the
 sour water stripper.

 Our specific comments and cost estimates for each of the  three
 cases presented are as follows:

 Case 1 can be handled by a  typical Phosam-W plant, which  con-
 sists of a sour water stripper followed by  absorption of am-
 monia from the stripped  vapor by an ammonium phosphate solu-
 tion.   The  phosphate solution  is then stripped to produce
 aqueous ammonia for fractionation to anhydrous ammonia product
 for sale.  The cost estimate for an installed battery-limits
 plant, without ammonia storage,  to produce 180 tons per day
 (TPD) of anhydrous ammonia  is approximately $14 million.

 Case 2 is uneconomical because of the extremely low feed  con-
 centration (530 ppm)  and the low potential production rate  (8
 TPD of ammonia).   However,  if ammonia removal is required for
 other than economic reasons (i.e., environmental standards),  a
 Phosam-W  plant could be designed for this  case.   For your
 information,  it is our understanding that other proposed  coal
 gasification  plants would use waters of this nature as cooling
 tower makeup.

 Case 3 is an  attractive  case for a Phosam-W plant.  The  cost
 estimate for  an installed battery-limits  plant, without am-
monia storage, to produce 90 TPD of anhydrous ammonia  is
 approximately  $9 million.
                            432

-------
   A nonconfidential design document can be prepared  for Case 1
   or Case  3,  which are the  most  attractive  feeds.   This work
   would  take  approximately five to eight weeks  to  complete and
   would  cost  $10,000.

Capital costs  of  Chevron WWT and Phosarn-W plants are compared on
the same  basis as quoted to Pullman Kellogg:

                              Chevron WWT          Phosam-W
   Case  1  (Lurgi, 3.6 MOD)     $12,000,000          $14,000,000
   Case  3  (SRC,  1.086 MGD)       6,000,000            9,000,000

If the  relationship

   Capital-j  (Capacity2/Capacity-j )x = Capital2

can be  assumed  to hold, on  the  basis of  two  points of informa-
tion,  it is  of  interest  to  note  that x  = 0.58  for the Chevron
plants  and  only 0.37 for  the  Phosam-W  plants.   This seems to
indicate that the Phosam-W  process is more capital-intensive  than
the Chevron  process, with the result that small  Phosam-W plants
are penalized.   As capacity  increases, however,  the difference
between  the  capital costs of the two designs decreases until, at
7.4 MGD, the capital costs  are  equal.  Above  7.4 MGD, Phosam-W
apparently has  the advantage.

Biological Oxidation with Powdered Carbon/Wet Air Oxidation—
Zimpro,  Inc. supplied us  with estimated investment and operating
costs  for  processing  four streams.

Stream  1—This  is the raw liquefaction dissolver wastewater con-
taining  high concentrations  of  phenols and other organics (BOD  =
52,700,  COD  = 88,600).  No  prior processing  was  contemplated in
order  to ascertain  whether wet  air oxidation could be
                              433

-------
substituted  for conventional processing.   Zimpro's comments for
this stream  follow.  Zimpro's estimates of  capital and  operating
costs are  shown in TABLE 8-55.

   The following costs are for a Wet  Air Oxidation  system con-
   sisting of three parallel 125  gallon per minute units designed
   to handle the wastewater described  in  your  letter. I might add.
   that this estimated  capital  cost is  for  a complete  system
   installed,  less buildings  and foundations.   The  operating
   costs and steam production (150  psig saturated) are  the total
   for the three units.

   The oxidized waste will contain  some residual  organic material
   which will likely necessitate  subsequent biological  treatment.
   However,  the residual organics contained in the oxidized  waste
   will be readily biodegradable  and  non-toxic.   From  the esti-
   mated residual BOD and COD,  the  size of  the biological  system
   for handling the residual organics  would be substantially re-
   duced since most of the organic constituents were  destroyed
   during Wet Air Oxidation.  It  is also  possible to  utilize this
   Wet Air Oxidation system for handling  the waste sludge  produc-
   tion from the biological treatment  system used for post  treat-
   ing the oxidized waste.

   Estimated BOD in the  discharge  is  7,000 mg/1 (87 percent
   reduction).  Estimated COD in  the  discharge is 9,000 mg/1 (90
   percent reduction).

   Figure 8-4? is a schematic illustration  of  the processing for
   Stream 1.

   Stream 2—This is the total of  wastewater from liquefaction
   combined with wastewater from  the process and the fuel gas
   producers.   It has been  stripped  and  the oil  has  been
                              434

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                             TABLE 8-55.  CAPITAL AND OPERATING COSTS  FOR  BIOLOGICAL OXIDATION  WITH  POWDERED
                                                  ACTIVATED CARBON AND WET AIR OXIDATION
     Stream 1:  Raw liquefaction dissolver wastewater:  Wet Air Oxidation System
     Stream 2:  Combined liquefaction feed to biological oxidation:  PACT plus Wet  Air Oxidation  of  Sludge
     Stream 3:  Combined sour water from Lurgi gasification
                                                       Stream 1
     Capacity, MOD
     Estimated Capital Investment, $MM
       0.54
  $12 to 16
                           Stream 2
      1.086
   $8 to 11
                                                                                                       Stream 3
        4.03
$8.5 to 11.5
*>.
OJ
U1
     Electric Power at $0.025/KWH
     Maintenance Labor and Materials
     Cooling Water at $0.05/1000 gals.
     Operating Labor at $80/man-shift
     Polymer at $2.50/lb
     Makeup Carbon at $0.28/lb
          Total Operating Cost
Cost per Day

      $4592
        600
        108
        720
      $6020"
Cost per Day

      $1350
        400

        480
         45
        640
Cost per Day

       $1475
         450

         480
         170
         840
     Credit for Steam at $3.00/1000 Ibs.
        Net Operating Cost

-------
              STEAM
              150 PSIG
              SATURATED
 RAW
WASTE
                               PRESSURE
                               CONTROL
                                VALVE
REACTOR
                                                        TYPICAi.  I  OF 3 UNITS
                AIR
              COMPRESSOR
              Figure  8-47.   Schematic W.A.O.  for  stream
                                   436

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  separated  as would be done for biological oxidation.  Zimpro
  proposes a biological system  employing powdered carbon with
  sludge  oxidized by wet air oxidation  for  this stream.

  For Streams 2 and 3, we are recommending a two-stage Waste-
  water Reclamation System  (WRS) .   This system includes a Wet
  Air Regeneration system for regenerating the spent  activated
  carbon  and oxidizing the  waste  biological solids associated
  with the spent carbon.

  Zimpro has done  considerable  work  on  coke oven  flushing
  liquors which are quite similar in terms  of  constituent pollu-
  tants to the waste you describe.  Based on  this  experience,  we
  are confident that the WRS will produce a high   quality efflu-
  ent. We would expect the following reductions:  COD >93 per-
  cent; BOD  >99.5 percent;  cyanides >99 percent; phenols virtu-
  ally 100 percent; thiocyanates 90 percent.

  In reviewing your  list  of components in the waste, I have
  concluded  that more ammonia and phosphorus will be  needed  to
  meet the nutrient requirements  of the waste.   I can account
  for 61.5 mg/1 of NH--N in the waste in the form  of CN, SON and
  NH  .   Generally,  the ratio  of  nutrients to BOD is  1-5-100
  phosphorus-nitrogen-BOD.  Based  on  this,  the  nitrogen
  requirement would  be 290 mg/1.   This means an  additional
  ammonia content of 228.5  mg/1 would  be  required.   Likewise,
  phosphorus in  the  amount of  58 mg/1  would  generally  be
  considered necessary.

  As you  know,  these  nutrient requirements are not unique to the
  WRS since  proper  nutrient concentrations will be required  for
  any biological  treatment  system.

Zimpro's estimates  of  capital  and operating  costs are shown in
                              437

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TABLE 8-55.

Figure 8-48  is a schematic  illustrating the system for  both
Stream 2  and  Stream 3.

Stream 3—This  is  the combined sour water from Lurgi  gasification
after oil separation, stripping, and phenol extraction;  i.e. the
stream ready  to undergo biological oxidation in the  conventional
manner.   Zimpro's  comments follow:

   The expected performance of the WRS for Stream 3  is  the same
   as for Stream 2.  Stream 3 is essentially the  same in  terms  of
   Ibs/day of  COD and  BOD as Stream  2.   Therefore, the costs
   associated with a WRS system are nearly the same  as Stream  2.
   One difference associated  with the higher flow  rate is the
   increase in  clarifier size which is the major contributor  to
   the slight increase in capital cost.

   Stream 3 seems  to have an adequate nitrogen supply, but may  be
   phosphorus deficient.  Assuming no phosphorus is present  in
   the waste, I would estimate that a phosphorus  dose rate of  17
   mg/1 would be required.

Zimpro's  estimates of capital  and operating  costs  are  shown  in
TABLE 8-55.

Streams 4 and 5—These were estimates of conventional biological
oxidation sludge for liquefaction and Lurgi gasification,  respec-
tively.   The  intent was to determine whether  wet air oxidation
would be  a viable  alternate to sending this sludge to our central
incinerator/boiler.  Zimpro's comments follow:

   Streams M  and 5 consist of waste sludge from the  Liquefaction
   and Lurgi Gasification Biox  systems.  As we  discussed,  I
                               438

-------
CO
              WASTE
                               2nd.
                             STAGE
                               1st.
                              STAGE
                                              AERATION BASINS
                                                                     POLYMER
                                                   AIR
                                           BLOWER
r©
     HP    I  CLARIFIER
                                   r
                                                                     POLYMER
                                                                THICKENER
                                 START-UP
                                 HOT OIL
                                 OR STEAM
                                                            AIR
                                                                   PUMF
                                                                 HP
                                                        COMPRESSOR
                                                                                        POLYMER
                                                                                    CLARIFIER
                                                                                                     FILTER
                                                                                                            FINAL .
                                                                                                           EFFLUENT
                     Figure  8-48.   Schematic for WRS  streams #2  &  #3

-------
 believe your estimated sludge flow rates  are a bit low,  based
 on the influent  BOD to the two Biox systems.  It is true  th'at
 long solids retention times will produce  low sludge yields due
 to the effects of endogenous respiration,  but I still  believe
 the yields will  be higher than those you  have listed.

 My estimate of  the  solids produced  in  each of  the above
 systems is as follows:

   Liquefaction  Biox System - 15,750 Ibs/day dry solids
   Lurgi Gasification Biox System - 17,100 Ibs/day dry  solids

 We would assume  the above waste solids would be thickened  to
 at least 3.5 percent solids by means of a  flotation thickener
 prior  to  feeding  the  streams  to the  thermal  sludge
 conditioning system.

 For your  reference,  we  do not  supply flotation thickening
 equipment,  but I have estimated the cost  of such for  systems
 capable of thickening the above streams from 0.94 percent  to
 3.5 percent as follows:

   Liquefaction Biox or Lurgi Gasification Biox sludge
   thickener - capital cost installed:  $180,000

As you  know,  the Process  we will propose  for this is a thermal
sludge  conditioning  unit which is a Low Pressure Oxidation
 (LPO) system.  With an LPO system,  we will do a low degree  of
oxidation  (about 5 percent in  terms  of  COD  reduction) and
raise the  temperature of the  sludge  to  about  180°C.   This
combination of oxidation  and heat  will dramatically  improve
the dewatering and thickening characteristics.

Following  the LPO system,  we would  propose a filter  press  to
                           440

-------
   allow final dewatering of the solids  to  about  a  moisture
   content of less than 60 percent.   The  resultant  filter cake
   can  be easily  disposed of on  land  with no potential public
   nuisance problems or, alternatively,  it could be mixed with
   coal  and burned in a coal fired boiler.

   The  capital  cost  and operating costs  for an LPO system  and
   filter press installed, not including buildings and
   foundations are shown in TABLE  8-56.

The schematic  for  processing of  Streams  4  and 5  is  shown  in
Figure  8-49.

Zimpro  submitted a technical  paper describing a "Wet Oxidation
Boiler  Incinerator" which could  be considered  as an  alternate  to
our central incinerator/boiler.

UNOX Biological Oxidation:  Quote  from  Union Carbide—
Through  telephone contact and correspondence an equipment cost
and design information were obtained  from Union Carbide, who  are
licensors of the UNOX process which  employs  high purity oxygen
instead of air in  biological oxidation.   The presentation  in
TABLE 8-57 was taken from their  response. Case  I refers to  waste-
water from a gasification process  typified by Lurgi (producing
p/o/t)  after phenol extraction,  stripping,  coagulation,and flo-
tation.  Case III refers to wastewater  from a liquefaction dis-
solver  similarly treated. Quotation  from  Union Carbide's  reply
follows.

   Effluent Standards—In both cases,  the wastewater  effluent  is
   required to meet the standards  shown in  TABLE 8-57.  The  stan-
   dards for TDS, COD,and phenol  are  unusually restrictive  and
   may  not be obtainable by secondary treatment.  As a compari-
   son,  the Illinois EPA has  set  a TDS level of  1,000 ppm after
                              441

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           TABLE 8-56.  CAPITAL AND OPERATING COST FOR
            LOW PRESSURE OXIDATION AND FILTRATION OF
            CONVENTIONAL BIOLOGICAL OXIDATION SLUDGES

Stream 4:  Waste sludge  from liquefaction biological oxidation
          system
Stream 5:  Waste sludge  from Lurgi gasification biological
          oxidation system
                            Stream 4              Stream 5

Capacity,  MGD                     0.053                 0.058
Estimated  Capital
  Investment, $M               $750                 $770

                            Cost per day           Cost per  day
Electric Power at
  $0.025/KWH                 $26.75                $28.75
Cooling Water at
  $0.057 1,000 gals            0.77                  0.83
Boiler Feed Water at
  $0.407 1,000 gals            7.44                  8.04
Chemicals  at
  $0.15/lb                     1.20                  1.20
Fuel at
  $0.45/gal                  114.30                 121.50
Maintenance Labor
  and Materials               45.00                 45.00
Operating Labor at
  $80/man-shift              320.00                 320.00
                            $515.46                $525.32
                                442

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                                                                                   VAPORS
OJ
                                                       PRESSURE
                                                       CONTROL
                                                        VALVE •
                                                                        DECANT TO
                                                                        AERATION BASIN
                                                                                         VAPOR ODOR
                                                                                        _CONTROL SYSTEM
                                                                                        THICKENING
                                                                                          TAN K
                                                                                          FILTER
                                                                                          PRESS
SOLIDS TO
 DISPOSAL
                            AIR
                          COMPRESSOR
                Figure 8-49.   Schematic of  LPO  &  filter  press for streams   #4 &  #5

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                             TABLE 6-57.   THE  UNION  CARBIDE  "UNOX"  SYSTEM  IN  WASTEWATER TREATMENT
  Case I:     Feed  is  wastewater  from  Lurgi  gasification  after  phenol  extraction,  stripping,  coagulation  and  flotation
  Case III:   Feed  is  wastewater  from  a  liquefaction  dissolver  after treatment  similar  to  Case  I
              (Quantities  in  mg/1  unless otherwise  stated)
                                 	Case  I   Effluents	
              Most  Stringent
              Standards  (Pullman From  UNOX  Secondary    From Multi-Media
              Kellogg  Summary)       Clarifier	      Filtration
                                                                                             Case  III   Effluents
                                                                          From UNOX First
                                                                          Stage Clarifier
                                                                           From UNOX Second
                                                                           Stage Clarifier
                                                                           From Multi-
                                                                             Media
                                                                           Filtration
Flow, MOD
PH
TDS
SS
Sulfide
Sulfate
Nitrate
Ammonia
Cyanide
Thiocyanate
COD
BOD
Phenolics
Oil and Grease
Copper
Mercury
 6 to 9
   1000
     15

    600
    2.5
    2.5
   0.02

    125
     30
  0.005
no visible
    0.1
  0.002
    4.03
       7

      30
Insig(l)

       0
    1(2)
   Insig
      78

     >30
     0.0
      25
 3.02
    7

   15
Insig

    0
 1(2)
Insig
   7§

   30
  0.1
   25
                                                                              0.515
                                                                                7.5

                                                                                 30
                                                                              Insig
                                                                              Insig
                                                                                105
                                                                                <25
0.515
    7

   30
Insig
 1(2)
Insig
   85

  >30

  <25
                                                                                                0.515
                                                                                                    7
Insig


 1(2)
Insig
   85

  <30

  <25
(l)Insig = Insignificant
(2)Ammonia added in slight excess

-------
dilution by  a receiving stream.   The  end of pipe discharge
requirement  for IDS concentrations  is allowed to rise 750 ppm
above background levels or up to 3,500  ppm if the  additional
IDS is caused by pollution  abatement  process or recycling.
Furthermore,  the effluent limitation  for phenol is 0.3 ppm.
Biological  treatment can do an excellent job  in  removing
phenolic material but present  continuous monitoring devices
cannot accurately monitor (much less detect) phenol concentra-
tions down to 5  ppb.  The COD  effluent standard of 125 ppm
requires  tertiary  treatment although an easily degradable
waste such as the Case III waste (COD/BOD = 1.65) would have
COD concentrations  in that range.   One  EPA-funded study showed
that biological  treatment reduced  the COD concentration of  a
coal conversion  waste stream (COD/BOD = 1.5) from 6,500 ppm to
300 ppm.  A  more difficult waste like Case I (COD/BOD  = 2.5)
would  have  higher  residual COD's  but the effluent levels
cannot be predicted without  further data.

Design Description—The Case I  wastewater is  treated  with  a
two-train,  four-stage rectangular UNOX System having  the
dimensions of 208 ft  by 104  ft by, 14 ft  plus 3  ft  freeboard.
Each stage contains one 75-NHp  aerator  to accomplish  oxygen
dissolution  and  solids mixing.   The design is  described  and
illustrated  on the attached "quick estimate"  documentation
sheets and layout drawings.   Comments regarding  the  process
design are listed below:

   1)  Ammonia addition of 70 ppm is required.
   2)   Nitrification will  not occur due to  short  sludge
        retention time (SRT) and elevated temperatures.
   3)  The cyanide  and sulfide concentrations  do  not  pose  a
       toxicity  problem.
   4)  The heavy metals will be adsorbed  by  the biomass  and
       wasted from  the system.

                            445

-------
   5)  Thiocyanate  will not be toxic  but  slow to degrade.
       About  60  to 80 percent will be removed.
   6)  An evaporative  cooler is included  in the system  to
       maintain a biologically  tolerable temperature  below
       104°F  by  removing 54 million Btu/hr from  the  internal
       recycle  stream.

TABLE 8-57 shows  the expected effluent quality after secondary
clarification and multi-media filtration.

In Case III,  a  two-step UNOX System is incorporated  to  treat
this high strength wastewater.  The first  step is  a two-train,
four-stage rectangular UNOX System having  dimensions of 182 ft
by 91 ft x 14 ft  plus 3 ft freeboard.  The first,  second, and
third stages  contain 40 NHp  aerators and the  fourth stages
contain a 50-NHp aerator  for oxygen dissolution  and solids
mixing.  Step 2  is a 2-MGD, one-train, two-stage  rectangular
modular UNOX  System containing a 20-NHp aerator  in each stage.
Its dimensions  are 59 ft by 29.5 ft by 10 ft  plus  4  ft  free-
board.   The  attached "quick  estimate" documentation sheets
describe both designs.  As in Case I, the  same process  design
comments apply.   An ammonia  addition of 425  ppm  is  required
and, similarly,  an evaporative cooler is included  to   maintain
biologically  tolerable temperatures in the reactor by  removing
15 million Btu/hr from the internal recycle  stream.

TABLE 8-57 shows  the expected effluent quality  coming  after
the first-step UNOX clarifiers,  the second-step  UNOX clari-
fiers and the multi-media filter.

General Comments—Further reduction in COD levels  can be ac-
complished with  ozonation.  However, more  information  regard-
ing COD characterization  is  required to determine  an  ozone
dose.
                           446

-------
   Dilution water  for  Case III was available but not used  because
   addition of that stream  would not have  simplified the UNOX
   System design nor reduced  the  amount of internal recycling  for
   cooling purposes.

   The UNOX System for Case  I has been priced  at $550,000 plus
   $400,000 for the required  evaporative  coolers.  The Case  III
   two-step UNOX System is priced at $550,000  plus $150,000  for
   the evaporative cooler.

Union Carbide explained that  prices quoted were only for the  "UCC
scope of supply" which is basically the  aerators, purge blower
and some instrumentation.  Clarifier, reactor,  pumps, etc.  are
not included.

"Quick Estimate" documentation sheets supplied by UCC are  includ-
ed as TABLES 8-58  and  8-59.   Illustrative  diagrams supplied  for
Cases I and III are presented as  Figures 8-50 and 8-51.

In order to arrive at  capital cost for the two UNOX Systems,  for
comparison with conventional  air  activated sludge, we applied  the
factor determined  in the Pullman  Kellogg  estimate (i.e. Invest-
ment = purchased equipment 4  0.112):
      Case I                  $8,500,000  (Lurgi)
      Case III                $6,250,000  (Liquefaction)

Phenosolvan Cost Information—
In response to  telephone conversations and  correspondence,
American Lurgi furnished by  telephone data  on  use of their pro-
prietary  Phenosolvan  process  for extraction  of phenols  from
wastewater using isopropyl ether  as the solvent.  Figure 8-52 is
a sketch illustrating  the system.
                              447

-------
  HEAT LOADING
  INTERNAL RECYCLE
  -7.7 MGD
NOTE:
DIMENSIONS AND
VOLUMES INCLUDE
NO ALLOWANCES FOR
"AM- THICKNESS OR
"EIRS.
                                                 INFLUENT =4.03 MGD
                                              I  RECYCLE =1.6 MGD
1 1
[PIPELINE
02=55.5 TPD
r
M * M

D
75 NHP
D
75 NHP
D
75 NHP
D
75 NHP
L,
i

D
75 NHP
a
75 NHP
a
75 NHP
a
75 NHP

CO
o
M
CM
in
fJ

,
^
                                   52'
                                                                 EFFLUENT
                                                       CLARIFICATION
                               ELEVATION VIEW
      Figure  8-50.- Typical UNOX  System  layout for Case I.
                                    448

-------
                    TABLE 8-58.   UNOX SYSTEM
                 "QUICK ESTIMATE" DOCUMENTATION


Customer:     Pullman Kellogg       Date:        April 27.  1978
Location:     Hypothetical	   Sales  Rep.  R.  W. Oeben
Consultant:   Case I	   Engineer    D.  L. Wang	
Design Basis:

  Flow, MGD                                            4.03
  Influent Wastewater Temp., °F                      130
  BOD , mg/1                                       2,000
  BOD , Ib/day                                    67,000
  COD, mg/1                                        5,300
  COD, Ib/day                                    178,000
  COD/BOD                                              2.65
  NH  , mg/1                                           30
  Phenols, mg/1                                      200
  Fatty acids, mg/1                                  560
  Suspended Solids, mg/1                              20
  PH                                                 7-9
  VSS/TSS inf.

UNOX DESIGN:
  Retention Time (on Q), hr                           13.3
  Biomass Loading, Ib BOD /lb
    MLVSS-day                                          0.8
  MLVSS Cone., mg/1                                4,500
  RSS Cone., %                                         2
  Clarifier Overflow Rate,
    gal/ft -day                                      600
  Oxygen Supply, tpd/Utilization, %              55.5/75
  Dissolution:  Power,  BHP                           562
                     ,  NHP/(Stagewise)       75/75/75/75
              :  Type
  Oxygen Generation:  Compressor Power,
                      BHP/NHP  Pipeline                99.5% 0  Purity
                                449

-------
Ul
o
                                                                             Q.Z MG.O
DV

2T)»WV
TD
1?.*?

ZOIIHP
D
	 P1PEU

CL
MIL QZ
                    Figure  8-51.   Typical UNOX System layout for Case  III.

-------
           TABLE 8-59.  "QUICK ESTIMATE" DOCUMENTATION
Customer:
Location:
Consultant:
Pullman Kellogg
Hypothetical
Case III
Date:
Sales Rep."
Engineer
April 27.  1978
R. W. Oeben
D. L. Wang	
Design Basis:

  Flow, MGD
  Influent Wastewater Temp., °
  BOD  Load, Ib/day
  BOD  Concentration, mg/1
  COD/BOD
  Suspended Solids mg/1

UNOX Design:
  Retention Time (on Q), hr
  Biomass Loading,
   Ib BOD /lb MLVSS-day
  MLVSS Cone. , mg/1
  RSS Cone. , %
  Clarifier Overflow Rate,
   gal/ft day
  Oxygen Supply,
   tpd/Utilization, %
  Dissolution: Power, BHP,
               NHP/(Stagewise)
             : Type
Oxygen Generation:
  Compressor Power, BHP/NHP
             : Size/Type

UNOX Reactor:
  Type

  Number of Trains/Stages
  Overall Dimensions

  Stage Dimensions
UNOX System Price: Oxygen Generation
                 : UNOX System
                          First Step  Second Step
                               0.515
                             130
                          39,000
                           9,100
                               1.5
                              20
                              97

                                0.6
                            4,500
                                2

                              600

                          34.9/70
                              312
                      40/40/40/50
                              UA
                    0.515
                  102
                1,954
                  455

                   30
                    3.5

                    0.4
                4,500
                    2

                  600

                1.6/75
                    38
                20/20
                               Pipeline 02
                        Rectangular

                        2/4
                        182 x 91 x 14

                        45.5 x 45.5
                          x 14
                  2 MGD Rect.
                   Modular
                  1/2
                  59 x 29.5
                    x 10
                  29.5 x 29.5
                    x 10
  TOTAL
Comments:   Require 95% BODR in 1st and 2nd steps.  Hypothet-
ical  coal conversion wastes.  Estimate & Design will be used in
EPA-funded document.  System requires evaporative cooler to
maintain biologically tolerable temperatures.
                               451

-------
K)
              CLEAN GAS
              LIQUOR
                              FILTER
               FRESH
               SOLVENT
             CONTAMINATED
             GAS LIQUOR
              EXTRACTOR
FILTER
                                           EXTRACTOR
                                                                                         DEPKEHOLIZED
                                                                                         CLEAN  	
                                                                         SOLVENT

                                                                       DISTILLATION
                                  RECOVERED-
                                  SOLVENT
                                           SOLVENT
                                           RECOVERY
                                           STRIPPER
                                                                                         GAS LIQUOR
                                                         BOTTOMS
                                                                                                  CRUDE
                                                                                                  PHENOLS
DEPHEHOLIZED
 CONTAMINATED
                                                                                             GAS LIQUOR
                           Figure  8-52.   Phenosolvan process,
                           (From Item  2 in  reference list)

-------
Flowrates and estimated compositions"of two  streams were furnish-
ed to  Lurgi.  Stream 1  was 185,000  Ibs/hr of raw liquefaction
condensate  based on H-Coal data.  Stream 2 was 1,400,000  Ibs/hr
of composition  similar to Lurgi  gasification or  other  p/o/t-
producing processes.

Total installed  costs were quoted  as  follows  for Germany.
American Lurgi  believe U. S. Gulf Coast prices could  be  30 to 40
percent higher.
   Wastewater,  M Ibs/hr
   Capital  Cost, DM
   U.  S.  Dollars,  at
     $0.48/DM

   Escalate 35%  to
     U.S. Gulf Coast
Stream 1
      185
8,000,000
Single train
Two train
  Stream .2
     1,400
22,000,000
30,000,000
3,900,000
5,265,000
              10,670,000
          to  14,540,000

              14,404,000
          to  19,630,000
It should  be  noted that  the  $12,000,000 estimated  by  Water
Purification Associates  (480) was reasonably  close,  considering
the estimate accuracies  with which we are dealing.  Lurgi stated
that the accuracy of their  budget estimates  is +. 25 percent ,
which is the general  figure used by most  contractors in quoting
quick estimates.

Utility requirements  quoted by  Lurgi were:
                               453

-------
      Per 1.000  U.  S.  gallons  of  treated  effluent
      Steam             80-270 Ibs
      Solvent Makeup     0.6-1.2 Ibs
      Cooling Water     1500 gal
      Power             4-6 KWH

Raw Water Treatment for  Removal of Inorganics —
L*A/Water Treatment Division furnished  us with equipment  costs  of
the usual  processes  involved in removing inorganics from raw
water. Basis given to them  was  the  raw  water analysis used  by
C. F.  Braun in their Lurgi process design on western  coal (294,
295, 296).   Costs  supplied are shown  in TABLE 8-60.  L*A/WTD  sup-
plied  us with an alternate set of figures,  using  the same treated
water  requirements, but  assuming  a very brackish  raw water  supply
such as might be found in New  Mexico.
   Process
Pressure filters  and
Reverse Osmosis
                           Through-put
                           _ GPM

                           8  at  350 each
                               2.016
                                               Equipment  Cost
                                               $1,354,000
Demineralizer Trains
Condensate Polisher
H.P.  BFW Deaerator
L.P.  BFW Deaerator
Total Equipment
                           2 at 1,000 each
                                730
                               5,800
                                840
                                                  404,000
                                                   85,000
                                                  170,000
                                                   35.000
                                               $2,048,000
Add-On as in TABLE 8-60
  at B5%
Total Estimated Investment
                                                1.740,800
                                               $3,788,800
In both estimates  the  demineralizer trains included cation units
and anion units in series.
                               454

-------
      TABLE 8-60.  ESTIMATED CAPITAL INVESTMENT FOR REMOVAL
                  OF INORGANICS FROM RAW WATER
                           Throughput,
	Process	             GPM                Equipment Cost

Cold Lime Softener            1,620
Gravity filters            3 at 750 each
Clearwell                     1,620                $   291,680»
Zeolite Softeners          3 at 450 each             130,270*
Demineralizer Trains       2 at  1,000 each          404,000*
Ion Exchange Condensate
  Polisher                    730                     85,000*
H.P. BFW Deaerator            5,800                   170,000
L.P. BFW Deaerator            840                     35.000
  Total Equipment                                 $1,115,950

Installation (estimated at 35%)                      390,600
Instrumentation                                     Included
Piping (estimated at 20*)                            223,000
Electrical  (estimated  at  10$)                        111,600
Other indirects  (estimated at 20$)                   223,000
  Total Estimated Investment                      $2,064,150
 *Total cost of equipment  in  the  process
                                455

-------
 The add-ons are purely  an  "educated guess"  based mostly on  the
 Bechtel reference cited earlier.  Freight is not included,  and it
 is assumed that no buildings  are necessary.   In cold or rainy
 climates the assumption of  no buildings would probably not be
 viable, but rough steel buildings or shelters  would probably be
 considered acceptable in most  cases.

 Chemicals usages were cited, and we have applied current costs as
 follows:

 Equipment           Chemical         Lbs/Day     C/Lb     $/Day

 Demineralizers      NaOH              6,132      17.5    $1,073
                    H2S04             6,132       2.5       153
 Zeolite softener    NaCl              2,734       1.5        40
 Cold lime softener   Alum,
                    Lime and
                    Polyelectrolyte               1.5

 Condensate polisher  NaOH                 36.4    17.5    $     6.37
                    H2SC>4                36.4     2.5    S     0.91

 Sludge quantities produced were stated, the  largest of which is
 25 percent of  the feed to reverse  osmosis  as reject.  In  that
 case evaporation would  probably be justified  to concentrate  the
 waste further  and conserve water.

 L*A/WTD offered some opinions  on  treatment  required  to  use
 wastewater as  a substitute for raw water as  a  boiler feed water
 and supplied information on the capability of reverse osmosis in
 removal of phenols,  boron, ammonia,  nitrates, Si, Ba.and Sr  that
was relayed from DuPont, the supplier of the membranes.

At our request, L*A/Water Treatment furnished additional  cost
                               456

-------
information  concerning  the variation with capacity of the  cost  of
cold lime clarifier,  sodium  zeolite softeners,  reverse osmosis,
and demineralizers  in the range of  the base case water quantities
and the alternates.

A curve for  budget  cost selling price of reverse osmosis units  is
shown in Figure  8-53.   The curve  flattens  at  about 1 MOD,  sug-
gesting that duplicate  units will be required for higher capaci-
ties.

Other comments  by L*A/Water Treatment were as follows:

      o  For the cold lime clarifier, cost  for capacities  above
         the 809,000  Ibs/hr  rate on which the quotation was based
         would  have to  be assumed to be directly proportional  to
         flow,  for  budget purposes, although resulting  estimated
         costs  will probably be high.

      o  For sodium zeolite  softeners, costs  for capacity  above
         the original 436,000  Ibs/hr may be estimated at $150/gpm
         for the additional  throughput.

      o  For ion exchange  units,   costs  for  capacity  above the
         original 569,000 Ib/hr would be directly proportional to
         flow.

      o  In  the absence of  tests,   it is  generally  assumed that
         reverse osmosis will  reject at  least 90 percent  of the
         TDS if a  25 percent  reject (loss)  stream  is  assumed.
         Temperature of operation  should  be restricted  to  65  to
         95° F  so  that membrane  life  may  be guaranteed and
         operation  will be  satisfactory.

      o  Recycling  Lurgi base  case  treated  water after  post-biox
                               457

-------
ib.
Ln
oo
Q

O

«/>


U
o


O.

O
          ,4
          W
          U)
2.4



2.2



2.0



1.0



1.6



1.4



1.2



1.0



0.8



O.G



...0.
                              10
                                    100

                              Capacity, GPD x 1000
                                                                     1000
                                                                                        I >
                                                                         10,000
                Figure 8-53.   Reverse osmosis:  budget prices without pretreatment
                                (add 15%  for complete  pretreatment  system.*)
                 *Communication from L*A Water Treatment

-------
        filtration and  reverse osmosis followed  by  ion  exchange
        should  be  feasible.   Tests  to  check  the  effect  on
        membrane fouling  of the  small (1 mg/1)  oil  and  grease
        residual were recommended.   It  was  stated that  a
        periodic cleaning with detergent (Biz) might  be needed.

     o  Direct ion exchange of stripped wastewater  from gasifi-
        cation processes  producing no p/o/t might  require  some
        pretreatment to reduce the estimated 52  mg/1  COD.   This
        level of  COD usually indicates  to the vendor that  a
        possible bacteria fouling problem exists.  Chlorination
        and carbon filtration or the use of ultraviolet sterili-
        zers are normally recommended if this is found  to be the
        case.   The  problem seems to  be  unlikely unless  the
        wastewater  has been exposed  to  open  air  conditions.
        Operating costs  for ion exchange  were cited  as  3
-------
produced) and  Bi-Gas  (no p/o/t produced)  were submitted  to
Envirotech  for  design and cost information.   Envirotech  obtained
the  following  information from  their  Goslin  group  which
specializes  in  evaporation.

Goslin estimates are based on a forced  circulation, six-effect
evaporator-crystallizer.  Although  steam economy could  be  im-
proved by incorporation of a feed  preheater,  no preheater was in-
cluded due  to their opinion that CaSO4 scaling would probably  be
a problem.   The  feed  compositions  for  the two cases,  which  we
believe  to  be  somewhat high,  were transmitted to  Goslin  as
follows:

                                     Case 1            Case 2
 Cooling  Tower Slowdown           69,500  Ibs/hr      74,300 Ibs/hr
 Sodium Softener Sludge          14C,,000             76,740
 Condensate Polisher Waste         4,000             10,280
 Cold Lime Clarifier Sludge       64,200             46,830
 Demineralizer Regeneration
   Waste                            -	     107.430	
                                283,700  Ibs/hr     315,580 Ibs/hr

TABLE 8-61 presents the design and cost  information.   Note  that
installed costs for Case 1 (Lurgi) are estimated at $4,000,000 and
for Case  2 (Bi-Gas) at $4,700,000 for 283,700 and 315,580 Ibs/hr,
respectively, of evaporator feed.
                             460

-------
        TABLE 8-61.  PULLMAN KELLOGG GASIFICATION STUDY:
                        EVAPORATOR COSTS
EVAPORATION                        Case 1           Case 2
Feedrate, Ibs/hr                    283,700          315,580

Steam press, psig                        25               18

Total requirement, Ibs/hr            61,000           67,800

Goslin Evaporator Size
  Vapor Heads, Dia.   ?   11-1/2 to 14-1/2'        12 to 15'
  Heating elements, ft               11,260           14,340
  Pumps, HP                             100              125
  Condenser                           Surface          Surface
  Cooling Water, GPM  (1)              2,100            2,350

Ejector - 2 stage
  Steam, Ibs/hr                         300              300
  Cooling water, GPM                     20               20

Steam economy  (overall)                    4.46              4.5

Total weight,  Ibs.                  520,000           600,000

Total cost, equipment  (2)        $2,000,000        $2,350,000

Installed factor  (3)                       2.0               2.0

Total Installed Cost             $4,000,000        $4,700,000
1.   Cooling water - assumed 90° F  temperature.
2.   Price  is FOB Birmingham,  Alabama.   Based  on  316  SS,  backward
     feed and includes  six  large diameter  vapor  pipes,  six
     recirculating pumps  and piping.
3.   Installed  cost  is  double  the  equipment  cost  and  includes
     Goslin six  effect  forced  circulation  evaporator  with
     instrumentation,  small piping,  foundation,  structure,
     insulation, wiring,  paint,  site  work  and  engineering.
                               461

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 INTEGRATED SCHEMES  FOR WASTEWATER TREATMENT

 As previously mentioned, three base cases  from  conceptual designs
 have been selected  to obtain water quantities for study  of  water
 treatment methods and sludge production and  disposal  from these.
 Figure 8-51! is a block flow diagram illustrating the  entire water
 system and treating processes employed by C. F. Braun  for  Lurgi
 (p/o/t-producing)  gasification.   Estimated  analyses of  key
 streams are tabulated in the lower portion of the figure.   The
 sour water analyses were obtained from sources  other  than the C.
 F. Braun report.  Results of treating the  sour  water  are Pullman
 Kellogg1 s best estimates and must be confirmed  by testing.  Vari-
 ous alternates to the Braun treating scheme  for "zero discharge"
 will be discussed and illustrated by sketches or tabulations.

 Figure 8-55 is a similar block flow diagram illustrating a high
 temperature entrained flow gasification process that  produces no
 p/o/t.   Quantities shown are from the conceptual  design  for
 Bi-Gas by C.  F. Braun.  The sour  water analysis was taken from
 Kopper-Totzek data, since Bi-Gas  analyses  and treating  data have
 not yet been  published.  Various  alternates  to  the Braun treating
 scheme will  be considered.  Results of treating methods  are
 Pullman Kellogg's best estimates  and must  be confirmed.

 Figure 8-56  is the water system  base case for an  integrated
 liquefaction  process.   Quantities shown are  from the  Ralph M.
 Parsons conceptual design for SRC  II, as previously mentioned.
 In Parsons1 design the stripped  sour water was returned to the
 process  gasifier,  which produces  the necessary hydrogen  for
 liquefaction,  and  all  organic materials  were assumed  to be
destroyed by  combustion at the  high temperature .of the Bi-Gas
reactor.  This may well be the preferred treatment, but  it should
be demonstrated in an integrated  pilot or  demonstration unit.  We
believe  the  organic  compounds will indeed be destroyed,  but
                              462

-------
                                                                                                            REVERSE  'REJECT TO EVAPORATOR
                                                                                                            OSMOSIS  (	"•
                                                                FROM BIOX FILTER
                                                                1,295,200
      .NON-OILY WATER RjINOFF
       INTERMITTENT *
       UNKNOWN
TO L.P. BFW t
SULFUR RECOVERY
1,053,300
                                                                                                             STEAM TO PROCESS
                                                                                                LOSS 	
                     1,217,000
ESSf
0 »
1000
M. P. BFW
DEAERATOR

955,800
DRIVERS
CONDENSATE RET

FROM DRIVERS *
                                                                                                            STEAM
                                                                                                            SYSTEM
                                                                                                                   SLOWDOWN
                                                                                                                   130,900
OJ
          NOTE: NUMBERS IN PARENTHESES ARE TOTAL FLOWS, LB/HR
               NUMBERS OUTSIDE PARENTHESES ARE WATER FLOWS ONLY,LB/HR
                                                                                TO BOILER
                                                                                ASH COOLER
                                                          EVAPORATION  __
                                                                                                                                          463,000
                                                       COOLING
                                                       TOWER
                                                                                                                                         BLOWDOHN
                                                                                                                                          69,500
                  Figure  8-54a.-  Integrated  scheme for  treatment  of  Lurgi   wastewaters.

-------
                                            FROM EVAPORATOR
                                            11,300 (12,8001
                                            11.61 SOLIDS
•BOILER ASH
•<;2,oooi loot SOLIDS
(SUPERHEATER ASH
'(15u6) 100% SOLIDS
BOILER ASM
COOLER
*
SUPERHEATER
ASH COOLER
ALTERNATE It BRAUN SCHEME BIOSLUDSt! PROM SLUDGE ACCUMULATOR ,

ALTERNATE 2i TO LANDFILL (USUAL PRACTICE!
ALTERNATE 3i TO INCINERATOR/BOILER
rnm.i.MftN KKT.i.rvin nrrnMMpMn&Ttniii
.CASIPIER ASH SLURRY
'19,380 (129,200)
85% SOLIDS

1 "*
SIEVE
BEND
—
THICKENER

H USES Hpu° MILI
TO DISPOSAL
46,620 (185,000) 74.8% SOLIDS
                                             SURGE TAN)
                                                         TO ASH SLURRY t SULFUR RECOVERY
  \COAL i ASH PILE RUMQTJ
  INTERMITTENT t UNX]
STORAGE
                                                                             COj. HjS TO SULFUR RECOVERY,_
                                                    .CAUSTIC (20%)
                                                    '(2500)
                                                  AMMONIA
                                                  RECOVERY
                                                             AMMONIA TO SALES
                                                                                    (14,100)
PROCESS QUENCH
(CONDENSATE 1 ._
'1,38»,000
TAR-OIL-HATER
SEPARATION

TAR I OIL TO


BOILER
85,500 (114,000) 751
,OILY WATER RUNOFF

'INTERMITTENT
AND UNKNOWN




PHENOL
EXTRACTION
m. '*
HATER
EHOVAL



HENOL TO SALES
SOUR HATER
STRIPPER

	 J

(3,000)


EQUIL
pH AD.


pH 9.5-11
COj OR H2S04
1
ZATIuN 1
IUSTMENT
,ALUM, POL

RH 7-8 4!
1
                                                                                                _L
                                                                                           FLOTATION
                                                                                                   1 FLOAT TO PONOS t BOILER _
                     _TO STORAGE TANK 8
        BIOSLUDCE TO  I    SLUDGE
       BOILER ASH COOLER!  ACCUMULATOR
       OR OTHER DISPOSAL"
                      CHEMICAL
                      ADDITION
                    t FILTRATION

[ER
|,


Hcprntin STAGE ^ *
BIOX
f »

1 AEROBIC **



*



SLUDGE FLOTATION ^^_

FIRST STAGE
BIOX



DIGESTION
                             I THICKENER
                                              I COAL DUST   r

                                               49,492 (51,500) 3.9% SOLIDS
Figure  8-54b.-  Integrated scheme  for  treatment of Lurgi  wastewaters.

-------
                                          Streams  in Figure 8-54


BOD
COD
TDS
TSS
Phenol
Cyanide
Thiocyanate
Ammonia
Sulf ide
Chloride
Oil
1

7,200
13,000
1,884
4,676
3100
8
260
13,600
506
266
21.000
2

6,000
10,400
1,884
468
2,500
8
260
10900
506
266
500
3
(mg/1
2,320
6,220
1,884
468
410
8
260
10,900
506
266
500
4
unless
2,070
5^220

125
410
5
260
80
10
266
500
5
otherwise
1.700
4,650

30
410
5
260
80
10
266
50
6
noted)
170
1,000

20
20
2
50
30
2
266
10
7

17
500

20
1
0.6
5
1
0.06
266
5
8

8
400

5
1
0.6
5
0.9
0.06
266
1
Water flow,
    Ib/hr
1389,000  1303,600   1,303,600  1,303,600 1247,700 1129300  1,295,200 1295200
Figure 8-54(c)
Stream compositions  for integrated scheme for treatment  of Lurgi
wastewaters  (part  3  of 3).

-------
-fi-
eri
      , NON-0 II.T HATER RUNOFF
      'INTERMITTENT
       I UNKNOWN
      .RAH WATER
                  1,078,100


               RECYCLE WATER
              iRAGE524,400
EVAPORATION
  12,700
                                                    TO PROCESS
                                                                                                        CONDENSATE   y
                                                                                                     RETURN FROM DRIVERS'
STEAM TO PROCESS
 DRIVERS
                                                                              FROM RECYCLE
                                                                              WATER STORAGE
                                                                                465,900
                      FROM MAS.TEWATER LIME CLARIFIES
            NUMBERS IN PARENTHESES ARE TOTAL FLOWS, LB/HB
            NUMBERS OUTSIDE PARENTHESES ARE WATER FLOWS ONLY, LB/HR
                                                                                                        ,300
                                                                                                                          74,300
              Figure  8-55a.-  Integrated scheme  for treatment  of wastewater  from  gasification
                                    processes  producing no  p/o/t.

-------
BOILER ASH
 2,700 (62,100) 31.6Z SOLIDS
 COAL t ASH PILE RUKOFF
 IHTERH1TTMT 4
              STORAGE
                                                    2103
                                    CO?. H?S TO SULFUR RECOVERY

fTOBSQUGCTCCIEENSATEl
2,171,200
CTD ; ppfu

LIME

i
CLARIFIES


C07,H-jS, HH^




AfVIO'UA
RECOVERY



KLUDGE TO
OILY MTEK RUNOFF
INTERrtllTEHT t UNKJlOWrf
EVAPORATOR
STORAGE









1
I'll A TO SALES ,_
(100)
LRNATE: TO CO'IBUST^

1
OS
I SULFUR RECOVERY
SOUR MtER
STRIPPER
OIL


OIL
RBnVAL
TO



f»
ADJUSTMEHT
2
2,173,200
U1C1NERATOR/EOILER ..





fO RAW HATE
STORAGE
521,100
TO COOLI.'iG
165,800
TO COAL
SLURRYK1G
l^si/juu
 Piaure 8-55(b).   Integrated scheme for treatment of
 Fxgure 8 bbID)    wast^water from gasification processes

                    producing no p/o/t  (part  2 of 3) .

 Note:   Numbers in parentheses are total  flows, ">/hr
         Numbers outside parentheses are water flows only/

         Ib/hr
                          467

-------
                     Streams in Figure 8-55
                         1            2
                     (mg/1 unless otherwise noted)
COD                        128           52
TDS                        831          475
TSS                      5.081            5
Phenol                       0.011        0.011
Cyanide                     13            6
Oil                          0            0
Ammonia                    184           20
Sulfide                      7            7
Chloride                   100          100
Hardness*                  630           80
Alkalinity*                650           10
pH                           8.5          7
Water flow, Ib/hr    2,474,200    2,473,200
*As CaCO
     Figure  8-55(c).  Integrated scheme for treatment of
                      wastewaters from gasification
                      processes  producing no p/o/t
                       (part  3  of 3).
                                458

-------
CTi
ID
LIVE STEAM TO SULFUR RECOVERY
' i
.PROCESS COMPENSATE SOUR WATER 2°' ""} AHMONI
'(SEE TOTE 2) 548,000 STRIPPER COj, llcIT ABSORB
. OILY WATER „„„„„ rnm
' 100 ACRES Po1l*'fV IAP" M*
RUNOFF FROM VARIABLE AND SEPARATOR
* PROCESS AMS'nr"JlMICT'IITTI:"'r
OIL
SLAG SETTLING BASIN OVERFLOW WATE
SANITARY SEWAGE SEWAGE DESIGN
1 25.000 "" TREATMCHT - ,„_
| SLUDGE
, DEIONIZER WASTES
'COOMN'G'TOWER BLOWDOKN ._ ^To^'clL?11
1 1.437,500 * ' x • , 5' 1
, BOILER SLOWDOWN
1 75,000\
RUNOFF FROM CLEAN AREAS 1 500 ACRES, VARIABLE AND IN
2S, COj, HOT
I AMMONIA


TER OILY WATER WATER
' " >'UNU 11 ACHEI n6/260
loiL


ANHYDROUS
AMMONIA
WATER
62,994
HATER TO SLAG QUENCH

SECONDARY OIL TO FRACTIONATION
SEPARATOR 20 GPM
R FIREWATER 0
FLOW BIOPOND
oo 	 "" u ACBE)


CPU NORMAL
WATER
60,000

299,254



SCREJ
SEDIMEN
16' X 64

t SLUDGE
TO DISPOSAL^
60,000
SETTLER
,550,000 (400,000 GAL)



SLUDGE
TO DISPOSAL
TERHITTENT




POND 1
(8 ACRES )j—

TO

SLOWDOWN _ STEAM AND POWER
75.000
BFW
1,455,000
«IOHJIE» "ASTES „

BACKWASH P,LTER

fALU«
N AND SETTLER " 	 ~J
T.,"AS'.''., °''J"'US"' - CLAR^i"S 7,257,500 COOLINO
8 X 16' _^ 200 0 	 m~ TOWEF
SLUDCE 4lo7 	
30,500 DOWN

FILTER I
"LT?S 1 DISPOSAL
' NOTES !
1. NUMBERS ARE FROM R.M. PARSONS SRC-II FLOW SHEET AND ARE LBS/HR OF
WATER ONLY UNLESS OTHERWISE NOTED.
FROM
PROCESS GASIFir.R 112,000
FUEL GAS GASIFIER 67,000
DISSOLVER 169,000
TOTAL 348,tloO
                                                                                            J. COAL SIZING AND CLEANING HATER IS FROM A CAPTIVE SYSTEM FED FROM A
                                                                                              MINEBASED POND.

                                                                                            4. PORTABLE WATER SUPPLY PROM WELLS AT 75 GPM. CHLORINATION AND 20,000
                                                                                              GALS STORAGE PROVIDED.
                                 Figure 8.-5S.-  Liquefaction base  case water balance,

-------
the fate of the inorganic  compounds must be traced  to confirm
that they  do  not cause operational problems such as  buildup,
scaling, downstream catalyst fouling, etc.

In the  alternate  to the liquefaction base case flowsheet Pullman
                           —/
Kellogg shows  a more conventional treatment for  comparison with
that used by Parsons.  Sour water analyses  and some  of the  treat-
ing results are from H-Coal bench  scale data and  from  treating
experiments by AWARE, Inc.  These references  were  mentioned
earlier in  this report.

As described in the foregoing  sections on costs  of  treatment,
Pullman  Kellogg  has  attempted  to  get up-to-date  budget cost
figures and treating efficiency advice or statements from various
vendors and licensors  of the treating modules  shown  on the flow-
sheets, and information on alternate methods which  could be used
instead of  those  shown.

Lurgi Gasification Flowsheet, Figure 8-5M

This process  produces tars, oils, and phenols and  all  water
issuing from the  gasifiers must be treated.   It  thus  represents
the most extensive and expensive water treatment  of  all  the gasi-
fication processes.  Treatment .modules shown are:

     o   Oil Separation
     o   Phenol  Extraction
     o   Stripping of C02, H2S,and NH
     o   Ammonia Recovery
     o   Dissolved Air  Flotation
     o   Equalization and pH Adjustment
     o   Biological Oxidation, including Sludge Handling
     o   Filtration of  Biological Oxidation  Effluent
     o   Evaporation of Inorganic Sludges
                              470

-------
The thickened,  stabilized sludge  from  biological oxidation  was
used for ash cooling in the Braun  conceptual design and  passed
out with the collected ash and  inorganic  solids  from the ovapora-
tor. Pullman Kellogg  suggests that this  organic  material  be
burned in a central incinerator boiler with the tars  and  crude
phenols which may not be sold  (see Section  9,  Control of  Gaseous
Emissions).  A common method  of disposal  is in a sanitary  land-
fill and this alternate is also indicated on  the  flowsheet.  Pro-
blems associated with the sanitary landfill disposal method  are
discussed in Section 10.  Using the costs discussed  in  the  fore-
going section,  our  best estimate  of the capital costs  for  the
wastewater treating scheme shown on the flowsheet are  presented
in TABLE 8-62.

Lurgi Gasification - Alternate  Treating Schemes

One fairly simple alternate to  the Braun  treating scheme would be
to reduce the quantity of the  sludges to  be fed  to the  four-stage
evaporator by employing reverse osmosis,  demineralization, and a
small evaporator on the reject  stream from  reverse osmosis.  This
is illustrated in Figure 8-57.

Capital cost of the alternate  case is estimated  as follows:
  Reverse Osmosis with Pre-filter        $ 632,000  (1)
  Demineralizer Train                       224,000  (1)
   Total Equipment (except evaporator)    $ 856,000
  Installation Cost (0.8 x equipment)        684,000  (2)
   Total Installed Cost                  $1,540,000
  Evaporator Installed Cost                1,890.000
   Capital Cost                          $3,430,000

(1) Equipment cost furnished by L»A Water Treatment
(2) Factor from Bechtel paper "WateReuse  -  1975."
                               471

-------
          TABLE 8-62.  ESTIMATED CAPITAL COSTS FOR
                     WASTEWATER TREATING

Item
API Separator

Phenol Extraction

Stripping and
Ammonia Recovery
Capacity,
MGD
3.8

3.7


3.6
Capital,
$MM
0.55

14.40»

12.0

Source/
Reference
SRI Re-
port (804)
American
Lurgi
Chevron
Research
Dissolved Air
  Flotation

Equalization Basin

Pumping Station
                Included in
  3.6           biological
                oxidation
(24 hr. hold time)
  3.6                0.15
                     0.39
Biological Oxidation"  3.6

Sludge Belt Press
Evaporator              0.816

  Total Capital Cost
                    10.00

                     0.47
                     4.0

                    41.96
Envirotech/
Kellogg

Pullman
Kellogg
Pullman
Kellogg
Envirotech/
Kellogg
H.O. Schultz
Goslin/
Envirotech
* Single-train plant,  quoted at $10,670,000 in Germany, esca-
  lated by 35 percent  for U.S.  Gulf Coast.  Two-train plant
  quoted at $14,540,000 in Germany, escalates to $19.6 million
  for U.S.  Gulf Cost.
••Includes effluent filters, sludge thickener, and aerobic
  sludge digestion.
                            472

-------
                                                       BABE CASE
                                               (QUANTITIES IN POUNDS PER HOUR)
U)
CONDENSATE POLISHER __
COLD LIME CLARIFIER
	 »
SODIUM SOFTENER
COOLING TOWER BLOWDOWN

SLUDGES ^ PRE- RF
WATER 283,000 FILTER OS
SOLIDS 1500
1
i
CAKE TO 1
EVAPORATOR
OR PUG MILL 1
68,100

SLUDGES m EVAPORATOR
_ WATER 283,000
SOLIDS 1500

SOLIDS CONCENTRATE
TO PUG MILL
WATER 11,300 r
SOLIDS 1500
ALTERNATE CASE
(QUANTITIES IN POUNDS PER HOUR)
DILUTE CAUSTIC
DILUTE ACID
1 ••
212,775
VERSE WATER 212.775 ^, DEMTNERAr.T2FB
MOSIS SOLIDS <500 PPM 22,5

JP.TPrT REGENERATION WASTE
VATER 70,925 WATER -v-10,000
SOLIDS 1500- SOLIDS 520
STEAM
19,4251
235,300 HIGH PRESSURE
*" BFW DEAERATOR

37,100 MED. PRESSURE
BFW DEAERATOR


HIGH PRESSURE
25
"" BFW DEAERATOR

Y EVAPORATOR 59,625 (MIN) 37,100 MED. PRESSURE

SOLIDS CONCENTRATE
TO PUG MILL
WATER 21,300 (MAX) 1
SOLIDS 2020 1 L

BFW DEAERATOR
EXCESS TO RAW
WATER STORAGE
                Figure 8-57.  Lurgi gasification.   Base  case  and alternate disposal
                              and water recovery.

-------
The capital  cost  for the same equipment,  prorated  from  the
Bechtel paper,  is $3,990,000, providing  a reasonably good  check
on the capital  cost development calculation.

The capital  cost of the base case  evaporator  was  given previously
as $4,000,000,  thus the capital cost advantage of  the  alternate
case is rather  small.  It should be noted that  the  Goslin evapo-
rator capital costs are less than  those  indicated in  the  Bechtel
paper  (see  "Costs  of Water Treatment"  section).   Use  of this
reference would indicate a  cost  of $6,500,000.   The  operating
cost of  the  alternate case, however,  should be  significantly
lower,  since  the savings in  low pressure steam  usage  is 48,675
Ib/hr  and credit  for the steam  saving  should  be only  partly
offset by the cost of the acid and caustic required to regenerate
the demineralizer train.

Demonstration  of  the operability of reverse osmosis  on waste
sludges would be required, since the reject stream  cannot contain
precipitated  solids that could clog the  membranes.

Several alternates were considered because of  concern  about the
possibility  of  high chlorides  in  the wastewater.   The  analyses
employed in  development of  the Lurgi flowsheet of  Figure 8-54
were from a  different coal than that used by  C. F.  Braun  in their
designs on "western coal."  Further, western  coals  are  generally
lower in chloride than eastern coals, particularly  those  from the
Illinois basin.  With Illinois coals the  chloride content of the
effluent water  would probably be considerably higher  than the 266
mg/1 shown in the Lurgi flowsheet.  The  most stringent  effluent
standards, discussed earlier in the report,  state  that  chloride
shall not exceed 250 mg/1.  Therefore, the 266  mg/1 shown on the
flowsheet would not meet this effluent discharge  specification  of
250 mg/1.  Reverse  osmosis is estimated to  remove 90/f"of the
chlorides and ion exchange could probably remove  virtually  all  of
                              474

-------
it.  Reverse osmosis would  also lower  the  TDS level below the
1,000 mg/1 effluent    discharge specification and perhaps
substantially reduce residual  phenol.

More pertinent than  effluent discharge specifications, since no
discharge is contemplated,  are the chloride,  cyanide, phenol,
sulfide,and TDS levels  that must apply to reuse as cooling water
makeup or makeup to  high, medium or low  pressure steam systems.
These specifications were quoted earlier  in  this report and are
repeated here in TABLE  8-63.   It can be  seen that the specifica-
tions are difficult  to  relate  to specific compounds  and  do not
easily lend themselves  to illustration by tabulation.  Such  items
as the Langelier and Ryznar indices relating to scaling have  been
omitted.

According to Betz Co. and others,  the compounds shown in TABLE
8-6M cause difficulties in the  cooling water system.

Foaming, usually caused by organic compounds in the water,  can be
troublesome in cooling  tower operation,  but can be controlled by
use of anti-foaming  agents.  Several compounds, of which soda ash
is an example, have  been blamed for delignification of cooling
tower wood.  Cyanides are objectionable  because of their highly
toxic nature and should be removed or at least converted to  less-
toxic cyanates.

Many of the effects  cited above can be reduced or eliminated by
controlling pH and by the use  of various  additives.   Many arti-
cles have been published on control of corrosion, scaling, foam-
ing and fouling.  Additives used in the  past  are being replaced
or their use is being  re-examined so that  the rigid discharge
controls  for wastewater that have been introduced  in  recent
years, or that are scheduled to be implemented, can be met.
                               475

-------
        TABLE 8-63.   SPECIFICATIONS FOR MAKEUP WATER (1)
Contaminant
                   Cooling
                   Tower
                   Makeup
                                     Boiler Feed Water
                                  150 psig600 psig1,450  psiq
                       (Parts per million,
                  100-3,000 (2)    No spec.
                                           unless specified)
                                            but undesirable
                    200-400 (3)
Chlorides
Total Dissolved
  Solids (IDS)   2,500-3,000 (3)   60 ppb (3)    60 ppb
Suspended Solids
Phenols
Ammonia
Oils
Sulfide
  (as ILS)
Iron
Copper
Silica
Total Hardness
  (as CaCCx )
Sodium (5)
 Total Alkalinity
  (as
                                                          60 ppb
                     1-2
                     0.5
                     0.08
                    <150
                   Related to
                     Indices
                                   0
                                   0,
                                 150
10
05
                                   0.3
                                  20  ppb
 0.025
 0.02
30,

 0.2
20 ppb
 0,
 0
< 2
01
01
                      0.0
                     20 ppb
                   Carbonate <5
                   Bicarbonate
                     50-150
                                 700
         400
(1) The cooling tower makeup specifications are unofficial
    recommendations from the paper "Reuse of Wastewater Effluent
    as Cooling Tower Make-up," Marvin Fleischman, U.  of
    Louisville,  WateReuse - 1975 (AIChE)
(2) Circulating water specification.  Wide limits have been
    reported.   3fOOO applies to stainless steel
    Circulating water specification
    < 20 ppb in saturated steam
(5) Specification in saturated steam, parts per billion
(3)
                              476

-------
     TABLE 8-64.   PROBLEM COMPOUNDS IN COOLING WATER SYSTEMS
Compound
            Scale
Corrosion   Fouling
Biological
Fouling
Reacts with
  Cooling
   Tower
 Chemicals
Ammonia
Oil
Organics
Phenols
Suspended
  Solids
Oxygen,
  CO
Total
  Dissolved
  Solids
Phosphorus
Silica
Sulfate
Chlorides
Free
  Mineral
  Acid
Nitrate
Sulfur
  Compounds
HCN
                         X
                         X
                         X
                         X
X
X
X
X

X

X
     X
     X
                                477

-------
The foregoing statements  are paraphrases  of information  in the
"Betz Handbook of Industrial Water  conditioning",  7th  Edition,
1976.

If reverse osmosis must be  used  to  remove  chlorides, the flows in
the Lurgi flowsheet would change as shown  in TABLE 8-65.

Cooling tower blowdown would be  sent to the  evaporator, as in the
base case, together with  the reverse osmosis reject.

The base case capital cost  would be increased by  the installation
cost of reverse osmosis plus the incremental cost of the increas-
ed evaporator capacity or,  as described earlier in the  alternate
to the Lurgi gasification base case, reverse osmosis plus deminer-
alizer  plus a small evaporator.  The  additional  capital required
for these two installations is roughly:

     Reverse Osmosis               $1,258,000
     Incremental Evaporator        1,093»000
         Total                     $2,351,000

     Reverse Osmosis               $1,258,000
     Reverse Osmosis +
       Demin. + Small Evaporator      640,000
                                   $1,898,000
The effects of chlorides  and other corrosive materials in the
cooling water system  may be  avoided  through use of corrosion re-
sistant materials  in  the cooling  water system, including  the heat
exchangers using cooling water.  Some conceptual designs (692)
employ more than one  cooling tower and cooling water  system and
confine wastewater makeup  to the  cooling  tower that serves stain-
less steel exchangers.  Such  a solution for the corrosion  problems
is practical since  many  of the exchangers in gasification

                              478

-------
  TABLE 8-65.   EFFECT OF REVERSE  OSMOSIS  IN  THE LURGI FLOWSHEET
Stream
  Water Flows Only.  Lbs/Hr
                With Reverse
Base Case          Osmosis
Leaving Biox Filter
  To Cooling Tower
  To Raw Water Storage
  To Reverse Osmosis
From Reverse Osmosis
  Clean Water to Cooling Tower
  Reject to Evaporator
Cooling Tower Flows
  Makeup from Reverse Osmosis
  Makeup from Boiler Slowdown
  Makeup from Biox
  Evaporation and Drift
  Slowdown (to Evaporator)

Total Evaporator Feed
1,295,200
  251,600
1,043,600
        0
  280,900
  251,600
  463,000
   69,500

  283,700
1,295,200
        0
  959,733
  335,467

  251,600
   83,867

 <251,600*
  280,900
        0
  463,000
  <69,500*

 <367,567
*The higher purity  of the makeup would  undoubtedly reduce  the
cooling tower blowdown requirement and  thus  reduce the makeup
requirement, but actual reduction would have to be determined by
operation or experimentation.
                                 479

-------
plants must be made of stainless  steel or other  corrosion re-
sistant materials  because of the corrosive nature of the streams
on the process side  of the exchangers.

Another approach might be stage-wise water condensation, as ex-
emplified by the Braun HyGas design.   The liquid  condensing at
the higher temperature would probably contain most of the inor-
ganic materials, and this quantity of water could  be treated at
lower cost.  It is our understanding that this approach is being
investigated in the  IGT HyGas pilot plant operation.

Other possible approaches include side-stream treatments on the
cooling tower blowdown instead of on the makeup.   These would be
evaporation,  reverse osmosis, demineralization,  or combinations
of the three as described for makeup treatment.   Obviously, these
would reduce makeup, and thus usage of the wastewater,  by a maxi-
mum of 69,500 Ibs/hr  (zero blowdown).   In order to  prevent
buildup of chlorides in the total water system,  it  will be neces-
sary to remove at least as much as is introduced with the coal.
Some Illinois basin coals contain as much as  0.5 percent by
weight of chlorine.  This represents 6,316 Ibs/hr on the flow-
sheet basis which converts to 5,036 mg/1 chloride  in wastewater
as a top maximum figure.

Another point worthy of mention in connection with  high chlorides
is that ammonia fixation (as NH4C1) would definitely occur and
two-stage stripping with lime treatment between  stages (see fol-
lowing section on gasification without p/o/t  production)  would be
necessary.

Other inorganic compounds that may be found in coal gasification
wastewater  and that are not removed by lime precipitation, coagu-
lation or flotation, are mainly boron compounds,  sulfates, sili-
cates, phosphates, and nitrates.   Remarks  and methods cited

                               480

-------
for chlorides  would also apply to  these  compounds.  Most are
considered highly  soluble but innocuous  in a recycling water
system unless they contribute to scaling or biological fouling.
Should the water  be discharged it  must be treated by reverse
osmosis and/or  demineralization or  evaporation  to meet standards
quoted earlier  in the report.

Alternate methods for removal of organic compounds are numerous:

  o  There are  many  variations in biological treatment processes,
     such as  trickling filters, rotating biological disc contac-
     tors, fluidized sand beds, use of high purity oxygen acti-
     vated sludge,and  others.  It  should  be  noted  that  Water
     Purification  Associates  (M80)  evaluated four  variations:
     conventional, high purity oxygen activated sludge (HPOAS) ,
     trickling  filter plus HPOAS and conventional plus nitrifi-
     cation and denitrification,  and found the combination  of
     trickling  filter plus HPOAS to be the  most cost  effective.

  o  Anaerobic  digestion in a first stage may be followed  by  one
     of the activated aerobic sludge processes.  Phenol extrac-
     tion by the Phenosolvan process could  be  eliminated  with a
     capital cost  saving of about $12 million.

     Envirotech has estimated that  they  could evaluate this
     option for $10,000 to $15,000 in existing equipment at their
     Salt Lake  City  laboratory.

  o  Use of powdered activated  carbon in the biological oxidation
     system with wet oxidation  regeneration (Zimpro-Dupont)  was
     reported  in  a  previous  section  to cost $8.5 to $11.5
     million.  This  could  be more  than the $10 million  estimated
                                  ,/ "^
     by  Envirotech/Kellogg  for the conventional air  activated
     sludge  system;  however,  it  would  undoubtedly be more
                              481

-------
efficient in removal  of  COD, BOD, cyanides,and thiocyanates
than would the conventional system.  The question is whether
the cooling tower  system could tolerate the greater amounts
of these components present in the Envirotech conventional
activated sludge effluent.  There are a few precedents  cited
which indicate that the  cooling tower  is  a good biological
contactor itself  and  that the algae  produced can be con-
trolled.  Some conceptual designs,  e.g.  El Paso, Burnham,
are counting on this method of operation.

Wet  air oxidation may  be considered as  a substitute  for
first stage biological oxidation.  Zimpro submitted an  esti-
mate of $12 to $16 million  for this.  Phenol extraction at  a
capital cost of about $12 million  could  be eliminated to
offset this cost.

The stream that is normally sent to biological oxidation  may
be sent instead to the central incinerator/boiler for  the
plant complex.  This alternate appears to  be viable techni-
cally, would save  considerable investment (about $15 mil-
lion, less incremental costs on the incinerator boiler)  and
would  provide fuel  to  reduce coal consumption.   Pullman
Kellogg favors this option, but recommends testing, preceded
by design estimates to check economic feasibility.

Should the previous alternate prove to be too great  a  di-
luent for the incinerator/boiler feed,  a separate catalytic
oxidation of wastewater  should be investigated.

The academic case  of treating for discharge, instead of  re-
use,  would require addition  of granular  activated carbon
treatment plus possibly  ozone treatment to meet the very  low
organic effluent standards.  In addition,  the inorganic  re-
moval steps described earlier would  be  required (reverse
osmosis and/or demineralization and/or evaporation).
                         482

-------
Evaporation for Treatment  of  Condensates from P/0/T-Producing
Gasification—
Vendors of evaporator equipment  state  that evaporation of waste-
waters  from gasification processes  that  produce p/o/t, after
phenol extraction,  stripping  and  flotation, appears to be feasi-
ble from an operational standpoint.  Future  development of con-
trol technology should include  evaluation of evaporation of  water
containing organic  compounds.

There are problems  associated with  this method of disposal:

  o  The quantity of organics in the evaporator discharge stream
     is  estimated  at  about  1,000  Ibs/hr  in  contrast to about
     110,000 to 120,000 Ibs/hr of  total  inorganic solid wastes
     that are normally discharged  from  the gasification plants
     for disposal,  including  ash/slag.

  o  Disposal of wastes containing  organic  compounds  could  cause
     problems in obtaining operating  permits.

  o  Demonstration of  disposal  techniques for the organic-con-
     taining waste  would probably be required  on a long term
     basis  on a demonstration plant scale.

 Economics  have been  developed for the  treatment  scheme  shown in
 Figure  8-54,  the base  case flowsheet   for gasification  processes
 producing  p/o/t.   The base case  includes phenol  extraction,
 stripping,and  flotation followed by 2-stage biological  oxidation
 and  filtration of  the  clarified water for reuse  as process  water
 and  cooling tower  makeup.  An evaporator,  cold lime clarifier, and
 sodium  softener  are  part  of  the overall water treatment scheme.
 Capital costs include  $10 million  for the biological  oxidation
                               483

-------
system and  $4 to 7 million for an evaporator  processing  0.82. MOD
of wastewater (Goslin estimated $4 to 4.4 million, while Bechtel
indicated that the cost might be $6.5 to 7 million).

For the evaporator alternate case, the biological oxidation sec-
tion is eliminated, the evaporator capacity is  increased to 3-62
MGD and both the cold lime softener and the sodium  softener are
reduced.  The evaporator capital cost, estimated by  applying the
0.6 exponent to  the  ratio of  capacities,  becomes  $9.7 to 10.7
million (averaging,  say, $.10.2  million)  if Goslin figures are
used,  and $15.8 to 17.1 million if Bechtel  figures are used.  The
question of multiple units versus  single units has  not been
answered satisfactorily and  requires further study:   Bechtel
describes the use of 3 evaporators for a total capacity of 2.33
MGD, while  Goslin states that a single unit is  feasible.

For the base case, the total capital for biological  oxidation and
the small  evaporator ranges  from $14 to  17 million.   For the
alternate case the  capital  cost of the evaporator ranges from
$10.2 to 17.1 million.  If Goslin is right, there is  a  possible
capital cost saving with the alternate case of  $3.8  million.

An additional capital cost saving in the alternate case may be
realized, due to the reduction in cold lime softening  and sodium
softening requirements, of on the order of $650,000 for a total
incremental cost advantage for the alternate  case of $4,450,000.

Operating costs  for the alternate case are probably higher than
for the base case:
                              484

-------
                                 Base Case       Alternate
 Operating Costs without
   capital charges               $  708,000       $1,456,000
 Incremental  capital at
    15 %/yr                        667.500       	-
                                $1,375,000       $1,456,000
Since none of the treatment alternatives have been demonstrated
adequately, this evaporation alternate should be explored  fur-
ther.   Evaporation equipment  vendors ,  such as  Goslin  and
Struthers  Wells, have examined the specifications for  the  evapo-
rator feed as supplied by Pullman  Kellogg for the  evaporator
alternate  case.  The tentative conclusions are that  evaporators
can be made to function in this  application without  excessive
foaming or corrosion but that  testing should be carried  out on
actual samples.

There is some indication from unofficial telephone contacts  that
ElPaso Natural Gas has had some  testing  done.  Most of  the
foaming appears to be  confined  to one of the six effects.
Apparently some provision for scrubbing of carry-over  organics is
contemplated.

Bi-Gas/Koppers-Totzek Gasification Flowsheet, Figure 8-55

These processes produce no organic pollutants and a slag  residue
that is more  leach-resistant  than the ash residue  produced by
Lurgi gasification.  Wastewater treating problems are thus  much
simplified.   Modules shown by Braun on their flowsheet are:

  o  Sour  water stripping to remove C02» H2S,and  ammonia

  o  Ammonia  recovery (or removal) by Phosam-W

  o  Evaporation of inorganic sludges
                               485

-------
Using the costing bases  previously discussed, the cost  for  a
Chevron WWT system processing  7.13 MGD is estimated as  $18.1
million.  This includes  ammonia recovery, although  the much
smaller  ammonia quantity,  compared to Lurgi gasification,  may
justify  only removal  and  not  recovery for sale.  Since  ammonia
interferes with the operation of the Glaus process for sulfur
recovery, it would have  to  be  incinerated if it were  not  re-
covered.  The decision for or  against recovery  would be specific
for specific operating cases.

The evaporator cost (by Goslin)  is estimated at  $4.7 million.

Alternates/Critique of Base Case Gasification Producing No P/O/T

Ammonia  removal is much more  critical with gasification processes
producing no p/o/t because biological oxidation is not included
to utilize the residual ammonia.  In the earlier discussion of
stripping and ammonia  recovery in the "Commercial Water Treating
Methods" section the  point was made  that there  is a good possi-
bility that ammonia fixation  will occur to prevent stripping to
20 to 50 mg/1 residual ammonia unless pH is adjusted to 9.5 to 11
with lime or caustic.   Therefore, Pullman Kellogg recommends a
procedure published by Bethlehem Steel Corp.  and used in their
coke oven plants.  Reference is "An Improved Process  for  the
Removal  of Ammonia from Coke  Plant Weak Ammonia Liquor," E.   M.
Rudski,  K. R. Burcaw and  R. J. Horst, Iron  and Steel  Magazine,
June, 1977.  This reference reports  excellent ammonia removal in
a single steam stripper  if  this  stripper is preceded by a
clarifier/thickener  fed  from a pre-liming vessel  where weak
ammonia liquor is well  mixed with sufficient 10 percent lime
slurry  to  raise the pH  to  11.   Suspended  solids  from  the
clarifier/thickener were  less than 50 mg/1  while the  underflow
contained approximately  30  percent  suspended solids.   The
                             486

-------
underflow effectively removed tar or entrained  coke.  (The Bi-Gas
process will  probably entrain some char into  the  effluent water.)
Subsequent stripping was free  of deposits formerly  encoantered
and less than 50 mg/1 of residual ammonia was achieved with steam
consumption of 0.13 kg/1 WAL in  contrast to the 0.30  kg/1 WAL in
the conventional  stripping  with lime addition  to  a "lime leg"
communicating with the  stripper.  Pullman Kellogg  believes that
lime addition in this manner would also precipitate virtually all
trace metals as well as other  inorganic compounds  which could
contribute to problems  in  subsequent water reuse.   Compositions
of streams 2 and 3 on the  bottom of the flowsheet reflect use of
the above technique.

It would be necessary to adjust  the pH of the stripped water  to  7
to 8, and this could be done either with C02produced in  the gasi-
fication plant or  with  sulfuric  acid.

Added  cost of the clarifier/thickener may  be offset by the
smaller size of the  stripper system in  this alternate.  We esti-
mate  the maximum added capital cost  as  $850,000 by adjusting
similar costs furnished by Envirotech  for  clarifiers.

In order  to use the  water  as cooling  tower makeup or boiler  feed
water,  combinations  of  reverse  osmosis and/or demineralization
and evaporation,  as  described  for  the  Lurgi  flowsheet, may or may
not  be necessary depending on the  actual  coal used and  the
concentrations of chlorine,  boron,  etc.   that are  present.
Experimentation is necessary  to  establish  whether  ammonia,
cyanides,and  sulfides remaining might  have to  be further  reduced
by such methods as pzonation and/or activated  carbon or  alkaline
chlorine  treatment.
                               487

-------
Liquefaction Prototype Flowsheet, Figure 8-56

As previously described, Figure 8-56 illustrates the method pre-
sented in the Parsons conceptual design of  recycling stripped,
combined wastewaters from the liquefaction reaction and the  two
high temperature gasifiers back to a waste  heat  boiler system
feeding the  process gasifier.  Also as previously stated, we  be-
lieve this should  be tried on a demonstration plant to determine
the fate of  the  inorganic compounds and whether their presence
would lead to unacceptable scaling, clogging, or catalyst poison-
ing.  It should  be noted that this system contemplates a consid-
erable  discharge  of wastewater to the river.

As an alternate  to Figure 8-56, Pullman Kellogg presents a system
more similar to  the Braun gasification schemes;  i.e., zero dis-
charge.  Figure  8-58 is an illustration of  the Pullman Kellogg
alternate.   This scheme contains the following features:

  o  Separate, two-stage stripping of gasifier condensate with
     lime addition between stages to remove C02, H2S, and ammonia
     to low  levels.   Stripped  water is used for  cooling  tower
     makeup
  o  Oil separation on the liquefaction wastewater
  o  Phenol  extraction of "oil-free" liquefaction wastewater
  o  Single  stage  stripping and ammonia recovery of extracted
     water using  either  Phosam-W  or  Chevron  WWT proprietary
     processes.  Although adjustment of pH may not be necessary
     prior to stripping, caustic addition is  provided
  o  Equalization  and pH adjustment to 7 to 8
  o  Flocculation
  o  Flotation
  o  Two-stage biological oxidation with powdered carbon addition
                              488

-------
                                    LIME (1301
                                    '(901 CAoT
00
            GASIFICATION 179,000
              CONDENSATES
                                                     ALTERNATE TO COMBUSTION
                                                     | AND SULFUR RECOVERY
NOTE:  NUMBERS IN PARENTHESES ARE TOTAL FLOWS/LB/HR
     NUMBERS OUTSIDE PARENTHESES ARE WATER FLOWS ONLY, LB/HR
                                                                                   163,000
            Figure  8-58a.-  Integrated scheme  for  treatment  of  liquefaction wastewaters.

-------
UD
O
1
, _ SIEVE _ THTt-vrnrn M, VACUUM "**
1 it.ua.aoo> BEMD ""S"
lit SOLIDS ~~"
,-.rn BACKWASH^ EURCZ HATER
BAND FILTER TANK

COAL AND SLAG PILE RUNOFF ~~" ~~~~
INTERMITTENT ( UNKNOWN

, OILY HATER RUNOFF OIL INTERMITTENT
1 "" "O"*™ *" REMOVAL
TAR AND OIL TO BOILER
(260) 75% WATER
LIQUEFACTION CONDENSATE 1 TAH . 0,L . WATER J PHENOL 3 S
1 *" SEPARATION *" EXTRACTION •"
PHENOL TO SALES
(87J)
>
I
(

TO DISPOSAL
m Mio ,,_ 	 ...^ uryff, fillip,
MILL (514,600) NUMBE
TO SLAG QUENCH WATFR TO SLAO QUENCH



3UR WATER 1 1 EOUALI2ATIOM t * _ FLOCCULAT
,'IHlH>Ea | '^J PH ADJUSTMENT


IHMOH,A AMMONIA TO SALES
tECOVERY ,1,00)
COj, HjS TO SULFUR RECOVERY
FACT WITH. WET AIR OXIDATION I ZIMPRO "WRS" PROCESS
PAC MMEUP
3000
TO STORAGE TANK B 7
1(3,000

|
SECOND STAGE f riABIFtER I FIR
BIOX j B
REGENERATED CARBON f | _J

IIMPRO "I"
BEACTOR ^ 1 "
AIRJ (ASH i CARBON
J
"HEAT SLUDGE
ECOVERY ^ THICKENER
BLOWDOWN TO DISPOSAL
' 130 TO 170

|
IS IN PARENTHESES ARE TOTAt, FLOWS, LB/HR
RS OUTSIDE PARENTHESES ARE HATER FLOWS ONLY,
FLOAT TO BOILER
99» WATER
OR 	 ^ fI,"TBTTnM *| f



*~ 1
ST STAGE
iox ^ 	 ' "



          Figure  8-58b.-  Integrated scheme for treatment of liquefaction wastewaters,

-------
                                   Streams in Figure 8-58


DOD
COD
TDS
TSS
Phenol
Cyanide
Thiocyanate
Ammonia
Sulfide
Chloride
Oil
Hardness*
Alkalinity*
PH
Water flow, Ib/hr
1

52700
88600
5300
2
6800
10
350
14400
29300
100
608
<80
80000
9.5
166700
2

52700
88600
5300
2
6800
10
350
14400
29300
100
220
<80
80000
9.5
166400
3
(mg/1
42700
73400
5300
2
410
10
350
14400
29300
100
50
<80
80000
9.5
4
unless
9100
14200

2
410
7
350
45
10
100
50
<80
700
7.5
166400 166400
5
6
7
8
9
10
otherwise noted)
9100
14100

2
410
5
350
45
10
100
25
<80
700
7.5
1C6000
455
3700

20
20
0.5 <
100
25
2
100
10
<80
700
7.5
45
1000

20
< 1
0.05
35
1
0.06
100
5
<80
700
7.5
76300 163000
40
950

5
< 1
< 0.05
35
1
0.06
100
1
<80
700
7.5
1C3000
-0
128

5031
0.011
13

184
7
100
- 0
630
650
8.5
179000
- 0
52

5
0.011
6

20
7
100
- 0
80
10
7.0
178000
*As CaCO.
Figure 8-58(b).   Stream compositions for integrated scheme for treatment
                  of  liquefaction wastewaters  (Part 3 of 3).

-------
     and regeneration  of  circulating stream by wet oxidation
     (Zimpro  and DuPont PACT).  Sludge handling  as indicated with
     concentrated sludge to the central incinerator/boiler
  o  Multi-media filtration of biological oxidation  effluent
     prior  to use as cooling tower makeup
  o  Installation of reverse osmosis plus evaporation  of its re-
     ject and the inorganic sludges from  the cold lime clarifier
     and demineralize.  Boiler blowdown is used  as cooling tower
     makeup to reduce fresh water usage

"Zero Discharge"  is thus achieved except  for  the  combined wet
(ca. 25 percent  water) slag-and-inorganic  residue  stream and
cooling tower evaporation and drift.

Using the costs in  the sections on "Costs of Water Treatment" and
"Budget Cost  Estimates Received From Licensors and Vendors," our
best estimate of the capital cost of the system shown in Figure
8-58 is developed in TABLE 8-66.

Parsons (80U)  indicated the following costs in their report:

   Raw Water  Treating                      $15.48 MM
   Sour Water Treating                       5.53
   Effluent Water Treating                   5.21
      Total Water Treating                 $26.22 MM

Only the last two items, total $10.74, might be compared with the
$33.506 for our treating system;  however,  we eliminate most  of
the Parsons  demineralizer with  evaporation.   A  more direct
approach is to evaluate those items eliminated  from the Parsons
scheme by Pullman Kellogg:
                              492

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    TABLE 8-66.   CAPITAL  COST  OF  ZERO  DISCHARGE  SYSTEM  FOR
               LIQUEFACTION  WASTEWATER TREATMENT
Capacity,
Item MGD
Gasifier Condensate
Stripping/NH recovery
Lime claririer
Liquefaction Condensate
API Separator
Phenol Extraction
Stripping/NH recovery
Equalization, pumping
station
Flocculation, Flotation
Two-Stage Biological
Oxidation with PACT
(Filter Included)
Reverse Osmosis
(Including pre-filter)
Evaporator
0.49
0.49
0.49
0.49
0.49
0.49
0.49
0.49
4.59
4.146
Capital-
$MM
3.73
0.34
0.16
5.07
3.73
0.16
0.436
9.00*
5.035
5.915
Source/ Reference
Chevron Research
Kellogg/Envirotech
SRI (804)
American Lurgi
Chevron Reserach
Pullman Kellogg
Kellogg/Envirotech

L*A Water
Goslin/Envirotech
   Total Capital Cost
33.506
•Zimpro says lower hydraulic flow with the same BOD load has very
 little effect on cost.
                                493

-------
   Reduction in Demineralizer              $1.47 MM
   Eliminate 4.34  MOD  clarifier             0.69
   Eliminate sludge  filter  (0.44 MGD)       0.11
   Reduce size of  raw  water treating
     ca. 20%                               2.66
      Total savings                        $4.93 MM

Adding the pluses  and  minuses:

   Total Parsons Treating Cost             $26.22 MM
   Units eliminated                        - 4.93
                                          $21.29 MM
   Deduct Parsons' sour water stripping    - 5.53
      Parsons system remaining             $15.76 MM
   Add Pullman Kellogg system               33.51
      Total treating system                $49.27 MM
      Total Parsons  system                  26.22
   Net added by Pullman Kellogg            $23.05 MM

Some additional cost may be eliminated from the Parsons system by
reducing the waste heat boiler injection system costs, but  this
cost cannot be estimated without much more detail than is  avail-
able at  this time.    Consequently, what has  been presented  in
effect is the maximum (Pullman  Kellogg) and  minimum (Parsons)
capital costs in handling liquid effluents from a coal liquefac-
tion plant:   $49.27 MM vs. $26.22 MM.

It is our  recommendation  that  any demonstration plant built
should be the conservative Pullman Kellogg  system,  but  should
include design features to permit testing of the simpler Parsons
system of injecting stripped combined wastewater into the  waste
heat boiler system that feeds the process gasifier.
                              494

-------
The same alternate treating  systems for inorganic  and  -organic
matter enumerated  for  the Lurgi  system would apply  also to the
liquefaction wastewater, so these will not be reiterated  in this
segment of the  report.

Operating Costs of Integrated Systems
Partial operating  costs  for the integrated systems  can be devel-
oped   by use of the  information tabulated  in  the segment on
operating costs for the  separate  treatment methods.   These oper-
 ating costs are shown in TABLE 8-67 for the recommended  systems
for p/o/t gasification,  gasification with no p/o/t, and liquefac-
tion.

The  treatment units  enumerated in TABLE 8-67 are  the major
systems  contributing to operating costs.   Processes such as API
separators, pH adjustment,  flocculation  and  flotation would add
relatively minor operating  costs  to  those shown.  Such operating
costs as are included  in  these operations  would  probably be
mainly  chemical costs rather  than utility or amortization  costs.
Amortization costs  for these operations  can be computed  at 15
percent of capital  per year,  to develop  the added costs as
 follows:

   Gasification with p/o/t                 $827/day
   Gasification with no p/o/t               None
   Liquefaction                           $311/day

 Inclusion  of chemical quantities for  pH adjustment,  lime, alum,
 and  polyelectrolyte.would be speculative without experimentation,
 since the  process  requirements are  not well  enough  known.
                               495

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       TABLE 8-67.   OPERATING COSTS OF INTEGRATED SYSTEMS
                  Operating Costs in $/day (1)
                 Gasification   Gasification
Treatment Unit    with p/o/t      no p/o/t
             Liquefaction
Phenol
  Extraction         $ 7,690
  (using avg.  values)
Chevron Stripping &
  Ammonia Recovery    13,982

PACT Biological
  Oxidation            6,605
  (Zimpro-DuPont)
Reverse Osmosis (Dow)
Evaporation (Goslin)   2.525
   Partial Total     $30,802
None
$25,334
None
  2,913
$28,247
$ 2,318
  3,253 (2)
  3,253 (2)

  2,276

  2,071
  3.669
$16,840
(1) Includes capital-related items at 15 percent  of  capital  per
    year
(2) Caustic or lime costs not included
                                496

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Raw water treating systems,  such- as lime softening,  zeolite
softening,and  demineralization, are not included  in  this  analy-
sis,  although  they  were included on the flow sheets for illustra-
tive  purposes  and to  show quantities, because  of the  extremely
great variation  in  raw water  analyses encountered in  the areas
that  are favorable  for location of conversion plants.
                               497

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EFFICIENCY OF WASTEWATER TREATMENT SCHEMES

The water  treating schemes outlined  in the preceding  section
assume "zero  discharge" to receiving  waters.  A discussion of
whether or not effluent waters can meet the  most stringent of the
standards for  discharge  to receiving waters is  therefore
academic.   The criteria for zero discharge are:

     o  Wet sludges and ash must be properly impounded  so  there
        will  be  no leaching into receiving waters via  rainfall.

     o  Available water treating methods must be efficient enough
        to permit recycle  of  wastewater for  cooling tower or
        boiler feedwater use without creating unacceptable corro-
        sion,  foaming, algae  formation, heat exchange  surface
        fouling, or adverse  reactions  with cooling tower or
        boiler feedwater chemicals.

Based on available  data on the  compositions and quantities of
conversion process  effluents  and  on data and information con-
cerning water treatment technology, we  believe  that both  criteria
can be met.   However,  proof that the criteria can be met  requires
demonstration by applying the techniques suggested and evaluating
the results over an extended period of  time.

Lurgi plants  in  the U.S. are planned by Wesco, El Paso,  ANG, and
others, and it is assumed that final designs for such  plants  will
include pollution control technology based  on best engineering
judgement   of the data available at the time of design. Operation
of the plants will prove or refute the  design judgements.  One or
more of these projects  appear  to offer  the best  near-term
opportunity for  the study of water reuse technology; however, DOE
demonstration plants may precede the commercial Lurgi  plants  into
operation.  In any case, intensive study of  minimum treatment of
                              498

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water necessary to permit  recycle to cooling  tower or boiler
systems  without  unacceptable corrosion,  foaming,  algae accumu-
lation and fouling,  scale  accumulation and  fouling, etc. should
be carried out  on  the  first  plants  large  enough  for the results
to be meaningful.

Once the large  plants  are  in operation, water treating licensors
and equipment vendors  should be  issued samples or granted access
to the cooling  tower and boiler  systems to study the requirements
for both total  recycle and  further treatment  to meet effluent
quality standards.

Developing Technology

A number of newer  water  treating processes have been disclosed in
the  open  literature  or are being touted  in advertisements by
licensors and  vendors.  Testing  and evaluation would be necessary
to determine  if any  of these offer any real  advantages  over
existing technology in  coal conversion  processes.   Aspects of
this newer technology  could  be:

     o  Energy  savings

     o  Reduction  in capital and operating  costs

     o  Additives  to prevent fouling,  scaling, foaming, etc.

     o  More efficient removal of contaminants

     o  Removal of any special contaminants  introduced by a  par-
        ticular coal,  a particular raw water or  a  prior treating
        process

     o  Elimination of operating problems
                                499

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     o  Reduction of disposal costs

Promising developing technology in water treating  which  we  have
noted, and the source of the information, includes  the following:

     o  Application of fluidized-bed technology  to  biological
       oxidation.
       We found references to this  technique  of extending
       surface for biological activity.  Brochures and  a letter
       from Ecolotrol, Inc.  claims a developed system  with far
       less space requirement  than  conventional biological
       oxidation.  The brochure  states  that  pilot plant rental
       units are available.  A technical paper describing a unit
       in operation in Nassau County, N.Y. appeared  in  the May
       1977 issue of the  Journal  of  Water  Pollution  Control
       Federation.  Oak Ridge  National  Laboratory published
       results of testing  ("Biodegradation of Phenolic Waste
       Liquors  in Stirred  Tank, Columnar,  and Fluidized-Bed
       Bio-Reactors" CONF-761109-4,  Holladay,  et al.,AIChE
       meeting, Chicago,  Nov.28 -  Dec.   2,  1976.   Kellogg
       reference 610).  The  fluidized bed  exhibited  highest
       degradation rate and phenol effluent of 0.5-1.0 mg/1, but
       retention time was not high enough  for good thiocyanate
       conversion.

    o  Oil fluidized evaporation.
       This  is  a  technique for removing  water from waste
       streams,  leaving the solids behind suspended in oil.  The
       oil is separated from the  solids in a centrifuge  and
       reused.  The  solids are encapsulated,  incinerated,  or
       otherwise prepared for ultimate  disposal.   This  techni-
       que,  called  the Carver-Greenfield process,  claims the
       advantages of eliminating  fouling of evaporator  heat
                             500

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exchangers  and  of  production .of dry solids.   The process
is marketed by  Dehydro-Tech Corp., East  Hanover,  N.J.,
from whom  brochures and correspondence have  been  re-
ceived.   Both mobile  and stationary pilot facilities are
available.

The Sulfex  process for  removing heavy  metals from waste
streams.
Developed by the Permutit Company, Paramus,  N.J. (Chemi-
cal Engineering, May  9,  1977), the process is claimed to
out-perform conventional hydroxide precipitation while
avoiding H  S evolution.  A  prototype was to  begin opera-
          <£
tion by end 1977.   It should be  mentioned  that several
vendors we  talked  to  mentioned use of sodium sulfide  as  a
scavenger  in water treating systems  as a  conventional
technique.  Most  inorganic sulfides  apparently can be
precipitated from  aqueous solutions.

Ultraviolet irradiation.
Several references, among these  Chemical Engineering of
Aug. 1,  1977,  have  been noted  regarding  ultraviolet
irradiation.   Irradiation  of ozone-enriched  secondary
treatment wastewater converted  all  organics to CC^ and
H 0, heavy metals  precipitated as either oxides or metals
and PCB's and viruses were  destroyed.

Sludge volume reduction.
A number of vendors offer  lime  sludge recovery systems,
e.g., Dorr-Oliver's Fluo-Solids lime sludge  recovery,
which could be of  interest  to  determine the  cost  effec-
tiveness of the process.  Other  techniques  for reducing
sludge volume include Permutit's "Spiractor," which works
by  "catalytic precipitation" and produces hard  pellets  of
sludges.
                        501

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o  Freezing.
   Freezing has been mentioned as a promising technique, but
   few data are available.   Fluor (PB-273 318/6WP "Compara-
   tive Economics of Freezing Process  as  Brine Concentra-
   tors" Shroeder, et al.,June 1977) prepared cost  estimates
   to  compare with vertical  tube vapor compression evapora-
   tors using CaSO  seeding  to prevent scale formation.  The
   method appears feasible  but requires development.

o  Treatment of purge streams that are toxic to bacteria.
   Reagents  purged from sulfur removal systems have been
   reported to kill  the working  bacteria in  biological
   systems (SRC, personal communication,and monthly report
   from Ft.  Lewis, Wash,  pilot plant) and therefore should
   not be allowed to reach  biological oxidation  feeds.  NCE
   (Nittetu Chemical Engineering,  Ltd.)  sells a thermal
   incinerator for  these  reagents which operates in  a
   reducing atmosphere. Purge liquors  from redox systems,
   such as  Takahax  and Stretford,  can be  treated and
   recycled back to the process.

o  Catalytic oxidation.
   Catalytic oxidation of organic-laden  wastewater may prove
   to  be viable and should  be investigated  further.  A good
   reference  is a paper from the  Proceedings  of the 29th
   Industrial Wastewater Conference  at Purdue  University,
   May 7-9, 1974:  "Aqueous Phase  Catalytic Oxidation as  a
   Wastewater Treatment Technique,"  Kotzer, et  al.  Copper
   oxide catalyst was employed at  oxygen partial pressure  of
   6.8 atmospheres  at  100  to 300° C,  using  air with  10
   percent excess oxygen.  Reported results of  treatment  of
   coke plant wastes containing 4000 mg/1 organics showed
   that 99 percent or more of the  organics were destroyed.
   The cost  was estimated  at 75
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   gal/day plant.   An  expander was employed  on  the exit
   gases  to run  the  air compressor.

o  Removal of  oil  from emulsified mixtures.
   From  the  same  conference  as the item above,  an
   interesting  paper  on  removal of  oil from emulsified
   mixtures was  presented.  This  could be important  in
   liquefaction  and  gasification processes producing  p/o/t.
   Reference  was  entitled  "Removal  of Oil  from Dilute
   Aqueous Emulsions by Auto-Coacervation and Coalescence in
   Carbon-Metal  Granular Beds," by Brown (Nalco)  and  Ghosh
   (U.   of Maine). The technique was said to be especially
   suitable  for  removing "oil haze."

   We are concerned  that the API separator shown on the pro-
   totype flowsheets is not sufficiently sealed to  prevent
   air leakage in  or noxious gases out.   A closed  coalescer
   bed such  as described  above might prove  to be the best
   solution  to this  concern.   It should be  mentioned that
   American  Lurgi  has  a  solid bed guard chamber  to  reduce
   oil entry  to Phenosolvan and Chevron WWT  says  any air
   contact would likely .interfere with stripping,  especially
   of sulfides.

o  Removal  of  chlorine.
   Chlorine  is expected to be  a problem with eastern coals.
   No data  are available on the composition  of  the chlorine-
   bearing materials.  Should  the chlorine  combine with
   organics,  an article of interest is  "Choosing  a Process
   for Chloride Removal"  by M.F. Nathan (Crawford  and
   Russell)  (Chemical  Engineering, Jan. 30,  1978).   Light
   organic  chlorides can  be  removed by stripping.   Aromatic
   chlorides are best  removed  by  carbon adsorption or poly-
   meric adsorption.  Other  methods discussed are  biological
                           503

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   oxidation and extraction.  Data are  presented.

o  The Lindman  precipitator.
   Precipitator,  Inc., Santa Fe  Springs,  Col.  makes
   interesting  claims for the Lindman precipitator  (Chemical
   Engineering, Jan.   2,  1978).  This  is  a  physical  and
   chemical  wastewater treatment that uses  sulfur  dioxide,
   iron and  lime in a continuous flow process.  On  a diluted
   primary  digester  sludge  reductions were:  TDS, 80.8
   percent,  SS, 99.4 percent, BOD,  73.9  percent and oil  and
   grease, 93.1 percent.  Capital equipment  cost  is  about
   $l/gal/day for units  larger than 250,000 gal/day.
   Operating cost is 20
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o  Liquid  membranes.
   An example of a  process  under development  and  only
   announced  in technical literature  is  "Wastewater Treat-
   ment  by Liquid Membrane Process," Kitigawa and Nishikawa
   (Takuma Co., Osaka, Japan)  and  Frankenfeld and Lia (Exxon
   Research and Engineering),  Environmental Science and
   Technology, June 1977.  Lab and pilot plant studies show
   liquid  membranes "capable  of  reducing levels of NH^  ,
   hexavalent chromium,  copper,  mercury, and cadmium from
   several hundred ppm to less than 1 ppm."

o  Mercury removal.
   Another reference describing Japanese know-how is "Mer-
   cury  Clean-up Routes-II," by Nicholas lammartino (Chemi-
   cal Engineering, Feb.  3>  1975).   The Japanese process
   referred to in the article is termed  "re-elixirization"
   and involves mixing wastewater with  a divalent ferrous
   salt, neutralizing with  alkali, and  oxidizing with air.
   Magnetic separation then removes insoluble ferromagnetic
   ferrite for disposal or special uses.  In  two  units
   mercury was reduced from 6.0 and  7.5 mg/1 to 0.005 and
   0.001 mg/1.  Arsenic, chromium,  lead,  cadmium,  zinc,
   copper, and magnesium were also reduced to low residual
   values.  Some coals  contain mercury  and gasification
   process data have  shown mercury  to volatilize and
   condense into the product  water.   The re-elixirization
   process, or the other two processes mentioned in this
   article (FMC and Georgia-Pacific)  could  conceivably  be
   required should mercury  prove to be a problem in the more
   conventional processes being proposed.

o  New bacteria strains.
   "Super  Bacteria" bred  by Polybac Corp.   of New York, N.Y.
   are offered commercially.  They appear  to be  especially
                         505

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        good for reducing  ammonia,  cyanides,  oil,  phenols,
        detergents and toxic organics  to  levels much lower than
        conventional bacteria.   Reference is "Plant Engineering,"
        June 23, 1977.  Costs  are  said to be 1.5 cents/1,000
        gallons.  Application as a "clean-up" biological stage  or
        for startup, high-load periods,  or  to aid  in  shock
        recovery, should be  investigated.

Water recovery in reverse osmosis systems  may  be enhanced by  a
method that is  described  in "Significantly  Increased  Water
Recovery From Cooling Tower  Slowdown Using Reverse Osmosis"  by  L.
J. Kosarek  (El Paso Environmental Systems, Inc.) (884).  The  paper
was presented at the Atlanta AIChE meeting Feb.  26-March 1,  1978.
Experimentation  is recommended  by DOE on  pilot plant or demon-
stration plant cooling towers.   Briefly,  cooling tower blowdown
and plant  effluent  are combined in  a  holding pond.   Water  is
pumped from the  pond to a blend  tank  where  temperature, pH and
"anti-sealant levels"  are  controlled.   One such antiscalant
mentioned is a polyphosphate.   Blend  tank  effluent is filtered
and sent to reverse  osmosis.  A spiral  wound reverse osmosis
membrane is recommended.   This procedure  is  said to increase
water  recovery over more  conventional  methods of reverse
osmosis.

Even further recovery is said to be  obtained if "a chemical  feed"
which inhibits and counteracts the anti-sealant in the brine  is
added.   A clarifier is necessary to  remove calcium sulfate  preci-
pitate and  supernatant is returned to  the blend tank.  The  preci-
pitate is also said to remove dissolved  silica and magnesium sul-
fate by coprecipitation or  adsorption on  calcium sulfate  crys-
tals.   A "small  bleed stream* purge is  necessary, which can  be
sent to a solar pond or evaporator.  Examples are cited where the
described system improved reverse osmosis  recovery from a  usual
75 percent  to 90 percent, from a usual 34  percent to 85 percent

                               506

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and even from a usual  10 percent to 90 percent on a utility plant
effluent and blowdown.  The  paper  confirms our  previous state-
ments  that  reverse  osmosis  is  considerably cheaper than
evaporation:
Capacity,  gpd
Investment
Operation  (labor,  chemicals,
  maintenance,  overhead)
Depreciation &  Taxes  (11/O
Electricity (2
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 NEED FOR LABORATORY DATA  ON  AVAILABLE SCHEMES

 Although Pullman Kellogg  has presented  estimates based  on best
 engineering judgement on  the efficiency  of various water treating
 methods, it is obvious that  virtually all of the schemes present-
 ed must be verified.   Actual coal  conversion process wastewaters
 should be supplied to licensors  and vendors for testing  in  their
 own laboratories or  rental  treating equipment supplied  by the
 vendors should be operated directly in the pilot plants.

 Potential problems that should be  resolved are outlined by treat-
 ment method category  in the  following discussion.

 Oil Separation

 Laboratory investigations are needed to more  clearly  determine
 whether there  are emulsion problems and,  if  problems  are  appar-
 ent,  the best means  to break the  emulsions.   Equipment  vendors
 could be of great help in this respect.

 Reports of pilot plant operations have  not  included in  clearly
 usable form the concentrations of  fly ash, char, unconverted coal
 fines,or other insoluble  solids  that may be  present in  the sour
 water.   Information and .data are needed  from which any effects of
 the solids  on oil separation  may be ascertained and  the best
means to deal  with  the solids may  be determined.

Oil separation means  other than  API separators ahead of  the
stripping operation would have to  be enclosed to prevent  H2S and
ammonia evolution.  We believe it  is desirable  to strip  as soon
as possible  unless  enclosed  processes such as  phenol extraction
are employed.
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Stripping

Analyses both before and  after  stripping have not been located  so
far.  The Carnegie  Mellon/AGA project should  publish some anal-
yses soon.   We believe single  stage stripping with steam will
drive CO2  and H2 S to low  levels (5 to 10 ppm)  and ammonia  at
least to the level  that is  required  for biological oxidation  (100
to 300 ppm).  This  statement requires the confirmation of labora-
tory work on actual waters.  In addition, the amount of ammonia
actually required  for biological  oxidation must be established
for use  as  a guide  for the  stripping investigations.   Our  theory
is that  the biological pond need  have no more ammonia than  can  be
stoichiometrically  used by  phenols and other  easily biodegradable
compounds in the  first stage.   Cyanates apparently  do not begin
to degrade  until  these compounds  are gone and when cyanates de-
grade they  produce  ammonia.  Residual ammonia from the final  bio-
logical  stage will  be hard  to control unless  long sludge  age  is
used, probably with powdered carbon.

The problem of obtaining  low  ammonia residuals when biological
oxidation is not  used can  be  solved, we believe, by two-stage
stripping with lime clarification between the stages.  Lime addi-
tion to  pH  9.5 to  11  will be beneficial in many ways: it precipi-
tates tars, suspended solids and  trace metals as well as freeing
"fixed"  ammonia from ammonium  salts of acids,  such as  ammonium
chloride. Early simulation  of this method on  process condensate
derived  from coal  conversion processes operating at high tempera-
ture and containing no p/o/t is recommended.

Flotation

Following  second-stage  stripping, recarbonation  with carbon
dioxide  and addition of sulfuric  acid  should be  compared  to
determine the best  method of  pH adjustment  before  flotation  and
                               509

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biological oxidation.   Flotation and  biological oxidation may
each require a different pH:  flotation  is  said to be  favored by
somewhat acid pH.   The  proper additives  to obtain best  oil re-
moval should be established  by  laboratory  test with vendor parti-
cipation.

Biological Oxidation

This process definitely requires  piloting  to  determine the actual
residuals of ammonia, cyanide,  thiocyanate,and other  compounds.
High surface area  powdered activated  carbon should be  evaluated
to establish the improvement  in the  lowering of residuals at
different levels of sludge age  and  carbon  content  of sludge.

Activated Carbon

Granular carbon beds following biological effluent  filtration
should be piloted  or tested  in  the laboratory to clearly estab-
lish  the residuals of  contaminants that  may be reached  by this
method in comparison to the  use of  powdered activated  carbon.

Regeneration of powdered activated  carbon  in  biological sludge by
wet oxidation is another variation  which merits investigation.

Reverse Osmosis

Inorganic and organic removal is  possible  by  reverse osmosis. Re-
moval of organic residuals such as  soluble oil, phenols,  cyanides
and cyanates should be  investigated as  well as removal  of inor-
ganics such as chlorides, boron,  ammonia, and  others.

Liquefaction Wastewater Disposal

Both Parsons and COGAS  Development  Co.  (see U.S. patent 3,966,633)

                               510

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have published  design conceptions  in  which stripped wastewater
from liquefaction is injected into a high  temperature gasifier,
which produces  slag and not phenolics,  in order to destroy the
phenolic and  other  organic impurities.   This appears to be an
excellent means  of disposal of  the  wastewater and  therefore
provisions should  be made to test  the  scheme on an integrated
liquefaction  pilot  plant or demonstration  plant.

It would be interesting to determine  the  fate of the inorganic
components of the wastewater.  Do they build up and cause  trouble
with catalyst plugging or poisoning?  Do they  they cause scaling
or plugging  of exchangers or pipes?   Do they eventually work
themselves out in  the slag without  causing  any of these pro-
blems?

It would also be interesting to have the  real  cost breakdown of
the very large  waste heat boiler system  that Parsons employs to
vaporize the  wastewater into the gasifier.

Cooling Tower Operation

We have  consulted  various cooling tower experts  in  order to
determine the effects on tower operation of residual amounts of
ammonia, cyanides,  cyanates, sulfides,and various  inorganic or
organic compounds  that may not  be  removed from the wastewater
that is used  for tower makeup.   No  really satisfactory answers
can be obtained without fairly  long-term experimentation, pro-
bably  on the demonstration plant  scale.  However,  supplying
cooling tower vendors and specialists with actual  samples from
pilot plant operation would  be  helpful  to them.  Certain tests
could  be made  in  their laboratories and certain  parts of the
problem are amenable to calculation such that  recommendations on
programs for  prevention of corrosion and scaling could be made
for the demonstration plant.
                              511

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Betz Company personnel stated that they  would prefer to be called
in during  the  design phase of the  cooling  system.   Certain
techniques  in exchanger design avoid  later operational troubles.
For example,  valve installations to permit flow reversal and "air
bumping", both  without taking the  exchanger off the line,  have
been found  to  be  practical in dislodging  scale accumulations
before the  scale severely interferes  with heat transfer.

If foaming  appears  to be  a problem,  its  severity  could  be
determined  in small-scale apparatus and  antifoam agents  could  be
evaluated.   Similarly, prediction of  biological (algae)  fouling
could be facilitated and additives recommended.  Several  firms
offer consulting  and design services for  nominal  fees and
arrangements  for DOE funds and for samples or plant access should
be made.

Most of the  same  firms also have  boiler  feedwater preparation
know-how.   However, these methods are generally better known (ion
exchange, reverse osmosis, evaporation,  etc.) and they  are  known
to remove practically all contaminants to  tolerable  levels  if
properly applied and, where necessary,  preceded by appropriate
pretreatment.  The  large bady of knowledge from .power  plant
practice is  applicable to boiler  feedwater  preparation  in coal
conversion  plants.

DOE Treating  Programs

A number of  instances have been cited previously of DOE coal con-
version  pilot plant water treating facilities or testing  done  or
in progress  by DOE  contractors  or  subcontractors.  These are
summarized  in the following discussion.

Solvent  Refined Coal—
The 50  TPD pilot plant at Fort Lewis, Washington has the  follow-
                              512

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 ing train of equipment: surge reser.voir, clarifier,  dissolved  air
 flotation, biological oxidation, sand filter, and charcoal  filter.
 Unfortunately, this unit has been  operated with  large dilution
 streams,  principally 216,000  gpd  of belt cooling water which
 could be recycled back to process with minimum treatment and kept
 out of the treating train.  It  would be most  interesting, once
 dilution has been reduced, to sample each step  of the treatment
 scheme for influent and effluent analysis and  analysis of  sludges
 produced.  To our knowledge this has not been  done, or at least
 no reports have been published.   One monthly report  revealed that
 purge from the Stretford unit poisoned the bacteria in the bio-
 logical oxidation  unit and this purge is now  sent to separate
 disposal.  Other inorganic sludges  are likewise sent to separate
 disposal:
     o  Thurston County Land Fill gets off-specification coal  and
        SRC,  waste sand from filters, waste  charcoal, and  asphalt
        coated rocks.
     o  Land Farm (Ft. Lewis)  receives alum  sludge,  clarifier,  and
        DAF skimmings, and excess biological oxidation sludge.
     o  Western Processing,  Kent,  Wash., a hazardous waste dis-
        posal  site,  receives ash,  Stretford  purge and  "tank
        bottoms."

 Sanitary waste and refuse are handled by the Fort  Lewis municipal
 systems.

 We feel that  a good opportunity  may exist here for study  of ways
 of consolidating these wastes and determination of the best solid
 waste management system to isolate  the solid residues from  ground
water.  Various solid  stabilization systems,  such  as Chem-Fix,  IU
 Conversion and the like,  could  be evaluated as  well as evapora-
 tion,  filtration and reverse osmosis to concentrate  the solids.

High Btu Gasification—
DOE sponsors,  and partially funds with AGA,  the Carnegie-Mellon
                              513

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University project  that monitors the HyGas, Bi-Gas, CC>2 Acceptor,
Synthane and Grand  Forks slagging gasifier  pilot plants.   This
team has conducted  some treating experiments but reports have not
been published  to date.  No  doubt, this  knowledgeable group can
solve in  the laboratory some  of the problems that  have  been
cited.   Pullman Kellogg submitted  several ideas to the  Carnegie-
Mellon  team, have met with them, talked by  telephone  and  corre-
sponded  with them to discuss possible laboratory investigations
and problems in water treating.

The 600  TPD H-Coal  pilot plant at  Cattlettsburg, Ky. will  have a
water treating  system consisting of 2-stage stripping, API separ-
ation,  emulsion holding, chrome reduction, induced air flotation,
biological oxidation, clarification and biological sludge  handl-
ing.  No reuse  of treated wastewater is contemplated,  but  a  good
opportunity to  pilot reuse schemes certainly exists here.  Plant
completion is anticipated about the end of 1978.

The Pittsburgh  Energy Research Center (PERC) has done  small scale
treating experiments at Bruceton,  Pa., and presumably  these  will
continue.   Cooperation with vendors could  prove very  helpful at
that location, where both  Synthane and  Synthoil pilot  plants
exist side by side.

Low Btu  Gasification—
Athough to  our knowledge no water treating  papers  have  been
published, it has been disclosed that Combustion Engineering has
started  up a 120 TPD high temperature entrained flow pilot plant
in Windsor,  Conn.   State officials are said to  be making tests on
emissions  and effluents.  This would appear  to offer  a good op-
portunity  to confirm treating methods used and  treating  results,
and to  obtain samples.  DOE  is funding  two-thirds and  C-E and
EPRI one-third.
                              514

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Liquefaction—
DOE has rebuilt the Conoco  plant at Cresap,  W.Va.  Monthly  re-
ports indicate that at least  sour water  strippers are supplied.
Other treating has not been clearly  defined.  Opportunities would
appear to exist at this location for water treating experimenta-
tion.

EPA and Proprietary Programs

Dr. Phillip Singer at the University of  North Carolina has an  EPA
contract for water treatment  of  coal conversion effluents. Publi-
cations thus far  indicate  that he  has  investigated biological
oxidation and carbon adsorption, mostly  on  synthetic sour  water
mixtures or single compounds.   Continuation  of the experimenta-
tion is expected to yield useful information on the effects  in
treatment processes of specific substances  encountered  in coal
conversion processes.

Gasification processes developed by  private funds include Texaco,
BGC/Lurgi and Shell/Koppers.   Only BGC/Lurgi  may be obligated  to
publish soon since they have  DOE funds  for  design.  Texaco  has
started up a 1MM  TPD  plant  in Oberhausen,  West Germany in  co-
operation with Ruhrkohle A/G  and Ruhrchemie.  Shell/Koppers have
a 150 TPD operating pilot plant in  Saarland, West Germany.   No
details on treating have been published  for either of these.
                              515

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NEED FOR DEMONSTRATION OF COMMERCIAL PROCESSES

Reference  has been made in  previous sections  to  the need for
demonstration of the individual commercial  water treating
processes and the integrated schemes proposed for coal gasifica-
tion with and without p/o/t production and coal liquefaction.  It
has been pointed out that treating results  of  virtually every
step should be verified by actual testing on wastewaters  from the
processes involved.

Some of the steps may be sufficiently verifiable on wastewaters
from DOE pilot plants, but the ultimate confirmation should come
from integrated operation on a demonstration  plant.  The demon-
stration plant presumably would  be large enough so that opera-
tions would be directly relatable to a commercial plant in every
respect.

Most of the DOE pilot plants are not directly  relatable to com-
mercial operation, since water  quantities or  concentrations of
pollutants  are frequently different due to  use  of  once-through
quench water,  experimentation with steam/coal ratios and  dilution
with various waste streams from the pilot installation (run-off
water,  aqueous wastes from the laboratory, area drains, inert gas
and hydrogen generators, etc.) which are much larger in relation
to the  feed  coal than would be  the case in  a  commercial size
plant.

Some of the pilot plant equipment producing  water  would not be
used at  all  in a commercial plant (e.g.,  hydrogen generation
systems would  be different and "thermal oxidizers"  installed in
many pilot  plants in lieu of water treating would not be  adequate
commercially).
                              516

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Commercial designs differ from the  pilot  installations  in  coal
transport media (water vs.  oil) and  in  design and operation of
quenching systems.  In most cases  the pilot plants are designed
to confirm operating conditions of gasification or liquefaction;
water treating, or waste control  in general,  is a very  secondary
consideration.

Regardless of the differences cited above  between pilot plant and
commercial design systems,  the pilot plant wastewater should  cer-
tainly be usable in setting conditions for design of wastewater
treating systems for demonstration plants.  Small scale treating
such as that being done by the Carnegie-Mellon team,  the  work by
the Synthane group at Bruceton, Pa.  and potential testing at the
SRC pilot plant  (as  suggested in  "Need for  Laboratory  Data on
Available Schemes" - subsection "DOE Treating Programs")  could be
very valuable in this respect.  Contract treating  such  as  that
done by AWARE,  Inc.  for Ashland Oil for the 600  TPD  H-Coal  pilot
plant is a good example of another route to obtain data for  water
treatment system design.

It has also been urged that DOE make use  of  vendor  and licensor
know-how and facilities in the testing phases, since  their  equip-
ment  will be  used  in the commercial plants and demonstration
plants.  Many  of these firms have  good testing  laboratories for
obtaining the  data needed  to select  the equipment  which will be
used  commercially.   Some of  these companies  also offer  small
rental units which could be  used  in the  DOE pilot  plants.  The
refining  industry, for example, is  quite  aware of such units and
have made good  use of  them as  have  other  industries  who  are  pre-
sently forced  to  improve their water treating systems in  order  to
satisfy  the Federal,  State and local regulations that are already
in  force.
                                517

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Demonstration  of "zero discharge"  water treating schemes employ-
ing recycle  of treated water should  be incorporated in demonstra-
tion plant  designs.   Specialists  in cooling  tower and boiler
operations should be given subcontracts  to  participate in  the
design of these systems and also  to monitor the systems during
demonstration  plant operation.  In  this  way the best additives
and conditions for control  of  scaling,  algae,  foaming, and
corrosion could be established  in the  particular plant to be
operated. Different  plant locations, different raw water and
coal compositions,  and the different coal conversion processes,
may present unique problems which could  dictate  additional
equipment or different additives to  control  corrosion, scaling,
algae,and foaming.

It has also  been demonstrated that there  are alternate integrated
schemes which  could be cheaper to  build or operate, but which  re-
quire experimental verification.  Incorporation  of  parallel
alternate water treating trains on  the demonstration plants is
suggested where design studies  dictate that  such systems are
feasible if  long-term operation bears out the design assumptions.
Total or partial by-passes for  various steps  could also be in-
stalled to allow establishment of  the need for  that step or the
minimum degree of cleanup actually required  by the cooling tower
or steam systems.
                             518

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NEED FOR FURTHER  STUDY

In addition  to  the  further study suggested  in  foregoing sections
("Integrated Schemes for Wastewater Treatment,"  "Need for Labora-
tory Data on Available Schemes"  and  "Need  for Demonstration  of
Commercial Processes"), study of alternate  commercial technology
and developing technology could  prove fruitful  should  the
schemes suggested not perform as expected.

Alternate Commercial Technology

Control  technology that has been mentioned,  and  references
documented,  is  as follows:

   o  Reverse  osmosis  on sludges with  evaporation  of reject
      stream.   Treated water to cooling tower.

   o  Reverse  osmosis  on sludges with  evaporation  of reject
      stream.   Treated water to demineralization for high  pres-
      sure steam  boiler feed water use.

   o  Study  of  stage-wise water condensation to concentrate  in-
      organic materials with a minimum of organic materials.

   o  Establish best side-stream treatment system  for  cooling
      tower.

   o  Establish best system for biological oxidation.   The many
      variations  offered  include trickling  filters,  rotating bio-
      logical  disc, contactors, fluidized sand beds,and High
      Purity Oxygen Activated Sludge.  Licensors  for the  above
      have been documented and  could be given  samples  and sub-
      contracts sufficient to establish efficiency,  capital cost,
      and operating costs on a firm-bid basis.
                              519

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   o  Anaerobic  digestion as a  first stage,  followed by  an
      aerobic  second stage.  One  licensor  of this technology  has
      been identified and others  are available.

   o  Powdered activated  carbon addition to  activated sludge
      systems.   High surface area  carbon and long sludge age,
      without  regeneration, is one  alternate.  Regeneration  by
      wet air  oxidation and higher  PAC rates  is another.  This
      system definitely enhances nitrogen  compound removal  as
      well as  BOD and  COD  removal  vs. conventional  activated
      sludge with no carbon addition.

   o  Thermal oxidation  of wastewater (Zimpro)  and  catalytic
      oxidation of wastewater should  both be  tried.  The  final
      cleanup  step following these must be established (probably
      biological oxidation at second stage conditions,  preferably
      with powdered active carbon addition).  High Purity Oxygen
      Activated Sludge (UNOX)  is  another candidate  for  the
      cleanup  stage.

   o  Establish the role,  if any, of  chemical oxidants  such  as
      ozone, chlorine,  or hydrogen peroxide.

   o  Establish the role,  if any,  of encapsulation processes such
      as  Chem-Fix, IU Conversion,  and  others.

Developing Technology

Developing control technology that has been  documented  includes
the following:

   o  Biological oxidation in fluidized bed (Ecolotrol,  Inc.).

   o  Oil  fluidized evaporation  (Dehydrotech Corp.).
                              520

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   o  Heavy metal removal by SULFEX process (Permutit).

   o  Ultraviolet irradiation with ozone.

   o  Lime sludge recovery (Dorr-Oliver  and others).

   o  Catalytic sludge precipitation (Permutit).

   o  Freezing (Fluor).

   o  Thermal incineration in reducing atmosphere and recycle  to
      process of  purge  liquors  from  redox  systems  such  as
      Stretford and Takahax (Nittetu Chemical Engineering.  Ltd.).

   o  Coalescence   of emulsified oil-water  mixtures  in  solid
      beds.  Substitute for API separator.

   o  Lindman precipitator (Precipitator,  Inc.).  Uses SC^  ,  lime
      and iron to remove suspended solids, BOD, oil,and  grease.

   o  Super bacteria  strains for  greater  cleanup in biological
      oxidation (Polybac Corp.).

   o  Mercury removal processes  (Japanese  "re-elixirization,"
      FMC, Georgia-Pacific).

Licensors of the  alternate and  developing  technology,  or  of
technology not in  wide  use at  present, could be furnished
subcontracts to demonstrate superior efficiency or advantages  in
operating or capital  cost.  Should special problems still exist
after the commercial technology  schemes have been thoroughly
evaluated, some of  these processes may provide answers  to the
problems.
                             521

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It is also  conceivable that unusual  contaminants in specific
coals would  not  be  removed by the  conventional processes  and
could require addition of some of  the  alternate and developing
methods  to  remedy this situation.

Economics of any of the methods mentioned  in  this section  should
be more  thoroughly  evaluated and  the  efficiency documented by
testing  on  the actual wastewater from the  coal  conversion process
in question.

The data presently  being generated  by DOE and EPA but  not  yet
published could conceivably change the  tentative  conclusions that
have been reached concerning water treating.  These reports, when
available,  should  be monitored  to  ascertain whether any such
changes  are  justified.
                             522

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                                 TECHNICAL REPORT DATA
                          (Please read Instructions on the reverse before completing)
 REPORT NO.
 EPA-600/7-79-22 8a
        2.
                                     3. RECIPIENT'S ACCESSION NO.
 TITLE ANDSUBTITLE
Coal Conversion Control  Technology
Volume I.  Environmental Regulations; Liquid Effluents
                                     5. REPORT DATE
                                      October 1979
                                     6, PERFORMING ORGANIZATION CODE
 AUTHOR(S)

L.E. Bostwick,  M.R.  Smith,  D.O. Moore, and D.K. Webber
                                     8. PERFORMING ORGANIZATION REPORT NO.
 PERFORMING ORGANIZATION NAME AND ADDRESS
Pullman Kellogg
 16200 Park Row,  Industrial Park Ten
Houston,  TX   77084
                                      10. PROGRAM ELEMENT NO.

                                         EHE 623A
                                      11. CONTRACT/GRANT NO.

                                        68-02-2198
2. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
                                      13. TYPE OF REPORT AND PERIOD COVERED
                                       Final;  4/77 -  11/78	
                                      14. SPONSORING AGENCY CODE
                                       EPA/600/13
5. SUPPLEMENTARY NOTES

919/541-2160.
IERL-RTP project officer  is  Robert" A.  McAllister,  Mail Drop 61,
          This volume  is  the product of an information-gathering effort relating
 to coal conversion  process streams.  Available and developing control technology
 has been evaluated  in view of the requirements of present and proposed federal,
 state, regional,  and  international environmental standards.  The study indicates
 that it appears possible to evolve technology to reduce each component of each
 process stream to an  environmentally acceptable level.  It also indicates that
 such an approach  would be costly and difficult to execute.  Because all coal
 conversion processes  are net users of water, liquid effluents need be treated
 only for recycling  within the process, thus achieving essentially zero discharge.
 With available technology, gaseous emissions can be controlled to meet present
 environmental standards, particulates can be controlled or eliminated, and
 disposal of solid wastes can be managed to avoid deleterious environmental effects.
 This volume  (I)  focuses on environmental regulations for gaseous, liquid, and
 solid wastes, and the  control technology for liquid effluents.
17.
                               KEY WORDS AND DOCUMENT ANALYSIS
                 DESCRIPTORS
                                             b.lDENTIFIERS/OPEN ENDED TERMS
                                                                       c. COSATI Field/Group
  Pollution
  Coal Gasification
  Coal Preparation
  Regulations
  Effluents
  Liquids
                          Pollution Control
                          Stationary Sources
                          Coal Conversion
                          Liquid Effluents
13B
13H
m
07D
13. DISTRIBUTION STATEMENT

 Release to Public
                         19. SECURITY CLASS (ThisReport)
                          Unclassified
     538
                         20. SECURITY CLASS (Thispage)
                          Unclassified
                                                    22. PRICE
EPA Form 2220-1 (9-73)
                                          522a

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