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)
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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
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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:
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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.
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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.
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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
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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
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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.
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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.
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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.
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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
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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
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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
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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
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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
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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
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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.)
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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.
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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
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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
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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
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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
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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.
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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.
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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
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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
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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
-------
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
-------
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
-------
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
-------
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
-------
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.
-------
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,
-------
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
-------
(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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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.
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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
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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:
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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
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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."
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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.
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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
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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)
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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
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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.
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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
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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.
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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.
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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)
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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.
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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)
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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
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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
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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.)
145
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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
-------
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.
151
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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)
154
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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.
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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.
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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.
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
-------
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
-------
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
-------
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
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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
-------
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
-------
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
-------
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)
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
Figure 8-43. Engineering News Record (ENR)skilled labor index.
2
r
CP
o
U)
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
vo
U)
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.
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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).
-------
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
-------
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
-------
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
-------
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
-------
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
-------
(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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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.
508
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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.
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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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