EPA.650/2-74-009-b
June 1974
Environmental  Protection  Technology Series












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                                   EPA-650/2-74-009-b
EVALUATION OF  POLLUTION CONTROL
      IN FOSSIL  FUEL CONVERSION
                 PROCESSES
     GASIFICATION; SECTION I:  SYNTHANE PROCESS
                        by

              C. D. Kalfadelis and E. M. Magee

           Esso Research and Engineering Company
                     P.O. Box 8
                Linden, New Jersey 07036
                 Contract No. 68-02-0629
                  ROAP No. 21ADD-23
               Program Element No. 1AB013
            EPA Project Officer:  William J . Rhodes

                Control Systems Laboratory
            National Environmental Research Center
         Research Triangle Park, North Carolina 27711
                    Prepared for

           OFFICE OF RESEARCH AND DEVELOPMENT
          U.S. ENVIRONMENTAL PROTECTION AGENCY
                WASHINGTON, D.C. 20460

                      June 1974

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This report has been reviewed by the Environmental Protection Agency
and approved for publication.  Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
                                 11

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                             TABLE  OF CONTENTS

                                                               Page

SUMMARY	   1

TABLE OF CONVERSION UNITS	   2

INTRODUCTION	   3

1.  PROCESS DESCRIPTION  AND EFFLUENTS - GENERAL	   5

2.  EFFLUENTS TO AIR - MAIN  GASIFICATION  STREAM	   8
    2.1  Coal Preparation and Storage	   8
    2.2  Coal Grinding	  13
    2.3  Gasification	  14

         2.3.1  Coal Feed System	  14
         2.3.2  Char Letdown	  16

    2.4  Dust Removal	  ^8
    2.5  Shift Conversion	  25
    2.6  Waste Heat Recovery	  25
    2.7  Light Hydrocarbon Removal	  25
    2 .8  Gas Purification	  26
    2.9  Residual Sulfur Cleanup	  27
    2.10 Methanation	  28
    2.11 Final Methanation	  30
    2.12 Final Compression	  "30

3.  EFFLUENTS TO AIR - AUXILIARY FACILITIES	  31

    3.1  Oxygen Plant	  31
    3.2  Sulfur Plant	  31
    3.3  Utilities	  33
         3.3.1  Power and Steam Generation	  33
         3.3.2  Cooling  Water	  36
         3.3.3  Waste Water  Treatment	  37
         3.3.4  Miscellaneous Facilities	  39

4.  LIQUIDS AND SOLIDS EFFLUENTS	  40

    4 .1  Coal Preparation	  40
    4.2  Coal Grinding	  41
    4.3  Gasification	  41
    4 .4  Dust Removal	  41
    4.5  Shift Conversion	  47
    4.6  Waste Heat Recovery	  47
    4.7  Gas Purification	  47
    4.8  Residual Sulfur Cleanup	  48
    4.9  Methanation	  48
    4.10 Gas Compression	  48
    4-11 Auxiliary Facilities	  48

         4.11.1  Oxygen  Plant	  48
         4.11.2  Sulfur  Plant	•	  48

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                        TABLE OF CONTENTS (Cont'd)
                                                                  Paee
           4.11.3  Power and Steam Generation	    49
           4.11.4  Cooling Water	    49
           4.1L5  Miscellaneous Facilities	    50

     4.12  Maintenance		    40

 5 •   THERMAL EFFICIENCY. ..		    51

 6.   SULFUR BALANCE	    55

 7.   TRACE ELEMENTS	    58

 8-   PROCESS ALTERNATIVES	    66

 9.   ENGINEERING MODIFICATIONS	    69

10.   QUALIFICATIONS	    72

11.   RESEARCH AND DEVELOPMENT NEEDS	    76

12 .   BIBLIOGRAPHY	    82

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                               LIST OF TABLES

Table
           Table of Conversion Units
           Stream Identifications for Revised
           Synthane Process
           Chars From Synthane Gasification of
           Pittsburgh Seam Coals ..............................     33
  3        Components in Gasifier Gas
  4        Mass Spectrometric Analyses of Benzene-
           Soluble Tar From Synthane Gasification
           By-Product Water Analysis From
           Synthane Gas
  6        Thermal Efficiency .................................     54

  7        Sulfur Balance ............................ • ........

  8        Trace Elements  in Condensate From An
           Illinois No.  6  Coal-Gasification Test ..............     60
   9        Trace  Components  in  Raw Gas  and Tar ................     61

                                                                   f\7
  10        Major  Elements  in Coal .............................     °^

  11        Minor  Trace  Elements ...............................     63

  12        Potentially  Hazardous  Trace  Elements ...............     64-

  13        Process  Alternatives Considered ....................     68

  14        Engineering  Modifications  Considered ...............     71

  15        Coal and Product  Analyses ..........................     73

  16        Plant  Utility Requirements .........................     74

  17        Coal and Product  Quantities  and  Heat  Content .......     75

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                           LIST OF FIGURES

                                                             Page

         Synthane Coal Gasification	         6

         Synthane Design Revised to Incorporate
         Environmental Controls and to Include
         Auxiliary Facilities	         9

3        Design Basis Dust Removal	        19

4        Raw Product Gas Scrubbing	        21

5        Tar Scrubber Shown Integral with
         Gas if ier Reactor	        23

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                                 SUMMARY
          The Bureau of Mines Synthane Coal Gasification Process has been
reviewed from the standpoint of its potential for affecting the environment.
The quantities of solid, liquid and gaseous effluents have been estimated,
where possible, as well as the thermal efficiency of the process-  A
number of possible process modifications or alternatives have been proposed
and new technology needs have been pointed out.

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                                   -  2  -
                         TABLE OF CONVERSION UNITS
  To Convert From




 Btu




 Btu/pound




 Cubic feet/day




 Feet




 Ga lions/minute




 Inches




 Pounds




 Pounds/Btu




 Pounds/hour




 Pounds/square  inch




 Tons




Tons/day
             To
 Calories,  kg




 Calories,  kg/kilogram




 Cubic meters/day




Meters




 Cubic meters/minute




 Centimeters




Kilograms




Kilograms/calorieskg




Kilograms/hour




Kilograms/square centimeter




Metric tons




Metric tons/day
Multiply By




  0.25198




  0.55552




  0.028317




  0.30480




  0.0037854




  2.5400




  0.45359




  1.8001




  0.45359




  0.070307




  0.90719




  0.90719

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                                   -  3  -

                              INTRODUCTION


          Along with  improved control of air and water pollution, the
 country  is  faced with urgent needs for energy sources.  To improve the
 energy situation,  intensive efforts are under way to .upgrade coal, the
 most plentiful domestic fuel, to  liquid and gaseous fuels which give less
 pollution.  Other  processes are intended to convert liquid fuels to gas.
 A few of the coal  gasification processes are already commerically proven,
 and several others are being developed in large pilot plants.  These pro-
 grams are extensive and will cost millions of dollars, but this is war-
 ranted by the projected high cost for commercial gasification plants and
 the wide application expected in order to meet national needs.  Coal con-
 version  is faced with potential pollution problems that are common to
 coal-burning electric utility power plants in addition to pollution pro-
 blems peculiar to  the conversion process.  It is thus important to examine
 the alternate conversion processes from the standpoint of pollution and
 thermal efficiencies and these should be compared with direct coal utili-
 zation when applicable.  This type of examination is needed well before
 plans are initiated for commercial applications.  Therefore,  the Environ-
 mental Protection Agency arranged for such a study to be made by Exxon
 (formerly Esso)  Research & Engineering  Company under contract EPA-68-02-0629,
using all available non-proprietary  information.

          Phase I  of the contract involved the collection and evaluation
 of published information concerning trace elements in coal, crude oil and
 shale.  This information is contained in the report, "Potential Pollutants
 in Fossil Fuels", by E. M. Magee, H, J. Hall and G. M. Varga, Jr.,
 EPA-R2-73-249, June 1973 (NTIS PB #225,039).  Phases II and III were  con-
 cerned with the collection of published information on fossil fuel conver-
 sion/treatment processes and the description of selected processes.   These
 selected processes were evaluated for their ability to produce clean fuels
 and for  their possibilities for environmental pollution.

          The present study, Phase IV of the contract, involves preliminary
 design work to assure the processes are free from pollution where pollution
 abatement techniques are available, to determine the overall efficiency of
 the processes and to point out areas where present technology and informa-
 tion are not available to assure that the processes are non-polluting.

          All significant input streams to the processes must be defined,
 as well as all effluents and their compositions.  This requires complete
mass and energy balances to define all gas,  liquid, and solid streams.
With this information, facilities for control of pollution can be examined
and modified as required to meet Environmental Protection Agency objectives.
Thermal efficiency is also calculated, since it indicates the amount of
waste heat that must be rejected to ambient  air and water and is related to
 the total pollution necessary to produce a given quantity of  clean fuel.

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                               - 4 -
Alternatively, it is a way of estimating the amount of raw fuel resources
that is consumed in making the relatively pollution-free fuel.  At this
time of energy shortage this is an important consideration.  Suggestions
are included concerning technology gaps that exist for techniques to
control pollution or conserve energy.  Maximum use was made of the
literature and information available from developers.  Visits with some
of the developers were made, when it appeared warranted, to develop and
update published information.  Not included in this study are such
areas as cost, economics, operability, etc.  Coal mining and general
ottsite facilities are not within the scope of this study.

          Considerable assistance was received in making this study, and
we wish to acknowledge the help and information furnished by EPA, the
Bureau of Mines, and the Lutmnus Company, as well as that furnished by many
specialists in Exxon Research and Engineering Company.

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                                  -  5 -
              1.   PROCESS  DESCRIPTION AND EFFLUENTS  - GENERAL
          The Synthane Process being developed by the  Bureau of Mines
is an intrinsically high efficiency fluidized bed coal gasification
system operating at commercial pipeline pressure and designed to produce
high-Btu content product gas.  Gasification is accomplished in the
presence of steam/oxygen, whereby heat required for the gasification
reactions is supplied by the reaction of oxygen with a portion of the
coal.  High pressure favors methane yield, minimizes gasifier volume,
reduces oxygen requirement and reduces product gas compression-   A good
fluidized bed operation insures the homogeneous reaction system required
to avoid damage by locally high oxygen concentrations.

          Development work was started in 1961 by the Bureau of Mines
on methods of pretreating caking coals in a fluidized bed.  It was
found possible to pretreat any caking coal by  the proper combination
of oxygen content of the fluidizing gas,  temperature, and residence
time  (1,2,3).  Earliest  gasification  tests with a two-bed fluid system
incorporating gas,  tar,  and  char recycle  (4)  led  to the development of
a single vessel system wherein the operations  of  coal pretreatment,
carbonization, and  gasification were  combined  (5).

          An  engineering evaluation of the Synthane Process, which by
this  time incorporated Bureau of Mines methanation  developments  (6,7),
was prepared  by The M.W. Kellogg Company  in  1970  (8).   Notwithstanding
the substantial extension  of high-pressure technology required  to com-
mercialize the process,  there was  found sufficient  incentive  in the
economies projected in  terms of overall simplicity, high  gasifier methane
yield,  and small  reaction  volumes  to  proceed  with design  of a  prototype
large pilot  plant.   The  prototype  pilot plant was designed  by  The Lummus
Company (9),  and  is now  being constructed.   It is expected  to  be
operational  in  1974.

          The process  basis  for our  evaluation is that  employed by the
Bureau of Mines  in its  economic evaluation of Synthane  Gasification  (10)
in  1971.   A  block flow diagram of  the process and auxiliary facilities
is  shown in  Figure 1.   This  design feeds  14,250 tpd  of  a Pittsburgh  seam
coal  containing 2.5% moisture, 7.4% ash,  and 1.6% sulfur to the gasifiers.
250MM scfd of product  gas is produced, with  a HHV of  927 Btu/scf.

           The design basis for the economic  evaluation was based on
laboratory investigation in a forty-atmosphere fluid-bed gasifier (11).
Although serving adequately to define the major processing hardware
 and energy requirements, so that  economic comparisons might be made with
 other gasification processes in a similar stage of development, the basis
 did not detail disposition of effluent streams which might require special

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                                                                                                                           ETU/SCF
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                                   - 7 -
processing to minify environmental impact.  In fact, until process
stream compositions are more precisely determined for specific feed
coals, the nature of such effluent streams, and the degree of processing
required, may only be inferred.  Second after achievement of primary
gasification targets, the definition of a process's pollution potential
is a major justification for the construction and operation of a
large pilot plant.

          The pollution potential has not been completely defined in
the context of U.S. standards even for those gasification processes
which have already been commercialized elsewhere.  Standards have
changed radically in recent years, and new standards continue to be
promulgated by governing agencies at  a high rate.  Coal compositions,
including sulfur and trace element contents, vary widely  (12),
even within particular regions or mines.  Stream compositions from a
particular process are generally sensitive to coal composition as
well as to specific operating conditions.

          On the other hand, gross estimates of the pollution potential
may be inferred on the basis of prior art and experience with processes
which treat coal  or petroleum  in analogous manner.  There is no direct
commercial coal" gasification prior art for the extreme pressure at which
the Synthane gasifier will operate.  Synthane gasification approaches
conditions which obtain in the commercialized Lurgi system, but the
,Lurgi gasifiers are "fixed-bed" devices operating at less than half the
pressure of the Synthane fluid-bed units-  The present Lurgi gasifier is
more restrictive with respect to feed coal physical properties than should
be the case with the Synthane system, which incorporates integral pretreat-
ment-  But a direct comparison of the pollution potential of the two
systems must await considerable further development.

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              2.  EFFLUENTS TO AIR - MAIN GASIFICATION STREAM


           All effluents to the air are shown in Figure 2 and Table 1. These
 effluents are based on the Bureau of Mines design (10), and are to some
 degree inferred by analogy with prior art.  Because of the large number
 of options open to Synthane development at this stage relative to
 established processes, there is every probability that substantial
 modification and/or improvement may be expected.

 2.1  Coal Preparation and Storage

           Common to all fuel coal usage, and particularly to coal
 gasification processes, are the operations of coal mining, which
 may include coal laundering, drying, and screening, coal transport,
 and storage. This study does not include energy and/or pollution con-
 siderations relative to these operations.

           On-site coal storage  will be required for all gasification plants
 to provide back-up for continuous  gasification operations.   For thirty
.days  storage,  there  might be four  piles,  each about 200 feet  wide,  20
 feet  high, and  1000  feet  long.   Containment of air-borne  dusts  is  generally
 the only air pollution control  required  for transport  and storage  operations
 although odor may be & problem  in  some instances.   Covered  or enclosed
 conveyances  with dust  removal equipment  may be  necessary.but  precautions
 must  be taken against  fire or explosion.   Circulating  gas streams  which
 may be used  to  inert or blanket a  particular operation or which may issue
 from  drying  operations will generally require treatment  to  limit particulate
 content before  discharge  to the atmosphere  (14).   Careful management  and
 planning will minimize dusting  and  wind  loss  and  the hazard of  combustion
 in storage facilities-

           The feed coal employed.-in this design has low inherent moisture
 content,  such that a special coal  drying step is not provided.   It may
 be possible  to  operate the system  without such a facility with coal from
 particular seams,  but  this indicates enclosed on-site  storage.   Coal of
 the type and size range (-3/4  inch) indicated to be held in stockpiles
 in this design  might be expected to acquire and retain 6-8 weight  per
 cent  surface moisture  on  exposure  to rain.

           Should drying be required, however, the options available are
 numerous, both  with  respect to  procedures and to the fuel or heat  source
 that  may be  employed.   Comments relating to coal drying in connection
 with  the Koppers Process  (14) are  pertinent.   Ideally,  no additional  fuel
 would be combusted specifically for coal drying purposes, but rather
 hot gas,  as,  for example,  flue  gas from the utility boiler,  would  be
 used.   Overall  energy  debits would be minor in such case.  The gas

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                                  II       I    1
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                                                            Figure 2. SYNTHANE DESIGN REVISED TO
                                                                    INCORPORATE ENVIRONMENTAL
                                                                    CONTROLS AND TO INCLUDE
                                                                    AUXILIARY FACILITIES
                                                                          Stream Identification)

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                                                 -  10 -




                                                TABLE  1

                          STREAM IDENTIFICATIONS FOR REVISED  SYNTHANE  PROCESS

                        (Stream Numbers  Refer to Figure  2.  See  Text  for  Details)
 COAL PREPARATION

   o  Coal  Storage
   o   Coal  Drying
  o  Coal Grinding
GASIFICATION

  o  Coal Feed Lock Hoppers
  o  Gasifiers
  o  Char Let-Down
DUST REMOVAL

  o  Tar Scrubber
  o  Aqueous Scrubber
  1.   Influence  of weather  (wind,  temperature)  on 20-25  acre
      on-site  coal storage  piles-
  2.   Dusting  and  wind  losses;  possible  odor.
  3-   Precipitation on  20-25  acre  storage  area.
  4.   Storm run-off estimated at 5000 gpm  contains  particulates
      and  may  be sulfidic.  Directed to  "oily water"  retention
      ponds along  with  run-off  from processing  areas  for
      subsequent addition to  waste water treatment  system.

  5.   No drying  facility provided  in base  case.   Assume
      utility  boiler flue-gas stream used  for drying  coal
      if required.
  6.   Assume 6%  moisture retained  on coal  stored  openly
      is removed,  equivalent  to 72,000 Ib/hr water  evaporated.
      Vent gas stream directed  to  limestone scrubbing facility
      for  particulate removal and  desulfurization.

  7.   53 MM cfd  air intake  to milling circuit.  Nitrogen from
      oxygen plant  may  be substituted in any proportion  to
      reduce fire  hazard.   Nitrogen from the oxygen plant
      may  be used  to  blanket  storage hoppers or transport
      facilities.   High-pressure steam may be used  as
      transport  medium  for  ground coal in  pipe ducts.

  8.   Outflow  stream includes up to 60 tpd coal fines
      (removed at  bag filters and  returned to coal  feed  bins)
      and  up to  20,000  Ib/hr  water vapor.
 9.  Treated C02 separated at sulfur recovery unit used as
     make-up to recycled gas pressurization system, amounting
     to 30-50 MM cfd.
 10.  No effluent to atmosphere excepting leakage at gas
     storage facilities; leakage into process of 30-50 MM cfd
     with coal feed.

 11.  1,187,500 Ib/hr coal feed (see text for analysis):
 12.  304,000 Ib/hr oxygen feed.
 13.  1,169,700 Ib/hr high-pressure steam feed.
 14.  Boiler feed water to cooling jacket,675 gpm.
 15.  Low-pressure steam from cooling jacket, 335,100 Ib/hr.

 16.  200  gpm boiler  feed water to  "dry  char"  cooler.
 17.   100,000 Ib/hr high  pressure steam  directed  to  shift  converters.
     3000-6000  Ib/hr  vented  steam  treated  to  remove  particulates
      if discharged to  atmosphere;  may be  used  to transport char to
     boiler or may be  directed to  water treatment  facilities.
 18.   4350 tpd  char,  assumed  dry.   Ducted  to utility boiler using
      steam as  transport  medium.
19.  Up to 3350 gph heavy tar recycled to gasifier, processed
     for sale, or directed to utility boiler.
20.  Up to 365,000 Ib/hr high-pressure steam generated in
     external tar.cooling circuit.
21.  730 gpm boiler feed water to tar cooler.

22.  1,110,000 Ib/hr aqueous scrubber effluent, directed
     to waste water treatment; depending on operating
     conditions, an additional 1500 gph  of tar and 6-7  .
     tph of ammonia may be separated from raw gas, in
     addition to phenols and oils.
23.  No discharge to atmosphere; 20-30,000 scfm raw gas
     evolved on depressurization of scrubber effluent
     recompressed into main gasification stream ahead of
     gas purification.
24.  600 gpm boiler feed water to scrubber cooling circuit.
25.  300,000'Ib/hr low-pressure steam generated in cooling
     circuit.

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                                                  -  11 -

                                           TABLE  1  (Cont'd)

                          STREAM  IDENTIFICATIONS  FOR REVISED SYNTHANE PROCESS

                         (Stream Numbers Refer to  Figure 2.  See Text for Details)
 SHIFT CONVERSION


 HEAT RECOVERY
  26.   Spent catalyst  (3-year  life normal).
  27.   548,900  Ib/hr high-pressure superheated steam.
 OIL SCRUBBER
 GAS PURIFICATION
 SUUUR GUARD
 METHANATION
COMPRESSION


OXYGEN PLANT





UTILITY BOILER
COOLING WATER
                                          28.
                                          29.
                                          30.
 31.




 32.

 33.
                                          34.
                                          35.
                                          36.

                                          37.


                                          38.
                                          39.
                                          40.
                                         41.
 42.
                                         46.
                                         47.
                                         48.
                                         49.
                                         50.
                                         51
                                         52
 950 gpm boiler feed water to  waste  heat boiler.
 474,500 Ib/hr low-pressure steam.
 395,000 Ib/hr condensate  directed  to  waste  water
 treatment.   Gases  which separate on decompression
 reinjected  into main gasification  stream via  routing
 for stream  23.

 Up to 1000  gph naphtha  in scrubbing oil stream, depending
 on operation of upstream  scrubbers.    This  system integrated
 with oil  recovered from aqueous scrubbing effluents
 (used as  scrubbing medium).   Up to  25,000 Ib/hr low-
 pressure  steam required for distillation of naphtha.
 18,000 Ib/hr high-pressure resaturation steam.

 19,000 Ib/hr condensate from  after-cooler directed to
 waste water treatment.  Spent  Benfield  solution and/or
 blowdown  (life not estimated)  requires  special treatment.
 Gases which separate  from condensates or blow-down
 on depressurization directed  to utility boiler.
 737,600 Ib/hr low-pressure steam into regenerators.
 No discharge  to  atmosphere.   270 MM cfd  acid  gas  stream
 directed  to sulfur recovery.   Up to 1.0  MM cfd product
 gas  lost  into acid gas  stream.

 Regeneration  gas or steam; inerting gas  required  on change-
 out  of bed  material.
 Discharges  to atmosphere may  include clean  regeneration
 or inerting gases.  Dirty  gas  and product gas vented on
 change-outs directed  to utility boiler.
 Spent  bed media.   Carbons  or chars may  be combusted
 in utility  boiler.   Sulfated metal oxides will require
 special treatment  or  burial In sealed pits  (life  not
 estimated).

 Oxygen-free gas circulated in Raney nickel  activation.
 Vented  activation  gas.  Hydrogen evolved  in activation
 and  product gas vented on  change-outs directed to utility
 boiler:  Metal dusts generated in catalyst  replacement
 contained in  closed filter system.
 130,000 Ib/hr  condensate from after-cooler directed to
 waste water treatment.  Catalyst replacement and  activation
will generate metallic solids effluents  and  caustic liquid
 effluents which will require special treatment.

 1000  Ib/hr condensate from Inter-coolers directed  to waste
water  treatment.
43.   425  MM scfd  air intake
44.   330  MM scfd  nitrogen and  other  air constituents.  (152  tph
     oxygen to gasifier).
45.   85  gpm water  condensate from  inter-coolers directed  to
      boiler feed-water  treatment.
      1060  MM scfd  combustion air intake.
      1070  MM scfd  flue gas  from char combustion,  including
      10,900  Ib/hr  S02.  (C02-18.5%, 02-1.9%, N2-79.47.,
      S-0.157.).  Directed to  coal drier, if required for
      drying  coal.
      115-135 tpd limestone  to desulfurize flue-gas from char
      combustion.   Scrubber placed on coal dryer exit if flue
      gas used to dry coal.
      1050  tpd ash  and  150-200 tpd sulfated lime from flue-
      gas treatment.  Disposition uncertain, depending on
      composition,  but  assume burial in mine or in sealed pits.
     Chemical additives may include chromium or zinc compounds,
     acids, chlorine, phosphates, phenols, copper complexes.
     2600 gpm water evaporated and 300 gpm drift loss into
     circulated air if air-fin usage maximized.  Early
     warning system required in return laterals to indicate
     leakage from process train to control emissions in cooling
     tower plumes.
     Draw-off from cooling towers estimated at 500 gpm.   May
     require special treatment ahead of injection into waste-
     water treatment.  Can be substantially reduced by incorporation
     of zeolite softening system in cooling water circuit,
     assuming leakage from process train is very small.
53.  20,000 MM scfd  air  circulated against cooling  towers.

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                                               - 12 -




                                          TABLE 1  (Cont'd)

                          STREAM IDENTIFICATIONS FOR REVISED SYNTHANE PROCESS

                        (Stream Numbers Refer to Figure 2.   See Text for Details)
SULFUR RECOVERY
WATER TREATMENT
54.  5 MM scfd regeneration air for Stretford solution.
55.  Vented regeneration air directed to boiler firebox.
     210-220 MM scfd C02 containing up to 5 ppm H2S-
     may be directed to boiler stack.
56.  Make-up Stretford solution.
57.  About 140 tpd elemental sulfur produced for sale.
     Liquid purge from Stretford will require special
     treatment.

58.  Additives to system may include milk of lime
     (115 tpd), anti=foam,  phosphoric acid (0.5 tpd)s
     sulfuric acid,  char (42 tpd), oxygen or ozone,
     and other agents-
59.  Up to 230 tpd lime sludge, 76 tpd wet char  (recycled to
     utility boiler), and miscellaneous sludges  from aeration,
     biox and separation facilities.  Sludges will require
     special treatment.
60-  Aqueous scrubber effluents from dust removal  require
     special treatment, including facilities for separation of
     ammonia, tars, oils, phenols, and pyridine  bases.  Up
     to 160 tpd of ammonia may be separated for  sale.
61.  Control of noxious evaporative  losses  in treatment
     facilities may require special  engineering, including
     floating covers  on retention ponds or  tanks and/or
     forced draft.

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                                  -  13 -
stream would require treatment to remove particulates prior to its dis-
charge.  If particulate removal were the only consideration for such a
stream, then cyclone separation/filtration or electrostatic precipitation
would generally be preferred to scrubbing to conserve water, minimize
water treatment loads, and to facilitate recovery  of  fines. In
this case, however, flue gas from the utility boiler will require
desulfurization (see Section 3.3.1), so that we have assumed that lime-
stone scrubbing will be used.

         On the basis that tar is combusted along with char in the utility
boiler, and that flue gas from the boiler would be available at the coal
dryer at about 550°F, the utility boiler flue gas stream could dry feed
coal containing in excess of 6 weight per cent water.  On the basis that
limestone scrubbing will be used thereafter to limit SO- emission,
saturated flue gas leaving the scrubber would carry some 166,000 pounds
per hour of water into the atmosphere.  To limit S02 emission to an
acceptable level could require up to 230 tpd of limestone and the
net resulting SOo emission will be on the order of 5500 pounds per hour.

2.2  Coal Grinding

          Approximately 53 MM cfd of atmospheric air is  aspirated
into the ball-mill grinding operation,  which reduces coal size
to 70 per cent through 200 mesh.  The air stream is heated in a circula-
tion system and passed through the mills,  where  it serves both  to control
moisture in the pulverizing process and as transport medium for the
pulverized material.

          Close control of the milling circuit is required when air is
used in this manner to reduce to a minimum operation in the explosive
region, such as may obtain at start-up or shut-down of mills.  Pre-
cautions should also be taken against accidental overheating of coal,
as may occur due to mechanical failure of a heated mill.  In general,
inerting systems are provided for these devices.   An  alternative might
involve use of an inert or low-oxygen gas stream in place of air as,
for example,  the nitrogen from the oxygen plant or a flue gas.

          The coal/air mixture passes through cyclones,  where separation
occurs, and the air stream is discharged to the atmosphere through bag
filters.  Such arrangement is commercially proven, with acceptable
particulate emission, though load on the filters may amount to some
60 tpd in this case (15).   Only trace quantities of hydrocarbons have
been detected in such commercial streams, and odor is not considered
a problem.   Collected fines from the filters are recycled to mill product,

          It  should be noted that it is possible to effect substantial
drying of coal in the milling circuit.  Such systems have been designed
to accept coals with surface moisture content ranging to 20 weight per
cent.   But the overall effect is to reduce mill capacity, such that
there is normally incentive to predry coal feed to the mills.

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Nominal drying capability, amounting to some 2 weight per cent of the
easifier coal feed rate, is estimated for the milling circuit in tnis
design, based on indicated air heater provisions and mechanical energy
requirements in the circuit.

2.3  Gasification

     2.3.1  Coal feed System

          Coal is charged to the gasifiers in the  Bureau  of Mines design
through pressurized lock hoppers.  A number of alternatives regarding
the mechanical arrangement, the pressurizing medium, and  the  consequent
net energy  requirement  and pollution potential  of  lock hopper operation
appear  feasible.

          In this design,  each gasifier is provided with one lock
hopper, which discharges alternately into two feed hoppers from which
coal is passed to the gasifier using a steam/oxygen mix as transport
medium!  Oxygen reacts with coal in the transfer line, liberating heat
which prevents steam condensation that might °f™ "J^^rs
coal transport.  Hence, in this case, some pretreatment of coal occurs
in the transfer line.

          The gasifier  charging sequence  involves  filling  the vented
lock hopper from pulverized coal storage  bins,  pressurizing the filled
lock hopper, and discharging its load into a feed  hopper.  In this
configuration, it is presumed  that a feed hopper is  maintained  slightly
above  gasifier operating  pressure while  on line to the  gasifier,  and
that pressure  is allowed  to drop to  the  gasifier pressure level as  the
hopper  empties.  At  this  point,  the  feed hopper is ready  to  accept  another
charge  from the  filled, pressurized  lock hopper.

           The  pressurized lock hopper  must be  vented to essentially
atmospheric pressure when empty of  coal in  order to be  refllled.   In a
multiple gasifier  system, operation  may be  sequenced such that  initial
venting may be to  a lock  hopper awaiting pressurization,  or to  a suc-
 cession of these,  such that some of  the energy represented by the_com-
 pressed gas may  be recovered directly, while simultaneously reducing
 the quantity of  residual gas to be vented ultimately.  Alternatively, two
 or more lock hoppers might be provided each gasifier specifically to
 permit such sequencing, since there may be practical operating limita-
 tions to the degree to which gasifier operation may be scheduled.

           Another alternative that may be attractive for  large systems
 would involve specific energy recovery in the  venting process, as by
 means of turboexpanders,  which may be used to  drive compressors or to
 generate electricity.  Obviously, combinations of direct  use and specific
 energy recovery are possible.

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                                  - 15 -
           The choice of pressurizing medium may directly affect the main
 gasification processing sequence, as well as the design and operation of
 the lock hopper system.  The use of steam alone as this medium is con-
 sidered mechanically unacceptable due to interference expected with coal
 transport from condensation, which may not be controllable.

           Since some fraction of the pressurizing medium will travel
 with the coal into the gasifier, the use of a nitrogen-containing inert
 gas for such medium is considered unacceptable from a process viewpoint,
 since it dilutes the product gas, reducing its heating value, and
 occupies volume in the reaction sequence otherwise.

           Direct pressurization from the gasifier,  as  has  been done
 commercially in the  Lurgi  system (16),  or the use of  any combustible
 gas,  as,  for example,  product  gas,  is  unacceptable,  inasmuch as the
 pretreatment section of the  Synthane gasifier must  operate in an
 atmosphere of steam  and oxygen.   On  the  other hand,  there  may be  suf-
 ficient  compression  energy credits  to warrant consideration of a  mechanical
 arrangement  which  permits  the  use of steam only  to  transport coal  from
 feed  hoppers and,  additionally,  to  strip combustible  gas from such
 transferred  coal before coal contacts oxygen  in  the  pretreater.   And
 should  coal  pretreatment not be required in a particular situation,  use
 of  raw  or  product  gas  for  pressurization may  be  a preferred alternative
 It  will  be necessary then  to include means  for purging the  vented
 hopper,  as by use  of steam or  nitrogen,  before the hopper  is opened  to
 be  filled.

           It  is  believed that  C02, which is separated  from the main
 process  gas  stream following shift conversion, is the  preferred pres-
 surization medium  (8,9).   Such  C02 must  be  superheated to  prevent  liqui-
 faction  at 1000  psia,  and  the  rate of heat  loss  from  the pressurized
 feed  system must be  controlled to prevent condensation.  Depending
 on  the mode  of operation of  the  feed system,  the volume  of  raw
 gas issuing  from the gasifier may be increased some 3-5  percent
 as  a  consequence of  admission of  pressurization  gas with coal.  This
 increased  volume must be handled  through the  acid gas  removal  step,  but
 it  is presumed  otherwise not to  affect process operation.

           The composition  of gas  vented  from  the  lock  hopper can only
be  surmised at this  point, since  it  will be a function of  the  method
of  operation of  the  coal feed system, including  the pressurization
medium employed  and  the properties of the coal in use.   It  is  probable
that  removal of  particulate matter will  be required before  such gas
may be vented to the atmosphere.  If combustible gas be  employed, it
might be recycled  to the gasification train via compression, or might
be directly combusted in the utility plant.

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                                 - 16 -
           In  the method  of  operation  of  the  coal  feed system described
 above  for  this  design, there  should be no  opportunity for gasifier
 gas  to back through  the  lock  hopper.  ..Hence,  trace  quantities  only  of
 coal-originated materials,  other  than coal dust,  should  appear in vent
 gas.   However,  the use of  a heated hopper  system, as will be required
 if  CO? is  the pressurization  medium,  may subject  coal in contact with
 heated surfaces to sufficiently high  temperature  to cause stripping of
 volatiles  or  of sulfurous  gas.  Formation of carbon- or  carbonyl sulfides
 is  also possible.

           It  is apparent that C02 obtained from the acid gas treatment
 facility may  contain sulfur,  as well  as  small quantities of CO and
 hydrocarbons.  The  form  and quantity  of  sulfur in this  gas  will depend
 on  the sulfur recovery process employed.  At Bruceton,  from the output
 of  a Stretford sulfur recovery unit,  H2S content  of separated  C02 is  indi-
 cated to be  less  than 5  ppm.  In the Bureau of Mines prototype  pilot plant,
 this gas,  including  the  lock hopper.vent stream,  will be incinerated in a
 thermal oxidizer  before  being discharged to the atmosphere. This-procedure
-may be directly applicable to the commercial design,  i.e.,  off-gas  from
'ThI sulfur recovery  unit,  including  lock hopper vent  gas, may  be sent
 to  the uSlIty boiler where sulfur would be oxidized  to S02 and the
 stream would otherwise dilute flue gases from fuel combustion.

           We have assumed an alternative to continuous  atmospheric  vent-
  ing which involves  containment of lock hopper vent gas, as in gas  holders
  from which  it could be.recompressed, limiting the requirement for  fresh
  make-up gas to the losses (largely back into the system)  from the  coal
  feed system.  In this arrangement,   it will probably be necessary to
  treat or filter gas entering the holder to remove dust.

            It  is thus indicated  that the  only material  which  may be
  discharged  from the  coal  feed system will  be C02, which gas  would
  otherwise have been so discharged from the  sulfur recovery unit.  The
  rate at  which such C02 will be  discharged will  depend  on  the  degree to
  which  gas is  recycled  in  the  feed system,  but the system  may  obviously
  be  arranged such that  no  gas  is discharged  to the atmosphere  at this  point.
         \
       2.3.2   Char Letdown

           Ash  must  be removed  from the  Synthane  gasifier,  as  in most
  gasification processes, in a more or less continuous fashion,  to main-
  tain  carbon  concentrations in  the gasification zone sufficiently high
  for desired  reactions to  proceed.  Experimental  work indicates incentive
  for limiting the degree of carbon gasification,  and a proposed feature
  of  the Synthane process involves setting  the carbon content of the ash
  (char)  removed from the gasifier such that  combustion of the  char  will
  balance the  total steam and  energy requirements  for the process.

           The high  operating pressure of  the Synthane  gasifier imposes
  special problems on the system used  to  extract char.   At the  point of

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                                   - 17 -
 discharge from the gasifier bed, char is indicated to be at temperatures
 in excess of 1700°F.

           The char in this design represents a significant  sensible heat
 discharge from the gasifier.   Trom thermal  and process  points  of view,
 perhaps the  ideal system would transfer  hot char directly to  the boiler
 in which it  is to be combusted along with any associated gas,  preserving
 most  of this heat and avoiding use of cooling media,  water  or  steam,
 that  would require additional  energy to  subsequently  separate  or treat.
 The mechanical design of a throttling arrangement that  would  permit such
 operation, however,  will require substantial development.

           Consideration of a variety of  alternatives  led the  designers
 of the  large pilot plant (9) to a system wherein char is cooled in
 situ  prior to the point at which it must be passed through  valves.   Hoc
 char  is caused to flow into a  separate fluidized bed  cooler by regulating
 the pressure differential between the gasifier bed and  the  cooler.   Steam
 is used to fluidize  the bed, and water is injected into the system for
 cooling.   High-pressure steam  is generated  in the cooler, and  this
 steam may be used in  the process (specifically in the carbon monoxide
 shift converter)  after it has  been  filtered to remove char  fines.   The
 designers point out  that this  steam might be directed to the gasifier
 in its  contaminated  state if the gasifier distributor were  designed to
 introduce contaminated steam and oxygen  separately.

           Cooled  char  may be fluidized out  of  the cooler bed into  lock
 hoppers, avoiding throttling valves, or may  be passed  from the bottom of the
cooler bed through valves into  lock hoppers.  Agglomerates which may come  from
 the gasifier  could present  problems  with  either  method  of cooler operation.

          The preferred  alternative  is a  "dry" system,  in which a  filled
 char  lock  hopper  is isolated with valves which are arranged to be blown
 clean before  closing.  Steam is  vented to atmosphere via filters arranged
within  the lock hopper, ahead of the pressure-reducing valves.  Char flows
 out of  the bottom of the  lock hopper into a  conveying line  in which steam is
 used as  transport medium.   The  empty lock hopper  is repressurized with
 steam before  being put  on  line  to again  receive  char.

          A  second alternative  directs a  char/steam mix  from the cooler
 through a  slide valve  into  a char slurry  quench  tank, where water  sprays
 cool the  char and a slurry  is  formed.  The  quench  tank  is vented to the
 char cooler.   Char slurry  is depressured  through  orifice/valve arrangements,
 the char  slurry is filtered to  recover water,  and water  is  recycled to the
 slurry  quench tank through  coolers.  The  char  filter  cake is estimated to
 contain 40-50 per cent water in  this case.

          Gas from the gasifier will be carried  into  the char cooler
along with char.  It is presumed that most  of  this gas will issue from
the char cooler along with  the  generated  steam and be directed back into
 the main gasification stream,  either directly  into the gasifiers or at

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                                  - 18 -
the shift converters.   It is not possible to estimate the degree of gas
contamination that may persist through the char depressurizing system
into the steam which is indicated to be vented ultimately from a  dry
char" process.  Some 3000 pounds per hour of steam is estimated to be
so vented if this scheme be applied to the Bureau of Mines design.  Depend-
ing on its composition, some of this vent steam may be employed in the
scrubber water treating system, or may serve to transport char to the
utility boiler, in an integrated commercial plant.  Although there       ^
would probably be least atmospheric pollution associated with a  wet char
or slurry letdown system, the water pollution generated and the energy
associated with water treatment and wet char combustion would indicate
that the slurry technique would be used only if an operable dry char
arrangement cannot be developed.

          To summarize, the design basis  (10) does not specify the method
by which char will be removed from the gasifiers, except to provide-
lock hoppers to receive char.  The lock hopper volume provided is not
consistent with estimates of char density, so that lock hopper cycle rate
may be higher  than indicated.

          With the preferred  dry  char  process, we have assumed  that  about
 100,000  pounds per hour of  high pressure  steam will  be generated  by  direct
water  injection  in  the  char cooler,  and  that  this  steam,  along  with  as-
 sociated gasifier gas,  will be  reintroduced into the process  at  the  shift
 converters.   Some 3000  to 6000  pounds  per hour  of  steam  is  estimated to  be
 vented from the  lock  hoppers, depending on cycle  rate.,  "Dry"  char is as-
 sumed  to be  conveyed  to the utility boiler  using a  steam transport, system.
 Net  atmospheric  pollution associated with char  let-down  is  therefore as-
 sumed  :ninor.

2.4  Dust Removal

          Raw gas issuing from the gasifiers must be  treated  to remove
particulates and  condensable matter that  may interfere with subsequent
gas processing.   The precise nature of materials which must be separated
from raw gas at this point  is not known,  except  that  coal or  char  fines
and coal-tars  or  oils are assumed to be present.

          In  the  design basis,  gas  from the gasifiers passes  firstly
through  cyclones, where heavier particles (char) are  removed, and  then the
gas is subjected  to cold-water  scrubbing  (see Figure  3)„  Scrubber liquor
effluent  is depressured into  decanters, where tar separation  occurs, and
water  is recirculated to  the  scrubbers through water-cooled heat  exchangers
by high-pressure  pumps,   This design does not further detail  the  operation,
or provide for further  handling of  separated products or  of scrubber
liquid.

          This gas clean-up process has not been experimentally  demons trate'd.
Laboratory procedure  (17) at  the  Bruceton laboratories of the Pittsburgh
Energy Research Center  (PERC) has generally involved  passage  of  gasifier
effluent  through  dust filters and a  series  of water-cooled  condensers,
wherein  dusts, tars,  and  water  are  condensed  from gas prior  to  pressure
reduction.

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                        FIGURE 3
                DESIGN BASIS DUST REMOVAL (10)
Coal
                                750°F
593.75 tph

Steam

1, 169,700 Ib/hr

Oxygen ^
152 tph
{
t
( \C

A F
S
k l )
\ F /
I
E -
R
7


1 '
)85 (C}
==> Y
L
O
]
V


1,700°F
Char
181.1 tph |'
{
^
f






x^?^5^
/^V.


==£>
C
R
U
B
B
E
VjL^



r^
-f _
27 ^° T^1 "^

977 psig

Char

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                                  -  20  -
           Prior  art would  indicate  that  the gas clean-up procedure
 outlined  in  the Synthane design will require substantial development from
 both  process and pollution view-points.  As proposed, the operation is
 a  significant energy  and cooling water consumer.  The physical operation
 of "dry"  cyclones is  by no means  assured in this  system.

           Provision has not been made to contain  and recover gas which
 will  be carried  out of  the scrubbers by  the scrub liquor, and which will
 separate  from the liquor as this stream  is depressured in the decanters.
 The implied  method of operation of  the decanters  would almost certainly
 lead  to emulsion formation in these vessels.  And the distribution of
 solid and liquid phases in these vessels otherwise  is impossible to
 assess.   It  is further  not clear whether water scrubbing alone will
 suffice to clean gas  of all material which may affect downstream pro-
 cessing.

           The designers of the prototype pilot plant have accordingly pro-
 vided a  flexible system (18) which  addresses  many of these  questions in
 a  manner  by  which it  is hoped to obtain  the experimental data required
 to design a  commercial  plant(see Figure  4).   In the pilot plant, gas from
 the gasifier passes firstly through a venturi water scrubber where bulk
 cooling occurs.   Venturi scrubber effluent is directed into a baffled
 high-pressure surge tank where gross separation of  particulates takes
 place.  The  same surge  tank is arranged  to serve  as reservoir for a
 separate  high-pressure  scrubber tower.   Low-pressure steam may be
 generated in the process of cooling recycled  effluents to the venturi
 scrubber  and to  the scrubber tower  from  the surge tank.  The scrubber
 tower is  arranged so  that  water and/or oil may be used as scrubbing
 media.  Effluent from the  high-pressure  surge tank  is depressured into
 a  low-pressure decanter, where final phase separation occurs.

          This system resembles  the  processing sequence  employed by  Lurgi
and others in  low-temperature  coal carbonization plants  constructed  in
Germany prior  to and  during World War II.  The Lurgi-Spulgas installation
at Offleben  (49)  utilized a waterspray and rotating screen to first  remove
dust and heavy tar from gases  leaving the carbonizing ovens.  Light  tars
and "middle  oil" were condensed in sequence,  and  the removal of condensable
material was  completed in mechanised wash-oil scrubbers which recovered
"benzine".

         This  same gas-treating sequence was  adapted to the Lurgi-pressure
coal  gasification  process (24).  Both hand-operated scrapers and water
sprays were  required  to maintain offtake passages through which gasifier
gas issued (at 575°F  and 20 atm.) into a water spray cooler.  Heavy tar
which  condensed  was discharged through a trap, and water was recirculated
 to the sprays  through external coolers.  The  gas  stream exited the cooler
at about  300°F .   Operation of the spray  cooler is however indicated to
 have  been  troublesome due  to tar-water emulsification, and the spray coolers
at Bohlen, for example, had undergone four or five dasign revisions (24).

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                  FIGURE 4
       RAW PRODUCT GAS SCRUBBING ( 9 )
Venturi
Scrubber
                                       To Shift
                                       Converter
                    Oil Wash
                                                                    ro
                                                                    f
                                                                     i
                                                     I—£>  Waste
                                                            Water
                                            Tar

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                                    - 22 -
          Lurgi designs (23,24,50,61)  place  the  direct-contact water  quench
 cooler immediately on the gasifier vessel,  minimizing  the  potential  for
.deposition in the gas off-takes.   It  is  apparently  not  practicable to
 extract high-level energy from this gas  quenching process.

          We believe it may be possible  to adapt  a"tar-scrubber"  of the type
 developed for petroleum fluid coking  reactors  (46,62)  to  the Synthane
 coal gasifier to avoid the mechanical problems associated  with tar and
 solids deposition in the gas  outlets. Moreover,  it  should  be possible
 to extract high-level energy  from the process.   The  configuration for
 this arrangement is shown in  Figure 5.

          In the  fluid coker,  the  scrubber vessel  is  integral with the coker
 reactor.   The cyclone is internal to  the reactor, with  its  outlet gas
 discharge  into the scrubber.   Heavy tar  condensed from  the  gas stream
 in the scrubber  is pumped through external  exchangers,  where high-pressure
 steam is  generated.   The cooled tar stream  separates, with  the portion
not  used  for  scrubbing being  returned to the coker feed line.  It is of
 course necessary to control temperature  of  the tar pool in  the bottom
 of  the scrubber  vessel and  tar velocities in the external circuit to pre-
vent  coking and  solids  deposition.

         In the  Synthane  design,  gasifier outlet temperature is estimated
to be  800-1400°F.   A  steam  dew-point  of  about 440°F  is estimated for the
raw  gas conditions.   It  is further  estimated that up to 70 percent of the
heavy  tar  in  the  gas  stream may be  condensed by operation of the tar
Scrubber at about  560°F  (63),  or  sufficiently high in temperature to
permit  generation  of  1009 psia steam  in  the external circuit.  It is
estimated  that about  365,000 pounds per  hour of 1000 psia  steam could be
generated  in  this  manner, assuming gasifier output to be at 1000°F.


         Removal of the bulk of the heavy tar in the gas stream at this
point should greatly  reduce the emulsification problem as  water is con-
densed from the gas downstream.  Similarly,  the tar  scrubber would
serve to remove a major fraction of the   char, ash, and coal fines contained
in this gas, so that  loads on  the  downstream tar-oil separation and water
treatment systems  should be reduced significantly.

         From a thermal point  of view, it would be desirable to return
the separated tar stream to the gasifier, as is  done in the petroleum
coker.  But if this is found to adversely affect  gasification,  such
separated tar could instead be directed  to the char  utility boiler (see
Section 3.3.1) or may be further processed for sale.

         It is recognized that the mechanical arrangement  at the  coal
gasifier reactor head is more  complex  than is the case  for a petroleum
coker, in that the coal feeding arrangement  must  be  accommodated.  It
should be possible, '-owe--er,  to offset line coal  feed svstom.

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                               - 23 -
                             FIGURE 5


                 TAR SCRUBBER SHOWN INTEGRAL WITH

                           GASIFIER REACTOR
   Tar
To Process
or Storage
                                                         Scrubbed Gas

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                                 - 24 -
         It would also be possible to design a single combined scrubber-
fractionater tower which would separate tar, oil,  and naphtha in sequence
up the column.  Economies effected in scrubber-fractionator vessel costs
must, however, be balanced against the added structional costs associated
with the placement of a tall structure oa top of the gasifier.  Hence
a succession of scrubbers, similar to the tar scrubber,  but operating at
successively lower temperatures, and generating steam at successively
lower pressures, might be used to clean gas ahead of the shift converters.
What must yet be defined, however, is the limiting temperature of gas
at the outlet of such a scrubber train, or the limiting contaminant levels
in gas that will not interfere with the shift conversion.  The Wes'tfield
Lurgi plant (23) was able to operate its shift reactors satisfactorily
(at 350 psig) on gas which had been cooled to 310°F.

           To the extent  that water vapor need not be condensed from
 gasifier effluent or  that gas  be cooled below about 800°F in the process
 of  cleaning gas, there  is net  thermodynamic advantage  to the process,
 since both additional heat and water  (supplied as high-pressure steam)
 are otherwise  required  in the  succeeding shift conversion reactors.
 Hence an ideal system would remove contaminants in gas only by cooling
 to  about 800° F, generating steam in the process.   Alternatively, shift
 conversion catalysts  and procedures might be developed to tolerate^
 carbon-containing contaminants still  present in gas from such "dry"
 cleaning process.   Gross contaminant  removal would  then follow shift
 conversion, at which  point the total  product gas  stream must be  cooled
 to  effect acid gas  removal in  any  case.

           Even if a more nearly  ideal system is not developed, the
 commercial  design will  almost  certainly include heat recovery  facilities
 at  this point.   Energy  recovery  in  the depressurizing  step  may also be
 practical,  as  by use  of turboexpanders on  gas, or hydraulic turbines  or
 flow-work  exchangers  (19)  on liquids.

            In  this  design, we have assumed that scrubbing will be used
 following the  tar scrubber, but that gas which separates from the scrubber
 ^fluent! on depressuring will be recompressed back into the main gas stream
 at  a point following  shift conversion. Additional tar and hydrocarbons wVnch
 condense along with water from the  gas stream as  the stream temperature  is
 lowered may be directed to finishing facilities to be  processed for sale  or
 could be burned in the utility boiler. Either or both water and light hydro-
 carbon might be recirculated to scrub the  gas stream  and  steam could be
 generated in the process of cooling the circulated fluids.  Alternatively
 at soTie point, gas would be sufficiently clean to permit direct operation
 In aTonventiona8! waste  heat boiler.  On the assu,P"- th-t gj. tejperature
 is reduced to about 300°F to effect clean-up, some 300,000 to 400,003
 pounds per hour of  low-pressure steam may be generated in the scrubbers.

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                                 - 25 -


           The degree of saturation of scrubber effluent with respect  to
any given gas component will depend on operating parameters  that  have  yet
to be defined.  Methane, hydrogen, tkS, and carbon monoxide  evolutions
from water at indicated conditions and rates could each amount to 400-
1000 scfm,  for example.  C02 evolution might be twenty times as much,  so
that the total gas stream could amount to 20-30,000 scfm, or to 30-40  MM
scfd.  Gas may also be physically entrained out of the scrubbers  in the
liquid effluent streams.

          Hence,  although there may be mechanical and  corrosion problems
associated with design of a suitable gas/liquor separator and with com-  •
pression of separated gas, the net effect should be that no  gas issues
to atmosphere in the dust removal process.

2.5  Shift Conversion

          Scrubbed raw gas from the dust removal process is  separated
into two equal streams, one of which by-passes the shift converters,
since only half of the total stream must be shifted to adjust the total
H2=CO ratio to 3:1 for purposes of methanation.  In this design,  a
significant quantity of high-pressure steam must be introduced to the
catalytic shift converters to achieve desired equilibrium, however.

          The shift conversion is a totally-contained procedure,  so
that no effluents issue to atmosphere.

2.6  Waste Heat Recovery

          The raw gas streams which are  split ahead of  shift  conversion
are  recombined following  the converters, and are cooled  from  an average
temperature of about 500°F to  300°F ahead  of the gas purification system.
Low-pressure  steam  is generated,  and  there  are no  effluents  to atmosphere.

2 .7  Light Hydrocarbonjtemoval

         We have  considered that  it may  be  desirable to  treat  the com-
bined gas  stream at this  point to remove condensable hydrocarbons to  minimize
contamination of  the Benfield  system.  It  may however prove  practicable
to defer such treatment until acid  gas has  been  removed, an alternative
which may  be  thermally  preferable  if  the main gas  stream is  to be cooled
to a low temperature after acid  gas removal.  A  number  of considerations
are  involved, including the ultimate  disposition for hydrocarbons which
are  separated (whether  processed  for  sale  or consumed as fuel), the effect
of hydrocarbon contamination  on  the method by which the  acid  gas  stream
is treated,  including the  desulfurized residual, as well as  the direct
effect  on  the Benfield  system.  There will  be considerable  relevant cotn-
mercial experience with the Benfield  acid  gas removal system  to enable
a designer to assess the  direct effect by  the time more  precise values
for  the gas composition become available.

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                                   - 26 -
         For our design,  we have assumed that the gas  stream may be  cooled
in water exchangers to about 90°F after it has been used to  reboil  the
Benfield regenerator and  passed through light oil scrubbers  to remove B-T-X
components.  The scrubbing fluid would be available from the upstream
hydrocarbon separators.  Gas which separates on depressurizing this  scrubber
effluent could be recycled to the vapor space of the upstream separators
for recompression into the main gas stream.  Downstream distillation facili-
ties would be required to separate naphtha if it were  to be  sold.  It is
estimated that 20,000-25,000 GPD of B-T-X coald be so  separated, requiring
an estimated equivalent of 25,000 pounds per hour of low-pressure steam.

         Part of the heat removed in the cooling process could be returned
to the gas stream after  scrubbing by exchange with the heated water leav-
ing the coolers, so that  the net thermal loss might be held  to the  equiva-
lent of about 60,000 pounds per hour of low-pressure steam.   About  18,000
pounds per hour of water  would be condensed from .the gas stream on cooling,
and this (equivalent) water would have to be reintroduced oa reheating  the
gas to avoid depletion of the Benfield solution.  This might best be
accomplished by direct introduction of high-pressure steam,  rather  than by
reintroduction of the contaminated separated water, which would be  directed
to the waste water treatment facility.

 2.8  Gas Purification

           The gas purification or acid gas removal process  which is used
 is the "Benfield" hot potassium carbonate system developed by the Bureau
 of Mines  (20;21,22).  This method of removing C02 and H2S from the pro-
 duced gas is indicated to have substantial thermal advantage over amine
 systems at the high process pressure employed.

           In the Benfield system, gas absorption takes place in a con-
 centrated aqueous solution of potassium carbonate which is maintained
 at above  the atmospheric boiling point of the solution  (225°-240°F) in
 the high-pressure absorber.  The high solution temperature permits high
 concentrations of carbonate  (alkalinity)  to exist without incurring
 precipitation of bicarbonate according to:

                     K2C03 + C02 + H20  	*>  2KHC03


 Partial regeneration of  the rich carbonate solution is effected by
 flashing as the solution is depressured into the regenerators.   In this
 design, sensible heat of the main gas stream is used  to reboil the
 regenerators, so that the gas is cooled to about 260°F in the process.
 The gas is further cooled in cold-water exchangers to about 225° F before
 entering the absorbers(but see Section 2.7 above).

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                                   - 27 -
            It  is nececsary  in  this  design  to  admit additional  low-pressure
  steam  into the regenerators to  complete the  regeneration process  and  to
  balance heat  and water  requirements.   Regenerated solution  is pumped  back
  through the absorbers.   The main process  gas stream exits the absorbers
  at  230 T,  and is cooled by cold-water  exchange  to about 100°P before
  undergoing residual  sulfur cleanup.  Stripped acid-gas flows  to the sul-
  fur recovery  plant.

            Most of the reported  experimental  work related to this  process
  was performed at a total absorber  pressure of 300 psig (22) on clean  eas
  mixtures.  There is  therefore some degree of speculation regarding
  extrapolation to the gas mix and high  operating pressure of the Synthane
  process.   At  least one  successful  commercial application of this  process
  in  a Lurgi gasification plant has been reported (23).  In this case,
  absorption takes place  at  about 284 psig.  Peed gas contains about
  36  volume  per cent C02  and about 300 grains  H2S/100 ft3.   C02 concentra-
  tions in outlet gas  is  two percent and H2S concentration is about five
  grains/100 ftj.   Corrosion problems have been encountered with the
  liquor circulating pumps in this system, but inhibiting additives have
  apparently been partially successful in this regard.

           The Bureau's  own work indicates that methane and CO are about
 one-fifth as soluble in concentrated K2C03 solution as they are in water
 at comparable partial pressures and temperatures,  and that hydrogen is
 about  one-third  as  soluble in carbonate (22).  The loss of product gas
 into the  acid gas  stream is a consideration in any acid gas removal
 process.    For this  design it  is estimated at about 0.5 per cent of the
 plant  output,  assuming saturation of the absorber  liquor.

           The  combination of  high-pressure absorption and  low-pressure
 regeneration is  a suitable case for consideration  of  mechanical energy
 recovery.   Comments  relative  to energy  recovery  at the dust  removal
 step (see  above) are  also pertinent here.   Incentives  for  development
 of such systems escalate with  plant size.   The economic balance  in any
 such attempted improvement  must  include factors  related to  development
 costs and  added process  complexity  and  operating hazards,  as well  as
 the  first  cost of required  hardware.

           There should be no discharge  to  the atmosphere from  the  gas
 purification plant.


2.9  Residual  Sulfur Cleanup

          Methanation catalysts are adversely sensitive to very small
quantities of  sulfur in  feed gas.  The Benfield system is reported to
be capable of  operation  such that sulfur present in process gas as hydrogen
sulfide and carbonyl sulfide may be virtually completely removed.  Less
is known about the other forms of organic sulfur which may be present  in
process gas, especially  thiophenes.

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                                   -  28  -
           This design incorporates a sequence of iron oxide and char
 towers for residual sulfur cleanup ahead of the methanation reactors.
 There is a long history of the use of such materials to clean synthesis
 gas (24,25,26).  It is estimated that total sulfur in gas may be reduced
 to less than 0.1 grain/100 ft3 in this arrangement.

           There is, however, no clear basis for estimating the life of
 these beds, and hence no indication of whether the intent is to dispose
 of spent material or attempt regeneration.  The designers of the proto-
 type plant have elected to reverse the order of treatment, placing
 the activated carbon bed ahead of the sponge iron tower.  In this case,
 activated carbon is meant to be regenerated regularly with steam, and
.sponge iron discarded when spent.  Reported experience (24)  indicates
 that temperature rise may be excessive in an activated carbon bed if
. H2S content of feed gas exceeds about 650 ppm>  as may occur  in this
 :case with an upset in the Benfield system.  It is also reported
 that gum formers, dienes, indene, and styrene,  if present, may inter-
 fere with recovery of H2S on carbon.   The steam stream used  to regenerate
 the  carbon bed  may  be  directed back to the  Benfield  regenerator,  or,  if
 contaminants  are  troublesome",  could" be directed to  the  utility boiler  for
 disposal.   Some provision will have to be made  to permit  change-out  of  the
 beds in this  section.   Hence,  the high-pressure gas in the beds will have
 to be vented, and the beds  will have  to be inerted  before being opened.
 It is assumed that  the vented  high-pressure gas will be directed to  the
 utility boiler.  Steam,  which  may be  used for inerting, may  be directed
 back to the Benfield regenerator.

           Steaming, or other inerting, will  also  be  required to  purge
 the  bed  of  oxygen when a  new bed  is to be put on  line.   It is  assumed
 then that  the only  discharge to atmosphere  from this section will  be
 such inerting medium,  and,  further, that  the quantity of  this  gas  will
 be very  small.

 2.10 Methanation

           The Bureau  of  Mines  has developed two methanation  processes
 for application in the Synthane system,  (6, 7,  27)  and both  will be
 tested in the prototype  pilot  plant being constructed at  Bruceton.

           This  design incorporates  the Tube Wall  Reactor  or TWR  process,
 in which the  methanation  reactor  is constructed in  the  form  of a
 heat exchanger.   Reaction occurs  on a  Raney  nickel  catalyst  coating
 applied  to the  exterior  of  the exchanger tubes, and  Dowtherm  is vaporized
 through  the tubes to  remove reaction  heat.   High-pressure steam is
 generated in  a  separate  boiler in the process of condensing  and cooling
 the  Dowtherm heat exchange  fluid, which is then recycled to  the
 methanator.

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                                  -  29  -
           The Bureau has developed techniques for coating the inside of
 tubes with catalyst, an arrangement which may be more amenable to scale-
 up,  simplifying catalyst replacement.   At this point, the expected life
 of catalyst in this system is not known.   Most of the experimental data
 reported (8)  was obtained at 300 psig, so that additional development is
 required to redefine the process at Synthane process pressure (V)30 psig).
 Catalyst life targets early on in the  development were set at 2000 hours.

           The Hot Gas Recycle or HGR methanation process also uses Raney
 nickel as a catalyst, but the catalyst in this case is deposited on an
 element consisting of closely-spaced parallel plates installed in a
 high-pressure shell.  The Dowtherm, or separate heat-exchange fluid, is
 avoided in this system by employing the process gas at very high recycle
 rates through the methanator to limit  temperature rise.  The physical
 configuration of the methanation reactors is considered more suitable for
 commercial scale-up in this arrangement,  but the process carries energy
 debits relative to TWR methanation, and the design of compressors for gas
 in this pressure-temperature regime will  require development.

           When on-line, there should normally be no atmospheric discharge
 from the methanation section.  As in the  case of the fixed-bed sulfur
 clean-up facilities discussed above, however, provision must be made for
 taking methanation reactors out of service for catalyst replacement.
 Hence, the reactor must first be vented of high-pressure gas.  Depending
 on the size of plant and the frequency of change-outs, it may prove
 desirable to  provide facilities for recompression of this gas back into
 the  product gas stream.  Alternatively; the vented gas could be directed
 to the utility boiler.   Inerting of these vessels prior to opening them
might  best  be  performed with  nitrogen  (supplied  from the  oxygen  plant),
and,  in  this  case,  the  inerting  effluent  stream  would be  directed  to
the boiler.

           If  Raney nickel is  employed  as  catalyst,  it is presumed that
facilities  for activating the catalyst, if not,  in fact,  for complete
removal  and replacement of catalyst on supporting surfaces,  will be pro-
vided  on-site.   Hence,  when a tube bundle of the TWR process, or a
catalyst  element  in the HGR system,  has been readied for reactivation,
a  dilute  sodium hydroxide (^2 per cent by weight)  solution is passed
over  the  element,  and the temperature  is  raised  to  about 95°C.   Hydrogen
is evolved  in  this  process, and  this stream might  be handled in the same
way as high-pressure  vent gas.   The  catalyst element must then be  washed
free of caustic,  using  quite  pure (distilled)  water.   Finally,  the catalyst
system is dried and  its temperature  raised by circulating hot,  oxygen-free
gas, such as nitrogen.   It  is assumed,  then,  that  only this  last (wet)
nitrogen  stream may  be  discharged to the  atmosphere  from  the methanation
section.

          Of course, if on-site facilities are additionally provided
to remove spent catalyst  from supporting  surfaces and  to  re-apply new

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                                  - 30 -
 catalyst,  then suitable arrangements must be provided  to  contain metal
 dusts that may be generated in preparing the surfaces  for recoating,
 applying bonding agents (nickel aluminide),  and flame  spraying  of
 new catalyst.

 2.11  Unal Methanation

           The  design basis does not include  specific equipment  for
 limiting CO content of product gas  issuing from methanation.  Depending
 on the ultimate use of product, CO  content may be  required to be held
 to less than 0.1 volume per cent.

           As indicated above,  the methanation process  which will be
 ultimately commercialized  has  not yet been defined.  However, the
 experimental data reported to  date  would indicate  that a  final  treat
 will be required to limit  CO content in  methanator effluent to  specifica-
 tion.   In  a commercial plant,  some  arrangement,  possibly  involving
 standby methanators,  would probably be required in any event to handle
 sudden loss of activity or other malfunction in the  process train at
 this point.

           In the prototype pilot plant,  based on Bureau of Mines experiments,
 the designers  have included fixed bed reactors containing pelletized
 methanation catalysts (nickel  oxides on  aluminates)  to reduce CO content
 to specification.   Although this procedure may be  amenable to scaleup,
 an integrated  method  for adjusting  temperature of  feed gas, and con-
 trolling temperature  within the beds,  must be developed.   Procedures for
 changing out such  beds,  following along  lines discussed above,  should
 result  in  only small  discharges of  inerting  gas  to atmosphere.

           In our design, we  have assumed  that  specification CO  levels
will be  achieved  in the methanation  plant  proper.

2.12  Final  Compression

          Pressure drop through  the Synthane   train is indicated  to
amount to about 65 psi.  Gas leaving the methanation plant is  cooled
tc 100°F to  remove water, and  is then compressed to 1000 psig,  the
design product  delivery pressure.

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                                -  31  -
               3.   EFFLUENTS TO AIR - AUXILIARY FACILITIES


          We have elected in this study to treat the main gasification
stream separately from all other facilities, which are thereby defined
as auxiliary facilities.  The functions of these auxiliary facilities
are nonetheless required by the process, and, for economic   and/or
ecologic reasons, would be constructed along with the gasification
system in an integrated plant.  These effluent streams are also shown in
Figure 2, and streams are identified in Table 1.

3.1  Oxygen Plant

          The oxygen plant provides a total of  3650 tons per day of
oxygen.  The only effluents to the air from this facility should be the
components of air, principally nitrogen.  About 330 MM scfd of nitrogen
will be  separated.  Some of this nitrogen may be used to  advantage in
the plant to inert vessels  or conveyances,  to  serve as transport medium
for combustible powders or  dusts,  as an  inert  stripping  agent  in
regeneration or  distillation,  or to  dilute  other effluent gas  streams.
It will  be possible to  generate about 900 KW of electricity by recovering
the compression  energy  of the  nitrogen through  turbo-expanders.

          About 425 MM scfd of air is taken into the oxygen facility.
Placement of the oxygen facility will depend in part on  the desire to
maintain the quality of the air drawn into the system and, especially,
 to minimize interference from plant effluents.

 3.2  Sulfur Plant

           The type of plant used for removal of E2S from the acid Sas
 overhead from the Benfield regenerators has not been specified in this
 design.  Originally,  sulfur removal was to have been accomplished by
 means of a direct oxidation Claus unit incorporating a tail-gas scrubber
 using lime or soda ash  (18).  However, the performance of the Claus
 system with the relatively low H2S concentration in the feed gas  (about P.-J
 weight per cent) could not be guaranteed.  Moreover, the desire to
use sulfur-free C02  from the  sulfur plant to pressurize  the coal  feed
lock  hoppers (see  Section 2.3.1) required that  residual  t^S  in such  gas be
considerably below the  level  that  might  be  achieved by the  Claus system.
Hence,  use  of  the  Stretford process  has  been  assumed  for  sulfur removal
 (28).

           In the Stretford process,  sour gas is washed with an aqueous
 solution containing  sodium carbonate,  sodium vanadate, anthraquinone
disulfonic  acid, and  a trace  of chelated iron.   The solution reaches an
equilibrium with respect to C02,  such that only small amounts of  C02
are removed from the  gas undergoing treatment.

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                                 - 32 -
          In this system, H2S dissolves in the alkaline solution, and
may be removed to any desired level.  The hydrosulfide formed reacts
with the 5-vale.nt state vanadium, and is oxidized to elemental sulfur.
The wash liquor is regenerated by air blowing, wherein reduced
vanadium is restored to the 5-valent state via an oxygen transfer
involving the ADA.  The sulfur is removed by froth flotation and
filtration or centrifugation.  The process may be effectively operated
at any pressure up to 1000 psig  (29, 30).

          The fate of carbonyl sulfide and other organic sulfur com-
pounds which may be contained in the main product gas stream is not now
clearly understood.  Hence, although it has been indicated that COS is
removed from gas by the Benfield system, it is not certain whether and
to what degree COS and other sulfur compounds may appear in the acid
gas overhead from the regenerators.  The Stretford system is indicated
to be only partially useful for the removal of organic sulfur compounds.
Hence the preferred treatment route for acid gas must await more
definitive information related to operation of the Benfield system at
high pressure, and especially to Synthane gasification of high sulfur
coals.

          It should also be noted that the developers of the Stretford
system have disclosed  (31, 32) processes which convert organic sulfur
compounds in hydrocarbon streams to I^S, as by treatment with steam
over U30s - containing catalyst, which I^S may then be removed in a
Stretford system.  As has been indicated elsewhere, the technology of
sulfur removal is advancing rapidly, so that it may be expected that  im-
proved procedures will have been demonstrated by the time coal gasification
finds much commercial application.

          About 210-220 MM scfd of C02 containing less than 5 ppm H2S
will be separated at the sulfur plant.  Depending on the relative
economics, the I^S content of this stream may be reduced to less than
1 ppm in the Stretford system prior to discharge to the atmosphere.   We
have assumed that the stream will instead be directed to the utility boiler
to undergo incineration and treatment along with flue gas.

          The air stream used for regenerating Stretford solution is
another effluent to the atmosphere from the sulfur plant.   This stream
is estimated to amount to some 5 MM scfd.  This stream is  also directed
to a boiler firebox.

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                                    -  33  -


  3.3  Utilities

      3.3.1  Power and  Steam Generation

           The choice of fuel for the generation of the auxiliary electric
  power and steam required by coal gasification plants markedly affects
  the overall process thermal efficiency.  It is generally least efficient
  to burn  the clean product gas for  this  purpose.  On the other hand,
  investment in power-plant facilities, including those required to handle
  the fuel and to treat  the flue gas, is  generally least when product gas
  is so used.

           Synthane gasification is one  of the class of coal gasification
  processes which generate a carbon-containing char.  Research to date
  would indicate that it is not desirable to gasify more than about 90%
  of the carbon in feed  coal, and that it may be preferable to limit
  gasification to about  60-70 per cent of carbon for most feeds.  A
  particular feature of the Synthane process design, therefore,  is  that
  the carbon content of char leaving the gasifier may be adjusted such
  that the subsequent combustion of the char will balance the power and
  steam requirements for the system.

          Char generated by the Synthane process is a  much more refractory
material than feed coal, and generally contains a significant fraction
of the sulfur in the original feed(ll).   Composition of the char produced
by the present design is not specified.   Several analyses for char generated
from the pilot gasification of a Pittsburgh seam coal  have been reported:
                                Table 2

                    CHARS FROM SYNTHANE GASIFICATION
                 OF PITTSBURGH SEAM GOALS (WT- PERCENT)

                       No.  1  (33)            No.  2  (47)
                                          Feed Coal
Feed Coal
Carbon
Hydrogen
Oxygen
Sulfur
Nitrogen
Ash
Volatile Matter
75.7
5.3
8.3
1.6
1.5
7.6
_
Char
71. A
0.9
1.8
1.5
0.5
23.9
—

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                                   - 34 -
          It is otherwise indicated, however, that the composition of the
char generated may be quite variable, depending on the feed coal and on
the operation of the gasifiers (11), so that the combustion properties of
char may  likewise vary.

           Experience with the large-scale combustion of char is so far
limited.  The Bureau of Mines has reported on one  investigation (34)
utilizing a specially-constructed dry bottom unit designed to simulate
the performance of an industrial steam-generating furnace.  In general, it
was found that volatile matter content in excess of 20 per cent was necessary
for combustion of chars in this apparatus in the absence of a more volatile
supplemental fuel (natural gas was used as supplemental fuel).  Carbon
combustion efficiency was likewise found to be a function of the volatile
matter content of char, ranging from 94 to 99 per cent for volatile contents
from 5 to 15 per cent.  More supplemental fuel was required for the least
volatile  chars to maintain flame stability.

          Hence, it may be assumed  that combustion of Synthane chars will
be possible in conventional fireboxes if product gas is used as supple-
mental fuel.  This alternative might be preferred then on the basis of
carrying  the least developmental debits, and because it should be
possible  to adjust S02 concentration in flue gas from most chars such
that subsequent flue gas  treatment may be avoided.  It has the disadvantage
of adversely affecting overall thermal efficiency.

          A large number  of power plant fuel alternatives involving
combinations or separate  use of feed coal, char, tar, raw gas, or
product gas are open to the Synthane plant designer.  It would appear
that conservation would dictate that carbon contained in generated
char should be recovered, as by use of char as fuel.  But an alternative
that may  be available would be to gasify Synthane char in a Koppers-
Totzek gasifier (14) or its equivalent, producing a low=Btu clean gas, which
may then  be consumed separately or in combination with one or more of
the other available fuels to produce power.  Since all auxiliary facilities
will have been otherwise  provided for the Synthane plant, the addition
of gasifier(s) for char may be a preferred alternative should char com-
bustion boiler development show particular problems, as with fouling,
corrosion, stability, or  sulfur removal.

          For this  design, we  have assumed that  equipment  will be  developed
to combust char alone with essentially complete carbon utilization.  This
may be possible,  for example,  in a fluidized bed boiler and, especially,
in a fluidized bed system which incorporates combustion in the presence
of limestone to remove sulfur (35).  Otherwise, such char combustion
will in general require that flue gases be treated to remove sulfur.
And,  as indicated above,   the development of a large-scale char burning
system, as with the development of any new commercial boiler concept,
may involve appreciable effort,  a long lead time, and considerable
investment.

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                              -  35  -
           At least one other power plant fuel combination deserves
 mention.  Tar removed from the gasifier output might be combusted
 along with char, providing the supplemental volatile matter that may
 be required to achieve stable combustion.  This alternative suffers
 mainly from the sulfur removal problem presented by such combustion..
 Moreover, tar should be valued higher than feed coal as fuel, so that
 feed coal might more properly be used as supplemental fuel if required
 for char combustion.  The present design assumes that produced tar will
 be sold, and credits the thermal balance with the fuel equivalent.  In
 the light of current petroleum availability and pricing, it may well
 develop that tar may be marketable.   Again, it may be possible to gasify
 tar along with char in a suitable gasification unit  to  produce clean gas
 avowing stack gas treatment  entirely and greatly reducing  boiler investment

           In the present design, 4350 tpd of char is combusted in the
 utility boiler.  If char of the composition (1) above is assumed,
 and if combustion be effected using 10 per cent excess air, 1060 MM
 scfd  of combustion air will be required.  The volume of flue gas from
 the combustion will amount to some 1070 MM scfd,  assuming feed char to
 be dry, that carbon combustion efficiency is 100 per cent,  and that all
 of the sulfur is converted to S02, i.e., no sulfur remains  in ash.

           A higher heating value of  11,000 Btu  per pound is estimated
 for char of this composition, so that the hourly firing rate amounts to
 some  3980 MM Btu.   Unfortunately, there will also be emitted some 10,900
 pounds per hour of S02 or about 2.7  pounds S02 per MM Btu.   Hence flue
 gases  must be  treated on the  basis of current standards to  reduce emitted
 S02 to less than 1.2 pounds per MM Btu  (36).   The theoretical limestone
 requirement for this purpose  amounts to some 115 tpd (13,71).

           A variety  of  flue gas  treatment processes  for particulate  and
 SOX control are  in  the development and demonstration stages  (37,38).
Although the effectiveness of some of these processes is now being tested
in  fossil-fuel-fired utility boilers, their use for char-fed boilers
has not been evaluated.  It is reasonable to assume that these systems
could be adapted to provide the necessary control for the char-burning
processes.  The adapted system would have to be environmentally sound
 (i.e. adequate control of all air, water, and solid waste streams)
and efficient.  Alternatively, development of a high-temperature char
gasification approach may prove viable.

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                                 - 36 -
          The emission of other gaseous pollutants from the char combustion
operation, including CO and NOX, are not now considered to present
particular technical problems.  Reported work with utility boilers (39)
would indicate that careful control of the combustion process may suffice
to produce acceptable levels in flue gas.

          Adequate control of particulate emissions should result from
the limestone scrubbing facility.  Normal design practices would limit
liquid droplet carry-over, would reheat gas downstream of the scrubber
using, hot-flue-gas exchange to prevent condensation and formation of
visible plumes, and would insure that gas could not by-pass the scrubber
in the reheat equipment by maintenance of an appropriate pressure balance.
Use of hot flue gas to dry coal, as has been proposed in Section 2-1 above,
would reduce the quantity of water required to presaturate the gas prior
to scrubbing.

     3-3.2  Cooling Water

          A total of 260,000 gpm of cooling water is indicated to be required
for operating the Bureau of Mines design-  About two-thirds of this requirement
is used for thermal exchange against the main high-pressure gasification
train, so that considerable mechanical design effort is foreseen to minimize
leakage losses into the cooling water system.which may otherwise preclude
use of cooling towers as heat rejection devices.  Undue leakage of hydro-
carbons, CO, NH3, phenols, H2S, or sulfurous materials into the cooling
water circuit .could not be tolerated in the plumes from cooling towers.
An early warning system to indicate the presence of hydrocarbons in cooling
water return laterals will probably be required in any case to avoid noxious
discharges.

          If cooling towers were used for this total plant, a minimum of
6600 gpm of water would be evaporated.  Drift loss would be in excess of
500 gpm, and draw-off might be  about 800  gpm.  Air requirement,
would.amount to some 48,000 MM  scfd.  Reheat of plumes would be required
to avoid fogs  in some cases •

          The design basis  (10)  includes  only minimum heat integration, consistent!
with a conservative approach to  an unproven design.  Moreover, some 30 percent
of the total cooling water requirement indicated  for dust removal could
be materially  reduced if alternative procedures can be applied (See Section
2.4 above)•

          It is probable that environmental considerations and the costs
of water reclamation will operate to restrict industrial water consumption  .
in most domestic locations-  Hence a commercial gasification design might
maximize use of air-cooled heat  exchangers, reserving the use of cold
water only  for "trim-cooling"'  or low-level heat  transfer applications.

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                                   -  37  -
The overall economic balance will consider added investments in heat-
exchange and electrical hardware associated with air-fin usage, as well
as investment in incremental electrical generation capacity.  Running
costs for the generation of power and for equipment operation would be
balanced against the net reduction in water treatment and pumping costs,
as well as the net reduction in water loss-

          On the basis that the indicated cooling water requirement for
dust removal is eliminated, and that half of the remaining requirement
may be displaced with  forced draft air-cooled heat exchangers, the incremental
electrical power requirement is estimated to amount to 24,000 KW-  Added
cooling water requirement associated with the incremental power generation
would bring the net total cooling water requirement'to an estimated 100,000 gpm,
so that water loss by  evaporation might be reduced to about 2600  gpm at the
cooling towers.  Drift loss would amount to 300 gpm on this basis-  Blow-
down, or draw-off from the system, might be held to 500  gpm.  There would
be a reduction  in the  steam usage indicated for pumping  cooling water, such
that the net incremental steam  requirement for power generation might
amount  to  200,000 pounds per hour of  1000 psia steam, or to an equivalent
thermal efficiency debit of about 1.5  percent.
           The  physical environmental  situation at  a-particular site,
 including  water availability,  climatic conditions,  and  available  area,
will set  limits on  the designer's  options  for  heat rejection.  Other
 means,  such as  cooling ponds,  may  be  practicable.   In very  apecial
 situations,  it  may  prove economic  to recover some  of the low-level heat,
 as by circulation in central heating systems to nearby  communities or in
 trade-off situations with irrigation water supplies, where  hot water  may
 be used to extend growing seasons-  In all situations,  the  sociological
 impact of the use of the environment will be an over-riding factor.

      3.3.3  Waste Water Treatment

           Facilities  required  to treat water,  including raw water, boiler
 feed water, and aqueous effluents, will include separate collection facilities:

           o  Effluent or chemical sewer
           ©  Oily water sewer
           e  Oily storm sewer
           ®  Clean storm sewer
           ©  Cooling  tower blowdown
           o  Boiler blowdown
           o  Sanitary waste

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                                   -  38  -
            Retention  ponds for run-offs and for flow equalization within
  the system will  be required.  Run-off from the paved process area could
  easily exceed  15,000 gpm during rainstorms.  Run-off from the unpaved
  process  and  storage  areas could exceed 60,000 gpm in a maximum one-hour
  period.

            Pretreatment   facilities will include sour water stripping
  for chemical effluents  and  Imhoff tanks or septic tanks and drainage
  fields for sanitary  waste.

            Gravity settling  facilities for oily wastes will include API
  separators,  skim ponds,  or  parallel plate separators.

            Secondary  treatment for oily and chemical wastes will include
  dissolved  air  flotation  units, granular-media filtration, or chemical
  flocculation units.

           Oxygen demand  reduction may be  accomplished in  activated  sludge
 units,  trickling filters, natural or  aerated  lagoons,  or  by  activated
 carbon treatment.

           Boiler feedwater treatment  will  in  general involve use of ion-
 exchange resins.  Reverse osmosis, electrodialysis,  and ozonation may
 find special  application.

          We  consider that the Synthane plant  will  be  able to take  advantage
 of  the  properties of  char and  of  attractive incremental costs for oxygen
 to  assist its waste water treatment.   Hence,  the  char produced  by the
 process should  have the  attributes of activated carbon, which has been
 shown to  be effective in the removal  of a  wide variety of the water
 contaminants  expected  (65).  The  Bureau of Mines design basis  includes
        M    f°rty-two  tons Per  day of  gasifier  char  for water  treatment
        Normally,  the  cost of activated carbon  tends  to restrict  its
        V°ntaminated Char S°  used may subsequently  be fired  in  the
     , Yf ,boller> water treatment in the Synthane system will  be considerably
simplified.

          Similarly,  oxidation of contaminants in water using oxygen,
 and  especially  ozone,  is  normally reserved for polishing  drinking water
 supplies  because  of high  costs.   Direct oxidation,  however,  is  very
 effective in  reducing phenol,  cyanide and  thiocyanate levels in waste
water  (64), and has particular advantage  in that  solids concentrations
are not thereby increased.  We, therefore,  believe  that early research  should
be directed  to the use of char and of  oxygen or ozone  to  treat aqueous
scrubber effluents from the Synthane  process to set  the stage for an
integrated commercial design.

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                                 - 39 -
          Evaporation will of course occur throughout this system, and
the concern of the designers will be to limit the co-evolution of noxious
or undesirable components which may be present.  Of particular concern
is the system which will be used to pretreat gas scrubber effluent
(See Section 4.4).  We note that it may be necessary to cover portions
of the water-treatment facility and/or provide  forced draft over some
units to  avoid undue discharge of hydrocarbons  into the atmosphere.
In the latter case, as with direct oxidation or ozonation, sweep gases
would be  ducted  to an  incinerator or boiler, and provisions for
minimizing explosive hazard would be required.

     3.3.4  Miscellaneous Facilities

          Provisions  for start-up of the gasification facility may
generate  short-term effluents  to the  atmosphere. Effluents  from start-up
heaters will depend on the fuel fired for such purpose.   Product gas
combustion in a boiler and/or in gas turbines may be justified to
produce start-up steam and power requirements.   In such case,  reverse
flow from the gas product delivery line may be practicable for fuel
supply,  or a pressurized gas storage facility might be provided on-site.

          Planned noise  reduction, especially  in coal handling, grinding,
and charging operations, hopper venting, and in the operation of large
compressors and  pumps, will be a requirement.   Similarly, we note that
normal commercial practice for high-pressure reaction vessels, and
especially for oxygen-blown reactors, would provide barricade shielding
or blast  protection to limit damage in event of rupture and to protect
personnel.  Lay-out of the commercial Synthane  gasification train will
require sophisticated  analysis to minimize the  amount and cost of such
shielding.

          Operation of a blow-down system and flare stack to which
accidental or emergency process releases may be directed will normally
produce a small  emission to the atmosphere.

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                                   -  40  -
                     4.  LIQUIDS AND SOLIDS EFFLUENTS


           Solid and liquid effluents based on our design are also shown
 in Figure 2 and Table 1.

 4.1  Coal Preparation

           On-site coal  storage will require that facilities for con-
 taining storm run-off be provided.  Hence, run-off from the 20-25 acre
 area required to hold a thirty-day supply of feed coal could easily
 amount to 5000  gpm during a major precipitation event common to almost
 all sections of the United States.  Such run-off may be expected to
 contain acidic particulate matter from most contemplated feed coals.

           It is assumed minimally that effluent limitation guidelines
 published by EPA for the coal mining industry under The Refuse Act
 Permit Program  (41) will apply to such coal storage facility.  The
 application of 'best practicable control technology' would require
 installation of impounding and settling facilities to be of sufficient
 size to handle run-off resulting from a once-in-ten-years' storm, and
 the operator would provide suitable recording analytical equipment,
 including a recording rain gauge, to guarantee compliance with con-
 centration schedules for discharges into waterways.

           Since  permissible  concentration  schedules  are  such  that
 impounded  water  will,  after  treatment,  be  of sufficient  purity to  be
 admitted  to  the  plant's  water  system,  it will be  advantageous to  plan
 for such  use  in  the  initial  design.  Similarly, run-off  from  the  gasifica-
 tion complex  otherwise will  have  to  be  contained.  More  than one  set of
 water treatment  facilities will be required to handle the various water
 streams coming  from  and  going  to  the gasification plant-  Depending on
 the severity  of  contamination  that may  be  expected from  the various
 processing areas, storm  run-off from such  areas would be directed to
 segregated holding facilities  consistent with the expected water quality
 (See Section  3.3.3).   It may be necessary  to provide an  impermeable
 subsurface barrier under certain  portions of the  facility, as the coal
 storage area, to prevent contamination  of ground water.

          Although not necessarily considered a part  of the gasification
facility,  the coal mining operation,  if it be located adjacent to the
gasification complex, would probably share treatment  facilities provided
for the  plant proper.  Hence, typical acid mine drainage, of perhaps
 300-400 gpm (42), might be treated continuously by accepted techniques
 (43, 44, 45),- to produce water suitable for discharge or for plant use.
 Except for a  separate initial holding pond and small lime addition
 facility, all other components of the treatment facility would amount
 to  incremental increases on facilities which must be provided the parent
 plant.

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          If coal laundering is practiced, facilities for retention
and disposition of liquid and solid effluents become more complex.
Combinations of screening and thickening devices will generate streams
of varying solids content, some of which would be considered refuse,
and have to be returned to the mine or be buried otherwise.   A properly
designed system would minimize make-up water requirement, by internal
treatment and recirculation of wash water.  A facility to launder feed
coal for this design might circulate 2200 gpm of wash water, and dis-
charge 1800 gpm along with thickened refuse.  Such refuse would be
impounded in clarifying basins, where evaporative loss would occur.
Make-up requirements would then be held to such evaporative loss and
to an estimated 500-600 gpm lost via the laundered coal product.
4.2  Coal Grinding

          In this design, which incorporates bag filters on the air
stream which issues from the ball mills, there should be no solid
effluent from the coal grinding operation.  Some 60 tpd of coal fines
recovered at the filters is recycled to mill product.

4.3  Gasification

            There should  be  no  major  solid  or  liquid  discharges  from  the
gasification section  excepting the gasifier char stream.   In  our design,
it  has  been assumed that a  dry char  let-down  system  can be developed,
such  that  char  may be ducted  to the  power  plant using  steam or  inert gas
as  the  transport medium.  Char is generated at the rate of 4350 tpd.

            Facilities used  to  store  and  compress  lock  hopper  vent  gas
may generate small solids and  liquid effluent  streams  that would require
treatment  or disposition.   Hence, coal fines  filtered  from such vent
gas are recycled  to feed.   Similarly,  water present  in such gas may  be
condensed  in a  compression  process,  and  would  be directed  to  treatment
 facilities. Water which may  be used as  sealing  fluid  in gas  holders may
 likewise require  periodic treatment  and  replacement.

 4.4  Dust Removal

           The  "dust removal" or gas cleaning section as envisioned
 for this design has  the greatest potential for pollution.  It  is at
 this point that all materials generated in the gasification  (other
 than acid gas)  that are not compatible with the gas  product are removed.
 In Synthane gasification, as with all processes which  gasify coal at
 intermediate temperatures,  the gasifier output may  contain all of the

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                                  -  42  -


 fines.
           The particular distribution of compounds which will be present
 in raw aasifier gas will of course depend on the composition of feed
 S.  and* '« the particular conditions of the gasification   The range
 of sulfur and B-T-X components which may be expected are listed  m  Table J
 tor two types of coal (47) .

          In the design basis,  cyclones and water-scrubbing are provided
to remove condensable matter-  Tars which may separate from such condensate
have beln partially characterized (Table 4).  Similarly, aqueous condensate
(obtained by passage of gasifier output from the Bruceton 40-atmosphere
 aboraSry gasifier through water-cooled condensers) from Synthane raw
gas has been analyzed, and compared with coke-plant weak ammoma liquor
(Tables)-
          We note that some of the polynuclear hydrocarbons which may
be present in raw gas have exhibited carcinogenic properties in animal
studies (67,68).  Control of such materials will generally be required
in connection with evaporation from the waste water treatment system,
in plumes from cooling towers if  leakage from the process train occurs,
in the direct handling of separated tar or oil products, and in the  flue
gases from char, coal, or tar combustion (69,70).

          The over-riding consideration is that gas clean-up shall be consistent
with satisfactory operation  of subsequent processing steps, especially
shift conversionyand tuethanation, and  that Benfield solution contamna-  .
tion be minimized.
           Scrubber  operation for  this  design has  been ^""a* £ *CCtl°n
 The  Bureau of  Mines has  evaluated the  operation of  facilities which
 may  be Squired to  treat waste water from this design (48)    Aqueous
 Affluent rrom  the scrubber water  decanters is fed to ammoma stills
 ft the rate of 1,110,000 pounds per hour.  Milk of  lime is  used to
 spring fixed ammonia in a steam-stripped tower according to
                Ca(OH)2 + 2NHA(X)
                                                       Ca(X)
 Generated lime sludge is directed to holding ponds for settling at
 the lite of 230 tpd (501 solids).  C02, H2S, and HCN present in the
 incoming decanter stream are sprung in a heated dissociator.  This
 las strLm is directed to the sulfur recovery unit.  160 tpd of ammonia
 is produced for sale. This general treatment method and its variations
 have been reviewed by Kohl and Reisenfeld  (66).

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                            - 43 -
                           Table 3
             COMPONENTS  IN  GASIFIER GAS  (47)
COS
Thiophene
Methyl Thiophene
Dimethyl Thi<
Benzene
Toluene
C0 Aromatics
 o
so2
cs2
Methyl Mercaptan
(ppm)
Pittsburgh
Seam Coal
860
11
42
:iene 1
Dphene 6
1,050
185
27
10
—
ntan 8

Illinois
No. 6 Coal
9,800
150
31
10
10
340
94
24
10
10
60

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                             - 44  -

                            Table  4

               MASS SPECTROMETRIC ANALYSES OF
                     BENZENE -SOLUBLE TAR
               FROM SYKTHAME GASIFICATION
                           (Vol. %)

 Structural  type;                 HP-118^-'             HP-1— ^
 includes  alkyl                 ,     #118               #92
 derivates _                Pittsburg          Illinois

 Benzenes                            1.9                2.1  ,
 Indenes                             6. I-7               8.6^'
 Indanes                             2.1                1.9
 Naphthalenes                       16.5               11.6
 Fluorenes                         10.7                9.6
 Acenaphthenes                      15.8               13.5
 3-ring aromatics                   14.8               13.8
 Phenylnaphthalenes                  7.6                9.8
 4-ring peri-condensed               7.6                7.2
 4-ring cata-condensed               4.1                4.0
 Phenols                             3.0                2.8
 Naphthols                           b/                  b/
 Indanols                            0^.7                (5.9
 Acenaphthenols                      2.0
 Phenanthrols                        —                  2.7
 Dibenzofurans                       4.7                6.3
 Dibenzothiophenes                   2.4                3.5
 Benzonaphthothiophenes              —                  1.7
 N-heterocyclics£'                  (8.8)              (10.8)

Average mol. wt.                 202                 212
a./  Spectra indicate traces of 5-ring aromatics.
b_/  Includes any naphthol present  (not resolved in these  spectra)
cj  Data on N-free basis since isotope corrections were estimated,

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                                  - 45 -
                                  Table  5

             BY-PRODUCT WATER ANALYSIS^ FROM  SYNTHANE GAS  (47)
 PH
 Suspended  Solids
 Phenol
 COD
 Thiocyanate
 Cyanide
 NH3
 Chloride
 Carbonate
 Bicarbonate
 Total S
I/  Mg/liter  (except pH)
2]  85% free NH3
JV  Not from same analysis
4V  S=       400
    S05      300
    S0=    1,400
    s2o= = 1,000
Pittsburgh
Seam
9.3
23
1,700
19,000
188
0.6
11,000





Illinois
No. 6
8.6
600
2,600
15,000
152
0.6
8,10Q2/
500_,
3/
6,0004,
W
11,0007,
Coke
Plant
9
50
2,000
7,000
1,000
100
5,000






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                                 - 46 -
          Water withdrawn from the fixed ammonia still is cooled to
100 F using air-fin exchangers, and is stored for 48 hours to permit
tars to separate.  This water is then directed to aeration tanks,
along with other aqueous streams condensed from the main product stream
(see below).  Antifoam, phosphoric acid, and sulfuric acid are added
to adjust pH and to promote the oxidation of organic material, including
phenols, cyanides, and thiocyanates,  in the aerators.

          Water from the aerators is directed to clarifying basins.
Overflow, containing 0.2 ppm phenol, flows to polishing towers where
gasifier char is used to remove phenols.  Treated water is returned
to the plant's raw water supply system at the rate of 1,760,000 pounds
per hour.  Wet char (about 1.75 tph of dry char is required) is
re-directed to the gasifier char stream after filtration.  Underflow
from the clarifiers is filtered to remove sludge and recycled to the
aeration tanks.  Sludge is filtered and combined with char fuel going
to the power plant at the rate of about 2.3 tpd.  Filtrates are recycled
to the aeration tanks.

          One concern with this processing sequence involves the
ultimate disposition of phenols.  Particular difficulty associated with
the recovery of dihydric phenols from aqueous streams led to the
development in Europe of the so-called "Phenosolvan" process (49).  In
this scheme, n- or isobutyl acetate (or other acetate. ) is used as
extraction solvent, permitting separation of phenol by-product.

          It is interesting in this context to review the gas liquor
treatment scheme provided for the Burnham Coal Gasification Complex (50).
In this arrangement, incoming gas liquor is filtered and mixed with
the Phenosolvan solvent.  Phenol-rich extract is distilled to recover
crude phenols,  and the solvent overhead, after separation from water,
is recycled to the extractors.

          Crude phenol is used to scrub fuel gas,  which is used to
strip solvent traces from the extractor raffinate.  Solvent-free raf-
finate is steam-stripped to remove NH3, CC^j  and I^S.  The C02 an^ H2S
are returned to the sulfur recovery unit.  Effluent from the strippers
is directed to biological treatment to render it suitable for use as
cooling tower make-up.

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                                 - 47 -
           In recent years,  the  rapid development  of  environmental  protection
requirements has outstripped environmental research and  development programs-
It is likely that noxious effluent limitations  will tighten in the  future,
so that considerable additional  research is needed to offset the  very high
incremental costs foreseen for extended application of current technology.
On the other hand, considerable  progress has already  been made toward
practical treatment systems  conforming with current standards in  related
coking and coal operations (40).

4.5   Shift  Conversion

          There  should normally be no  liquid or solid effluents  from
the  shift operation.  However,  facilities  will be  required  to  dispose
of spent or inactive catalyst (See Section 4.12).

4.6   Waste  Heat  Recovery

           Some 395,000 pounds per hour of  condensate is generated  in
the  process of cooling combined gas  streams prior to acid gas removal.
Condensate  is further  cooled, and is then directed to the aeration
tanks in the waste water treatment plant.

           The depressurization  of this, and all  other condensates
 collected from the high-pressure gas stream, will release absorbed
gas    It will be advantageous to direct all such condensates
 to a common expansion vessel,  from which released gas may be recom-
 pressed back into the main gas  stream.  In particular, gases recovered
 from condensates ahead of methanation might be reinjected ahead of
 acid gas removal.

 4.7  Gas Purification.

           Condensate streams are generated in the Benfield loop as
 circulated gas  is cooled.  The disposition of these streams will  depend
 on  their composition, but they may  in  general be  directed  to  the  waste
 water treatment  plant.  Some 19,000 pounds per hour of condensate xs
 separated  from  treated  gas as  this  stream is cooled ahead  of  the
 residual sulfur clean-up beds.

            Additionally,  facilities  will be required  to dispose  of
 contaminated  Benfield solutions.  (See Section 4-12).

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                                  - 48 -
 4.8   Residual  Sulfur  Cleanup

           As previously  discussed,  facilities will be  required  to
 dispose  of spent material  used  in  the  cleanup beds.  Activated  char
 or carbon  may  be combusted in the  power  plant, but disposition  of
 other materials, such as iron oxide, is  less certain (See Section 4.11.5)

 4.9   Methanation

           About 130,000  pounds  per  hour  of  condensate  is  separated
 from  the main  gas  stream as it  cools on  exit from the  methanation loop.
 Gas which  separates from such condensate on depressurization may be
 compressed back into  gas product,  or may be consumed as fuel in the
 power plant.   Condensate is directed to  waste water treatment.

           As discussed above, on-site  facilities for catalyst replace-
 ment  and activation may  generate a  variety  of liquid and  solid  streams,
 including  spent catalyst,  metal dusts, and  caustic solutions.   Dis-
 position of these  materials is  discussed in Section 4-12.

 4.10  Gas  Compression

           A small  quantity of condensate, about 1,000  pounds per hour,
 is separated from  product  gas in the final  compression.   Gas which
 separates  on depressurization of this  stream may be combined with gas
 evolved  from methanation loop condensate.

 4.11  Auxiliary Facilities

      4.11.1  Oxygen Plant

           About 85 gpm of  water will be  condensed from entering air at
 the oxygen facility.  This water should  be  suitable for addition to the
 plant's  boiler feedwater treatment  system.

           There should normally be  no  other liquid or  solid effluents
 generated  in the oxygen  plant.  However,  if a refrigerant, such as ammonia,
 is employed in the refrigeration loop, facilities for  disposition of
 such material will be required  at intervals.

      4.11.2  Sulfur Plant

           Elemental sulfur make is  about 140 tpd from the Stretford
plant.   Sulfur purity may  be  quite  high,  and product may be made
available  in solid or molten  form,  so  that  marketability  should be
high.

           Sulfur recovery  systems based on  sodium, as  in  the Stretford
system,  require that  the rhodanic salt resulting from  the capture of
cyanogen in the absorbent  liquor, and  thiosulfate and  sulfate salts

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 resulting from oxidative  side  reactions,  be  continuously removed, and
 fresh alkali  supplementeds  to  maintain  recovery  efficiency.  The waste
 liquor withdrawn is  very  high  in chemical oxygen demand, and is generally
 incinerated.   The COD  of  this  waste  stream may be lowered by adding
 enough sodium to change the whole sulfur  content to  sodium  sulfate prior
 to  incineration.   However,  caustic requirement for this facility might
 amount to about a ton  per hour.

           An  incineration process (51)  has been  developed to incinerate
 such waste liquor with a  gas fuel under reducing conditions, such that
 sodium salts  are decomposed to carbonates which  may  be captured and
 returned  to the Stretford system.  This process  results in  zero liquid
 or  solid  effluent, but is high in energy  cost and investment.

      4.11.3  Power and Steam Generation

           The largest  solid effluent  stream  from the boiler will be
 ash.   Ash in  the  coal  feed  to  the gasifiers  amounts  to about 1050 tpd.
 Most  of this  material  is  removed from the gasification train with
 char  and,  if  char  is burned  as fuel  in  the power plant, this same ash
 will  be discharged at  the boiler.  There  will be  small ash  "losses"
 to  tar, and ash will otherwise appear in  raw gas  and in scrubbing
 liquors and condensates.

           The  quantity of ash  discharged  from the  boiler will of
 course  depend  on  the degree  of efficiency with which the fuel (char)
 is  combusted.   Hence,  a carbon combustion efficiency of 96  percent
 would  increase  the ash rate  about 10  percent above theoretical.
 Similarly,  it  is  not now  known what  the composition  of such ash may be
 otherwise,  especially  with  regard  to  sulfur  content  and to  particular
 toxic  trace elements which  may affect the  costs  for  ultimate disposition
 of  this material.  It  is  now considered that ash effluents would be
 buried  in a mine  in  a  manner that would minimize  subsequent adverse
 environmental impact.

           If  limestone is used to  treat flue gas  to  limit S02 emissions,
 about 150  tpd of  sulfated lime will be  generated.  Long-term disposition
 of  such material  is likewise uncertain.   It  may  ultimately be required
 that  sulfur be  recovered, as by  regeneration of  the  sulfated material.

     4.11.4  Cooling Water

          A variety of chemical  additives may be  used to treat water
 circulated  in the cooling system to control  algae and corrosion.  These
will appear in  tower draw-offs,  along with matter originally present in
make-up streams.  Depending  on the extent of facilities provided to
 treat waste water effluents, such  draw-offs  may  be treated

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                                    -  50  -
to precipitate or neutralize specific toxic elements, such as chromium
or zinc, before being directed to further treatment.

          As  indicated above, there may be particular problems associated
with  leakage  into the cooling water system from the high-pressure
gas processing train.  In general, however, such leakage would be
expected to add to atmospheric emissions at the cooling towers, with only
trace quantities of condensable liquids or solids appearing in the
cooling water circuit.

      4.11.5  Miscellaneous Facilities

          A variety of materials  is indicated to be required to treat
waste water effluents, including milk of lime, antifoam, phosphoric
and sulfuric  acids, and char or activated carbon.   In addition, water
treatment may require the use of  lime-soda alums, ion exchange resins,
caustic, ferrous ion, and chlorine, among other agents.  Ultimately,
these additives exit the system as concentrated sludges, contaminated
solids, or in aqueous streams with high salt content.  These effluents
may be concentrated, dried, and/or incinerated.  Ultimate disposition
of the dry or concentrated residuals1 is uncertain,  however, especially
if heavy metals, leachable salts, or organic contaminants are present.
Burial in sealed pits appears the only practicable  method for disposal
of materials which must be prevented from leaching  into ground or
surface water, although the logistics and economics of such techniques
requires extensive further study.

4.12 Maintenance
          Normal plant operations will require the periodic replacement
or replenishment of catalysts and other chemical agents used  to process
coal and gas.  Such maintenance will generate contaminated solid and
liquid effluents, including shift catalyst, Benfield solution, methanation
catalyst, activated carbon, iron oxide, and caustic streams.   In general,
spent materials will be sulfidic.  Metal value may justify specific
reclamation, but again, it would appear that the ultimate disposition of
such solid effluents" is now uncertain.  Incineration or thermal oxidation,
as in a fluid bed incinerator, might be used to remove hydrocarbon and
sulfur, but control of metallic particulates from such systems requires
further study, as does the disposition of residues.

           Operation of start-up heaters will generate solid or liquid
effluents consistent with the fuel consumed.  Hence,  if coal is fired,
ash and stack treatment effluents may be accumulated,  and subsequently
directed to the operating plant's normal treatment routing.

-------
                                   - 51 -

                           5.  THERMAL EFFICIENCY


           The efficiency with which energy is  utilized ranges from less
 than 5 percent for the ordinary incandescent lamp to perhaps 75 percent
 for a well-maintained home heating furnace.  The automobile engine has
 an efficiency of less than 20 percent.  Modern fossil fuel power plants
 are not more than twice as efficient.  On the average, probably less than
 35 percent of the available heat in fuels consumed in the United States
 is recovered usefully (52).

           The determination of thermal efficiency is useful for providing a
 basis on which to compare like processes, or to gauge incentives for process
 improvements.  Obviously, there are other equally important bases on which
 processes may be compared, including economic and ecologic factors  associated
 with process improvement or increases in efficiency.   In large measure, such
 costs  may be related  to  the technological state  of  an art.   Hence,
 it is  unlikely  that more  efficient  methods  for converting  energy
 to visible  light  will find widespread  use until  a device  that  is  as
 convenient,  inexpensive,  and  reliable  as  the  incandescent  lamp
 is developed.


          In  the case of fossil fuel conversion processes, the thermal ef-
ficiency is calculated as the ratio of the heating value of product(s) to
the heating value of the (coal) feed.  In the present design, the higher
heating value for coal feed, based on the analysis given for Pittsburgh
seam coal as  fired to the gasifiers (10), has been estimated by conventional
formulas to be approximately 13,700 Btu per pound, which is at variance
with the heating value reported.  Product gas is indicated to have a higher
heating value of 927 Btu per scf, a value consistent with its analysis.
Similarly, a  thermal credit of 130,000 Btu per gallon is taken for recovered
tar, which is considered a saleable product.  On this basis, a base thermal
efficiency of 63-5 percent is indicated (See Table 6).  Since tar
is  not a "clean" product,  we note that its thermal value should
be  discounted in the  event that it is not marketable as such.

          The basis otherwise assumes that char may be completely combusted
to balance the plant's steam and power requirements.  If, for example, a
carbon combustion efficiency of only 96 percent is achieved  in the char
combustion process, the shortfall would be equivalent to about one percent
on feed coal, so that overall efficiency would drop about the same amount.
We have assumed that a carbon combustion efficiency of 100 percent will
be achieved•

           The design basis (10) does not include specific allowance for
treatment of  scrubber effluent.  The Bureau of Mines design  (48) for waste
water treatment, including scrubber effluent, requires the energy equivalent
of 2.6 percent of gasifier feed coal for its operation, in addition to an

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                                     52  -
  incremental  24,000  gph  of  raw water  which must be upgraded  to  boiler
  feedwater.   If  this energy requirement were  to be generated
  by  burning coal  or  tar  along  with  char in the powerplant, so that additional
  desulfurization  of  flue gases or its equivalent would be required, overall
  process  efficiency  would be reduced  about four percent below baseline.
  However, credit  might then be taken  for the  heating value of separated
  ammonia, amounting  to about 0.8 percent of feed coal equivalent.

            Although recovered tar should be valued higher than feed
  coal for the purpose of supplying the volatile component that may be
  required to achieve stable char combustion,  such tar would be combusted
  if it could not  be marketed.  Combustion of all of the tar would balance
  the utility load estimated for waste water treatment.

            As discussed in Section 2.7,  the  base  design does not include
 distinct facilities for separation of oils,  naphtha,  or phenols.  It
 has been estimated that about 25,000 gpd  of  B-T-X may be produced (47),
 in addition to 60,000 gpd of tar oil and  15,000 gpd  of crude phenol in
 a plant of this  size,  although it must be  emphasized  that the exact
 quantities of these materials  which may  be  extractable from  gasifier
 output  will be distinct functions of the composition  of feed coal and
 of the  particular conditions  of  the gasification.  We estimate  the  thermal
 efficiency debit associated with the  removal  of hydrocarbon,  including
 crude distillation,  will be about equal  to  the thermal credit for the
 separated material.

            The design basis does  not  include  specific provision for  drying
 feed coal.   If moisture  content  of  feed coal  had  to be  reduced  an incremental
 five percent  due  to  moisture  accumulation on  storage,  the  thermal require-
 ment amounts  to  about  0-5  percent of  the feed coal.   We  believe that flue
 gas  from  the  utility boiler may  be  used to effect  such  drying,  avoiding
 this energy debit (See Section 2.1).

           Similarly,  substitution  of a Stretford  sulfur  recovery system
 for  a direct  oxidation Glaus plant  will significantly  increase  utility
 requirements  associated  with sulfur recovery,  but  the effect on overall
 efficiency is minor, on  the order of  0.2 percent.

           As discussed  in  preceding  sections, there  are numerous opportunities
 in the proposed system which a designer may consider  for energy recovery
 or energy reduction.  In all such cases, the  potential energy benefit must
 be weighed against the costs associated with  such recovery, including not
 only investment,   but also factors associated with operability,  increased
 processing complexity or decreased overall reliability, and potential
hazards.  In many cases, the technology is  not straightforward, so that
 additional research and development will be required.  Obvious areas
 for such investigation include the methods  for feeding coal to the gasifiers
and for extracting char,  and the potentials for energy recovery in the
dust removal and gas purification systems  as  proposed.

-------
                                    -  53  -
          We have estimated that more than 300,000  pounds  per  hour  of high-
pressure steam may be generated if a tar scrubber can be  applied  to gasifier
output (Section 2.4).  Further, 300,000 pounds  per  hour of low-pressure
steam may be additionally generated in subsequent water scrubbing/cooling
of raw gas, simultaneously reducing cooling water load and the associated
energy debit.

          Similarly,  we have estimated that 100,000 pounds per hour of
high-pressure steam may be generated in the char let-down process,  or
that the bulk of the sensible heat of char may  be conserved if a  dry
char let-down process is developed.

          If air-fin cooling is substituted for cold water exchange as
outlined in Section  3.3.2,  the  net  energy  debit  is estimated  at about 1.5
percent, but net water loss in the cooling water circuit  can be reduced
by more than half.

          Finally compression energy required to deliver  final product gas
to commercial pipelines is  conserved  in the  Synthane  system by operation of
the gasification train at essentially pipeline pressure.   It  may be
desirable  to consider operation of  the system at some  reduced pressure.
Hence, operation at  the 600 psi level would  bring much of  the required
hardware within the  realm of commercial experience and safety codes, such
that development lead times and potential  process hazards  may be consider-
ably reduced.  The final gas compression debit in this case should amount
to no more than about one percent on  overall efficiency.   Such consideration,
of course, must also weigh  factors  related to the effect of pressure on
gasifier output and  to required reaction volumes-  Additional development
will be required before this effect can be properly assessed .

-------
                                                      Table 6

                                                THERMAL EFFICIENCY



                                                                         Equivalent      Thermal  Efficiency as
  Bureau of Mines  Svnthane Design Basis  (10):                quantity      MMBTU/Hr      Percent of ca,65°                  59<3
  Sulfur (TPH)                                              <+Wi.-             630                   3.9
                                                              5.7              /.s                   «  -,
 - Equivalent Coal Feed  (TPH)                               15.24
                                                                            130
- Hydrocarbon Removal and Distillation                                     ,,c
                                                                           115
                                                           , nnn
                                                           1UUU              130
                                                                                                           63.5
 Bureau of Mines Water Treatment Base Case  (481
                                                                                                -2.6
                                                                                                           60.9
 Estimated Effects of Additions and Modifications

 - Incremental Flue-Gas Treatment, Sludge Dewatering
   and Handling, Boiler Feedwater Treatment, Ash
   Handling Associated with Power and Steam Generation
   for Waste Water Treatment-
                                                                            220                 -!.3
 + Produced Ammonia (TPH)                                    , ,
                                                             6.6
                                                                                                           60.4

                                                                                                -0.7
 + Produced Hydrocarbon (GPH)
                                                                                                          60-5
 -  Stretford  Sulfur  Recovery  Substitution
   For  Claus  Plant
                                                                             35                 -0.2
                                                                                                          60.3
 -  Product Gas Loss  in Acid Gas Removal
                                                                            50                 -0.3
                                                                                                          60.0

+ Steam Generation in Tar Scrubber                                         ,-, „
                                                                           540                 +3.3

+ Steam Generation in Water Scrubber and Credit
  for Cooling Water Reduction, Less Energy
  Associated with Scrubber Operation and Steam
  Production.                                                              300                 +l^

+ Steam Generation in Char Let-Down                                        150
                                                                                                          66.0
- Air-Fin Substitution for Cooling Water                                   250

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                                   - 55 -


                           6.  SULFUR BALANCE
          The sulfur balance for this design (see Table 7) has been
estimated using a variety of sources (11,33,47) along with.the design
basis (10).  The analytical results reported by the Bureau of Mines
for various laboratory gasification experiments for Pittsburgh
seam coal are not necessarily mutually consistent with the design
basis.  However, the estimate is reasonable if reported values for
organic sulfur levels in raw gas are assumed (47)•

          Approximately 60 percent of the sulfur in the gasifier coal
feed appears as H2S in the gasifier output (10).  Essentially all
of the sulfur in this form, including that portion dissolved in
aqueous condensates, may be recovered as saleable elemental sulfur
product.  Depending on relative economics, the concentration of H2S
in the C02 stream separated at the sulfur plant may be reduced
to less than 5 ppm, so that it may be practicable to dispose of
this stream by passing it up the stacks of the main boilers.

          Nearly 30 percent of the incoming sulfur is retained in
the gasifier char in this case.  It is probably not reasonable to
expect that all of this sulfur will be oxidized in the char combustion
process-  We have arbitrarily assumed 96 percent conversion to SC>2
(equivalent to about 0-25 percent sulfur in final ash).  The flue
gas scrubber on the char boiler will be required to remove at least
6100 pounds per hour of S02, so that less than 4800 pounds per hour
may issue to the atmosphere in the scrubbed flue-gas stream.  If lime-
stone is used in the scrubbing system, some 12,300 pounds per hour
of sulfated lime will be generated at theoretical conversion.
In practice, the quantity of limestone required and the amount of
solid residual produced may be half again as much (13,71).
          Concentrations of organic sulfur compounds in raw gas
reported for Synthane gasification of Pittsburgh seam coal (47)
appear quite low, especially with regard to carbonyl sulfide.  How-
ever, it may be assumed that COS and mercaptans present in gas sub-
jected to catalytic shift conversion will be hydrolyzed to H2$ and
C02> so that organic sulfur will be thereby reduced by half (in
the shift by-pass stream).  Moreover, depending on the scrubbing
procedures used to treat raw gas before shift conversion, or to
extract naphtha or oil components from the gas stream, more or less
of the organic sulfur compounds may be diverted to other streams.

          Research relating to the Benfield acid gas removal process
(74) indicates that COS removal in commercial systems ranges from
75 to 99 percent,mercaptan removal ranges from 68 to 100 percent,
and disulfide removal ranges from 71 to 85 percent.  And 85 percent
removal of thiophene has been reported for a commercial installation,
although this effect runs counter to expectation or to laboratory
test results.  In general, most of such absorbed sulfur would

-------
                                     - 56 -
 appear as H2S in regenerator off-gas-  Undesirable reaction products
 (sulfates, thiosulfates,  thipcyanates, polysulfides) appear to accumulate
 in the activated hot carbonate solution only to a limited and
 acceptable  extent.   Hence it would appear that organic sulfur levels
 would be reduced by at least 70 percent on average in the Benfield
 system.   Such compounds  which persist beyond this point would be
 removed  in  the sulfur guard beds preceding methanation.

          Sulfur which is present in aqueous condensates collected
 from the gas  processing  train will undergo varying treatment  in the
 waste water treating plant depending on the overall quality of the
 particular  stream.   l^S  which separates on depressurization of such
 streams,  or which issues from the ammonia recovery system,  will be
 directed (along  with C02)  to the sulfur recovery  plant.  Although  it;
 is  not possible  to  designate how much sulfur may  be sprung  to
 atmosphere  in aeration/oxidation facilities which may  be provided
 for water treatment,  very close  control of such emissions will  be
 required.   Hence, the bulk of dissolved sulfur  will issue generally  in
 calcium  sludges  or  in chars (activated  carbon)  from the treatment
 plant.   These  accumulated  residuals would  be  de-watered and fed to
 the  main char  boilers for  incineration.

          The  concentration of sulfur in  tar  separated  from the gas
 stream is estimated,  on  the  foregoing basis,  at about 2.5 percent
This  is  higher, by a  factor  of three,  than  the results obtained  in'a
reported  laboratory gasification  (47).  However, the distribution of
sulfur among the various component sub-streams  issuing  from the
gasifier has been shown to be primarily a function of coal feed com-
position and of gasification conditions, and may be further influenced
by the manner  in which the streams are separated.

-------
                                  - 57  -
                                Table 7
                              SULFUR BALANCE
                                                Lb/Hr
          Percent
In Feed Coal
19,000
H S Converted to Sulfur Product                 11,400     60-0

Char From Gasifier                               5,435     28.6
  M                                                             •
  Final Ash                                        210      1.1
  As SC"2 in Flue Gas                             2,290     12.1
  As Sulfated Residual from Flue-Gas Scrubber    2,935     15.4
Organic Sulfur in Raw Gas*
   (Thiophene, Mercaptan, Sulfides)
  Hydrolyzed in Shift Converter
  Hydrolyzed in Benfield
  Sulfur Guard
   165
    80
    55
    30
 0.9
 0.4
 0-3
 0.2
Total Sulfur in Aqueous Condensate*
  Recovered as H2S
  Oxidized/Released to Atmosphere
  As Sludge to Incineration
   935

   270
   100
   565
 4.9

 1.4
 0.5
 3-0
 Tar  (By  Difference)
  1,065
  5-6

100.0
 *  Estimated per Reference 47

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                                  - 58 -
                            7,   TRACE ELEMENTS
           Trace  elements  are  usually  defined as  those elements present  to
 the  extent  of  0. 170  (1000  ppm)  or  less.   Nearly all  trace  elements  show  an
 enrichment in coal  ash relative to their crustal abundance  (53).   Manganese
 and volatile elements such as mercury are exceptions.   This enrichment
 is attributed to concentration effects or exchange  reactions during  the
 formation, of coals.  Almost every element has  thus  been found in  coals,
 but  the variation in concentrations is quite broad  (12).

           The  fate  of trace elements  present in  the  feed  coal to conversion
 processes  has  so far received  little  attention.   To  the extent that  such
 conversion processes approach  conditions  which obtain during  combustion, it
 may  be  pertinent to apply results  obtained  in trace  element  studies  of  the
 combustion of  coals 64,55,56).   Even in such studies,  however, the  con-
 ditions of combustion have been noted to  affect  element dispositions.
 Coal handling  and preparation methods can likewise  influence results,
 so that generalizations may not be meaningful.   Obviously,  extrapolation
 to a particular  conversion process or feed  coal  would be  conjectural in
 large measure.

          Although  very large  quantities  of coal  are consumed in combustion
 processes,  so  that  the total quantities of  trace  materials,  some of  which
 are  highly  toxic, that may be  released are  likewise  large,  it has  been  only
 recently that  concerted effort  has  been directed  to  the definition of the
 real  problems.   This  effort, of course, has been  associated with the
 promulgation of  sanctions  affecting permissible discharges  to the atmosphere
 and waterways  of  the  United States.   Particular sanctions relating to toxic
 discharges  are still  in process of  formulation (57).  Research is required
 in many cases  not only to  set  limits  and goals, but also  to develop
 analytical  procedures that may be generally adapted.  With  fossil  fuels,
 the general problem relates to  the  complexity of  the chemical system, in-
 cluding the large number  of components, the imprecision of available sensors
 or test methods, and  the  difficulties associated  with representative sampl-
 ing of very large streams-  The detection and monitoring of many trace
 elements requires sophisticated procedures and equipment which cannot
 be practically applied commercially.  In fact,  the magnitude and nature
 of many industrial  streams is such that direct quantification or
measurement is impractical.  The general nature of the pollution problem
 associated with Synthane gasification has been described by the Supply-
Technical Advisory Task Force (58).  At this point it is generally con-
 sidered that gasification will present no insurmountable control problems.
On the other hand,  it is seen that considerable  research will be required
 to establish practical and economical control procedures.

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                                - 59 -


          Trace elements which have been detected by the Bureau of
 Mines in condensate from the laboratory Synthane gasifier are shown
 in Table 8 for an Illinois No. 6 coal  (47).  Similarly, toxic trace
 elements which have been found in Synthane raw gas and tar are shown
 in Table 9,

           Literature values (12) for the elemental composition of
 Pittsburgh seam coals are presented in Tables 10 through 12 .  Reported
 values may of course not be representative of a particular poal;  but
 in many eases,  element levels are remarkably consistent in a particular
 region.

           Table 10 lists the major elements in coal (exclusive of
 C,H,0,N).   On the basis that reported  values  may apply to  the feed
 coal in the present  design, we  have calculated  the quantity  of each
 element  which daily  enters  the  process vj.a the  gasifiers.   Similarly,
 for the  purpose of comparison,  we have calculated the  quantity of each
 of these elements which would appear in the condensate from  raw gas
 if reported values (47) were to apply  to the  present design.   Obviously,
 we would expect the  bulk of these materials (other than sulfur) to
 exit the process  via the ash residual  from char combustion.   But  the
 elements vary widely in the form in which  they  appear  in coal and in
 their reactivity, volatility,  and solubility  otherwise.

           Table 11 similarly lists some of  the minor or trace  elements
 in feed  coal.   It should be emphasized that concentrations of some
 of these elements can vary  by factors  of ten  or more within  a region,
 and  that analytical  methods employed by researchers have had  high
 or unmeasured inherent imprecision  in  many cases.   Reported  values  may
 also  suffer frpm  bias  in some cases, in that  analyses  were performed
 on coals which  were  known to  contain high  concentrations of particular
 elements;  and the original  intent of the analyst  has not always survived
 reprinting  of his data.

          HCN,  mercury,  and arsenic have been detected in  raw gas  and
 in tar from Synthane  gasification by the Bureau of  Mines (47).  These
 materials  are listed  in Table 12, a  tabulation  of  some of  the hazardous
 trace  elements  in coal  prepared on  the  same basis  as the preceding
 tables.  For these elements especially,  it will  be  important  to close
 the material balance.   Recently reported studies  indicate  the difficulty
 associated  with the  attempt  to  follow mercury,  for  example, throughout
 a  commercial coal-fired  utility installation.   But  the  state-of-the-art
 of detection is bound  to  progress rapidly  as  attention is  focused on
 particular  elements  through  legal sanctions,  and as coal processes
 proliferate.

          Each  developer of a coal conversion process may ultimately
 be required to  account  for  the disposition of elements  present in feed
whose toxicity  or ultimate  impact on the environment warrants control.
He  may moreover be required to guarantee the containment or  neutralization
of such materials in effluent streams,  and this, in turn, may influence
 the adoption of particular processing alternatives, even including  the
conditions of gasification.   For Synthane, this will require  additional
research firstly to define the levels of these elements through the

-------
 Ca
 Fe
 Mg
 Al
 Se
 K.
 Ba
 P
 ?n
 Mn
 Ge
 As
 Ni
 Sr
 Sn
 Cu
 Nb
 Cr
V
Co
                            - 60 -
                            Table 8

             TRACE ELEMENTS IN CONDENSATE, FROM AN'
          ILLINOIS NO. 6 COAL-GASIFICATION TEST (47)

No. 1
4.4
2.6
1.5
0.8
401
117
109
82
44
36
32
44
23
.33
25
16
7
4
4'
1

No. 2
3.6
2.9
1.8
Q.7
323
204
155
92
83
38
61
28
34
24
26
20
5
'8
2
2
Average
(by wt)
4 ppn)
3 ppm
2 ppm
0.8 ppm
360 ppb
160 ppb
130 ppb
90 ppb
60 ppb
40 ppb
40 ppb
30 ppb
30 ppb
30 ppb
20 ppb
20 ppb
6 ppb
6 ppb'
3 ppb
2 ppb

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                                 - 61 -
                                Table 9

               TRACE COMPONENTS IN RAW GAS* AND TAR (47)
   COAL FEED                     RAW GAS                        TAR

                             HCN           Hg               Hg          As
                         ppb by vol.  ppm  fry vol.     ppm  by wt.  ppm by  wt.

111. Char                     5            r            .

111. #6 Coal                 20         Q.00001          0.003       0.7

W. Kentucky                  11            -                -

N. Dak. Lignite               3            -                -

Wyoming Sul?-Bit.              2            -
   It is  indicated that no mercury or HCN was detected in product gas.

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- 62 -
Table 10
MAJOR ELEMENTS IN COAL

Si
Fe
S
Al
Ca
K
Mg
Na
Concentration
in Feed Coal
(Wt. %)
4.0
1-5
1.6
1.0
0.5
0.22
0.17
0.06,9
In Feed to
Gasifier
Ib/day
1,140,000
428,000
456,000
285,000
142,500
62,700
48,500
19,700
Concentration in
Condensate (47^
(ppm)

3
1400
0.8
4
0.16
2
- ••—
Discharge to
Water Treatment
Ib/day
--
50
22,500
13
65
3
32


-------
  -  63  -
Table 11
MINOR TRACE ELEMENTS
In Feed
Goal
B
Ba
Zn
V
Li
Gr
Ni
Ge
Cu
Mn
Mo
Y
La
U
Co
Sn
ppm
165
100
44
35
25
22
14
12
12
10
8.2
7.7
5.1
5
3.8
1.5
Ib/dav
4700
2900
1250
1000
710
620
400
340
340
290
230
220
150
140
110
43
In
Condensate
ppm (47)
__
0.13
0.06
0.003
--'
0.006
0.03
0.04
0.02
0.04
—
—
--
—
0.002
0.02
Ib/day
.2
1
0.05
--
0-1
0.5
0.6
0.3
0-6
--
—
--
-1-
0-03
0.3

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                                  -  64  -
                                Table  12
POTENTIALLY HAZARDOUS TRACE ELEMENTS
Be
F
As
Se
Cd
Hg
Pb
HCN
In
Feed
Coal
2
85
31
2.2
0.14
0.2
7.7
-
To
Gasifier
Ib/dav
60
2430
880
65
4
6
220
-
(PPM)
Condensate Raw Gas* Tar
-
-
.03 (.5)** - 0.7 (.7)
•36 (6)
-
.0001 (.04) .003 (.003)
—
20 '(1000)
 *  No Hg or HCN detected in product gas.

 ** Numbers in parentheses indicate quantities in pounds per day
    appearing in design streams.

*** Units as given in Reference (28).

-------
                                 -  65  -
process sequence for particular feed coals at preferred gasification
conditions.  A preliminary study of this type has been reported for
the Hygas bench-scale unit (59) .  Additional research may then be
required to indicate specific modification of the process sequence
to remove or contain these materials or to adequately plan effluent
treatment facilities.

          It would appear, on the basis of results published thus
far, that Synthane gasification does not appear to introduce new
control problems.  Rather, since the gasification train and water
loops,including run-off,may be designed to be largely self-contained,
emphasis of the controls development will be directed to flue gases
and ash from the combustion process that powers the system, to the
gas residual from acid gas treatment, and to the concentrated residuals
from waste water treatment.  The enormous current government/industry
effort to define and set effluent goals and to develop economical
control procedures for coal-fired industrial operations will have
a direct bearing on the extent of additional research that may be
required^once stream compositions have been completely defined for
Synthane gasification.

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                                  - 66  -
                          8.   PROCESS ALTERNATIVES


           Most of the process alternatives which we have considered in
 connection with the particular design chosen as the basis for this report
 will require additional research, development, and/or evaluation.   Some
 would change or diffuse the  character of the process.  Operation of the
 process at a lower pressure, for example, would influence all aspects of
 the design and each such aspect would have to be evaluated for its effect
 on the total design, including investment and costs.   On the other hand,
 most of the laboratory results published thus far relating to this process
 have been obtained at pressures considerably below the 1000 psi level,  so
 that extrapolation to high pressure  has already introduced a measure of
 uncertainty.   The primary process considerations which may be affected  by
 pressure include gasification rates,  raw gas composition,  dust removal
 operations,  and acid gas removal.  In fact,  there are so many such inter-
 related considerations which may affect the  overall efficiency,  cost and
 pollution potential,  that it is not  particularly useful to extend  analysis
 in the  absence of real data.   Operation of a prototype  plant over  a
 range  of pressures should ultimately resolve this question.

          Similarly,  the  use of a high temperature gasification process
to gasify char and tar separated from the Synthane train to produce a
clean fuel for power  generation, and so avoid flue-gas desulfurization,
appears  now to be viable  processing alternative.  On the other hand, there
is bound to be further development of desulfurization processes, and a
continuing redefinition of applicable standards, as well as development
Of combustion processes for chars and tars, so that constraints which
face the ultimate designer may be substantially different from those that
now appear,,

          Other processing alternatives which suggest themselves include:

          o  Use  of  a tar scrubber as  a  first  element  in the
             dust  removal operation.   Incentives  include
             reduction in water treatment  loads  and thermal
             efficiency  credits.

          o  Alternative  facilities for adjusting gas composition
             ahead of methanation, including the possibility of
             auxiliary coal gasification for this purpose.
             Gasification of char and/or tar to produce a
             hydrogen-rich gas may also be attractive.

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                                   - 67 -
          o  Use of extraction processes to remove phenols, for
             example, from scrubber effluent.

Even if particular alternatives are evaluated at a given stage in a process's
development and found to be marginal, it may be necessary to re-evaluate
these same options at a later stage as basic data are firmed.  Hence, the
development of  alternatives continues, even  through  the life of a commercial
plant.

            Table 13 lists some of the alternatives considered in connection
with the base design.

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                                    - 68 -


                                    Table 13

                       PROCESS ALTERNATIVES  CONSIDERED

 Coal Drying

 o  Coal-fired vs^ use of boiler flue gas.

 o  Lime-scrubber vs_ electrostatic precipitator or bag filters-

 o  Flash drying in ball mills.

 Gasification

 o  Variations on lock-hopper coal charging  operations-

 o  Char let-down process variations.

 o  Operation at lower total  pressure.

 Dust Removal

 o  Inclusion of tar  scrubber and  internal gasifier cyclones  vs_  external
    cyclones  and water scrubbing.

 o  Inclusion of facilities to remove middle  and  light oils from prqduct
    gas-

 Shift Conversion

 o  Alternative  means  for adjusting  gas composition ahead of
    methanation.

 o   Improvements  in shift conversion processes.

 Acid Gas Treatment

 o   Use of Stretford process vs_ Glaus plant and tail-gas cleanup.

 o   Inclusion of  facilities to  convert organic sulfur to H2S and  to
    treat Stretford blow-down.

Utilities

o  Alternative fuel choices for power and steam generation.

o  Waste-water treatment variations, including use of process char
   and oxygen or ozone.  Use  of extraction for phenol removal-

o  Maximum air-fin usage vs cooling water for heat rejection.

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                                    -  69  -
                       9..   ENGINEERING MODIFICATIONS
           Engineering modifications  that may  be  advantageous will occur
 to the detail designer„   Obviously,  these cannot be divorced from
 process  considerations,  but  rather will reflect  an  attempt  to  optimize
 energy utilization  or reduce investment or  operating .cost within process
 constraints.

           As  discussed above,  operation of  this  process at  high pressure
 on  a  commercial  scale will involve development of hardware  that is
 currently  non-existent.   While reaction volumes  are small,  wall thick-
 nesses are large and stresses  are high, so  that  vessel costs and operating
 hazards  may not  be  optimum.  The engineering, design, and operation of
 this  system will be considerably simplified if operating pressures are
 substantially reduced, based on current technology.  On the other hand,
 this  is  not seen to imply that technology should not be extended, or that
 engineering considerations should prevail over processing benefits that
 may be seen for  operation at high pressure.

           A number  of engineering alternatives involve integration of
 facilities.   The net increase  in thermal or material efficiency that may
 result must be balanced,  in  general, against  increased process complexity
 and/or costs  or  reduced  operating reliability.   Hence, the  use of
 hot flue gas  from the utility  boiler to dry feed coal has been
 incorporated  into our design.   On the other hand, this alternative
 constrains  the relative  placement of the coal drying and boiler
 facilities, and  the start-up and operation  of these facilities
 is made more  complex, involving inter-related controls.

           Similarly, attempts  to minimize energy requirements for com-
 pressing lock-hopper gas  that  depend on the scheduling of gasifier opera-
 tions must  be assessed on the  basis of potential for decreased overall
 reliability or the  slowing of  overall operation.

          The location of a  given facility  within the total plant may be
 optimized on  the basis of one  or more major considerations, but will in
 general prove non-optimum from other viewpoints.  Hence the air intakes
 for the oxygen facility might  be located to minimize interference from
 plant effluents.   But it  will  also be desired to minimize piping and
 hardware required to deliver oxygen to the  gasifiers.

          Incentives for other modifications will depend on future process
development.  There would now  appear to be considerable incentive for
 energy recovery on depressurization of scrubber  effluent.  This
 processing  sequence will  almost certainly be  improved in the
 course of future research.

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                                 - 70 -
           A major modification  that deserves attention, as with most
preliminary gasification designs, is the general substitution of air
fin cooling for the use of cooling water.  This may prove especially
important  in this case, since the high operating pressure increases the
possibility of leakage into the cooling water system and subsequent
emission at the cooling towers.  Again, basic economics and the designer's
ingenuity will dictate whether, and to what degree, such substitution
may be practicable.

          Table 14 lists some  of the  engineering  modifications  considered
in connection with the base design.

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                                  - 71 -
                                  Table 14





                    ENGINEERING MODIFICATIONS CONSIDERED
Coal Drier
 •  Use of  limestone scrubber to treat boiler flue gas drying medium.




 Gasification Train




 •  Operation at lower pressure.




 •  Treatment of depressurized gases and condensates.




 Dust Removal




 •  Power generation on depressurization of scrubber effluents.




 •  Steam generation in cooling raw gas.




 Acid Gas Removal




 •  Power generation on depressurization of scrubber effluent,




Methanation




 •  Provision for limiting CO in product gas.




Utilities




•  Air-fin substitution for cooling water.




•  Containment of run-off and inclusion in plant  water  balance.

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                                   - 72 -
                            10.   QUALIFICATIONS


          This  study  is  based on the process design  (Figure  I  and Tables  15-17)
 supplied  by  the process  developer (10,48), with modifications  as discussed
 and  shown in Figure 2  and Table  1.  Costs or economics were  not considered
 except dj.rectionally.  Although  it was not always possible to  resolve
 process details with  assigned energy or mass consumptions, overall assignments
 are  considered reasonable and consistent with the data obtained at the
 laboratory level  (8,11,22).

          Variations in feed coal and product compositions make  it
difficult to compare gasification processes.  Significant variation
is seen even for the "same" process on different coals.  Similar
variation will extend to the pollution potential of the process.
Considerable additional research and/or development will be  required
to define pollutant levels in particular streams with the precision
required by today's standards, and so permit a more accurate assignment
of energy requirements.

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             - 73 -

            Tgble 15
   COAL AND PRODUCT ANALYSES
        Pittsburgh Seam
   Coal Feed to Gasifier (10)

c
HO
2
NO
2
So
2
00
2
Ash
Moisture
HHV
Wt. Per Cent
73.8
5.2

1.5

1.6

8.0

7.4
2.5
13,700 Btu/lb
      Product  Gas  to  Pipeline

                   Mol Per Cent
H2                      3.6
CO                      0.1
C02                     3.7
CH4                    90.4
N2                      2.1
H20     '                0.1
HHV                927 Btu/scf

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                                                     -Table 16


Unit
Coal preparation
Gasification
Dust removal
Shift conversion
Waste heat recovery
Purification
Methanation
Pipeline compression
Oxygen plant
Sulfur recovery
Subtotal

Steam plant
Powerplant
Utilities:
a. cooling water
b. plant lighting
c. sanitary water
General facilities
Miscellaneous and
contingencies
Total

Steam
1,000 psia

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                             -  75 -
                          Table  17

         COAL AND PRODUCT  QUANTITIES AND  HEAT  CONTENT

                       Coal  Consumption
                                                        Equiv.
                                      TPH            MM BTU/Hr
Coal  to Gasifiers (10)                593.75
16,270
Equivalent Coal  to Utility             15.24                420
Boiler for Water Treatment (48)
                                      609.0              16,690
                    Products and Equivalents



Product Gas  (MM SCFH)                 10.41             9,650

Tar (gph)                           4849                  630

Sulfur (tph)                           5.7                 45

NH  (tph)                              6.6                130

B-T-X (gph)                         1000                  130

                                                        10,590

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                                    -ye-
                    ll-  RESEARCH AND DEVELOPMENT NEEDS


            The Bureau of Mines, as developers of the Synthane Process,
 have, with The Lummus Company, designed a versatile pilot plant now
 under construction, which is geared to the determination of many of
 the basic data which will be required to design a commercial plant.
 The following paragraphs discuss research and development needs that
 bear on the efficiency and/or pollution potential of the process.

            Paramount among the research needs will be demonstration of
 the operability of the integrated gasification system.   Hence the  following
 operations must be demonstrated simultaneously in a continuous manner:
            o Coal Feeding, involving lock hopper operation

            o Coal P re treatments, involving fluidized bed operation

            o Gasification, involving fluidized bed operation

            o Char Let-Down,  involvfing continuous withdrawal from
              a fluidized zone and lock hopper operation
 Achievement of operability in the prototype  pilot plant  will  almost
 certainly involve  developmental modifications.

            Equally important will be  the  determination of basic  gasification
 parameters on gas  composition and gasification  rates,  including  the
 effects  of:

            o Feed  Coal Properties/ Pretreatment

            o Total Pressure

            o Temperature

            o Steam/ Oxygen Ratios

            o Carbon Conversion

Perhaps  the most important aspect of this program will be  the data which
may be used  by  the designer  of  the commercial gasification system to
optimize gasifier  total  pressure.  Investment and operating costs for
each component  of  the  total  system, including auxiliary  facilities, will
be affected by  the gasification pressure  level, as will  the overall thermal
efficiency and  pollution potential of the process.  Detailed parametric
analysis based  on data to be obtained at Bruceton should point the way
to an optimum design.

           The  third major objective of the pilot plant program
involves the ultimate selection for development of one of the two novel
Bureau of Mines methanation processes, Tube Wall Reactor (TWR) or Hot

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                                    - 77 -
Gas Recycle (HGR), both of which have been included in the prototype unit.
This selection will evolve from operations on a much larger scale
than heretofore, and over a broader total pressure range.  These results
may significantly affect process thermal efficiency.

           Obviously, initial effort in the pilot plant program will
be heavily weighted toward achievement of primary goals.  It was considered
that such achievement must precede secondary developments that may be
required to commercialize the process.  Included among such developments
are:

           o  Development of a char-burning boiler

           o  Optimization of "dust removal" from raw gas

There is indicated to be no facility provided in the prototype plant for
char combustion studies.  From some points of view, this may be considered
a serious deficiency.  However, there are a number of coal conversion
processes undergoing development which produce similar chars, so that
progress in char conversion and combustion may be otherwise expected.
Moreover, as has been already discussed, unless significant progress is
shown for flue gas desulfurization, it may prove more attractive to gasify
char, bypassing combustion development entirely.  It will of course remain
to  be demonstrated that Synthane char may be gasified, but this is now
considered to be a low-risk option.

           The problem of raw gas treatment, on the other hand, is
not nearly so straightforwardo  There will be processing constraints
on the quality of gas that may be admitted to shift conversion and
subsequent gas treating operations^ as these processes are now
visualized„  Hence reliable operation of the catalytic shift
converter and of the Benfield acid gas removal process, both of which
have been included in the prototype plant, may prove the best
yardstick for judging the efficacy of dust removal.

           Apart  from processing  constraints,  the  method of raw gas
treatment may have significant  impact on overall  efficiency and  on
the pollution potential of the  process..   Hence  the  degree to which
gas must be cooled to effect clean=up and  the  particular procedures
employed will translate to energy and water  requirements and,  specifically,
to  the quantities of "contaminated"  streams  that  must  be further
processed for economic or ecologic reasonso  The prototype  plant
has been provided a  flexible gas  scrubbing system which  should  point
the way to a practicable design.  We have also suggested a variation
on  this design, incorporating a tar scrubber as the leading  element
in  the dust removal  operation.  This device has been commercially
proven for petroleum fluidized bed coking operations, but at
generally less  severe operating conditions than will be  required here.
We  see considerable  incentive for  the development of this or some
similar technique, however, which  avoids or reduces the  thermal
and pollution debits of the aqueous scrubber.

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                                  - 78 -
            It is unfortunate that it is not possible a priori to specify
 the exact quantities  and nature  of materials which will have  to  be
 removed from raw gas.  These will depend as much on the conditions of
 gasification as on the properties of the particular feed  coal.   It is
 similarly not possible to pre-judge how variation in pretreatment or
 gasification parameters may affect such residuals.   Hence the approach
 taken in the pilot plant program,  which  will firstly optimize the
 gasification on the basis of primary yields,  appears to be a  logical choice
 Moreover, successful  operation of the pilot plant will mean that
 particular requirements for at least one practicable system will have been
 established.

            It is presumed therefore that future  or  secondary  developments
 will:
             o Optimize raw gas treatment on the  basis  of  overall
               thermal efficiency.   Research efforts  may  be directed
               to "hot gas" clean-ups to  improved shift conversion
               catalysts or proceduress or to alternative  means  for
               adjusting hydrogen content before  methanation.

             o Optimize raw gas treatment on the  basis  of  pollution
               potential.  Obviouslys these  developments cannot  be
               divorced from each other,  or  from  the  primary requirement
               to deliver a clean product gas.  Research may be  directed
               to procedures for  neutralizing or  recovering materials
               from "contaminated"  streams generated  in the clean-up
               process,  or to operations  on  the main  gas stream.  Specific
               problems may include the dephenolization of aqueous
               scrubber streams,  or the removal of HCN, thiophenes, or COS
               from the  main gas  stream or from the acid gas separated
               by the  Benfield  system.

            The pilot  plant  will  also permit evaluation of  the Ben-
 field acid  gas removal  process over  a broader pressure range than
heretofore.   A better definition of  the  kinds of treatment that may  be
required  for  both  the main  product stream and for the  acid gas  that  is
separated should evolveo  Moreover,  the  inclusion of a Stretford
scrubber  in the prototype plant should serve to flag any unwanted
interactions  between  the  acid gas  removal and sulfur recovery processes,
again establishing the  basis for a practicable commercial design.

            On  the basis  that successful operation of the pilot
plant will  be  achieved,  it will  thereafter be possible to investigate
any aspect  of  the process to any desired degree of precision.,   On the
other hand, in the current domestic  energy framework, a decision to
commercialize may be required before all research or optimization studies
can be completed.  It may be important finally only to know that the
process is workable, that efficiency is reasonable,  and that adverse
environmental impact is within reasonable tolerances.  The questions
relating to environmental impact may be the most difficult to  resolve
quicklyo

-------
                                - 79 -
           The concentrations of residuals in processing streams that
may bear on environmental impact can be very low«  Even at the greatly
expanded prototype plant scale (relative to previous laboratory-
scale), it may not be practicable to resolve all possible problems.
It is considered that:

            o Special effort should be made in connection with the
              earliest operations of the prototype pilot plant to
              instrument or to otherwise provide for analysis of
              trace components known to be toxic or undesirableo
              Routine analytical methods for many trace elements
              and compounds are not available, and must be developed.
              In many cases, sophisticated laboratory procedures
              only may be applicable,  and precision is poor.
              Commercial plant magnitudes will be 200-300 times
              greater than the prototype plant scale,  so that
              judgements relating to commercial design could easily
              be misdirected.

            o The varying composition of coals and the difficulties
              associated with representative sampling of solid streams,
              makes it extremely difficult to obtain balances for trace
              elements around coal operations.  The multiphase nature
              of the output streams from many coal conversion
              processes or treatments  adds to the general problem.
              And representative sampling becomes more difficult for
              any stream as the stream size increases.

              The proper interpretation of prototype pilot plant  results
              will be greatly simplified if clear balances are shown
              around processing equipment.  Sampling systems should be
              designed to permit such  balances to be generated with a
              high degree of confidence.  Special effort should be
              directed to sulfur in all its forms, HCN,  arsenic,  mercury,
              cadmium,  and  metal  carbonyls.

           o  Because the Synthane  process generates char which
              exhibit many  of the desirable  properties of activated
              carbon and because  incremental  oxygen should be available
              from the Synthane oxygen plant  at  relatively low cost,
              we  consider that  early research directed to the use
              of  these materials  for treatment of Synthane effluents
              may lead to greatly simplified  pollution control  systems
              for water and  gas loops.   Hence  research may be directed
              to  the  use of  char  in fixed- or fluidized-bed  units
              to  treat gas  streams,  including the main product  s.tream
              (65),  or to treat liquid  effluents,  especially  waste
              water  streams,  for  the removal  of  specific  constituents.
              In  general,  the  use of char  for  pollution  control would
              be  viable  only if it  could be demonstrated  that flue
              gases  from the  subsequent combustion of  contaminated

-------
                     -  80  -
 char were compatible with standards for atmospheric
 discharges, or could readily be treated to make them
 so.  It would not, for example be particularly useful
 to take COS from one stream and discharge it to the
 atmosphere in another.  Hence additional research,
 which should be coupled with the char combustion
 development, would be required to demonstrate overall
 effectiveness.

 Similarly, the use of oxygen or of ozone,  especially
 for the oxidation of contaminants in waste water,
 warrants attention.  Direct oxidation using these
 materials is advantageous in many cases because
 residuals which form when other oxidants such as
 chlorine are used are avoided.   Moreover,  oxidative
 reactions which go slowly or not at all with air
 frequently go rapidly with ozone or oxygen,  so
 that  the sizes of treating facilities  and  treat
 times are reduced.  Such oxidation does introduce
 questions relating to corrosion,  toxicity,  explosive
 hazard  and relative costs,  all  of which factors may
 be  inherent  in any treatment method,  but which can
 be  assessed  in the research program.

 Finally,  there  is  a growing need  to conduct  research
 related  to toxic  or noxious  materials  that  is  not
 specific  to  Synthane  gasification,  but  which relates
 to  all  fossil-fuel utilization.   Obviously,  toxic
 elements  which  enter  a process must concentrate or
 exit  the  process  at some  point.   Not only are  the
 quantities discharged  important,  but so also must
 be  the  form  in which  such discharged materials
 appear.   There  is  hardly  any form  or compound  of
 mercury,  for example, which  may not be  considered
 toxic or  hazardous  in some  sense.   But  there are
 obviously  relative  degrees of toxicity  associated
with  its  various compounds,  and work is  required
 to define  these least toxic  forms,  as well as  to
develop technology  for conversion  to desired
 forms within the process  framework.  A more  realistic
approach  to control of some  elements or  compounds
which cannot be effectively  concentrated or extracted
 from effluent streams may be their conversion to
the least objectionable forms in such streams.

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                      - 81 -
Zero direct discharge to atmosphere or to waterways
may be technologically possible within the gasification
process battery limits, but the desired objectives
will not be achieved if discharged ash, concentrated
sludges, or solid streams contaminate the environment
at some later time.  The magnitude of this problem
is very great, but so also is the combined effort
which may be brought to bear by affected industries,
consumers, and regulatory agencies to achieve a
solution.

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                                  - 82  -
                           12. BIBLIOGRAPHY


  (1)   Forney,  A.  J.,  R.  T.  Kenny,  S.  J.  Gasior,  and J.  H.  Field,
       "Destruction of Caking  Properties  of Coal  by Pretreatment in a
       Huidized  Bed", Ind.  Eng.  Chem.  Prod.  Res.  Develop.,  Vol. 3,
       No.  1, March,  1964,  pp.  48-53.

  (2)   Forney,  A.  J. ,  R.  F.  Kenny,  S.  J.  Gasior,  and J.  H.  Field,  "The
       Production  of Nonagglomerating  Char from Caking Coal  in a
       Continuous  Fluid-Bed  Reactor",  Preprint-Division  of  Fuel Chemistry,
       American Chemical  Society, Vol.  8,  No.  3,  Aug.-Sept., 1964,  pp. 1-9.

  (3)   Gasior,  S.  J.,  A.  J.  Barney,  and J.  H.  Field, Ind.  Eng. Chem.  Prod.
       Res. Develop.,  Vol.  3,  1964.

  (4)   Ibrney,  A.  J.,  R.  T. Kenney,  S.  J.  Gasior,  and  J.  H.  Field,  ".Fluid
       Bed  Gasification of Pretreated  Pittsburgh  Seam  Coals",  Advances in
       Chemistry,  Am.  Chem.  Soc., Vol.  69,  1967,  pp.  128-140.

  (5)   Forney, A.  J.,  S. J. Gasior, R.  T.  Kenny, and W. P. Haynes,
      "Steam-Oxygen Gasification of Various U.S.  Coals", Second Int.
       Fluid-Bed Combustion Conf., Hueston Woods State Park, Ohio,
      Oct.  1970.

  (6)   Jbrney, A.  J., R. J. Demski, D.  Bienstock,  and J. H.  Field,
      "Recent Catalyst Developments in the Hot-Gas-Recycle  Process",
      BuMines R.I. 6609,  1965.

  (7)  Haynes, W.  P., J. J. Elliott, A. J. Youngblood and A. J.  Forney,
      "Operation  of a Sprayed Raney Nickel Tube-Wall Reactor  for Production
      of a  High-BTU Gas", Preprint - Div. of Fuel Chemistry Symposium,
      A.C.S., Vol. 14, No. 4,  Sept., 1970, pp. 26-48

  (8)  "Engineering Evaluation and Study of the Bureau of Mines  "Synthane"
      Process", The M. W. Kellogg Company, December 21, 1970.

  (9)  Frith,  J. F. S., "Engineering Aspects of the Synthane Coal
      Gasification Process",  Second Synthetic Hiels from Coal Conference,
      Oklahoma  State University,  Stillwater,  Oklahoma, May,  1972.

(10)  "An Economic Evaluation  of  the Synthane Gasification of Pittsburgh
      Seam  Coal at 1000 psia",  BuMines Report No. 72-9A, October,  1971.

(11)  Mills,  G. A., "Progress  in  Coal  Gasification - U.S.  Bureau of
      Mines", Proc. Third Synthetic Pipeline Gas  Symposium,  Rosemont,
      Illinois, November,  1970, pp.  57-78.

(12)  Magee,  E. M., H. J.  Hall, and G.  M.  Varga,  Jr.,  "Potential
      Pollutants  in Fossil Fuels",  EPA-R2-73-249, June,  1973.

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                               -  83  -
(13)   Slack,  A0 V., H. Lo Falkenberry,  and R0 E. Harrington,  J. Air
      Pollution Control Assoc., Vol. 22,  No. 3,  March,  1972,  p. 159-166.


(14)   Magee,  E. M,, Jahnig,  C0  E0  and Shaw,  H.,  "Evaluation of  Pollution
      Control in Fossil Fuel Conversion Processes,  Gasification,  Section  1,
      Koppers-Totzek Process",  EPA "NTIS  P3  No.  231 675/OWP".

(15)   Foster  Wheeler Corporation,  private communication.

(16)   Weir, H.  M. s  "High Pressure  Gasification of Coal  in Germany",
      Ind.  Eng. Chem., Vol.  39, 1947, pp. 48-54.

(17)   Forney, A. J., S. J.  Gasior, W. P.  Haynes, and S. Katell, "A
      Process to Make High-BTU  Gas from Coal", Bu.  of Mines Technical
      Progress Report 24, April, 1970.

(18)   Final Report, Coal to Gas'Prototype Pilot  Plant,  U.S. Bureau
      of Mines, Contract No. HO 110989, The  Lummus  Co., October, 1972.

(19)   Cheng,  C. Y., L. T. Fan,  and J. A.  Hunter, RGD Progress Report
      No. 357,  Office of Saline Water,  U.S.  Dept. of the Interior.

(20)   Benson, H. E., J. H.  Field,  and R.  M.  Jimeson, Chem. Eng. Prog.
      Vol.  50,  No.  7, 1954,  pp. 356.

(21)   Benson, H. E., J. H.  Field,  and W.  P.  Haynes, Chem. Eng.  Prog.
      Vol.  52,  No.  10, 1956, pp. 433.

(22)   Field,  J.  H., H.  E.  Benson,  G. E. Johnson, J. S.  Tosh,  and
      A.  J. Forney, "Pilot-Plant Studies  of  the  Hot Carbonate Process
      for Removing  Carbon Dioxide  and Hydrogen Sulfide",  Bureau of
      Mines Bulletin 597, 1962.

(23)   Ricketts, T.  S., "The Operation of  the Westfield  Lurgi Plant",
      I.G.E.  Journal, October,  1963, pp.  563.

(24)   Newman, L. L., "Oxygen in the Production of Hydrogen or .
      Synthesis Gas", Ind. Eng. Chem.,  Vol.  40,  No. 4,  April, 1948,
      pp. 559-582.

(25)   Sands,  A. E., H. W. Wainwright, and L. D.  Schmidt,  Ind. Eng.
      Chem.,  Vol. 40, 1948,  pp. 607.

(26)   Sands,  A. E., H. W. Wainwright, and G. C.  Egleson,  "Organic Sulfur
      in Synthesis  Gas", Bureau of Mines  Kept, of Investigations 4699,
      1950.

(27)   Corey,  R. C., "Bureau of  Mines Synthane Process", Second
      Synthetic Fuels for Coal  Conference, Oklahoma State University,
      May,  1972.

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                                 -  84  -
 (28)   Forney,  A.  J.,  and J.  P.  McGee,  "The  Synthane  Process  -  Research
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                                  - 85 -


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                                 - 86 -
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4. TITLL AND SUBTITLE Evaluation of Pollution Control in
Fossil Fuel Conversion Processes; Gasification:
Section 1: Synthane Process
7. AUTHOR(S)
 .D. Kalfadelis and E.M.  Magee
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Esso Research and Engineering Company
P.O. Box  8
Linden. NJ 07036
                          	 _ Q~7 	
                                TECHNICAL ru-Toiu
                          r/i'.nc read luwii<'lii>n\ mi I hi.' MTCM.
1. KU'Oli I NO.
EPA- ^50/2^74^00 9 -b_
                                                       3. H LCI I'll. N I JS ACCl:SSIuVNO.
            5. REPORT DATE
            June 1974
            6. PERFORMING ORGANUA'I ION CODE
                                                        I. PERFORMING ORGANISATION REPORT NO
               GRU. 4DJ. 74
            10. PROGRAM ELEMENT NO.
            1AB013; ROAP 21ADD-23
            11. CONTRACT/GRANT NO.

            68-02-0629
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
                                                       13. TYPE OF REPORT AND PERIOD COVERED
            Final
            14. SPONSORING AGENCY CODE
15. SUPPLEMF.NTARY NOTES
16. ABSTRACT
The report gives results of a review of the U. S. Bureau of Mines' Synthane Coal
Gasification  Process, from the standpoint of its potential for affecting the
environment. Where possible, it estimates the quantities of solid, liquid, and
gaseous effluents,  as well as the thermal efficiency of the process. It proposes a
number of possible process modifications  or alternates ? and points out new
technology needs.
17.
                              KEY WORDS AND DOCUMENT ANALYSIS
                 DESCRIPTORS
Air Pollution
Coal Gasification
Fossil Fuels
Thermal Efficiency
Trace Elements
                                           b.IDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
Clean Fuels
Synthane Process
High-Btu Gas
Researc Needs
                                                                    c.  COSATI I ickl/Group
13B
13H
21D
20M
06A, 06P
13. DISTRIBUTION STATEMENT

Unlimited
19. SECURITY CLASS ('lliis Report)
Unclassified
 I NO. OF P
     93
20. SECURITY CLASS (Thi
Unclassified
                          22. PRICE
EPA Form 2220-1 (9-73)

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