EPA-650/2-74-009-g
May 1975
          Environmental Protection Technology Series
ALUATION  OF POLLUTION CONTROL
        IN  FOSSIL  FUEL CONVERSION
                              PROCESSES
         GASIFICATION:  SECTION 5. BI-GAS PROCESS
                           U.S. Environmental Protection Agency
                           Office of Research and Development
                                Washington, 0. C. 20460

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                                     EPA-650/2-74-009-g
EVALUATION  OF  POLLUTION  CONTROL
      IN FOSSIL  FUEL  CONVERSION
                  PROCESSES
       GASIFICATION: SECTION  5.  BI-GAS PROCESS
                         by

                      C. E. Jahnig

            Exxon Research and Engineering Company
                      P. O. Box 8
                 Linden . New Jersey 07036
                  Contract No. 68-02-0629
                   ROAP No. 21ADD-023
                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

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

                       May 1975

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                       EPA REVIEW NOTICE

This report has been reviewed by the National Environmental Research
Centt-r - Research Triangle Park, Office of Research and Development.
EPA. and approved for publication.  Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
                   RESEARCH REPORTING SERIES

Research reports of the Office of Research and Development. U.S. Environ-
mental Protection Agency, have been grouped into series.  These broad
categories were established to facilitate further development and applica-
tion of environmental technology.  Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields.  These series are:

          1.  ENVIRONMENTAL HEALTH EFFECTS RESEARCH
          2.  ENVIRONMENTAL PROTECTION TECHNOLOGY

          3.  ECOLOGICAL RESEARCH

          4.  ENVIRONMENTAL MONITORING

          5.  SOCIOECONOMIC ENVIRONMENTAL STUDIES
          6.  SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS

          9.  MISCELLANEOUS

This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution.  This work provides the new or improved
technology required for the control and treatment of  pollution sources
to meet environmental quality standards.
 This document is available to the public for sale through the National
 Technical Information Service, Springfield, Virginia 22161.

                 Publication No. EPA-650/2-74-009-g
                                 11

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                            TABLE OF CONTENTS
 .  SUMMARY	 .	-. •-	

2.  INTRODUCTION	• • • • •••'•• ••••'•• • • v......;...    3

3.  BASIS AND BACKGROUND	 • •«• • • • >'	* ••'•••	    5

4.  PROCESS 'DESCRIPTION......... ...........	•••	-		   6

    4.1  Coal Preparation 'and Drying.	• - •	    6
    4.2  Gasification	•	    j>
    4.3  Quench and Dust Removal	    10
    4.4  Shift Conversion	    10
    4.5  Acid Gas Removal	    j°
    4.6  Methanation and Drying	    j^
    4.7  Auxiliary Facilities	    12

5.  EFFLUENTS TO AIR	    13

    5.1  Coal Preparation  and Drying	    13
    5.2  Gasification	    21
    5^3  Quench and Dust Removal	    21
    5.4  Shift Conversion	    22
    5.5  Acid Gas Removal	    22
    5.6  Methanation and Drying	    23,
    5.7  Auxiliary Facilities	    2A

6.  EFFLUENTS  - LIQUIDS AND SOLIDS	    26

    6.1  Coal  Preparation	    2^
    6.2  Gasification	    2^
    6.3  Quench and  Dust  Removal	    2^
    6.4  Shift Conversion	    2°
    6.5  Acid  Gas  Removal	    30
    6.6  Methanation and  Drying	    31
    6.7  Auxiliary Facilities	    32

7.  GAS  HANDLING AND SOUR WATER CONSIDERATIONS	    33

8.  SULFUR BALANCE	    36

9.  THERMAL EFFICIENCY	    38

10.  TRACE  ELEMENTS	   41
                                    111

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                        TABLE OF CONTENTS  (Cont'd)
11.  ALTERNATIVES TO CONSIDER		    44




12.  TECHNOLOGY NEED.S	...	    50




13.  PROCESS DETAILS...				    54




14.  QUALIFICATIONS	,		    62




15.  BIBLIOGRAPHY		    63
                                      iv

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                               LIST OF TABLES
Table


                                                                          2
           Table of Conversion Units. ... . • •-• • • • • • • ••••'• • > • • • • • • ••• • • • • •


                                                                          8
  1        Coal Feed - W. Kentucky No.  11 .......... • ...............


                                   .   ~                                   9
  2        Products from BI-GAS  Process. ......... .............. ...... .-



  3        BI-GAS Process -  Inputs and Effluents.- ..-...•.-........-....•
  4        Flue Gas  Flow Rates  and Composition

           From Boiler Plus  Steam Superheater. .
                                                                          37
   5         Sulfur  Balance ................................. .........



   6         Thermal Efficiencies for BI-GAS Process.. ...............



   7         Example of Trace Elements That May                            ^

            Appear  in Gas Cleaning Section ..........................


                                                                          45
   8         Alternatives to Consider ................................



   9         Technology Needs ...... • .................................



  10         Steam Balance for BI-GAS Base Case ............... .......



  11         Water Requirements  for  BI-GAS Base  Case. ..... ...........



  12         Electric Power Consumption ..............................



  13        Make Up Chemicals and Catalyst  Requirements .............      58


                                                                          59
  14        Potential  Odor Emissions ................................



  15        Potential  Noise Problems ................................


                                                                          61
  16        Miscellaneous Inputs ................................

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                             LIST OF FIGURES


Figure

  1       Flow Plan and Flow Rates for Plant
          Making 250MM SCFD of Pipeline Gas
          From W. Kentucky No. H Coal	
          Block Diagram Showing Streams In
          & Out of Specific Sections of Plant
          Possible System for Pumping Coal
          to High Pressure,  Using Slurry ...........................     47
                                    vl

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                                    - 1 -
                               1.  .SUMMARY
          The BI-GAS Process of Bituminous Coal Research,  Inc. has been
reviewed from the standpoint of its effect on the environment.  The
quantities of solid, liquid and gaseous effluents have been estimated,
where possible, as well as the thermal efficiency of the process.  For
the purpose of reducing environmental impact, a number of possible process
modifications or alternatives have been proposed and new technology
needs have been pointed out.

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                               - 2 -
  To Convert:From




Btu




Btu/pound




Cubic feet/day




Feet




Gallons/minute




Inches




Pounds




Pounds/Btu




Pounds/hour




Pounds/square inch




Tons




Tons/day
TABLE OF CONVERSION UNITS






    	To     	




    Calories , kg




    Calories,  kilogram




    Cubic meters/day




    Meters




    Cubic meters/minute




    Centimeters




    Kilograms




    Kilograms/calorie, kg




    Kilograms/hour




    Kilograms/square  centimeter




    Metric tons




    Metric tons/day
Multiply By




0.25198




0.5552




0.028317




0.30480




0.003785.




2.5400




0.45359




1.8001




0.45359




0.070307




0.90719




0.90719

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                                     - 3 -
                             2.   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 commercially 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 prob-
 lems   peculiar to  the conversion  process.  It is thus important  to examine
 alternative  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
 Research & Engineering Company under Contract No.  EPA-68-02-0629,  using
 all available nonproprietary   information.

          The present study under the  contract involves  preliminary design
 work  to  assure that 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  nonpolluting.   This
 is one of a  series  of reports  on  different fuel conversion  processes.

          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 caused by  the production of a given  quantity of
 clean  fuel.

          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
 and/or contacts ^?ere made with the developers  to update published  information.
Not included in  this  study are such  areas as cost,  economics,  operability,
etc.    Coal mining and  general offsite  facilities are not within  the scope
 of this  study.

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                                   - 4 -
          Considerable assistance was received in making this study,
and we wish to acknowledge the help and information furnished by EPA
Bituminous Coal Research, Inc., and by Steams-Roger Inc.  The process
design and balances used in this study are based on a detailed report
on the BI-GAS process prepared by Air Products and Chemicals, Inc. (9)

          Acknowledgement is also made to Dr. Henry Shaw of Exxon
Research and Engineering who made the initial contacts to assemble
background information on the BI-GAS process.

          Four previous reports in this series on gasification were
issued as Section 1 with the various process names listed.   In reality
they were Sections 1,  2,  3,  and 4;  thus,  this report is labeled as
Section 5.

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                                    - 5 -
                         3.   BASIS  AND BACKGROUND


          A  number  of processes  have  been  evaluated  for  making clean fuel
 from coal  (1,2,3,4,5,6).  These  include gasification at  pressures from near
 atmospheric  in  the  case  of  Koppers-Totzek,  to  1,000  psig, for  example
 with BI-GAS  or  Synthane.  Reaction temperatures  also cover  a  range of
 from moderate temperatures  in  the  Lurgi process,  to very high temperatures
 in  the Koppers-Totzek process  with slagging of the ash.   Some processes
 such as Lurgi and Synthane  make  byproduct  char  or tar,  while others make
 no  by-products  (C02 Acceptor and Koppers-Totzek  processes).   The BI-GAS
 process avoids  making by-product char or tar,  using a  two zone gasifier
 with the upper  zone at 1700°F, while  the lower zone is at 3000°F and
 produces slag from  the coal  ash.


          As a  result of early studies, Bituminous Coal  Research concluded
 that an optimum type  gasification  process would  have the following features:

           (1)   Operation at  high pressure  to avoid the need for
                compression when  supplying pipeline gas.

           (2)   Make no char  by-product.

           (3)   No tars or liquid products would  be produced
                which  would  complicate the clean-up.

 This  led to  the concept  of a high-pressure,two zone gasifier.   Temperature
 of  the upper zone is  high enough to prevent  tar  formation, while the
 lower zone is at 3000°F  so that  residual slag  is  low in  carbon content
 and  can be discarded.  A  further advantage  of  high pressure is  that
 it  increases the amount of methane formed in the  gasifier, thereby significantly
 reducing the heat load on the  gasifier and  the gas volume to  be handled
 in  the downstream operations.

          Information  is  available in the literature on  the BI-GAS process,
 including the design  of the  pilot plant facilities (7,8   ), and projections
 of a commercial plant  design and operation  (9).   In the  present study
 to evaluate environmental aspects of  the process, we have  used  as a starting
 basis the commercial plant projections developed by Air Products and
 Chemicals, Inc.   (9).    Some modifications were made where  necessary to assure
 environmentally sound  operations, as  for example, to reduce sulfur emissions
 from coal fired furnaces.  Also,  in the course of the study, other modifications
became apparent which  could  give better environmental control  or improve
 thermal efficiency of  the process,  and these are described briefly in this
report for consideration.

          The plant  is sized to make  250 million SCFD of pipeline gas by
gasifying coal  with steam and oxygen.   The design includes shift conversion
and methanation to give a gas with a heating value of 943 Btu per cubic foot,
available at 1,075 psia.   Western Kentucky coal la used,  and after cleaning
 and washing, the amount is 14,535 tons per day (at a nominal 8.4% mois-
 ture) which provides all  of  the  fuel  for coal drying and utilities
 production in addition to the gasification requirements.

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                                     -  6  -


                           4.  PROCESS DESCRIPTION


           A flow plan of the process is shown in Figure 1,  together with
 major flow rates and operating conditions.   Coal used is shown in Table 1,
 while products are shown in Table 2.  It is convenient to subdivide
 the process into the following operations,  each of which will be described
 in the following subsections:   (1)  Coal Preparation,  (2) Gasification,
 (3) Quench and Dust Removal, (4)  Shift Conversion, (5) Acid Gas Removal,
 (6) Methanation, and (7) Auxiliary  Facilities.

 4-1  Coal Preparation and Drying

           This process section includes crushing,  cleaning  and drying as
 well as a storage pile with 30 days capacity.   Run of mine  coal feed
 amounts to 23,243 tons per day.   This  is crushed and  coarse refuse is re-
 jected amounting to 4,804 tons per  day.  The  coal  can then  be sent to
 storage,  or to the washing operation which  rejects an additional 3,904
 tons per  day.   Drained coal from  washing, containing  8.4% moisture,  is
 used partly as fuel to the utilities plant  supplying  steam  for the pro-
 cess,  while the remainder goes to the  grinding  and drying facilities.
 Here it is ground to  70% smaller  than  200 mesh,  dried to 1.3% moisture,
 and sent  to storage silos.   Some  of the  dried coal is used  as fuel in
 the dryer,  amounting  to 11,137 pounds  per hour  or  about  134 tons per
 day.

           Since  the gasifier operates at 80 atmospheres, it  is necessary to
pressurize  the  coal feed.  The original design used piston  feeders to push
the coal into a high pressure  feed hopper  and is  the system used  in the
present environmental evaluation.   Subsequent work has indicated that other
methods such as  lock hoppers   or  slurry  feeding  may  be  preferable; however.
the change would make only minor modifications in  effluents to  the
environment, although thermal efficiency would be  lower  than  for the case
using piston feeders.

4.2  Gasification

           The  coal is  gasified using steam and oxygen in a  two  zone  reactor
 at  80  atmospheres.  Operation  of  the reactor is  based on entrained flow
 rather  than using  a fluidized  bed or fixed bed reactor.   Coal is fed
 to  the top  1700°F  zone where it mixes with steam and  hot  synthesis gas
entering from  the  lower  zone.  Conditions in this  upper  zone  favor high
formation  of methane, with negligible amounts of tar  or  oil.  Although
the volatile content of  the coal  feed is completely consumed,  there  is
considerable unreacted  char remaining which is carried out  with  the  gas
and recovered by cyclones  following the reactor.

          The char  is recycled by means of lock hoppers  to  the  lower
gasification zone where  it is reacted with steam and  oxygen at  3000°F.
A special char  feeding  system is provided,  since it is indicated that
a reliable and very uniform feed rate must be maintained, so as  to avoid
conditions  that could give excessive flame temperatures.  Synthesis gas
is  formed and passes to  the upper reactor as described earlier.  Slag is
withdrawn from  the bottom, quenched with water,  and removed by way of
lock hoppers.   Since it  has little or no combustible  content, it can be
discarded  (from an energy viewpoint).

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STORAGE
30
DAYS

R.O.M. COAL FEED
1,936,899
8.4V. racist 1
(23,243 cp_d)[

TO BOILER 148 400
TO SUPHTR 31 200

1,211,256 '
\

-" BREAKER "'

WASHINC
\WA
CO
k . 946,307




1.31 MOISTURE
\
SHED
AL
/ "
CRUSH
DRY
;ROUND\
COAL \

COAL 8-4% MOIST 11,137

SILOS
10 @
800T
each

                                                                          BICAS  - PROCESS
                                 FLOWPIAN AND FLOW  RATES FOR PLANT MAKING 250MM SCFD OF PIPELINE GAS FROM W.  KENTUCKY NO. II COAL
                                                                (NUMBERS ARE LB/HR EXCEPT AS NOTED)                          1115°F
                                                                                                       RAW
                                                                                                                                                  QUENCH
                                                                                                                                                  VESSEL
 REFUSE
400,357
(4804 tpd)
                           REFUSE
                          325,286
                          (3094 tpd)
                                     SULFUR
                                     35,132
                                    (422 tpd)
             TAIL GAS
             513,287
         (Includes  4.3  tpd
          of sulfur)
                                          v '     s~\
                                       A      /O,3823
/•
 ,.„„_
 650°F   i^
 CLEANED
  WET
  GAS
                                                                                                                   68,391
PIPELINE GAS PRODUCT
  250MM SCFD
  1075 psia
   943 Btu/SCF  HHV

Vol.%  CH4 91.8%
        H,  5.1
        N2  1.9
       CO,  1.1
       CO   0.1
          100.0%
                                                                                                                                                     SAND FILTERS
                                                                                                                                                      (Back blow not  Included
                                                                                                                                                                in flow  rates)
                                                     -/

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                                - 8 -
                               Table 1
                   Coal Feed - W. Kentucky No.  11
Proximate Analysis' Wt %
Moisture
Volatile matter
Fixed carbon
Ash
Ultimate Analysis Wt. %
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen (by diff.)
As Rec'd.
8.4
39.5
45.4
6.7
68.15
4.67
1.37
3.48
7.24
Dried
1.3
42.5
49.0
7.2
73.40
5.03
1.48
3.75
7.84
Moist &
Ash Free

46.5
53.5
--
80.20
5.50
1.62
4.10
8.58
                                     84.91
                   91.50
                100.00
Heating Value




  HHV Btu/lb.
12,330
13,285
14,510
Coal Consumed




  Coal Dryer




  Gasification




  Utility Boiler




•  Steam Superheater
% Moisture




    1.3




    1.3




    8.4




    8.4
       Ib/hr




       11,137




      946,307



      148,400
       31,200

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                                 -  9  -
                                Table 2
                     Products from BI-GAS Process
Pipeline gas




  Volume, MM SCFD




  Pressure psia




  Temperature °F




  High Heating Value Btu/SCF






  Composition vol%
    N2




    co2




    CO








By product Sulfur' tpd




Slag  (dry basis)  tpd




    Gaeifier




    Dryer




    Boiler + Superheater








NH .  potential tpd




(@ 60% of N in coal)
 250




1075




  95




 943
 91.8




  5.1




  1.9




  1.1



  0.1




100.0




 422








 820




  10




 144




 974



 112

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                                 - 10 -
4.3  Quench and Dust Removal

          Hot raw gas from the gasifier passes to cyclone separators which
remove most of the char and solid particles in the gas.  Quench water is
added to the cyclone in order to moderate the temperature, and additional
quench water is added in a quench vessel after the cyclone separator.

          The quenched gas still contains some dust that was not removed
by  the cyclones, but must be removed  so as not to plug  the fixed bed of
shift conversion catalyst.  Rather  than scrub the dust  out with water,
which would require considerable cooling, the dust is  filtered out
at  high  temperature using sand beds.  These operate in  parallel in  a
cyclic manner.  Pressure drop will  build-up during the  onstream cycle,
and the  bed is  cleaned when necessary by back flushing  with  clean gas
 so as to lift  and  agitate  the  sand  particles.   Entrained dust  from  back
 flushing is  then  returned  to  the  gasifier where  it  leaves with the  slag.
 4.4  Shift  Conversion

          After dust removal,  the gas next goes to a shift converter where
 carbon monoxide reacts with steam to form hydrogen and carbon dioxide  increasing
 the ratio of H2 to CO to three to one as required in the final methanation.
 A sulfur resistant shift catalyst must be used, resulting in relatively
 low activity compared to those used on sulfur free gases.  A large excess
 of steam is maintained to give 50 mol. % steam in order to facilitate the
 desired reaction and to prevent catalyst degradation or carbonaceous
 deposits.  Steam conversion in this shift reactor is about 21L.

           After shift conversion, the gas is cooled to remove most of the

 an^n^^^
 disposed of by using itas part of the quench water  and thereby provides  steam
 required for shift conversion.  One advantage  of  this  specific design is
 that a very large quantity of sour water  can be disposed of by injecting
 ft into the hot'gas  for quenching.  A further  advantage  is that no  facilities
 are  then needed for  generating steam used in shift  conversion, and  neither
 are  exchangers needed  for  cooling  the hot raw  gas from the gasifier.

 4.5.  Acid Gas Removal

           Removal of all sulfur compounds is needed to meet pipeline gas
 specifications and to protect the methanation catalyst.  The bulk of the
 sulfur, as well as CO  , is removed using  the proprietary Benfield process
 based on hot carbonate scrubbing.  Two separate absorber towers are used
 in series.  The first of these produces a gas relatively high in sulfur
 content, about 8% H  S, to facilitate sulfur recovery in the Glaus plant.
 The second absorber  is for final cleanup  of sulfur  from the gas and for
 CO- removal.

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                                   - 11 -
          Most of the C02 is removed in this second absorber and vented
to the air;, however, this COo vent stream contains excessive amounts
of ^S, namely 3400 ppm,, and further processing is needed to clean it up.
Therefore, adsorption using molecular sieves has been' provided to recover
the H2S content and send it to the Glaus sulfur plant.  Air Products
 has  indicated, (9)  that .a Rectisol process which uses  scrubbing with refriger
 ated methanol would be  preferable for  acid  gas removal,  and that  it would
produce a reasonably concentrated stream of I^S for the Glaus plant
while at the same time giving a clean C02 stream which could be vented
directly to the air.  However,  other studies indicate that this vent stream
from a Rectisol unit requires incineration or cleanup because of excessive
content of combustibles and sulfur (5).  The Rectisol process uses methanol
scrubbing at low temperature, and can remove carbonyl sulfide and other
contaminants.  Gas leaving the hot carbonate scrubbing system used in the
present design contains moisture, most of which is removed by cooling the
gas ahead of methanation.  This is a clean condensate which can be used
for boiler feed water make-up.
          Gasification can produce many compounds in addition  to
 such as cyanides and  thiocyanates as well as  large amounts of  ammonia.
 There are also various sulfur  compounds, particularly carbonyl suicide
 and some carbon disulfide.  It is essential to completely remove all of
 these before methanation  in order to protect  catatlyst activity.
 Most of the ammonia and compounds that are highly soluble in water will
 be removed in the  condensation after shift conversion.   Hot carbonate
 systems for acid gas  removal have the important  advantage that they do
 remove carbonyl sulfide.  Amine systems, in general, do  not remove . carbonyl
 sulfide, 'and moreover react irreversibly with cyanides thus requiring purge
 of the chemical solution.

 4.6  Methanation and Drying

          Clean synthesis gas  is methanated in  this  section to increase
 the heating value  of  the  gas up to  pipeline quality.  The reaction of
 CO with 3 volumes  of  H2  to make methane  and water can be carried out  in
 a fixed bed of nickel catalyst. A  guard bed  of zinc oxide ahead of  the
 reactor removes traces  of sulfur compounds  in order  to protect the
 methanation catalyst. Methanation  is a  highly  exothermic reaction,
 releasing about  207, of  the heating  value in the reacting gases.  Reactor
 temperatures  of  500°F at  the  inlet  and  850°F  at the  outlet  are maintained
 by recirculating  some of  the  gas leaving the  reactor through  exchangers
 to generate high  pressure steam. Methanation is carried out  to a high
 conversion  so that the  residual CO  content  is no more  than  the 0.1 Vol.  70
 specified  for pipeline  quality gas.  Residual hydrogen content is 5.1 Vol. 7o.
 Since methanation generates  a considerable  amount of water,  this is
 recovered  as  clean condensate upon cooling.   More complete  drying of the
 gas is then carried out using a glycol  system to meet the  requirement
 of 7  lb water maximum per MM SCF of gas.

           For the present study the processing sequence used by Air
 Products has  been followed.   Their flow rates and utility requirements
 were reviewed and used in the evaluation of environmental aspects.

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                                   - 12 -
 4.7   Auxiliary Facilities

           In addition to the gasification system,  auxiliary facilities are
 needed to make .the plant completie and self-sufficient.   A Glaus plant is
 included to make by-product sulfur from the H2S that is recovered in acid
 gas  removal.  The basic Glaus plant will not give  adequate sulfur recovery
 or clean-up, since the feed gas will contain no more than 157o H2§, therefore
 tail gas clean-up was added.

           A conventional air separation plant is included in the base design
 to provide oxygen needed for gasification.   It does not generate contaminated
 waste streams, but it is a large consumer of utilities  and therefore has
 an important effect on thermal efficiency.

           As would be expected, the process uses large  amounts of steam
 and  electricity.  All utilities needed to make the plant self-sufficient
 are  provided in the design, including high pressure and low pressure steam,
 electric power generation, water make-up treating, circulating cooling
 water, and waste water treating.  Fuel requirement  for these has been
 been included on the basis that coal would be used for  fuel.  Since the
 coal has a high sulfur content,  pollution control  will  be  needed .on
 these fuel consumers.   The simplest  approach  is to add  flue  gas clean-up
 so that  coal can still be  used as fuel,  and a number of processes  are
 available (10).   An alternative would be to use low sulfur,  low Btu gas
 made in  the process for fuel  in utilities generation and in  coal drying.

          The particular study includes, utilities requirements for offices
shops, laboratories, and cafeteria (e.g. 50,000 Ib/hr of steam for heating'
buildings).  These are not always included in similar studies of other
processes; therefore, caution is required in making comparisons with other
studies.

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                                     - 13 -
                          5.  EFFLUENTS TO AIR
          Overall flow rates for the process were shown in Figure 1.  Figure 2
and Table 3 show all of the streams entering and leaving specific units,
some of which are returned to other units within the plant.  All streams
which are actually discharged to the environment are indicated by heavy
dashed lines in Figure 2 and by asterisks in Table 3.  For discussion these
are grouped according to whether they are released to the air  or represent
liquid and solid effluents.  Effluents to the air are discussed in the
following subsections.

5.1  Coal Preparation and Drying

          The  first effluent to  the air  is  from the  coal handling  and
preparation area.  Run  of mine  coal  is delivered by  rail and truck and
conveyed to a  breaker where it  is  crushed to  1-1/2 inches  and smaller.
Refuse amounting to 4804 tpd is  rejected at  this  point and must be disposed
of  in a suitable manner.  Such  operations will  normally have a dust problem,
and careful consideration.and planning is required for control.  Covered
conveyers should be provided wherever possible;  even so> there may  be
vent streams or leaks that could release dust.   If needed, a dust  collection
system could be used operating  at  slightly below atmospheric pressure
to  collect vent gas and pass it  through  bag  filters.  Since  spills from
conveyers and  leaks can also create dust, facilities such  as clean-up
equipment and  water sprays may be  needed.

          The  coal storage pile  is also  of concern in that wind can pick
up  and disperse fine particles.  Evaluation  is  needed for  each specific
situation in order to provide proper control  measures.  Proposals  for
dust control have been  made such as spraying  oil  or  asphalt  on the surface
of  the pile, or covering it with plastic.  The  amount of coal  handled  is
so  large that  a loss of even a  small fraction of  a percent could be
excessive.

          A further consideration  on any coal storage pile is the  possibility
of  fires and spontaneous combustion which would result in  evolution of odors,
fumes, and volatiles.   One control measure is to  compact the pile  by layers
as  it is being formed.  In any  event, plans and facilities should  be
available for  extinguishing fires  if they occur (11).

          The  next step is to wash and screen the coal, and in this operation
another 3904 tpd of refuse is rejected.  Disposal of this  refuse should
be  carried out in a way to avoid pollution.   Since it is wet there should
be  little or no dusting problem  except when it  dries out.  However,  it  can be
expected that  there will be spills of the refuse  or coal in  the coal preparation
area, and that these will create a dust  nuisance  when they dry out and are
disturbed by the wind or by trucks-  Again this calls for  plans and facilities
for cleaning up dust and for flushing to the  storm sewers.   Although a
detailed design of this coal preparation and  handling system is not available,
it  will no doubt include a tailing pond  to allow  recovery  and disposal
of  fine material from the washing  operation.  Proper environmental controls
are needed as  discussed in the  literature (12).

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                          Figure 2


                         BIGAS PROCESS
BLOCK DIAGRAM SHOWING STFAMS IN & OUT OF SPECIFIC SECTIONS OF PLANT

2345 .67
t||| j|
RUN OF
MINE COAL
"

CRUSH
AND
WASH .
CLEANED
COAL
~^

GRIND
AND
DRY

line, other streams are returm
8 9
_L _i^



GROUND
COAL


GASIFIER


QUENCH
RAW GAS & CLEANED_GAS ^-
SAND J~
FILTERS

ttf It lit n
,J il-li U » >' ""
20 21 22 23
24 25 26
1 ill! _LL
CLEANED
/GAS .^



SHIFT


COOL
SHIFTED GAS , 	



ACID GAS
REMOVAL


M
27 28


SCRUBBED GAS
•^


METH.

DRYER

^__ PIPELINE GAS



1
29
30 31 32 3334353637 383940 414243 444546
4 fc $ HI'
f I ? lit


SULFUR
PLANT



WASTE
WATER
[j III Hi \\\

TREAT.


MAKEUP.
WATER
TREAT.
COOLING UTILITY
TOWER BOILER
i J /, A ft A
TTT
47 48  49
TT
50 51
It
52 53
TTT
                             54 55 56
                                            57 58 59

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                                       - 15 -
                                     Table 3
Stream
Number
1
2
3 *
4 *
5 *
6 *
7 *
BI-GAS
Identification
Coal to gasifier
Rain runoff
tfind
Refuse
dash water
Flue gas
Spent limestone
Process - Inputs and
Flow Rate
Ib/hr
946,307
e.g. 6" in 24 hrs.
--
400,357
e.g. 4000 gpm
131,700
2,970
Effluents
Comments
Dried cleaned coal 1.37= moisture
Runoff from coal storage pile
Can cause dust nuisance
Rock waste from coal cleaning
Recirculate through clarifiers and
tailing pond for cleanup & reuse.
Vent gas from coal dryer.
(For analyses see Table 4)
From vent gas cleanup on coal
 8*     'Slag from gasifier
         Dust  recovered by
         sand  filters
10       Rain
11       Wind
      68,391
e.g. 6" in 24 hrs.
12
13
14
15
16
17
18
19
Wash water
Air
Limestone
Steam
Oxygen
Quench water
Sand
Quench water
e.g. 4000 i
122,700
2,500
409,719
497,625
68,270
--
1,254,87
dryer, e.g. spent limestone
plus ash from coal fuel

Plus equal wt.,of water to fo.rm
slurry for handling

Returned to gasifier by back :
blowing with part of cleaned gas,
e.g. 5% of total gas

Rain on coal storage and handling
area

Wind effect on coal storage and
handling area

Used to clean crushed coal

For burner on coal dryer

Raw materials used for stack gas
cleanup

To gasifier to react with coal

Oxygen to gasifier to generate
heat

To quench 3000^ slag—steam Is
returned to gasifier

Makeup to sand bed filter

Quenches 1700"F raw gas from
gasifier, includes sour water

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                                      -  16 -

                                Table 3  (Cont.)

                         BI-GAS Process - Inputs and Effluents
Stream
Number       Identification

  20       Sour water



  21*      Chemical purge



  22       H2S stream


  23       H2S (pure)


  24*      C02 vent stream


  25       Water

  26*      Water reject


  27       Chemical makeup




  28       Molecular  sieve


  29       Glycol

  30*     Tail  gas


  31*     Sulfur

  32*     Purge chem.


  33*     Ammonia
   34       H2S
35*      Phenols
                                    Flow Rate
                                      Ib/hr

                                     866,613
                                  e.g. 50,000



                                     451,429


                                       3,825


                                   1,147,115


                                      214,818

                                      27,219
                                      513,287


                                       35,132




                                       7,689


                                      e.g. 87
           Comments

Condensed from raw gas,  contains
H2S. NHo etc.  Is returned to
Quench  (#19 above)
Purged to reject contaminants from
acid gas scrubbing solution.  Will
contain potassium carbonate

Acid gas sent to Glaus plant for
sulfur recovery (6.9 vol. 7« H2S,
44.7 vol. % C02, 48.4 vol. % H20)
To Glaus plant.  From molecular
sieve recovery on C02 vent gas.

From acid gas removal (mol. sieve is
used to control sulfur emission).

Formed by methanation reaction

Removed by glycol dryer on product
gas

Makeup  chemicals to acid gas removal
system.  Will include K^CO-j and
possibly inhibitors, antifoam
agents, etc.

Makeup on sieve to clean  up C02
vent  stream

Makeup agents  to  glycol  dryer

From  sulfur  plant after  tail gas
cleanup

By-product sulfur recovered

From  tail gas  cleanup  operation,
purged  to reject  contaminants

Potential by-product separated in
waste water  treating

Stripped out of sour water and
sent  to  sulfur plant.

Potential by-product or  to disposal
 from waste water treating --  amount
unknown

-------
                                        -  17  -
Stream
Number

  36
  37i
  38
  39*
                                   Table 3  (Cont.)

                         BI-GAS Process  - Inputs  and Effluents
  Identification
Treated water
Sludge



Makeup water


Chemical waste
   Flow Rate
     Ib/hr

     86,000
  see Table 13
   3,489,000
                                      see  Table  13
            Comments.

Water  after, treating.   A  small
stream of  sour water will probably
have to be purged  to reject  conta-
minants and trace  elements from
the  system.   Further information
is needed  to define cleanup  require-
ments.

Sludge formed in waste  water treating,
e.g. from  biox,misc. solids.  May  have
odor problem: Should be incinerated.

To cooling tower and boiler  feed
water

Chemicals  used in  treating makeup
water
  40*
Sludge
41*
42*
43*
44*
45*
//:*
46
47
48
49
50
Air
Water mist
Water
Flue gas
Slag
Spent limestone
H2S stream
Air
Chemical
Sour water
 51
Chemicals
  see Table 13


 272,000,000
 (85  MMM SCFD)

 e.g. 263,000

ca. 600,000

    1,971,000

       12,033



       44,530


      455,254

       93,165



  e.g. 86,000



  see Table 13
 Sludge  formed  in  treating water
 makeup  with  lime, alum., etc.  can
 be disposed  of with  slag.
Air flowing through cooling tower
 (plus evaporated water 2,626,000 Ib/hr)
Drift loss from cooling tower
 (0.2% of circl.)
 Slowdown1from  cooling  tower

 From utility boiler  (see Table 4).

 From coal used as fuel on utility
 boiler  (may  dispose  of with gasifier
 slag)

 Used to desulfurize  flue gas on
 utility furnaces

 To sulfur plant for  recovery (Streams
 22 and  23)
 Used in Claus  plant  to burn H  S

 To tail gas  cleanup  on Claus plant.

 Purge of  sour  water  may be required
 to prevent build up  of trace elements
 etc. in recirculated sour water.

 As required  to clean up purge
 stream  of sour water.

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                                       - 18 -

                                   Table 3  (Cont.)

                          BI-GAS  Process -  Inputs  and  Effluents
Stream
Number       Identification

  52       Makeup water



  53       Chemicals



  54       Air

  55       Cooling water

  56       Chemicals



  57       Air


  58       Coal


  59       Limestone
 Flow Rate
   Ib/hr

 3,489,000
 see Table 13


272,000,000
(85 MMM SCFD)

262,580 gpm

 see Table 13



  1,837,000


    179,600


     37,500
           Comments
Treated and used as makeup for
cooling tower and boiler feed
water

Used to treat makeup water, e.g.
lime, alum, caustic, acid, ion ex-
change resin

Air flow through cooling tower

Recirculated cooling water

Antifouling (e.g. chlorine) and
anticorrosion (e.g. chromate)
agents in cooling water circuit.

Combustion air used in utility
furnaces

Coal fuel used in utility boiler plr
superheater (8.4% moisture)

Used for stack gas  cleanup on
utility  furnaces
  *  Streams emitted :to the environment.
     Other streams are returned to process.

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                                   - 19 -


           Noise  control  should  be  carefully considered  since  it  is  often a
 serious  problem  in  solids handling and size reduction.   If  the grinding
 equipment  is within a  building,  the process area may be  shielded from
 undue noise, but additional  precautions are needed  for  personnel inside  the
 building.

           Following the  washing operation,  cleaned  coal  is  sent  to  the
 crushing and drying system   and also to the utility areas as  fuel.  Adequate
 dust  control is  needed on all these handling operations.  In  the dryer,
 moisture content is reduced  from 8.4% to 1.37» by contacting with hot
 flue  gas.  Heat  is  supplied  by  burning part of  the  dried coal.   Since this
 fuel has 3.75% sulfur,  corresponding to 5.64 Ib SC>2 per MM Btu,   it will
be necessary to  clean  up the vent gas  to remove sulfur as well as particulates.
It will be desirable to recover and use the coal fines,  for example, by
using dry cyclones,  then sulfur in the  flue gas can be removed by one of
 the processes that are offered  for stack gas clean-up (13).   Some of these
have proposed to use a throw-a-way limestone medium, while others provide
 for regeneration of a  chemical  scrubbing agent to make by-product sulfur,
 sulfuric acid,  or gypsum.

          In the drying operation a large volume of hot gas is contacted
with the coal.    Oxygen content  is normally  limited to about 10 Vol. "/„
by safety considerations.  Also the maximum temperature should be limited
 to avoid heating the coal above 500°F,  so as not to release volatile matter.
 It is common practice  to use a  large amount of excess air,  such  as 10070,
 in order to minimize moisture content  of the drying gas and thereby
 facilitate drying.  In some  cases effluent  gas may be recycled or inert
 gas added to control gas temperature and oxygen content.

          With the present high  price of fuel, the design of drying facilities
 should be reconsidered and optimized to minimize fuel consumption.  This
 subject is discussed more fully in a previous study (4).  In brief, it is
 desirable to operate the dryer with minimum excess air,  for example 107,
 excess, and to recycle vent  gas as needed to control temperature  of the
hot gas.  This gives minimum fuel consumption as well as minimum volume
 of vent gas to be cleaned up.   Of course, the moisture content of the
 drying gas will  be higher than when a  large amount of excess air  is used
making it more difficult to  achieve the same degree of drying, although
 the moisture content of  the  dried coal  could be allowed to  increase slightly.
 Further details  on  flue gas  composition are given in Table 4 and  accompanying
 notes.

          In general,  it will be desirable  to maximize the preheat temperature
 on the coal feed, and  to preserve this  sensible heat so as  to reduce heat
 load on the gasifier and reduce oxygen requirement.  Preheat temperatures
 as high as 500°F have  been used without substantial evolution of  volatile
 matter from coal.   This  temperature has also been considered practical from
 the standpoint of using  lock hoppers.

          The coal  feeding system  for  pressurizing  the coal in this specific
 design is based  on  a piston  feeder  as  originally proposed.  Storage silos
 are also included.   Normally there  will be  no effluent to the air from this
 system, although it may  involve pneumatic transport of coal,in which  case

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                           - 20 -
                           Table 4

           Flue Gas Flow Rates and Composition
           From Boiler Plus Steam Superheater
Fuel Fired (Alternatives)

Fuel Ib/hr
Air Ib/hr
Flue Gas Ib/hr
Flue Gas Comp.  Vol-  °/°

    C02
    H20
    S02
    N2
    02
                                Coal
         179,600  (8.4% Moist)
       1,837,000
       1,971,000
       (586 MM SCFD)
Low Btu Gas

 132,663
                                                   ,
                                                  (562 MM SCFD)
 NOTES :

 (1)  Sulfur contained in above coal amounts to 6,250 Ib/hr, and
      flue gas cleanup must be provided.  Using limestone scrubbing,
      for example, would require 37,500 Ib/hr of limestone, at
      twice the theoretical consumption.

 (2)  On coal dryer, flue gas composition from combustion of coal
      fuel will be similar to above.  In addition, moisture amounting
      to 74,212 Ib/hr is removed from coal, giving a total  of 5I/c
          in vent gas.
  (3)  Ash  from coal used  for  fuel to be disposed of:
Coal dryer
Boiler plus Superheater
                                                 803  Ib/hr
                                              12,033  Ib/hr
  (4)   High heating values are:  12,330 Btu/lb for coal,  and 16,695
       Btu/lb for low Btu gas.

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                                  - 21 -


 recovery and clean-up of the conveying gas is needed.  In the event-that
 lock hoppers are used instead of  the piston feeder, then there will be.
 considerably more vent gas from depressuring the hoppers which should
 be cleaned-up and returned to the system.  A promising way to reduce the
 volume of gas from the lock hopper operation  is to use pressure stages
 so that the highest pressure gas  from the final stage can be used to
 pressure the initial lock hopper  stage to an intermediate pressure level.

           Instead of using stack gas clean-up on the coal dryer for sulfur
 control, it would be possible to use part of the low Btu product gas for
 fuel.  Dust removal- on the vent gas could then be by bag filters or a
 scrubber.   This route would,  of course, call, for an increased capacity
 on the gasification system.

 5.2  Gasification

           In normal operation there will be no effluents to the air from
 the gasification section, since all of the gas streams are contained and
 processed in downstream equipment.

           Slag formed in the  lower zone of the gasifier is quenched with
 water and  the resulting steam flows back up into the gasifier.   Quenched
 slag is removed by way of lock hoppers.  It is handled as a water slurry,
 and reliance is placed in the shattering effect of the quench to control
 particle size of the slag and provide a slurry that can be handled.  Typically,
 the slurry may contain equal  weights of slag and water.  Depending on the
 final disposition of the slag slurry, there may or may not be a dust problem.
 For example,  if it is used as land fill or if it goes to a storage pile,
 there could be a dust problem when it dries out.  The possibility of odors
 needs to be defined for the handling and disposal system.   Also, other
 emissions will occur  and need  to be defined.

 5.3  Quench and  Dust  Removal

          Raw  gas  leaving  the  gasifier  goes  through cyclones  to  recover
 entrained dust or  char, which  is  then returned  to  the  lower  stage  of  the
 gasifier by means  of  lock hoppers.   It  should be possible  to  contain  this
 system  and  the pressurizing gas so that  normally there  will be no  emissions
 to  the  air.

          After  quenching, the gas goes  through  sand bed filters in parallel
 to  remove dust.  These filters are cleaned by back  blowing with part of
 the synthesis gas, and this dusty  stream is returned to the gasifier for
 disposal  and thereby contained within the system.

          Normal maintenance will be  needed on the  sand filters and possibly
also as a result of upsets.  Precautions are needed to control emissions
 to the air during such periods, for example, in  cleaning or replacing
the sand  and on depressuring the equipment.  Gas released on depressuring
should be recovered and returned to the system.  Similar comments apply to
the lock hoppers and other parts of the process with regard to depressuring
and maintenance.

-------
                                  -  22  -
 5.4   Shift Conversion

          Shift conversion does not generate gaseous effluents, but
 a large amount of water is condensed following the shift converter and ahead
 of acid gas removal.  This water will contain ammonia, l^S and possibly
 small amounts of other materials such as cyanides, phenols, etc.} if these
 are formed in gasification, or during startup or upsets.  The sour water
 will have a very strong odor and care must be taken to avoid possible
 leaks or spills.  Normally, it will all be returned to the process and
 used as part of the quench water ahead of the sand filters  in order to
 dispose of it without causing emissions to the air.  A nominal amount of
 sour water storage capacity would be desirable  to assure that none will
 have to be discharged during start-up or upsets.

          While not directly associated with effluents to the air, it
 should be pointed out that the closed system for handling sour water
 and disposing of it by total recycle  may have to be modified.  Compounds
 such as ammonia, phenols, etc., will be removed rather completely from
 the gas during condensation and recycled to the quench point.  Since
 they are not destroyed in quenching, they will build-up in concentration
 in the circulating sour water stream,  so that facilities may have to be
 added to separate them and purge them from the system.  A similar situation
 can occur with volatile trace elements.  This subject is discussed further
 in Section 6. EFFLUENTS - LIQUIDS AND SOLIDS.

 5.5  Acid Gas Removal

          This system removes sulfur compounds such as l^S and COS as
well as C02,  using the proprietary Benfield process (14).  It uses a
hot solution of activated potassium carbonate in two separate absorber
 systems in series.  The first of these produces an acid gas stream with
 a relatively high content of H2S,   which is sent to a Claus sulfur recovery
 plant.  There should be no specific emissions to the air from this first
 scrubbing system.

          In the second step residual sulfur is removed together with most
 of the C02,  producing a gas stream which is discharged to the atmosphere.
A further description of this acid gas removal operation is given in
 Reference (9), which points out that the sulfur content of this C02 stream is
 3400 ppm and will require additional processing to clean it up before
release to the atmosphere.  One method is to use molecular sieves to adsorb
 the H2S which is then desorbed and sent to the Claus plant,  and this provision
 is included in our environmental study.

          The use of molecular sieves was said to be quite expensive, but
other techniques are available for consideration.   One possibility is
 to use an absorption/oxidation type process to remove l^S from the C02
vent stream.   I^S would be oxidized using an activated scrubbing liquid
 to form free sulfur which is separated as a by-product.  Such processes
are offered for commercial use by Stretford,  IFF,  and Takahax (15).
Subsequent to the original study,  Air Products indicated that the Rectisol
process which uses methanol scrubbing at low temperature would be better

-------
                                   - 23 -
for acid gas removal in this application.  However, results from plant
operation (38) and from planning studies (37) show that the CO- vent
stream from Rectisol also has an unacceptably high sulfur content.  More-
over, it contains over 1 vol % combustibles including ethane, ethylene,
methane, and carbon monoxide.  Incineration of this vent gas is necessary
from the standpoint of odors, combustibles, and H_S content (3,5).

          Since flue gas desulfurization is used elsewhere in the process,
on the coal drier and utility boiler, it may be that this CC>2 stream could
be blended in and cleaned up with incremental additions to the flue gas
desulfurization system.

          This particular BI-GAS design does not use air-fin cooling; instead,
all of  the waste heat  is transferred  to  cooling water.  However,  in many
applications  the design will use air-fin cooling in  order  to minimize  the
load on  the cooling  tower and  the water  make-up requirement.   In  such  cases
careful  consideration  must be  given  to potential emissions  to  the air.
With air-fin  exchangers, a very large volume  of air  is  passed  over the exchanger
surface, and  in the  event of leaks or tube  failures, a  considerable amount
of material can be dispersed in the  air, causing serious emissions to  the
atmosphere.   This can  be more  of a problem for operations  at very high
pressure, as  at 1000 psig, and on contaminated streams  such as  sour water.

          The problem  is not avoided by  using cooling water, since any
leakage  will  be into the cooling water which  then  flows through the  cooling
tower where it is efficiently  stripped by  a large  volume of air.

5.6  Methanation and Drying

          After acid gas removal, the gas  is  reheated,  passed  through  a
sulfur  guard  bed, and  then  to  the methanation reactor.   The system is  all
enclosed, hence there  should be no major effluents to  the  air.   However,
there is considerable  equipment that can be expected to contribute miscellaneous
emissions,  including:

           -   Exchangers  that may  leak or fail.
              Recycle gas compressors and valves.
           -   Circulating cooling water.

Leaks can  be  expected  from  such equipment  operating at 1000 psig, especially
 from seals.   Methods have been developed for estimating the amount of
 leakage in oil refineries,and  techniques for monitoring and reducing
emissions  have been carefully  considered (16).   Such background should
be  applied in designing gasification plants so as  to minimize  potentially
undesirable emissions.

           Clean  condensate  is  recovered after methanation, and when this
 is  depressured,  some gas will  be  released which  should be  recovered or
 incinerated.   Water is also separated in the final glycol  drying step,
 and should be recovered rather than being released to the  atmosphere.

-------
                                  -  24 -
5.7  Auxiliary Facilities

          One of the auxiliary facilities associated with the process is
the Glaus plant to recover sulfur.  The acid gas containing sulfur compounds
is first burned with added air to form free sulfur which is condensed and
recovered.  This is followed by additional stages using a catalyst .to allow
operating at lower temperature so as to increase the sulfur recovery.  A
typical value for sulfur recovery may be 977, in a three-stage operation,
provided the feed gas contains 20% or more of I^S.  This would still give
excessive sulfur emission in the Glaus plant tail gas, amounting to about
25 tpd of SC-2 for this case.  It is, therefore, necessary to add tail
gas clean-up, and this modification has been included in pur balances
and calculation of thermal efficiency.  A number of processes are offered
commercially for such tail gas clean-up (17).

          One other consideration on the sulfur plant'is to control odor
emissions due to leaks or associated with handling the .product sulfur.
There is an appreciable solubility of H2S in molten sulfur, and it may
escape during handling or storage; however, there are well established
techniques for controling this and other possible sources of contamination
such as sulfur dust.

          The plant producing oxygen-for gasification is'relatively clean,
and the major effluent to the air is waste nitrogen.  The operation is
conventional and is hot expected to emit undesirable compounds or odors.
It is, of course, a large energy consumer and so affects the size of the
utilities system, and contributes significantly to the total amount of .
waste heat that must be dissipated from the process.

          Perhaps the major source of contaminants emitted to the air is
the utilities system which includes steam generation, power .generation,
cooling water, treating of make-up water and waste water,  as well as
miscellaneous items such as utility air and instrument air supplies.  Coal
is used as fuel in the boiler and steam superheater.;  It has a high sulfur
content corresponding to 5.64 Ib  of S02 per MM Btu   vs. an allowable
value of 1.2 for large stationary boilers.  Consequently,  control measures
such as flue gas clean-up will be needed.  A sulfur removal of 807» would
be sufficient, and this level of desulfurization has been achieved or
exceeded by many of the processes offered for commercial use.  In addition,
control of fly ash emission is required when burning coal.  For this case
an ash removal of 98.167, is needed in order to meet the target of 0.1 Ib
of dust emission per MM Btu's.  This level of removal has been obtained
with flue gas scrubbing.

          Instead of burning coal, it would be possible to use part of .the
low sulfur, low Btu gas made in the process as fuel  in order to limit
the .emissions of sulfur and dust.  This would consume a sizeable part
of the total raw gas since the boiler fuel consumption corresponds to 16.47,

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                               - 25 -
of the gas production, while the steam superheater consumes  an additional
3.4%.  There is also a loss in efficiency, since gasification to make
low Btu gas has an estimated thermal efficiency of 77%,  whereas flue
gas desulfurization is indicated to have a considerably higher efficiency (95%).
For any specific case, these alternatives need to be considered and evaluated,
including credits for the gas fuel route which may result from using a
combined cycle wherein the gas is first burned in a flue gas turbine to
generate power, and is then used in a furnace for steam generation.

           Emissions  of NO  must  also  be defined  and  controlled  in  a  speci-
 fic  application of  the process.   The  amount  will depend  on  the  furnace
 design,  use  of staged combustion,  fuel nitrogen  content, etc.   In  general,
 NO  production can be decreased  by designing for a  lower flame  temperature
 an?  by  using low nitrogen fuel.   Low  Btu fuel gas is attractive from these
 standpoints.   Processes  are being developed  to remove NO  from  flue  gas,
 and  a satisfactory progress will probably be available  soon.

          The flow rate and composition of the flue gases from the boiler
for burning either coal or low Btu  gas were  compared in Table 4.  Including
the steam superheater furnace, the volume of flue gas from the utilities
area is more than twice the volume of pipeline gas produced.

          As is true  for many other gasification processes,  by far the
largest effluent to the air is from the utility cooling tower.  Flow of
air through the cooling tower is  85,000 MM SCFD.   In addition, there is
a drift loss due to mist carried out by the  air.  A  typical estimate of
this would be about 263,000 Ib/hr, although  it could be reduced considerably
by using some of the  newer techniques that are being  developed to control
drift loss from cooling towers (18).  Drift  can cause deposits  in  the
nearby area due to dissolved solids in  the cooling water.  Careful consideration
should also be given  to the potential  fog problem or plume associated
with cooling towers due to condensation under unfavorable atmospheric
conditions.  One way  to avoid the  plume  is to provide reheat  on the  air
leaving the cooling tower, but this will not normally be warranted.  It
may be that these problems  can be  taken care of by proper design and
placement of the cooling  tower.

          Normally, there will not be  contaminants introduced into the
cooling water  circuit that might be stripped out by  the air flowing  through
the cooling  tower.  However, experience has  shown that  leaks  can be  expected
in exchangers used in cooling water service, especially at high pressures
such as the  1000 psig in  this process.  Leaks, for example, in  exchangers
on sour water  service could  introduce  sulfur,  cyanide and ammonia  into
the cooling water, which would then be  stripped out  into the  air.  Special
precautions  and  possibly monitoring equipment may be needed from this
standpoint.

          The volume  of air  passing through  the  cooling  tower is so  large
that every precaution should be  taken  to see that it does not inadvertently
become contaminated.  For  this design,  the air flow  is  about  85,000  MM CFD,
or roughly 340  times  the  volume  of pipeline  gas  produced, and is by  far
the largest  gas  stream released  to the  environment.

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                                   - 26 -


                      6.   EFFLUENTS  -  LIQUIDS AND  SOLIDS
           Emissions to the environment of liquid and solid effluents will
 be discussed in the order in which they appear on the flow plan of Figure 1.
 Individual streams are identified on Figure 2 and described in Table 3.

 6.1   Coal Preparation

           A first and major effluent is the refuse from coal preparation
 and cleaning.   This includes the rock and gangue delivered with the run
 of mine coal.   Such refuse is separated and rejected after the first breaker,
 which crushes  run of mine coal.   Additional refuse is separated in the
 washing operation.  These streams amount to 4,804 and 3,904 tpd respectively
 and will contain some coal as well as pyritic sulfur. They are therefore
 subject to oxidation and leaching, can cause pollution problems similar
 to acid mine water, and should be reviewed and considered from this standpoint
 (28).

           The  refuse might be returned to the mine or used as land fill
 provided the potential problems  of secondary pollution are evaluated and
 controlled. The enormous magnitude of this effluent stream is illustrated
 by the fact that it amounts to over 860 acre feet per year of refuse to
 be disposed of.   It is obvious that very careful and thorough planning
 will be necessary to avoid unexpected problems due to pollution from leaching
 of acid or soluble compounds and metals, or from dust.

           In the washing operation, wash water will be sent to a settling
 pond where fines will be removed so that the water can be reused.   Disposal
 of.these fines,  or tailings,  must be provided for.  Handling of the fines
 will call for  special precautions, since if they are spilled on the ground
 they can dry out and then become dispersed by the wind or by trucks using
 the area.  The system should be  designed for complete recycle of the
 wash water so  that there is no water effluent from the operation,  which
 would present  a difficult clean-up problem from the standpoint of dissolved
 and suspended  materials.

           Leaching, or seepage,  through the bottom of the tailing pond
 should also be controlled.  In a heavy clay-type soil this may not be
 a problem; however, in sandy soil it may be necessary to provide a barrier
 which might be a layer of plastic or clay.

           A further consideration on the coal preparation area is with
 regard to the  coal storage pile.  The design includes 30 days' storage,
 or about 700,000 tons; so the coal storage pile will cover a very large
 area.   Rain runoff  can lead to  undesirable effluents.  A large part
 of the rain can run off quickly  and carry suspended particles, while
 the remainder  will have a long contact time with the coal and can pick
 up acids and organics.  Therefore, rain  runoff from the storage area
 should be collected in storm sewers and sent to a separate storm pond.
 With a certain amount of treatment, this water can then be used as make-
 up for the process.  Control of  seepage may be desirable on the pond,
. and particularly on the coal storage area, using for example, a layer
 of concrete, plastic or clay.

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                                 - 27 -
          Other effluents from the coal preparation area are associated
with coal drying.  Coal fines that are picked up by the drying gas should
be.recovered by bag filters, or scrubbers and returned to the process.
In addition, where coal is used as fuel on the dryer there will be by-
product ash to be recovered and disposed of.  It might be included along
with the refuse from coal cleaning, or it could be combined with the
slag from gasification and disposed of as land fill.

6.2  Gasification

          Coal feed is reacted with steam and oxygen at high temperature
and about 80 atmospheres pressure in the gasifier.  The major effluent.
from this section is the slag formed from ash in the coal.  Essentially,
all of,the ash in the feed is rejected here, after having been fused in
the lower zone of the gasifier which operates at 3000°F.  Molten slag
is quenched in water and thereby shattered  to form a slurry which is
then depressured using lock hoppers for removal from the high pressure
system. The slag should be relatively sulfur free and unreactive,  having been
fused at high temperature.  Also, it contains little or no carbon and
therefore  can be discarded.  For handling, it can be mixed with an equal
weight of water to form a slurry.  This water will pick up dust from the
slag, and can leach out soluble salts and metals; therefore, it should
be collected and reused so as not to become an effluent from the plant.
The ash slurry might be dewatered for disposal in the mine and the water
sent to a holding pond for reuse.

          Production of dry slag is 68,391 Ib/hr, corresponding to about
90 acre-ft.  per year; consequentlyAdequate provision for disposal is needed.
The other major stream leaving the gasifier is the raw gas product.  It
contains a large amount of char which is blown out of the gasifier and
recovered in cyclones for recycling to the lower zone of the gasifier.
No other streams are normally released to the environment from the
gasification section.

6.3  Quench and Dust Removal

          A large part of the coal feed to the gasifier is blown overhead
since the reactor operates at high velocity and with high entrainment.
This char is separated in a cyclone where quench water is introduced.
The recovered char goes to lock hoppers and a feeder which returns it to
the lower zone of the gasifier.   Except for leaks and maintenance,  there
should be no emissions fromi these facilities.

          The raw gas is further quenched with sour water in a quench
vessel ahead of the sand bed filters.   These filters operate in parallel,
and when the pressure drop builds up,  one unit is cleaned by back blowing.
Dusty gas from the backblowlng operation is returned to  the  gasifier.   The
cleaned sand filter is then placed back in service.

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                                   -  28  -
          An  important  feature  of  the  sand bed  filters  is  that  they  provide
 dust  removal  at high  temperature,  such that water  does  not have to be
 condensed.  This  is a major  advantage  when using a sulfur  resistant  shift
 catalyst  so that  shift  conversion  is carried  out before the  raw gas  has
 been  cooled and the moisture condensed out.   Thus,  the  steam required  for
 shift conversion  is provided partly by residual steam leaving the gasifier,
 together  with sour water which  is  introduced  as quench.  This arrangement
 provides  a convenient and  effective way to dispose of sour water.

          Ash removed by the sand  filters will be  returned to the lower
 gasification  zone and  can leave with  the slag.  However,  there will be
 some  volatile components,  such  as  arsenic and zinc compounds etc., that
 will  be revaporized and carried up with the gas.   They  can then condense
 again and be  caught by  the sand bed filters.  It will be seen that this
 constitutes a system  with  total recycle, with no way for certain materials
 to  escape.  Therefore,  it  may be necessary to provide a purge stream in
 order to  remove such  materials.  For example, part of the  dust  recovered
 by  the sand bed filters could be removed for  disposal.  The  composition
 and nature of this stream"cannot be estimated at this time,  neither  can
 the amount be predicted.   The required information should be obtained  during
 operation of  the  pilot  facilities.

          Similarly,,  it may  be  necessary to provide a purge  stream,  or
 separation system, on the  sour  water if certain chemical compounds or
 trace elements tend to  recycle  and build up in concentration.

 6.4   Shift Conversion

..       .As  pointed  out,  shift conversion is carried out before sulfur
 has been  removed  from the  raw gas.  Therefore, a sulfur resistant shift
 catalyst  is required, and  these normally have lower activity than catalysts
 which are used on sulfur free gas.  Steam in  the entering gas is adjusted
 to  give about one mole  per mole of dry gas.   Steam conversion in the shift
 reactor is about  27%, while  62% of the CO entering is reacted.

          After shifting,  the gas  is cooled to condense out  most of  the
 remaining moisture, which gives  866,613 Ib/hr  of sour condensate. This water
 will,  contain  l^S  and  other sulfur  compounds as well as  ammonia  and probably
 traces of phenols, cyanides,  etc.  that are present in the gas.   This
 sour  water can all be disposed  of by recycling to  the process to provide
 part  of the quench required  at  the outlet of  the gasifier.

          In  this particular BI-GAS design,  the amount  of  water consumed
 in  the shift  reaction is 385,630 pounds per hour so that this much unreacted
 water in  the  gases leaving the  gasifier could be disposed of without having
 a net production  of sour water  from the process.   In addition there  is
 68,270 pounds per hour  of  water used for quenching the  slag,  and perhaps
 this  could be an  additional  consumption of sour water.

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                                  - 29 -
          It should" be pointed out that compounds such as ammonia and
phenol will dissolve in the sour water and be recycled through the quench.
Of course, quenching does, not actually destroy these materials, although
they might be'destroyed in the shift reactor, -and this is a distinct
possibility which would be worthwhile to explore.  If they cannot be
destroyed then -it will be necessary to provide a purge stream, which is
further processed to separate compounds that build up in the recycle
stream.  For example, ammonia and phenol could be separated and taken .
off as by-products for sale or for incineration.  Trace elements that
are volatilized in the gasifier,  such as arsenic, boron, lead, etc., may
also tend to build-up in the.' circulating, sour water stream and have to
be removed and disposed of.  This subject is discussed further in
Section1 10'- TRACE ELEMENTS.

          One possible modification is to provide stripping on a portion
of the recycle sour water stream so as to remove volatile materials -such  .
as ammonia.  In the case of less volatile soluble materials such as phenols,
these will tend to build up and it may be necessary to add an extraction
step to separate them and remove them from the system.  It is possible
that contaminants may be destroyed in the shift conversion reactor by
hydrogenation as a result of the large amount of hydrogen present.  Further
exploration of this possibility would be desirable.  Oxygenated compounds
might -also be destroyed, and perhaps the rate of the ammonia equilibration
reaction would be sufficient to control the concentration of ammonia to
an acceptable level.   'On the other hand, such recycling might undesirably
increase 'the concentration of some materials such as cyanides and thiocyanates.
Obviously, more information is required to define the situation.

          While this particular design of the BI-GAS process does not show
liquid or solid effluents or by-products from this section of the plant,
further clarification and information is needed from pilot plant operations
regarding contaminants such as ammonia, cyanides, phenols, etc., that may
be formed in gasification and tend to concentrate in the recirculated
sour water.  They will either have-to-be destroyed in the recycling
operation  or removed from the system by using appropriate separation
technique's.  Ammonia is of particular -concern since in many gasification
processes about 607, of the nitrogen in the coal is converted to ammonia.
It is relatively easy to separate and remove as a valuable by-product, and
for this design the production of ammonia could be of the order of 100
tons/day.

          Other trace materials may be much more difficult to separate
and dispose-"of.  For example,  it is known that many trace elements will
volatilize to a considerable extent during gasification.  Such, elements
include mercury, arsenic,  antimony,  cadmium, zinc, fluorine, boron etc.
and many of these can be quite toxic.  To some extent, they may be removed
by the sand filters and thereby returned to the gasifier.  However, it
is unlikely that they will leave with the molten slag, and therefore
may recycle between the gasifier and sand filters and build up in concentration.

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                                - 30 -
If this happens, perhaps they could be removed by purging some of the
dust recovered on the sand filters to a separate metal recovery system.
It is also likely that some of these metals will pass through the sand
filters and show up in the sour water stream.  Since this is also recycled
completely, there is no place for such metals to leave the system;
consequently*they will build-up in concentration in the recycled sour
water stream.  Again, it may be that part of this stream could be
processed to separate and recover such materials.

          In any event, it is apparent that provisions will have to be
made for removing from the system materials such as trace elements that
are volatilized in the gasifier.  It is most important to obtain the
additional information needed in this area to define the problem and
proper controls.  The amount and nature of the trace elements leaving
the gasifier 'should be carefully determined during pilot plant operation,
so that environmental aspects can then be properly evaluated.  This is
one area where additional information is urgently needed.

6.5  Acid Gas Removal

          The acid gas removal system is intended to remove sulfur compounds
as well as CC^, prior to methanation.  Amine scrubbing is commonly used
for this purpose but is not effective on removing forms of sulfur other
than H-S,  such as COS and CS2 which may be present.  Other techniques
may use hot potassium carbonate scrubbing  or absorption with refrigerated
methanol  both of which are effective for removing carbonyl sulfide.
Another route is to use absorption/oxidation systems where the HoS is
reacted directly to free sulfur, which is then separated as a by-product.
This type of system is offered by Stretford, Takahax,  IFF and others,
but may not give adequate removal of COS,etc.  Of course, a separate system
is then needed for C02 removal.

          This particular BI-GAS design uses the  Benfield hot carbonate
system to provide two separate gas streams.  One of these is relatively
high in H2S content for processing in the sulfur pliant, while the other
is a C02 stream relatively low in sulfur to be vented.  There are no
major liquid or solid effluents from this operation; however, it is necessary
to purge a small amount of the scrubbing solution since certain contaminants
build-up and interfere with the operation.  The amount and composition of
this purge have not been given, but it probably contains an appreciable
amount of potassium carbonate, and might be disposed of by neutralizing
it with sulfuric acid that is used in the water treating system for
regenerating ion exchange residence.  It might also be processed for
recovery.  Some suitable disposal needs to be defined.

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                                 - 31 -
          One  complication  that occurs  in all processes where coal.is
gasified with  oxygen  results  from the  formation of carbonyl sulfide in
the gasifier.   it  generally results  in  complications  and  limits  the
choice of processes for acid gas  removal, since carbonyl sulfide  is not
removed adequately by conventional amine scrubbing.  An interesting
possibility  is  to  react COS  with  steam  over a catalyst at  moderate
temperatures so as to convert  it  to  H2S, which can readily be removed.
It has been  shown  that catalysts  such as alumina will promote this
reaction (19) .   Possibly, COS  conversion could also be carried out in
the shift reactor  or in a  separate  bed of suitable catalyst.

          The  scrubbing towers of the acid gas removal system will no
doubt be very  effective for removing trace amounts of dust or other
materials which have not been  separated by the  upstream -processing.
Such materials  will also accumulate  in  the scrubbing solution and may '
have to be separated and purged.  In some other processing schemes, filtering
of the scrubbing solution has  been included to separate solid particles
which are then  rejected from the  system.  Depending on the nature of
such materials  they might be disposed of along with the slag from gasification
or possibly  processed for recovery.

          Again, it should  be  pointed out that certain trace elements
will be volatile to some extent in the  gasifier and will be carried out
in the raw gas.  These must show  up  in  the downstream processing, where
they will be separated out.  The  amounts can be very significant.  For
example, a concentration of only  10  parts per million in the entering
coal corresponds to a total of 240 Ib/day, a large part of which  may
volatilize in  the  gasifier.  Since there are a large number of elements
to consider, the total  amounts  to  be  disposed of can be very formidable,
particularly if they are toxic,- as is the case for many volatile  elements.
Information  is  needed on where they  will appear, and in what form, so
that the situation can be evaluated  and proper control  measures  included
as required.

606  Methanation and Drying

          Following acid gas removal}the gas is quite clean and should not
contain significant amounts of undesirable contaminants.  Methanation
produces 214,818 Ib/hr of water,  which  is condensed and is suitable for boiler
feed water make-up.  The large heat release in the methanation reaction is
used to generate high pressure steam, but this is used within the process
and is not an effluent from  the plant.,   Finally,  the gas is dried with glycol
to meet pipeline specifications.   Water removed at this point is  27,219 Ib/hr
and,again,  should be suitable for make-up water if it is recovered.  There
may also be a small amount of purge  from the system containing glycol,
which could be  incinerated or passed through the biox system for  clean-up.

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                                  - 32 -
6.7  Auxiliary Facilities

          As previously discussed, there will be solid effluents from the
furnaces burning coal for utilities production.  Residual ash can be
disposed of together with the, slag from gasification.  In addition,  there
is spent limestone from flue gas desulfurization which can be similarly
handled  and also sludge from water treating.  Sludge from biological
oxidation should be incinerated to avoid,odor problems.

          Some water must be purged from the cooling water system in order
to control concentration of dissolved solids.  This represents the minimum
net discharge of water from the plant.  While there will also be blowdown
from boilers, it can be used as cooling tower, makeup, and the sour water
will be cleaned up for reuse.  Water discharged from the plant will contain
sodium chloride, sulfates, and other dissolved solids.  The amount,  com-
position, and disposition need to be carefully defined and evaluated in
any large scale application.

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                                   - 33 -
               7.   GAS HANDLING AND SOUR WATER CONSIDERATIONS


          There are a number of possible ways, which can be used to clean-up
the raw gas leaving the gasifier  so that it can be methanated to high
Btu pipeline gas.  The choice can have a very large effect on effluents
and 'particularly on the production of sour water and the disposal of it.
To a large extent, the choice is a matter of selecting the order in which
the processing steps are carried out,  and some of the routes are as follows:

          (1)  The hot gas goes first to shift conversion using
               a sulfur resistant catalyst, followed by acid ,gas
               removal and methanation.

          (2)  The raw gas is cooled and scrubbed for acid gas
               removal, and then goes to shift, C02 removal, and
               methanation.

          (3)  The gas is desulfurized at high temperature such as
               700°F instead of using amine or hot carbonate scrubbing,
               and is then methanated directly with steam, followed by
               C02 removal.

The first of these is the route usually planned in making SNG by coal gasi-
fication.  It requires gas clean-up ahead of the shift reactor in order to remove
materials that might foul the shift catalyst, particularly dust and tar.
Catalyst activity is relatively low due to the presence of sulfur and a
large excess of steam is generally needed to control deposits on the catalysts.

          The second type of system is more typical of operation to manufacture
high purity hydrogen, where the shift reaction must be maximized.  An
active shift catalyst can be used since it is not exposed to sulfur.  However,
if this route is used in making SNG, the gas must be cooled after shifting
in order to scrub out C02 before methanation.  This introduces an extra
heating and cooling step which is inefficient.  Thus, the entire gas
stream is cooled three times compared to twice in the first case.

          The third approach is a new proposal for gas processing which
should be simpler and more efficient, although it requires development
of technology.  With this combination the gas is only cooled once, and
that is after the final methanation.  The gas is first desulfurized at
high temperature using a process such as that studied by the Bureau of
Mines based on the reaction of iron with sulfur (30), or that studied by
CONSOL based on half-calcined dolomite.  Next, the. CO is methanated di-
rectly by .reaction with steam rather than with hydrogen.  It should be
possible to react CO .with steam to form methane and CO,-,, since this type
of reaction Is^carried out in a number of processes making .SNG from
naphtha by reacting It with steam to form methane and C0« (31,32,33).


          It would also be possible to use conventional shifting and
methanation in two separate stages, but it is more efficient to react the
CO to methane directly since it requires less steam.  In other words, it
combines the steam consumption of the shift reaction together with the
steam formation in methanation, whereby the actual steam requirement is
reduced.

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                                  - 34  -
          With this route it will be necessary to remove sulfur, dust and
tar at high temperature ahead of methanation.  As mentioned, sulfur might
be removed in a bed of iron type adsorbent,  which might also remove dust,
or the dust could be removed in sand bed filters.  Tar could be removed
by scrubbing, for example, at 500-600°F.  While the projected methanation
reaction has been used effectively on naphthas, it will probably be more.
difficult to'obtain the desired conversion on heavier oils or .on aromatic
type compounds.  Therefore, the system may be best suited for those
gasification processes that do not make tar or naphtha.

          An advantage for removing C02 after methanation is; that there
is less volume of gas  and the concentration of CC>2 is higher.  Of course,
the total amount of C02 to be removed is the same as in the other
routes.

          It should be pointed out that compounds such as phenol and
ammonia in the raw gas can pass through the system and; may not be removed
until the final cooling step.  In addition,  the effect of volatile trace
metals must be considered.  It is not clear whether these would be removed
along with the dust or whether they might deposit on the catalyst and
affect its activity.

          The potential savings and simplification possible with this
modified system.for gas cleaning would seem to provide considerable
incentive to develop suitable techniques for removing sulfur and dust'
at high temperatures.  Techniques are known for removing small amounts
of sulfur at high temperature, for example,  using iron, zinc oxide, or
nickel base materials.  The problem has been that these cannot be
conveniently regenerated, and therefore are not practical for removing
large amounts of sulfur.  It should be possible to develop practical
regeneration techniques,  so that the sulfur adsorbent could be recirculated
and used continuously or batch wise.

          Dolomite may also be a promising prospect for such a system
based on background available from the CC>2 Acceptor process development  (4).
This work has shown that dolomite will remove  sulfur compound from gases
at high temperature.  It has also been shown that the spent material
can be desulfurized and regenerated by reacting with CC>2 in a water slurry
at 190°F to produce a stream of t^S which is available at a reasonably high
concentration so that it  can be processed efficiently in a conventional
Claus plant.

          If techniques were developed for removing dust -and sulfur at
high temperature, then they would also.be useful for making clean,low
Btu fuel gas from coal.   For example, coal could be gasified with air
or oxygen, and after clean-up used in process  furnaces or utility.boilers,
which would then not require individual stack  gas clean-up.  The system
should have a higher thermal efficiency than conventional systems to -'make

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                                  - 35 -
low Btu gas in that little or no sensible heat in the hot gas from
gasification would be wasted.  A further very important advantage is
that the clean fuel gas could be used in a .combined cycle for power
generation.  That is,  the low Btu gas would first be used in a gas
turbine generating electric power,  and it would then go to a furnace
for final combustion and steam generation.

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                                  -  36  -
                          8.  SULFUR BALANCE
          Details on the amount of sulfur in the various streams entering
and leaving the plant are shown in Table 5.  Essentially all of the sul-
fur emission from the plant is to the air, and most of this is in the
flue gas discharged from the steam boiler and super heater.  Of the sul-
fur entering the plant in the coal feed, 83.4% is recovered as by-product
sulfur from the sulfur plant.  An additional 12.4% of the sulfur is re-
moved and rejected by the flue gas desulfurization facilities on the
utilities furnaces and coal dryer.  A number of processes are offered
for stack gas cleanup, and many of these can give a sulfur removal well
above the 79% target, at little or no added cost.

          Streams such as the waste water discharge and the CO™ vent gas
will be cleaned up to avoid odor problems, and will then contain negligible
amounts of sulfur.  Thus, the raw C0~ stream from acid gas removal contains
3400 ppm H?S which is removed by molecular sieve adsorption and sent to
the sulfur plant.  Similarly, the slag is assumed to be free of sulfur
and not a contributor to pollution.  These items should be examined care-
fully in a final plant design.  While the gas liquor contains considerable
H_S, most of this will be removed in the sour water stripper and sent to
tRe sulfur plant.  The biox unit provides final cleanup on the effluent
water.

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                                - 37 -



                               Table 5

                         Sulfur Balance  (1)


Sulfur Input in Coal  (1)                              Ib/hr          %

  To gasifier                                         35,487        84,2
  To coal dryer                                          418         1.0
  To utility steam boiler                              5,164        12.2
  To steam superheater                                 1,Q86         2.6

  TOTAL IN                                            42,155       100.0


Sulfur Output (1)

  From Glaus plant (2)                                35,132        83.4
  In Glaus tail gas (2)                                  355         0.8
  In pipeline gas product                                nil         	
  In treated sour vater                                  nil         	
  In CC>2 vent gas                                        nil         	
  In slag                                                nil
  From flue gas desulfurization coal dryer  (3)           330         0.8
  From flue gas desulfurization boiler (3)             4,080         9.6
  From flue gas desulfurization superheater (3)          858         2.0
  In flue gas on coal dryer (3)                           88         0.2
  In flue gas on boiler (3)                            1,084         2.6
  In flue gas on superheater (3)                         228         0.6

  TOTAL OUT                                           42,155       100.0
NOTES:

  (1)  Does not include refuse from coal cleaning operations which
       could be sizable and needs to be defined.

  (2)  Basis:  99% S recovery including tail gas clean-up.

  (3)  Based on flue gas desulfurization with 79% S removal.

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                                   -  38  -
                        9.  THERMAL EFFICIENCY
          The base  thermal efficiency for the process is obtained by
 comparing the heating value of  the net pipeline gas produced, with  that
 for  the  total coal  used including gasification and all utilities production.
 As shown in Table 6, the base efficiency is 65.9%.  Coal is used as fuel
 in the coal drier and the utilities  systems, requiring flue gas clean-up;
 but,  the fuel required for this is not included in the above number.  How-
 ever, it is estimated that this will increase the fuel requirements by
 less  than 5% on  the individual  furnaces, and less than 1% on the total
 coal  delivered to the plant.  Base efficiency with this allowance will then
 be about 65.3%

           An alternative would be to use  low sulfur  low Btu gas  made  in
the process as fuel  to the furnaces.   Pollution  due  to sulfur and ash  would
then be avoided,  but it  would still  be necessary to  provide  good  dust  removal
on the coal dryer.   Obviously,  such  use of gas  fuel will  appreciably reduce
the amount of gas available to the pipeline,  and correspondingly  decrease
thermal efficiency of the process,  as illustrated below:
Fuel used in;

  Coal dryer            coal       gas        gas         gas
  Steam superheater     coal       coal       gas         gas
  Utility boiler        coal       coal       coal        gas

MM Btu/hr in:

  Coal consumed         14,920     14,775     14,390      12,560
  Low Btu gas           11,191     11,046     10,661       8,831
  Pipeline gas           9,830      9,703      9,365       7,757

Thermal Efficiency %    65.3       65.1       64.6        61.8
Using all gas fuel instead of coal decreases thermal efficiency from 65.3%
to 61.8%.  At the same time, production of pipeline gas is reduced by 217=,
for a given size of gasifier.

These results again emphasize the desirability of applying an efficient
flue gas clean-up operation, so as to allow using high sulfur coal as
fuel.

          It is also of interest to look at the thermal efficiency for this
specific design as a way to make low sulfur,  low Btu gas.   Heating value in
the gases prior to methanation corresponds to about 74% thermal efficiency
for the gasification step, including an allowance for  flue gas clean-up.
Of the total heating value in the low Btu gas, 41.67» is contributed by  its
methane content.

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                                - 39 -
          In considering thermal efficiency of the process as a source of
clean low Btu fuel gas, it is proper to exclude the shift conversion
operation since it is not needed.  Then the quenching can be omitted and
replaced with a more efficient heat exchanger to generate high pressure
steam, thereby decreasing the size of the utility steam boiler.  This
reduces the total coal consumption and adds another 37, to the thermal
efficiency,, bringing it up to 77% for making clean fuel gas.

          Thermal efficiencies for the various alternatives considered
In the BI-GAS process are summarized in Table 6.

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                               - 40 -
                               Table  6
               Thermal Efficiencies for BI-GAS Process
Base Coal * Consumption




  Gasifier




  Coal dryer




  Steam Superheater




  Utility boiler
   Ib/hr




1,018,700




   12,000




   31,200




  148.400




1,210,300
Base Case Thermal efficiency




  Without flue gas  desulfurization




  With flue gas desulfurization







  With low Btu gas fuel to;




    Coal dryer




    and steam superheater




    and utility boiler






Alternative to make only low Btu gas




  Base case design




  Without shift conversion
MM Btu/hr




 12,560




    145




    385




  1,830




 14,920






 Efficiency




   65.9




   65.3
                         65.1




                         64.6




                         61.8
                         74.0




                         77.0
 * Based on 8.4% moisture

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                                    -  41  -
                           10o  TRACE ELEMENTS
          Coal contains many trace elements present in less than 1%
concentration  that need to be carefully considered from the standpoint
of potential impact on the environment.  Many of these may volatilize
to a small or large extent during processing and many of the volatile
components can be highly toxic.  This is especially true for mercurv,
selenium, arsenic, molybdenum, lead, cadmium,  beryllium and fluorine.  The
fate of trace elements in coal conversion operations, such as gasification
or liquefaction, can be very different than experienced in conventional
coal fired furnaces.  One reason is that the conversion operations take
place in a reducing atmosphere, whereas in combustion the conditions are
always oxidizing.  This maintains the trace elements in an oxidized condition
such that they may have more tendency to combine or dissolve in the major
ash components such as silica and alumina.  On the other hand,the reducing
atmosphere present in coal conversion may form compounds such as hydrides,
carbonyls or sulfides which may be more volatile.  Studies on coal fired
furnaces have indicated that smaller particles in fly ash contain a higher
concentration of trace elements, presumably due to volatilization of
these elements in the combustion zone and their subsequent condensation and
collection on the fly ash particles (20).  Other studies on coal fired
furnaces are pertinent (21,22,23) and some of these report mass balances
on trace elements around the furnaces (24).

          Considerable information is available on the analyses of coal,
including trace constituentSj and these data have been assembled and evaluated
(25,26).  A few studies have been made to determine what happens to various
trace elements during gasification (2,27).  As expected these show a very
appreciable amount of volatilization on certain elements.  As an order of
magnitude, using the factors for this specific BI-GAS design would result
in 240 Ib/day carried out by the gas for each 10 ppm of trace element
volatilized from the coal.

          In order to make the picture on trace metals more meaningful9
the approximate degree of volatilization shown for various elements has
been combined with their corresponding concentration in a hypothetical
coal (as typical), giving an estimate of the pounds per day of each element
that might be carried out with the hot gases leaving the gasifier.  Results
are shown in Table 7 in the order of decreasing volatility.  Looking at the
estimated amounts that may be carried overhead, it becomes immediately
apparent that there can be a very real problem.  For each element the net
amount carried overhead must be collected, removed from the system, and
dispose of in an acceptable manner.  In the case of zincs boron and fluo-
rine the degree of volatilization has not yet been determined, but they
would be expected to be rather volatile.  Even if only 10% of the total
amount is volatile, there till be large quantities to remove in the gas
cleaning operation and to dispose of.

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                         - 42 -
                          Table 7


Example of Trace Elements That May Appear in Gas Cleaning Section
                 Possible           % Volatile        In Gas
  Element     ppm in Coal (a)     for example (b)     lb/day(c)
    Cl              1500               >90+           32,400
    Hg              Oo2                 90+           5
    Se              2.2                 74            39
    As              31                  65
    Pb              7.7                 63
    Cd              0=14                62            2
    Sb              Ool5                33            i
    V               35                  30            252
    Ni              14                  24            81
    Be              2                   18            9
    Zn              44                  (10)          106
    B               165                 (10)          396
    F               85                  (10)          204
    Ti              340                 (10)          816
    Cr              22                  nil           nil
   (a)  Mainly based on Pittsburgh Seam Coal  (2)=

   (b)  Mainly based on lower  temp gasifier  (27) and  indicated  at
       10%  for Zn, B, and F?  in absence of  data.

   (c)  For  12,000 tons/day of coal feed

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                                 - 43 -
          A complication results in the gas clean-up section  due to the
presence of volatile trace elements. In the BI-GAS design, raw gas from the
gasifier is cooled and cleaned to remove all dust and other contaminants
except for the more volatile ones such as H2S.  Contaminants collect in
the dust and sour water both of which are returned to the system  and presumably
recycled to extinction.  Chemical compounds such as cyanide taay thereby
be destroyed but this cannot be the case for trace elements.  It will be
difficult for volatile elements to leave with the slag through the 3000°F
zone, they will therefore build up in the recirculating streams and have
to be purged from the system.

          The preceding  discussion has been directed primarily at trace
elements that are partially volatilized during gasification and that
therefore must be recovered and disposed of in the gas cleaning section.
Consideration must also be given to trace metals that are not volatilized
and  leave in the solid effluents from the plant, one of which is the slag
from gasification.  Undesirable elements might be leached out of this
slag since it is handled as a water slurry  and will ultimately be exposed
to leaching by ground water when it is disposed of as land  fill or to the
mine.  Sufficient information is not now available to evaluate the potential
problems and the situation may be quite different from the  slag rejected
from coal fired furnaces since the  slag is produced in a reducing atmosphere
rather than an oxidizing one.  Background information on slag from blast
furnaces used in the steel industry may be pertinent from this standpoint,
since the blast furnace operates with a reducing atmosphere.  However, a
large amount of limestone is also added to the blast furnace, consequently
the  nature of the slag will be different.

          An additional source of possible contamination from trace elements
is associated with the disposal of  refuse from coal cleaning.  It is known
that contained sulfur compounds will oxidize upon exposure  to the air and
form an acid solution in the presence of water.  It is quite likely that
a number of trace elements can be extracted from the refuse by this acid
solution.  For example, similar systems have been proposed  and studied
for  recovering copper, nickel, iron, etc. from low grade ores.  It might
be thought that this situation is no worse than that existing for natural
mineral deposits; however, the conditions are quite different.  First,
the  mineral has been crushed and reduced in size so that vastly more
surface is exposed and available for extraction.  In addition, the mineral
is exposed to a large amount of oxygen, which together with the large
surface area can cause considerable oxidation of sulfur compounds, organic
materials, and minerals in the refuse, whereas natural mineral deposits are
not  subject to such conditions.  Some studies have been made in this general
area (28,29),but much more work is  needed.

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                        11.   ALTERNATIVES TO CONSIDER


          This section of the report covers various modifications to the base
design that warrant further consideration and evaluation.  Some of these are
added as required to control pollution.  Other alternatives are discussed
that may improve thermal efficiency of the process, some of which will require
additional experimental work or development of new technology.  Table 8
summarizes a number of items.  The first modification to consider is the
addition of facilities to control sulfur emission on furnaces firing high
sulfur coal as fuel.

          In the base design, high sulfur coal is used for fuel on the coal
dryer and in the utilities furnaces.  Flue gas clean-up is therefore needed
on each of these, and a large number of processes are offered commercially
for this purpose (10,13,34,35).  Some of these use scrubbing with lime, lime-
stone, magnesia, or sodium carbonate solutions.  In the case of limestone,
the spent material is discarded, whereas in most other processes the scrubbing
medium is regenerated to produce a by product sulfur compound such as
sulfur, sulfuric acid, or gypsum.  Those processes that use scrubbing will
also remove particulates, as is required when burning coal as fuel.

          Instead of using coal with flue gas clean-up, it would be possible
to use part of the clean, low Btu gas produced in the process as fuel for the
furnaces.  In evaluating this route, allowance should be made for the large
difference in thermal efficiency compared to burning coal directly.  Some
energy is required to operate flue gas desulfurization,  such that the thermal
efficiency corresponds to about 95%, whereas gasification to make low Btu
clean  fuel gas has a thermal efficiency of about 75%.  This specific BI-GAS
plant  design used about  15.8% of the total coal feed for firing in  the  coal
dryer  and in the utilities area.  Therefore, the energy  for flue gas
desulfurization will decrease  overall plant thermal efficiency by  about
0.6%,  while the  gasification route reduces it by about 3.0%.

          In any event,  the  coal dryer will  require  dust recovery.  Fortunately,
fuel  consumption for coal drying is  small  relative to  the utility furnaces,
so  it  is  reasonable to use  low  Btu,clean  gas as fuel on  the coal dryer.   One
advantage  is  that  this avoids complications  that may result if coal is  used
as  fuel,  and  the ash  from  this  coal mixes with and contaminates  the coal
fines  picked up  by the gas  in the dryer.

          A second modification to  consider  is on  the  system  for recovering
and handling  dust  carried  out by the raw gas leaving the gasifier.   In the
base  design a  large amount  of char  is  entrained  from the reactor and  separated
in  a  cyclone  for return  to  the  lower  zone.   Lock hoppers are  used  for
repressuring  the recovered  char, and  since these require the  use of mechanical
valves,  the 1700°F raw gas  and  char  are  cooled to  1115°F by  injecting  quench
water into  the cyclone.  Recovered  char  is then  injected into the  lower
gasification  zone  which  opesates at  3000°F.   It would  of course  be  more
efficient to  return the  char without  cooling,  but  since  mechanical  valves
are used,  some cooling is  necessary.   However, there is  an alternative to

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                                  - 45 -


                                 Table 8

                         Alternatives to Consider


-  Add stack gas clean-up to remove sulfur and dust on coal fired furnaces,
   or use low Btu,clean gas fuel.

-  Omit cooling on cyclone after gasifier and use standpipe to return
   hot char to gasifier at 1700°F instead of 1115°F.

-  Design coal dryer for coal fuel and low excess air (e.g. 107») with
   vent gas recycle, to minimize fuel consumption and volume of vent gas
   to dust removal.

   Pressurize coal feed by pumping a water slurry, which is evaporated in
   a fluid bed using indirect heating, to form steam which is used in
   gasifier and shift converter, while at the same time preheating the
   coal feed to 500-550°F.

   Evaluate alternate of using  light hydrocarbon instead  of water
   to make slurry.  Hydrocarbon would then be condensed and reused.

-  Remove excessive sulfur from C02 vent stream by using absorption/
   oxidation process instead of molecular sieves.

-  Instead of cooling to scrub out acid gases,  remove sulfur at high
   temperature and then react CO with steam catalytically to form
   methane directly.  Dolomite or iron system might be effective for
   sulfur removal.  Final step is then cooling and C02 removal from
   smaller volume of gas.

-  General efficiency items to conserve fuel:

   -  heat pumps on acid gas removal and sour water stripper
   -  air-fin exchangers to save cooling water
   -  air preheat on furnaces

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                                 - 46 -
using lock hoppers which would not require cooling, in which the char
would be recovered in cyclones at 1700°F and flow down through vertical
standpipes to build up pressure on the fluidized char, as needed in order
to return it to the lower zone.  This general technique is well established
for use in many fluidized solids operations, such as fluid catalytic
cracking in oil refineries.  Returning the hot char without cooling significantly
reduces the heat load on the gasification zone, so that oxygen requirement is
decreased by about 15%.  This also reduces the gas volume to be handled,
and the amount of C02 to be removed in the acid gas removal section.

          Another modification that could improve efficiency of the process
and simplify the operation  is in the method of pressurizing the coal
feed.  It was originally proposed to use a piston feeder on the dry
coal powder, since this inherently has minimum power consumption. At the same
time it was suggested that lock hoppers could be used  with pressure staging
to minimize the amount of vent gas that would have to be collected and compressed.
Lock hoppers ©re used commercially but are expensive, and the cyclic operation
of valves requires considerable maintenance.

          It has also been proposed to mix the coal with a liquid to form a
slurry which then can be pumped into the high pressure system where the liquid
is evaporated.   The liquid may be water in an amount approximately equal to
the weight of coal so that the slurry can be handled and pumped.  In some cases
a light hydrocarbon such as naphtha is used instead of water so as to reduce
the heat load,  in which case the vapors can be condensed and reused.  Latent
heat to evaporate naphtha is about 150 Btu per pound, compared to roughly 700
for water at high pressure.

          This route is promising, especially with water, since large quantities
of steam are used in the gasifier and in shift conversion.  The combined steam
consumption is about 1.7 million pounds per hour, and heat for generating this
steam must come either from waste heat or from furnaces.  The quantity of
steam is large relative to the coal feed rate of slightly less than 1,000,000
pounds per hour, and would be sufficient to form a pumpable slurry for feeding.
If the coal feed were slurried with an equal weight of water and pumped to about
1100 psig, then it could be evaporated by indirect heat exchange with the hot;
raw gas available at 1700'F from the gasifier, after the char has been separated
by means of a cyclone as previously described.  Latent heat to evaporate the
water amounts to about 600 million Btu  per hour, which could be provided by
sensible heat of the raw gas if it were cooled from 1700 to 900°F.  It is
therefore of interest to consider flowing the hot gas through a heat exchanger
which would transfer heat to the coal slurry in order to evaporate it to dry-
ness.  The operating temperature would be about 550°F. and past work has shown
that coal can be preheated to this temperature without evolving a large amount
of volatiles  or becoming plastic and sticky.

          It may not be practical to carry out such an operation in a conven-
tional tubular exchanger because of local overheating or plugging, but one
possibility is to use a fluid bed in which  there are heat transfer  tubes, as
proposed for fluid bed boilers.  Such an approach is illustrated in Figure 3.

          A \sater slurry is injected into the fluidised bed where it is evap-
orated to dryness.  Similar systems have been used successfully on small commercial

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                                       Figure  3

            POSSIBLE SYSTEM FOR PUMPING  COAL  TO  HIGH PRESSURE,  USING SLURRY
      COAL  FEED
        HOPPER
 946,307
                               WATER
                            (Can be sour water)
                                   946,307
                                    200°F
        SLURRY MIXING
                 TANK
                                       PUMP
                                 (To 1100 psig,
                                  2300 theo. HP<0
       STEAM TO GASIFIER AND
            SHIFT CONVERSION
       —^    946,307
        HEATING COILS,
        1050 MM Btu/hr
        (e.g.  Dowthertn, or hot raw gas
         from gasifier)                i
PREHEATED COAL TO GASIFIER
         946,307
Numbers are flow rate, Ib/hr.

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                                  - 48 -


 units to evaporate various slurries.  Heat is supplied indirectly by exchanger
 coils submerged in the bed,  which are found to provide excellent heat transfer
 without fouling.   Hot gases from the  gasifier could flow through the coils to
 supply necessary heat.   Instead of this  arrangement,  heat could be supplied
 from a furnace using for example Dowtherm or liquid metal to assure good heat
 transfer and temperature control.

           Steam from evaporation of the  slurry can be fed to the upper and
 lower zones of the gasifier as desired.   Part of the steam can also be used
 in the shift converter.,  Although the steam will contain some solid particles,
 this should not matter.  Dry coal is  withdrawn from the bed and fed to the
 gasifier, for example, using a standpipe   or screw feeder arrangement.
 It will be noted that the coal is preheated to 550°F in this system.  Its
 sensible heat content is thereby increased by about 150 million Btus per
 hour, giving a corresponding saving in the overall heat load on the
 gasifiero

           The base design uses hot carbonate scrubbing for acid gas removal
 and it has the advantage that it will remove carbonyl sulfide whereas amine
 scrubbing is not effective.  Of the total sulfur in the raw gas some 10% of
 it may be present in forms other than H S, such as carbonyl sulfide, conse-
 quently these other forms of sulfur must also be removed in order to give
 satisfactory cleanup.  This particular hot carbonate system makes a vent stream
 of CO, which is excessively high in sulfur content and needs to be cleaned up.
 Therefore we have added a molecular sieve unit to remove H S from this
 CO, stream and sent it to the sulfur  plant for recovery.  Further con-
 sideration should be given to catalytic  hydrolysis of carbonyl sulfide
 to form H.S.  This would be used prior to acid gas removal,  and might be
 combined with the shift operation as  suggested by Bituminous Coal Re-
 search (36) .

          Acid gas  removal is a  large consumer of utilities, equivalent to
about 10% on overall thermal efficiency.    It  therefore warrants  thorough
consideration of  alternatives in order to  arrive at an optimum  system.   In
this connection,  the desirability of hydrolysing carbonyl  sulfide prior  to
acid gas removal  should be emphasized.  If this can be done  it  allows a  much
wider choice of processes  for acid gas removal, including  conventional amine
scrubbing as well  as adsorption/oxidation  type systems such as  Stretford,
Takahax, or IFF.

          The adsorption/oxidation system  could also be  used  for  cleaning up
the C02 vent stream, since it will remove  HjS without removing  C02.   Other
methods may be cheaper  or  simpler, such as scrubbing with  limestone  slurry.
This would  pickup sulfur and have to be  disposed of in a suitable manner.
One possibility is  to return  it  to the gasification zone*  If  flue  gas
desulfurisation is  used on furnaces in the plant,  it is  quite possible that
the CO, vent stream could be  included along with  the  flue  gas  for processing.

          As deacribed more  fully in  the  section  on Gas  Handling and Sour
Water Considerations, there  appears to be  a large  potential  advantage for
developing  practical techniques  to remove  sulfur  at high temperature and avoid
the need  for liquid scrubbing.   The major  potential advantage would be to
mathanate  CO directly, without having to  shift  or  cool the gas  for  acid  gas
removal.   It would  also be necessary  to remove  dust at high  tempereture9  but
 this  could be done  with  sand bed filters.   Thus the gas  might  first be cooled
 to about  600-900°F, $nd  the dust  removed.   Then it  would  be desulfurized  and

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                                     - 49 -
sent through the methanation reactor, where the CO would be reacted with steam
and whatever hydrogen is present to  form methane and C02°  Finally the gas would
be cooled and scrubbed for CCL removal  and dried to provide pipeline quality
gas.  With this route the gas would  never have to be reheated and cooled again,
as is necessary with the present conventional systems.

          Efficiency of the process  and fuel consumption  might be improved
by reoptimizing a number of general  items  which are more or less conventional,
such as the use of heat pumps,  air-fin exchangers, and increased air preheat
on furnaces (4,5).

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                                  - 50 -
                         12o   TECHNOLOGY NEEDS
          From this review and examination of environmental aspects of the
BI-GAS process, a number of areas have been defined where further information
is needed in order to evaluate the situation, or where additional studies
or experimental work could lead to a significant improvement from the stand-
point of environmental controls, energy consumption, or thermal efficiency
of the processo  Items of this nature will be discussed in this section of
the report, and a summary is shown in Table 9.

          Any coal conversion operation has solid refuse to be disposed of. Coal
cleaning for the present design generates over 860 acre feet per year of refuse.
In addition, the production of slag from gasification is 820 tons per day or
another 10 acre ft/yr.  More work is needed in order to define methods of
disposal that do not create problems due to leaching of acids, organics,
or sulfur which could contaminate natural water..  In addition, adequate
controls are needed with regard to the potential dust nuisance and washing
away of particulates.  In many cases the material may be suitable for land
fill  with revegetation.   Although there is already a lot of background
on this subject, specific information is needed on each coal and for each
specific location in order to allow thorough planning to be sure that the
disposal will be environmentally sound.

          Coal drying is used on most coal conversion processes; consequently,
considerable effort is warranted to optimize the operation from the standpoints
of-fuel consumption, dust recovery, and volume of vent gas to be handled.
It will often be attractive to burn high sulfur coal rather than clean gas
fuel, and to include facilities for cleaning up the vent gases.

          The need for a simple ^efficient means of feeding coal to the high
pressure gasifier has been apparent and has received considerable study.
For pressure levels of 400=500 psig, lock hoppers have been used satisfactorily,
although they are expensive.  For systems at 1,000 psig it may be attractive
to pump a water slurry of the coal in order to pressurize it, particularly
if it is possible to then evaporate the slurry at high pressure and thereby
supply steam to the process.

          One item that is critical in the BI-GAS process  is the need for
efficient removal of dust from gas at high temperature=  In general, this
is required in any coal gasification system where the gas is shifted before
it is cooled and scrubbed.  An important advantage is that particulates are
kept out of the sour water stream,  and  consequently  it  is easier  to clean up.
Sand bed filters are promising for dust removal from hot gases, although they
have not been fully demonstrated commercially.

          In the area of acid gas removal, systems based on amine or hot
carbonate are not completely satisfactory and leave room for improvement»
Amine scrubbing is not effective on carbonyl sulfide, while contaminants
such as cyanide interfere with regeneration of the scrubbing liquid.
Hot carbonate systems do remove carbonyl sulfide*, but it is often difficult
to provide a highly concentrated stream of H2S to send to the sulfur plant.
In addition the C02 stream vented to the atmosphere may contain too much
sulfur«  Adsorption/oxidation systems are often not effective on carbonyl

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                                 - 51 -
                                     (


                                 Table 9

                             Technology Needs


-  Environmentally sound disposal of large amounts of refuse from coal
   cleaning and washing, with regard to dust, leaching and sediment,
   trace elements, land use, etc.

-  An optimized design for coal drying to use low excess air and give maximum
   allowable coal preheat, with good dust recovery.

   An improved system to feed coal into high pressure zones, for example
   using a piston feeder on water slurry.  Slurry could be evaporated
   in heated fluid bed to make steam for gasifier and preheat the coal
   feed.  Light hydrocarbon might be used instead of water, and condensed
   for reuse.

   A simpler and more efficient process for acid gas removal which would
   provide an l^S stream of high concentration (e.g. 50 vol. 7») to the
   sulfur plant, while giving a separate clean stream of CC>2 that can be
   vented to the air.  Desirable features to include:

      good sulfur clean up, to a few ppm
   -  a clean CC>2 vent stream that does not require incineration
      low utilities consumption
      little or no chemical purges to dispose of

-  An effective process to remove sulfur at high temperature could lead
   to improvements, such as reacting CO directly with steam to form
   methane.

-.  Ways to handle COS, CS2, thiophene,  etCc, that are usually present
   and may not be removed by many acid gas removal processes.  Hydrolysis
   to H2S is probably one good approach.

   Sour water cleanup.  Most of it may be used for quenching, but some
   purge will probably be needed to remove trace elements and perhaps
   ammonia and phenols.  There is a great need for a practical system
   to evaporate sour water to make steam for use in the gasifier, and a
   fluid bed system appears promising.

   Information on trace elements and techniques for their disposal.

   -  Extent of volatility for specific process and coal.
   -  Where they appear in gas clean up system,  and in what form.
      They may collect on the char or sand bed filter and build up
      by recycling.  Others may appear on shift catalyst and in sour
      water or acid gas removal.
   -  Many may be toxic and require separation and decontamination treatment
      before disposal.
   -  Leaching may occur on the slag or on refuse from coal cleaning»
      Information is needed to define the potential problem and to
      devise environmentally sound disposal techniques.

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                                   - 52 -
 sulfide  and  in  any event  do  not  remove  CC>2  as  required,  and  therefore
 additional processing  is  needed.   The available  systems  for  acid  gas
 removal  have very high utility requirements,  causing a significant  loss
 in thermal efficiency  for conversion of coal  to  clean fuel products.
 In addition  there is often a waste stream of  chemical scrubbing medium
 which may be difficult and expensive to dispose  of.

          Desirable objectives for. an acid  gas removal process can  be
 summarized as follows  :(a) good clean up of  all forms of sulfur to give
 a stream high in sulfur concentration  for processing in a Claus sulfur
 plant, (b) effective C02 removal while  producing a vent stream satisfactorily
 low in sulfur and pollutants, (c) low utility and energy consumption,
 (d) no waste streams that present a disposal  problem.

           The need for a process to remove  sulfur at high temperature  has
 been discussed fully in preceding sections  of this report.   Systems based
 on dolomite  or iron appear promising;  however, they may give less complete
 sulfur removal than conventional scrubbing  systems,  in which case a methan-
 ation catalyst that is tolerant of higher sulfur (e.g. 50 ppm) may  have to
 be developed.  If the  sand bed filtering technique could be incorporated
 to remove particulates at the same time that  sulfur is removed, such systems
 would be even more attractive.  A further need is to destroy or remove un-
 desirable contaminants such as carbonyl sulfide, cyanides,  and possibly
 phenol and  ammonia.  This function might also be provided by a high temper-
 ature gas cleanup system.

          The need for a  simple,effective method to clean up sour water
for reuse is another item that is  common to most fossil  fuel conversion
operations.   Sour water generally  contains  sulfur compounds, ammonia, I^S,
phenol, thiocyanates,  cyanides, traces of oil, etc.  These are  generally
present in too high a  concentration to allow going directly to  biological
oxidation, but their concentration is often too low to make recovery
attractive.   Particulates, if present,  further complicate the processing
of  sour water.  Usual  techniques  for clean up  include  sour water  stripping
to  remove HoS and ammonia, and in  addition,  extraction may be required
to  remove phenols and  similar compounds.  Such operations are large
consumers of utilities and have a  large effect on overall thermal efficiency.
In most cases the net  amount  of sour water produced is less than  the amount
of  steam consumed by reaction in  gasification  plus shift conversion, which
suggests a way to dispose of  sour  water.  One  approach is to use  the
sour water as quench on the hot gas  leaving the gasifier, as is done in
this BI-GAS design.  However, it  is not clear  that compounds such as phenol
and ammonia will actually be  destroyed by recycling,  so  they may have  to
be  separated and withdrawn as by-products.

          An alternative  approach  is to vaporize the  sour water to make
steam which can be used in the gasifier.  In this case,compounds  such  as
phenol should be destroyed and reach equilibrium concentration  in the
circulating sour water.   It may not be practical to vaporize sour water
in  conventional equipment such as  exchangers,   due to  severe  fouling and
corrosion problems.  Therefore, new  techniques may be  required, and one
possibility would be to vaporize  the sour water by injecting it into a
hot bed of fluidized solids.  The  system could be very similar  to that
proposed for evaporating  a water  slurry of  coal feed  as  discussed in
connection with Figure 3.  In fact,  sour water may be  used in  some cases
to  form the  slurry.

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                                     - 53 -
           On trace elements, information is needed on the amount vaporized
 in the gasifier and what happens to them, where they separate out and in
 what form, so that techniques can be worked out for recovering or disposing
 of the materials.  Again specific information is needed for each coal and
 for each coal conversion process since operating conditions differ.  In
 many cases,  the trace elements may tend to recycle within the system and
 build up in concentration.  This offers an interesting opportunity to
 perhaps recover some of them as useful by-products.  The toxic nature of
 many of the volatile elements should be given careful consideration from
 the standpoint of emissions to the environment,  as well as protection of
 personnel during operation and maintenance of the plant.  Carcinogenicity
 of coal tar and other compounds present in trace amounts  or formed
 during start up or upsets  should also be evaluated.

           Protection of personnel,  especially during  maintenance  operations
 should be given careful attention,  which will require that additional
 information  be  obtained.   Thus,  toxic  elements that vaporize in the gasifier
 may condense in equipment such  as piping and exchangers  where they could
 create  hazards  during cleaning  operations.   This may  apply particularly
 to sand bed  filters  and to shift conversion reactors.

           In this  specific BI-GAS design,  there  is  no sour process  water
 effluent  from the  plant which might  contain trace elements.   Moreover the
 slag  is drained  and  disposed of  as  a moist  solid rather  than a  slurry.
 On this basis the  question of cleaning  up waste  water effluent  does  not
 apply.  However, in  an  actual application  there  will  very  likely  be  a water
 effluent,  and detailed  study of  the  facilities for  clean up  will  be
 needed.   In any  event,  the  water make-up that  is brought to  the plant
 will contain dissolved  solids including sodium and  calcium salts.  Calcium
 salts may be precipitated  during the water  treating operation to  form a
 sludge which can be disposed of  with the other waste  solids, but  the
 fate of the sodium salts in the  make-up water calls for  further study.
 These will leave with the blowdown from the cooling tower.   If the concentration
 of dissolved solids is too  high  in this blowdown water to  allow discharging
 it to the river, then some  suitable method of disposal will have  to be
worked out.  On one proposed commercial plant, this has been handled
by using an evaporation pond where the water is evaporated to dryness.
The salts accumulate and will ultimately have to be disposed of.  If they
cannot be used or sold then  it would seem logical to dispose of them in
the ocean.

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                                    - 54 -
                            13.  PROCESS DETAILS
          Additional details on the process are given in Tables 10
through 16.

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                                 - 55 -
                               Table  10
                   Steam Balance for BI-GAS Base Case
 1265 psig  steam Ib/hr

               Generated

     Shift Outlet WHB       545,700


     TOTAL                  545,700
                          Consumed
               Gasifier
               Shift
               Q£ preheater
                     410,100
                      65,400
                      70.200
                     545,700
600 psig steam Ib/hr

               Generated

     Auxiliary boiler     1,329,400
     TOTAL
1,329,400
                          Consumed

               Power gener.         606,400
               Acid gas remov.      430,700
               to 400 psig steam    292.300
                   1,329,400
400 psig steam Ib/hr

               Generated

     From 600 psig          292,300
     Shift & Meth. WHB    1,056,100
     TOTAL
1,348,400
                          Consumed
               Coal feeding
               SNG compressor
               Glycol dry.
               02 plant
               02 compressor
                       9,600
                     192,900
                       4,700
                     743,400
                     397.800
                   1,348,400
50 paig steam Ib/hr

               Generated

     Raw gas WHB
     Glaus plant
     Turbo generator
     TOTAL
  600,600
   70,000
  298.900
  969,500
                          Consumed
Acid gas removal
BFW deaerator
Building heat
833,100
 86,400
 50.000
969,500

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                                - 56 -
                               Table 11

               Water  Requirements  for  BI-GAS Base Case

Cooling Water Circulation                          GPM
   Coal preparation                                    0
   Gasification                                      450
   Quench & dust  removal                               Q
   Shift conversion                                    0
   Acid Gas removal                              114,000
   Methanation &  drying                            1,930
   Oxygen plant                                  117,600
   Sulfur plant                                    1,100
   Power generation                               27,500
                                                 262,580


Cooling Tower Makeup                                GPM
   Drift Loss                                        526
   Evaporation                                     5,252
   Slowdown (net)                                   1,200
                                                   6,978

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                                 - 57  -
                               Table 12

                      Electric  Power  Consumption
                                                   KW
Coal preparation                                 24,000

Gasification                                      3,500

Quench & dust removal                                 0*

Shift conversion                                      0*

Acid gas removal                                      0*

Methanation & drying                              2,250

Oxygen plant                                          0*

Sulfur plant                                        270

Condensate pumps                                  4,700

Cooling Water pumps                               7,140

                                                 41,860
             *  A small amount of power will be used for
                instruments,  lights,  etc.

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                                 - 58 -
                               Table 13

               Make Up Chemicals  and Catalyst  Requirements
Chemicals

     Acid Gas Removal:

          - scrubbing solution
          - additives

     Sulfur Plant tail  gas cleanup

     Glycol for drying  prod,  gas


     Cooling Tower Additives

          Anticorrosion,  e.g.  chromate
          Antifouling,   e.g.  chlorine


     Water Treating

          Lime
          Alum
          Caustic
          Sulfuric acid


Catalysts, etc.

     Sand for sand bed  filters

     Shift catalyst

     ZnO guard bed to remove  sulfur

     Methanation catalyst

     Molecular sieve to clean up CO,, vent

     Ion exchange resin for water treating

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                      - 59 -
                    Table 14

            Potential Odor  Emissions


Coal  storage  and handling.
Coal  preparation, washing,  settling pond-
Coal  drying - vent  gas.
Vent  gas from lock  hoppers.
Wet ash handling and disposal.
Sour water stripping and handling.
CC-2 vent stream from acid gas removal.
Sulfur plant and tail gas.
Biox pond and other ponds.
Leaks: ammonia,  H2S, phenols, etc.

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                        - 60 -
                      Table 15

                Potential Noise Problems
Coal handling and conveyors.
Coal crushing, drying and grinding.
Oxygen plant air and oxygen compressors.
Lock hoppers, especially on depressuring from 1100 psig.
Burners on furnaces.
Stacks emitting flue gases.
Turbos-generator etc., in utilities area.

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                        - 61 -
                      Table 16

                 Miscellaneous Inputs


For water treating:  lime, caustic, alum, sulfuric acid,
                     chlorine

Cooling water additives:  anti algae (chlorine)
                          anti corrosion (chromium salt)

Other chemicals:  carbonate and additives for acid gas removal
                  glycol  for drying product gas

Catalysts, etc.: sand for sand bed filters
                 methanation catalyst
                 Claus plant catalyst
                 ZnO guard bed to  remove sulfur
                 Sieve  for sulfur  clean  up on C02 vent  gas

Oil:  to  lubricate  pumps, compressor,  etc.

Bios nutrients,  if  required.

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                                   - 62 -
                           14.  QUALIFICATIONS
           As pointed out, this study does not consider cost or economics.
Also, areas such as coal mining and general offsites are excluded, as well
as miscellaneous small utility consumers such as instruments, lighting
etc.  These will be similar and common to all coal conversion operations.

           The study is based on the specific process design and coal type
cited, with modifications as discussed.  Plant location is an important
item of the basis and is not always specified in detail.  It will affect
items such as the air and water conditions available, and the type of
pollution control needed.  For example, this BI-GAS study uses high sulfur
western Kentucky coal to supply gasification as well as utility furnaces.
Therefore, flue gas clean up has been added.  Because of variations in
coal feed, moisture content, and other basic items, great caution is
needed in making comparisons between coal gasification processes as they
are not on a completely comparable basis.

           Other gasification processes may make large amounts of various
by-products such as tar, naphtha, phenols, and ammonia.  The disposition
and value of these must be taken into account relative, to the increased
coal consumption that results and the corresponding improvement in overall
thermal efficiency.  Such variability further increases the difficulty of
making meaningful comparisons between processes.

           The BI=GAS process makes no appreciable amounts of tar, naphtha,
or phenols; however, there could be a sizeable yield of ammonia, amounting
to over 100 tpd and it is assumed that this can be recovered and sold.

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                                     - 63 -
                             15.   BIBLIOGRAPHY


1.  Magee, E.M.,  Jahnig, C.E. and Shaw, H.,  "Evaluation of Pollution
    Control in Fossil Fuel Conversion Processes, Gasification; Section 1:
    Koppers-Totzek Process", Report No- EPA-650/2-74-009a, January 1974.

2.  Kalfadelis, C.D., and Magee, E.M., "Evaluation of Pollution Control
    in Fossil Fuel Conversion Processes, Gasification; Section 2;
    Synthane Process", Report No. EPA-650/2-74=009b, June 1974.

3.  Shaw, H., and Magee, E.M., "Evaluation of Pollution Control in
    Fossil Fuel Conversion Processes, Gasification; Section 3s
    Lurgi Process", Report No. EPA-650/2-74-009c, July 1974.

4.  Jahnig, C.E., and Magee, E.M., "Evaluation of Pollution Control
    in Fossil Fuel Conversion Processes, Gasification; Section 4:
    C02 Acceptor Process", Report No.  EPA-650/2=74-009d,  December 1974.

5.  Kalfadelis, C. D.  Evaluation of Pollution Control in Fossil Fuel
    Conversion Processes, Liquefaction:  Section 1:  COED Process.
    EPA-650/2-74-009e, January 1975.

 6   Jahnig,  C.E.,  "Evaluation of Pollution  Control in Fossil  Fuel
     Conversion Processes,  Liquefaction; Section 2, Solvent Refined Coal
     Process",  Report No*  EPA 650/2-74~009f,  March 1975.  •

 7.  Grace, Rober J., "Development of the BI-GAS Process1,1 IGT Symposium,
     September 1973.

 8.  Grace, R.J., and Zehradnik,  R.L., "BI-GAS Program Enters Pilot
     Plant Stage", Fourth Synthetic Pipeline Gas Symposium, Chicago,
     October 30-31, 1972,,

 9   Engineering Study end Technical Evaluation of the Bituminous Coal
   "  Research, Inc. Two Stage Super Pressure Gasification Process.
     Research and Development Report No. 60 for Office of Coal Research
     by Air Products and Chemicals, Inc., 1970=,

10.  "Control Techniques for SO* Air Pollution", Rept, AP-52, U.S.
     Dept. Health, January 1969.

11.  Coalgate, J.L., Akers, D.J. and From, R.W. "Gob Pile Stabilisation,
     Reclamation, and Utilization", OCR R&D Report 75, 1973.

12   EPA Symposium "Environmental Aspects of  Fuel  Conversion  Technology"
     Colony Oil  Shale Development M.To  Atwood.  St. Louis, Missouri
     May 13=16,  1974, EPA-650/2-74-118.

13.  National  Public Hearings  on Po^jesr Plant  Compliance  with  Sulfur.
     Oxide Air Pollution  Regulations,  EPA Report  January 1974.

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                                    - 64 -
14.   Parrish,  R.  W.  and Neilson,  H.B.,  "Synthesis Gas Purification
     Including Removal of Trace Contaminants by the BENFIELD Process",
     presented at 167th National Meeting of ACS,  Div. of I&EC,
     Los Angeles, March 31-April 5,  1974.

15.   Hydrocarbon Processing April 1973, pp0  109-116

16.   Atmospheric Emissions from Petroleum Refineries, U.S. Dept. of Health,
     Education and Welfare, Publ0 No,  783, 1960.

17.   Characterisation of Glaus Plant Emissions,
     EPA Report EPA-R2-73-188, April 1973.

18.   Cooling Tower Operations
     Furlong, E., Environmental Science & Technology
     Volume 8, No. 8, August 1974, page 712

19.   Pearson, M.J., "Hydrocarbon Processing," 52, (2), p. 81.

20.   Lee, R.E., et a., "Trace Metal Pollution in the Environment", Journ.
     e£ Air Poll. Control, 23, (10), October 1973.

21.   Schultz, H.9 Hattman, E.  A., and Booker,  W.  B., ACS Div.  of  Fuel.
      Chem.,  Vol. 8,  No.  4, p.  108,  August 1973

22.   Billings, C. E., Sacco,  A.  M., Matson, W. R.,  Griffin, R. M.,  Coniglio,
      W. R.,  and Harley,  R. A., "Mercury Balance on a Large Pulverized  Coal-
      Fired Furnace", J.  Air Poll. Control Association, Vol. 23, No. 9,
      September 1973, p.  773

23.   Schultz,  Hyman  et al., "The  Fate of Some  Trace  Elements During Coal
      Pre-treatment and Combustion",  ACS  Div. Fuel  Chem.  8,  (4), p.  108
      August  1973

24.   Bolton,  N.E., et al,  "Trace  Element Mass  Balance Around a Coal-Fired
      Stream Plant",  ACS  Div.  Fuel Chem.,  18,  (4),  p. 114,  August  1973.

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

26.   Trace Elements  and  Potential Toxic Effects in Fossil Fuels
      H = J.  Hall,  EPA  Symposium "Environmental Aspects of Fuel Conversion
      Technology" St. Louis,  MO.,  May 1974.

 27.   Attari, A. "The Fate of Trace  Constituents of Coal During Gasification",
      EPA Report'650/2-73-004,  August 1973.

 28.'  Control of Mine Drainage from Coal Mine Mineral Waste, EPA Report
      14010 DDN 08/71 (NTIS No. PB-2Q8  326)

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                                   - 65 -
29°  Kim, A.G., "An Experimental Study of Ferrous Iron Oxidation in Acid
     Mine Water",  Proc. Second Symp. on Coal Mine Drainage Research, Mellon
     Institute, Pittsburgh, Pennsylvania,  May, 1968.

30=  Removal of Hydrogen Sulfide from Hot Producer Gas by Solid Absorbents
     Bureau of Mines - RI7947 (1974)

31.  Production of High Btu Gas from Light Petroleum Dist.
     R=J. Cockerham & George Percival,  Ind. Bag. Chem; Proc. Design &
     Development,  Volume 5, No. 3 (July,  1966), pp. 253-257

32.  CRG Route to SNG,  F.E. Hart et al.,Hydrocarbon Processing, April 1972
     P. 89,

33.  Substitute Natural Gas from Liquid  Hydrocarbons,  A°  Roeger.
     Proceed.52nd Annual Convention, Natural Gas Processors Assoc.
     Vol. 52, 1973 pp.  152-165.

34.  Status of Flue Gas Desulfurization Technology F.  T.  Princiottap
     EPA Symposium on Environmental Aspects of Fuel Conversion Technology.
     St. Louis, Missouri,  May 13-16, 1964,  EPA 650/2-74-118.

35.  Chemical Engineering:  Environmental Engineering,  October 21, 1974
     pp. 79-85.

36.  Grace, R.Jo, and Diehl, E°K»,  "Environmental Aspects of the BI-GAS
     Process", EPA Symposium on Environmental Aspects of Fuel Conversion
     Technology, St. Louis, Missouri, May 1974, EPA 650/2=74=118

37.  Environmental Aspects of El Paso's Burnhanel Coal Gasification
     Complex.  C. R. Gibson, et al.  EPA symposium on Environmental
     Aspects of Coal.  Conversion Technology, St. Louis,  Missouri.
     May 1974, EPA 650/2-74-118.

38.  Bertrand, R. R. et al., "Trip Report - Four Commercial
     Gasification Plants Nov. 6-18, 1974" EPA Report, May 1975.

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                                 TECHNICAL REPORT DATA
                           (Please read Inunctions on the reverse before completing)
 1. REPORT NO.
 EPA-650/2-74-009-g
                            2.
                                                        3. RECIPIENT'S ACCESSION*NO.
 4. T.TLE AND SUBTITLE Evaluation of Pollution Control in
 Fossil Fuel Conversion Processes; Gasification:
 Section 5.  BI-GAS Process
            5. REPORT DATE
            May 1975
            6. PERFORMING ORGANIZATION CODE
 7. AUTHOR(S)

 C.E. Jahnig
            8. PERFORMING ORGANIZATION REPORT NO

              GRU.9DJ.75
 9. PERFORMING ORGANIZATION NAME AND ADDRESS
 Exxon Research and Engineering Company
 P. O.  Box 8
 Linden, NJ  07036
            10. PROGRAM ELEMENT NO.

            1AB013; ROAP 21ADD-023
            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: 6/72-8/75
            14. SPONSORING AGENCY CODE
 15. SUPPLEMENTARY NOTES
 16. ABSTRACT
 The report gives results of a review of the Bituminous Coal Research,  Inc.
 BI-GAS Process,  from the standpoint of its effect on the environment.  The
 quantities of solid, liquid, and gaseous effluents were estimated, where
 possible, as well as the thermal efficiency of the process.   For the purpose of
 reducing environmental impact,  a number of possible process modifications
 or alternatives were proposed, and new technology needs pointed out.
 7.
                              KEY WORDS AND DOCUMENT ANALYSIS
                 DESCRIPTORS
                                           b.IDENTIFIERS/OPEN ENDED TERMS
                         c.  COSATI Field/Group
 Air Pollution
 Coal Gasification
 Fossil Fuels
 Thermal Efficiency
 Trace Elements
Air Pollution Control
Stationary Sources
Clean Fuels
BI-GAS Process
Fuel Gas
Research Needs
13B
13H
21D
20M
 8. DISTRIBUTION STATEMENT
 Unlimited
                                           19. SECURITY CLASS (ThisReport/
                                           Unclassified
                         21. NO. OF PAGES
                              72
                                           20. SECURITY CLASS (Thispage)
                                           Unlimited
                                                                    22. PRICE
EPA Form 2220-1 (S-73)

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