EPA-600/2-76-102
 April 1976
Environmental Protection Technology Series
                        ENVIRONMENTAL ASPECTS  OF
                  RETROFITTING TWO INDUSTRIES  TO
LOW-  AND  INTERMEDIATE-ENERGY  GAS  FROM  COAL
                                 Industrial Environmental Research Laboratory
                                      Office of Research and Development
                                     U.S. Environmental Protection Agency
                                Research Triangle Park, North Carolina 27711

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                RESEARCH REPORTING SERIES

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

;-•: ;;•  i.'.  . Environmental Health Effects Research
-•: .  • 2.    Environmental Protection Technology
     3.    Ecological Research
     4.    Environmental Monitoring
     5.    Socioeconomic Environmental Studies

 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
                     EPA REVIEW NOTICE

 This report has been reviewed by the U.S. Environmental
 Protection Agency,  and approved for publication.  Approval
 does not signify that the contents necessarily reflect the
 views and policy of the Agency, nor does mention of trade
 names or  commercial products constitute endorsement or
 recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield. Virginia 22161.

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                                       EPA-600/2-76-102

                                       April 1976
         ENVIRONMENTAL ASPECTS

    OF  RETROFITTING TWO INDUSTRIES

  TO LOW-  AND  INTERMEDIATE-ENERGY

                GAS FROM COAL
                         by

       D.A. Ball, A.A.  Putnam,  D.W. Hissong
J.Varga, B.C. Hsieh, J. H. Payer, and R. E. Barrent

           Battelle-Columbus Laboratories
                  505 King Avenue
                Columbus, Ohio  43201
               Contract No.  68-02-1843
                ROAPNo. 21BBZ-006
            Program Element No. 1AB013


       EPA Project Officer:  William J. Rhodes

     Industrial Environmental Research Laboratory
       Office of Energy, Minerals, and Industry
          Research Triangle  Park, NC 27711


                    Prepared for

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

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                   TABLE OF  CONTENTS

                                                           Page
 SUMMARY	xii
 LIST OF ABBREVIATIONS	xiii
 LIST OF CONVERSION FACTORS	   xiv

 INTRODUCTION 	   1
 OBJECTIVE	   5
 APPROACH 	   6
 CONCLUSIONS	   7

I.   TARGET INDUSTRY  SELECTION 	
     Evaluation of  Candidate Industries 	   9
          Petroleum Refining (SIC 2911)	12
          Blast Furnaces and Steel Milles (SIC 3312)....   14
          Other Industries Considered 	   21

II.   GASIFIFR AND GAS  CLEANUP SELECTION	24
     Gasifier Selection  	   24
     Industry Consideration in Gasifier Selection 	   27
     Gasification Systems Selection for the Steel
     Plant Model. .'	28
     Gasification Systems Selection for the Refinery
     Model	29
          Selection of Gas Cleanup Systems	30

III.   CONVERSION OF A  SECONDARY  STEEL  PLANT TO
       INTERMEDIATE-ENERGY GAS	   33
          Industry  Data	34
     Model Electric-Arc Furnace Steel Making Plant	36
     Model Plant Relationship to Industry	42
          Gasification Plant Design 	   42
     Burners and Furnaces in a Secondary Steel Plant.  ...   48
          Burner Types. .	   48
          Summary of Burner Changes 	   57
                            1X1

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                      TABLE  OF CONTENTS
                           (Continued)

                                                           Page

IV.   CONVERSION OF A REFINERY  TO LOW  ENERGY
      GAS	63

     The Refinery Industry	63
          Energy Consumption	63
          Types of Fuels Used	68
          Adaptability to Firing Low-Energy Gas	73
     Description of Model Refinery	77
          Size and Products	77
          Processes	77
          Current Fuel Use Patterns	78
          Geographic Consideration	79
          Other Considerations	79
          Potential Demand for  Low-Energy Gas	80
          Comparison of the Model Refinery With Other
          Refineries	80
     Gasification Plant Design	85
     Burners and Furnaces in  a  Refinery Plant	91
     Burners	91
V.   CONSIDERATIONS  IN DISTRIBUTING LOW-AND
     INTERMEDIATE-ENERGY GAS IN  INDUSTRY 	   98

     Volume and Pressure  Considerations 	   98

     Corrosion Considerations on Substituting Low- or
     Intermediate-Energy  Gas for Natural Gas	  102

          Corrosive  Species in  Low- and Intermediate-
          Energy Gas From Coal	105
          Mitigation and  Monitoring of Corrosion by Fuel
          Gas	107
          Conclusions	110
VI.   ENVIRONMENTAL CONSIDERATIONS IN  RETROFIT.  .  .  Ill

     Emissions  from the Gasification Process	Ill

          Model Steel Plant	Ill
          Model Refinery Plant	  114

     Emissions  from Combustion Processes	117

          Emissions of Sulfur Dioxide 	  117
          Emissions of Oxides of Nitrogen 	  122
          Particulate Emissions 	  134
          Emissions of Trace Constituents 	  134
                               IV

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                     TABLE OF CONTENTS
                           (Continued)

                                                         Page

VII.  POTENTIAL  IMPACT  OF ADVANCED HOT GAS
       CLEANING SYSTEMS. 	  135


VIII.  THE EFFECT OF AVAILABILITY OF  ALTERNATE
        CLEAN FUELS FROM COAL  ON INDUSTRIAL  DEMAND
        FOR LOW-  AND INTERMEDIATE-ENERGY GAS  ...  142

     Replacement of Natural Gas by  Liquified Natural
     Gas or Synthetic Natural Gas	142

     Replacement of Natural Gas by  Liquid Fuels	148

          Conclusions	151


REFERENCES	153
                       APPENDIX   A

COMBUSTION OF LOW- AND nMERMEDIATE-ENERGY GAS IN
INDUSTRIAL PROCESSES	A-l

  INTRODUCTION  	  A-l

     Flame Stability	A-l
          Presentation of Flame-Stability Data 	  A-3
          Discussion  of Flame Stability in Burners.  .  .  .  A-6
     Flame Radiations	A-23
     Flow Considerations 	  A-26

     Summary	A-29

  REFERENCES	A-30

  LIST OF SYMBOLS	A-31
                       APPENDIX  B

MATERIAL AND ENERGY BALANCES FOR MODEL PLANTS	B-l
                              v

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                      LIST OF TABLES
Table 1.   U.S. Total and  Industrial  Energy Consumption
           in 1972	     1

Table 2.   Domestic Fossil-Fuel  Reserves	     3

Table 3.   Energy Use by the  10  Major Industrial  Con-
           sumers of Gas,  Oil, and Coal by 4-Digit SIC
           Code for 1971	    10

Table 4.   Ranking of Industry Groups by  Selection
           Criteria	    11

Table 5.   Target Industry Location in Relation to
           Coal Availability  for Refineries	    13

Table 6.   Energy Use Patterns in Sample  Integrated
           and Secondary Steel Plants (1973)	    16

Table 7.   Estimated Energy Use  Patterns  in the
           Integrated and  Secondary Steel Industry.  ...    18

Table 8.   Target Industry Location in Relation to
           Coal Availability  for Secondary Steel  Mills.  .    20

Table 9.   Commercial Gasifiers  Considered for  Model
           Industry Plants	    25

Table 10.  Secondary Steel Mill  Production in the
           United States	    35

Table 11.  Steel Plant Statistics 	    41

Table 12.  Coal Analysis for  Steel Mill Model	    44

Table 13.  Gasification Plant Design  for  Steel  Mill
           Model	    45

Table 14.  Energy Balance on  Steel Mill Gasification
           Plant	    46

Table 15.  U.S. Refinery Size Distribution as of
           January 1, 1975	    64

Table 16.  Complexity Factors and Energy  Requirements  for
           Refining Processes	    65

Table 17.  Crude Runs and Energy Consumption Data for
           U.S. Refineries	    69
                                 VI

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                      LIST OF TABLES
                          (Continued)

                                                            Page

Table 18.  State-by-State  Breakdown of 1973  Crude Runs
           and Energy Consuirption  for U.S. Refineries.  .  .   70

Table 19.  Fuel Energy Contents Used  by Bureau of Mines.  .   71

Table 20.  Number of Refineries Using Hydrotreating
           Processes	75

Table 21.  Potential Demand for Low-Energy Gas at
           Model Refinery	81

Table 22.  Comparison of Energy Consumptions for Model
           Refinery With U.S.  Average Values	83

Table 23.  Gasification Plant  Design  for Refinery Model.  .   85

Table 24.  Refinery Model  Plant Coal  Analysis	87

Table 25.  Capacities and  Estimated Energy Consumption
           of Largest Refineries in the United States.  .  .   90

Table 26.  Furnaces in a Small Refinery	93

Table 27.  Required Pipe Size  for  Gas Distribution ....  100

Table 28.  Discharges From Steel Mill Model  Gasification
           Plant /	112

Table 29.  Discharges From Refinery Model Gasification
           Plant	115

Table 30.  Expected Emissions  of Sulfur Dioxide From
           Combustion Processes in Model Plants	121

Table 31.  Relative NO Production  of  Various Fuels at
           10 Percent Excess Air	127

Table 32.  Typical Ammonia Concentrations in Raw Un-
           cleaned Fuel Gas From Coal	132

Table 33.  Estimated Emissions From Raw and  Cleaned
           Fuel Gases	133

Table 34.  Advanced High-Temperature  Cleaning Systems
           Under Development	136

Table 35.  High-Btu Gasification Program	138
                             VII

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                      LIST OF  TABLES
                          (Continued)

                                                           Page

Table 36.  SNG Plants in Advanced Stages of Planning.  .  .   144

Table 37.  Composition  and Properties of Some Natural
           Gases, LNG, and SNG	   145

Table 38.  Coal Liquefaction	   147

Table 39.  Properties of Various Liquid Fuels	   149

Table A-l. Fuel Composition and Thermal Properties.  .  .  .   A-4

Table A-2. Fuel Stability Factors	   A-5

Table A-3. Comparison of Volumes of Fuel Gas to
           Natural Gas	   A-28

Table 3-1. Koppers/MDEA Gasification Plant Material
           Balance for Model Steel Plant	   B-2

Table B-2. Wellman-Galusha/Stretford Gasification Plant
           Material Balance for Model Refinery Plant.  ..  .   B-15
                      LIST OF  FIGURES

Figure 1.  Projected Domestic Natural Gas Production. . .     2

Figure 2.  Projected Domestic Oil Production	     2

Figure 3.  Statistical Distribution of the Capacities of
           Electric-Arc Furnace Melting Plants in the
           United States	    37

Figure 4.  Statistical Distribution of Electric-Arc
           Furnace .Nteltinq Plants in the United States
           Having Continuous Casting Machines 	    38

Figure 5.  Location of Electric-Arc Furnace Steelmaking
           Plants and the Location of Bituminous, Sub-
           bituminous and Lignite Coal Fields in the
           United States	    39
                           Vlll

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                      LIST OF FIGURES
                          (Continued)
Figure  6.    Composite Electric-Arc Furnace Plant Flow
             Sheet  (Capacities  in net tons)	     40

Figure  7.    Koppers-Totzek/MDEA Steel 14111 Gasification
             Plant	     43

Figure  8.    Steel  Mill Plot  Plan	     49

Figure  9.    Bloom  HTR Flat-Flame Nozzle-Mix Burner.  ...     50

Figure  10.   North  American 4832 Flat-Flame (or Radiation
             Type)  Nozzle-Mix Burner	     51

Figure  11.   Bloom  Forced-Air Radiant Tube  Burner	     53

Figure  12.   North  American 220 and North American 221
             Dual-Fuel Nozzle Mix Burner	     54

Figure  13.   North  American 214 Dual-Fuel Nozzle Mix
             Burner	     55

Figure  14.   North  American 223 Dual-Fuel Nozzle-Mix
             Burner	     56

Figure  15.   Bloom  401-L Long-Flame Burner	     58

Figure  16.   Bloom  Long-Flame Burner,  Cold  Air	     59

Figure  17.   Selas  Duradiant  Premix Burner  	     60

Figure  18.   Erie City Ring-Type Gas and  Oil  Burner for
             Boiler Use	     61

Figure  19.   Refinery  Energy  Consumption  Versus  Fuel
             Cost	".	     66

Figure  20.   Refinery  Energy  Consumption  Versus  Refinery
             Complexity	     67

Figure  21.   Plot Plan of Arco's  Cherry Point Refinery .  .     74

Figure  22.   Plot Plan of Mobil  Oil's  Joliet, Illinois
             Refinery	     75

Figure  23.   Land in Use for  Process Equipment and
             Storage at Refineries	     76
                                IX

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                      LIST OF  FIGURES
                           (Continued)

                                                           Page

Figure 24.  Flow Sheet for the Wellman-Galusha
            Gasification Plant	     86

Figure 25.  Refinery Plot Plan	     89

Figure 26.  Zink VPM Vertical Gas Burner for High
            Hydrogen Gas	     94

Figure 27.  Refinery Boiler Burner	     95

Figure 28.  Zink VYR Vertical Gas Burner for Process
            Heaters	     96

Figure 29.  Industrial Gas Distribution System	     99

Figure 30.  Required Gas Supply Pressure for Substituting
            Gas from Coal for Natural Gas in an Existing
            Distribution System	   101

Figure 31.  Compression Power for Steel Mill MOdel Gas
            Supply	   103

Figure 32.  Compression Power for Refinery Model Gas
            Supply	   104

Figure 33.  SO- Emissions Versus Sulfur in Coal	   118

Figure 34.  SO- Emissions Versus Sulfur in Fuel Gas . . .   120

Figure 35.  Effect of Air Preheat on Nitric Oxide
            Equilibrium	   123

Figure 36.  Effect of Total Air on Nitric Oxide
            Equilibrium	   125

Figure 37.  Effect on Total Air, Flame Temperature and
            Residence Time on Nitric Oxide Concentrations   126

Figure 38.  Fractional Conversion of NH, in Premixed
            Methane-Air Mixture .  .  .	   129

Figure 39.  Fuel Nitrogen in Liquid Fuel-Fired Rankine-
            Cycle Combustor Converted to NO	   130
                            x

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                      LIST OF FIGURES
                          (Continued)

                                                            Page

Figure 40.  Fuel Nitrogen Converted to NO	    131
                                          X

Figure 41.  Effect of Fuel Gas Chemical and  Sensible
            Heat on Combustion Temperature	    139

Figure 42.  Relative Volume of Fuel Gas Required at
            Different Fuel Gas Temperatures  for V^ + 70F.    141

Figure A-l. Flash-Back Velocity Gradient  as  a Function
            of Gas Concentration in Mixture  	    A-7

Figure A-2. Critical Heat Release Rate per Unit Volume
            (Flash-Back Velocity Gradient Times HHV
            of Mixture) as a Function  of  Gas Concentra-
            tion in Mixture	    A-8

Figure A-3. Flash-Back Velocity Gradient  Times  Gas
            Higher Heating Value  (HHV) as a  Function
            of Gas Concentration in Mixture  	    A-9

Figure A-4. Premix Burner, Flame Retention Type	    A-11

Figure A-5. Delayed Mixing Burners	    A-17

Figure A-6. Nozzle-Mixing Bunrers	    A-22

Figure A-7. Radiation From Adiabatic Flames  at  10
            Percent Excess Air	    A-24

Figure B-l. Koppers/MDEA Gasification  Plant  Material
            Balance for Model  Steel Plant 	    B-l

Figure B-2. Wellman-Galusha/Stretford  Gasification PLant
            Material Balance for Model Refinery Plant  . .    B-14
                               XI

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                              SUMMARY


         This study involved an analysis of the constraints and
environmental impact of converting selected industries to low-
and intermediate-energy gas from coal.  Two target industries
(the secondary steel industry and petroleum refining industry)
were selected for analysis.  A hypothetical model plant was de-
veloped for each target industry and characterized as to layout,
energy use, combustion process characteristics, and relation to
the respective target industry as a whole.  A gasifier and gas-
cleaning system combination was selected for each model plant and
sized to provide sufficient low- or intermediate-energy gas to re-
place the model plant's requirement for natural gas and oil.  Ma-
terial and energy balances were done for each model plant, and
the constraints involved in process modification, along with the
potential environmental impact, were evaluated.

         The model steel plant had a capacity of 996,000 metric
tons (1,100,000 tons) of molten steel per year and an average
demand for natural gas and oil of 21.1 x 106 MJ/day (20 x 109
Btu/day).  A Kopper-Totzek gasification plant with four 2-head
gasifier units combined with a MDEA (methyldiethanolamine) gas-
cleaning system was selected to provide intermediate-energy gas
(HHV 11.27 MJ/NM3; 285 Btu/scf)' for the plant.

         The model refinery plant had a capacity of 3,972,500
liter/day  (25,000 barrel/day) of crude oil and an average energy
demand for natural gas and oil of 4.13 x 106 MJ/day (3.92 x 10$
Btu/day).  A Wellman-Galusha gasification plant with three 10-
foot diameter gasifiers combined with a Stretford gas-cleaning
system was selected to provide low-energy gas (HHV 6.62 MJ/Nm3;
1062 Btu/scf), yielding a product gas with a high-heating value
varying from 9.26 MJ/Nm3 (235 Btu/scf) during the winter to 10.8
MJ/Nm3  (274 Btu/scf) during the summer.

         It was concluded that there were no major technological
constraints in converting the model secondary steel plant to inter-
mediate-energy gas or the model refinery to low-energy gas (when
mixed with refinery gas).  In both cases, however, most burners
and gas distribution networks would have to be replaced.  Based
on current data and knowledge, there appeared to be no insurmountable
environmental problems in retrofitting either model plant to gas
from coal providing appropriate commercially available control
equipment is employed.  However, studies will be necessary to
acquire new data to define the real environmental impact which
might require more or less control for new future sources.
                              xi i

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                       LIST OF  ABBREVIATIONS


scf      -  Standard cubic foot as measured at 60 F and 30 inches of
            mercury (American Gas Association standard temperature
            and pressure)

psia     -  Pounds pressure per square inch absolute

psig     -  Pounds pressure per square inch gage

osi      -  Ounces pressure per square inch gage

Kcal     -  Kilocalorie

J        -  Joule
                          /-
MJ       -  Mega joule (10  joule)

Kg       -  Kilogram

Ib       -  Pounds mass

Btu      -  British Thermal Unit

m        -  Meter

mm       -  Millimeter

Nm       -  Normal cubic meter

C        -  Degrees Celsius

F        -  Degrees Fahrenheit

N        -  Newton

ppm      -  Parts per million by volume (at 0 °C and 760 mm Hg)

HHV      -  High heating value of fuel including the latent heat of
            vaporization of water formed during combustion

LHV      -  Low heating value of fuel not including the latent heat
            of vaporization of water formed during combustion
                                   Kill

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                     LIST OF  CONVERSION  FACTORS


Btu  (at 60 F) x 0.252 x 103 =  calorie  (cal)

Btu  (at 60 F) x 1.055 x 103 =  Joule  (J)

feet x 0.3048 = meter  (m)

degrees Fahrenheit  (F) -32 x 0.555 = degrees Celsius  (C)

standard cubic foot  (scf)  (at  60 F and 30 in. Hg) x .0268
  normal cubic meter  (Mn3)  (at 0 °C and  760 itm Hg)

Btu/scf x 0.0394 = Msga Joule/tan3  (MJ/Mn3)

pound mass  (Ib) x 0.453 = Kilogram  (Kg)

lb/106 Btu x 11.798 = Kg/106 Real

U.S. ton (2000 Ib) x 0.906 = metric ton  (1000 Kg)

pound force per square inch (psi) x 6.89 x 103 =
  Pascal (Pa) = Newton/nr  (N/m2)

psi x 7.03 x 102 = Kg force/m2

ounces per square inch (osi) x 0.431 x 103 = Pa

grains x 6.5 x 10~^ = Kg

gallon (U.S.) x 3.78 = liter

barrel (42 gallon) x 158.97 = liter

acre x 4050 = m2
                                    XIV

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                         INTRODUCTION

          In the past several decades/ U.S. industry has become
 increasingly reliant on natural gas and petroleum as sources of
 energy.   Increased industry use of natural gas and oil as prime
 fuel'resulted from:  (1) the availability of these fuels at low
 cost;  (2)  the low purchase, operating, and maintenance cost of
 gas- and oil-fired equipment;  (3) the relatively dependable supply
 of gas and oil such that large fuel storage facilities were not
 needed;  and (4) the environmental acceptability of these fuels.
 As can be seen from Table 1, industry accounted for about 45 per-
 cent of the natural gas, 17 percent of the petroleum, and 32 per-
 cent of the total energy consumed in the United States in 1972.
          TABLE  1.   U.S.  TOTAL AND INDUSTRIAL ENERGY
                    CONSUMPTION IN 1972(l)
                      Energy Consumed,  IP12 MJ (IQ1-* Stu)
                     Natural GasPetroleumTotal
Industry
Total U.S.
II. 0 (10.4)
24.4 (23.1)
5.8 (5.5)
3.5 (33.0)
24.1 (22.9)
76.0 (72.1)

         In recent years, industry has been faced with acute
shortages of natural gas as a source of energy.  As a result,
many industries have become increasingly reliant on oil and
propane, the easiest and most immediately available substitutes
for natural gas.  Increased demand for these alternative  fuels,
however, along with the limited domestic supply and foreign
politics, have caused their cost to increase dramatically and
their availabitliy to be uncertain.

         Projections as to the future supply and availability of
natural gas vary.  A recent projection is shown in Figure 1.
The general conclusions are, however, that supply will continue
to be limited and that, either through allocation or increased
price, natural gas will be increasingly unavailable and unat-
tractive as an industrial fuel.  Oil is currently available to
industry as an alternative fuel to natural gas; however,  the

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availability  of this fuel  is largely a  function  of extensive
imports.   In  the  future it is probable  that there will be_in-
creasing private  and Government pressure  to reduce these  imports.
Domestic supply of  oil, on the other hand,  is limited, with
little hope'for significant increase supply in the future,  as
shown in Figure 2.
 H
 O
a
o
a:
a.
z
Z
20-

27-

24-

21-

18-

15-

12-

 9-

 6-

 3-
                   ACTUAL
     ANNUAL MARKET PRODUCTION
     (EXCLUDING FLARED, VENTED
     AND REINJECTED)
                            CUMULATIVE
                            PRODUCTION
                            THROUGH
                            1974= 478 TCP
                                            PROJECTED
                                                                      r
                                                                       20
                                                           WITH
                                                           STIMULATION
                                                           TECHNIQUES
  INCLUDES
  ALASKAN
  NORTH
  SLOPE

REMAINING RECOVERABLE'
AFTER 1974 =
     750 TCP
    +250 TCP FROM STIMULATION
                                         1,000 TCP TOTAL
                                                                      -27

                                                                      -24



                                                                      -18

                                                                      -15

                                                                      -12

                                                                      -9

                                                                      -6

                                                                      _.O
     1920   1930   1940   1950   1960   1970   1930
                                  CALENDAR YEAR
                                              1930   2000   2010   2020
                                  ai
                                  UJ
                                  a.
                                                                       03
                                                                       D
                                                                       U
                                                                       u.
                                                                       O
                                                                       V)
                                                                       _1
                                                                       _1
                                                                       E
                                                                       i-
         FIGURE 1.  PROJECTED DOMESTIC NATURAL GAS  PRODUCTION
                                                                    (2)
        IN THIS FIGURE, DOMESTIC OIL INCLUDES CRUDE AND NATURAL GAS LIQUIDS
    5.0-,
a
o
s.
a.
D
Z
V)
_J
UJ
cc
cc
CO
u.
o
CO
g
3
_i
5
4.0-
    3.0-
    2.0-
    1.0-
                     ACTUAL
                                               PROJ ECTED
               CUMULATIVE PRODUCTION
               THROUGH 1974 =
               123 BILLION BARRELS
                 WITH
                 ENHANCED
                 RECOVERY
REMAINING RECOVERABLE
AFTER 1974 =
  142 BILLION BARRELS
  +40 BILLION BARRELS WITH
  	  ENHANCED RECOVERY
  182 BILLION BARRELS, TOTAL
                                                                   13
                                                                  -12
                                                                  -11
                                                                  -10
                                                                  -9
                                                                  -8
                                                                  -7
                                                                   6
                                                                  r5
                                                                   4
                                                                  -3
                                                                  -2
                                                                  -1
     1920   1930   1940   1950   1960    1970   1980
                                CALENDAR YEAR
                                               I      I      i
                                             1990   2000   2010   2020
                                                                       V)
                                                                       Ul
                                                                       cc
                                                                       cc
                                                                       <
                                                                       CQ
                                                                       u.
                                                                       o
                                                                       CO
                                                                       z
                                                                       o
           FIGURE  2.  PROJECTED  DOMESTIC OIL PRODUCTION
                                                             (2)

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         A common recommendation is  for  industry  to  convert fuel-
using processes to America's most abundant  fossil-fuel  resource,
coal.  As can be seen in Table 2, coal resources  dwarf  those of
natural gas and oil in domestic supply.
             TABLE 2.  DOMESTIC FOSSIL-FUEL RESERVES
                                                     (2)
                               Recoverable Reserves	
               Resource       I012 MJ          (I015 Btu)
Coal
Natural Gas
Petroleum
12,700
818
840
(12,000)
(775)
(800)
         But, converting to direct firing of coal  in boilers  or
processes may require extensive alteration and the addition of
pollution control equipment.  Also, many types of  industrial  pro-
cesses are not readily adaptable to direct firing  of coal.

         An alternative to direct use of coal is to convert the
coal to a clean liquid or gaseous fuel prior to firing  it.  The
technology for doing this is not new.  Reportedly  there were  over
11,000 coal-gasification plants in the United States in the 1920 's
making a low-heating value fuel gas for a wide variety  of industrial
       .  Only a few of these plants remain in use today.
         A variety of types of gasification processes were used
for making gas from coal in  the past and many of these are  still
commercially available.  Basically the gas from these processes
could be categorized by heat content as either low-energy gas ,
having a heating value of about 4.7 to 7.9 MJ/Nm3  (120 to 200 Btu/
scf ) , or intermediate-energy gas, having a heating value of  about
9.85 to 13.8 MJ/Nm3 (250 to 350 Btu/scf ) .  Low-energy gas is made
by reacting air and steam with coal in a partial combustion  process
yielding a gas primarily composed of C02 , CO, H2 / and approximately
50 percent N*>.  When oxygen is substituted for the air, the  N2 is
reduced to about 1 to 2 percent and the heating value of the fuel
gas is doubled.  The intermediate-energy gas can be used as  a fuel
or as the synthesis gas for production of methane or higher  hydro-
carbon products.  Most gasifiers can produce either low- or  inter-
mediate-energy gas.  However, some slagging units are limited pri-
marily to oxygen-blown operation die to the higher temperatures re-
quired to maintain slagging conditions.

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         The primary reason this technology was practically aban-
doned in this country was the availability of natural gas and oil.
These high-grade fuels were cleaner, easier to use, less hazardous
to handle  (gas from coal contains toxic CO), and above all, less
expensive.  Their use has prompted the development of more sophis-
ticated burners and furnaces with precise heat release character-
istics and better control systems which allow safer, more efficient
operation with a minimum of operator attention.  Modern glass melting
operations, for instance, require about half the melter area for a
given production rate as melters did 30 years ago—when firing with
gas from coal was common.  This increase in productivity is a re-
sult of many improvements, but the availability of natural gas and
oil was an important factor.

         Converting industries from natural gas to gas from coal
involves many considerations, including fuel-gas production, uti-
lization of the fuel gas, and the environmental impact of gasi-
fiers.  Two of these considerations relate to coal gasification
for any application (power plant, industry, etc.), however, the
utilization aspect is much more critical for retrofitting indus-
trial applications where a wide variety of process characteristics
must be considered.  For instance, low- and intermediate-energy
gas has a heating value of from about one-sixth to one-third
that of natural gas.  In addition, other combustion properties
such as flame temperature, burning velocity, and radiation char-
acteristics will also be different than those of natural gas.

         This report describes the potential for conversion of
two model industrial plants from a primary dependence on natural
gas and oil to the production and utilization of fuel gas produced
on-site from coal.  Gasification, utilization, environmental, and
economic aspects are discussed with the primary purpose being to
assess the potential environmental problems and to aid in determin-
ing the priority that limited environmental resources should have
in these areas.

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                          OBJECTIVE
         The objective of this study was to quantitatively
evaluate the potential environmental impact of retrofitting
selected American industries from the use of natural gas and
oil to the use of low- and intermediate-energy fuel gas pro-
duced from coal and to quantify the major constraints and
problems that would be encountered in such a retrofit.

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                           APPROACH
         Two industries were selected as target industries based
on an analysis of their amenability to low- or inetermediate-
energy gas.  Hypothetical model plants were then developed based
on the characteristics of typical plants within each of the tar-
get industries.  Each of the model plants was characterized as to
its existing fuel-use and fuel-distribution patterns, existing
pollution abatement systems, and location relative to coal supply
and reserves.

         Subsequently, for each model plant, a gasification sys-
tem (including gasifier and gas-cleaning processes) was selected
on the basis of commercial availability, operating limitations,
unit size, and the potential for its integration into the model
plant, including the potential for use of byproducts or wastes.
The impact of installing the gasification plant and converting
the plant to distribution and utilization of the fuel gas were
determined, and an assessment was made of the environmental im-
pact of converting the plant to coal gasification.

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                           CONCLUSIONS


         It was concluded  that there were no major technological
constraints in converting  the model secondary steel plant to  inter-
mediate-energy gas or the  model refinery to low-energy gas  (when
mixed with refinery gas).   In both cases, however, most burners
and gas distribution networks would have to be replaced.  Based
on current data and knowledge, there appeared to be no insurmountable
environmental problems in  retrofitting either model plant to  gas
from coal providing appropriate commercially available control
equipment is employed.  However, studies will be necessary  to acquire
new data to define the real environmental impact which might  require
more or less controls for  new future sources.

         Sulfur and nitrogen compounds in the fuel gas (primarily
H2S and NHs) represent the primary source of atmospheric emissions
from combustion of fuel gas.  These constituents are also potentially
corrosive, especially if any water vapor is present.  Although the
corrosivity of these constituents has not been accurately defined,
it appears that their concentration in the fuel gas should  be re-
duced below that which would be considered environmentally  acceptable
to minimize corrosion in the intricate and extensive gas distribu-
tion systems found in most industrial plants.

         The major environmental hazard involves the gasification/
gas cleanup plant itself.  Many of the potential atmospheric  emis-
sions in the fuel gas become potential liquid and solid effluents
after they are removed from the gas.  A variety of processes  will
be required for treating the various liquid streams used in cleaning
and cooling the fuel gas.  In many industries water treatment sys-
tems are already in use similar to those that would be required for
a gasification plant.  In the refinery industry, for example, water
treatment processes are commonly used for removing oils, phenols,
ammonia, and H-S; however, in almost all cases these treatment sys-
tems would have to be enlarged or additional processes added  if
a gasification plant was installed.  The expertise and technology
for treating these various streams in an environmentally acceptable
manner appear to be avialable.

         The major factor in determining whether an industry  would
convert to low- or intermediate-energy gas is economics.   Even a
small gasification plant would involve many processes, most of
which involve either cleaning the gas or treating various effluent
streams associated with gas cleaning.   These various cleaning sys-
tems also constitute the major cost in a coal gasification plant.
Modifications required in furnaces are primarily determined by
the heating value of the gas with high heating value gases requiring
fewer modifications.  The requirements for a complex gasification
plant and attractiveness of a high grade fuel gas (such as inter-
mediate-energy gas from an oxygen-blown gasifier)  tend to favor
large-scale industrial applications.  Thus,  gasification is most
attractive for large individual industrial plants or groups of
smaller plants in an industrial park.

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                   I.   TARGET  INDUSTRY  SELECTION


            An important part of this study of industrial energy/fuel problems

was the selection of  the target industries for analysis.   To determine those

industries to be included, various four-digit SIC code industrial groups were

evaluated as to their applicability to low- and intermediate-energy gas

according to the following industry selection criteria.


      (1)    Consumption  of Natural  Gas  and Fuel Oil.   The se-
            lected industries should be major consumers of natural gas
            and fuel  oil on a national basis.  Selection  of  such in-
            dustries  would insure that, should they convert  to low- or
            intermediate-energy gas from coal, there would be a signi-
            ficant impact on releasing natural gas and oil for other uses.

      (2)    Amenability  of the Processes to Low- and Inter-
            mediate  Energy Gas.  The industries selected should have
            processes and plant sizes that would make them appear amen-
            able to conversion to low- or intermediate-energy gas.
            Results of a previous survey study on converting industrial
            processes to low-energy gas were used in evaluating industries
            relative  to  these criteria^4)-

      (3)    Location Relative  to Available Coal Supplies.  Any
            industry  selected should be generically located  near coal
            supplies.  Because this study involved only on-site gasi-
            fication,  coal would have to be shipped to the plant.

      (4)    Dependence on  Natural  Gas  and Oil.  Any  industry
            selected  should have a high degree of dependence on a
            source of clean gaseous or liquid fuels.   Those  industries
            that could more easily convert to direct use  of  coal would
            be considered less urgent for study than those that could not.

      (5)    Potential  for Long-Term Utilization of Low- and
            Intermediate-Energy Gas .  The cost of energy is im-
            portant to all industries, however, some industries are
            more energy  intensive than others and as a result, are
            more sensitive to energy costs.  These energy-intensive
            industries were felt to have more incentive to make the
            long-term commitment necessary in installing  a coal gasi-
            fication  facility.  Less energy-intensive industries, on
            the other hand, would be more likely to pay high prices for
            premium fuels (remaining natural gas and oil,  electricity,
            or future high-grade fuels from coal)  to minimize the
            amount of modification necessary in  their processing
            operations.

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                 Evaluation of Candidate  Industries

            A list of the major energy consuming industries (by four-digit
SIC code) was compiled for evaluating candidate industries.  Table 3 lists
17 industries including the 10 major consumers of natural gas, distillate
and residual fuel oil, and coal in 1971.  After initial screening of this
list the following industries were selected for further study:

            Petroleum Refining                     SIC 2911
            Blast Furnaces and Steel               SIC 3312
            Industrial Organic and                 SIC 2818,
              Inorganic Chemicals                      3819
            Hydraulic Cement                       SIC 3241
            Paper and Paperboard Mills             SIC 2621,
                                                       2631
            Primary Aluminum                       SIC 3334
            Glass Containers                       SIC 3221.

            These seven industry groups were then ranked in order for each
of the five criteria.  The results of this ranking are shown in Table 4.
The ranking is somewhat arbitrary and based on views gained from a variety
of sources of information resulting from this study and the previous study
on converting industrial processes to low- and intermediate-energy gas^4\
            According to this ranking, two industry groups, petroleum refining
(SIC 2911) and blast furnaces and steel mills (SIC 3312),  appeared highly
attractive for selection  as target industries.   Discussions were held with
representatives of both of these industries and, subsequently, these industries
were selected for detailed study.
      The analysis used in evaluating the two selected target industries  under
the five criteria was as follows.

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                         TABLE 3.  ENERGY USE BY THE 10 MAJOR INDUSTRIAL CONSUMERS OF
                                   GAS, OIL, AND COAL BY 4-DIGIT SIC CODE FOR 1971
SIC
3312
2818
3241
2621
2631
291 1
2819
3334
3221
3352
2821
261 1
2815
2824
2812
2823
3313
Rank! ng
Gas
Blast Furnaces and Steel
Industrial Organic Chemicals
(not elsewhere classified)
Hydrau 1 ic Cement
Paper Mills
Paperboard Mills
Petroleum Refining
Industrial Inorganic Chemicals
(not elsewhere classified)
Primary Aluminum
Glass Containers
Aluminum Rolling and Drawing
Plastics and Resins
Pulpmi 1 Is
Cyclic Intermediate and Crudes
2
3
5
6
7
1
4
8
9
10
-
-
-
Organic Fibers (non-eel 1 ulosic)-
Alkalies and Chlorine
Man-made Fibers (cellulosic)
E 1 ectro-Meta 1 1 urg i ca 1 Products
-
-
-
Oi 1
1
10
5
2
3
4
-
-
-
-
7
6
8
9
-
-
-
Coa 1
3
4
1
2
5
-
-
-
-
-
10
-
-
8
6
7
9
Fuel Use
Gas
689
638
219
212
191 (
1405 (
396 (
132 (
127 (
64
57
40
14
44
49
13
2
(653)
(605)
(208)
(201 )
181 )
1332)
375)
125)
120)
(61 )
(54)
(38)
(13)
(42)
(47)
( 12)
(2)
, I09 MJ/year (1
Oil
176
27
43
170
166
72
24
1
9.5
2
30
40
29
27
5
2
1
(167)
(26)
(41)
(161 )
(157)
(68)
(23)
(1 )
(9)
(2)
(29)
(38)
(28)
(26)
(4)
(2)
(1)
O12 Btu/year)(a)
Coa 1.
140
139
190
157
86
9.5
37
17
—
3
39
5
76
63
84
67
54
(133)
(132)
(180)
(149)
(82)
(9)
(35)
(16)
—
(3)
(37)
(4)
(72)
(60)
(80)
(64)
(51)
lota H D ;
1005
805
452
569
443
I486
457
150
136
70
127
84
1 19
135
138
82
57
(953)
(763)
(429)
(51 1)
(420)
(1409)
(433)
(142)
(129)
(66)
(120)
(80)
( 1 13)
(128)
(131 )
(78)
(54)
Total Energy
Use(c)
1323
958
452
555
460
1509
478
151
137
76
141
85
133
139
147
84
59
(1254)
(908)
(459)
(526)
(436)
(1440)
(453)
(143)
(130)
(72)
(134)
(81)
(126)
(132)
(139)
(80)
(56)

(a)  Gas  at  40.9 MJ/Nm3  (1038 Btu/scf), oil at 39.8 MJ/litre  (6.0 x  I06 Btu/42 gallon  barrel),  coal  at
    30.5 x  I03 MJ/metric  ton (26.2 x  I06 Btu/ton).
(b)  Total of  purchased  fossil  (gas, oil, coal).
(c)  Total of  all  purchased  fuels and  purchased electric power.

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                        TABLE 4.  RANKING OF INDUSTRY GROUPS BY SELECTION CRITERIA
                                      (High nurrbers indicate higher ranking)




Industrie 1

Blast Furnaces Organic and


Selection Criteria
Petroleum
Ref i n i nq
SIC 291 I
and
Steel Mi 1 Is
SIC 3312
1 norgan ic
Chemica 1 s
SIC 2818,2819
Hydrau 1 ic
Cement
SIC 3241

Paper and
Paperboard
Mi 1 Is
SIC 2621 ,2631


Primary
A 1 umi num
SIC 3334


Glass
Containers
SIC 3221
( I)  Industry Con-
sumption of Natural     7
Gas and OiI

(2)  AmenabiIity of
Processes to Low-       -,
and Intermediate-
Energy Gas

(3)  Industry Location
Relative to Coal Sup-   4
p I ies

(4)  Industry Dependence .
on Natural Gas and Oil
(5) Potential for Long-
Term Utilization of
Low- and Intermediate-
Energy Gas

TotaI                   28
31
18
15
16
12
20

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                                     12
Petroleum Refining  (SIC 2911)

            The petroleum refining industry ranks first in use of natural gas
and fourth in use of oil for fuel among American industries ranking it very
high under Criterion 1.  The use of natural gas in this industry is about
twice that of the second highest user, blast furnaces and steel.
            The major uses of fuel in a refinery are for process feed stock
heating and in boilers for steam generation.  The relative amounts of steam
and fuel for energy for various refinery processes are given later in this
report (Table 16).
            Process heaters are similar to water tube boilers in design.  Fuel
is fired into the heater which contains banks of tubes through which the oil
is pumped.  The major fuels used for this purpose are natural gas, refinery
gas, and possible some residual oil.  These process heaters and boilers are
considered relatively amenable to being converted to a low- or intermediate-
energy gas from coal'^).  Therefore, refineries also rank high under Criterion 2,
            The location of an industry relative to available supplies of coal
is also important because on-site gasification would require shipment of coal
to the plant.  Table 5 gives installed refinery capacity in various states
having significant coal resources.
            The first segment of Table 5 lists refinery capacity in the top
10 coal producing states.  This installed capacity accounts for 23.5 percent
of total U.S. refinery capacity.  The second segrtent of Table  5 includes
refineries that have significant coal reserves although not necessarily high
production rates.  When this segment is added to that for high coal-producing
states, the total installed capacity accounts for 58.3 percent of the total
U.S. capacity.  This segment of the industry would still rank first in natural
gas use and sixth in oil use of those industries shown in Table 1.  Therefore,
the refinery industry ranks high under Criterion 3.
            Refinery gas consists of off gases from various processes in the
refinery.  This gas can be a high grade fuel gas consisting of hydrogen,
methane,  ethane, propane, butane, and possible other hydrocarbons.  In 1973,
refinery gas accounted for about one-third of energy consumed in U.S. refineries
and was exceeded only by natural gas in fuels consumed for energy.  By using
refinery gas, residual oil, and its crude feed for energy, if necessary, a
refinery could always be energy self-sufficient.  However, many of these items,

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                      13
TABLE 5.  TARGET INDUSTRY LOCATION IN RELATION
          TO COAL AVAILABILITY FOR REFINERIES

Rank
1
2
3
4
5
6
1
8
9
10
Rank
4
7
15
14
2
1
17
13
5
Total
Total
Coal
Producing States
Kentucky
West Virginia
Pennsylvania
1 1 1 inois
Ohio
Vi rginia
1 ndiana
Alabama
Tennessee
New Mexico
Coal
Bearing States
Alaska
Colorado
Kansas
Missouri
Montana
North Dakota
Texas
Utah
Wyom i n g
(a 1 1 industry)
Ref in i ng
10° litre/day
26. 1
3. 13
120.3
185.7
93.7
8.42
89.5
5.46
6.98
16.4
555.8
Refining
I06 litre/day
10.5
9.5
71.1
17.1
25.0
9.32
624.7
22.7
29.7
819.5
1,375.3
2,360.0
Capacity,
barrel /day
164,000
19,750
757,020
1,168,150
589,770
53,000
563,275
34,375
43,900
103,060
3,496,300
Capacity,
barrel /day
66,050
60,000
447, 180
107,000
157,206
58,658
3,929/430
143,000
186,870
5,155,394
8,651,694
14,845,407
Percent of Tota 1 i n
Coal
Coal
Producing States
Producing and Coal- Bearing
23.
States 58.
5
3

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                                     14
particularly the various constituents in refinery gas, can be recovered as
premium fuels with wider adaptability than low- or intermediate-energy gas
from coal.  Therefore, although refineries have alternatives to natural gas
as a fuel, it may be highly attractive if these premium fuels resulting from
the refining operations are released for other uses and low- or intermediate-
energy gas from coal is fired in their place.  This would result in refineries
being relatively attractive under Criterion 4.
            The petroleum industry is also energy intensive.  The gross energy
consumed per 1967 dollar of value added for 1971 was 300 MJ (284 x 103 Btu)
per 1967 dollar   .  This value is higher  (indicating more energy intensive)
than any other industry considered in this study.  Also, refineries represent
considerable capital investment and installing a high investment long-term
energy supply system, such as a coal gasification plant, would be within
reason.  Refineries would, therefore, tend to rank high under Criterion 5.

Blast Furnaces and Steel Mills (SIC 3312)

            In conversations with representatives of the iron and steel industry,,
it was discovered that, for purposes of evaluating the applicability of gas
from coal, basic steel mills (as represented by SIC 3312) should be generically
separated into integrated and nonintegrated types.  Integrated mills are
generally large plants that produce semifinished steel products directly from
iron ore.  Secondary or nonintegrated mills tend to be smaller plants and
produce a somewhat more finished grade of product but start with iron and
steel scrap or prereduced iron ore pellets.
            The principle differences in these two generic types of plants rela-
tive to the potential for utilization of low- or intermediate-energy gas is in
the ability of the integrated plant to reduce iron ore to iron in a blast furnace
by combining the raw ore with coke and lime under intense heat.  The blast
furnace,  along with the coke oven used to pyrolize coal into coke, produces
by-product fuels in the form of combustible tars and gases which reduce the
need for higher grade fuels such as oil and natural gas.  Secondary mills,
on the other hand, have no sources of such by-product fuels and must rely
on purchased fuels such as oil and natural gas as their energy sources.  A

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                                      15

recent MSI  survey(7),  for example, revealed that  in 1973 a sample of  in-
tegrated steel plants was only about  18 percent dependent on natural gas
as a source  of energy, whereas a sample of secondary mills was 66 percent
dependent.
             Discussions with representatives of the integrated steel industy
revealed that integrated plants would react to shortages of natural gas and
oil by increasing their utilization of by-product blast furnace gas, coke-
oven gas, and tars.  Blast furnace gas with a heating value of about 3.5
(90 Btu/scf) can be used for underfiring coke ovens, boilers, and preheating
air injected into the blast furnace.  Coke-oven gas with a heating value of
about 19.7 MJ/Mn   (500 Btu/scf) can be used almost anywhere in  the plant
where natural gas is used.  Tars, which are normally sold, could be used as
an additional source of fuel, if necessary.
             In the secondary steel industry, there are few alternatives to
natural gas  as a fuel.  Many processes in the industry require a clean
gaseous or liquid fuel.  In recent years gas shortages have forced plants
to use more  oil and propane, fuels which are expensive and occasionally
hard to obtain due to short supply.   Low- or intermediate-energy gas could,
therefore, be an attractive fuel for  this segment.
             Statistics do not distinguish specifically between the integrated
and secondary segments of the industry.  Therefore, in order to determine
how the secondary steel industry ranks under Criterion 1, the potential
displacement of natural gas must be estimated from available data.
            A 1973 survey of energy use in 16 sample integrated companies
and 35 sample secondary companies^) produced the data given in Table 6.
Assuming that the 16 integrated companies sampled were the largest of the
18 integrated companies, the figures shown in Table 6 represent 186 of 195
blast furnaces(8) or roughly 95 percent of national capacity.   The estimated
total integrated steel production in 1973 would then be
                  80,321,430/0.95 = 84,548,873 metric tons
                                    (93,321,000 tons).

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                   TABLE 6.   ENERGY USE PATTERNS IN SAMPLE INTEGRATED
                             AND SECONDARY STEEL PLANTS (1973)(7 *
 Total  1973 Industry Shipments	100,978,230 metric tons
                                              (III,455,000 tons)

 For the 16 sample integrated companies

   Net shipments	80,321,430 metric tons
                                              (88,655,000 tons)

   Natural  gas consumed	566 x I03 MJ  (537 x 10l2 Btu)
                                                            6.0 x I06 Btu/ton

   Oil  consumed	241 x I03 MJ  (229 x I012 Btu)
                                                            2.6 x I06 Btu/ton

   Propane  consumed	0.84 x I03 MJ (0.8 x I012 Btu)
                                                            2.6 x I06 Btu/ton

For the 35  sample secondary companies

   Net shipments	6,220,596 metric tons
                                              (6,866,000 tons)

   Natural  gas consumed	73 x I03 MJ  (69.5 x 10l2 Btu)
                                                           10.I x I06 Btu/ton

   Oil  consumed	10 x I03 MJ  (9.6 x I012 Btu)
                                                           1.4 x I06 Btu/ton
   Propane  consumed	0.3 x I03 MJ (0.3 x I012 Btu)
                                                           1.4 x I06 Btu/ton

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                                     17
            Assuming also that the 35 secondary companies sampled were chosen
more or less randomly from the 126 companies  (listed in Reference 9), then
the figures in Table 6 would represent approximately 35/126 or 28 percent of
the national capacity.  The estimated total secondary steel production in 1973
would the be
                6,220,596/0.28 = 22,216,414 metric tons
                                 (24,521,428 tons).
Ihe total production estimated by this method is 106,762,240 metric tons
(117,842,428 tons)(9)
            By this estimation, integrated steel plants account for roughly
79 percent of steel production and secondary steel plants approximately 21
percent.  Applying the energy use per ton data of Table 6, the resulting
energy use estimated in Table 7 are obtained.
            It is estimated that the secondary steel industry consumes approxi-
mately 31 percent of the total natural gas consumed in the steel industry and
26 percent of the combined natural gas and oil.  In 1974, the latest year for
which figures are available, the total natural gas used by the steel industry
was 704.6 x 109 MJ (667.9 x 10   Btu).  Therefore, considering conversion of the
secondary steel industry to fuel gas from coal, the estimated possible displace-
ment of natural gas is 218.4 x 109 MJ (207 x 1012 Btu), and the displacement
of oil and natural gas combined is 288 x 109 MJ (273 x 1012 Btu)*.
            In 1971, the year for which industry fuel-use data are presented in
Table 3, the secondary steel industry would have consumed about 213.1 x 109 MJ
(202 x 1012 Btu) of natural gas and about 21.7 x 109 MJ (20.6 x 1012 Btu) of
oil.  This would rank the secondary steel industry eighth in natural gas use
and also eighth in combined use of natural gas and oil.  This would still rank
the secondary steel industry high under Criterion 1.
            Fuel-using processes in  the secondary steel industry are similar
to those in the primary or integrated industry and consist of various types
of furnaces for heating steel for a variety of forming and heat-treating
*1974 was not a high-production year for the steel industry; thus, these
 values might be considered minimum values.

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              TABLE 7.  ESTIMATED ENERGY USE PATTERNS IN THE
                        INTEGRATED AND SECONDARY STEEL INDUSTRY
 Estimated integrated steel company data
      Net shipments	84,548,826 metric tons
                                             (93,321,000 tons)
                                                     /-\                  I O
      Natural gas consumed	591 x  I09 MJ  (559.93 x  10   Btu)
      Oil and propane consumed	256 x  I09 MJ  (242.63 x  10   Btu)

Estimated secondary steel  company data
      Net shipments	22,216,414 metric tons
                                             (24,521,428 tons)
      Natural gas consumed	261 x  I09 MJ  (247.67 x  I012 Btu)
      Oil and propane consumed	36 x I09 MJ   (34.3 x 10 l2 Btu)
Total Estimated Natural  Gas Use	851 x  I09 MJ  (807 x  10l2 Btu)
Total Estimated Oil and  Propane Use	292 x  I09 MJ  (277 x  I012 Btu)
Percent of total  industry  natural gas used by secondary mills	31 percent
Percent of total  industry  natural gas, oil, and propane used by
  secondary mills	26 percent
oo

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                                      19
operations.  Many of these  furnaces,  like those in the integrated steel
industry, are designed to allow conversion  from natural gas to coke-oven
gas which has a heating value of about 19.7 MJ/Nrr  (500 Btu/scf).  Many of
the furnaces are considered relatively easy to convert to at least an inter-
mediate-energy gas with 11.8 MJ (300  Btu/scf).  Thus, the secondary steel
industry ranks relatively high  under  Criterion 2.
            A further refinement of the potential for use of low- and inter-
mediate-Btu gas in  the secondary steel industry is obtained by estimating
that segment of the industry in relative close proximity to sources of coal.
liable 8 lists installed electric-arc  furnace capacity  (electric arc furnaces
are used nearly exclusively in  the secondary steel industry) in the top
10 coal-producing states('°5 and in 9 additional states that have significant
coal reserves.  Thus, 57.6  percent of the industry is located in the top 10
coal-producing states, and  70.4 percent of  the industry is located in states
having significant production or significant reserves.  Considering that the
secondary steel industry located in coal-producing or coal-bearing states has
a high potential for conversion, a more refined estimate of the amount of
natural gas and fuel oil that could be displaced by low- or intermediate-energy
gas in the secondary steel  industry is approximately 89.6 x 109 to 105.5 x 109
MJ (85 x 1012 to 100 x 1012 Btu) of natural gas and from 100.2 x 109 to
122 x 109 MJ (95 x 1012 to  116  x 1012 Btu)  of natural gas and fuel oil per
year.  Thus, in relation to Criterion 3, the secondary iron and steel industry
would rank high.
            Ihe dependence  of the secondary steel industry on a source of clean
gaseous or liquid fuel was  mentioned earlier.  The major portion of fuel use
in a secondary mill is for  furnaces which generally could not be converted
to direct firing of fuels such  as coal, nor could these processes be easily
replaced with those that could  fire coal directly.  Thus, the secondary steel
industry would rank high under  Criterion 4.
            The basic metals industries are considered highly energy intensive.
The gross energy consumption per 1967 dollar of value added for SIC 331

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                            20
 TABLE 8.  TARGET INDUSTRY LOCATION IN RELATION TO COAL
           AVAILABILITY FOR SECONDARY STEEL MILLS


Rank
1
2
3
4
5
6
7
8
9
10


Rank
4
7
15
14
2
1
17
13
5

Total
Total (a
Percent
Coal
Producing States
Kentucky
West Virginia
Pennsy 1 vania
1 1 1 inois
Ohio
Vi rginia
Indiana
Alabama
Tennessee
New Mexico

Coal
Bearing States
Alaska
Colorado
Kansas
Missouri
Montana
North Dakota
Texas
Utah
Wyoming


1 1 industry)
of Tota 1 i n
Electri
IOJ metric
625
136
7,234
4,222
3,420
245
1,1 10
489
226
—
17,708
Electri
10^ metric
__
453
45
1,087
—
—
2,346
—
—
3,932
21,640
30,743

c Arc Capacity,.
ton/year \0J ton/year
690
150
7,985
4,660
3,775
270
1,225
540
250
—
19,545
c Arc Capacity,
ton/year 10^ ton/year
__
500
50
1,200
—
—
2,590
—
—
4.340
23,885
33,933

Coal Producing States                      57.6
Coal Producing and Coal Bearing States     70.4

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                                     21

 (basic metals) was 44.7 x 103 kcal  (177.5 x 103 Btu) per 1967 dollar of value
 added^ for 1971 which is one of the highest of the various industries con-
 sidered in this study.  This would result in secondary steel also ranking high
 under Criterion 5.

 Other  Industries  Considered

            Seven other industrial groups that consume significant amounts of
 natural gas and oil for fuel were also considered along with petroleum refining
 and secondary steel mills.  These seven other groups were felt to be less
 attractive than the two selected;  however, they would not in all cases be
 considered unattractive for study.

            Industrial Organic and  Inorganic  Chemicals [not elsewhere
 classified] (SIC 2818, 2819).  The industrial chemical industry (SIC 281)  involves
 the production of a wide variety of chemical products.  The two groupings con-
 sidered here, organic and inorganic chemicals not elsewhere classified,  are by
 far the major fuel-using groups within the industrial chemicals industry;  how-
 ever, they also involve a wide variety of products.
            In production cf chemical products, the  major use of natural gas and
 oil as fuel is in boilers for steam generation.  In  one study^'' \  boiler fuel
 use was estimated at 50 to 60 percent of total process energy needs,  and in
 discussions with a major chemical  company, it was learned that boiler fuel use
 in many plants could range from 75 to 90 percent of  all process energy use.   In
 discussions with this same company, it was learned that it would be more eco-
 nomical to replace existing gas- and oil-fired boilers with coal-fired boilers
 equipped with appropriate pollution control devices  (particulate and  SCO  than
 to build a coal gasification plant for firing coal.
            Nbnboiler fuel use in  a chemical plant consists of items  such as
natural gas reforming, catalyst regeneration,  and feedstock heating or heating
 to maintain prescribed reaction temperatures.   Due to the combustion  require-
ments of these processes (extremely close temperature control with  a  large

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                                     22
number of burners per unit), thery are considered unattractive to retrofitting
to low- or intermediate-energy gas from coal.
            For these reasons the industrial chemical industry as a whole was
considered unattractive for use as a target industry in this study.  This,
however, should not imply that in particular cases industrial chemical plants
may not be attractive applications for low- and intermediate-energy gas from
coal.

            Hydraulic Cement (SIC 324).  The manufacture of hydraulic cement
was also considered as a potential target industry.  Cement plant fuel use
is confined almost entirely to one process; firing the long inclined rotating
kilns used in producing the clinker necessary for making cement.  These kilns
are commonly fired from the product discharge end with a small number of large
burners.
            Many cement plants are fired with coal, and in fact, the hydraulic
cement industry ranks first in coal consumption for U.S. industry (Table 3).
Kilns fired with oil or natural gas would be considered relatively convertible
to low- or intermediate-energy gas.  However, because the cement industry is
relatively evenly scattered throughout the country to maintain close proximity
to markets and minimize shipping costs, many of those plants designed for natural
gas and oil would be located in areas where coal is not readily available.  Also,,
if coal were available, it may be more economical to convert a gas- or oil-
fired kiln to direct coal firing.   For these reasons the cement industry, though
potentially attractive for application of low- and intermediate-energy gas,
was not selected as a target industry for this study.

            Paper and Paperboard Mills (SIC 2621, 2631).  This industry
combination ranks fourth in combined consumption of natural gas and oil of those
industries listed in Table 3.  Industries in this group were not selected as
target industries because the vast majority of fuel used in a paper mill is
for boiler applications.  Installation of a coal gasification plant to supply
gas primarily for boiler firing is not considered economically competitive
with direct coal-fired boilers.  Also, a large fraction of  the paper industry

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                                     23
is located in  the northwest and northeast sections of the country—close to
supplies of timber but where coal availability is low.

      Primary Aluminum  Industry  (SIC 3334).  Primary aluminum ranks eighth
in use of natural gas for industries listed in Table 3.  This fuel is used
principally for calcining alumina and refining and melting operations in  the
plant as the basic production process uses the Hall Heroult electrolytic method.
Due to the high electric energy required for producing aluminum, most aluminum
plants are located in areas where cheap hydroelectric power is readily available,
such as the northeast and northwest area of the Ifaited States.  These areas
generally have poor coal availability and, thus, primary aluminum was not con-
sidered as attractive as the two target industries selected.

            Glass Containers (SIC 3221).  The glass container industry is
considered a relatively attractive candidate for conversion to intermediate-
energy gas.  The glass melting operation is by far the major energy-consuming
process, consuming about 85 percent of energy used in glass making.   The melter
consists of a large refractory-lined tank where usually natural gas is fired
over the molten glass.  Temperatures in the melter are high (often over 3000 F)
and require close control.   In natural-gas-fired melters, regenerators are
used to preheat combustion air to obtain the necessary melter tempereatures and
improve efficiency.  Converting these melters to low-energy gas from air-blown
gasifiers would be difficult.  However, the higher flame temperatures and other
properties of intermediate-energy gas make it an attractive candidate for
substitution.
            The glass industry is highly dependent on natural gas; however, many
container glass plants (over 50 percent)  use electric heating to boost the
capacity of gas-fired melters.   Some all-electric melters have been built and
offer certain advanatages in lack of pollution-control requirements  and higher
thermal efficiency of the melter itself.   In the future the glass industry
could shift more and more to electric boosting and all-electric melting to
relieve the dependence on natural gas ^'2 ^
            As a result of  these considerations,  the glass industry  was con-
sidered somewhat less attractive than the two target industries selected for
this project.

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                                     24

               II.   GASIFIER  AND  GAS CLEANUP  SELECTION

            For each of the hypothetical model plants studied, a variety of
gasifier-gas cleanup system combinations were considered.  These various
combinations were screened and eventually one combination was selected for
each of the two model plants.  During the screening, an attempt was made to
appropriately match the gasification system characteristic with model plant
requirements.  Thus, the gasifier/plant combinations reported here appear
to be reasonable selections for the model plants of interest.  Actually, for
most applications several different gasifier-gas cleanup systems might be
selected for a given application by another investigator or after more in-depth
analysis.

                           Gasifier Selection

            In selecting gasifiers for model plants, attention was given only
to those processes that had been commercially proven in the past and are
currently commercially available.  Table 9 lists the 10 processes considered
along with some of their salient characteristics.  These processes consist
of three basic types:  entrained slagging, fixed bed, and fluidized bed.  Both
air-blown and oxygen-blown configurations were considered.
            Entrained slagging gasifiers are represented by the Kbppers-Tbtzek
and Babcock & Wilcox.    Entrained slagging gasifiers have the advantage of
being able to fire nearly any coal regardless of characteristics.  They also
are capable of being produced in larger unit sizes with higher gas production
rates per unit.  The gas produced in these units, due to its high temperature,
usually contains no tars, phenols, or oils, and is also generally very low in
ammonia.
            Entrained gasifiers require pulverizing of the coal,  usually to a
size specified as 70 percent through a 200-mesh sieve.   They also are primarily
restricted to oxygen-blown operation, producing a gas of about 300 Btu/scf.   The
lower temperatures that accompany air-blown operation make it difficult to main-
tain slagging conditions, and when air-blown operation is possible,  it pro-
duces a generally low-grade gas of around 4.7 MJ/Mn  (120 Btu/scf).   In the oxygen-
blown configuration, entrained slagging units generally require more oxygen

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                  TABLE 9.   COMMERCIAL GASIFIERS CONSIDERED FOR MODEL INDUSTRY PLANTS
                                         Unit Output,
Gasi fier
                                    10° MJ/day   (10   Btu/day)
                                                Potential
                                                Byproducts
                                 Limitations
Lurgi
fixed/agitator
                                     8.4-12.7
Wei I man Galusha


Applied
  Technology


Winkler


Riley Morgan

Wooda I I
  Duckham


Babcock &
  WiI cox

M. W.  Kellogg


Wilputte
f ixed/agitator


fixed/2-stage



fluidized


f ixed/agitator

f ixed/2-stage



entrained slagging


fixed/agitator


fixed/agitator
                       16
                      0.7
(8r12)
Koppers-Totzek   entrained slagging  8.4-17.4     (8-16.5)
                    1.6-2.6     (1.5-2.5)
                    0.2-2.4     (0.2-2.3)
                    1.4-14.8    (1.3-14)
                    1.6-3.2     (1.5-3.0)
                                  ( 1 .0)
                                                   (15)
                    2.6-3.7     (2.5-3.5)
                                                    0.6
tar, oil, phenols,


steam


tar, oil, phenols,


tar, oiI, phenols,
NH3


steam


tar, oil, phenols,
            tar, oil, phenols,
            NH


            steam
            tar, oiI,  phenols,
            NH3

            tar, oiI,  phenols,
            NH-,
Needs sized low-
caking coal

Oxygen-blown only,
pulverized coal

Needs sized low-
caking coal

Needs si zed coaI,
free swelling  index
<3

Needs crushed  low-
caking coal

Needs sized low-
caking coal

Needs sized coaI,
free swelling  index
<3

Primarily 0~-blown,
pulverized coal

Needs sized low-
caking coal

Needs sized low-
caking coal
                                                                                          Ul

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                                    26
than fixed-bed or fluid-bed units.  These units operate at high gas tempera-
tures usually over 1650 C  (3000 F) which could result in significant loss of
sensible heat in  the gas  if extensive heat recovery equipment is not employed.
These high gas temperaures do allow the entrained slagging unit to produce a
significant amount of steam which may become a valuable by-product in some
industry situations.
            Fixed-bed gasifiers have certain limitations of coal-feed character-
istics for proper operation.  Generally, coals with low-caking characteristics
or low free-swelling index (generally Western lignitic coal or some low-
swelling, free-burning Eastern coals) work best in  these gasifiers.  Agitator-
type fixed-bed units such  as Lurgi, Vfellman Galusha, Riley Morgan, Kellogg,
and Wilputte can generally utilize coals with mildly caking characteristics—
up to a free-swelling index of about 7.  Two-stage fixed-bed units such as
Applied Technology Incandescent and Woodall Duckham are limited to coals with
a free-swelling index of less than 3.  Fixed-bed units also require the coal
to be carefully sized for  proper operation.   Coal feed is usually double screened
to reduce the percentage of undersized and oversized particles.  With bituminous
coal, elimination of as great a percentage of the fines (particles less than
0.6 mm (1/4 inch)) as practical is important.
            Fixed-bed units, due to their lew temperature of operation, produce
a significant amount of tars, phenols, and oils in  the product gas.  These must
be removed prior to use in most industrial situations.  These constituents may,
in many cases, represent pollutants or potential wastes, but in some industrial
situations may be used as  by-products in the industrial processes.  Fixed-bed
units are also limited to  relatively small unit capacities.  This is due to an
inherent limitation on  the through-flow velocity and also a limitation on
manufacturing large rotating parts (such as grates or agitator arms for the
inside of a vessel).  Fixed-bed units are capable of high thermal efficiencies,
however, approaching 90 percent on a hot gas basis.  They also have high
turndown ratios and are capable of operating at very low loads in an efficient
manner.  Many fixed-bed units are rated at turndown ratios of over 90 percent.

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                                     27
            Only one fluidized-bed gasifier, the Winkler, has been commercially
proven at this time.  In fact, the Winkler gasifier was the first demonstration
of the fluidized-bed principle.  Fluidized-bed gasifiers are limited to mildly
caking coal, similar to fixed-bed gasifiers.  Coal for the Winkler gasifier
must  first be crushed to a size less than 0.95 cm  (3/8 inch), and undersize
particles or fines can be tolerated.  However, a significant amount of the ash
 (up to 70 percent) is carried away with the gas stream and must be removed prior
to the gas being used.  These units operate at gas temperatures of 815 to 982 C
 (1500 to 1800 F), about half way between those of fixed-bed units and entrained
slagging units.  Ihese units are available in relatively large unit capacities,
have relatively high turndown ratios, can operate at up to 50 percent over
design capacity, and relatively simple in operation.

          Industry  Consideration in Gasifier  Selection

            The characteristics of a particular gasification system are im-
portant when considering its applicability to a particular industry.   In some
industries the production of tars, phenols, oils, and ammonia commonly pro-
duced in fixed-bed processes would be considered valuable byproducts.   In
other industries, however, these constituents would be troublesome wastes and
would have to be disposed of in some acceptable manner.   On the other hand,
some industries may have a need for the large amounts of steam generated in
cooling down the hot gas entrained slagging processes.  Some industries may
have the need for the high turndown capability and flexibility of fixed-bed
units, whereas other industries may prefer the high on-stream factors and con-
tinuous operating capability of the entrained or fluid-bed units.  Also, some
industries will have the need for a higher grade gas—such as an intermediate-
energy gas produced from an oxygen-blown gasifier.   In these cases either an
entrained, fixed-bed, or fluid-bed unit would be appropriate.   In other cases,
however, this higher grade gas may not be necessary, and an air-blown gasifier
(without the necessity of an oxygen plant)  would be satisfactory.  These cases
would tend to be selective for fixed-bed units which produce a higher grade
gas when air-blown than either an entrained or fluid-bed unit.

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                                     28
             The size or  unit capacity of the gasifier is important when con-
 sidering it for industry.   Entrained and fluidized-bed units are offered primarily
 in large unit capacities.   Fixed-bed units, on the other hand, are restricted
 to relatively small unit capacities.  In a particular design, multiple numbers
 of gasifiers are attractive in  that they offer greater load flexibility and
 the ability to carry some  fraction of the load should one unit fail.  Too many
 units, however,  minimize the advantages of economy of scale and generate in-
 creased  complexity.   Hence,  industrial plants with large energy demands may
 find it  attractive  to select a  few entrained or fluidized-bed units; whereas,
 industrial plants with smaller  energy demands will find it attractive
 to select several atmospheric fixed-bed units.  These considerations were
 used in  making a cursory evaluation of which gasifier, cleanup system com-
 binations were most applicable  to the two model plant studied.
                Gasification  Systems Selection for
                        the Steel Plant Model
            The steel plant model in  this study has an energy demand of from
16 x 106 to 24 x 106 Ml/day  (15 x 109 to 23 x 109 Btu/day).  Therefore, only
those gasifiers with larger unit capacities—that is, Koppers-Totzek, Babcock
& Wilcox, Winkler, and Lurgi—were considered.  The other units listed in
Table 9 would involve a large number of individual units to satisfy this energy
demand and were considered unattractive for this reason.  The coal selected
for use in the model steel plant was a lignite type with a low free-swelling
index which would present no particular problem to any of the listed gasifiers.
Therefore, feed stock characteristics were not considered important as a
selection parameter in choosing a suitable gasification process.
            The steel plant would have no use for byproducts such  as  tars,
phenols, oils, or ammonia, and, therefore, attention was directed primarily
at entrained and fluidized-bed processes which do not produce significant
amounts of these products.  Cxi the other hand, the steel plant could possibly
have use for a low-grade steam, either for space heating or for process use,
which would make the selection of entrained or fluidized-bed processes more
attractive.  Of the three nonfixed bed processes (Koppers-Totzek,  Babcock &

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                                       29

Wilcox, and Winkler), the Koppers-Totzek was chosen as the representative
gasification process for detailed  consideration.  This selection was based
primarily on the fact that more information was available on the performance
of the Koppers-Totzek process process than either of the other two gasifiers.
Both the Babcock & Wilcox and Winkler processes are also attractive, and
designs based on these processes should involve similar considerations to that
based on the Koppers-Totzek.

                    Gasification Systems  Selection-
                       for the  Refinery Model

            The model refinery has an energy demand approximately 3.5 x 10
to 4.6 x 106 MJ/day  (3.3 to 109 to 4.4 x 109 Btu/day).  Due to this relatively
small energy demand, fixed-bed units with lower unit capacities were con-
sidered attractive for selection.  Also, because the gas made from coal would be
blended with refinery gas having a heating value of about 39.4 MJ/Mn^ (1000
Btu/scf), air-blown operation producing low-energy gas was considered to be
satisfactory.  Also, the refinery potentially could utilize the tars, phenols,
and the other chemical products in fixed-bed processes.
            The coal selected for the refinery was a lignitic coal having a
free-swelling index of about 4 to 4-1/2.  This restricted the selection of a
gasification process to those fixed-bed units having agitator-type beds.  The
two-stage fixed-bed processes such as Ffoodall-Duckham and Applied Technology
Incandescent are restricted primarily to coals with free-swelling index of
less than 3.
            The Wellman Galusha was selected over the other small agitator-type
fixed-bed units of Riley Morgan, Kellogg,  and Willputte, based primarily on the
fact that in tine recent past it has achieved a greater degree of commercial
application.  Two gasification plants currently are still operating using
Wellman Galusha gas producers, and the information on operational character-
istics provided from these plants was considered to be potentially useful in
the study.   The other agitator-type fixed-bed units would also be attractive
for consideration and results obtained from analysis with the Wellman Galusha

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                                     30
would be expected to be similar to that for the other gasifiers.  If a suit-
able supply of coal with free-swelling index less that 3 could be obtained,
consideration of two-stage fixed-bed units would provide an interesting
comparison to that of the agitator-fixed bed.

Selection of  Gas  Cleanup Systems

            A wide variety of cleaning systems are available for removing
sulfur compounds from fuel gas.  All currently commercially available system
operate at low temperatures below 120 C (250 F) and would require precleaning
the gas of particulates, tars, and other constituents that may interfere with
the gas desulfurization step along with cooling to the prescribed operating
temperature.
            Most commercially available desulfurization systems use wet scrub-
bing for removing sulfur compounds from the  fuel gas.  These systems can
generically be separated into physical, chemical, and physical-chemical ab-
sorption/desorption types.  A special class of chemical absorption sytems
involves direct oxidation  of H2S to sulfur rather than desorption.
            Physical absorption processes normally operate at higher pressures
and are capable of reducing H2S, COS, and CS2 to extremely low levels.   Ihese
processes can also be made selective for E~S over CCL, producing a concen-
trated H2S steam suitable for sulfur recovery in a Glaus unit.  Physical
sorbent processes, however, have a high solubility of hydrocarbons in the
sorbent and sorbent costs are high.  Examples of physical sorbent processes
are Lurgi Purisol and Eectisol, Allied Chemical Selexol, and Fluor solvent.
            Chemical absorption processes include scrubbing with ammonia or
alkali solutions.  Mono amine systems have high sorbtivities for H2S but are
sensitive to deactivation from reaction with COS.  Di-amines and tertiary-
amines are less sensitive to deactivation but have lower solubilities of H2S
and remove little or no COS or CS2-  Amine systems also remove increasing
amounts of C02 as the sulfur level in  the fuel gas is reduced.   Alkaline salt

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                                      31
sorbents remove both sulfur compounds and CO-.  Examples of chemical sorbent
processes are nonoethanolamine  (MEA), diethanolamine  (DEA), and monoethanol-
diethanolamine  (MDEA).
          Physical-chemical desulfurization processes use a combination of
physical and chemical sorbent.  These processes attempt to take maximum ad-
vantage of the attractive characteristics of both physical and chemical types
of processes while minimizing the unattractive features of each.  Examples of
these processes are Shell Sulfinol and Lurgi Amisol.
          Some types of processes such as chemical sorbent systems also remove
CO- in addition to H-S.  Removal of CCL makes it difficult to obtain a suf-
ficiently high concentration of H2S  (at least 15 percent) in  the gas resulting
from sorbent regeneration to use a Glaus plant for sulfur recovery.  In these
cases, it may be necessary to use a chemical absorption/direct oxidation
process for sulfur recovery.  The direct oxidation processes can also be
used directly on  the fuel gas for removal of sulfur compounds.  These processes
involve absorption of sulfur compounds to elemental sulfur.  Examples of
direct oxidation processes are Stretford and Giammarco-Vetrocoke.
            In addition to wet desulfurization systems various dry removal
systems have been used commercially over the years.  These processes operate
at low temperatures and involve adsorption of sulfur compounds on iron oxide
(supported by various media), activated carbon, or molecular sieves.  Although
some of these processes were used at one time for H2S removal from producer gas and
coke-oven gas, they are not generally considered applicable to low- or inter-
mediate-energy gas today due to requirements for large amounts of sorbent, high
cost of sorbent, or necessity for maintaining prescribed humidity and gas tempera-
ture for proper operation.
            The commercial fuel-gas desulfurization systems exhibit a wide variety
of operating characteristics.  Optimizing the selection of any one of these
processes would necessarily involve many detailed engineering considerations.
For this study, systems were selected that would be likely candidates for an
actual plant design based on gasifier vendor's recommendations.  For the steel
plant model using a Kbppers-Tbtzek gasifier, an MDEA system was chosen and for
the refinery model, using a Wsllman Galusha gasifier, a Stretford system was
chosen.  Both gasifier vendors recommend the use of these respective cleaning
systems as a first consideration in a plant design similar to those evaluated

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                                     32
in this study.  Both vendors, however, may reconrnend different systems if
warranted by a particular application.
            Both the MDEA and Stretford systems involve chemical absorption.
Both these systems can operate satisfactorily at the near ambient pressures
of the Koppers and Wellman Galusha gasifiers.  In the MDEA system, H2S and
up to 75 percent of the COS are absorbed in an amine solution which is sub-
sequently regenerated with steam and pressure reduction yielding an H2S -
rich gas stream.  The H-S-rich gas stream is suitable for feed to a Glaus
unit which converts about 95 percent of the H2S to elemental sulfur.  In the
Stretford process, H2S is absorbed in Stretford solution (a dilute ammonium
vanadate, sodium citrate, and soda ash), and this is oxidized in solution to
elemental sulfur which is then filtered from solution.

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                                     33

               III.   CONVERSION  OF  A  SECONDARY  STEEL
                      PLANT TO  INTERMEDIATE-ENERGY GAS

                     The Secondary Steel  Industry

            The secondary steel industry produces semifinished or finished
products from iron or steel scrap or prereduced iron ore pellets.   Because
the feedstock for a secondary steel plant is in a reduced  or semi-refined
state, blast furnaces and coke ovens (which are used in integrated plants
to reduce iron  ore to iron) are not required.   Ihe electric-arc furnace is
almost exclusively the type of furnace employed in secondary steel mills for
making steel from scrap or prereduced iron ore  although some open-hearth
furnaces remain in service.  Integrated steel plants use primarily the basic
oxygen furnace for steelmaking.
            The electric-arc furnace is a short cylindrical  shaped furnace
having a rather shallow hearth.  Three carbon,  or graphite,  electrodes project
through the roof into the furnace.   Charge materials consist of 100 percent
scrap and the required alloying elements.  Electric energy passing through
the electrodes into the metallic charge creates the heat required to melt
the charge.  When the first scrap charge is almost completely melted a second
and a third scrap charge may be added,  depending on the size of the furnace
and density of the scrap.  The molten steel is  poured into ingot molds, where
the steel solidifies before further processing.
            Solidified ingots are removed from  the molds and placed in soaking
pits where the temperature of the ingot is permitted to equalize,  after which
the temperature of the ingot is raised to the required temperature for rolling.
In an electric-arc furnace steelmaking shop the soaking pits are fired with
natural gas or fuel oil.  The hot ingots are delivered to  a  blooming mill
where they are rolled to slabs, blooms, or billers, depending on the size
of the ingot and the end-products produced at any particular steel plant.
An alternate method for producing these intermediate products is to use a
continuous casting machine which makes  the slabs,  blooms,  or billets, directly
from the molten steel.  In such a secondary steel making plant the soaking pits
and blooming mill are not required thus reducing the overall plant energy require-
ments.

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                                      34
             Slabs, blooms, and billets are permitted to cool to ambient tempera-
 tures,  after which they are inspected, defects removed, and eventually they
 are reheated for additional rolling.   The reheating furnaces are usually fired
 with natural gas or fuel oil.   Some smaller reheating furnaces may be fired with
 propane.   Reheated slabs are rolled into plate, sheet, or strip; reheated blooms
 into heavy structural beams, channels, and railroad rails; and reheated billets
 are rolled into angles, channels,  reinforcing bar,  round bar,  square bar,  rod,
 and other "merchant products".
             Some electric furnace  shops may manufacture finished products,  in
 addition  to the usual semifinished products.   The finished products made may
 include wire fencing, reinforcing  mesh, building joists,  nails,  and miscellaneous
 forged  products, to name a few.

 Industry  Data

             Secondary steel mills  make a significant contribution to the total
 amount  of steel produced in the  United States.   These plants produce plain-
 carbon, alloy,  and stainless steels.   Production statistics for  secondary
 steel mills from 1965 through 1974 are given in Table 10.
          The secondary steel industry consists of  electric-arc  furnace  steel-
making plants which primarily use  steel scrap for the complete melting charge.
One electric-arc furnace steelmaking shop, that is associated with an integrated
steelirvaking plant, routinely uses molten pig iron  for about 50 percent of the
metallic charge.  Qie or two other electric-arc furnace shops, in similar cir-
cumstances, will occasionally use molten pig iron for about 50 percent of the
metallic charge.

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TABLE 10.  SECONDARY STEEL MILL PRODUCTION IN THE UNITED STATES
                                                                (9)

Year
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
Carbon
I06 metric
tons
7.6
8.3
9.1
9.9
12.1
12.9
13.5
14.8
17.3
17.7
Stee 1 ,
I06 tons
(8.4)
(9.1)
(10. 1)
(10.9)
(13.3)
(14.1)
(14.9)
(16.4)
(19.1)
(19.5)
Al loy Steel ,
I06 metric
tons I06 tons
3.5
3.6
3.2
4.0
4.8
4.3
4.3
5.2
6.1
6.2
(3.8)
(4.0)
(3.5)
(4.3)
(5.1)
(4.7)
(4.7)
(5.7)
(6.7)
(6.9)
Stain less,
tO6 metric
tons I0b
1.35 (
1.49 (
1.34 (
1.33 (
1.40. (
1.16 (
1.15 (
1 . 40 (
1.71 (
1.09 (
tons
i.4)
1.6)
1.4)
1.4)
1.5)
1.2)
1.2)
1.5)
1.8)
2.1)
Tota 1 Arc-
Furnace Steel
106 metric
tons 10
12.5
13.4
13.6
16.2
18.1
18.2
18.3
21.5
25.1
26.0
•
6 tons
(13.8)
(14.8)
(15.0)
(16.8)
(20. 1)
(20.1)
(20.9)
(23.7)
(27.7)
(28.6)
Percent
of Total U. S.
Steel Production
10.5
1 1. 1
11.9
12.8
14.3
15.3
17.4
17.8
18.4
19.7
                                                                                             U)
                                                                                             Ul

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                                     36
          There are 126 electric-arc furnace steelmaking plants in  the United
States.  Of these, 14 plants make steel for the manufacture of forgings and
related products.  The remaining 112 plants which are considered representative
secondary steel plants for this study produce steel that is rolled into strip,
sheet, bars, rods, angles, channels, and related products.   Plain carbon steels
are made in 70 plants, with the remaining 42 plants producing primarily alloy
and stainless steels.  A statistical distribution of the annual production
capacities of the 112 arc-furnace steelmaking plants is shown in Figure 3.
          Of the 112 electric-arc furance steelmaking plants that fall into
the category for this study, 53 have continuous casting operations,  leaving
59 plants that still operate with soaking pits and blooming mills.  Figure 4
shows a statistical distribution of electric-arc furnace plants, according to
annual steelmaking capacities, that use continuous casting machines  to convert
the molten steel into slabs, blooms, and billets.  It should be noted that
steelmaking plants with annual capacities of 220,800 metric tons (200,000 net
tons) per year or less have a significant number of continuous casters.
          The locations of the electric-arc furnace steelmaking plants are
shown in Figure 5, superimposed on  a map showing the coal fields of the United
States.

                     Model  Electric-Arc Furnace
                          Steel  Making Plant

          It would be ideal to select a plant that could be characterized as
being "typical" in its representation of the electric-arc furnace steelmaking
plants in the United States.  However, such is not the case,  especially with

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                                37
                       Total Number of Plants in Size Classification
                       Number of Plants Producing Plain Carbon Stee1s
                       Number of Plants Producing Alloy
                        and  Stainless  Steels
                           i   1   S   i
     0 ' 5010015020025030035040045050055060065070075°800850900  100°1500
                       Plant Capacities, 1000 net tons
    Note:  50 denotes melting plants producing from 50,000 to
           99,000 net tons per year; 100 denotes melting plants
           producing from 100,000 to 149,000 net tons per year; etc.
FIGURE 3.  STATISTICAL DISTRIBUTION OF THE CAPACITIES OF ELECTRIC-ARC
           FURNACE MELTING PLANTS IN THE UNITED STATES

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                       33
i n
JLU
<" Q
N y
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w a
8
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o /
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c ra °
c« U
r-l -fl c
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o to ^
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a ?
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-

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:-
-


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r








1 0
Q
S
7






n
  100   200   300   400   500   600   700   800   900   1000
                Plant Capacities,  1000 net tons
FIGURE 4.  STATISTICAL DISTRIBUTION OF ELECTRIC-ARC
           FURNACE MELTING PLANTS IN THE UNITED STATES
           HAVING CONTINUOUS CASTING MACHINES

-------
     " /           /   J
    '   V  V « .      /   /

    •        •••

    *^L   \   ••
    • A-  \   > • • •,
             \   VL   y   i
         e   *   x-ii4<  ,rr^	j
                 /    	-L..J   *\A     '
FIGURE  5.  LOCATION OF ELECTRIC-ARC FURNACE STEELMAKING PLANTS AND THE LOCATION OF BITUMINOUS,

          SUBBITUMINOUS AND LIGNITE COAL FIELDS  IN THE UNITED STATES

-------
                                     40
respect to size as shown in the statistical distribution of annual plant
capacities in Figure 3.  A composite model plant was selected as providing
the required background for the work conducted for this study.  The compo-
site plant consists of melting facilities capable of making 996,600 metric
tons (1,100,000 net tons) of steel per year.  A general flow sheet of the
composite plant is shown in Figure 6.
       Reheat Furnace
           200,000
         I Bar Mill
         Rolled Bar
          170,000
                           Electric-Arc Furnace j
                                Molten Steel
                                 1,110,000
                                   Ingots
                                 1,100,000
                                Soaking Pits
                               Heated  Ingots
                                 1,090,000
                              | Blooming  Mill
  Reheat Furnace
      300.000
    I Rod Mill |
    Reheat Furnace
       400,000
  [Merchant  Mill |
Cut and Coiled Rod
     250,000	
Angles, channels, etc,
	350,000	
                 FIGURE 6.   COMPOSITE ELECTRIC-ARC FURNACE
                            PLANT FLOW SHEET (Capacities in
                            net tons)

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                                      41
          Electric-arc furnace steelmaking plants placed into operation in
recent years almost without exception use continuous casting machines to
produce slabs, blooms or billets from the molten steel.  For such plants the
flow sheet in Figure 6 would not show soaking pits or the blooming mill.
          The products, indicated on the flow sheet as bar, rod, angles and
channels, would be shipped out of the plant as semi-finished products or used
in-plant for the production of special products.  The rolling operations all
require reheat furnaces to heat the steel to the required rolling temperatures.
Fuel requirements for the reheating furnaces are the major consumers of fuel
in electric-arc furnace steelmaking plants.  Additional fuel requirements are
created by reheating furnaces required for forging operations, galvanizing
lines, and heat-treating furnaces.
          The energy demand of this plant ranges from a minimum of 15.8 x 10
               q                                   69
MJ/day (15 x 10  Btu/day) to a maximum of 24.3 x 10  MJ/day (23 x 10  Btu/day)
with an average energy demand of 21.1 x 10  MJ/day (20 x 10  Btu/day).  Minimum
demand usually occurs on weekends and during down time for plant maintenance.
Table 11 summarizes the characteristics of the steel plant model.
                     TABLE 11.  STEEL PLANT STATISTICS

metric ton/year (ton/year)
Molten steel capacity
Rol led bars
Cut and coi led rod
Angles, channels
Energy Demand
Maximum
Average
Mi nimum
996,600
154,000
226,000
317,000
I06 MJ/day
24
21
16
(1,1 10,000)
(170,000)
(250,000)
(350,000)
(109 Btu/day)

(23) (peak production)
(20) (normal production)
(15) (weekends, downtime)

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                                      42
               Model Plant Relationship  to Industry

          The model plant selected for the model is not representative of
any particular electric-arc steelmaking plant in the United States.  Rather,
it is a hypothetical plant which is to be used as a representative of the
industry.  The model plant would be located on a river where water would be
available for the gasification plant and advantage could be taken of river
transportation of coal.  Ihe majority of the electric-arc furnace plants in
the United States are located on rivers or coastal sites where there is a ready
access to water.

                       Gasification  Plant  Design

          A Koppers-lbtzek gasification  system was selected for the steel
plant model.  This plant would consist of four two-headed gasifier units and
would gasify about 1721 metric ton/day (1900 ton/day) of coal producing approxi-
mately 23.5 x 106 MJ/day (22.3 x 109 Btu/day)  of fuel gas with a high heating
value of 11.3 MJ/Mn  (286 Btu/scf).  An MDEA cleanup system was selected for
use in desulfurizing the fuel gas.   This process,  which operates at atmospheric
pressure, is commonly recommended by Koppers in  such applications.  Figure 7
shows an overall flow sheet of the gasifier and gas-cleanup system.
          The Koppers-Tbtzek process is restricted primarily to oxygen-steam
gasification producing intermediate-energy gas of about 11.8 MJ/Mn  (300 Btu/scf).
The intermediate-energy gas was considered desirable for the steel mill appli-
cation after reviewing the combustion requirements of the various furnaces in
the plant.  Conversion of these processes to a gas with a lower heating value
would require extensive conversion and modification and was considered unfeasible.
          The coal selected for the steel mill model was a lignitic coal with
a moisture content of about 27 percent and a sulfur content of 1.7 percent.   A
complete analysis of the coal is given in Table 12.   This coal would be pul-
verized to 70 percent through a 200-mesh screen and dried during the pulveri-
zation step to less than 4 percent surface moisture before feeding to the gasifier.

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                   Oxygen
                                                                                        Air
Saturated
   steam
To
pulverizer
                                           Waste heat
                                           recovery
                                                     water   ni
                                                                               MDEA sulfur
                                                                               removal
                           Raw
                           gas
                          cooler
                      Drying
                      air
CoaK      Coal
storage    pulverizer
                                                                                   Claus
                                                                                   plant
                                                           Cooling
                                                            tower
                                                                                                 »*••
                                                                                                 Clean gas
                                                         Vent
                                                         stream
                                                                                      Sulfur
                                                                                 Make up
                   FIGURE 7.  KOPPERS-TOTZEK/MDEA STEEL MILL GASIFICATION PLANT

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                                   44
            TABLE 12.  COAL ANALYSIS FOR STEEL MILL MODEL
                 Proximate  (as received)

                  Moisture
                  Ash
                  Volatiles
                  Fixed Carbon
                  Heat Value

                Ultimate  (dry)

                  Carbon
                  Hydrogen
                  Nitrogen
                  Chlorides
                  Sulfur
                  Ash
                  Oxygen
   26.5  percent
   10.I  percent
   29.0  percent
   34.4  percent
   8416  Btu/lb
   66.10  percent
    4.46  percent
    0.67  percent
    0.07  percent
    I .70  percent
   13.40  percent
   13.60  percent
                Hardgrove Grindability    52.2

                Ash Fusion Temperature  (initial atmosphere)
                   Initial deformation
                   Soften ing
                   Fluid
I 141  C (2087  F)
1224  C (2236  C)
1289  C (2352  F)
          Gas produced in  the gasification step would be passed through a
waste-heat boiler for steam recovery and then through a two-stage venturi
scrubber for removal of particulates and any tars that may be formed in the
process.  Because the Koppers-Totzek gasifier operates at such a high tempera-
ture  (about 1815 C  [330 F]) only trace amounts of tars, phenols, oils, and
a relatively small amount of ammonia are present in  the fuel gas.  From the
venturi scrubber the gas would be processed through a cooler and then into
the MDEA sulfur-removal system for removal of sulfur compounds.

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                                    45
          The  final  fuel  gas would contain about 300 ppm of sulfur compounds
and the overall efficiency of the  gasification process would be  about 70
percent.  A complete material balance  for the gasification plant is given in
Appendix B.  Pertinent  statistics  on the  gas plant design  are  summarized  in
Table 13.
                TABLE 13.  GASIFICATION PLANT DESIGN
                           FOR STEEL MILL MODEL
Gasifier -  Koppers-Totzek  (four two  headed  unit trains)
Desulfurization - MDEA  (methyl-diethanolamine) with Claus sulfur  recovery
Maximum Gas Production  Rate - 23.5 x  I06 MJ/day (22.3 x  I09 Btu/day)
Minimum Gas Production  Rate -  15.3 x  I06 MJ/day (14.5 x  I09 Btu/day)
                               (with  all four  units operating)
Gas High Heat Value -  10.7 MJ/Nm3 (286 Btu/scf)
Coal Consumption -  1730 metric ton/day (1900  ton/day)
Overall Efficiency - 67.3 percent
          The four-unit gasification plant design was selected to provide
adequate flexibility for steel mill operations.  The design capacity of
         6                  9
23.5 x 10  MJ/day  (22.3 x 10  Btu/day) is slightly less than the maximum
                               6                Q
steel plant demand of 24.3 x 10  MJ/day  (23 x 10  Btu/day).  The Koppers
unit can be operated at up to 10 percent over capacity in situations such
as this where peak demands are intermittent and not for sustained periods
such as in the case of the steel mill.  Therefore the Koppers plant shown
                                   fi                  9
would be capable of up to 25.8 x 10  MJ/day  (24.5 x 10  Btu/day) during
peak periods.
          A complete standby gasifier unit was not felt necessary in this
particular case.  Steel mills have planned annual outages for maintenance
and also low-load periods on weekends and during certain times of the year.
The Koppers gasifier has demonstrated a high availability of up to 95 percent
in foreign installations and presumably most maintenance could be taken care
of during steel mill down times or low-load period.  The four-unit design

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                                   46
would allow one complete train to be out for service while the plant would
still be able to maintain the minimum mill energy demand of 15.8 x 10  MJ/day
(15 x 109 Btu/day).  This would allow for gasifier maintenance and repair on
weekends and other low-load periods without disrupting service.
          Table 14 gives energy flows in  the steel mill gasification plant.

       TABLE 14.  ENERGY BALANCE ON STEEL MILL GASIFICATION PLANT
                          (Mstric and English)

                          Energy Produced
Product Gas -
Metric
23.5 x !06 MJ/day
(980 x I03 MJ/hr)
       EngIish
22.3 x I09 Btu/day
(928 x I06 Btu/hr)
Saturated Steam
  Waste Heat Boiler - 75,963 Kg/hr
                      (262 C and 4.72 x 10  Pa)
  Jacket Steam -  14,179 Kg/hr        _
                  (135 C and 2.07 x 10  Pa)
167,688 Ib/hr (503 F and  685  psig
37 x I06 Btu/hr for turbine ex-
pansion
31,300 Ib/hr
(275 F and 30 psig)
                          Energy Consumed
Gasifier Steam -  11,808 Kg/hr
Oxygen Plant - 52.7 x  I03 MJ/hr
Sulfur Removal and Recovery^'°
   Low Pressure Steam  -  861 Kg/hr
Miscellaneous (pumps, etc.)''"' -
                         17.6 x  I03 MJ/hr
26,032 Ib/hr
50 x I06 Btu/hr
1900 Ib/hr
16.7 x 10  Btu/hr
                      Net Energy Requirements
Oxygen Plant -  14.77 x 10  MJ/hr
Miscellaneous -  17.6 x 10  Mj/hr
Total - 32.37 x  I03 MJ/hr
14 x 10  Btu/hr
16.7 x I06 Btu/hr
30.7 x I06 Btu/hr
                       Overall  Efficiency
Product Gas Produced - 979 x I03 MJ/hr
Energy Required - 32.27 x 10  MJ/hr
Net Energy Production - 946.6 x 10  MJ/hr
Coal Consumed - 71,777 Kg/hr (19.6 MJ/Kg)
928 x 10  Btu/hr
30.7 x I06 Btu/hr
897.3 x !06 Btu/hr
158,448 Ib/hr (8416 Btu/lb)
= 1333 x I06 Btu/hr
Overall Efficiency - 946.6/1407 = 0.673
897.3/1333 = 0.673

-------
                                    47

 As mentioned,  the plant produces 23.5 x 106 MJ/day (22.3 x 109 Btu/day)  of
 product gas or 979 x 103 MJ/hr (928 x 106 Btu/hr)  at design capacity after
 requirements for coal drying are satisfied.  In this design saturated steam
 at 503 F and 685 psig (167,000 Ib/hr)  is generated in the waste heat boiler*
 and  an additional 14,179 Kg/hr (31,300 Ib/hr)  of low-pressure steam is gen-
 erated in the cooling water jacket*.
           Ihe oxygen plant is the biggest single energy consumer in the plant
 and  is estimated to require 52.8 x 103 MJ/hr (50 x 106 Btu/hr) which is based
 on an oxygen plant energy-consumption rate of 299 kwhr/metric ton (330 kwhr/
      14, 15).  This energy consumption is  for compressing air to about 690 kN/nr
  (100 psig) prior to separation into oxygen and nitrogen.  Ihe saturated steam
 from the waste-heat boiler can be used to supply about 39.0 x 10  MJ/hr
  (37 x 10  Btu/hr) in a turbine condenser unit leaving 2.4 x 10  MJ/hr  (9 x
 10  Btu/hr) still required.
           Ihe MDEA sulfur removal process requires steam for regenerating the
 amine absorbent.  Some steam, however, is generated in the Glaus sulfur re-
 covery unit partially offsetting the regeneration requirement.  The net steam
 requirement is estimated to be about 861 Kg/hr (1900 Ib/hr) of low pressure
 steam.**  This requirement could be satisfied by the 2386 Kg/hr (5268 Ib/hr)
 of jacket steam that remains after the gasifier steam demand of 11,792 Kg/hr
  (26,032 Ib/hr) is satisfied.
           Miscellaneous energy requirements for the plant  (pumps, fans, etc.)
 are estimated at about 1.8 percent of the product gas energy production.**
 This requirement of 27.1 x 10  MJ/hr (25.7 x 10  Btu/hr) as well as the addi-
 tional 9.5 x 10  MJ/hr (9 x 10  Btu/hr)  required by the oxygen plant would
 be satisfied by purchased electricity.  Electric arc secondary steel plants
 are major consumers of electricity and as such would have adequate supply and
 low rates making this attractive.  This would have to be evaluated in detail
 however before a final decision could be made.
 *In some designs high pressure steam is generated in the waste-heat boiler.
  However, this leads to higher tube temperatures and hence higher corrosion
  rates due to acid gas (H2S, etc.)  attack.  In  this design maximum tube life
  was desired and, therefore, steam temperatures were limited to saturation.
**Based on data in Reference (10)  for nearly identical plant.  Values were
  adjusted based on plant energy production rate (clean gas).

-------
                                     48
            Figure 8 shows a representative plot plan of the steel mill with
  the gasifier and coal-storage piles included.  The steel mill proper covers
  about 930,000 m2 (230 acres) of land with approximately 280,000 cm2 (70 acres)
  of land in building area.  Though the buildings in Figure 8 are shown linked
  together, in reality they would be interspersed throughout the available area
  and relatively little free land would be available in the steel mill proper.
  Ihe gasification and gas-cleaning plant is estimated to require about 630,000
  m  (15 acres)  of land and coal storage for a 1-month suoply of coal would
                                2
  require an additional 10,000 m  (2-1/2 acres).

                     Burners and  Furnaces  in a
                       Secondary  Steel Plant

            Ihis section describes the types of burners used to fire various
 processes in the model steel plant and the possibilities for firing these
 burners with an intermediate-energy fuel gas produced by coal gasification.

Burner  Types

            A  great portion of the burners, especially those of larger capacity,
in  the secondary steel industry are designed with provision to burn either
coke-oven gas or natural gas.  As indicated elsewhere (Appendix A)  some of
the potential compositions produced by coal gasification systems are within
the range of coke-oven gas composition, and several have burning parameters
within the coke-oven gas range.  Thus, those burners which can be converted
with little difficulty from natural gas to coke-oven gas also have a potential
for conversion to some intermediate heating value gases.  The following
figures illustrate several of the burner types used in the secondary steel
industry.
            Figures 9 and 10 show two designs of flat-flame burners.   Swirl
is imparted to the air in these burners, so that the flame spreads out along
the surface and heats it to a point where there is a significant radiant
heat output.  Several manufacturers make this type of burner.   Such burners
might be found in the furnaces in the forged products and wire making department.

-------
Gasification
8 Cleaning .
 15 acres
                     Coal
                    storage
2.5 acres

1
Steel Mill Proper: j Bar joist
•
Land area 230 acres warehouse j 	
Building area 70 acres i Mill building
i— . . t
i 	
'Motor
1 	 i i T- | ~
1 Scrap yard 'Electric 1 Soaking (Blooming i
1 ^furnace j pits 'mill |


I Rails
JT
	 } Long
t Shipp
i-
	 1
room 1
_ _ i
(Billet
[jinil,


1

span 1
ing j
1 	 1
1
!!
1 if -
i « ~




r~ ~i
1 J
	 1 	 '
I
Nails, i
wire, 1 w
mesh "S "
i ! O< -o

                       FIGURE 8.   STEEL MILL PLOT PLAN

-------
                       50
    Fuel
FIGURE 9.  BLOCM HTR FLAT-FLAME NOZZLE-MIX BURNER

     The burner is designed to use natural
     gas or coke-oven gas in a sealed-in
     tile.

-------
                         51
FIGURE 10.  NORTH AMERICAN 4832 FIAT-FLAME (OR RADIATION
            TYPE) NOZZLE-MIX BURNER
     The burner is designed to use natural gas or
     coke-oven gas in a sealed-in tile.

-------
                                    ' 52

          These burners are designed so that they can successfully  fire coke-
oven gas.  However, the maximum spud size may not be sufficient to  obtain an
acceptable fuel velocity of an  intermediate heating value gas  (changing from
17.7 MJ/Mn3  [450 Btu/ft3] to  11.8 MJ/Nm3  [300 Btu/ft3]  fuel gas requires a
50 percent increase in volume flow rate).  Furthermore, the intensity of swirl
imparted to the fuel by the combustion air might be insufficient to obtain
satisfactory combustion.  Thus, even though the stability parameters might
match those of coke-oven gas, the burner may not perform satisfactorily and
could need replacing.  A short  series of experiments on a few of these burners
would be the optimum way of answering the interchangeability question.
          Figure 11 shows one version of a forced-air radiant-tube  burner.
Flame holder details vary with  manufacturer.  Other designs of burner, in-
cluding  inspirators  (in which  the  fuel aspirates the air) and exhaust suction
type are available.  These burners were used in  the forged products depart-
ment, and for annealing.  For burners such as in Figure 11, there appears to
be no reason that intermediate  fuels could not also be  used.  Possibly, a
change in spreader might be needed,  and, definitely, a  somewhat increased back
pressure on the fuel would be required.  For systems using inspirators, the
chances are that the inspirator portion would have  to be changed.
          Figure 12 shows a general  heating burner  that can use a variety of
fuels, and can be fired with  considerable excess fuel.  It is used  in various
operations such as primarily  in the  forged-products area.  This burner should
operate satisfactorily on intermediate-heating value gas, but the back pressure
would have to be increased to 16 percent to 24 percent of the air pressure.
          Figure 13 shows a dual-fuel ultrastable burner only used  in limited
numbers in forging operations.  From the pressure requirements on   this
burner for coke-oven gas (see Figure 13), it appears quite questionable that
it could be used for intermediate-heating value fuels.  A change in burner design
or burner type would probably have to be made.
          Figure 14 shows a burner that can produce a long flame or operate
with high excess air.  It is used in forging operation and wire making.
From the low pressure drop with coke-oven gas in this burner and the great
flexibility of operation, there should be no difficulty in utilizing the
intermediate-heating value fuel from the gasifier in the burner.

-------
                              53
   PREMIX VALVE
    Gas
                f
               Air
           '//////-
.*<•///.''//,''//'/.'///',
M^^lL
FIGURE 11.  BLOOM FORCED-AIR RADIANT TUBE BURNER
               Develops a Long Flame With  Uniform
               Heat  Release Along the Length of a
               Radiant Tube.  Natural Gas  or Coke
               Oven  Gas May Be Used.

-------





Y^td


'KM

\
*— -.
i_^.
3
                                               Oil
FIGUPE 12.  NORTH AMERICAN 220 AND NORTH AMERICAN 221
            DUAL-FUEL NOZZLE-MIX BURNERS


      General heating burner uses liquified petro-
      leum gas (1 percent of air pressure), natural
      gas (2 percent of air pressure), coke-oven gas
      (8 percent of air pressure),  and light oil in
      sealed tile.  Burner will operate at "double-
      rich" condition.

-------
                              55
  Oil
           ATOMIZING
             AIR
GAS
                             MAIN AIR
FIGURE 13.  NOR1H AMERICA!^  214 DUAIr-FUEL NOZZLE MIX BURNER
       Ultrastable burner uses natural  gas,  coke-oven
       gas, light oil, or heavy  oil  in  sealed-in tile.
       For coke-oven gas (19.7 MJ/Nm3)  (500  Btu/scf,  0.4
       sp.gr), gas pressure  equals 1/5  air pressure at
       stoichiometric; for "double-rich"  firing, coke-
       oven gas pressure must equal  air pressure.

-------
                              56
FIGURE 14.  NORTH AMERICAN 223 DUAL-FUEL NOZZLE-MIX BURNER
           Excess air burner uses natural gas,  coke-
           oven gas (413 Pa gage) (0.06 psia)  or dis-
           tillate oil in a sealed-in tile.   Mixture
           rate varies from 50 percent excess air,  the
           amount depending on burner size and  firing
           rate.

-------
                                     57
            Figure 15 shows a snail long-flame burner used on the rolling mills
  in conjunction with larger long-flame burners such as shown in Figure 16.
  Burners similar to that shown in Figure 15 are also used in the soaking pits
  and rod mills, it appears probable that both burners could be used with
  intermediate heat-up value fuel with little difficulty.
            Figure 17 shows a premix radiant cup burner of relative small
  capacity, often used in large numbers for annealing and similar operations.
  Ihe burner should be quite adaptable to intermediate-heating value fuels.
  While tips are not listed as available for 11.8 MJ/Mn  (300 Btu/scf) fuels.
  demand for such should lead to their production.  However, the mixing and
  monitoring system would probably also require some revision.
            Figure 18 is a typical ring-type gas and oil burner for boilers.
  This particular burner can be stretched to handle gases down to 15.7 MJ/Mn
   (400 Btu/scf).  However, below this value, down to 9.8 lyU/Mn  (150 Btu/scf),
  a different burner design would be recommended.  Below 9.8 MJ/Mn  (250 Btu/
  scf ) , a third burner design would be used.

  Summary of  Burner Changes

            The analysis of the study of the secondary steel plant is based
 on  the assumption that a Koppers-Tbtzek gas is used as a replacement for
 natural gas.  On this basis, it is found that most of the burners used are
 in  the questionable area as to satisfactory performance.  Most of the burners
 are built to handle natural gas and coke-oven gas.  Ihe stability values for
 Kbppers-lbtzek gas are better than natural gas (except for premixed burners
 where flashback may occur) , and about equal to coke-oven gas.  However, the
 lower heating value  (order of 11.8 MJ/Nm   [300 Btu/scf])  compared with coke-
oven gas  (order of 19.7 MJ/Nm3 [500 Btu/scf] can lead to flow distortions in
nozzle mix burners (because of the higher volume fuel flow rate) .   This could
result in unsatisfactory performance.   Experimental data are required on some
typical industrial burners using Koppers-Totzek fuel to answer this question
in a definitive manner.   The small numbers of premix burners must be considered
carefully, first as to changes needed to prevent flashback, and, second, as
to changes needed in the mixing system;  new burners, or a completely different

-------
                  58
  AIR
       GAS
FIGURE 15.  BLOOM 401-L LONG-FLAME BURNER

           Natural gas,  propane,  butane,  or
           coke-oven gas.   Turndown ratio is
           20:1.   At rated capacity 0.2 psi
           required for  both gas  and air.

-------
                             59
 -OH.
STEAM
    FIGURE 16.  BLOOM LasTG-FLMIE BURMER, COLD AIR
               Radial fins  result in uniform
               air flow.    When the adjustible
               flange in  in the back position,
               the flame  in luminous.  With the
               flange in  the forward position, the
               flame  has  little luminosity.

-------
                  60
^tr^^
                            Premixed
                            Fuel acid Air
FIGURE 17.  SELAS DURADIANT PREMIX BURNER
         Cup-shaped ceramic "washed" by
         hot combustion products, radiates
         heat to work.  Tips are available
         for gases with 15.8 to 126.1 MJ/Nm3
         (400 to 3200 Btu/scf).

-------
                   61
            Windbox X


Register
Louvers
\

(
Air


                                     Steam-oil
                                     outlet holes
               Gas  f
FIGURE 18.  ERIE CITY RING-TYPE GftS AND OIL
            BURNER FOR BOILER USE
            This  burner will  handle  gases
            with  heating  valued  down to
            15.8  MJ/Nm3  (400  Btu/scf) with
            some  adjustments.

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                                    62
design might well be needed.  This is especially true in the case of space
heaters.  In seme instances, boiler burners may be easily adaptable to Koppers-
Tbtzek gas, but in others, it is expected that new burners will be required.
           Using Koppers-Tbtzek gas, no difficulty is foreseen relative to
radiation output changes or furnace pressure drops.  Fuel line pressure drops,
on the other hand, require careful consideration.
           If the heating value of an intermediate-energy gas could be in-
creased to a value similar to that for coke-oven gas (either by removal of
inerts or addition of a higher grade fuel such as methane) conversion of
burners in a secondary steel plant could be greatly simplified.

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                                     63
         IV.   CONVERSION  OF A REFINERY  TO LOW-ENERGY GAS

                        The  Refinery Industry

            In order to generalize the conclusions for the hypothetical refinery
 (to be described later), it is necessary to examine how this refinery compares
with other refineries in the United States.  The following discussion presents
data on U.S. refineries so that  the model refinery can be compared to other
refineries.  Among items discussed are
            •    Energy consumption
            •    Types  of  fuels used
            •    Amenability to conversion to  low-  or
                 intermediate-energy gas.

Energy  Consumption

           • Size.    The most important variable affecting the  total energy
consumption of a refinery is the size of the refinery, expressed in terms
of crude oil throughput.  The distribution of sizes of the refineries in the
United States is shown in Table  15.  The median capacity is 4.53 x 10  liter/day
(28,500 barrel/day).   That is, half the refineries in  the United  States are
smaller than this and half are larger.  The average capacity is 9.11 x 10
liter/day (57,318 barrel/day), this being higher than the median because of
a relatively few numbers of very large refineries.

            Complexity.  Another secondary variable affecting the energy
consumption of a refinery is the complexity of the processing operations
                   (18)
used.  W. L. Nelson   has quantified the complexity of refineries by defining
a parameter known as  the Nelson  complexity factor.   This factor is obtained
by multiplying the capacity of each type of processing (distillation, catalytic
cracking, etc.)  by a  factor,  then summing the products,  and then dividing the
total by the crude oil capacity.  The complexity factors for the various refin-
ing processes are shown  in Table 16.  Also shown in this table  are some approxi-
mate energy requirements for the processes.  Although the complexity factors
were originally based on costs,  they have been found to be reasonably good

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                                      64

    TABLE 15.   U.S.  REFINERY SIZE DISTRIBUTION AS OF JANUARY 1,  1975('7'

Capacity Range,
103 B/CD(a)
<5
5-10
10-15
15-25
25-50
50-75
75-100
100-200
>200
TOTAL
Median Capacity
Number of
Ref i neries
49 -j
31 V
) 124
19 /
25 )
50
21
21
28
15
259
( 128 refiner!
Total Capacity,
B/CD
146,592
230,688
234,780
517,520
1,910,592
1,309,385
1,878,950
4,002,900
4,614,000
14,845,407
es smal ler, 128 ref
Percent
Capaci
0.99
1.55
1.58
3.49
12.87
8.82
12.66
26.96
31.08
100.00
i neries
of Average Capacity,
ty B/CD
2,992
7,442
12,357
20,701
38,712
62,352
89,474
142,961
307,600
57,318
larger) = 28,500 B/CD

 (a)  B/CD = barrels per calendar day..  I barrel  =  42  gallons =  158.97  liters.
measures of the unit energy consumption  (energy consumption per unit of
throughput) of the various processes.  The Nelson coitplexity factor for the
U.S. refinery industry as a whole is 8.88.  This value is based on the total
capacities of the various processes in the U.S., and as such it represents an
"average" U.S. refinery  (not a median size refiner).
          Nelson has developed correlations of the energy consumptions of
refineries in terms of the refinery complexity and the fuel cost.  The latter
is important because, as fuel costs have risen, more extensive conservation
measures have been adopted with the result that energy consumption has de-
creased.  This is shown in Figure 19, which is a plot of energy consumption
versus fuel cost with complexity as a parameter.  This plot covers the time
period from 1950 through 1975.  The years corresponding to the various points.
(fuel costs) are shown for the center curve.  Figure 20 shows the energy con-
sumption as a function of complexity with fuel cost (time) as a parameter.  The
unit energy consumption varies linearly with complexity.

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                                       65
                  TABLE 16.  COMPLEXITY FACTORS AND ENERGY
                             REQUIREMENTS FOR REFINING
                             PROCESSES('8 ^

Refining Operation
Topping, low gravity crude, light duty
Topping, high gravity crude, heavy dury
Vacuum flash
Vacuum disti 1 lation
Thermal Cracking
Two coi 1
Visbreaking
Catalytic crude oi 1
Catalytic Cracking
65 percent conversion (zero recycle)

Airl ift type
Fluid bed
75 percent conversion (0.75 recycle)
Airl ift type
Fluid bed
Thermal reforming
Catalytic reforming
(a)
A Iky lation
Polymerization'3^
Isomerization
Hydrogen treating, 100 ft3/bbl
Hydrogen treating, 300 f t3/bb 1
Hydrocracking
Lube manufacture
Solvent extraction
- Solvent dewaxing
Lube finishing
Wax finishing
Typical complete lube plant
Coki ng
Asphalt manufacture
Ne 1 son
Comp 1 ex i ty
Factor
1
1
1
2

3
2


5



6


3
4

10
9
3
2
4
6

4.5
9
50
100
62
5
2
Approx. Requirements Per '
Barrel of Feed
Fuel, MJ
55
74



506
200
422



501
480

601
591
174
338

12.7
200





150
—
166
1 1 1



(IOJ Btu)
(52)
(70)



(480)
(190)
(400)



(475)
(455)

(570)
(560)
(165)
(320)

(12)
(190)





(142)
—
(157)
(105)



Steam, Ib
40
55



45
30
40


I
40
50

75
90
20
75

680
75





130
300
100
300



(a)  Fuel  and  steam requirements  per  barrel  of  product  (rather than  feed)

-------
    20 r-

-------
0)
tJ
3
M
O

M

-------
                                   68
            Refinery Energy Consumption  Data.  Knowing that the size
 variable can be accounted for by using unit energy consumptions (energy consumption.3
 per unit of throughput) and having Nelson's correlations for the complexity
 variable, typical refinery energy consumption data are needed to compare the
 energy consumption of the model refinery with that of the U.S. refining in-
 dustry as a whole.  The Bureau of Mines publishes data on the energy consumed
 at refineries in the U.S., breaking this down by states (or state groups)
 and sources of energy(20)^  Table 17 summarizes the national totals, in-
 cluding the breakdown by sources, for the last 3 years for which the data
 are available.  Table 18 presents the state-by-state breakdown of the energy
 consumptions for the most recent year available (1973).  This table also
 includes the 1973 and 1975 crude oil capacities for all the states and the
 unit energy consumptions and average refinery complexities for the states
 with the larger refinery capacities.  As backup information, Table 19 contains
 the fuel energy contents used by the Bureau of Mines(22) 3^ developing their
 tabulations.

Types of Fuels Used

            Because refinery gas is a major source of energy in most refineries,
it will be instructive to consider the quantities of refinery gas available  for
fuel users in various refineries.  Two aspects in which they have available  for
fuel use are concerned with the two processes which generate the greatest share
of the refinery gas at the model refinery—catalytic reforming and catalytic
cracking.

            Hydrogen From Catalytic  Reforming.   As mentioned previously,
the catalytic reforming process generates as a byproduct considerable quantities
of hydrogen.  This hydrogen can be used in hydro-treating processes to remove
sulfur from liquid fuels.  The feed to the catalytic reformer itself requires
a mild hydro-treating to remove traces of sulfur which would otherwise poison
the catalyst.  The quantity of hydrogen needed for other hydro-treating operations
depends primarily upon the sulfur content of the crude oil being processed.
Also, some refineries use hydrocracking as a conversion process,  either instead
of, or in addition to, catalytic cracking, and hydrocracking requires rela-
tively large quantitites of hydrogen.  There are some refineries at which the

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                                       69
                   TABLE 17.   CRUDE RUNS AND ENERGY CCNSUMPTION
                              DATA FOR U. S. REFINERIES(2'>

Crude Oil Capacity, 103 B/CD(a)
Crude Run, 10 3 B/CD
Capacity Utilization, percent
Consumption of Energy Sources
Oil, 103 B 3
Liquefied petroleum gas, 10 B
Natural gas, 10 ,scf
Refinery gas , 10 scf
Petroleum coke, 10 tons
Coal, 10 tons
Electricity, 106 kwhr
Steam, 10b Ib
9
Energy Consumption, 10 Btu
Oil
Liquefied petroleum gas
Natural gas
Refinery gas
Petroleum coke
Coal
Electricity
Steam
TOTAL
3
Energy Consumption, 10 Btu/B crude
Total
Ex. refinery gas and coke
Natural gas and LPG only
1971
12,884.31
11,199.48
86.92

38,072
6,850
1,062,938
981,557
10,444
405
20,720
36,762

239,359
27,475
1,095,889
971,742
314,573
9,728
70,697
44,114
2,773,577

678.5
363.8
274.8
1972
13,235.09
11,728.39
88.62

44,324
13,418
1,040,746
1,053,492
11,230
339
22,612
38,870

276,318
53,820
1,073,009
1,042,957
338,247
8,143
77,152
40,644
2,910,290

679.8
357.2
263.2
1973
13,799.62
12,430.83
90.08

49,574
10,136
1,073,742
1,083,363
13,282
329
23,382
33,945

309,095
40,655
1,107,028
1,072,529
400,054
7,902
79,779
40,734
3,057,776

673.9
349.4
252.9
1974
14,530.85
12,689.32
87.33























(a)   Average  of  values  at beginning and end of year.  Oil and Gas Journal.

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TABLE 18.  STATE-BY-STATE BREAKDOWN OF 1973 CRUDE RUNS AND ENERGY CONSUMPTION FOR U.S.  REFINERIES
                                                                                                 (20)


1973 Crude RunCe;
States (103 B/CD) Oil
Arkansas
Calif., Wash., Ore.,
Alasks, Hawaii
Colorado
Delaware, Mass.,
R.I., Virginia
Georgia, N. Car.,
S. Car., Florida
Illinois 1
Indiana
Kansas
Kentucky, Tennessee
Louisiana 1
Maryland
Michigan
Minnesota, Wise.,
N. Dak., S. Dak.
Mississippi, Alabama
Missouri, Nebraska
Montana
New Jersey
New Mexico
Jiew York
Ohio
Oklahoma
Pennsylvania
Texas 3
Utash
West Virginia
Wyoming
Arizona
TOTAL 12
Percent of Energy
Consumption
48
,971
38
113

57
.79
.42
.84
.40

.76
,031.12
491
373
175
,462
18
122
242

287
101
119
593
46
100
500
447
604
,209
115
13
141
3
,430


.61
.27
.15
.09
.58
.88
.35

.59
.07
.08
.21
.39
.49
.32
.16
.28
.11
.97
.72
.23
.95
.83


1,978
37,942.
1,041
4,267

1,362
54,274
36,944
4,602
9,537
15,443
2,223
3,628
10,575

1,776
346
5,042
38,493
163
3,911
10,104
1,374
45,763
8,681
3,805
2,534
3,288

309,095
10.1

1973 Energy Consumption (109 Btu) ^
LPG
205
13,649
421
40

373
2,403
325
999
1,656
6,811
—
650
148

365
2,254
453
192
610
2,238
734
433
16
4,966
586
—
128

40,655
1.3

Nat. Gas
5,236
146,111
2,169
1,041

801
11,182
4,542
34,889
5,791
116,835
—
3,244
1,524

25,411
4,446
5,653
9,826
3,600
--
20,677
49,739
20,390
612,382
5,625
1,235
15,012

1,107,028
36.3

Ref. Gas
2,914
184,618
3,086
24,744

—
88,626
42,301
30,425
12,072
116,917
11
7,172
15,997

20,099
8,606
11,370
37,280
3,126
8,460
47,974
42,867
64,549
280,330
8,864
967
10,154

1,072,529
35.1

Coke &
Coal
— _
58,284
994
13,614

—
42 , 108
15,753
14,126
4,790
32,951
—
2,319
9,940

4,458
4,217
5,693
19,879
1,175
2,530
14,456
13,012
21,688
113,523
4,789
552
6,385

407,956
13.3

1973 Energy Consumption
(103 Btu/B Crude Run) Nelson
Ex.
Elec. & Ref. Gas
Steam Total Total and Coke
239
25,604
300
8,876

20
7,363
983
2,289
1,242
28,060
31
778
1,501

2,975
157
972
10,092
188
652
3,975
2,351
4,481
16,033
624
263
464

120,513
3.9

10
466
• 8
52

2
205
100
87
35
316
2
17
39

55
20
29
115
8
17
97
109
156
1,035
23
5
35

3,057
,572
,748 648.7 310.3
,038
,582

,555
,955 547.2 199.9
,848 562.0 238.5
,330
,268
,017 592.2 313.2
,265
,971
,685

,084
,026
,183
,763 534.6 270.7
,862
,791
,920 536.2 196.3
,776 672.6 330.2
,887 711.3 352.0
,915 884.4 548.2
,933
,551
,431

,776 673.9 349.4
N.G., Complexity
LPG Factor
and Oil 1973

274.8 9.26




180.3 8.89
"233.0 8.11


260.6 9.05







224.0 9.02


172.6 8.52
315.8 9.51
300.0 10.07
534.5 9.36




321.1 9.24
100.0



                                                                                                            o

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                                  71
       TABLE 19.   FUEL ENERGY CONTENTS USED BY BUREAU OF MINES(22)
                                        Enerev Content
         Fuel
   Metric Units
   English Units
Crude oil




Distillate fuel oil




Residual fuel oil




Liquefied petroleum gas




Natural gas




Refinery gas




Petroleum coke




Coal




Electricity




Steam
9,032 kcal/liter




9,270 kcal/liter




10,006 kcal/liter




6,383 kcal/liter




9,211 kcal/std m3




8,845 kcal/std m3




8,400 kcal/kg




6,699 kcal/kg




863 kcal/kwhr




669 kcal/kg
5.675 x 10  Btu/bfal




5.825 x 106 Btu/bfal




6.287 x 106 Btu/bbl




4.011 x 106 Btu/bbl




1,031 Btu/scf




990-Btu/scf




30.12 x 106 Btu/ton




24.02 x 106 Btu/ton




3,412 Btu/kwhr




1,200 Btu/lfa

-------
                                    72
demand for hydrogen is too great to be satisfied by the reformer byproduct
and a separate hydrogen generation plant is used.
           The number of refineries in the U.S. using various hydrotreating
processes is shown in Table 20.  In this table, "hydrotreating" refers to
the mildest type of process (such, as that used for the reformer feed), "hydro-
refining"  to more severe processes, and "hydrocracking" to the conversion
process mentioned above.  The use of hydrotreating processes in this country
is expected to increase as more crude oil having higher sulfur content is
processed and as the restrictions on the sulfur contents of fuels are tightened.,
               TABLE 20.  NUMBER OF REFINERIES USING
                          HYDROTREATING PROCESSES< I 7)
    Crude Oil Capacity Range,  I03 B/CD    25    25-100   100   All Sizes
    Number of Refineries Using
Hydrocracking
Hydroref i n i ng •
Hydrotreat i ng
Al 1 Refineries in U.S.
5
2
41
124
13
24
82(a)
92
26
18
43
43
44
44
166
259

    (a)  Model refinery  included here.
           Off Gas  From Catalytic  Cracking.   The catalytic cracking
process produces considerable quantities of light hydrocarbons (C-^-C.)  which
are collected as a gaseous stream.  Much of this stream is made up of un-
saturated  (olefinic)  hydrocarbons such as ethylene, propylene, and butylene.
Since these olefins are not as desirable in fuel products as are other types
of hydrocarbons, it is common practice to include with a catalytic cracker
another process to utilize the olefins produced by the catalytic cracker.
The two processes which can be used for this purpose are alkylation and poly-
merization.  Both processes yield a high octane product containing mostly

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                                    73
 branched-chain paraffin compounds, a product which is blended into gasoline.
 In alkylation, isobutane is added to the olefins to form branched-chain com-
 pounds in the gasoline boiling range.  In polymerization, the light olefins
 combine with each other to form a similar product.   A refinery which has
 either of these olefin utilization processes will not have large quantities
 of light olefins available for fuel use.

Adaptability to Firing
Low-Energy Gas

            Land Area.  The amount of land area occupied by the processing
equipment is important in analyzing the possibility of retrofitting refineries
to low-energy gas because it determines the distances over which the gas must
be piped.  The processing equipment usually occupies only a small part of the
total refinery area.   Storage tanks usually occupy the largest part of the
area.  With the increasing emphasis on pollution abatement, water treatment
facilities can use a considerable fraction of the refinery area.  As examples
of typical refinery layout,  the plot plans of two refineries recently built
in the United States are shown in Figures 21 and 22.
            The land area required by a refinery depends on the size and com-
plexity of the refinery.  W. L. Nelson(25) has determined some average land
usages per unit of refinery throughput and has expressed them in terms of the
refinery complexity factor.   These data are plotted in Figure 23.   They include
the land in use for process equipment and storage but not for administration
buildings and buffer zones around the plant.  Based on some available refinery
plot plans, such as those shown in Figures 21 and 22,  it appears that the
process equipment typically occupies 1/3 to 1/5 of the area included in the
correlation of Figure 23.

            Access  to Waterways.  Although not absolutely essential,  access
to a waterway is an attractive feature of a site for a coal gasification facility.
Considerable quantities of cooling water are required for such a facility,  even
when a recirculating system is used.  If the waterway is navigable,  it may be
desirable to transport at least part of the coal to the facility by barge.

-------
                           74

Clai



Holding & 	
Lf ication /
P°nd~"o\/^
Decanting >N
Basin *(j/
Flares &
Slowdown


i •

R
o
1
Stora
^
\S O Sul
Reco1
ik
Amine_>
Sulfur
Unit

.— — i ^e^
1 	 ' Co
0 O
O 0
o o
o o
•Jaste W<
fur
/ery
U £1



ater Treatment
C^A — Administration 1
, m
Main Processing Area [
i/
jU
r~u

1
t t
.ayed tt
ker i
0 0
0 0
0 0
0 0

o ::
o
«-flv<
Hydre
— Lij
1 'FT
J U
faphtha
leformer
0 0
0
0 0
o

o
, .
O T^O
ge Area
O

LO)
o
0
o


irogen Unit
^cracker
?ht Ends
Crude &
'Vacuum
Unit

0 O
O O 0 '
O
O


l
V

1

FIGURE 21.  PLOT PLAN OF AROO'S CHERRY POINT REFINERY

            Capacity:  1,000,000 B/SD
            Total Area:  450 Acres
                                                      (23)

-------
                             75
                                  Waste Water Treatment
           FCC	
           Feed}.
j oo
OOOO
OOO

OQO
000
                                   •Product  Storage
                                               *-LP Gas Spheres
 Coker
o
o
o
                                     „
                        TO  OP
                                     j-Amine  Sulfur Un i t
           P~j     Main/  Reformer /
            I    I Processing  ..'  Alkylatio*
           f       Area

     Administration
o
o
o

  f
Crude
Storage
FIGUEE 22.  PLOT PLAN OF MDBIL OIL'S JOLIET, ILLINOIS, REFINERS
           Capacity:  164,000 B/SD
                                                             (24).

-------
50
40
30
20
10
            Land in Use for Process  Equipment and Storage
              (acres per 10,000 B/D  crude capacity)
                                           I
Complexity of
U.S. Industry

       I
                                           8          10

                                    Nelson Refinery Complexity
                  12
14
16
          FIGURE 23.  LAND IN USE FOR PROCESS EQUIPMENT AND STORAGE AT REFINERIES(25)

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                                 77


                 •  Description of Model Refinery

Size and Products

            The model petroleum refinery used in this study has a crude oil
capacity of about 3.97 x 106 liter/day (25,000 barrel/day).   The products
of the refinery are propane, butane,  gasoline, kerosene,  distillate,  residual
(No. 6)  fuel oil, and asphalt.  There are seasonal variations in the  quanti-
ties of these products produced. More gasoline is produced in the sunnier,
and more residual fuel oil is produced in the winter.  Asphalt is produced
only in the suttmer.  Such seasonal  variations are normal  for petroleum refineries.

Processes

            The following refining  processes are used in  the model refinery:
              •  Fractionation of crude oil and petroleum fractions
              •  Catalytic cracking
              •  Catalytic reforming (including feed hydro-treating)
              •  Polymerization.

            Catalytic cracking is a process for reducing  the molecular weight
of hydrocarbons and is used to produce hydrocarbons boiling in the gasoline
range from higher boiling hydrocarbons.  Catalytic reforming  and polymeri-
zation are processes for producing  high octane streams for blending into gasoline.
In catalytic reforming, paraffinic  and naphthenic hydrocarbons are converted
into aromatic hydrocarbons, which high higher octanes.  Hydrogen is liberated
in this process.  In polymerization,  light olefins such as ethylene,  propylene,
and butyLanes are combined to form  branched-chain hydrocarbons in the gasoline
and boiling range.  Branched-chain  compounds have relatively high octanes.  The
light olefins are produced in the catalytic cracker.

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                                  78
Current Fuel  Use  Patterns

            The primary fuel used in the model refinery is  a blend of off gases
from various units within the refinery.  Off gases are collected from a number
of processing units, the major sources being the catalytic  cracker and the
catalytic reformer.  The quantity and quality of the blended refinery gas
varies daily, but the average quantity is 1.45 x 105 ]Sfcn3/day (5.12 x 106 scf/day)
and the average composition is
                     Specie                  Mole,  percent
                      H2                            29.7
                      C,                            32.7
                      C2's                          13.0
                      C3's                          10.4
                      C4's                           6.9
                      N2                             7.2.

            The average heating value of this gas is about  37.3  MJ/Nm3  (1000
                                                         6                 9
Btu/scf).  Thus, the refinery gas supplies about 5.40 x 10   MJ/day  (5.12 x 10
Btu/day) of heat.
            The collected off gases go to a fuel gas drum which  provides for
gas mixing and surge volume.  Purchased natural gas is added to  the  fuel gas
drum as needed to maintain a desired pressure level which is usually about
45 to 50 psig.  The blend of refinery gas and natural gas is then distributed
to the various burners in the refinery.
            The model refinery manufactures asphalt from a  portion of its
residual oil.  Due to the high demand for this product in the summer and
negligible demand in winter, the refinery would vary its operations  between
summer and winter accordingly.  The average amount of natural gas required
would be 19,000 Nm3/day (673,000 scf/day)  during the summer (May through
November) and 570 Nm3/day (20,000 scf/day)  during the winter (October through
April).  These quantities correspond to heating values of 0.21 x 10  MJ/day
          g
(0.02 x 10  Btu/day) in the winter.

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                                     79
                                                      6                  9
            During the winter, an additional 2.17 x 10  MJ/day (2.06 x 10
Btu/day) of heat would be supplied by burning residual (No.  6)  fuel oil.
This fuel oil has a heating value of about 43,000 kJ/kg (18,500 Btu/lb).
When this fuel oil is used, it is atomized with steam and fed to the burners
along with the refinery gas/natural gas blend.  For the processes which are
set up to burn the oil, the heat input from the oil is restricted to about
10 percent of the total heat input of the furnace.  This is  necessary to
minimize operating problems, since the process heaters were  not designed for
oil.
            Mding the above figures, the total heat supplied by refinery gas,
                                                     6                  9
natural gas, and residual fuel oil is about 6.11 x 10  MJ/day (5.79 x 10
                                    6                  9
Btu/day) in the summer and 7.60 x 10  MJ/day (7.20 x 10  Btu/day)  in the  winter.

Geographic Considerations

            The model refinery is assumed located close to plentiful supplies
of coal which could be used for the production of low-energy gas.   The model
refinery would also be bounded by a navigable waterway which could be used
for barging coal into a gasification plant and for supplying the water needs
of such a plant.  The refinery could also be accessed by rail transport.
            Refineries typically are located near to a number of other industrial
facilities, which introduces the possibility that a single gasification plant
could supply low-energy gas to this refinery plus other nearby facilities.   This
concept is beyond the scope of this study.

Other  Considerations

            The model refinery processes low-sulfur crude oil (normally less
than 1 weight percent sulfur).  The refinery has no sulfur plant and uses no
hydrodesulfurization processes except for the removal of trace  amounts of
sulfur from the feed to the catalytic reformer, which is always a required
operation.  The products of the refinery are low in sulfur content.   The
residual fuel oil produced contains less than 2 weight percent  sulfur.

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                                    30
Potential Demand  for Low-Energy Gas

            In considering the retrofitting of this refinery to use low-energy
gas, the first priority is for replacing the purchased natural gas.   The  second
priority is for replacing the residual fuel oil burned during the winter.
Since this is low-sulfur fuel oil, it should be regarded as a premium fuel
which could be used in a number of industrial facilities for which  other  means
of controlling sulfur oxide emissions would be less practical.   The residual
fuel oil is also difficult to use in the existing furnaces at the refinery.
            The third priority is for replacing several species in  the refinery
gas which have, other uses for which they are better suited.  One of these
species is hydrogen, which can be used in hydro-treating operations  in the
refinery.  Hydro-treating not only reduces the sulfur content of petroleum
fractions, but also increases the volume of the products by adding  hydrogen
to them.  Thus, the hydrogen can be used to produce more and cleaner liquid
fuels.  Hydrogen can also be marketed for other uses.   The other species  which
could be displaced from the refinery gas are propane and butane.  These are
premium fuels which are normally recovered and marketed, either separately or
as "liquified petroleum gas" (LPG).  Propane and butane are normal  products
of the model refinery;. the amount of these products normally recovered depends
on available storage and market demand.   The recovery of additional quantities
of these species from the refinery gas is attractive considering the in-
creasing price and demand for these premium fuels.
            Table 21 shows the potential demand for low-energy gas  at the model
refinery.  Based on displacing the purchased natural gas,  the residual fuel
oil burned, and 98 percent of the hydrogen, propane, and butane from the  re-
                                                   6                  9
finery gas, the potential demand is about 3.51 x 10  MJ/day (3.33 x 10 Btu/day)
                           6                  9
in the surtmer and 5.00 x 10  MJ/day (4.74 x 10  Btu/day)  in the winter.

Comparison of the  Model  Refinery
With Other Refinerie's"

            Size.  The model refinery,  with a crude oil capacity of about 3.97
x 10  liter/day (25,000 barrel/day), is  close to the median size  but less than
the average size U.S. refinery.  Because it is close to the median  size,  it is
felt to be a good model with respect to  size.

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                     TABLE 21.  POTENTIAL DEMAND FOR LOW-ENERGY GAS AT MODEL REFINERY




Fuel
Purchased
Res idua 1
Hydrogen
Propane i
Butane in
TOTAL



Di sp laced
natural gas
fuel oi 1 burner
(a)
in refinery gas
(a)
n refinery gas
refinery gas



Summer
(May-Nov)
0.17
—
0. 10
0.31
0.26
0.84

IOV MJ/day
Winter
(Dec-Apr)
0.01
0.52
0. 10
0.31
0.26
1 .20
Heating Va

Annua 1
Average
0. 10
0.22
0. 10
0.31
0.26
0.99
1 ue Demand

Summer
(May-Nov)
0.67
—
0.41
1.21
1 .04
3.33

IOV Btu/day
Winter
(Dec-Apr)
0.02
2.06
0.41
1.21
1 .04
4.74


Annua I
Average
0.40
0.86
0.41
1.21
1 .04
3.92

                                                                                                                 CO
(a)  Heating  value  demand  based on 98 percent  recovery of  specie  from refinery gas.

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                                    82
            Complexity.  The Nelson complexity factor for the model refinery
is 5.92 and that for the U.S. refining industry as a whole is 8.88.  Thus, the
model refinery is less complex that the average U.S. refinery.  As a result of
this difference in complexity, one would expect (based on Figure 19)  the unit
energy consumption for the model refinery to be about 34 percent less than that
of the average U.S. refinery.

            Refinery Energy Consumption.    A comparison of the energy
consumption of the model refinery with the U.S. average value is shown in
Table 22.  The annual average consumption of refinery gas, natural gas, and
residual fuel oil by the model refinery corresponds to about 1.55 MJ/liter
crude oil  (233,000 Btu/B crude oil).  This is not a total energy consumption in
the sense of the Bureau of Mines data^O) since it does not include coke or
purchased electricity.  The amount of coke consumed as fuel is difficult to
estimate because this includes the coke deposited on catalysts in process
units and then burned off, such as is done in catalytic crackers.  The amount
of electricity used for process units at the model refinery must be included
to determine total energy use.  In order to obtain an approximate comparison
with the Bureau of Mines data^20) one can add to the known energy consumption
of the model refinery the average values for coke and electricity for the state
(or group) in which the model refinery is located.  This gives a total energy
consumption of about 2.20 MJ/liter crude oil (330,000 Btu/B crude oil).
            For comparison with the model refinery, the U.S. average energy
consumption has to be adjusted for the differences in time (fuel cost)  and
complexity.  Using Nelson's correlation (Figure 19) to correct the U.S.
average value to the time and complexity of the model refinery cases gives
a total energy consumption of about 2.38 MJ/liter crude oil (358,000 Btu/B
crude oil).  This agrees reasonably well with the value of 2.20 MJ/liter
cited above.  Thus, the total energy consumption of the model refinery appears
to fall in line reasonably well with other industry data when the effects of
the pertinent variables are properly considered.

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                           TABLE 22.   COMPARISON OF ENERGY CONSUMPTIONS FOR
                                      MODEL REFINERY WITH U.S. AVERAGE VALUES

Energy Source
Net Energy
1973 U.S.
Refinery
Average
Consumpt

May-Nov
ion, J/l
Mode 1

itre ( I03 Btu/B
Refinery, 1975
Dec-Apr
crude)(a)

Annua 1
Average
Crude oi I                 0.331  (0.05)
Distillate fuel  oil        47.1  (7.09)
Residual  fuel  oil         404.7  (60.98       0.0 (0.0)    .      548.2 (82.6)        228.3 (34.4)
Liquefied  petroleum gas   59.5  (8.96)
Natural  gas             1619.2  (243.99)   184.5 (27.8)          5.3 (0.8)         109.5 (16.5)                 £
Refinery gas            1568.7  (236.38  1206.5 (181.8)      1206.5 (181.8)      1206.5 (181.8)
Petroleum coke           585.1  (88.17)
Coal                       I 1.6  (1.74)
Purchased  electricity    116.7  (17.58)
Purchased  steam           59.6  (8.98)                                            _ -- _
  TOTAL                 4472.5  (673.92)(b)                       .                1544.3 (232.7)(c)
Refinery Complexity             9.24                                5.92

(a)  MJ/Mter crude = (1.591)  ( I03 Btu/B crude).
(b)  Adjusting from 1973 to 1975 and from complexity  9.24 to 5.92 using Figure 3 yields
                           (6.73.92)(|£)  = 358 x 10  Btu/B.
                                     664
(c)  Does not include coke or purchased electricity.  Adding average values of these for
     state (or group) of model  refinery gives total  of 330 10-* Btu/B.

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                                     84
           Types  of Fuels Used.   The model refinery is heavily de-
pendent upon the refinery gas as. an energy source.  While this is a major
energy source in most refineries, there are many refineries in which it is
not nearly so dominant as was assumed for the model refinery.   The data in
Table 18 indicate that, on a national basis, refinery gas provides about
35 percent of the total energy needs of refineries.  This compares with
about 55 percent for the model refinery (including the estimated coke and
electricity).
           For the model refinery, low-sulfur crude oil is processed, no
other hydrotreating operations are used, and, hence, much of the hydrogen
from the catalytic reformer can be used for fuel.  In many other refineries,
the crude oil will contain more sulfur, more of the hydrogen will be re-
quired for hydrotreating operations, and,  hence, less of the fuel needs will
be satisfied with refinery off gases.  Polymerization is used  in the model
refinery, but aUcylation is much more widely used in other refineries.
Therefore, most of the C^-C. compounds in the refinery gas of  the model
refinery are assumed to be saturated hydrocarbons (paraffins).

           Land Area.  The model refinery occupies a total of about 32
acres, of which only about 3 acres are used for the processing equipment.
As can be seen from Figure 23,  the area per unit throughput for the model
refinery is somewhat less than the general correlation would indicate.   Thus,
the model refinery is probably somewhat more compact than many other refineries.

           Access to Waterway.   The model refinery is located on a navi-
gable waterway,  and this is true for most  other refineries as well.   Re-
fineries, crude oil is received and refined products are shipped by tankers
and/or barges.

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                                   85
                    Gasification  Plant Design

            Due  to the  low overall energy demand of the model refinery,  an
 air-blown  fixed-bed, Wallman-Galusha gasification  system was selected for
 study.   The gasification  plant would supply  about  5.00 x 10   MJ/day (4.74
 x  10  Btu/day)  in the  winter  and 3.51 x 10   MJ/day (3.33 x 109 Btu/day)  in
 the summer.  Figure 24 shows  the flow sheet  for the Wellman-Galusha gasi-
 fication plant.   The mixture  of  refinery waste  gas at  39.6 MJ/Nm  (1062
 Btu/scf) and low-energy gas from the Vfellman-Galusha at 6.26 MJ/Nm  (168
 Btu/scf) would  have a  heating value  of  about 9.84  MJ/Nm (264 Btu/scf) in
 the winter and  8.72 MJ/Nm  (234  Btu/scf)  in  the summer.  A complete material
 balance  for this  plant is given  in Appendix  B.   Table  23 summarizes the
 pertinent  characteristics of  the refinery model gasification plant.
             TABLE 23.   GASIFICATION PIANT DESIGN FOR REFINERY MODEL
                Gasifier -  Wellman-Galusha C3 units!
                Desulfurization -  Stretford
                Maximum gas production rate -  5.0. x 1Q5 MJ/day
                                               (.4.77 x I09 Btu/day)
                Gas high heat value -  6.619 MJ/Nrrv5 (.168 Btu/scf 1
                Coal  consumption -  228 metric ton/day
                                   (252 ton/day)
                Efficiency -  76.7  percent
           The coal selected for use in this system was an Eastern bituminous-
type coal with 6 percent moisture, 8 percent ash, and sulfur content of 3.9
percent.  The free-swelling index of this coal is about 5, dictating the use
of an agitator-type fixed-bed gasifier.  A complete analysis of the coal is
given in Table 24.

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   Coal
preparation
  Coal  storage

          ©Cooling water
                                          Scrubber/o.  Copier
                                           ^.v  ^  (7)  ^.A ^
                                                             Stretford  	
                                                             absorber|j~
                                        •Clean gas
           © Makeup water
                Cooling pond
                                                20)
                                                ^•Sulfur
                                                                                                            CO
 Tar oil
separator
-Ammonia
 stripping
                                                                  JL©
                                                                                          .Phenol
                                                                                          removal
                  FIGURE 24.  FLOW SIffiET FOR THE WELIJ1AN-GALUSHA GASIFICATION PLANT
                             (See Appendix B for complete material balance.)

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                                      87
            TABLE  24.   REFINERY MODEL PLANT COAL ANALYSIS

Proximate
Moisture
Volati le Matter
Fixed Carbon
Ash
Ultimate Analysis
Hydrogen
Carbon
Nitrogen
Oxygen
Sulfur
Ash
HHV (Btu/lb)
Grindab i 1 ity
Free-Swelling Index
Wt. Percent
6. 1
32.7
48.3
8.4
4.8
68.0
2. 1
6.8
3.9
8.4
13690
60
5

           Due to the snail size of the gasification plant it was not felt
practical to install coal preparation facilities, therefore, crushed-sized
coal would be purchased from the mine and stored at the gasification plant.
The gas plant would consist of three 10-ft diameter Wellman-Galusha units
capable of producing a total of 5.03 x 10  MJ/day  (4.77 x 10  Btu/day) of
fuel gas with a heating value of 6.26 MJ/Nm   (168 Btu/scf).  The coal con-
sumed would be about 278 metric ton/day (252 ton/day) and the overall thermal
efficiency of the plant would be 76.7 percent.  The raw gas from the gasifier
is processed directly through a scrubber for the removal of tars, oil, phenols,
and airmonia, and then through a cooler section where additional ammonia, tars,
and other condensible constituents are removed.  The gas is then fed into a
Stretford-type desulfurization system which oxidizes sulfur compounds to
elemental sulfur in solution, eliminating the need for a Glaus plant.  The
final gas product would contain 300 ppm of sulfur, or less, and would be
mixed with refinery gas and distributed to the various processes in the refinery.

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                                  88
            Figure 25 shews an overall plot plan of the refinery with
 gasification and coal storage facilities and also the required cooling
 pond.  The processing facilities of the refinery itself occupy about
         2
 16,200 m  (4 acres) of ground, and storage capacity requires an
                    2
 additional 93,000 m  (23 acres) of ground.  The gasification plant
                                                       2
 for the refinery is estimated to require about 4,050 m   (1 acre)
                                     2
 of ground with an additional 4,050 m  (1 acre) required for a cooling
 pond.  Coal-storage facilities for 1-month supply of coal would require
                      2
 an additional 4,050 m  (1 acre).
               Potential  Impact of  Low-Energy  Gas

            The petroleum refining industry is a promising candidate for
retrofitting to the use of low-energy gas because the consumption of
energy, and particularly natural gas, by the industry is high and because
much of the industry is located in regions of high coal availability.   The
industry includes a wide range of refinery sizes and energy requirements.
The model refinery used in this study is somewhat small when one considers
the economic justification of a coal-gasification facility to serve a
single refinery.  It is important to look at some of  the larger refineries
in the United States in order to appreciate the impact which the use of
low-energy gas from coal could have on the nation's refining industry.
            Table 25 lists the 24 largest petroleum refineries in the
United States.  For each of these refineries, the table gives the Nelson
complexity factor and estimates of the consumptions of energy in the form
of natural gas and oil.  The latter were obtained by
            (1)  Determining the unit energy consumption (all
                 sources) from the complexity using Nelson's
                 correlation (Figure 19)
            (2)  Multiplying the above by the fraction of the
                 total energy supplied by natural gas and oil,
                 using the Bureau of Mines data for the state
                 or state group in which the refinery is located
                 (Table 18).

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 Coal storage
   I  acre
  Gasifica-
  tion &
  Cleaning
   1.0 acre
 Cooling pond
   I .acre
Rivet
bank
                                         Processing,  4 acres
1
1
1
I



Gasoline
Production
I
i Process
! Support
~| r ~~>
i
1 i Light gas MCatalytic
1 [Recovery'
1
I
j
'Crocking
~l
l
1
_J


j Crude


Oil
( Distillation






l
1
I
i
. _ i

                                                                                             CO
                                     Refinery  storage, 23 acres
                          FIGURE 25.  REFINERY PLOT PLAN

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TABLE 25.   CAPACITIES AND ESTIMATED ENERGY CONSUMPTION^1 7 )
           OF LARGEST REFINERIES IN THE UNITED STATES

(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(ID
(12)
(13)
(14)
(IS)
(16)
(17)
(18)
(19)
(20)
(21)
(22)
(23)
(24)
State
Louisiana
Texas
Texas
Indiana
Texas
Texas
Texas
Texas
Illinois
Louisiana
New Jersey
Louisiana
Mississippi
California
Texas
Illinois
California
California
Pennsylvania
Louisiana
Illinois
Pennsylvania
Ohio
Pennsylvania
Company
Exxon
Texaco
Exxon
Amoco
Amoco
Mobil
Gulf
Shell
Shell
Cities
Exxon
Shell
Std (Calif)
Std (Calif)
Atlantic-
Richfield
Marathon
Std (Calif)
Atlaatic-
Richfield
Atlantic-
Rich field
Gulf
Mobil
Gulf
Sohio
Sun
Coal
City Availability
Baton Rouge
Port Arthur
Bay town
Whiting
Texas City
Beaurcont
Port Arthur
Deer Park
Wood River
Lake Charles
Linden
Norco
Pascagoula
£1 Segundo
Hous ton
Robinson
Richmond
Carson
Philadelphia
Belle Chaase
Jollet
Philadelphia
Lima
Marcus Hook

High
High
High
High
High
High
High
High





High
High


High

High
High
High
High
Crude Oil
Capacity, '•1/-'1
103 B/CD
445
406
400
360
333
325
312
294
283
268
265
240
240
230
213
195
190
185
185
180.4
175
174.3
168
165
Nelson
Complexity
9.
8.
12.
9.
10.
9.
10.
9.
10.
9.
8.
7.
6.
7.
10.
5.
12.
8.
5.
8.
8.
7.
7.
13.
45
69
99
26
23
18
24
77
15
52
15
27
99
94
12
84
45
28
75
17
62
83
50
73
Unit Natural Gas and
Oil Consumption
MJ/liter crude 10 Bt"/B crude
396
500
749
366
590
528
590
563
318
399
325
304
333
320
584
183
504
334
231
342
270
315
229
554
249
314
471
230
371
332
371
354
200
251
204
191
209
201
367
115
317
210
145
215
170
198
144
348
Total Natural Gas and
Oil Consumption
10 MJ/day 10 Btu/day
28.1
32.1
47.6
21.0
31.4
27.3
29.3
26.3
14.4
17.0
13.7
11.6
12.7
11.6
19.7
5.6
15.2
9.9
6.8
9.9
7.6
8.9
6.1
14.4
111
127
188
83
124
108
116
104
57
67
54
46
50
46
78
22
60
39
27
27
30
35
24
57
                                                                                           O

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                                    91
"Cable 25 also indicates which refineries are located in states considered as
having a high coal availability  (production or reserves).
            Among the refineries listed in Table 25 are
              •  Seven refineries having estimated natural gas
                 and oil consumption greater than 83 x 106 MJ/day
                 (79 x 109 Btu/day) and located in states having
                 high coal availability.
              •  Nine refineries having estimated natural gas and
                 oil consumption of 21-83 x 106 MJ/day  (20-79 x
                 109 Btu/day) and located in states having high
                 coal availability
              •  Eight refineries located in states not having
                 high coal availability.
With regard to coal availability, it should be noted that there may be
cases in which transporation of coal from a nearby state is feasible.
Cft the other hand, there may be cases in which coal reserves in a given
state are not feasible for use at a site within  the same state but are
fairly far away.
            For these large refineries, the estimated natural gas and oil
consumptions are high enough to justify on-site coal gasification facili-
ties.  It appears that there are quite a number of refineries in the United
States for which the energy needs and locations are such that retrofitting
them to use low-energy gas from coal could make considerable sense.  The
impact of this option upon the petroleum refining industry could be quite
significant.

                    Burners and Furnaces  in
                         a  Refinery  Plant

            This section describes.typical furnaces and burners used in a
refinery plant similar to that described in this study and the possibilities
of converting these processes to low-energy gas.

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                                   92
                                 Burners

            In the case of the refinery discussed in this study, because of
the relatively small fuel needs, the use of a Wallman-Galusha air-steam gas
producer is proposed.  This gas would be mixed with refinery gas from which
marketable components such as hydrocarbon, propane, and butane had been
stripped leaving CH,, C2H6' an<^ N~ as components in a gas of 41.8 MJ/Nm
(1062 Btu/scf) high heating value  (HHV).  The HHV of the fuel mixture is
10.4 MJ/Nm   (264 Btu/scf) during the summer  (when the mixtures contain 10.8
percent by volume refinery gas).  Ihe HHV during the winter is 9.25 MJ/Nm
(235 Btu/scf)  (when the fuel gas contains 7.5 percent by volume of refinery
gas).  The summer and winter Wobbe numbers would be 291 and 258.  Ihe flash-
back velocity gradient at stoichiometric and the heat release rate at stoi-
chiometric are very slightly below the values given in Table A-2 for Wellman-
Galusha gas, and somewhat above those for natural gas.
            For the fuel mixture the flash-back velocity gradient times the
higher heating value, a probably important criterion for nozzle-mix type
                                     3             44
burners, varies from 591 to 512 MJ/Nm -sec (15 x 10  to 13 x 10  Btu/scf-sec).
These values are far below the value for natural gas, but still an improvement
over Wellman-Galusha gas.
            For the typical refinery considered in this study, Table 26 lists
characteristics of the furnaces used for process heating and steam raising.
Figure 26 shows an inspirating burner used on refinery furnaces.  Figure 27
shows the burner used in refinery boilers.
            Cn changeover to the mixed fuel from natural gas, it is probable
that all the furnace burners would have to be changed to gas burners of the
general type shown in Figure 28, when sufficient draft is available.   When
sufficient draft was not available, exhaust fans could be added, or nozzle-
mix burners with blowers would be used.
            Because of the low-heating values of the gas, the burners in
boilers would require changing.  (See discussion of secondary steel plant
boilers.)  One boiler manufacturer would recommend a vortex burner for the
lew heating value gases.  They would also recommend replacing the multiple

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TABLE 26.  FURNACES IN A SMALL REFINERY

No.
1
2
3
4
5
6
7
8
9
Type
Pref lash reboi ler
Crude heater
Vacuum tower heater
Light oi 1 heater
Tar stripper heater
Unifier heater
Platforming heater
Raw oi 1 heater
Boi lers
Des i gn
I03 MJ/hr
8.2
20.3
14.2
29.7
38.8
10.5
21. 1
5.9
47-65
Capacity,
(I06 Btu/hr)
(7.8)
(19.5)
(13.5)
(28.2)
(36.8)
(10.0)
(20.0)
(5.6)
(45-62)
Temperature, F (
Stack
516
504
574
493
643
609
—
527
—
(960)
(940)
(1065)
(920)
(1 190)
(1128)
—
(980)

F)
Furnace
668
757
689
654
663
—
649
677
—
(1235)
(1395)
(1270)
(1210)
(1225)

(1200)
(1250)
—
02 Efficiency,
3ercent Percent Fuels
4.5
2.0
4.5
3.5
4.8
2.6
4.8
9.2
-
69.6
71.5
66.8
71.6
63.0
64.0
—
54.0
—
Gas,
Gas,
Gas,
Gas,
Gas,
Gas
Gas
Gas
Gas,
No.
No.
oi 1
No.
No.



No.
6 oi 1
2 oi 1

6 oi 1
6 oil



6 oi 1
                                                                             CO

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             94
                Spider
                      Secondary
                        Air
                       Primary
                        Air
FIGURE 26.  ZUS1K VPM VEETICAL GAS BURNER
            FOR HIGH HYDROGEN GAS

   Spider  with  radial arms distributes
   primary air-fuel mixture evenly over
   secondary air  stream.  No  adjustment
   needed  in shifting from start-up gas
   to high hydrogen fuel.

-------
                                         95
  Oil-
Steanf*
                      Air
                     Air
    Swirl
    'Vanes
                                                A
                                                  X
                                                                X
X
\
                                                        N
                                                            X
                                                             \
                        FIGUEE 27.   REFESEPY BOILER BURNER

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                   96
                   Tip  Cone
FIGURE 28.  ZINK VYR VERTICAL GAS BURNER
            FOR PROCESS HEATERS

 Burner designed to use raw gas at
 appreciable pressure,  and natural draft
 to supply air.   Has a  high turndown
 ratio and can use a wide  variety of
 gases.  Gas-tip cone is perforated with
 slots to permit passage of air into re-
 circulation zone.

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                                     97
burners with a single large capacity burner.  This would cut down cost of
replacing air ducting.  However, because of the high cost of field work, it
is quite possible that the replacement of the entire boiler-burner systems
with new package units would be the most economical approach.
            To summarize, it is probable that all the burners in a refinery
might have to be replaced when a change is made from the natural gas.
Further, it may be most economical to replace the boilers with new
package boilers rather than attempt to make field changes on their
burners.

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                                      98
           V.   CONSIDERATIONS IN  DISTRIBUTING LOW-  AND
                 INTERMEDIATE-ENERGY GAS  IN INDUSTRY

                          Volume and Pressure
                            Considerations

           Industrial gas distribution systems are often intricate and
extensive.  The model steel plant in this study would have  approximately
9144 m  (30,000 ft)  of gas piping with diameters ranging from 38  to 254 mm
 (1-1/2 to 10 inches).  The refinery model would have approximately 762 m
 (2500 ft) with sizes ranging from 25 to 152 mm (1 to 6 inches) in diameter.
These piping systems would be carbon steel with some brass  valves and
fittings.  Natural gas distribution systems are commonly rated at about
1030 kPa gage (150 psig).  In most plants in the two industries  considered
in this study, however, natural gas would be distributed at much lower
pressures of about 276 to 345 kPa gage (40 to 50 psig).
           A schematic of an industrial piping system is shown in Figure  29.
The gas is supplied to the system at some supply pressure,  Ps, and exits
the system at the burner at pressure,  ?„.  The difference between Ps and  P..,
                                       ij                                 hi
is the pressure drop through the system which for turbulent flow is propor-
tional to the gas density (p) times the square of the velocity  (V).  Prior
to being admitted to the burner, the exit pressure,  ?„,  is  further reduced
                                                     £1
by an orifice to a pressure normally less than 6.9  kPa gage (1 psig).
           Because natural gas is often distributed at much less than  the
design  pressure of the distribution system, it is  useful to look at the
possibility of using the same system for a lower energy  gas.  The governing
equation relating the supply and exit pressures for two  gases (1 and 2)
assuming the same energy supply rate for both cases is

                         2      21       ">      ">
                      p    - p    = -i-  ip  * - p   2)
                       s2     E2    w 2  ( si     El ;


where W = Wobbe number = HHV /p"  at standard conditions.  An extreme,
simplified case would be where ?„,  = ?„„ = 0.   The  equation then reduces  to

-------
Supply Pressure P
Exit Pressure P,
Burner Pressure < 1 psig
                   Gas  Distribution  System
                             FIGURE 29.   INDUSTRIAL GAS DISTRIBUTION SYSTEM

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                                   100
Figure 30 shows this relationship for 3 cases:  Wellman-Galusha gas,
Wellraan-Galusha gas mixed with refinery gas for the refinery model, and
Koppers-lbtzek gas for the steel plant model.
           As can be seen in Figure 29, for a natural gas supply pressure
of 207 kPa gage (30 psig) , a pressure of 1070 kPa gage (155 psig) would be
necessary for the Koppers-Totzek gas in the steel mill model and over 1380
kPa gage (200 psig) would be necessary for the Wellman-Galusha gas and
refinery gas.  Both the steel mill model plant and the refinery model plant
were assumed to have a natural gas supply pressure of from 276 to 345 kPa
gage (40 to 50 psig) .  It would be concluded, therefore,  that using the
existing distribution system would require pressures that would exceed the
design pressure of the existing system.  It would be assumed that at least
part or all of the gas distribution system would have to be replaced.  The
required pipe size would depend on the pressure at which the gas is supplied.
If the gas were supplied at the same pressure as the natural gas and the
total pressure drop through the system were kept constant, then the required
pipe areas for two gases are related by
For the three cases shown in Figure 29, the area ratios would be as shown
in Table 27.

             TABLE 27.  REQUIRED PIPE SIZE FOR GAS DISTRIBUTION*



Natural Gas
Wellman-Galusha Gas
Wellman-Galusha Refinery
Gas Mixture
Koppers-Totzek Steel Mi 1 1 Gas

HHV
Btu/scf
973
168
235

286


W
1244
183
256

338
Pipe
Area
Ratio
1
6.8
4.8

3.7
Pipe
Diameter
Ratio
1
2.61
2.19

1 .92
* Assuming the same supply pressure and heat delivery rate.

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                         101
   200
 ca
J2

CO

"O

 8
1-1

 g-
    150
oo
•H
05

-------
                                   102
The size of pipe and its cost would have to be weighed against the available
space and costs of compression.  Compression could require a significant
amount of energy depending on the final gas pressure.   The itiost efficient
way to compress the gas is with interceding in an isothermal process.
Most large compression systems use interceding.   The  other extreme is
adiabatic compression where no heat is transferred from the gas as it is
compressed.  Figures 31 and 32 show the power requirements for both adiabatic
and isothermal compression for the steel and refinery  plant models, respec-
tively.  Compression of fuel gas to 6.9 x 10  Pa (100  psig)  (P9/Pi =7.8)
                                                    6                  9
in both model industry cases would require 0.40 x 10  MJ/day (0.38 x 10
Btu/day) for the steel mill model (which is 1.8 percent of the total energy
in the clean gas) and 0.15 x 106 MJ/day (0.14 x 109 Btu/day)  for the
refinery model (which is 2.9 percent of the total energy in the clean gas).
          Corrosion Considerations  on Substituting  Low-
           or  Intermediate-Energy Gas for Natural Gas

          Potential corrosion problems in gas distribution  systems and
process equipment resulting from the substitution of  low- or  intermediate-
energy gas from coal for natural gas are also an important  consideration.
Corrosive constituents in the produced fuel gas can increase  degradation of
carbon steel, brass, and other materials found throughout fuel systems.
Specific interest is given here to retrofitting a steel plant to fuel gas;
however, the discussion has general applicability to  a variety of industrial
processes.
          While the composition of gases produced by  coal gasifiers is some-
what unique, a broad experience exists for handling of corrosive gases from
other sources, e.g., coke oven gas, sour gases from petroleum production,
gases generated in chemical processes, and refinery industries.  Experience
with distribution of town gas, used extensively in  Europe,  is directly
applicable.  The approach taken in this  study was to  identify the corrosive
species in fuel gas and, where possible, to establish acceptable limits for
distribution.  Also, corrosion mitigation and monitoring procedures were
reviewed.

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                                    103
          1.0
 10  MJ/day
= (LO9 Ktu/day)
          0.5
                         2468

                       Pressure Ratio  P2/P1  ^For Pl =
10
             FIGURE 31.   COMPRESSION POWER FOR STEEL MILL MODEL
                         GAS SUPPLY

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                                    104
          0.3
          0.2

  106 MJ/day

(109 Btu/day)

          0.1
                                 Pressure Ratio  P2/P1   ^For Pl
                                                                      10
              FIGURE 32.  COMPRESSION  POWER FOR  REFINERY
                           MODEL GAS SUPPLY

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                                    105
Corrosive  Species  in Low- and
Intermediate-Energy  Gas  from Coal

          A variety of materials is used in the distribution and usage of
 fuel gas.   Carbon steel for pipes and fittings is the most prevalent
 material with lesser  amounts  of brass found in valves and high-alloy steels
 and nickel  alloys in  process  equipment.  Constituents in fuel gas in the
 presence of water support corrosion of these materials.  Of primary concern
 are conditions resulting in general corrosion, but those which promote
 stress-corrosion  cracking are also considered.
          Constituents of fuel gas can be divided into three groups:
 corrosive,  inhibitive, and inert.  Carbon dioxide (CC^)/ hydrogen sulfide
 (H2S) and other sulfur-containing species, ammonia (NH3), and hydrogen
 cyanide  (HCN)  promote corrosion.  Carbon monoxide (CO) inhibits corrosion;
 whereas hydrogen  (H-), methane  (CHJ , and nitrogen (N~) do not significantly
 affect corrosion.  The acid gases, carbon dioxide and hydrogen sulfide,
 readily corrode mild  steel.   Copper alloys are corroded by sulfur compounds
 and are susceptible to corrosion or stress-corrosion cracking in the presence of
 ammonia.  Nickel  and  nickel alloys are corroded by sulfur compounds.
 Although the  effect of a given species on corrosion is generally known, the
 corrosivity of a  mixture of gases is not readily predictable because of
 complex interaction and temperature effects.
          Of  all  the  constituents in fuel gas, hydrogen sulfide is the most
 deleterious because even small amounts can greatly accelerate corrosion.  An
 early study of the corrosion  of steels by natural gas containing traces of
 H-S recommends that H9S content be controlled to less than 2.28 mg/m  (0.1
                                (26)
 grain per 100 cubic feet of gas)    .  Corrosion is not severe in the absence
 of  water.   Corrosion  of steel in refinery condensing systems was found to
                                   (27)
 increase with sulfide concentration    .  Inhibitor treatment and pH
        (28)
 control     were  necessary to control corrosion of steel in storage of high-
 pressure sour gas (13 percent H-S, 5 percent C02)•  Monel and Inconel alloys
 were substituted  for  austenitic stainless steel in special equipment operating
 at  ambient  temperatures.  Many other instances are recorded in which severe
 corrosion problems arose from handling of moist hydrogen sulfide containing
 gases.

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                                    106
          In addition to general corrosion, stress-corrosion cracking  (SCC)
is promoted by H~S.  Susceptibility to SCC for a range of ferrous materials
increases as hardness increases.  In sour gas service, most failures of
tubular components occurred with alloys, the hardness of which exceeded
     (29)
R 22    .  Field failure data and laboratory studies form the basis for
NACE's publication IF 166, "Sulfide Cracking Resistant Metallic Materials
for Valves for Production and Pipeline Service" which recommends R 22 as
                                                                  c
the maximum hardness level for this service.  The recomnendation has seen
much broader application than just for valves.
          Based upon laboratory data, 0.001 atmosphere was chosen as the
critical partial pressure of H2S at which SCC will occur       .  Under
more severe conditions, higher temperature and pressure, the value is lower
      (32)
still    .  The point to be made is that even small amounts of H2S can
promote SCC.
          Carbon dioxide dissolves in water to form carbonic acid, a
corrosive agent to mild steel.  Corrosion rates in excess of 100 mils per
year have been observed for partial pressures of approximately 690 kPa
(100 psia).  Obrect     identified CCU as a major corrodent in steam-
condensate systems.  It is also recognized as a primary contributor to
corrosion in handling of sour gases.  A rule-of-thumb for natural gas
transmission is that no special corrosion mitigation procedures are required
for partial pressures of CO- below 35 kPa (5 psia).  This level is not
absolute as evidenced by a steady lowering of the acceptable limit over the
years.  Presence of both H2S and C02 lowers the tolerable limits of each
gas.
          Mixtures of carbon dioxide-carbon monoxide-water were shown to
promote SCC of a high-strength steel.  Steel specimens failed in 65 percent
CO - 35 percent C0~ mixtures at total pressure as low as 2 atmospheres at
    (34)          z
20 C    .  This system has also resulted in SCC of mild steed in town gas
composition    .  Recent work at Battelle has shown SCC of mild steel to
occur in C02-CO-CH4-H20 at C02 and CO partial pressures of 6.9 kPa (1 psia)
and less.  All three constituents (C02/  CO,  and H2O)  must be present to
support SCC.

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                                   107
           Ammonia accelerates the corrosion of mild steel,  but is presence
 in fuel gas is of greater consequence because of its deleterious effect on
 copper and copper alloys.  Stress-corrosion cracking of many of the copper
 alloys is readily promoted by NEL, even at trace levels. At high concentra-
 tions, general corrosion of copper alloys is a serious problem.
           Copper alloys are also corroded by sulfur-bearing canpounds.
 Nickel and nickel alloys are susceptible to sulfidation in  aqueous phase
 and at high temperatures.  The latter is of concern when burning sulfur-
 containing fuel.
           Other constituents of fuel gas can participate in corrosion
 processes, but the primary contributions to corrosivity of  fuel gas are
 made by species discussed above:  hydrogen sulfide, carbon  dioxide, and
 ammonia.
           In addition to corrosive gases, fuel gas contains condensable
 tars and ash, which can cause plugging and blockage if not  controlled.   A
 beneficial effect of condensable organics is that they can  coat the metal
 surfaces and retard corrosion.

Mitigation  and Monitoring
of Corrosion by Fuel  Gas

           In the above section,  it was shown that raw fuel  gas contains
several species which promote corrosion of materials commonly found in gas
distribution systems and processes equipment burning fuel gas.   Here,
procedures to mitigate and monitor corrosion by fuel gas are discussed.
"Control of Internal Corrosion in Steel Pipelines and Piping Systems",
NACE Standard KP-01-75, presents recommended practice for corrosion control
of pipeline systems,  including gas transmission and gas distribution systems.
Relevant portions of the recommended practice are presented  below with
experience from comparable service conditions,  namely,  transport of coke
oven and town gas, transmission of natural gas,  and handling of sour gases
during production.
           Corrosion control can be achieved in this service by several
procedures:  (1)  elimination of corrosive species in the fuel gas,  (2) use

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                                    108
of corrosion inhibitors,  (3) application of coatings, and  (4) substitution
of more corrosion-resistant material.  Choice of procedure is made on the
basis of economics and ease of application to a specific problem area.
           In view of the number of corrosive species present in fuel gas
                                                                v
and the variety of materials in contact with the gas, removal of water
provides the most general means to control corrosion.  In the absence of
water, corrosion throughout the distribution system would be negligible.
 (Corrosion in town gas systems in Europe was controlled by removal of water
                    /o/r\
and desulfurization    .)  Water can be removed by water separators, by
refrigeration, or by dehydrators.  Various types of dehydrators are available
including glycol and desiccant.  Using these means, the dewpoint of the gas
is maintained below service temperatures to prevent condensation in the
system.  Commercial units are available to dehydrate large volumes of gas.
           It may be advantageous to remove other corrosive constituents in
addition to water.  Conmercial processes are available to remove acid gases,
annvDnia, and other corrosive species.  Removal of sulfur prior to use of
fuel gas decreases corrosion throughout the system (in addition to elimina-
ting the need for flue-gas clean-up units).
           Addition of corrosion inhibitor can be used in conjunction with
other corrosion control procedures.  Several types of inhibitors are avail-
able for either continuous or batch application.  Filming inhibitors are
effective for gas distribution systems.  Application of protective coatings
is not seen to be necessary for the bulk of the piping system, but it can
be beneficial in specific areas.
           In process equipment when a specific corrosion problem is identi-
fied, selection of a more corrosion resistant material may provide a ready
solution.  For example, nickel and high-nickel alloys are susceptible to
sulfidation and are not recommended for use with high temperature sulfur
bearing gases.  Alloys resistant to sulfidation should be used.
           The need for corrosion mitigation and the evaluation of its
effectiveness are determined by analysis of corrosion monitoring data.  The
level of sophistication required is determined in part by the consequences
of a failure.  A leak in a fuel gas system is less tolerable than a leak in

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                                   109
a natural gas system, because, in the addition to fire and explosion
hazards, noxious carbon monoxide would escape.  Prior to conversion to
fuel gas, the entire system should be inspected and a list of materials
throughout the system compiled.  Any questionable components, because of
present condition or known corrosion susceptibility, should be replaced.
A sample of each type of component in the system should be reinspected
periodically for corrosion damage after conversion to fuel gas.  These
inspections can be supplemented by data from corrosion coupons and probes
installed throughout the system as necessary.  Analysis of gas, residue,
and deposits found in the system also provides valuable information.
Experience gained following conversion to fuel gas will dictate the
frequency and amount of inspection required.
          Handling of fuel gas presents similar corrosion problems to
those of handling coke oven gas, i.e., a variety of acid gases and other
corrosive components are produced in a moist gas.  Corrosion control
practiced varies with the severity of corrosion problems experienced at
different plants.  Except for special instances, distribution systems of
carbon steel have provided good service.  For mitigation, where corrosion
was excessive, the coke oven gas was either dried or partially dried and
desulfurized.  low corrosion rates of carbon steel have been observed in
some moist coke oven gas service with no applied conversion control.
These low rates were attributed to condensable hydrocarbons coating the
steel surface.  Austenitic stainless steel has been used successfully to
carry moist coke oven gas.  However, it must be recognized that austenitic
stainless steel, particularly in the sensitized condition, is susceptible
to SCC in presence of polythionic acid    , chloride, or fluoride
Polythionic acid and chloride can form from, or are found in, the
environment, while fluoride can result from use of some welding fluxes.
          Internal corrosion of natural gas transmission lines is
controlled primarily by dehydration of the gas and inhibitor treatment.
Inhibitor can be injected continually or by batch treatment in a pigging
operation.  Monitoring of internal corrosion in pipelines transporting
                                                        (39)
natural gas containing CO- and Hos was recently reviewed    .  Corrosion
data obtained on an operating system are presented for corrosion coupons,
hydrogen probes, electrical resistance probes, and corrosion spools.

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                                    110
           Corrosion problems related to oil and gas production (drilling
 operation) in the presence of H-S and CO-  are not amenable to mitigation
 by dehydration or removal of corrosive species.  Corrosion is controlled
 under these conditions by inhibition, pH control, and selection of
 corrosion resistant materials.  Much information is available in the
 literature describing corrosion and sulfide stress corrosion cracking
 behavior of a variety of materials in sour gas service.  These data can
 be applied to material selection and corrosion mitigation for fuel gas
 service.

 Conclusions

           Conversion to fuel gas from natural gas will require additional
corrosion-control procedures.  Corrosive constituents are present in fuel
gas but are not found in appreciable amounts in natural gas, e.g., acid
gases and ammonia, corrode common materials found in gas distribution
systems.  While fuel gas compositions are somewhat unique in relative
amounts and mix of corrosives, experience in corrosion control in similar
services is directly applicable.  One of the most certain and perhaps most
economical means of corrosion mitigation is to remove water from the gas
prior to injection in the distribution system.  Individual corrosives can
also be eliminated; desulfurization is common practice.  These techniques
are successfully applied to the transport of coke oven gas.  In specific
process units, selection of more corrosion resistant materials may be
necessary.  An example of the latter is the elimination of high nickel
alloys from units for direct burning of coke oven gas because of severe
sulfidation.
           It is recommended that a thorough corrosion survey of systems for
materials compatibility as affected by gas conversion be made prior to any
conversion, and be repeated periodically after conversion.  In this way
corrosion problems can be identified and suitable corrosion mitigation
procedures selected.

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                                     Ill

             VI.   ENVIRONMENTAL  CONSIDERATIONS  IN RETROFIT

            Emissions from the  Gasification Processes

Model  Steel  Plant

           Table 28 summarizes the  major emissions from the gasification
process for the model  steel plant.   The major points of emissions in this
process are the coal storage,  coal  pulverizing and preparation facilities,
the oxygen, plant,  the  filter which  separates water from slag and clarifier
sludge, cooling tower, and the Glaus sulfur recovery process.
           Snissions from the coal storage pile will involve fugitive dust
picked up by the wind and  leachate resulting from rain water filtering
through the coal pile.  The coal pile should be packed tight to limit dust
loss and  prevent air  from  entering the pile causing oxidation and spon-
taneous combustion.   Conveyors should be hooded with the hood exhaust
processed through  a baghouse or electrostatic precipitator.   Leachate
from the  coal  pile would resemble acid mine drainage in many respects—
containing acids,  organics, and soluble metals.   This water should be col-
lected and ponded  for biological reduction of pollutants before being dis-
charged to a water source.
          Fugitive  dust problems can be minimized by coating the coal pile
with a plastic material and drawing from it only during periods of emergency.
The coal  normally  would then be taken directly from unit train or barge
by covered conveyors.   The logistics of such an operation,  however,  would
have to be carefully  planned to ensure proper operation of  such a system.
However,  care  must be taken to prevent breaks in the coating which would
create a  chimney effect causing aspiration of air into the  pile resulting
in oxidation and combustion.
           Emissions from the coal pulverizing preparation step consists
of pollutants  in the  gas used in drying the coal, plus possibly some volatile
constituents from  the coal.  A portion of the final product gas is combusted
to heat air which  is  then supplied to the pulverizer for drying purposes.
This stream is then vented from the pulverizer.   The stream consists pri-
marily of carbon dioxide, nitrogen, some water vapor,  and oxygen.   The stream
would  also contain particulates and possibly some small  amounts of sulfur
dioxide oxidized from the coal.
          The vent  stream from the coal preparation step should be pro-
cessed  through a baghouse or electrostatic precipitator  or some other

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                                     112
                      TABLE 28.   DISCHARGES FROM STEEL MILL
                                 MODEL GASIFICATION PLANT
Source
Coal storage —
fugitive dust and
leachate from rain

Coal pulverizing






Oxygen plant

Fi Iter


Cool i ng tower
p 1 ume

Claus

Glaus tai 1 gas

Area of
Impact
Ai r,
Water


Air
(or





Air

Water,
Sol id Waste

Air


Sol id Waste
(by-product)
Air


Flow Rate
Dependent on
wind and rain
conditions

492, 160 Ib/hr
1 12, 144 scfm)





72,704 scfm

21,616 Ib/hr


17,500 Ib/hr


1,704 Ib/hr

675 scfm

Discharge
Ma i n
Composition
Coal dust
Acids
Organ ics
Soluble Metals
C09
M
H20
Oo
CH4
S02
Particulates
N2
C02,H20,02
C
Ash
H20
H20
Dissolved and
suspended sol i ds
S

H?S
C02

Percent(a)
— _



2 (v)
68 (v)
13 (v)
17 (v)
Trace
Trace
Trace
99 (v)'
Trace
17.8 (w)
72.2 (w)
10.0 (w)
100 (v)
—

100 (w)

2.7 (v)
97.3 (v)
(a)   (v)  volume percent
     (w)  weight percent.

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                                    113
efficient particulate removal device for controlling particulate emissions.
Emissions of other constituents would include some sulfur compounds such as
SCU, though these emissions should be relatively small.  Also, in any coal
crushing operation, considerable noise is generated and the pulverizing
operation should be housed in a building to minimize this effect.
           To limit dust loss, the entire coal pulverization facility
should be located in a building with positive ventilation control.  The
exhaust from the building would then be processed through a particulate
control device.
           The discharge from the oxygen plant would involve primarily
nitrogen which is not considered a harmful emission and would require no
control.
           Wet slag from the gasifier along with clarifier sludge from the
water scrubbing operation is processed through a filtration step for
liquid/solids separation.  The slag from the gasifier contains a variety
of constituents typical of coal ash but due to the high temperature in
the gasifier is relatively inert and not expected to be a pollution
problem; however, actual operating data will be necessary to verify this.
Sludge from the clarifier, however, would contain dissolved gases such as
H-S which could present an odor problem.  Lime could be added to the
clarifier circuit to fix the H~S in a nonvolatile form, or with highly
alkaline coals, the alkalinity in the slag from the gasifier may be
sufficient to alleviate the problem^ ' 6 \
           A significant discharge to the atmosphere would be the cooling
tower plume.  The cooling tower water would contain dissolved constitutents
from the scrubber circuit that overflows from the clarifier.  These con-
stituents would be present to some extent in the drift loss or plume from
the cooling tower.  Although many of these compounds may be present only
in infinitesimal amounts when combined with the water in the plume, they
may create a corrosion or health menace in the area around the plant.  A
solution to this problem is to use dry cooling towers or a cooling pond
either of which would involve much greater cooling area.

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                                     114
            About 772 kg/hr  (1704 Ib/hr) of elemental sulfur would be pro-
 duced from the Glaus  plant in this process.  This sulfur would be of
 marketable quality and could be stored and shipped.  The Glaus process,
 however, only removes about 95 percent of the sulfur compounds of the
 inlet stream.  The resulting tail gas or vent stream from the Glaus process,
 therefore, would contain hydrogen sulfide and CO--  With the system shown
 and if meeting regulations with the least direct cost were an objective, then
 this tail gas could be blended with the product gas from the gasifier and
 combusted without exceeding even the strictest state limitations on sulfur
 dioxide emissions.

Model Refinery Plant

            The major emissions from the refinery model gasification plant
are shown in Table 29.  Sources of emissions are coal storage, the gasifier
itself, scrubber effluent, and emissions from the Stretford desulfurization
process.
            Effluents from coal storage would involve similar considerations
to those discussed for the steel plant model.  Because crushed, sized coal
would be purchased from the mine, however, dust loss for the refinery would
be less than for the steel plant due to the lower percentage of fines or
small particles.  Also, air and noise pollution from drying and crushing
operations in the coal preparation step would not be present.  If these
operations were installed, similar consideration to those for the steel plant
model would have to be employed.
            About 801 kg/hr (1768 Ib/hr) of dry ash would be emitted from
the gasifier in the form of bottom ash.  The Wellman-Galusha is a "dry ash"
or nonslagging process and the bottom ash may have characteristics similar to
that from a stoker or pulverized fired boiler.  Common practice in boiler
installations is to truck or sluice the ash to pond or landfill.
            The effluent from the scrubber system contains significant amounts
of tars,  ammonia, and phenols,  which would have to be treated prior to
disposal.  In some cases these products may be able to be used in the
industrial plants or marketed.   For instance, in the case of the refinery,

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                                       115
                    TABLE 29.  DISCHARGES FROM REFINERY MODEL
                               GASIFICATION PLANT
Source
Coal storage —
fugitive dust and
leachate from rain
Scrubber effluents
Tar separation
NH, stripping
Phenols
Cyanide
Hydrocarbons
Pond
Evaporation
Discharge
Area of Main
Impact Flow Rate Composition
Solid waste Depends on wind Coal dust
and rain condi- Acids
tions Organ ics
Sol uble meta Is
Water
1 153 Ib/hr Tar
1095 Ib/hr NH3
H20
120 Ib/hr Phenols
HCN
CxHy
Air
Trace Ammon i a
Phenol s
W\/r1 r*<"»^a r*h/~mc

Percent
— —

91
9
20
80
• 100
—
—

Trace
it
Stretford
Sol id waste
(by-product)
777 Ib/hr
HCN

Sulfur
Sod i urn
Th iosuI fate
 & sodium
 Th iocyanate
100

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                                    116
the recovered tars could possibly be used to supplement residual oil in
making of asphalt.  However, this would have to be evaluated as to the
effect of these tars on the asphalt production process of the plant.  Tars
would be recovered by decantation and would result in a composition of
about 91 percent tar, and 9 percent water.  Ammonia and other compounds,
such as trace amounts of hydrogen sulfide which may be dissolved in the
scrubber water, could be steam stripped and recovered for sale.  Phenols
could also be recovered for use by use of the Phenolsolvan process, or
they could be biologically reduced to sludge and separated from the water
for disposal.  There is no inmediate use for phenols in the refinery so
biological reduction would probably be employed.  The economics of this
versus recovery of the phenols in a potentially more expensive process
would have to be evaluated further.
          In addition to tars, ammonia, and phenols, the scrubbing water
could also contain small amounts of hydrogen cyanide (HCN) and hydrogen
fluoride (HF).  Hydrogen cyanide in the water stream can be very detrimental
to a biological control process, and it may have to be treated separately.
Otherwise, it would be expected to follow hydrogen sulfide through the
process.  Hydrogen fluoride would react with the ash in the coal and be
disposed of in a neutralized form with the ash.
          Because many of the constituents in the scrubbing water are
highly volatile and odorous, care must be taken throughout the water
scrubbing and treatment system to minimize leaks and evaporation.  Reaction
vessels should be covered and vented either back to the scrubbers or to
some other control process.  Also, if the volatile and odorous constituents
are not removed from the water before being discharged to the settling
pond, odors could result from pond evaporation.
          The recovery or disposal of tars, ammonia, phenols, and other
gas liquor constituents will involve some hydrocarbon emissions.  These
emissions result from leaks around seals in pumps and storage facilities.
Refineries, in general, are accustomed to dealing with the problems
associated with handling these compounds, however, and should be able to
handle the additional load supplied by a coal gasifier.

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                                     117
            The Stretford desulfurization process for this particular
  design would produce 349 kg/hr (770 Ib/hr)  of elemental sulfur which
  could be stored and sold.  The Stretford purge stream will contain
  sodium salts of anthraquinone disulfonate,  metavanadate, citrate,
  thiosulfate, and thiocyanate.  This stream may require special treatment
  or disposal methods (40).


                 Emissions from  Combustion Processes

            Qnissions from combustion processes result generally from four
 types of pollutants; emissions of sulfur dioxide,  oxides of nitrogen,
 particulates, and trace constituents, such as polycyclic organic matter
 or heavy metals.

Emissions of  Sulfur Dioxide

          In the gasification process many sulfur compounds in the coal are
converted to sulfur compounds in the gas.  The major sulfur-bearing  consti-
tuent is hydrogen sulfide with minor amounts of carbonyl-sulfide (COS),
carbon disulfide (CS~), and mercaptans.  If these compounds are not  removed
from the fuel gas prior to combustion, they are oxidized quantitatively
to sulfur dioxide in the products of combustion.  These expected emissions,
if all the sulfur in the coal is converted to sulfur in the gas, are shown
in Figure"33 as a function of coal sulfur and heat content.
            Standards have not yet been developed specifically for dealing
with sulfur emissions from coal gasification applications as described  in
this study.  There is currently debate on whether sources fired with gas
from coal should be treated as solid fuel fired or gas fired sources and as
to whether emissions should be based on the heating value of the gas or solid
fuel.
            If emissions are based on the heat content of the coal,  then they
are a function of coal sulfur and heat content as shown in Figure 33.   As  can
be seen from Figure 33,  a coal-sulfur content of less  than 0.5 to 0.8 percent

-------
                                118
    10.0
    8.0
 m


126,
 in
 c
 o
 en
 to
    4.0
 UJ

  CJ

 O
 CO
     2.0
    0.0,
       0.0
                    J	I
                             Federal standard  for solid fuel firing
                             1.2 1
                               j	I
i.O          2.0          3.0

      Percent Sulfur in Cool
4.0
5.0
           FIGURE 33.   S02 EMISSIONS VERSUS SULFUR  IN COAL .

-------
                                    119
would be required for most ooals before compliance with the Federal New
Source Performance Standard for solid fuel fired sources of 2.16 kg S09/10
                   g                                                  ^
kcal  (1.2 Ib SO-XIO  Btu) heat input could be met without some form of
desulfurization.
            Figure 34 shows the expected emissions of sulfur dioxide from
combustion processes based on the heat and sulfur content in the fuel gas.
As can be seen, to meet the Federal standard for new sources based on solid
fuel firing, a sulfur level in the fuel gas of about 1000 ppm would be
allowable for low-energy gas with a heating value of 5.59 kJ/Nm  (150 Btu/
scf).  As the heating value of the gas increases, the allowable sulfur
content also increases.
          Many states, however, have tighter standards for SCL emissions
and it appears that the trend is for tighter standards to be promulgated.
New Mexico has established one of the strictest standards for SCL emis-
                                                     6
sions from solid fuel-fired sources — 0.61 kg SCL/IO  Kcal input  (0.34
             6
Ibs of SCL/10  Btu input).  Meeting this standard would limit the sulfur
                                                            3
concentration in fuel gas with a heating value of 5.91 MJ/Nm   (150 Btu/scf)
to 300 ppm or less.  However, New Mexico has proposed a much stricter
                          c                 g
standard of 0.07 kg S02/10  Kcal  (0.04 IbAO  Btu) for gasification plants
involved in producing SNG.  Whether this standard would also apply to
gasification plants producing lower heating value fuel gases is uncertain.
            In addition to environmental limitations on sulfur content in
the fuel gas, there are also certain process considerations in an industrial
application.  Hydrogen sulfide is known to have a high corrosion potential
in piping and distribution systems, especially when in the presence of water
vapor or oxygen.   Also, when firing the gas directly in a furnace,  sulfur
compounds in the fuel gas (such as hydrogen sulfide)  can cause problems with
sulfidation of certain kinds of products,  particularly high-grade steel
products.   Determining the maximum limit of sulfur compounds in the gas to
prevent these problems from occurring will require further definition;
however, it is possible that these requirements may be more restrictive than
environmental requirements in some cases.   A more complete discussion of the
potential deleterious effects of fuel gas contaminants on distribution systems
and products is given in Section V.

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                       120
   Federal standard for solid,-  xo>
   fuel firinq, 1.2 Ib S02/10b A°
—Bt-a—
          400
 800        1200
S in Fuel Gas, ppm
ieoo
2000
 FIGURE 34.   S02 EMISSICMS  VESSUS SULFUR IN FUEL GAS

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                                        121
               For this study a maximum sulfur concentration in the fuel gas
     of 300 ppm was established.  This limitation would allow meeting the
     Federal standard for solid fuel firing of 2.16 kg SO-/10  Kcal (1.2 Ibs
           c                                             ^
     S02/10  Btu)  based on the fuel gas heating value for both cases described
     in this study.  Additionally, it is also a reasonable lower bound on what
     can easily be achieved by atmospheric pressure, chemical-absorption type
     sulfur removal systems, such as those analyzed in this study, without
     unusually high operating cost or complex sulfur recovery processes.
               The expected emissions of sulfur compounds for both hypothetical
     industry plants studied are given in Table 30.  Emissions are given as a
     function of both the heat content of gas fired and the heat content of
     coal gasified.  In the case of the steel plant model, the disposition of
     the Glaus plant tail gas must be considered.  The tail gas, consisting
     primarily of CO2 and H2S, could be handled in several different ways.

               (1)   The tail gas could be processed through a Stretford
                    or other type of liquid phase oxidation system to
                    remove the KLS and convert it to elemental sulfur.

               (2)   The tail gas could be combined with the clean gas
                    and burned in the plant processes.
               (3)   The tail gas could be incinerated or burned in a
                    boiler.
                TABLE 30.  EXPECTED EMISSIONS OF SULFUR DIOXIDE FROM
                           COMBUSTION PROCESSES IN MODEL PLANTS

                                       Emissions, kg S02/I06 Kcal
                                    	(Ib S02/I06 Btu)	
                                    Based on Gas
                    kg S02/day      Energy Burned    Based on Coal
                   (Ib SC>2/day)     in Processes    Energy Gasified
Steel Plant
Model
1778
3869
(3925)
(8541 )
0
0
.316
.688
(0.
(0.
176)
383)
0.222
0.480
(0.
(0.
124)
267)
clean
clean
gas only
gas with
                                                                      Glaus tai I  gas
                                                                      combi ned
Refinery Model       2020 (4460)     0.359 (0.200)(a)  0.417 (0.232)
(a)  Low-energy gas plus refinery waste gas.

-------
                                    122
           Table 30 shows expected sulfur emissions for Cases (1) and (2)
 above.  Case  (1) would be considered an expensive solution but would
 minimize total atmospheric sulfur emissions.  The complexity of the plant
 would increase along with the amount of elemental sulfur that would have
 to be handled.  Case  (2) represents the simplest solution but results in
 nearly double the total atmospheric sulfur emissions.  Case (3) would
 result in the same total emissions as Case  (2) if the tail gas were
 incinerated with no sulfur controls.  If the tail gas were burned in a
 coal-fired boiler, which might be used for raising steam for operating
 the gasification plant, SCu scrubbers could be used on the boiler to
 reduce the overall sulfur emissions.

 Emissions of Oxides of Nitrogen

           This discussion is to evaluate the probable change in NO  emis-
                                                                   .X
sions that would result when changing from the combustion of natural gas to
the combustion of one of the moderate or low heating value fuels considered
in this study.  The case in which there is no fuel-bound nitrogen will be
considered first.  Then the effect of fuel-bound nitrogen, specifically in
the form of ammonia, will be considered.
           Figure 35 shows the equilibrium nitric oxide concentration as a
function of the percent theoretical air for several different air preheats
of natural gas-air mixtures.  The rapid increase of NO with air up to about
25 percent excess air, followed by a fall-off, is obvious from Figure 35.
Figure 36 shows, however, that for constant combustion temperatures, the NO
concentration tends to level off at a constant value as the percent theore-
tical air increases.  It is clear, then, that the equilibrium NO concentra-
tion increases with increase in available oxygen and with combustion tempera-
ture.  Gas composition has little effect on the curves of Figure 36 if these
two factors are used as basic values.  The largest change is to adjust the
NO concentration linearly with the N~ concentration in the stoichiometric
mixture(42).

-------
                                    123
   5000
0)
e
3
"5
E
o.
CL


0
c

-------
                                        124
            Reducing
            conditions-*
Oxidizing
   10,000
£
Q.
O.

c
o
c

-------
                                     125
         Thus, in comparing natural gas with the other fuels of concern
in this study, and assuming a constant percent theoretical air, the adiabatic
flane temperature and amount of N~ in the stoichiometric mixture are the
primary considerations for the case with no fuel-bound nitrogen.  This per-
mits the specific heating value of the fuel, the stoichiometric•fuel/air
ratio, and the air and/or fuel preheat to be neglected as considerations.
           The next factor to consider is the effect of the available
reaction time.  This is significant because the rate of production of thermal
NO is slow compared to the combustion times available or needed in most
furnaces.  This is why a maximum value of 175 ppm of NO when burning natural
gas with 15 percent excess air is reasonable, whereas the equilibrium value
is about 3000 ppm  (Figure 35).  Figure 37 shows the effect of residence time
on curves comparable with Figure 36.  These values can be compared with
current New Source Emission Standards for large boilers of 175 ppm, 230 ppm,
and 575 ppm of NO  for 15 percent excess air burning gas, oil, and coal,
                 x                                              g
respectively.  These correspond to 0.36, 0.54, and 1.26 kg NO/10  kcal
(0.2, 0.3, and 0.7 pounds of NO per 10  Btu).  It is seen from Figure 37
that at a combustion gas temperature of 1760 C (3200 F), the NO concentra-
tion only reaches 1/8 the equilibrium concentration shown in Figure 36 in
0.4 sec.  (At only 3.05 m/sec, this would be a distance of 1.22 m.)  For
2000 C  (3600 F), the ratio is about 1/10.  One may conclude then that for
flames at the same firing rate, same temperature, and same excess air,
there will be little difference in the actual concentration of thermal NO.
          A computation can now be made of the relative NO  values for dif-
ferent fuels operating under the same excess air conditions and same initial
temperature, providing no fuel-bound nitrogen  (discussed below) is present.
Four fuels are considered, a natural gas  (Table A-l), a Koppers-Totzek gas
considered as a replacement for natural gas in a secondary steel plant, and
a Wellman-Galusha gas mixed in proposed winter and summer proportions with a
refinery gas.  The equilibrium NO at the adiabatic flame temperature with 10
percent excess air is computed for each of these gases from Figure 36, cor-
recting the concentration value by the ratio of N2 in the raw mixture to that

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                               126
              Reducing conditions
  10,000
                        Oxidizing conditions
    1000
o
£
E
Q.
Q.


c"
O
c
0)
u
c
o
u


-------
                                    127
for natural gas.  The value is then further corrected  for the heating value
of the raw mixture*.  It is seen from Table 31 that the low temperature of the
refinery gas/Wellman-Galusha gas mixture reduces the NO production the most,
in spite of the high nitrogen content of the fuel.  The high heating  value of
the Koppers-Totzek gas per unit mass  of products, plus the increased  volume
ratio of fuel-to-air, more than compensates for the increased temperature of
the Koppers-Totzek gas and, thus, also results in lower NO production.  As a
result, if essentially all fuel-bound nitrogen is stripped from the moderate
and low-heating value gases, these gases will give lower NO output than natural
gas under similar firing conditions.
         TABLE 31.  RELATIVE NO PRODUCTION FROM THERMAL FIXATION
                    OF VARIOUS FUELS AT 10 PERCENT EXCESS AIR
                                                                Relative
   	Fuel	NOX Production
   Natural gas                                                    1.00
   Koppers-Totzek                                                0.93
   Wei I man-Galusha, winter mix with refinery gas                 0.72
   We IIman-GaIusha, summer mix with refinery gas                 0.74
          Nitrogen bound in various fuel constituents  (primarily NH_ for gas
from coal) does not convert to NO  by the same process as thermal fixation
                                 ^C
of elemental nitrogen.  In the case of fuel-bound nitrogen, temperature and
time are of little importance.  The two major factors are stoichiometry (or
percent excess air) which determines the amount of oxidant available, and the
concentration of nitrogen compounds in the fuel.
 *As  an example,  the Koppers-Totzek gas may be compared with natural  gas.   The
  adiabatic flame temperatures with 10 percent excess air are 2190  K  and 2140  K.
  From a cross-plot of Figure 36,  the concentration of NO is 3400 and 3000  ppm,
  respectively/  The raw mixtures  have 63.0 and 75.3 percent N2, respectively?
  using the ratio, the value of  3400 is corrected "to 2845.   The heating value  of
  the raw mixtures are 1098 and  1074 Btu/lb,  respectively;  correcting to a
  common heat input, 2845 ppm of NO becomes 2783 ppm of NO.   The ratio of this
  value to 3000,  which is 0.928, is the NOx production of the Koppers-Totzek
  mixture relative to natural gas.

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                                  128
          Ihe effect of stoichiometry on conversion of NEL to NO  in a
                                                         •j      X
methane flame is shown in Figure 38.  These data are for a premixed flame
where fuel and oxidant are thoroughly mixed prior to burning.  In nozzle
mix-type burners, which are more common in industry than premix burners, the
stoichiometry in the flame is primarily a function of the mixing rate be-
tween the fuel gas and combustion air.  In these cases the amount of combustion
air would have only a minor effect on NO  conversion.
                                        X
          Ihe major effect of fuel-bound nitrogen conversion to NO  in nozzle
                                                                  X      (43)
mix-type burners is nitrogen concentration in  the fuel.  Turner, at al.,
have shown that the form in which the nitrogen is bound in the fuel has no
                              *
effect on nitrogen conversion.   Figure 39 shows the conversion  of fuel-bound
nitrogen to NO  in a Rankine-cycle can-type combustor using a liquid fuel with
              X
pyridine as the nitrogen carrying additive.  The data for the curve in Figure
39 represent a wide range of excess airs of from 120 to 175 percent of theoretical
air and indicate that, within this range of excess air levels, excess air has
little or no effect on nitrogen conversion.
          Figure 40 shows a compilation by Dykema and Hall     of utility
boiler data over a wide range of nitrogen concentrations of the mass fraction
of fuel-bound nitrogen converted to NO .  The curve of Figure 38 and correspondmg
                                      X
data of Hazard (Figure 39) are added.  While the scatter of the data is large,
it must be realized the there is an arbitraryness in accounting for the amount
of thermal nitrogen to be deducted from the total; the higher fraction mass
conversion calculation is particularly sensitive to this effect.  Nevertheless,
the trend of the data is obvious.
          Data on fuel-bound nitrogen, which predominantly consists of NH-,
in fuel gas from coal is limited.  Table 32 illustrates some typical ammonia
concentrations in raw uncleaned gas from various types of coal gasification
processes.  In cold gas desulfurization processes, much of this ammonia (at
least 90 percent) would be removed in the water scrubbing step preceding de-
sulfurization, as long as the scrubbing water is continuously stripped of
absorbed ammonia.  Additional ammonia may be removed in the desulfurization step
depending on the sorbents used.
*
 This analysis involved liquid fuels with eight different nitrogen containing
 additives.

-------
    1.0
 x
O
z

o 0.8

 ro
I
Z
>4—
O
c 0.6
                                         129
OJ
>
c
o
O 0.4

"o
o
u
o
   0.2
   O.O1
      0.7
0.8       0.9         1.0       I.I        1.2        13

        Air/Fuel  Ratio Relative to Stoichiometric
1.4
       FIGURE 38.   FRACTIONAL CONVERSION OF NH-. IN PRFMIXED METHANF-AIR
                             (44)
        NH3  equivalent to 1200  ppm  NO and air consisting  of oxygen-
        hefium mixture.

-------
                                      130
V)

o
5

»  0.004

if
o>
>
jg
o>
o:

ox
c
u>
a
0.003
    0.002
c

=  0.001
o
o
    0.000

      0.000
                                1
                                        1
               0.001        0.002       0.003       0.004

                     Mass Fraction  of  Nitrogen in  Fuel
0.005
       FIGURE 39.   FUEL NITROGEN IN LIQUID FUEL-PIKED RANKINE-

                    CYCLE GQMBOSTOR CONVERTED TO NO *C44)
       *Usina pyridine  as  the  nitrogen  source  and using ASTM

        Jet A combustor.   Tests  covered from 120 to  175 percent
        theoretical air.

-------
 X
O
TD
0>
c
O
O
c

-------
                                       L32
                TABLE 32.  TYPICAL AMMONIA CONCENTRATIONS IN RAW
                           UNCLEANED FUEL GAS FROM COAL

Ammon i a
Gasif ier
Vo 1 ume
Percent
Ib/lb fuel
x I03
MJ/Nm3
(Btu/scf)
Reference
Koppers-Totzek
  single stage          0.17        1.13
  entrained slagging
  (CL blown)

  two-stage entrained   0.38       2.53
  slagging (ai r blown)

Lurgi
  pressurized           0.70       4.66
  fixed-bed
11.3     (286)
 4.9      (125)
12.7      (323)
46
47
48
(02 blown)
atmospheric
fixed bed
(air b-lown )
0.25 1.46 5.5 (139) 47

          Table 33 shows expected emissions of NO  (in lb/10  Btu of heat input)
for the ammonia concentrations shown in Table 32 using the curve of Dykema and
Hall from Figure 40.  Values are given for both the raw gas and assuming 90
percent ammonia removal.  In addition, Table 33 gives estimated emissions due
to thermal fixation of N_ assuming a thermal contribution of 100 ppm NO in the
flue gas on stoichiometric mixture.  Total expected NO emissions from both
thermal fixation and oxidation of fuel-bound nitrogen assuming 90 percent NH-,
removal are also given.

-------
                                     133
                    TABLE  33.  ESTIMATED EMISSIONS FROM
                               RAW AND CLEANED FUEL GASES
                       	NO  Emissions,  Kg/106  Kcal  (Ib/IQ6  Btu)
                        Due  to NH,  in  Gas
                                   3] I I  UOij      -r-i     ,  . ._
                     	Thermal  NO  Assuming   Total  NO  With
                                Assuming yu*   100  ppm  NO  in  Stoi-   90  Percent  NH,
   Gasitier          Raw Gas   Removal of NH3 chiometric  Mixture    Removal

Koppers-Totzek
  single-stage en- 0.79 (0.44)   0.08  (0.047)     0.15  (0.086)     0.24   (0.133)
  trained slagging
  two-stage en-    2.63 (1.46)   0.47  (0.259)     0.22  (0.120)     0.68   (0.379)
  trained slagging
Lurgi pressurized  |J3 (0.63)   0.3!   (0.171)     0.16  (0.092)      0.47  (0.263)
 fixed bed
Atmospheric        2.09 (1.16)   0.25  (0.141)     0.20  (0.112)      0.45  (0.253)
 fixed bed
          For the raw gas expected emissions of NO from oxidation of fuel-bound
nitrogen alone would exceed the Federal standard of 1.26 Kg NO/10  kcal  (0.7
Ib NO/10  Btu) for coal-fired systems in two cases and would exceed the standard
for gas-fired systems of 0.36 Kg NO/106 kcal  (0.2 Ib NO/106 Btu) in all cases.
With 90 percent removal of NH., the expected NO emissions including the assumed
contribution from thermal fixation  would be less than the coal standard of
1.26 Kg NO/10  kcal (0.7 Ib NO/10  Btu) in all cases and would approach the gas
standard in most cases.
          In both industry systems considered in this study, NH~ is assumed
to be entirely removed in the combination of water scrubbing and amine or
Stretford desulfurization.  Emissions of NO would, therefore, consist primarily
of those from thermal fixation of elemental nitrogen.  Under these circumstances
NO emissions overall would decrease relative to those with natural gas as was
shown in Table 31.

-------
                                    134

Particulate Emissions

          Particulate content in the final clean product gas from both of
the gasification plant models is negligible.  Combustion of this gas,  there-
fore, would be expected to result in negligible particulate emissions  to the
atmosphere and no particulate control would be required.  In both model plant
cases the low-energy gas would be replacing the firing of some heavy oil which
would result in an overall decrease in particulate emissions from these two
industries.

Emissions  of Trace  Constitutents

          Emissions of trace organic constituents such as polycyclic organic
matter  (POM) are a function of the number of long chain hydrocarbons or
ring-type-hydrocarbons in the fuel itself and of the combustion conditions.
Coal and oil both contain significant quantities of these compounds.   However,
the product gas from gasification, should contain few, if any, long chain or
ring-type hydrocarbon components.  Combustion conditions for firing the fuel
gas would be similar to those for firing natural gas.   Thus, emissions of
these types of materials would be expected to be similar to that of natural
gas.  They would be significantly less than if the coal were fired directly
or if oil were used directly as the fuel.
         Other trace constituents, such as trace metals that may be vaporized
in the combustion process, are also potential pollutants.   The more volatile
metals  (mercury,  etc.)  would be vaporized in the gasification process  but should
be condensed in the water scrubber and cooling sections of the gas-cleaning
processes.  The ultimate fate of these constituents must still be determined
in order to assess the true environmental impact.

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                                    135
                VII. POTENTIAL IMPACT  OF ADVANCED
                     HOT GAS  CLEANING  SYSTEMS

          All fuel gas desulfurization systems that are applicable to
cleaning gas from coal and have been proven commercially successful are
at gas temperatures of less than 250 F.  The two processes used in this
study, the MDEA and Stretford systems, operate at temperatures of ambient
or slightly above.  The r<^« fuel gas from a gasifier, however, contains
significant amounts of sensible heat which could represent from 10 to 20
percent of the energy in the raw gas, depending on the process and the raw
gas temperature.  There has been considerable emphasis on developing fuel
gas desulfurization processes capable of cleaning fuel gas at elevated
temperatures.  This would allow the gas to be fired hot, thus, conserving
the sensible heat and increasing the overall thermal efficiency.   This
concept has obvious merit, especially for power plant applications where
the hot gas needs only to be piped a short distance to the point of com-
bustion-.  However, different considerations are necessary for industrial
plants.  Therefore, an evaluation was made of the relative advantages and
disadvantages such systems might nave in an industrial situation.
          Table 34 lists the leading hot-gas desulfurization systems under
development.  These processes can generally be classed as those using fully
calcined dolomite of half-calcined dolomite (Consolidation Coal and Air
Products and Chemicals), those using iron oxide (Bureau of Mines and Babcock
& Wilcox), and those using molten salt baths (Battelle-Nbrthwest).
          The dolomite processes operate at the highest temperatures [from
about 815 to 1100 C (1500 to 2000 F)] and regeneration yields an H2S-rich
gas suitable as a Claus feed.  Regeneration of these processes is accomplished
with steam and C02 according to the following reaction:

                CaS-MgO + H20 + C02  -»•  CaCCyMgO + H2S.

This reaction is for the Consolidation Coal half-calcined dolomite process.
The Air Products and Chemicals full-calcined dolomite process has been
abandoned due to poor sorbent regenerability ^ 5 0 )^

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                                          136
                   TABLE 34.  ADVANCED HIGH-TEMPERATURE CLEANING
                              SYSTEMS UNDER DEVELOPMENT
Process Sorbent
Consolidation CaCO,'MgO
Coal* 3
Air Products CaO-MgO
and Chemicals
Bureau of Mines Fe~0, + fly ash
Babcock & Wi Icox ^e9^3
Battel le-Northwest NaCOj + CaC03
Temperature, C (F)
816-982 (
87I-I093C
423-816 (
371-649 (
593-923(1
1500-1800)
1600-2000)
800-1500)
700-1200)
100-1700)
Su 1 fur
Form Status
H2S Pilot
hLS Abandoned
S02 Pilot
SCU Experimental
H2S Pilot
*Conoco Coal Development Corporation
               Processes using iron oxide as a sulfur sorbent operate at tempera-
     tures of about 370 to 815 C  (700 to 1500 F).  The sorbent is regenerated with
     air yielding an SC^-rich gas stream by the following reaction:
                        2FeS + 3-1/2
2S0
     The SO- can then be reduced to elemental sulfur, converted to sulfuric acid,
     or converted to CaSO, with lime or limestone scrubbing.
               The molten salt process operates at temperatures of from 593 to
     923 C  (1100 to 1700 F) and absorb sulfur compounds in a molten solution of
     NaCO., srcd CaCCs.  The sorbent is regenerated with steam and CCu yielding an
     H?S rich gas stream suitable for feed to a Claus sulfur recovery unit.
               At the present time, none of the hot gas cleanup systems discussed
     are commercially available.  At present, all are in the pilot stage of
     development with the exception of Babcock & Wilcox, which is experimental,
     and Air Products, which has been abandoned.  The time scale for commerciali-
     zation of these systems is uncertain, but it would be unlikely that any would
     be commercially available before 1980.

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                                    137
          In general, hot gas cleanup processes are not expected to be as
flexible as cold liquid scrubbing processes in achieving low-sulfur levels
(below 100 ppm) in the product gas^48).  This could cause a problem in some
industrial situations where very low sulfur levels are necessary to minimize
corrosion in gas distribution systems and minimize effects on products in
direct-fired furnaces.  In this study a sulfur level of 300 ppm was assumed
adequate for both environmental, piping, and product degradation purposes.
After actual trial or new standards, however, it may be determined that a
lower sulfur level would be desired.  Under these circumstances, a cold
liquid scrubbing system would be more flexible in being able to achieve a
lower sulfur level.
          None of the hot-gas cleaning systems discussed is capable of
removing armonia and only one, the Battelle-Northwest molten salt, is
capable of removing particulates; however, even this process would require
filtration of the molten salt, which is a difficult problem yet to be solved.
In cold gas liquid scrubbing processes, ammonia and particulates are reduced
to low levels in the gas by the water scrubbing steps preceding desulfuriza-
tion.
          The anroonia compounds, if left in the gas, could lead to
unacceptably high NO  emissions for some gasification processes due to
                    J^
oxidation of fuel bound nitrogen (see Table 33 in Section VI).  Also, ammonia
compounds could lead to higher corrosion rates in piping (see Section V).
At present, no processes are available for removing aimionia compounds along
with sulfur from hot fuel gas.
          Also, a hot fuel gas would result in a higher flame temperature
than would a cold fuel gas which would increase the production of thermally
produced NO  .  Figure 41 shows the effect of fuel temperature on flame
           J^
temperature.  Flame temperature could be reduced by dilution with excess
combustion air; however, this would reduce thermal efficiency by increasing
stack losses—defeating the purpose of a hot fuel gas.
          Data on particulate loading in raw fuel gas are very limited, but,
depending on the process, particulate content can be high.   Fixed-bed gasi-
fiers would tend to be lowest due to their large coal size and low flow
velocities.  The Winkler fluidized-bed gasifier reportedly carries from
50 to 75 percent of the ash in the coal over with the raw gas (5 (I  The

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                                   138
Koppers-Totzek entrained slagging process results in about 50 percent of
the ash in the coal being carried over with the raw gas with the remaining
dropping out as slag.  For one case, Hoppers indicates particulate loading
in the raw gas of 26 g/Kfcn3  (11.57 grain/scf )< 47>.
         • Particulate removal devices capable of operating on hot-fuel gas
at temperatures similar to those of hot-gas desulfurization systems are not
well developed.  Electrostatic precipitators have been used successfully at
temperatures of 255 to 590 C  (500 to 1000 F) in the utility industry for
controlling fly-ash emissions.  Laboratory tests have been conducted on hot
precipitators with gas temperatures up to 815 C (1500 F) with removal effici-
encies of 90 to 98 percent; however, long-term continuous operation was not
             (52)
demonstrated    .A novel granular bed filter has been developed with removal
efficiencies of greater than 90 percent on particles down to 2 micrometers   '.
Other processes such as cyclones and ceramic filters have also been developed
for removing particulates from high temperature gases.  Plugging and fouling
from tar compounds could be a problem in all high temperature particulate
removal systems when operating on raw fuel gas from coal.  High temperature
corrosion from acid gases such as H-S is also a potential problem.
          In cold gas liquid scrubbing desulfurization systems, particulates
are removed in the water scrubbing steps preceding desulfurization.  These
liquid scrubbing systems can be highly efficient in removing particulates to
very low levels in the gas stream.  Koppers reports that, for an inlet
                        3                                                   3
grain loading of 26 g/ton  (11.57 grain/scf), an outlet loading of 0.004 g/!S&n
(0.002 grain/scf) is achieved with a two-stage venturi scrubber^^ .  This
represents a removal efficiency of greater than 99.9 percent.  It is doubtful
that a high temperature particulate removal device could be as efficient as
cold gas scrubbing.  In an industrial situation, where few furnaces would
have particulate control devices, the lower particulate removal efficiency
would be a drawback of hot desulfurization systems.
          With cold gas cleaning systems, waste-heat boilers can be used to
recover heat in the raw gas by generating steam.  This steam could be used
in the industrial plant, for driving pumps and turbines in the gasification
plant, or for sorbent regeneration in the cold-desulfurization system.  Using
waste heat in this manner minimizes the differences in thermal efficiency

-------
                                       139
                       REFERENCE FUEL HHV = 120 BTU/SCF

                      REFERENCE FUEL TEMPERATURE = 80F

                        STOICHIOMETRIC FUEL-AIR RATIO

                         INITIAL AIR TEMPERATURE = 82SF
  4800
   4600
01
tr

P  4400
cc
LU
0.
5
LU
I-

2
O
C  4200
CO

O
0
O
t-
<
co  4000
<

Q
   3800
   3600
                         INCREASE FUEL

                         TEMPERATURE
                                                 INCREASE FUELHHV
                                  I
       100
                    120          140          160          180


                     FUEL CHEMICAL PLUS SENSIBLE HEAT-BTU/SCF
                                                                         200
       FIGURE 41.  EFFECT OF FUEL GAS CHEMICAL AND SENSIBLE  HEAT ON

                    COMBUSTION TEMPERATURE

-------
                                   140
between hot and cold gas processes.  Three of the five hot gas desulfurization
processes shown in Table 34  (the two dolomite-based processes and the molten
salt process) also require steam for sorbent regeneration.  The other two,
both iron oxide systems, use air and, as a result, yield sulfur as SCL which
is more difficult than H2S to convert to a usable or easily handled form.
Thus, differences in overall efficiency between hot and cold systems can be
minimized with waste heat recovery.
          Probably the biggest drawback of hot gas cleaning systems for
industrial applications is the necessity for distributing the hot gas in
extensive and intricate gas distribution systems often necessary in an
industrial plant with a large number of furnaces.  As can be seen from
Figure 42, a gas temperature of from 705 to 815 C (1300 to 1500 F) would
require distribution of three to four times the volume of gas that would
be required at 21 C (70 F).  In addition, the higher temperatures would
increase piping degradation due to corrosion and high stress.
          In summary, the availability of a hot gas desulfurization system
is not felt to be especially attractive in the industrial situations
reviewed here.  The inability to remove ammonia combined with higher flame
temperatures would result in increased emissions of NO .  Problems with
                                                      X
high temperature particulate removal would also result in increased
pollution potential of hot systems over cold systems and, combined with
an inability to achieve very low sulfur levels in the product gas, may
make hot systems inappropriate in some industrial situations.  Also,
distribution of a hot gas would magnify corrosion and stress problems in
piping and would require larger diameter pipes with the addition of insula-
tion.  With waste-heat recovery the difference in efficiency between hot
and cold gas systems is reduced (less than 5 percent overall difference in
most cases), which would minimize the potential advantage of a hot gas
system.

-------
Volume
Ratio,
                                    500
1000
                                                                                                   1500
                                               Fuel Gas Tenperature, F
                      FIGURE 42.   RELATIVE VOLUME OF FUEL GAS REQUIRED AT DIFFERENT
                                  FUEL GAS TEMPERATURES FOR V-^70 F

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                                      142
          VIII.   THE EFFECT  OF AVAILABILITY OF  ALTERNATE
                  CLEAN  FUELS  FROM  COAL ON  INDUSTRIAL  DEMAND
                  FOR LOW- AND INTERMEDIATE-ENERGY GAS
            A variety of advanced processes currently are under development
 for manufacturing clean synthetic fuels from coal.  These processes  are
 generally more sophisticated than existing commercial units and are  intended
 to operate more efficiently, economically, and on a larger scale.  In
 addition, many of these processes are capable of producing higher grade
 fuels than low- or intermediate-energy gas.
            Table 35 lists  those processes currently under development by
 ERDA for manufacturing substitute natural gas (SNG) from coal.   SNG, which
 has a heating value of about 39.4 MJ/Mn   (1000 Btu/scf), is made by
 methanating synthesis or intermediate-energy gas by reacting CO and  EL, over
 a nickel catalyst to yield CH..  The source of the intermediate-energy gas
 can be most any oxygen-blown gasification process, but the advanced  processes
 under development and shown  in Table 35 are intended to maximize the yield of
 methane in the gasifier to minimize the amount of methanation required.  None
 of the processes shown in  Table 35 are expected to be of commercial  scale
 before 1980.  A variety of first generation commercial SNG plants are being
 planned, however, based on current technology.  Table 36 lists SNG projects
 that are currently in advanced stages of planning or awaiting government
 approvals.
            Substitute natural gas from coal is expected to have properties
 very similar to natural gas  and from a combustion standpoint be directly
 substitutable for natural  gas with only minor burner adjustments.  Table 37
 shows compositions of several natural gases compared to several reported SNG
 compositions from coal,  one  from oil, and a sample LNG (liquefied natural
 gas).
              Replacement of  Natural Gas  by Liquified
               Natural  Gas or Synthetic Natural Gas

            It is seen that the normal range of natural gases (even a wider
range could be found) brackets the three synthetic gases produced fron coal in

-------
                                     TABLE 35.   HIGH-B1U GASIFICATION PROGRAM
                                                                             (53)
   Major Projects
 Contract Value
$M (Cost Share)
   Contractor
   Location
       Key Events
•  CCL Acceptor
   Process
    26.8
    (6.6)
Conoco Coal Dev.  Rapid City, S.D.
Co.
                   Methanation plant con-
                   struction, complete
                   FY 75
•  Hygas Process
    18.5
    (2.0)
Institute of Gas  Chicago,  III
Technology
                   Steam oxygen system
                   construction, complete
                   FY 75
    Steam-Iron           18.2
    Process              (7.9)
   Ash-Agglomerating      8.9
   Process               (1.7)
                    Institute of Gas  Chicago, I
                    Technology
                                     Complete pilot plant
                                     construction FY 75
                    Battelle-Columbus West Jefferson,    Complete pilot plant
                                      Ohio               construction FY 75
                                                                                                                CO
•  Bi Gas
    66.0
   ( 10.0)
Bituminous Coal
Research
Homer City, Pa.
Complete pilot plant
construction FY 75
   Synthane
    19.0
Rust
Engineering/
Lumus Corp.
Perc

Bruceton, Pa.
Complete construction
FY 75

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                                     144
             TABLE 36.  SNG PLANTS IN ADVANCED STAGES OF PLANNING
                                                                  (54)
                                         g
    Developer	Plant Capacity  (10  Btu/day)    Expected  Starting  Date
American Natura
 Gas Company
Cities Service Gas
 Co. and Northern
 Natural Gas Company

E! Paso Natural Gas
 Company
Natrual Gas Pi peline
 Company

Panhandle Eastern
 Pi peline Company
 and Peabody Coal

Texas Eastern Trans-
 mission Corp.
 (WESCO)

Texas Gas Trans-
 mission Company
1000 x  I09 Btu/IO9 Btu/day
4-250 x  I09 Btu/day trains
1000 x  10  Btu/day
4-250 x  10  Btu/day trains
785 x 10  Btu/day
1000 x 10  Btu/day
4-250 x I09 Btu/day trains

270 x I09 Btu/day
1000 x 10  Btu/day
4-250 x I09 Btu/day trains
250 x 10  Btu/day
First train-1981, sub-
sequent trains at 4-
year intervals

Currently under study
1980 - first 230 x 10
Btu/day plant pending
FPC approval

First train-1982, sub-
sequent trains at 3-year
intervaIs

1981
1980 - first 250 x 10'
Btu/day train pending
FPC approval

1983

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TABLE 37.  COMPOSITION AND PROPERTIES OF SOME NATURAL GASES, LNG, AND SNG
Composition
or Property
CH4
C2H6
C3H8
Other HC
co2
CO
N2
H2
HHV, Btu/ft3
S.G.
Stoich. A/F
Wobbe No.
Natura 1
Gas
No. 1
94.9
3. 1
0.3
0. 1
1 .1
0.0
0.5
0.0
1029
0.588
9.70
1342
Natura 1
Gas
No. 2
90.2
3.7
0.6
0.2
0.8
0.0
4.5
0.0
1009
0.609
9.42
1281
Natura 1
Gas
No. 3
72.8
6.4
2.9
0.6
0.2
0.0
17. 1
0.0
945
0.695
8.90
1 133
LNG
86.3
9.0
3.2
1 .3
0.0
0.0
0.2
0.0
1 162
0.952
10.89
1440
SNG
( f rom o i 1
69.5
15.0
0.4
0.0
0.3
0.0
0.3
14.5
1027
0.541
9.52
1394
SNG
(COED)
88.9
0.0
0.0
0.0
2.9
0. 1
1 .6
6.5
921
0.558
8.63
1233
SNG
( Lurgi )
95.8
0.0
0.0
0.0
2.0
0. t
1 .4
0.7
872
0.577
9. 15
1280
SNG
(Biqas)
91 .8
0.0
0.0
0.0
1 . 1
0. 1
1.9
5. 1
946
0.549
8.87
1277
                                                                                             Cn

-------
                                      146
respect to Wobbe number, and almost brackets them in respect to the heating
value.  Thus, one would expect that only minor adjustments would be needed on
the control system  (5 percent change in Wobbe number is usually assumed to
be tolerable without adjustment) to switch to one of these synthetic fuels.
            In the  case of LNG, an adjustment will certainly be required,
resulting from the  high ethane content in the fuel.  However, the stability
limits of the flame are not changed significantly.
            A high  hydrogen synthetic fuel made from oil is also shown.  While
the Wobbe number is not as high as that of ING, the high hydrogen content
results in about a  40 percent increased value of the flashback velocity
gradient.  Thus, there is a possibility with such a fuel as this that pre-
mixed burners might have to have their burner faces changed.  In precision
heat treating, glass forming, and similar operations, the change in flame
shape may also result in a need for adjustment when switching to a high
hydrogen fuel such  as indicated here.
            Processes are also currently under development for producing clean
liquid fuels from coal by processes termed liquefaction.  Unlike gasification,
which is an old basic technology, liquefaction is a relatively new technology.
Liquefaction of coal was accomplished by the Germans in the 1930's and 1940's
using gasification  in combination with Fischer Tropsch synthesis, which combines
CO and ^ into higher hydrocarbons from about C2 through Cg.  These lightweight
liquid fuels are currently being produced in a large gasification/liquefaction
plant in Sasolburg, South Africa, using this type of technology.  This tech-
nology is generally considered too expensive and inefficient for use in the
U.S. today, and so  ERDA is funding development of processes for directly
hydrogenating solid coal producing a heavy liquid fuel similar to a No. 6
residual oil.  Table 38 lists the processes currently being developed to
accomplish this.
            Another possibly attractive liquid fuel from coal is methanol
which is made through gasification in a process very similar to that used for
producing SNG (using a copper catalyst instead of a nickel catalyst).  The
technology for producing methanol from coal is available; however, no
commercial plans are known at this time.

-------
TABLE 38.  COAL LIQUEFACTION
                            (52)

Major Projects
• Coa 1 -Oi 1 Energy
Development (COED)
• Solvent Refined Coal
(SRC)
• H-coa 1
• Clean Coke
• Synthoi 1
Contract
$M (Cost
21 .
41 .
3.
(2.
1 I.
(2.
(1.
Value
Share) „ , ,
Contractor
0 FMC
0 PAMCO
0 HRI
7)
5 U.S. Steel
9)
1 ) Foster Wheeler
Location
Princeton, N.J.
Tacoma, Wash.
Trenton, N.J.
Cattelsburg, Ky.
Monroevi Me, Pa.
Perc
Key Events
Pi lot operations
comp 1 ete FY 75
Pi lot operations
started mid FY 75
PDU runs FY 75
pilot-plant decision
mid FY 75
PDU complete FY 77
pi lot p lant deci si on
FY 77
RFP for construction
June . 75

-------
                                    143
             Table 39 lists  some pertinent properties of several grades of oil
 along with liquified coal,  methanol, and shale oil for comparison.  When using
 a liquid fuel as  a replacement for natural gas, several considerations are
 necessary.

             Replacement of  Natural Gas  by Liquid  Fuels

             In industrial heating boilers and other types of heat exchangers,
 and in many other industrial applications  (note number of dual-fuel burners
 under secondary steel industry discussed earlier), dual-fuel burners are com-
 monly used which  allow natural gas and various grades of oil to be burned
 simultaneously.   These typically  burn  No. 2 and/or No. 6 fuel oil; in the
 latter case,  provision must be made for  heating the fuel slightly to be able
 to pump and atomize it.   It is clear that all the fuels listed in Table 6
 except methanol have similar heating values.  Thus, if their viscosity is
 in the proper range (by preheating, if necessary), the fuel nozzle should
-perform properly  at design  capacity.   The low heating value of methanol
 indicates that a  new nozzle would be required to obtain a higher flow rate.
 The Bureau of Mines'  hydrodesulfurized oil (Snythoil) and the shale oil could
 be treated as No.  6 oil.  It would require preheating by a sufficient amount
 to be pumped.   COED oil which  is  a product of pyrolysis or gasification falls
 between No.  2 and No.  4 fuel oil  in viscosity, and might require no preheating
 or only mild preheating,  depending on  other circumstances.  Methanol requires
 no preheating,  but its low  viscosity may result in insufficient pump lubri-
 cation;  thus,  a new pumping system might be required as well as new nozzles.
             In regard to  radiation, all the fuels except methanol would be
 expected to be highly radiant; those derived from coal would probably be
 more radiant and might require some dirtying of heat exchanger surfaces (say,
 by adding magnesium oxide to the  fuel) to obtain the proper radiation/convec-
 tion balance.   In  the case  of  boilers, some change might be necessary in super-
 heater controls.   Methanol would  perform similarly to a somewhat cooled
 natural gas  flame,  with low radiant input.

-------
                           TABLE 39.  PROPERTIES OF VARIOUS UOUID FUELS

No. 1 No. 2
Fuel Fuel Oi 1 Fuel Oi 1
HHV, Btu/lb 19,600 19,400
Kinematic viscosity,
mm2, at 100 F 1 .4-2.2 2.0-3.6
at 122 F
No. 6
Fuel Oi 1
18,300-
18,700

92-638
Bureau of
COED Mines(a) Shale Oi 1
19,000 17,700 18,000
5.5
300-500 30
Methanol
9,776
0.6


(a)  Bureau  of  Mines'  hydrodesulfurized  oil  (Synthoil).

-------
                                  150
          In furnaces where dual-fuel burners are not in use, the installa-
tion either of such units or of separate liquid fuel burners could be in
order.  The considerations would be much the same as outlined above, except
that the fuel heating system, pumps, and burner could be designed specifi-
cally for the fuel.  Since, in these instances, it would not be known,
a priori, that the change in radiation would have no detrimental effect,
this factor would have to be verified.
          In some instances, the flame shape is important, and care would
have to be taken to ensure a similar shape.  Difficulties could be expected
with tunnel burners or radiant tube burners; No. 6 fuel oil and similar
fuels would not be acceptable in these instances on the basis of presently
available burners.  Premix burners cannot be replaced directly by fuel oil
burners, and alternative burner designs and furnace configurations might be
required.
          The third alternative is to use a prevaporizer.  Liquid fuel is
burned on the combustion side of a heat exchanger to heat the main air
stream to, say, 370 C (700 F).  Liquid fuel is then sprayed into the hot
gas and vaporized, and the mixture can be substituted for premixed natural
gas and air with minor changes.  Systems are commercially available for
vaporizing No. 1 and No. 2 fuel oils.  It should be noted that methanol
will reach a stoichiometric mixture at only 18 C (67 F)  mixture temperature,
and the fuel rich limit at 40 C (105 F).  Air at about 205 C (400 F) would
vaporize the methanol to a stoichiometric mixture.
          Liquid fuels for the industrial uses studied can be used to
completely replace natural gas, provided that at least some fuel with
vaporization properties similar to or better than No. 2 fuel oil is
available for situations where a gaseous fuel is essential.  Also liquid
fuels can be stored indefinitely and used when needed, which is an at-
tractive characteristic in industries where fuel demand varies widely from
day to day.  In all instances but those in which dual-fuel burners are now
used successfully, checks would have to be made on the radiation properties.
For methanol, because of low viscosity, it might be necessary to change
pumps and burner nozzles.
         The gasified and liquefied products discussed in this section as
alternatives to low- and intermediate-energy gas have attractive features

-------
                                  151
for industry.  SMG could essentially be substituted directly for natural
gas in practically all industries with almost no foreseeable modifications.
Most industries would be willing to pay a somewhat higher price for this  fuel
over low- or intermediate-energy gas depending on the degree of modification
that would be necessary in processing operations.  Liquefied coal  (No.  6  oil)
or methanol could also easily be used in many industries although modifications
such as addition or replacement of burners along with installation of heated
lines would be necessary.  In many industries, however, equipment has already
been installed for using No. 6 oil and some operating experience has been
gained with its use.  In these cases use of liquefied coal would be attractive.
          However, the most important factors in determining the potential for
use of alternate clean fuels from coal instead of low- or intermediate-energy
gas are supply and cost.  If all the SNG plants listed in Table 35 were con-
structed and operated at 100 percent load factor, they would supply about 2.0 x
  12             15
10   MJ (1.9 x 10   Btu) per year of gaseous energy.  In 1972 industry used
about 11 x 10   MJ (10.4 x 10   Btu) of natural gas and an additional 58  x 10
           9                                                              12
MJ (55 x 10  Btu) of oil in supplying its energy requirement of 24.4 x 10  MJ
(23.1 x 10   Btu)   .  The total U.S. demand for natural gas in 1972 was  24.4 x
1012 MJ (23.1 x 1015 Btu) and for oil 34.8 x 1012 MJ (33 x 1015 Btu)(2).
Construction plans and schedules for SNG plants have consistently fallen  be-
hind, and today it seems certain that no commercial SNG plants will be in
operation by 1980 and only a few by 1985.  A total of 176 sites have been
identified capable of supporting a 264 x 10  MJ (250 x 10  Btu) per day SMG
                  (54)
plant for 34 years    .  If all 176 sites were developed and operated at
                                               12            15
full capacity, they would produce about 17 x 10   MJ (16 x 10   Btu)  per
                                                                 12
year of SNG.  It would be highly unlikely that more than 5.3 x 10   MJ
(5 x 10   Btu) per year of SNG could be produced by the year 2000 which would
                                                                     12
be less than half the 1972 industry demand and less than the 7.7 x 10   MJ
(7.3 x 10   Btu)  used by the household and commercial sector in 1972

-------
                                   152
 It would be a good assumption,  therefore,  that SNG or any natural  gas
 equivalent will be reserved for high priority uses in the future and will
 not be of any higher availability to industry than natural gas currently is.
            At present,  no commercial coal  liquefaction plants have been
 planned,  and only one significant sized demonstration plant  is scheduled for
 construction (to be built in New Athens, Illinois, by Coalcon) producing
 6.2 x 105 liters/day (3900 barrels/day)  of oil (or approximately 24.3 x 10  MJ
 per day [23 x 109 Btu/day])  and about 23.2 x 106 MJ/day  (22  x 109  Btu/day)
 of SNG.  This plant is  not scheduled for operation until the early 1980's.
            ERDA's current plans call for the production  of about 9.5 x
   12                15
 10   MJ/year (9 x 10   Btu/year)  of SNG and  liquefied coal products  by  the
          (2)
 year 2000   .   This would be equivalent to about 16 percent  of our 1972 use
 of natural gas and oil  of 59.2  x 1012 MJ (56.1 x 1015 Btu).
            Even if the  goal of  9.5 x 1012  MJ/year  (9  x 1015  Btu/year) of
 these fuels is attained,  which  would require a significantly accelerated
 pace over that of today,  it would be unlikely that these fuels would be
 available to industry despite their relative ease  of  application.  Rather,
 they would be reserved  for high priority uses such as home heating,  trans-
 portation,  and chemical feedstocks.
          Also,  significant  engineering and  development  efforts will be re-
 quired to perfect the processes for manufacturing  higher grade alternate fuels
 from coal.   This,  combined with the greater  complexity reouired in processina
 operations,  including the necessity for high pressure  operation, in many cases
will  probably result in significantly higher production  costs for these fuels
compared  to those of low- and intermediate-energy  gas  made with existing pro-
 cesses .
          Therefore, industry's pursuit of low- or intermediate-energy gas,
which is  generated on site for their needs,  seems  entirely reasonable as a
means of  securing both near- and long-range  supplies of needed fuel.

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                                     153


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 (2)  A National Plan for Energy Research.  Development, and Demonstration;
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 (3)  Economics of Fuel Gas  From Coal. Foster, J.F., and Lund, R.J., McGraw
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 (4)  Study of Potential Problems and Optimum Opportunities in Retrofitting
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 (5)  1972 Census of Manufacturers.  U.S. Dept. of Commerce, Bureau of Census.

 (6)  Energy Consumption in  Manufacturing.  Myers, J.G., et al., a report to
      the Energy Policy Project  of the Ford Foundation, Ballinger Publishing
      Company, 1974.

 (7)  Special Survey on Gross  and Net Consumption of Fuels and Energy; Com-
      mittee on Taxation and Statistics, Energy Task Group, American Iron
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 (8)  A Cost Analysis of Air Pollution Controls in the Integrated Iron and
      Steel Industry, Battelle report to NAPCA, Contract PH22-68-65, May, 1969.

 (9)  Potential for Energy Conservation  in  the Steel Industry, Lownie, H.W.,
      et al., FEA,  Contract CO-04-51874-00, May 30, 1975.

(10)  Factors Affecting the  Future of the Coal Industry in the United States,
      Battelle working paper,  April, 1973.

(11)  Federal Findings on Energy for Industrial Chemicals, report from International
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      September 2, 1974.

(12)  Challenge to U.S. Glass  Manufacturers in These Energy-Critical Times,
      Hibscher, C.W., and Steitz, W.R,, Ceramic Bulletin. Vol. 54, No. 6, 1975.

(13)  The Reserve Base of Coal for Underground Mining in the Western United States,
      Matson, T.K., and White, D.H., Information Circular 8678, Bureau of Mines,
      p. 3, 1975.

(14)  Cost Factors in Oxygen Production, Hugill, J.T., presented at Efficient
      Use of Fuels Symposium,  Institute of  Gas Technology, Chicago, 111.,
      December 9-13, 1974.

(15)  What Does Tonnage Oxygen Cost, Katell, S., and Faber, J., Chemical Engineering.
      June 29, 1959.

(16)  Evaluation of Pollution  Control in Fossil Fuel Conversion Processes Gasification,
      Section 1;  Koppers Totzek,  Magees, E.M., Jahnig, C.E., Shaw, H., ESSO Research,
      EPA-650/2-74-009a, January, 1974.

-------
                                       154


(17)  Oil and Gas Journal, April 7, 1975.

(18)  Oil and Gas Journal. Nelson, W.L., April 14,  1958,  April  21,  1958,
      March 7, 1966, October 30, 1972.

(19)  Oil and Gas Journal. Nelson, W.L., p.  132,  March 17,  1975.

(20)  U.S. Bureau of Mines Mineral Industry  Surveys Crude Petroleum Petroleum Products
      and Natural Gas Liquids;  1973 Final  Summary,  Bureau of Mines  Energy
      Breakdown, Table 3 reference; Table  4  reference, February 14, 1975.

(21)  Oil and Gas Journal. April 2, 1973,  and April 4, 1974.

(22)  Mineral Industry Surveys; Crude Petroleum.  Petroleum  Products,  and Natural
      Gas Liquids, 1972 and 1973, U.S.  Bureau of  Mines.

(23)  Oil and Gas Journal, January 24,  1972.

(24)  Oil and Gas Journal. April 23, 1973.

(25)  Oil and Gas Journal, Nelson, W.L., December 4,  1972.

(26)  Bureau of Mines Technical Paper 560, Devine,  J.M.,  Wilhelm, C.J., and
      Schmidt, L., 1933.

(27)  Materials Protection, J.  Gutzeit, Vol.  7, 17, 1968.

(28)  Oil and Gas Journal. Mottley, J.R.,  and Pfister, W.C., Vol. 61, 23, 177,
      1963.

(29)  Materials Performance, Tuttle, R.N., Vol. 13, 42, 1974.

(30)  Corrosion, Treseder, R.S., and Swanson,  T.M., Vol 24,  31,  1968.

(31)  Materials Performance, Battle, J.L., et  al.,  Vol. 9,  11,  1970.

(32)  Materials Performance, Battle, J.L., et  al.,  Vol. 14,  43,  1975.

(33)  Proceedings 2nd International Congress  on Metallic  Corrosion, Obrecht, M0F.,
      New York, 624, 1963.

(34)  NKK Technical Report, Tanimura, M., Nishimura,  T.,  and Nakazawa, T.,
      Overseas, Tokyo, December, 1974.

(35)  Proceedings of International Conference  on  SCC  and  Hydrogen Embrittlement
      of Iron Base Alloys. Brown, A., Harrison, J.T.,  and Wilkins, R., Firmmey,
      France, 1973.

(36)  Corrosion. Samans, C.H.,  Vol. 20, 256,  1964.

(37)  Corrosion. Ward, C.T., Mathis, D.L., and Staehle, R.W., Vol. 25, 394, 1969.

-------
                                    155
 (38)  Stahl U. Eisen, Heischkeil,  Werner,  Vol.  68,  228,  1948.

 (39)  Proceedings 5th International Congress  on Metallic  Corrosion, Hewes, F.W.,

 (40)  Evaluation of Pollution Control  in Fossil Fuel Conversion Processes
       Gasification; Section 1:  Lurgi Process, Shaw, H. and Magee, E.M.,
       ESSO Research, EPA 650/2-74-009c (July, 1974).

 (41)  Industrial Boiler Design for Nitric  Oxide Emissions Control. Brashears, D.F.,
       Western Gas Processor and Oil Refiners  Association, March 8, 1973.

 (42)  Analytical Studies on Kinetics of Formation of Nitrogen Oxide in Hydrocarbon-
       Air Combustion, Martiney, P..I.,  Combustion  Sci & Tech, Vol. 1, 461, 1970.

 (43)  Overall Reaction Rates of NO and No  Formation from Fuel Nitrogen. DeSoete,
       G.G., 15th International Symposium on Combustion, The Combustion Institute,
       1093-1102, 1975.

 (44)  Influence of Combustion Modification and  Fuel Nitrogen Content on Nitrogen
       on Nitrogen Oxides Emission  From Fuel Oil Combustion, Turner, D.W., Andrews,
       R.L., Siegmund, C.W., Combustion. Vol.  44, 21-30,  1972.

 (45)  Conversion of Fuel Nitrogen  to NO in a Compact Combustor. Hazard, H.R.,
       Trans. ASME, J. Eng.  Power.  Vol. $6A, 185-188, 1974.

 (46)  Analysis of Gas, Oil, and Coal Fired Utility  Boiler Test Data. Dykemh, O.W.,
       and Hall, R.W., U.S.  EPA, Symposium  on  Stationary Source Combustion, Sep-
       tember 24-26, 1975.

 (47)   Koppers-Totzek; Take  a Long  Hard Look.  Mitsak, D.M., and Kamody, J.E.,
       Second Symposium, Coal Gasification, Liquefaction,  and Utilization: Best
       Prospects for Commercialization, Univ.  of Pittsburgh, August, 1975.

 (48)   The Environmental Impact of  Coal-Based  Advanced Power Generating System.
       Robson, F.L., Giramonti,  A.J., Symposium  Proceedings: Environmental Impact
       of Fuel Conversion Technology, EPA-650/2-74-118, 237-257, October, 1974.

 (49)   Evaluation of Pollution Control  in Fossil Fuel Conversion Processes; Gasi-
       fication, Section 1,  Lurgi Process.  Shaw, H., and Magee, E.M., EPA 650/2-
       74-069C, July, 1974.

 (50)   Low and Intermediate  Btu Fuel Gas Cleanup, Colton,  C.B., and Dandavati, M.S.,
       EPA Symposium on Environmental Aspects  of Fuel Conversion Technology II,
       December 15-18, 1975.

 (51)   The Winkler Process.  A Route to  Clean Fuel From Coal. Banchik, I.N., EPA
       Symposium, Environmental Aspects of  Fuel  Conversion Technology II, December,
       1975.

 (52)   Progress in High Temperature Electrostatic Precipitation. Shale, C.C.,
       APCA Journal. Vol. 17, 3, March, 1967.

(53)'   ERDA'S Synthetic Fuels Plans. Knudsen,  C.W.,  presented at the Industrial
       Utilization of Gas From Ohio Coal Conference, Battelle Columbus Laboratories,
       May 6, 1975.

-------
                                      156


(54)   Status of Synfuels Projects, September. 1975. Excerpt from Synthetic  Fuels.
      Vol. 12, 3, Cameron Engineers, September, 1975.

(55)   Synthetic Pipeline Gas, Linden, H.R., presented to the Pacific Coast
      Gas Association, San Francisco, California, September 8,  1971.

(56)   United States Energy Through the Year 2000, Dupree, W.G., and West, J.A.,
      U.S. Dept. of Interior, December, 1972.

-------
               APPENDIX  A
COMBUSTION OF LOW- AND INTERMEDIATE-ENERGY
       GAS IN INDUSTRIAL PROCESSES

-------
                              APPENDIX  A
              COMBUSTION OF LOW- AND INTERMEDIATE-ENERGY
                     GAS IN INDUSTRIAL PROCESSES

                             INTRODUCTION
          Moderate- and low-energy gas obtained from various gasification
processes have been suggested as substitutes for natural gas in many in-
dustries, including the two that are; the subject of this report, namely,
the secondary steel industry and the refinery industry.  Problems to be
considered in making such a substitution are flame stability, fuel
cleanliness and pollution tendencies, flame heat transfer characteristics,
and overall flow rate (fan capacity).  Three of these items are discussed
below; pollution problems are covered in Section VI.
                           Flame Stability

          It should be noted that a change to moderate or low-energy gases
is the reverse direction to that made decades ago; as natural gas became
available, the use of various combustible mixtures from coal-gasification
processes were phased out.  A similar more recent process occurred in
England with the development of the North Sea gas supplies.  Generally
speaking, these fuel changes were accompanied by changes in types of
burners.  For instance, in the residential area, the quiet, soft diffusion
flame burners in heating units were replaced by the noisier, harder, but
more compact premixed flame burners.  Unfortunately, such changes have
reinforced a connotation that moderate- and low-energy gas implies large
combustor systems.  Yet, the real reason is that the low burning velocity
of natural gas permits the use of premixed burners that lead to more com-
pact designs in the case of household heating applications.  This example
clearly shows that each potential conversion must be analyzed in detail
in order to draw valid conclusions.
          Basically, flames may be either of the premixed flame type,
wherein the fuel and air are uniformly mixed before entering the com-
bustion zone, or of the diffusion flame type, wherein the fuel and air
are separated until they reach the combustion zone.  In the latter case,
however, the leading edge of the flame surface is premixed locally;
in fact, in many recent designs of burners, a small premixed region is

-------
                                  A-2
purposely formed.  Thus, the flame stability is related to premixed
flame characteristics.  The flames may be either laminar, wherein
the rate of mixing (of mass, momentum, and energy) is controlled by
the molecular kinetic properties, or turbulent, wherein the rate of
mixing is controlled to a significant degree by the turbulence
characteristic of the flowing gases in the precombustion region.
Most industrial burners have turbulent flames; however, in consider-
ing the fine details of flame stability, the laminar flame character-
istics usually control the local phenomena.
          Practical burners can combine features of both types of com-
bustion.  For instance, many premixed burners use fuel-rich mixtures;
secondary air is added to the products of the premix flame to produce a
diffusion flame.  Nozzle-mix burners (for example, a fuel jet surrounded
by multiple air jets firing into a burner tile) may show either a
diffusion flame or premixed flame, depending on where the flame is
stabilized.  Thus, it is difficult to single out one feature of a com-
bustible mixture that can be considered to characterize the fuel for
comparison purposes, even if the burner is not changed in the process
of changing fuels.
          If a comparative parameter must be chosen, however, the most
easily available pertinent parameter seems to be the flash-back velocity
gradient.  Experimental values of this parameter are obtained by firing
a Bunsen-type burner in the open.  The flow rate of the combustible mix-
ture to a laminar flame is slowly reduced until the flame flashes back.
It is found that the velocity gradient at flashback in laminar flow is
independent of duct sizes over a wide range of sizes and ambient atmos-
pheres.  Values are available from one source (A-l)  of information for
a wide variety of fuels, and some combination rules have been developed
for those fuel mixtures not listed (for instance, see Reference A-2).

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                                  A-3
          The great significance of the flash-back velocity gradient
in studies of industrial combustors is that it is related closely to
several other significant combustion parameters.   For instance,  the
flash-back velocity gradient is proportional to the blow-off limit in
an enclosed system, to the chemically controlled reaction rate per unit
volume, to the square of the burning velocity, and it is inversely pro-
portional to the ignition delay time mentioned by many investigators.
It also has been suggested that it is proportional to the peak frequency
                               (A-3)
of the combustion roar spectrum

Presentation of Flame-Stability Data.

          Table A-l presents the information on the composition and higher
heating values of compositions that are considered characteristic of the
various fuels considered in this analysis.  Table A-2 presents computed
values of the stability limits considered from three points of view:
          (1)  The usual critical flash-back velocity gradients
               at stoichiometric and the maximum flash-back velocity
               gradients are presented.
          (2)  The stoichiometric and maximum values of the heat
               release rate (the product of the gradient and the
               corresponding higher heating value per cubic foot
               of fresh mixtures) are given.

          (3)  The stoichiometric and maximum value of the products
               of the gradients and the corresponding higher heating
               value of the fuel are tabulated.
          Also included are the Wobbe Numbers (the high heating value
divided by the square root of the specific gravity) which comprise a
useful parameter in evaluating fuel changes in aspirating-type premix
burners or burners in which pressure sensitive controls are used to
regulate the relative rates of flow of fuel and air.

-------
                              TABLE A-l.  FUEL  COMPOSITION  AND  THERMAL PROPERTIES

Volume
Gasifier
Lurgi
Lurgi

Koppers-Totzek
Koppers-Totzek
Coke oven*-
Wellman-Galusha
Natural gas'c)
Propane'"^
Gasifying Medium
Oxygen- s t earn
Oxygen- s t eam-
stripped
Oxygen- steam
Oxy g en- steam-
stripped

Air-steam


N
1
2

2
1
4.6
50
0.6
0
co2
33
0

7
0
0.1
3
0.9
0
CO
13
20

56
61
10.6
29
0
0
Percent
H2
37
55

35
38
58.4
15
0
0
CH4
16
23

0
0
26.3
3
91.5
0
C3H8
0
0

0
0
0
0
1.3
98.6
HHV,
MJ/Nm3
12.7
18.7

11.6
12.6
19.3
6.8
42.0
99.3
Fuel
(Btu/scf)
(322)
(474)

(294)
(319)
(490)
(172)
(1066)
(2521)
Heat Release for
Stoichiometric
Mixture
MJ/Nm-;
3.4
3.8

3.7
3.7
3.7
2.9
3.8
4.0
1 (Btu/scf)
(87)
(96)

(93)
(95)
(95)
(73)
(97)
(102)
Adiabatic (a)
Flame
Temperature
K F
2104 (3328)


2320 (3717)


2041 (3214)
2232 (3358)


(a)  Calculated with  dissociation,  at Stoichiometric  ratio.


(b)  Bureau Mines  RI  5225,  Fuel No. 43.


(c)  Also  contains 5.2  percent C«H,, 0.5 percent  other  hydrocarbons;  Bureau Mines RI 5225, Fuel No. 1.


(d)  Also  contains 1.4  percent C0H,; Bureau Mines RI  5225, Fuel  No.  3
                              J D
                                                                                                                           I
                                                                                                                           -t-

-------
                                          TABLE A-2.  FUEL STABILITY  FACTORS
Flash-Back Velocity
Gasification Gradient, sec~l
Gasifier
Lurgi(c)
Lurgi(c)
(c)
Koppers-Totzekv '
Koppers-Totzek
Coke oven
(c)
Wellman-Galusha
Natural gas
(b)
Propane
Medium Stoichiometric
Oxygen- steam
Oxygen- steam- stripped
Oxygen- steam
Oxygen- steam- stripped

Air- steam


767
1930
2020
2660
2200
584
420
1:60
Max imum
775
1950
2640
4430
2290
650
420 .
600
Heat Release Rate,
103 MJ/Nm3-sec
(103 Btu/ft3-sec)
Gradient x HHV,
10^ MJ/Nm3-sec
(104 Btu/ft3-sec)
Stoichiometric Maximum Stoichiometric Maximum
2.6
7.2
7.4
10.0
8.0
1.7
1.6
2.1
(66)
(183)
(187)
(254)
(204)
(43)
(40)
(53)
2.6 (67)
7.4(187)
9.4( 40)
15.0(380)
8.5(2.5)
1.8 (46)
1.6 (41)
2.4 (61)
1
3
2
3
4
0
1
5
.0
.6
.5
.4
.1
.4
.7
.6
(25)
(91)
(63)
(86)
(105)
(9.7)
(44)
(142)
1.0 (25)
3.6 (92)
3.3 (84)
5.6(142)
4.3(110)
0.4 (11)
1.7 (44)
6.0(152)
Wobbe^
No.
368
769
353 '
i
404
847
187
1364
2019
(a)   Higher  heating value of the  fuel divided by the square root  of  the  fuel  specific  gravity.




(b)   Flash-back velocity gradient obtained  from Bureau Mines RI 5225.




(c)   Flash-back velocity gradient computed  using Reference A-2.
                                                                                                                            Ul

-------
                                   A-6
          The gradient values of Table A-2 are obtained from Figures A-l,
A-2, and A-3.  Figure A-l presents the flash-back velocity gradients as a
function of the fuel gas concentration relative to the stoichiometric
      *
value.   These gradients were constructed using a modification, presented
in Reference A-2, of the techniques presented in Reference A-l and data
from the same source. Figure A-2 presents the critical value of the heat-
ing rate per unit volume, based on the fresh mixture properties.  Figure
A-3 presents the curves of Figure A-l in an alternate form, each curve
being multiplied by the corresponding higher heating value for the fuel.
It is noted that the natural gas curve peaks close to stoichiometric, while
the remainder of the fuel-air mixtures peak on the fuel-rich side.
          A consideration of Figures A-l and A-3 shows that natural gas
behaves much like the fuels that have the lower HHV.   Other than natural
gas, the produced fuels (principally consisting of H , CO, and inerts)
line up roughly in order of the amount of inert present.   Considering
Figure A-l, natural gas (with no appreciable inerts)  has  stability limits
lower than any of the listed fuels resulting from various coal gasification
processes.
          In some uses of low- and medium-energy gas, the gas may be pre-
heated.  Similarly, there are instances wherein the air is preheated.  These
cases may be analyzed in a manner similar to that discussed below for the
nonpreheated cases.  However, suitable stability curves similar to those
in Figures A-l, A-2, and A-3 must first be constructed.

Discussion of Flame Stability in Burners

          Three general types of burners are considered in the discussion
of flame  stability  - pretnix  burners, delayed-mixing  burners, and nozzle-
mixing burners.  While it is not difficult to distinguish premix burners
from the other two types, the distinction between delayed-mixing burners
and nozzle-mixing burners is sometimes rather vague.   For the purpose of
this discussion, combustion in a nozzle-mixing burner will be more intense,
* Relation of fuel gas concentration relative to stoichiometric,  F,  to air
  to fuel equivalance ration, or, is given in table of symbols,  page  A-32.

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                                    A-7
        August 26, 1975
5x10
4x10°  '
3xlOJ  -
Koppers-Totzek
 (Stripped)
                                   Lurgi (Stripped)
 2x10
                  OT9~        1.0         1.0         1.2

        Gas  Concentration,  Fraction  of Stoichiometric
       FIGURE A-l.  FLASH- BACK VELOCITY GRADIENT AS A FUNCTION
                    OF GAS CONCENTRATION IN MIXTURE

-------
              August 26,  1975
                                  A-8
 o
 0)
 CO
CO
 cd
 u
     4xl05
     3x10
         5
     2x10
         5
 3
 4J
 I
 i-<
 o
 C

 S3
 0)
 4J
 §•   4xl04
 CO
105
      8x10
      6x12"   -
      3x10    &
      2x10
       10
                         Koppers-Totzek—|

                         (Stripped)
                                    Lurgi  (Stripped)
            0.8
                 0.9           1.0          1.0         1.2

            Gas Concentration, Fraction of Stoichiometric
               FIGURE A-2.
                      CRITICAL HEAT RELEASE RATE PER- UNIT VOLUME

                      (FLASH-BACK VELOCITY GRADIENT TIMES HHV OF

                      MIXTURE) AS A FUNCTION OF GAS CONCENTRATION

                      IN MIXTURE

-------

en
 4J
 ffl
 X

 4-1
 c
 0)
 •t-i
 •o
 rt
  O
  O
 i-l
  (0
  O
  ca
  PQ
  I
     2x10
             August 26, 1975
     8x10
     6x105   &
    4x105  '"
     3x105   •
 >   2x10"   -
      10
     8x10
     6x10
     4x10
        ,J   MM^
                                                        KOPPERS-TOTZEK

                                                          (Stripped)
                     Lurgi  (Strippea)

              Koppers-Totzek
                                                     A-9
           0.8          0.9         1.0         1.1          1.2

               Gas Concentration, Fraction of Stoichiometric
           FIGURE A-3.
FLASH-BACK VELOCITY GRADIENT TIMES GAS

HIGHER HEATING VALUE  (HHV) AS A FUNCTION

OF GAS CONCENTRATION  IN MIXTURE

-------
                                   A-10
with at least a significant fraction of the combustion taking place within
or close to the burner tile.  Delayed-mixing flames will generally extend a
considerable distance from the burner and often be characterized by a low
turbulence level and mixing rate.  Significant amounts of furnace gases
might be recirculated into the base of their flames.  To complicate the
problem further, some premixing is often used in delayed mixing and
nozzle-mixing burners to aid in producing a stable ignition region for
the flame.
                         jf
          Premix Burners.  Premixed flames are reasonably common in industry
and are the easiest to analyze.  The premixed fuel and air are usually
supplied to the region from an inspirator or Venturi mixer, an aspirator
or suetion-type mixer, or a fan mixer.  The burner may be a small port
or ported manifold type, a large port (or pressure type), a tunnel burner,
or a flame-retention type pressure burner.  For high firing rates with
turbulent flow, the flame will not hold at the end of the duct.  Therefore,
a variety of flame-holding systems are used.  Figure A-4 is an example
of the flame-retention type burner, in which some of the combustible mix-
ture is slowed down and diverted into an annular combustion region.  The
flame in the protected annular region acts as a pilot to maintain or hold
the main flame.  In closed systems (such as tunnel burners), steps, recesses,
grids, and other obstacles are often used to hold the flame.  These form
protected recirculation zones, which hold the flame and from which the
flame spreads.
          In all of these cases, the key factor is a term proportional to
                                   **
the velocity gradient at flashback.    As a simple example, consider a closed
 *
    "Usually, a burner applied with gas and air which has previously been
    mixed, but sometimes a burner within which the gas and air are mixed,  ..
    before they reach the nozzle (as opposed to nozzle-mixing burners)."
**  Often, in the case of flame holding by obstacles, an explanation of
    performance based on the concept of a delay time is advanced;  this
    delay time is proportional to the reciprocal of the flash-back
    gradient.

-------
                    A-ll
                  M —
                  IS1
AIR &

 GAS

 FIGURE A-4.
PREMIX BURNER, FLAME

RETENIION TYPE

-------
                                   A-12
 system where  the  blow-off  velocity  gradient, G,  ,  is,  say B times the
                                  *V*
 flash-back velocity gradient,  G   .'   For  turbulent  systems, the gradient
 is  usually given  merely  in the form of U/D--the  average flow velocity, U,
 divided  by a  characteristic diameter, D.  Then,  U,  =  B U^, ~ DG,., .  Now,
 if  the critical velocity gradient is doubled by  a change in fuel, then
 both the blow-off and flash-back velocities will double.   In many burners,
 the equivalent of single or multiple steps are used,  so that on premature
 flash back the characteristic  diameter  is decreased as the flame  moves
 upstream;  this decreases the critical flash-back velocity  at the  same
 time as  the flow  velocity  increases, thus stopping the flash back.  For
 such a design, increasing  the  critical value of  G will increase the range
 of  flow  rates for stable flames, but not necessarily  the heating  rate,
 as  will  be shown.
           A constant heating rate system will  now  be considered with a
 change in fuel.   Considering a single burner with  a volume flow rate of
 combustible mixtures,  Q, and a heating value per unit  volume of mixture,
 H ,  the  heat  release rate  will be QH .  When the critical blow-off condi-
  m                                   m                     23
 tion is  reached,  the heat  release rate is given  by QH  ~ UD H  ~ D GH .
                                                     m      m       m
 For a single  size of burner, the key term for  comparison is GH .  The
 relative values of this  term are plotted on Figure A-2.  It is seen that,
 on  the basis  of the heat release rate at blow-off, natural gas and Wellman-
 Galusha  gas are about  the  same on the excess air side  and all other gases
 shown here are more stable against  blow-off.   On the other hand, these gases
 are more prone to flash back,  and their use could  result in a significant
 decrease in turn-down  ratio.
                                      **
           If  the  fan power is  limited,   the change from, say, natural gas
 to  low energy gas may  be complicated by  this power limit.  The air power
                                      *3   /
 is  given by QAp,  which varies  with  pQ /D .  Assuming a constant heat release
 rate,  that is,  if QH  is constant,  and that dynamic (rather than viscous)
                                                              /  o
 pressure losses are controlling,  the air power varies with p/D H  .   For
                                                                m
 <
   A list of symbols used in this section is presented on page A-32.
** Similar results are obtained if fan pressure is considered to be
   controlling.

-------
                                  A-13
 a  stoichiometric mixture  in the air.,  p does not vary appreciably in cotn-
             3
 parison  to H   .  Thus,  the relative values of H  are of great importance.
 It is  seen from Table A-l that the values vary from 102 for propane to 73
 for gas  from Wellman-Galusha gasifier.  The stripped Lurgi, the unstripped,
 and the  stripped Koppers-Totzek, and  the coke oven gas are directly
 interchangeable with natural gas on this basis.  We note that, if D is
 increased to compensate for the lower value of H  of the Wellman-Galusha
                                                m
 gas, flashback will be  encouraged.  (This is the reason that in shifting
 to a medium- or low-energy gas from natural gas, there is a tendency to
 shift  to nozzle-mixing  or delayed-mixing burners).
          If the number of burners (or the number of elements in some
                                                             243
burner designs^  can be changed,  then the constant term is  p/N D H
 (again assuming dynamic pressure losses^.   Assuming that  burner designs
 for comparative fuels are to be limited by the critical velocity gradient,
                            4/3  2/3 5/3
 then the constant  term is PG   /N   H      It  is  seen that the number of
burners  (or number of ports')  must be increased in changing to the'moderate
 or low energy gas  from natural gas to avoid flashback while at the  same
                                      2                     -3/2
 time the total area of the burners (ND )  must  vary with (H ^     .   Thus,
                                                          m
if N is about 1 for natural gas,  then N would  be  about 25  to 30 for moderate
 energy gases and abcmi- ^ t-n 6 for low-energy gases.
          Although the  volume of products is not exactly proportional to
 the volume of fresh mixture, it is close enough that the term p/D H  can
                                                                   m
 be considered also as a measure of flow power loss through a furnace and
 stack.   Thus, again, while several of the gases, as listed above, are
 interchangeable with natural gas, Wellman-Galusha gas will require more
 than twice the pressure compared to natural gas to move the products of
 combustion through a furnace.  In a boiler-type furnace, the higher
 velocities associated with a change to low heating value gas would re-
 sult in  a higher heat fluxes initially and possibly excessive cooling
 of the products of combustion in the  latter part.  In a furnace using
 direct heat conduction  to a material, this could be an advantage.
          The Wobbe Number, which is  the ratio of the higher heating
 value  of a fuel to the  square root of the specific gravity of the fuel,
 is the common measure of interchangeability in simple combustion units
 with a fixed firing rate, where (a) fuel is used to aspirate air

-------
                                   A-14
(inspirator or Venturi-type unit), (b) air is used to aspirate fuel
(aspirator or suction type), or  (c) a pressure-type control is used to
control the ratio of the fuel gas and air.  The reasoning that leads to
the Wobbe Number is as follows.
          Consider a unit in which the fuel is used to aspirate the air.
In this combustion unit of fixed configuration, with, say, a constant
                                     2
pressure drop on the fuel spuds, PfQf  is a constant.  For the heat re-
lease rate to be constant, QfH,-  is also constant, and it follows that
  2
H  /p  is a constant.  Normalizing the fuel density to specific gravity
and taking the square root results in the Wobbe Number.  Therefore, if
the Wobbe Number changes, the firing rate of this simple type of unit
changes with change in fuel  unless spud size or supply pressure is
changed.
          But this is not the entire story.  In a combustion unit of
fixed configuration, with any of the types of interconnections between
fuel and air mentioned above, the ratio of momentum flux of the fuel to
                                 2     2
air remains constant.  Thus, P/}-: /P Q   is a constant.  If a denotes
                              I JL   3, cl
the air/fuel ratio relative to stoichiometric air/fuel ratio and H  is
                                                                  a
the heating value of air, Q H  = Q..H /a.  By substitution, it follows that
           -L /2             a a    t t
LH,/(p-/p )   ]/(aH ) is a constant.  As the heating value of the air
  £   r.  a         a
that is used in burning any hydrocarbon fuel does not vary greatly, a
change in Wobbe Number also results in a change of excess air in the com-
bustor if no other change is made.  It is often assumed that a change in
Wobbe Number of more than 5 percent requires a change  in  spud  size.
          From Table A-2, it is clear that any change from natural gas
to one of the other fuels will necessitate a change in spuds or re-
adjustment of the control system in some manner.

-------
                                   A-15
                                •i.
          Delayed-Mixing Burners .  Turbulent mixing is usually considered
as the rate controlling factor in turbulent diffusion flames of industrial
importance.  The chemically limited reaction rate, which is far greater
than the gross reaction rate of the furnace, is not considered to be con-
trolling or even important, other than through its effect on flame stability.
However, the effect of turbulence itself is not well understood in complex
flow systems, and additional complications arise from the presence of a
flame that adds a random set of volume sources as the gases expand by heat
from random pockets of combustion.
          Nonturbulent and turbulent diffusion flames have one feature in
common:  the flames must be held at some point, line, or area.  In a non-
turbulent flame, the adjacent fuel and air interdiffuse over the end of the
partition separating the two gases.  At some distance downstream of the
partition, a combustible mixture of varying composition is reached over
a region greater than the  laminar flame thickness.  In this region, at
a distance equal to or greater than the quenching distance, a premixed
flame develops and holds (or "seats") the diffusion flame.  In fact, the
diffusion flame may be pictured as a stepwise series of premixed flames,
each with hotter but more dilute initial composition.
          In a turbulent flame, a firm seating of the flame often does
not occur (unless provision for a little local premixing has been properly
built into the burner).   One notes that local cells of the fuel and air
are of different compositions, temperature, and velocities and have different
                                                                   **
molecular and thermal dilutions as they approach the reaction zone.    Thus,
there are only local regions where the maximum turbulent flame speed can
 *  Delayed-mixing burners are those "in which the fuel and air leave
    the burner nozzle unmixed and thereafter mix relatively slowly*
    largely through diffusion.  This results in a long luminous flame
    called a diffusion flame, luminous flame, or long flame." ^A~^
**  This variation from the average of local time and space concentrations
    is known as the unmixedness of the fluid.

-------
                                   A-16
exceed the velocity of the oncoming fuel-air mixture.  Therefore, the
flame-holding points shift about in space as the local low-velocity
regions shift about in the turbulent stream.  Furthermore, all of the
leading edges of the flame must move at close to the maximum premixed
flame speed through the turbulent mixture, stretching and spreading the
      #
flame.   When the flame no longer contains enough local regions where it
can "buck" the oncoming stream and not be extinguished, it will blow off
unless held by some independent energy source.
          It thus appears that the critical stability parameter in an
enclosed turbulent diffusion flame will be related to the maximum flash-
back velocity gradient rather than the velocity gradient specific to the
average mixture ratio.
          Figure A-5 shows typical delayed mixing burners that will re-
sult in a long luminous flame.  Figure A-5a is a version in which the
fuel and air velocities are similar and the flow streams are paralled.
Increase of the cross-flow gas at the Venturi throat results in a decrease
in flame length and luminosity.  Natural gas and low Btu gases are inter-
changeable in this burner with change in gas pressure.  We note that a
pilot flame is incorporated for ignition and/or piloting of the diffusion
flame.  The pilot flames are usually premix or nozzle-mix flames.  There-
fore, if the stability of the diffusion flame depends on the pilot flame,
then the stability conditions of the pilot flame are of prime importance.
However, even with a pilot flame, the diffusion flame may not be suffi-
ciently held so that a satisfactory flame results.   Thus, the stability
characteristic of the diffusion flame must also be considered.  On the
other hand, the pilot flame is not normally subject to a necessity for
a turn-down capacity.  Current practice in design of burner, for safety
*                   (A-5)
   Otsuka and Niioka      suggest that,  in cases where the flame  is
   being rapidly stretched as would be the case in a turbulent  flame
   front, the flame forms  in the maximum temperature region rather
   than the stoichiometric region often assumed in the literature.

-------
                            A-17
                            PILOT TIP
                   AIR
GAS
                                 (b)
        FIGURE A-5.  DELAYED MIXING BURNERS

-------
                                   A-18
reasons, is to insure satisfactory flame performance without a pilot flame.
It is noted that the protective effect of the short tile of this burner
helps insure satisfactory holding of the flame.
          Figure A-5b shows a delayed mixing burner in which the fuel re-
mains in a high-velocity, coherent jet for a considerable distance,  surrounded
by a low-velocity air mantle.  The flame is piloted through the effect of
the recirculation and mixing annular region surrounding the fuel jet.
          In neither of the burners is there any problem of flashback.
Thus, only the possibility of blowing off the flame need be considered
in comparing performance with various fuels.  Considering the fuels in
Table A-l, it is seen from the values for the maximum flash-back velocity
gradient in Table A-2 that natural gas is the most unstable of the tabulated
fuels.  For medium energy fuels, the combustion systems are much more stable.
However, this argument does not take into account the necessary change in
fuel flow rate with low energy fuels if the burner remains unchanged.
          Figure A-5b may be considered as just a simple diffusion flame
of the Bunsen burner type, with only fuel in the central jet.  With a
change in fuel, the maximum diameter of the flame increases as the stoichio-
                                                      *
metric air/fuel ratio increases.  For turbulent flames  at a constant heat
input rate, the length of flame changes little.  For a constant shape of
burner and considering a constant heat input rate and a low velocity of the
air in relation to the fuel jet, the holding point of the flame will be
determined roughly by the product of the higher heating values and the
maximum flash-back velocity gradient.  Figure A-3 (and Table A-2) present
the values of this point for the various fuels considered.  It is seen
that the order of fuels has changed from those noted in the previous dis-
cussion.  Propane, stripped Koppers-Totzek gas and coke-oven gas are the
most stable fuels, but natural gas is now above unstripped Lurgi and
Wellman-Galusha gases.  When the fuel velocity is higher than the average
*
   While the aspiration rate of the fuel jet cannot be significantly altered,
   care is usually taken to eliminate as much swirl and turbulence from the
   air flow as possible to keep from increasing the mixing rate unnecessarily.

-------
                                   A-19
air velocity, the movement of the combustible interface outward with in-
creasing value of the stoichiometric air/fuel ratio also improves the
stability of natural gas relative to the remainder of the fuels.
          This is not the entire story, however.  For most delayed mixing
burners, such as shown in Figure A-5a, the fuel and air velocities are
                                           *l.
about the same to inhibit premature mixing.   Therefore, stability of the
flame, if the flame is held within the tile, is governed by whichever
velocity is controlling--the fuel velocity or the air velocity, or a
combination thereof—in the exact region of holding.  Furthermore, if
changes in fuel are made without concomitant changes in burner dimensions,
the relative values of fuel and air velocity will change, and the significant
control point may change.  The flame may find a stable region or attachment
around the annular air jet, rather than the fuel jet.  In this case, the
flames stabilize closer to the air jet as the air/fuel volume ratio at
stoichiometric decreases.  Furthermore, and more important, the air velocity
does not change much with fuel at a constant heat input rate.  In this case,
the curves of Figure A-l should be considered for stability.
          If the flame does not stabilize close to the inlets in either
position, then the slow mixing can result in other diffusion flames start-
ing beyond the tile in the region where recirculating gases will slow the
flow velocity and dilute the air annulus.
          When these burners are used in radiant tubes, it is often desirable
to have the heat flux peak near the burner and hold at that value or fall
off gradually, rather than increase slowly to a peak value some distance
down the tube.  To accomplish this, a small amount of air may be bled into
the fuel jet (or vice versa) so that the boundary of the fuel jet as it
emerges from the fuel tube is a combustible mixture.  This portion of the
boundary burns as a premixed flame, both boosting the heat flux to the wall
near the inlet and serving as a pilot for the downstream diffusion flame.
However, because of the diffusion effects,  there is still a composition
gradient, and the stability even in this case should probably be treated
as one would a diffusion flame stability problem.
*
    These are sometimes called laminar flow burners,  but this does  not
    denote viscous flow (Reynold's numbers are still  high).   Rather,  it
    denotes flow without high intensity turbulence in the interface.

-------
                                   A-20
          The pressure drops that are involved in supplying the fuel are
now considered briefly.  As may be deduced from the discussion of the
Wobbe Number, in connection with premix flames for a pair of fuels in
which this number does not vary too much, the fuels are interchangeable
in diffusion-flame applications as well as premix-flame applications.
It is seen from Table A-2 that the medium energy gases are the closest to
natural gas, but are far from being within the 5 percent variation usually
allowed.  Furthermore, a massive addition of propane, about 32 percent by
volume for the Koppers-Totzek unstrippable gas, would be required to boost
the values sufficiently to bring them within range.  But it is noted that
the energy values of the stoichiometric mixtures are about the same for
these fuels as for natural gas, so that changes only in the burner or
control settings would be required to obtain satisfactory operation of
a burner system.
          Interestingly, increasing the orifice sizes for the medium
energy gas sufficiently to maintain the same stoichiometry percent results
in a decrease in gas pressure while maintaining a constant heat release
rate.  Changing the orifice size a lesser amount so as to maintain the back
pressure on the fuel, and maintaining a constant heat release rate results
in an increase in the excess air using fuel aspiration.  This, of course,
may be handled by an additional adjustment.
          One can conclude, therefore, that in replacing natural gas in a
diffusion flame with medium energy manufactured gas, no stability problems
will be encountered.  In confirmation of this, one may note that burner
manufacturers often indicate these burners can be used with both natural
gas and coke-oven gas.  However, there can be a stability problem with
lower energy fuels if some changes in burners are not made.  For extreme
cases, the burner and type of flame may have to be changed.

-------
                                    A-21
                              *
            Nozzle-Mix Burners.  Nozzle-mix burners combine the advantage
  of the relatively short flame of the premix burner and the lack of flash-
  back problems of the diffusion flame.  The short flames are obtained by
  three different methods.  Figure A-6a shows the use of multiple high-
  velocity air jets parallel with the fuel jet.   The air jets aspirate the
  fuel in around them and form short flames because of the small jet diameter
                            i-if
  and potential core length.    Figure A-6b shows the use of nonparallel  jets.
  These may impinge, may interlace (with multiple fuel jets as well as air
  jets), or may be canted to produce a swirl flame and even a heavy recircu-
  lation zone on the burner axis.  If a disk is  added to the end of the
  fuel jet in Figure A-5b, a high velocity air flow and a recirculation zone
  are formed which lead to an intense mixing.  The burner in Figure A-5b  then
  becomes a nozzle-mix burner.  Some of the fuel in this case may be diverted
  radially to improve mixing further.  In all these cases, the internally
  recirculating hot gases plus the hot ceramic tile wall provides good flame
            j^y*.^
  stability.
            If the flame is held as a diffusion flame in a nozzle mix burner,
  then the flame might either be held around the central fuel jet or the
  peripheral jets.  The argument here is exactly the same as for the delayed
  mixing burners.  The main difference is that,  when the flame is not attached
  close to the inlet of either the fuel or air,  rapid mixing may take place
  before a stable region for the flame to seat is encountered.  In this case,
  the action of the flame is much like a premix burner.
            Therefore, it is concluded that in changing from natural gas  to
  moderate or lower energy fuel in a nozzle mixing burner, the position of
  the flame base may change from around the fuel jet to around air jets,
  or vice versa, depending on relative flow velocities and change in laminar
  flame speed.  Therefore, an unqualified comparison of stability cannot  be
  made.  As a result, it is not clear whether a flame might satisfactorily
  contain itself within a nozzle-mixing burner tile with a specific change
  in fuel.  Again, as for the delayed-mixing burners, it should be noted  that
  several designs are specified by the manufacturers as operating with either
  natural gas or coke oven gas.
  * "A burner in which fuel and air are not mixed until just as they leave the
    burner port, after which mixing is usually very rapid.   The flame cannot
    flash back to this type of burner".  A-4.
 ** On occasion, the role of the fuels and air jets are reversed.
*** Care must be taken to prevent aspiration of cold furnace gases both into
    the tile and the flame base.

-------
                                    A-22
  GAS

                                                       /-
              AIR
GAS
                   AIR
                                 (a)
                                (b)
                  FIGURE A-6.  NOZZLE-MIXING BURNERS

-------
                                  A-23
                          Flame Radiation

          The effect of change in fuel on radiation output will now be
considered.  It is obvious that heat is also transferred by convection
to work surfaces, and to boiler tubes.  As a result, if less heat is trans-
ferred by radiation, more heat may be transferred by convection, with a
resulting decrease in the overall effect of the change.  In furnaces where
large amounts of recirculating gas are present, the buffering effect is
increased further.  Since much of the radiation will come from gases cooled
from their maximum temperature, differences in radiation will be reduced
by this effect as the gases loose heat.  Particulate radiation is ignored
in this treatment, first, because there should be a little particulate in
the clean gases considered, and second, because no way of estimating an
expected concentration is available.
          Figure A-7 is generated from Figures 6.9, 6.11, 6.12, and 6.13
of Reference A-6, using product composition and temperature for adiabatic
burning with 10 percent excess air of certain of the fuel gases listed in
Table A-l (unstripped).  It is interesting to note the high radiating
ability of the natural gas flame, for flames more than about one foot
thick.  Ultimately, of course, all the curves must flatten out at great
thickness as they cannot radiate in excess of the black-body temperature
of the particular composition.  It is also noted that only the K-T gas
exceeds the natural gas in radiation, although the Lurgi gas is not too much
lower.  Stripping of the CO, from the Lurgi gas would raise the products
temperature and probably bring all three curves close together.  The product
gases of air-blown gas producers are highly diluted with nitrogen, and as
a result, the flame is cooled and the radiation is decreased, as seen from
comparing the Wellman-Galusha curve and the Winkler curve with the natural
gas curve .
          A curve is also shown for the effect of air preheat on the radia-
tion output, for the Winkler gas.  It is seen that the radiation output is
increased, but far less than enough to bring the gas up to that of natural
gas.

-------
                             A-24
   200
    100
CO
 <
     10
 •H
 W
 W
           Koppers Totzek Gas
                  Natural Gas
             Lurgi (62 blown)
- Wellman Galusha (air blown)
           Winkler (air blown)
          Winkler(air blown)*
      "O.I     0.2     0.4  0.6 Q8 I      2     4   6  8 10
                           Flame Thickness, ft
                                                  20     40
           FIGURE A-7.   RADIATION FROM ADIABATIC FLAMES
                        AT 10 PERCENT  EXCESS AIR

-------
                                  A-25
          Some feel for the magnitude of the effects resulting from the
various changes in the fuel products can be obtained from a consideration
of Figures 6-14 of Reference A-6, which is a simplified emissivity chart
for CCL-lLjO mixtures in a restricted temperature range.  A temperature-
emissivity product is plotted as a. narrow band of curves covering a range
of ratios of partial pressure of H.,,0 to CO-, against the flame thickness
times the sum of the CCL and ILO pressures.  As an example, radiation from
the product gases from stoichiometric combustion of the natural gas and
Winkler gas are compared.
          The slightly greater amount of (CC>2 + ikO) for the natural gas
leads to about 2 percent greater temperature-emissivity product for natural
gas, while the change in ILO/CCL ratio is from 1.90 to 0.41 leads to about
10 percent greater temperature-emissivity product for the natural gas flame
(actual amount increases with flame thickness).  The absolute temperature
ratio of the natural gas to Winkler gas is about 1.14.  Thus, even though
one temperature term is already in the temperature-emissivity product, there
is a further 50 percent increase of natural gas radiation compared to Winkler
gas.  Thus, the gas temperature itself has the largest effect.  As mentioned
before, convection heat transfer effects.gas cooling from heat losses, and
any soot radiation effects will reduce the significance of these differences,
but the differences will still be sufficiently large so that they must be
evaluated.
          Another aspect of radiation is that associated with flame de-
tection and safety considerations.  From the above discussion, it is clear
that the performance of any radiation activated controls on a furnace must
be considered, if the fuel is changed.

-------
                                   A-26
                           Flow Considerations

          There are three different comparisons that might be made relative
to flow rate when low or intermediate heating value gas is substituted for
natural gas.  On the basis of equal heat inputs, the direct substitution of
one fuel for another in the fuel lines can be compared.  Assuming stoichio-
metric mixture, the flows of premixed fuel and air can be compared and the
product flows can be compared.  Table A-3 presents these comparisons, relative
to natural gas, for the three replacement gases of immediate interest to
the project.  Both relative flow velocities, and more important, relative
pressure drops  (assuming turbulent flow) are given.
          If the same fuel lines are used, typical intermediate energy gas
from oxygen-blown producers must be delivered to the point of application
at 3 to 4 times the flow rate of natural gas to achieve the same heat input.
The low energy fuels from air-blown producers require anywhere from 6 to 9
(for Winkler gas, not listed) times the flow of natural gas.  The differences
in the flow rates of the stoichiometric mixtures are less pronounced than
those for the fuel, since the "heating value" of air is about constant.
Because of the collapse effect of burning CO or H , as compared to hydro-
carbons, the product gases may have a lesser volume at standard conditions
than the raw mixture.  As a result, the product flow rate for K-T gas
actually is lower than for natural gas.  For the low energy gas from an
air-blown producer the increase is less than 20 percent.  The corresponding
relative increase in pressure drop for the various fuels that would result
if the same fuel and flue gas equipment is used is also shown.  For inter-
mediate energy fuels about 10 to 15 times the pressure drop would be in-
curred through existing distribution mains and burners; there is between
a negative 20 percent and positive 10 percent change in pressure drop through
heat exchangers and other gas passages downstream of the combustion zone.
For the low energy fuels, however, pressure drops of over 50 times that for
natural gas would be expected in existing mains and burners; corresponding
pressure drops in passages downstream of the combustion zone would show a
50 percent or more increase relative to natural gas.

-------
                                  A-27

          The increased flow rates and pressure drops in fuel supply systems,
burners, heat exchangers, and exhsiust flues that could be encountered in
retrofitting a process from the use of natural gas to low or intermediate
energy gas while maintaining the s:ame process heat input could pose a
serious problem.  Supplying the necessary increased fuel supply rates to
various processes throughout an industrial plant will require either
pressurized distribution mains, larger distribution mains, or some com-
bination of the two.  Pressurized mains would complicate the problem of
potential leakage of a toxic carbon monoxide-laden gas into working areas.
Increasing the size of distribution systems to handle the increased flow
at lower pressures could create problems for processes widely dispersed
throughout the plant or in the areas where space is at a premium.  Only
one of the three gasification systems considered commercial in this study--
i.e., the Lurgi process—delivers the fuel gas under pressure (300 to 500
                    2
psig, 2070 to 3430/m ).  Fuel gas from the other two processes would have
to be compressed, either before or after the gas cleanup stage ,for pressurized
distribution.
          The increased flows and pressure drops occurring downstream of
the combustion zone  with certain of the substitute gases, though less
than those in fuel supply systems, can potentially be a more serious problem.
Induced draft and forced draft fans would have to be boosted to higher
operating pressures to compensate for higher flow rates.  In some cases
it may be possible to reduce the pressure drop through the process, such
as by removing tubes in boiler heat exchangers, to allow greater volumes
of flow at lower pressure drops without upsetting the heat transfer
characteristics of the process.
          If changes in the process cannot be made to compensate for in-
creased flows and pressure drops, process derating may be necessary.  This
problem could be more severe for handling the increased volumes of flue
gases than for handling of increased volumes of fuel.  Analysis of Table
A-3 reveals that inability to handle additional flue gas volume could result
in a derating of up to 5 percent for intermediate energy (300 Btu/scf;
           3
2664 Kcal/m ) gas or up to 25 percent for low energy gas (150 Btu/scf;
1332 Kcal/m3).

-------
TABLE A-3.  COMPARISON OF VOLUMES OF FUEL GAS TO NATURAL GAS
Process
Lurgi
Kopp e r s -To t z ek
Wellman-Galusha
Natural Gas
HHV,
Fuel
Gasifying Medium Only
Oxygen-steam 12.7
(322)
Oxygen-steam 11.6
(294)
Air-steam 6.8
(172)
42.0
(1066)
Relative Flow Rates
MJ/Nm . (Btu/scf) Fuel Gas /Natural Gas
Stoichiometric Stoichiometric
Raw Mixture Fuel Raw Mixture Products
3.4 (87) 3.31 1.11 1.03
3.7 (93) 3.63 1.04 .885
2.9 (94) 6.20 1.31 1.18
3.8 (97) 1.0 i.o 1.0
Relative Pressure Drop
Fuel Gas/Natural Gas
Stoichiometric
Fuel Raw Mixture Products
13.5 1.19 1.11
14.9 1.01 .806
52.7 1.66 L49
1.0 i.o 1.0
r
ho
00

-------
                                   A-29
          Alterations necessary in burner designs are uncertain without
laboratory data on which to base the redesign.  Burners that at one time
were used for low energy gas are not readily available today as production
items.  Further, the old designs would no longer be acceptable in most
cases, as advances in burner and process technology have resulted in burners
with generally wider stability ranges, intermittent instead of continuous
piloting, and sophisticated combustion monitoring and control.  This aspect
of the problem is discussed in a subsequent section.
          It is generally felt that adequate industrial burners can be
developed for intermediate and most low energy gases.  Generally, flow
areas in fuel supply lines and burner parts would have to be increased to
handle the increased fuel flows necessary to maintain the same energy input
as with natural gas or oil.  Overall burner diameters or tile diameters
probably would not be increased in most cases, however, minimizing the
amount of modification necessary in the walls of the furnace.
          Larger general-purpose burners should be easiest to retrofit to
low or intermediate energy gas.  However, the performance of some specialty
types of burners may be difficult to duplicate.  These include high-
intensity or high-velocity burners., burners where particular flame shapes
are necessary and applications requiring carefully controlled mixing and
combustion rates.

-------
                                    A-30
                               REFERENCES
(A-l)   Grumer,  J.,  Harris,  M.  E.,  and Rowe,  V.  R.,  Fundamental  Flashback,
       Blowoff, and Yellow  Tip Limits of Fuel Gas-Air Mixtures,  U.S.
       Bureau of Mines,  RI  5225,  1956.

(A-2)   Putnam,  A. A.,  "Effect  of  Recirculated Products on Burning
       Velocity and Critical Velocity Gradient",  Combustion and Flame,
       22,  277-279  (1974).

(A-3)   Giammar, R.  D.,  and  Putnam, A.  A.,  "Combustion Roar of Turbulent
       Diffusion Flames", Trans.  J. Engineering for Power, 92A,
       157-165  (1970).

(A-4)   North American  Combustion  Handbook,   The North American  Manu-
       facturing Company, 1952

(A-5)   Otsuka,  Y.,  and Niioka, T., "The One-Dimensional Diffusion Flame
       in a Two-Dimensional Counter Flow Burner.  Combustion and Flame,
       "21,  163-176, (1973).

(A-6)   Hottel,  H. C. ,  and Sarofim, A.  F.,  Radiative Transfer, McGraw-Hill
       Book Company, 1967,  Figures 6-14.

-------
                              A-31

                       LIST OF SYMBOLS

 D       Characteristic burner diameter
 F       Gas concentration, fraction of stoichiometric
 Gfb     Critical flash back velocity gradient,  calculated from data of
         Reference A-l by Reference A-Z modification of Reference A-l
         techniques
 G,       Blow off velocity  gradient
  bo
 S        Mole fraction of  fuel  in  a  stoichiometric mixture
U       Average  flow velocity through the burner
^fb     Average  flow velocity at flash back, proportion to EG^
Ufc0     Average  flow velocity at blow off, proportional to DG^
Q       Volume flow rate of combustible mixture
Qf      Fuel flow rate
Q-      Air  flow rate
 ci
HJJJ      Heating value per unit volume of combustible mixture
H_      Heating value per unit volume of fuel
H       Heating value per unit volume of air
N       Number of burners
AP      Pressure drop across burner
a        Air/fuel  ratio  relative to  stoichiometric air/fuel ratio; =
         (1  - FS)/F(1-S)
 0        Density  of combustible mixture
 p        Fuel density
 0        Air  density
  3
 B        Ratio of blow-off  to  flash-back velocity gradient

-------
       APPENDIX  B
MATERIAL AND ENERGY BALANCES
      FOR MODEL PLANTS

-------
                  Oxygen
                                                                                     Air
Saturated
  steam
To
pulverizer
                                         Waste heat
                                         recovery
                                                   water   f\\
                                                             Raw
                                                             gas
                                                            cooler
                                         MDEA sulfur
                                         removal
CoaK      Coal
storage     pulverizer
                                                                                Claus
                                                                                plant
                                                         Cooling
                                                          tower
                                                                                               Clean gas
                                                        Vent
                                                        stream
                                                                                   Sulfur
                                                                    a
                                                                     i
                                                                              Make up
         FIGURE B-l.   KOPPERS/MDEA GASIFICATION PLANT MATERIAL BALANCE  FOR MODEL STEEL PLANT

-------
TABLE B-l. KOPPERS/MDEA GASIFICATION PLANT MATERIAL BALANCE FOR MODEL STEEL PLANT
                             (Metric and English Units)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2S
COS
H20
°2
so2
TOTAL

Coal
Metric
Kg/hr
34915.7
2356.9
352.0
898.1
7186.7
36.3
7079.7
--
-_
__
--
19045.4
--
--

1


as Received
Unit
wt7o
48.58
3.28
0.49
1.25
10.00
0.05
9.85
--
_ _
__
--
26.50
--
--

Kg/hr 71870.8
NM3/hr

Temperature
Pressure
Kl/hr
C
atm
--
__
--
English Unit
Ib/hr
76976
5196
776
1980
15844
80
15608
--
~ ~
__
--
41988
--
--

Ib/hr
SCFM
GPM
F
PSIG
wt%
48.58
3.28
0.49
1.25
10.00
0.05
9.85
--
— *™
__
__
26.50
--
--

158448
--
--
--

2


Coal to Gasifier
Metric
Kg/hr
34915.7
2356.9
352.0
898.1
7186.7
36.3
7079.7
—
_.
__
--
2200.8
--
--

Kg/hr
NM3/hr
Kl/hr
C
atm
Unit
wt7o
63.45
4.28
0.64
1.63
13.06
0.07
12.87
--
-_
__
--
4.00
--
--

55026.2
--
71
--
English
Ib/hr
76976
5196
776
1980
15844
80
15608
--
_ _
__
_-
4852
--
--

Ib/hr
SCFM
GPM
F
PSIG
Unit
wt7o
63.45
4.28
0.64
1.63
13.06
0.07
12.87
--
__
__
--
4.00
--
--

121312
--
160
--
3
Steam to Gasifier
Metric Unit English Unit
Kg/hr Mol.70 Ib/hr Mol.7»
_.
__
--
--
--
--
__
__
• •• •••• ^ ^ ^ ^
__ __ -_ __
--
11807.9 100.00 26032 100.00
--
-- — -- --

Kg/hr 11807.9 Ib/hr 26032
NM3/hr -- SCFM
Kl/hr -- GPM
C 121 F 250
atm 2 PSIG 15

-------
TABLE B-l. (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2
H2S
COS
H2°
°2
so2
TOTAL
Temperature
Pressure
4
Oxygen to
Metric Unit
Kg/hr Mol.%
__
..
__
__
__
__
__
—
—
731.2 2.00
__
_-
40930.4 98.00
Kg/hr 41661.6
NM3/hr 30885
Kl/hr
C 110
atm 2

Gasifier
English Unit
Ib/hr Mol.%
__
__
__
--
__
--
--
—
__
1612 2.00
—
__
90236 98.00
Ib/hr 91848
SCFM 18176
GPM
F 230
PSIG 15
5
BFW to Gasifier Jackets
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
__
__
__
__
__
__
._
—
__
__ __ -- --
__
__
14908.7 100.00 32868 100.00
Kg/hr 14908.7 Ib/hr 32868
NM3/hr -- SCFM
Kl/hr 14.93 GPM 66
C 110 F 230
atm — PSIG

Steam
Metric
Kg/hr
--
—
--
--
--
--
--
—
--
__
__
--
14197.4
Kg/hr
NM3/hr
Kl/hr
C
atm
6

from Gasifier Jackets
Unit English
Unit
Mol.% Ib/hr Mol.%
--
--
__
__
__
__
__
__
__
__ __
__
_-
100.00 31300
14197.4 Ib/hr
SCFM
GPM
135 F
3 PSIG
--
--
--
--
--
--
--
--
--
—
--
--
100.00
31300
275
30
                                                                            (j

-------
TABLE B-l.(Continued)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
N2
COS
H20
°2
so2
TOTAL
Temperature
Pressure
7

Spray Cooling Water
Metric Unit
Kg/hr Mol.%
__
__
__
__
__
__
__
__
— — — -
_.
__
16456.3 100.0
Kg/hr 16456.3
NM3/hr
Kl/hr 16.48
C 29
atm
English Unit
Ib/hr Mol.%
__
__
__
__
«_
__

_-
— - --
__
--
36280 100.00
Ib/hr 36280
SCFM
GPM 72
F 85
PSIG
8
BFW to WH Boiler
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
__
--
--
--
__
—
--
--
_- __ __ __
—
_.
79855.8 100.00 176052 100.00
Kg/hr 79855.8 Ib/hr 176052
NM3/hr -- SCFM
Kl/hr 79.96 GPM 352
C 110 F 230
atm -- PSIG
9
Steam from WH Boiler
Metric Unit English Unit
Kg.hr Mol.% Ib/hr Mol.%
__
__
.
--
__
__
--
--
— — — ~ -— — —
--
__
76047.5 100.00 167668 100.00
Kg/hr 76052.9 Ib/hr 167668
NM3/hr -- SCFM
Kl/hr -- GPM
C 262 F 503
atm 47.6 PSIG 685

-------
TABLE B-l (Continued)
Stream No.
Description

Composition
C
H
N
S
0
Cl
Ash
CO
CO,
H2
N2
H2S
COS
H20
02
so2
TOTAL

Raw
Metric
Kg/hr
1745.4
..
--
--
--
--
3539.8
£. C. It O
U J / JLi.
18301.5
2643.5
1083.2
845.5
108.9
27397
.-
—

10


Gas to Scrubber
Unit
Mol.7o
--
--
--
--
--
--
--
41.44
7.35
23.17
0.68
0.46
0.034
26.86
--
--

Kg/hr 121377.6
NM3/hr 133951

Temperature
Pressure
Kl/hr
C
atm
--
177
1.47
English
Ib/hr
3848
--
--
--
—
--
7804
144872
40348
5828
2388
1864
240
60400
--
--

Ib/hr
SCFM
GPM
F
PSIG
Unit
Mol.7o
--
--
--
--
--
--
--
41.44
7.35
23.17
0.68
0.46
0.034
26.86
--
--

263052
78832
--
350
6.Q

11
Gas to Gas
Metric
Kg/hr
--
--
--
--
--
—
--
65712.8
18301.5
2643.5
1083.2
845.5
108.9
30622
--
--

Kg/hr
NM3/hr
Kl/hr
C
atm
Unit
Mol.7o
--
— '
--
--
--
--
--
40.18
7.12
22.47
0.65
0.44
0.032
29.1
--
—

119318.3
138140
--
77
1.40

Cooler
English
Ib/hr
--
--
--
--
--
--
--
1 /. 1. 0 TO
iH-H-O If.
40348
5828
2388
1864
240
67512
--
—

Ib/hr
SCFM
GPM
F
PSIG


Unit
Mol.7o
--
--
--
--
--
--
--
40.19
7.12
22.47
0.65
0.44
0.032
29.11
—
--

263052
81297
--
170
5.9
12
Scrubber Feed Water
Metric Unit English Unit
Kg/hr Mol.7c Ib/hr Mol.%
-_
--
--
--
--
--
-_
—
__
_-
--
--
--
126579.5 100.00 67512 29.11
--
-_

Kg/hr 126579.5 Ib/hr 279060
NM3/hr -- SCFM
Kl/hr 126.7 GPM 558
C 29 F 85
atm -- PSIG
                                                                         td

-------
TABLE B-l  (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2
H2S
COS
H20
°2
so2
TOTAL
Temperature
Pressure
13

Scrubbing Water Return
Metric Unit
Kg/hr Mo 1.7.
1745.4 1.36
—
_-
_.
_-
__
3539.8 2.75
_-
_.
_.
__
123353.5 95.89
_-
Kg/hr 128638.8
NM3/hr
Kl/hr 123.5
C 49
atm
English Unit
Ib/hr Mo 1.7.
3848 1.36
__
__
__
--
__
7804 2.75
__
-_
__
—
271948 95.89
__
Ib/hr 283600
SCFM
GPM 544
F 120
PSIG

Gas
Metric
Kg/hr
--
—
—
--
--
--
--
65712.8
18301.5
2643.5
1083.2
845.5
108.9
3173.3
--
14


to H?S Removal
Unit
Mol.7.
--
--
—
--
--
--
--
54.37
9.64
30.39
0.88
0.58
0.042
4.08
--
Kg/hr 91868.7
NM3/hr 102095
Kl/hr
C
atm
35
1.34
English Unit
Ib/hr
--
--
--
--
--
--
--
144872
40348
5828
2388
1864
240
6996
--
Ib/hr
SCFM
GPM
F
PSIG
Mol.7.
-- .
--
--
—
--
--
—
54.37
9.64
30.39
0.88
0.58
0.042
4.08
—
202536
60084
95
5
15
CW to Gas Cooler
Metric Unit English Unit
Kg/hr Mol.7. Ib/hr Mol.7.
—
__
—
—
__
--
__
- w
CO
__
_-
921231.6 100.00 2030968 100.00
--
Kg/hr 9121231.6 Ib/hr 2030968
NM3/hr — SCFM
Kl/hr 922.4 GPM 4062
C 29 F 85
atm -- PSIG

-------
TABLE B-l (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2
N2
H2S
COS
H20
°2
so2
TOTAL
Temperature
Pressure

Gas Cooler
Metric Unit
Kg/hr Mol.
__
__
—
__
--
__
—
__
—
__
948681.2 100.
—
Kg/hr 948681.2
NM3/hr
Kl/hr 949.9
C 49
atm
16
Effluent Water
English Unit
% Ib/hr Mol.%
—
—
—
—
—
__
—
__
__
—
00 2091484 100.00
—
Ib/hr 2091484
SCFM
GPM 4183
F 120
PSIG


Metric
Kg/hr
—
--
--
—
--
—
—
--
2075.6
865.6
--
--
--
Kg/hr
NM^/hr
Kl/hr
C
atm
17
Glaus Plant Feed
Unit English Unit
Mol.% Ib/hr Mol.%
_-
--
__
__
--
__
--
__
65.00 4576 65.00
35.00 1908 35.00
—
—
—
2941.1 Ib/hr 6484
1717 SCFM 1010
GPM
35 F 95
PSIG


Metric
Kg/hr
--
--
--
—
__
—
—
65712.8
16303.9
2643.5
1083.2
41.7
—
2062.9
—
Kg/hr
NM3/hr
Kl/hr
C
atm

Clean
Unit
Mol.%
--
--
--
--
--
--
--
56.10
8.86
31.35
0.92
0.03
—
2.74
--
87848
98961
27
1.24
18
Gas
English Unit
Ib/hr Mol.%
--
-_
—
-_
_-
__
__
144872 56.10
35944 8.86
5828 31.35
2388 0.92
92 0.03
_-
4548 2.74
—
Ib/hr 193672
SCFM 58240
GPM
F 80
PSIG 3.5

-------
TABLE B-l (Continued)
Stream No. 19
Dosr.ripUnn Sulfur By-Product
Metric Unit English Unit
Composition Kg/hr Mol.% Ib/hr Mol.%
C
H
N
S 772.9 100.00 772.9 100.00
0
Cl
Ash
CO
co2
H2
N2
H2S - 	
cos
H20 " 	
°2 	
so2
TOTAL
Kg/hr 772.9 Ib/hr 1704
NM3/hr -- SCFM
Kl/hr -- GPM
Temperature C — F
Pressure atm — PSIG

Clean Gas to
Metric Unit
Kg/hr Mol.%
__
—
—
__
--
—
__
3655.9 56.10
907.2 8.86
146.9 31.35
59.9 0.92
1.8 0.03
—
114.3 2.74
—
__ --

Kg/hr 4886
NM3/hr 5505
Kl/hr --
C 27
atm 1.24
20
Air Heater
English
Ib/hr
—
—
--
--
--
--
—
8060
2000
324
132
4
—
252
--
--

Ib/hr
SCFM
GPM
F
PSIG


Unit
Mol.%
—
--
--
—
—
--
—
56.10
8.86
31.35
0.92
0.03
—
2.74
—
--

10772
3240
__
80
35

21
Clean Gas to
Metric
Kg/hr
—
--
—
—
--
—
—
62056.9
15396.7
2496.6
1023.3
39.9
--
1948.6
—
--

Kg/hr
NM3/hr
Kl/hr
C
atm
Unit
Mol.%
--
--
--
--
--
—
--
56.10
8.86
31.35
0.92
0.03
--
2.74
--
__

82962
93456
—
27
1.24


Compressor
English
Ib/hr
--
--
--
--
--
--
—
136812
33944
5504
2256
88
—
4296
—
— —

Ib/hr
SCFM
GPM
F
PSIG
Unit
Mol.%
--
—
—
—
--
--
—
56.10
8.86
31.35
0.92
0.03
--
2.74
—
__

182900
5500
--
80
35
                                                                           I
                                                                          oo

-------
TABLE B-l  (Continued)
Stream No.
Description

Composition
C
H
N
S
0
Cl
Ash
CO
C02
N2
COS
H20
°2
so2
TOTAL


Temperature
Pressure
22
Hot
Metric Unit
Kg/hr Mol.%
__
__
—
__
—
__
__
__
6651.5 2.12
154620.6 77.58
__
1429.7 1.12
43693.7 19.18
0.9 .0009

Kg/hr 206395.4
NM3/hr 168438
Kl/hr
C 260
atm

Air


English Unit
Ib/hr
--
--
—
--
—
--
—
—
14664
340880
—
3152
96328
2

Ib/hr
SCFM
GPM
F
PSIG
Mol.%
—
—
—
--
—
—
—
—
2.12
77.58
—
1.12
19.18
.0009

455024
99128
••—
500
— —
23
Air to Air
Metric Unit
Kg/hr Mol.%
__
—
__
_-
—
—
__
—
--
154558.9 79.00
—
__
46952.2 21.00
__ __

Kg/hr 201511.1
NM3/hr 165339
Kl/hr
C
atm

Heater
English Unit
Ib/hr Mol.%
__
—
__
__
__
—
—
—
__ __
340744 79.00
__
__
103512 21.00
_ _ — -

Ib/hr 4442 56
SCFM 97304
GPM
F "
PSIG

24


Effluent from Coal Preparation
Metric Unit
Kg/hr
—
—
--
—
—
—
—
—
6651.5
154670.6
—
18274.3
43693.6
— —

Kg/hr
NM3/hr
Kl/hr
C
atm
Mol.%
--
--
--
—
--
--
--
--
1.88
68.57
—
12.59
16.96
— —

223040
190555
. —
74
•" ~
English Unit
Ib/hr
--
--
—
—
--
—
--
—
14664
340880
--
40288
96328
— —

Ib/hr
SCFM
GPM
F
PSIG
Mol.%
—
--
—
—
--
--
—
—
1.88
68.57
--
12.59
16.96
— —

492160
112144
_ «•
165
•• ~

-------
TABLE B-l  (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2
H2S
COS
H20
°2
so2
TOTAL
Temperature
Pressure
25
Slowdown Water
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
--
__
—
__
—
__
__
__
__
;; ; ;; ;;
—
__
709.4 100.00 1564 100.00
._
_« -> •• » -• -•
Kg/hr 709.4 Ib/hr 1564
NM3/hr — SCFM
Kl/hr 0.71 GPM 3
C F
atm -- PSIG
26
B lowdown
Metric Unit
Kg/hr Mol.%
__
—

__
__
—
__
—
—

—
--
3802.9 100.00
__
_ _ « •»
Kg/hr 3802.9
NM3/hr --
Kl/hr 3.81
C
atm

Water
English Unit
Ib/hr Mol.%
—
__
--
—
—
—
—
—
_-

—
__ __
8384 100.00
__
« •• « »
Ib/hr 8384
SCFM
GPM 17
F
PSIG
27
Slug to Filter
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
—
—
-- -- -- --
—
--
—
3539.8 50.00 7804 50.00
__
__

—
—— — -• —— ™~
3539.8 50.00 7804 50.00
—
	
Kg/hr 7079.6 lb/hr 15608
NM3/hr -- SCFM
Kl/hr -- GPM
C 49 F 120
atm ~~ PSIG
                                                                             I
                                                                            h-4
                                                                            O

-------
TABLE B-l  (Continued)
Stream No.


Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2
N2
H2S
COS
H20
°2
so2
TOTAL


Temperature
Pressure
28
Cooling Water
Metric Unit
Kg/hr Mol.%
__
—
__
__
__
__
--
—
__
— — — —
__ __
— — — —
_-
77571.5 100.00
—
"

Kg/hr 77571.5
NM3/hr
Kl/hr 77.67
C 29
atm

to Quench Tank
English Unit
Ib/hr Mol.%
__
__
__
__
__
--
-_
__
__
••— ——
->. — —
» w •• ••
-- --
171016 100.00
__ __


Ib/hr 171016
SCFM
GPM 342
F 85
PSIG
29
Water to Clarifier
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
__
-- -- -- --
•• •• — — ••-• •• —
--
__
__
— .
__. -- — --
— — — — — — — —
••« ^^ ~™ ^««
•• m* tm _ ^^ ^ "•
"
•••• M« •••• ^ tmt
74031.7 100.00 163212 100.00
—


Kg/hr 74031.7 ib/hr 163212
NM3/hr " SCFM
Kl/hr 74.12 GPM 326
C 49 F 120
atm -- PSIG

Slurry
Metric Unit
Kg/hr Mol.%
__
_•» _ «
™ ™ ~ *™
-- --
--
--
3539.8 20.09
-- --
•""• ™ *"
""
"

^ <• •• _
12332.3 70.00
__


Kg/hr 17617.5
NM3/hr
Kl/hr 12.4
C 29
atm
30
to Filter
English Unit
Ib/hr wt%
__
— •• « .
— — « ••
-- --
--
-_
7804 20.09
-- --
— — — —
"
""
-
— — ^ —
27188 70.00
-_


Ib/hr 38840
SCFM
GPM 54.4
F 85
PSIG

-------
TABLE B-l  (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2
N2
COS
H20
°2
so2
TOTAL
Temperature
Pressure
31
Slag
Metric Unit English Unit
Kg/hr wt% Ib/hr wt%
1745.5 17.80 3848 17.80
--
__
_-
__
—
7079.6 72.20 15608 72.20
__
_.
—
979.8 10.00 2160 10.00
__
Kg/hr 9804.8 ib/hr 21616
NM-Vhr — SCFM
Kl/hr -- GPM
C F
atm — PSIG
32
Water from Filter
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
__
__
_-
—
._
__
—
—
—
__
14892.3 100.00 32832 100.00
—
Kg/hr 14892.3 ib/hr 32832
NM3/hr — SCFM
Kl/hr 14.9 GPM 66
C 29 F 85
atm -- PSIG
33
Water to Cooling Tower
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
_-
—
—
—
—
—
—
__
__
—
50122 100.00 110500 100.00
—
Kg/hr 50122 ib/hr 110500
NM3/hr *••<• SCFM
Kl/hr 50.2 GPM 221
C 29 F 85
atm -- PSIG

-------
TABLE B-l (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Cl
Ash
CO
co2
H2
H,>S
COS
H20
°2
so2
TOTAL
Temperature
Pressure
34
Make-Up Water
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
—
._
__
__
—
—
__
__
—
__
__
31751.5 100.00 70000 100.00
• *» —~ — — — ••

Kg/hr 31751.5 Ib/hr 70000
NM-Vhr — SCFM
Kl/hr 31.8 GPM 85
C F
atm -- PSIG

35


Clean Fuel Gas
Metric Unit
Kg/hr
--
--
—
—
—
—
—
62056.9
•15396.7
2496.6
1023.3
39.9
—
968.9
~ ••

Kg/hr
NM3/hr
Kl/hr
C
atm
Mol.%
--
—
--
—
—
--
—
56.88
8.98
31.79
0.94
0.03
--
1.38
*•••

81982.3
92171.4
16
6.44
English Unit
Ib/hr
—
—
—
--
—
«
—
136812
33944
5504
2256
88
—
2136
*™ "*

Ib/hr
SCFM
GPM
F
PSIG
Mol.%
—
--
—
--
--
__
—
56.88
8.98
31.79
0.94
0.03
--
1.38
"*™

180740
54244
60
80
                                                       w
                                                       I

-------
                                                                                              »-Clean gas
preparation
                                            Scrubberv-s  Cooler
                                              *'     (7)     «
  Coal storage

           •—S.
           l3)Cooling water
                                                       Tar oil
                                                      separator
Ammonia  ,
stripping
15) Makeup water
                                                                                                                to
                 Cooling pond
                 FIGURE B-2.  WELLMAN-GALUSHA/STRETFORD GASIFICATION PLANT MATERIAL
                              BALANCE  FOR MODEL REFINERY PLANT

-------
TABLE B-2.  WELLMAN-GALUSHA/STRETFORD GASIFICATION PLANT MATERIAL BALANCE
            FOR MODEL REFINERY PLANT
                       (Metric and English Units')
Stream No.
Description
Composition
C
H
N
S
0
Ash
CO
C02
CH4
H2S
Phenols
Tar
H20
°2
TOTAL
Temperature
Pressure
1

1
Coal as Received
Metric Unit
Kg/hr wt70
7711.1 68.0
544.3 4.8
238.1 2.1
442.3 3.9
771.1 6.8
952.5 8.4
—
— — __
: ::
__
—
—
680.4 6.0
__ __
Kg/hr 11339.8
NM3/hr
Kl/hr
C 25
atm
English
Ib/hr
17000
1200
525
975
1700
2100
—
— ~
;;
_-
—
—
1500
--
Unit
wt%
68.0
4.8
2.1
3.9
6.8
8.4
—
• —
—
--
--
--
6.0
--
Ib/hr 25000
SCFM
GPM
F
PSIG
77
—


Metric
Kg/hr
1233.8
87.1
38.1
70.8
123.4
152.4
--
-*•
—
--
—
—
108.9
--

Coal
Unit
Wt70
68.0
4.8
2.1
3.9
6.8
8.4
—
••••
V M
--
	
	
6.0
— —
Kg/hr 1814.4
NM-Vhr
Kl/hr
C
atm
25
--
2
Fines
English
Ib/hr
2720
192
84
975
272
336
—
•""
^ ^
--
—
—
240
— —


Unit
wt7o
68.0
4.8
2.1
3.9
6.8
8.4
--
•• ~
•• *•
--
—
—
6.0
— —
Ib/hr 4000
SCFM
GPM
F
PSIG
77
--

3
Coal Feed to
Metric Unit
Kg/hr
6477.
457.
200.
371.
647.
800.
--
™~
—
--
—
--
571.
— —
Kg/hr
NM3/hr
Kl/hr
C
atm
wt7o
3 68.0
2 4.8
0 2.1
5 3.9
7 6.8
1 8.4
--
~ ~
— —
--
—
--
5 6.0
--
9575.4
25
--

Gasifier
English
Ib/hr
14280
1008
441
156
1428
1764
—
~~
—
--
--
--
1260
--


Unit
wt7o
68.0
4.8
2.1
3.9
6.8
8.4
—
— -
;;
--
—
—
6.0
--
Ib/hr 21000
SCFM
GPM
F
PSIG
77
—

-------
TABLE B-2 (Continued)
Stream No.
Description
Composition
C
II
N
S
0
Ash
CO
co2
CH,
N2
NH3
Phenols
Tar
H20
02
TOTAL
Temperature
Pressure
4
Air and
Metric Unit
Kg/hr Mo 1.7.
—
—
—
-_
—
—
—
•••• ••••
_-
19186.0 59.01
—
—
5292.5 25.30
5828.7 15.69
Kg/hr 30307.2
NM3/hr 27474
Kl/hr
C 66
atm

Steam
English Unit
Ib/hr Mo 1.7.
_-
—
__
_..
—
—
_-
M •• • •
—
42298 59.01
—
—
11668 25.30
12850 15.69
Ib/hr 66816
SCFM 16169
GPM
F 150
PSIG


5
Hot Raw
Metric Unit
Kg/hr
9.1
—
--
—
—
79.8
11383.8
2126.0
421.9
615.5
19300.8
99.3
389.2
54.4
475.4
4075.5
•-r
Kg/hr
NM-Yhr
Kl/hr
C
atm
Mbli.7.
—
—
--
—
—
—
24.86
2.95
12.77
2.35
42.17
0.36
0.70
—
—
13.84
—
39030.7
38681
360
— —

Gas
English Unit
Ib/hr Mo 1.7.
20
—
—
—
—
176
25097 24.86
4687 2.95
930 12.77
1357 2.35
42551 42.17
219 0.36
858 0.70
120
1048
8985 13.84
—
Ib/hr 86048
SCFM 22764
GPM
F 680
PSIG
6
Ash
Metric Unit English Unit
Kg/hr wt7. Ib/hr wt70
81.7 10.18 180 10.18
—
—
—
—
720.3 89.82 1588 89.82
—
MM «— « •» M —
	
—
_-
	
__
	
Kg/hr 802.0 lb/hr 1768
NM3/hr — SCFM
Kl/hr " GPM
C F —
atm -- PSIG

-------
TABLE B-2 (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Ash
CO
CO-
CH4
N2
NH3
Phenols
Tar
H20
02
TOTAL
Temperature
Pressure
7
Gas to Gas
Metric Unit
Kg/hr Mol.7.
..
__
—
__
-_
—
11383.8 23.90
2126.0 2.84
421.9 12.30
615.5 2.26
19300.8 40.60
389.2 0.67
—
—
5320.6 17.39
—
Kg/hr 39557.8
NM-Vhr 40178
Kl/hr
C 57
atm

Cooler
English
Ib/hr
--
—
--
—
—
-_
25097
4687
930
1357
42551
858
—
--
11730
—
Ib/hr
SCFM
GPM
F
PSIG


Unit
Mol.7.
—
—
—
—
--
—
23.94
2.84
12.30
2.26
40.60
0.67
—
—
17.39
—
87210
23645
135
*••
8
Scrubbing Water
Metric Unit English Unit
Kg/hr Mol.7. Ib/hr Mol.7.
—
--
—
—
—
__
--
__ — — — — — —
__
__
—
—
69313.5 100.00 152810 100.00
--
Kg/hr 69313.5 Ib/hr 152810
NM^/hr ~ SCFM
Kl/hr 69.4 GPM 68.8
C 25 F 77
atm -- PSIG
9


Scrubbing Water Return
Metric Unit
Kg/hr wt7o •
9.1 0.01
-- --
__
--
—
79.8 0.12
—
__ __
—
99.3 0.14
54.4 0.08
475.4 0.69
68068.4 98.96
—
Kg/hr 68786.4
NM3/hr
Kl/hr 77
C 53
atm
English Unit

Ib/hr wt7.
20 0.
-_
_-
--
—
176 0.
—
-_
__
219 0.
120 0.
1048 0.
150065 98.
—
Ib/hr 151648
SCFM
GPM 127
F 127
PSIG
01
-
-
-
-
12
-
_
-
14
08
69
96
-



                                                                         OS
                                                                          I

-------
TABLE  B-2 (Continued)
Stream No.
Description Gas
10
to Sulfur Removal
Metric Unit English Unit
Composition Kg/hr
C
H
N
S
0
Ash
CO 11383.8
C02 2126.0
H2 421.9
CH4 615.5
N2 19300.8
NH3
H2S 389.2
Phenols
Tar
H20 1499.6
°2
TOTAL Kg/hr 35736
NM3/hr 35160
Kl/hr
Temperature C 35
Pressure atm
Mol.T, Ib/hr Mol.70
—
__
—
_>
__
—
27.35 25097 27.35
3.25 4687 3.25
14.06 930 14.06
2.58 1357 2.58
46.39 42551 46.39
0.77 858 0.77
-_
__
5.60 3306 5.60
.7 Ib/hr 78786
SCFM 20692
GPM
F 95
PSIG —
11
Cooling Water
Metric Unit English Unit
Kg/hr Mol.7o Ib/hr Mol.7»
_-
—
—
__
—
—
—
__
—
MM «_ _» ••-•
	
	
125928.6 100.00 277625 100.00
Kg/hr 125928.6 Ib/hr 277625
NM3/hr -- SCFM
Kl/hr 126.1 GPM 555
C 25 F 77
atm — • PSIG
12
Cooling Water Return
Metric Unit English Unit
Kg/hr Mol.7o Ib/hr Mol.T,
—
—
—
__
__
—
—
—
—
__ __ — _ — —
_.
—
129749.6 100.00 286049 100.00
Kg/hr 129749.6 Ib/hr 286049
NM3/hr — SCFM
Kl/hr 129.9 GPM 572
C 53 F 127
atm -- PSIG
                                                                            I
                                                                           I-"
                                                                           oo

-------
TABLE  B-2 (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Ash
CO
co2
N2
NH3
Phenols
Tar
H20
02
TOTAL
Temperature
Pressure
13
Tar
Metric Unit
Kg/hr wt%
422.8 80.83
36.7 7.03
3.6 0.69
5.5 1.04
6.8 1.30
—
—
•"~ — ••
—
—
_.
47.6 9.11
—
Kg/hr 523
NM-Vhr
Kl/hr
C 25
atm


English Unit
Ib/hr wtT,
932 80.83
81 7.03
8 0.69
12 1.04
15 1.30
—
—
—
__
__
—
105 9.11
—
Ib/hr 1153
SCFM
GPM
F 77
PSIG
14
Ammonia
Metric Unit
Kg/hr wt7o
—
__
—
—
—
—
—
MM MM
99.3 20.00
—
__
397.4 80.00
—
Kg/hr 496.7
NM-Vhr
Kl/hr 0.42
C 25
atm

Solution
English Unit
Ib/hr wt70
__
__
—
—
—
—
__
M M •• M
219 20.00
—
—
876 80.00
__
Ib/hr 1095
SCFM
GPM 2
F 77
PSIG
15
Phenols
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mo 1.7.
—
—
-:_
—
—
--
--
—
-_
54.4 — 120
-_ __ __ __
--
"•• — •• — *• "• ••
Kg/hr 54.4 Ib/hr 120
NM3/hr — SCFM
Kl/hr -- GPM
C F
atm -- PSIG
                                                                           tri
                                                                           I

-------
TABLE B-2 (Continued)
Stream No.
Description
Composition
C
H
N
S
0
Ash
CO
co2
N24
NH3
H2S
Phenols
Tar
H20
02
TOTAL
Temperature
Pressure
16
Water to Gasifier Jacket
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
__
__
—
__
—
—
—
-- -- -- --
—
— — ~~ "•• •"•
--
-- -- -— --
__
64259.5 100.00 141668 100.00
>.
Kg/hr 64259.5 Ib/hr 141668
NMP/hr -- SCFM
Kl/hr 64.3 GPM 283
C 25 F 77
atm — PSIG

Water from
Metric Unit
Kg/hr Mol
—
__
—
__
—
—
—
•»•» ••»
—
__ __
--
-- --
—
58976 100
•_.
Kg/hr 58967
NM3/hr —
Kl/hr 59.0
C 66
atm
17
Gasifier Jacket
English Unit
.% Ib/hr Mol.%
__
—
_-
__
—
__
—
W ~M
__
_— __
__
_-
	
.00 130000 100.00
—
Ib/hr 130000
SCFM
GPM 260
F 150
PSIG
18
Water Loss
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
__
—
—
__
__
—
—
w •• «« «••
^ ^ 
-------
TABLE  B-2  (Continued)
Stream No.
Description
Composition
C
II
N
S
0
Ash
CO
co2
CHA
N2
NH3
H2S
Phenols
Tar
H20
02
TOTAL
Temperature
Pressure
19
Make-Up Water
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
—
__
__
._
__
—
__
MM M M M M MM
__
MM MM •»• MM*
—
	
__
16680.9 100.00 36775 100.00
—
Kg/hr 16680.9 Ib/hr 36775
NM3/hr — SCFM
Kl/hr 16.7 GPM 73.5
C 25 F 77
atm — PSIG
20
Sulfur
Metric Unit English Unit
Kg/hr Mol.% Ib/hr Mol.%
..
—
—
352.4 100.00 777 100.00
__
—
__
MM — — MM MM
—
__ __ __ ._
	
__
__
_.
.__
Kg/hr 352.4 Ib/hr 777
NM3/hr — SCFM
Kl/hr — GPM
C F
atm — PSIG


Metric
Kg/hr
—
._
—
__
—
—
.11383.8
2126.0
421.9
615.5
19300.8
14.5
--
—
444.1
—
Kg/hr
NM3/hr
Kl/hr
C
atm
21
Clean
Unit
Mol.%
--
—
—
--
—
—
28.70
3.41
14.74
2.71
48.67
0.03
—
—
1.74
--
34306.6
33513
16
™~

Gas
English
Ib/hr
—
—
—
--
—
—
25097
4687
930
1357
42551
32
—
—
979
—
Ib/hr
SCFM
GPM
F
PSIG


Unit
Mol.%
--
—
—
—
--
—
28.70
3.41
14.74
2.71
48.67
0.03
—
—
1.74
—
75633
19723
60
M -.
                                                                            i
                                                                           IS5

-------
                                TECHNICAL REPORT DATA
                          (Please read Inurucnons on the reverse before completing)
1. REPORT NO.
 EPA-600/2-76-102
2.
                           3. RECIPIENT'S ACCsSSIOf»NO.
A. TITLE AND SUBTITLE
 Environmental Aspects  of Retrofitting Two Industries
 to Low- and Intermediate-Energy Gas from Coal
                           5. REPORT DATE
                            April 1976
                           6. PERFORMING ORGANIZATION CODE
7-AUTHOR(S)D.A.Ball,  A.A.Putnam, D.W. Hiss ong,
 J.Varga, B.C.Hsieh, J.H. Payer,  and. R. E. Barrent
                           8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
 Battelle-Columbus Laboratories
 505 King Avenue
 Columbus,  Ohio 43201
                           10. PROGRAM ELEMENT NO.
                           1AB013; ROAP 21BBZ-006
                           11. CONTRACT/GRANT NO.
                            68-02-1843
12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC 27711
                             ?..TYPE OF REPORT
                             inal; 9-11/74
                                                                    AND PERIOD COVERED
                           14. SPONSORING AGENCY CODE
                            EPA-ORD
is. SUPPLEMENTARY NOTES Project officer for this report is W. J. Rhodes, Mail Drop 61,
 Ext 2851.
16
-------