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.
-------
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 agowhen 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.
-------
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.
-------
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.
-------
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.
-------
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.
-------
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
-------
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
-------
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 countryclose 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
-------
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 gassuch 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 capacitiesthat is, Koppers-Totzek, Babcock
& Wilcox, Winkler, and Lurgiwere 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.
-------
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
H
w a
8
C
-I C -,
o /
CO i-l
u u fi
c ra °
c« U
r-l -fl c
a* «w -J
H
IH w ,
o to ^
«
H r-l o
0) CJ J
JD
a ?
3 ^
&
n
-
-
-
t-
[
-
^
.
"
_
[ -
~
-
:-
-
_
~
~~-
-~
i
_
~
-
~
,
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
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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)
-------
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.
-------
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
-------
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.
-------
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
-------
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.
-------
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.
-------
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
-------
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.
-------
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 refinerycatalytic 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
-------
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.
-------
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
-------
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)
-------
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.
-------
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.
-------
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.
-------
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.
-------
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.
-------
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.
-------
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.
-------
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.)
-------
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.
-------
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).
-------
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
-------
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
-------
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.
-------
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
-------
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
-------
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
-------
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.
-------
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.
-------
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
-------
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.
-------
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.
-------
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
-------
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
-------
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.
-------
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
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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 .
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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.
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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 stoichiometricfuel/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
-------
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.
-------
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.
-------
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 )^
-------
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.
-------
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 lossesdefeating 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
-------
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
-------
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
-------
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
-------
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.
-------
153
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(2) A National Plan for Energy Research. Development, and Demonstration;
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(4) Study of Potential Problems and Optimum Opportunities in Retrofitting
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(6) Energy Consumption in Manufacturing. Myers, J.G., et al., a report to
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(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,
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(11) Federal Findings on Energy for Industrial Chemicals, report from International
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(12) Challenge to U.S. Glass Manufacturers in These Energy-Critical Times,
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(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.
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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).
-------
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.
-------
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 thereofin 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 processdelivers 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
------- |