EPA-460/3-74-012-C
July 1974
ALTERNATIVE FUELS
FOR AUTOMOTIVE
TRANSPORTATION -
A FEASIBILITY STUDY
VOLUME III - APPENDICES
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 48105
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EPA-460/3-74-012-C
ALTERNATIVE FUELS
FOR AUTOMOTIVE TRANSPORTATION -
A FEASIBILITY STUDY
VOLUME III - APPENDICES
Prepared by
J. Pangborn, J. Gillis
Institute of Gas Technology
Chicago, Illinois 60616
Contract No. 68-01-2111
EPA Project Officer:
E. Beyma
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Mobile Source Air Pollution Control
Alternative Automotive Power Systems Division
Ann Arbor, Michigan 4biUb
July 1;974
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the Air
Pollution Technical Information Center, Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; or, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22151.
This report was furnished to the Environmental Protection Agency by
The Institute of Gas Technology in fulfillment of Contract No. 68-01-2111
and has been reviewed and approved for publication by the Environmen-
tal Protection Agency. Approval does not signify that the contents
necessarily reflect the views and policies of the agency. The material
presented in this report may be based on an extrapolation of the "State-
of-the-art." Each assumption must be carefully analyzed and conclusions
should be viewed correspondingly. Mention of trade names or commer-
cial products does not constitute endorsement or recommendation for use.
Publication No. EPA-460/3-74-012-C
11
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PREFACE
This report is the result of a research team effort at the Institute of Gas
Technology. In addition to the authors, the major contributors to the study
were J. Fore, P. Ketels, W. Kephart, and K. Vyas.
This report consists of three volumes:
Volume I — Executive Summary
Volume II — Technical Section
Volume III — Appendices.
in
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TABLE OF CONTENTS
Page
SUMMARY 1
APPENDIX A. Properties of Potential Alternative Fuels for
Automotive Transportation 5
Data Sheets for 18 Candidate Fuels 6
Bibliography 42
APPENDIX B. Detailed Process Descriptions and Economics
for Candidate Fuels From Coal and Oil Shale 43
Gasoline and Distillate Fuels From Coal 43
Description of CSF Process 46
Overall Energy Balance and Efficiencies 54
Pollution 54
Economic Analysis 56
Gasoline and Distillate Fuels From Oil Shale 61
Description of Gas Combustion Process 61
Overall Energy Balance and Efficiencies 70
Pollution 70
Economic Analysis 73
Methanol From Coal 77
Description of Koppers-Totzek Gasifier and
ICI Synthesis 78
Overall Energy Balance and Efficiencies 85
Pollution 86
Economic Analysis 87
SNG From Coal 90
Description of Lurgi Process 91
Overall Energy Balance and Efficiencies 98
Pollution 98
Economic Analysis 100
References Cited 103
Bibliography 104
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LIST OF FIGURES
Figure No. Page
B-l Fischerrtropsch Synthesis at Sasolburg 44
B-2 Flow Diagram of CSF-Process Production of
Gasoline (50,000 bbl/Day) From Coal 47
B-3 Flow Diagram of 50,000-bbl/Day Gasoline
Refinery 53
B-4 Flow Diagram for Production of Gasoline and
Light Distillate (50,000 bbl/Day) From Oil Shale 62
B-5 Green River Oil Shale Formation of Colorado,
Utah, and Wyoming 64
B-6 Flow Diagram of Gas Combustion Process
Developed by U. S. Bureau of Mines 66
B-7 Koppers-Totzek Low-Pressure Gasifier 79
B-8 Flow Diagram of Production of Methanol From
Coal 84
B-9 Lurgi Pressure Gasifier 92
B-10 Flow Diagram of Lurgi-Process Production
of SNG (288.6 million SCF/Day) From Coal 94 .
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LIST OF TABLES
Table No. Page
1 Selected Properties of 18 Fuels 2
2 Pattern Synthesis Processes and Fuel Costs 3
B-l Typical Products of SASOL Process 45
B-2 Product Yield of SASOL Process 45
B-3 Composition of Gaseous Streams From CSF Process 50
B-4 Composition of Liquid Streams From CSF Process 51
B-5 Composition of Solid Streams From CSF Process 52
B-6 Energy Balance for CSF-Process Coal-to-Gasoline
(50,000 bbl/Day) Plant 54
B-7 Sulfur Balance for CSF-Process Coal-to-Gasoline
Plans (50,000 bbl/Day) 55
B-8 Wastes, Sources, and Treatments for a Coal-to-
Gasoline Plant 55
B-9 Investment Cost for CSF-Process Coal-to-Gasoline
(50,000 bbl/Day) Plant 57
B-10 Operating Cost for CSF-Process Coal-to-Gasoline
(50, 000 bbl/Day) Plant (90% Stream Factor) 58
B-ll Calculation for Determining Unit Production
Cost by DCF Method for CSF Process Coal-to-
Gasoline (50,000 bbl/Day) Plant 59
B-12 Calculation for Determining Unit Production Cost by
DCF Method for CSF-Process Coal-to-Gasoline-
Plus-Distillate-Oil (50,000 bbl/Day) Plant 59
B-13 Process Streams From Production of Gasoline and
Distillate Fuels From Oil Shale 63
B-14 Current Oil-Shale-Retorting Technology 65
B-15 Typical Retorting Product Yields 68
B-16 Properties of Typical Crude Shale Oil 68
B-17 Properties of Typical Syncrude 69
B-18 Energy Balance for Production of 50,000 bbl/Day
of Gasoline and Light Distillate From 30gal/Ton
Colorado Oil Shale 70
ix
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LIST OF TABLES, Cont.
Table No. Page
B-19 Sulfur Balance for Production of 50,000 bbl/Day
of Gasoline and Light Distillate From 30 gal/Ton
Colorado Oil Shale 71
B-20 Wastes, Sources, and Treatments for an Oil-Shale-
to-Gasoline Plant 72
B-21 Investment Cost for the Production of 50,000 bbl/Day
of Gasoline Plus Light Distillate From 30 gal/Ton
Colorado Oil Shale 74
B-22 Operating Cost for the Production of 50,000 bbl/Day
of Gasoline Plus Light Distillate From 30 -gal/Ton
Colorado Oil Shale 75
B-23 Calculation for Determining Unit Production Cost
by DCF Method for 50,000 bbl/Day of Gasoline
Plus Light Distillate From 30 gal/Ton Colorado
Oil Shale 76
B-24 Components Expected in Crude Methanol 81
B-25 Composition of Gaseous Streams From a Coal-to-
Methanol From a (5000 Ton/Day) Plant 82
B-26 Composition of Solid Streams From a Coal-to-
Methanol (5000 Ton/Day) Plant 83
B-27 Composition of Product From a Coal-to-Methanol
(5000 Ton/Day) Plant 85
B-28 Energy Balance for a Coal-to-Methanol (5000 Ton/Day)
Plant 85
B-29 Sulfur Balance for a Coal-to-Methanol (5000 Ton/Day)
Plant 86
B-30 Wastes, Sources, and Treatments for Coal-to-Methanol
Plant 87
.B-31 Investment Cost for Coal-to-Methanol (5000 Ton/Day)
Plant Using Koppers-Totzek Gasification and ICI
Methanol Processes 88
B-32 Operating Cost for Coal-to-Methanol (5000 Ton/Day)
Plant Using Koppers-Totzek Gasification and ICI
Methanol Processes 89
B-33 Calculation for Determining Unit Production Cost by
DCF Method for a Coal-to-Methanol (5000 Ton/Day)
Plant 89
x
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LIST OF TABLES, Cont.
Table No. Page
B-34 Composition of Gaseous Streams From a Coal-to-
SNG (Z88.6 Million SCF/Day) Plant 95
B-35 Composition of Solid Streams From a Coal-to-SNG
(288.6 Million SCF/Day) Plant 96
B-36 Composition of Liquid Streams From a Coal-to-SNG
(288.6 Million SCF/Day) Plant 96
B-37 Energy Balance for Coal-to-SNG (288.6 Million
SCF/Day) Plant 98
B-38 Sulfur Balance for a Coal-to-SNG (288.6 Million
SCF/Day) Plant 99
B-39 Wastes, Sources, and Treatments for a Coal-to-
SNG Plant 100
B-40 Investment Cost for Lurgi-Process Coal-to-SNG
(288.6 Million SCF/Day) Plant 101
B-41 Operating Cost for Lurgi-Process Coal-to-SNG
(288.6 Million SCF/Day) Plant 102
B-42 Calculation for Determining Unit Production Cost by
DCF Method for a Lurgi-Process Coal-to-SNG (288.6
Million SCF/Day) Plant 103
XI
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SUMMARY
This volume contains two appendices:
A.. Properties of Potential Alternative Fuels for Automotive Transportation
B. Detailed Process Descriptions and Economics for Candidate Fuels From
Coal and Oil Shale
As a summary of the complete data sheets given in Appendix A, the
pertinent properties of 18 fuels are summarized in Table 1. In the case of
coal, a relatively clean, solvent-refined coal would be required for automotive
use, but for the sake of characterization, an Illinois coal (raw) is described
here. [The technical section (Volume II) of this report considers solvent-
refined coal. ] Hydrazine is included because it is a fuel for fuel cells; direct
or flame combustion in a heat engine is not implied. Many vegetable oils
are (theoretically) useful as engine fuels (in external combustion, heat-engine
cycles), so we have tabulated the properties of cottonseed oil as an example
because there were sufficient data for characterization.
Appendix B presents detailed process descriptions for gasoline and
distillate oils from coal, gasoline and distillate oils from oil shale, methyl
alcohol from coal, and substitute natural gas (SNG) from coal. Either these
processes are at or near commercialization, or sufficient data on the components
of these processes have been published to allow characterization and reasonable
estimates of economics. The economics have been calculated by using discounted
cash flow (DCF) financing in accordance with the method contained in The
Supply-Technical Advisory Task Force — Synthetic Gas-Coal. The described
processes are "pattern" processes for fuel synthesis, and other processes
would be equally or less favored. Certain portions of the process descriptions
and calculations in Appendix B have been derived from IGT in-house source
material that has been made available to this as well as to other projects.
This information includes personal communications that cannot be referenced.
The synthesized fuels are candidates for use as alternative fuels for automotive
transportation, but they are not necessarily the selected (chosen or recommended)
1 Synthetic Gas-Coal Task Force, The Supply-Technical Advisory Task Force —
Synthetic Gas-Coal. Prepared for the Supply-Technical Advisory Committee,
National Gas Survey, Federal Power Commission, April 1973.
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Table 1. SELECTED PROPERTIES OF 18 FUELS
Fuel
Acetylene
Ammonia
Carbon Monoxide
Coal
Diesel Oil
Ethanol
Fuel Oil (Heavy)
Gasoline
Hydrogen
Hydrazine
Kerosene
Methane
Methanol
Methylamine
Naphtha
Propane
LPG
Vegetable (Cottonseed) Oil
Fuel
Acetylene
Ammonia
Carbon Monoxide
Coal
Diesel Oil
Ethanol
Fuel Oil (Heavy)
Gasoline
Hydrogen
Hydrazine
Methane
Methanol
Methylamine
Naphtha
Propane
LPG
Vegetable (Cottonseed) Oil
Chemical -V
Formula
CjH;
NH,
CO
Mix
Mix :
C;H5OH
Mix 3
Mix
H:
NjH.
Mix !
CH«
CH3OH
CH,NH,
Mix
C,H8
Mist
Mix
Heat of Va^or
ieation ai
Boiling Foin:.
Btu /Ibm
264
584
--
--
155
370
85
130
--
561
14O
219
473
340
145
150
180
--
E.oiecular Melting Boiling Ibrn/cuft Vapor,
Weizht Point, "F Point, °F (77* F, 1 atm) Btu/cu ft
26.04 -114 -119 0.070 1448
17.03 -108 -28 0.045 365
25.01 -341 -313 0.074 322
84
43-240 -- 325-650 53.4
44.07 -179 600-1000 49.0 1451
00-1000 -- 100-400 60.6
55-145 -- -- -45.5
2.02 -431 -423 0.0053 275
•2.05 34.5 236 63.1
Si-230 -- 300-480 50.6
to. 04 -296 -258 0.052 913
52.04 -144 148 49.7 768 •
•1.03 -134 20 0.087 1089
•4-170 -- -- 48 8461
44.09 -306 -44 0.110 2385
•0-60 -- -50 0.117 2399
20-30 338+ 56.9
Least Least Amount Least Amount
Flash Detectable Causing Eye Causing Throat
No' Odor No Irr No Irr
20 40 400
No Odor No Irr No Irr
..
100 25-50
55 10 5000 5000
150 -- ? ?
-36 to -50 10-50a ? ?
No Odor No Irr No Irr
100 -- b
100 25-100a 500-1000 500-1000
No Odor No Irr No Irr
52 100 7 ?
0 0.02 10-50 10-50
20-50 10-50a ? ?
-156 ? a No Irr No Irr
-155 1
486
Liquid ,
Btu/lbm
20,776
8,001
4,347
18,480
11,929
17, 160
19.291
51,623
6,500
19.092
21,520
9,078
12.855
18,864
19,944
20,514
16, 113
Flammability
Limits, Ignition
% in air
2.5-80
15.5-Z6.6
12.5-74.2
--
0.7-5.0
3.3-18.9
--
1.4-7.6
4-74
4.7-100
0.7-5.0
5.0-15.0
6.0-36.5
4.9-20.7
0.9-6.0
2.1-10. 1
2.4-9.6
"
Maximum Allowable
Temp.-'F
581
1204
1128
1100
490
738
765
495
1065
74-518
491
1170
878
806
450-530
808
920-1020
650
Octane Number
fui- G-hr Exposure, Research Motor Cetarie
ppm Method Method Number
d
100
100
-- c
500
1000
500
d
1
500
d
200
10
500
30,000-50
10,000
--
,000
40
111
130+
..
Low Low 40-70
106 89
<0 <0
92-100 84-92 18
130+
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alternatives. The selected fuels depend on th6 needs for supplemental fuel,
as shown by an energy demand and supply projection, and on the application of
a fuel selection procedure, as described in the technical section. Table 2
summarizes the pattern processes and the corresponding fuel synthesis
costs (as of about December 1973).
Table 2. PATTERN SYNTHESIS PROCESSES AND FUEL COSTS
Raw
Material
Coal
Coal
Oil Shale
Coal
Coal
Synthesized
Fuel
Gasoline
Gasoline and
distillate oils
Gasoline and
distillate oils
Methanol
SNG (CH4)
Pattern
Process
Consol synthetic
fuel (CSF) plus
refining with
hydrocracking
Consol synthetic
fuel (CSF) plus
refining with
catalytic
cracking
Gas Combustion
Process (Bureau
of Mines) plus
hydrotreating and
refining
Koppers-Totzek
gasifier and ICI
synthesis
Lurgi gasifier
with methanation
Production Cost (DCF)
Volume Units
$0.33/gal
$ 0. 31 / gal
t0.25/gal
$0.23/gal
$1.84/103 SCF*
Energy Units*
$2.81/106 Btu
$2.51/106 Btu
S2.05/106 Btu
$3.88/10* Btu
$2. 14/106 Btu
Based on the low heating value of the fuel.
A-94-1709
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APPENDIX A. Properties of Potential Alternative
Fuels for Alternative Transportation
Acetylene
Ammbnia
Carbon Monoxide
Coal (and So I vent-Refined Coal)
Diesel Oil
Ethan ol
Fuel (Heavy)
Gasoline
Hydra zine
Hydrogen
Kerosene
Methane
Methanol
Methylamine
Naphtha
Propane
LPG
Vegetable (Cottonseed) Oil
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ACETYLENE
Chemical Formula
C2H2
Molecular Weight
Melting Point
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
NT Volumetric
Air Volumetric
O2 Weight
N2 W-ight
Air Weight
Air for Combustion, Liquid Fuel
Products of Combustion,
COz Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Vapor
26.036
English Units
0.06971 Ib/cu ft
8.276 Ib/cu ft
0.9107
1,499 Btu/cu ft
1,448 Btu/cu ft
21,500 Btu/lb
20,776 Btu/lb
177,934 Btu/cu ft
171,922 Btu/cu ft
21,500 Btu/lb
20,776 Btu/lb
Metric (SI) Units
-81°C
-83°C*
1.117 kg/cu m
132.582 kg/cu m
0.9107
5. 5842 X 104 kJ/cu m
5.394 X 104 kJ/cu m
5.00 X 104kJ/kg
4.8321 X 104kJ/kg
662.854 X 104 kJ/cu m
640.458 X 104 kJ/cu m
5.000 X 104 kJ/kg
4.832 X 104 kJ/kg
lir component per unit of fuel
2. 5 cu ft/cu ft 2. 5 cu m/cu m
9.411 cu ft/cu ft 9.411 cu m/cu m
1 1. 9 11 cu ft/cu ft 11. 9 11 cu m/cu m
3.0731 Ib/lb 3.0731 kg/kg
10. 224 Ib/lb
13.297 Ib/lb
10.224 kg/kg
13.297 kg/kg
it of product per unit of fuel
2 cu ft/cu ft 2 cu m/cu m
1 cu ft/cu ft
9. 41 1 cu ft/cu ft
3.381 Ib/lb
0.692 Ib/lb
10. 224 Ib/lb
1 cu m/cu m
9. 41 1 cu m/cu m
3. 381 kg/kg
0.692 kg/kg
10. 224 kg/kg
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ACETYLENE, Cont.
English Units Metric (SI) Units
Flammability Limits 2. 50-80. 0%
Flash Point
Ignition Temperature 581 °F 305°C
Heat of Vaporization at Boiling Point 264 Btu/lb
Octane Number 40
Research Method
Motor Method
Cetane Number
Toxicity
Least Detectable Odor No odor
Least Amount Causing Eye Irritation No irritation ,
Least Amount Causing Throat Irritation No irritation
Least Amount Causing Coughing No coughing
Maximum Allowable for Prolonged Exposure Simple asphyxiant in high concn
Maximum Allowable for Short Exposure (0. 5 hr) 100 mg/liter
Dangerous for Short Exposure (0. 5 hr) 100 mg/liter
Comments
Normal transportation is by furnished air cylinders packed with asbestos
fibers and dissolved in acetone at about 250 psi pressure. Also generated
onsite from reaction between calcium carbide and water in self-regulating
generators similar in principle to "Kipp" generators. As a gas under
pressure, acetylene may decompose violently. The free gas should never
be used, transported, or stored outside of its special cylinders at pressures
in excess of 2 atmospheres.
^Sublimes at 1 atmosphere.
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Chemical Formula
AMMONIA
NH3
Molecular Weight
Melting Point
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
17.031
English Units
-108°F
-28° F
0.0456 Ib/cu ft
48. 1 Ib/cu ft
0.5961
0.674
441. 1 Btu/cu ft
365. 1 Btu/cu ft
9668 Btu/lb
8001 Btu/lb
465.031 Btu/cu ft
384.848 Btu/cu ft
9668 Btu/lb
8001 Btu/lb
Metric (SI) Units
-77.7°C
-33.35°C
0.721 kg/cu m
77.056 kg/cu m
0.5961
0.674
1.6432 X 104 kj/cu m
1.3068 X 104 kj/cu m
2.2249 X 104 kJ/kg
1.8609 X 104 kJ/kg
1721 X 104 kl/cu m
1434 X 104 kJ/cu m
2.2249 X 104kJ/kg
1.8609 X 104 kJ/kg
-air component per unit of fuel-
0.75 cu ft/cu ft
2.823 cu ft/cu :ft
3. 579 cu ft/cu ft
1.409 Ib/lb
4.688 Ib/lb
6.097 Ib/lb
0.75 cu m/cu m
2. 823 cu m/cu m
3. 579 cu m/cu m
1.409 kg/kg
4.688 kg/kg
6.097 kg/kg
-air component per unit of fuel-
801. 7 cu ft/cu ft
3017. 5 cu ft/cu ft
3819.2 cu ft/cu ft
1.409 Ib/lb
4.688 Ib/lb
6,. 097 Ib/lb
801. 7 cu m/cu m
3017. 5 cu m/cu m
3819.2 cu m/cu m
1.409 kg/kg
4.688 kg/kg
6.097 kg/kg
--unit of product per unit of fuel-
1. 5 cu ft/cu ft
3.323 cu ft/cu ft
1. 587 Ib/lb
5.511 Ib/lb
1.5 cu m/cu m
3. 323 cu m/cu m
1.587 kg/kg
5.511 kg/kg
8
-------
AMMONIA. Corit.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight,
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
unit of procfuct per unit of fuel-
1603. 3 cu ft/cu ft 1603. 3 cu m/cu m
3551.9 cu ft/cu ft 3551. 9 cu.m/cu m
1.587 Ib/lb
5.Ill Ib/lb
15.50-26.60%
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization at Boiling Point 584.4 Btu/lb
1204°F
Octane Number
Research Method >111
Motor Method
Cetane Number
Toxicity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0.5 hr)
Comments
1.587 kg/kg
5.111 kg/kg
651°C
1356 kJ/kg
20 ppm
40 ppm
400 ppm
400 ppm
0.076 mg/liter 100 ppm
700 ppm
1700 ppm
Normal transportation is in cylinders as a liquid, in tank cars, trucks,
and pipelines. At concentrations of 100 ppm in air, there is noticeable
irritation to the eyes and nasal passages.
-------
Chemical Formula
CARBON MONOXIDE
CO
Molecular Weight
Melting Point
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
.Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
Oz Volumetric
N2 Volumetric
Air Volumetric
02 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
28.01
English Units
-340. 6°F
-312.7°F
0.0740 Ib/cu ft
6.268 Ib/cu ft
0.9672
321.8 Btu/cu ft
321.8 Btu/cu ft
4347 Btu/lb
4347 Btu/lb
27,264 Btu/cu ft
27,264 Btu/cu ft
4347 Btu/lb
4347 Btu/lb
Metric (SI) Units
-207°C
-191. 5UC
1.186 kg/cu m
100.41 kg/cu m
0.9672
1. 1988 X 104 kJ/cu m
1. 1988 X 104kJ/cu m
1.0110 X 104kJ/kg
1.0110 X 104 kJ/kg
6.341 kJ/kg
6.341 kJ/kg
1.011X 104 kJ/kg
1.011X 104 kJ/kg
-air component per unit of fuel-
5 cu ft/cvi ft
882 cu ft/cu ft
382 cu ft/cu ft
571 Ib/lb
900 Ib/lb
2.471 Ib/lb
0. 5 cu m/cu m
1.882 cu m/cu m
2. 382 cu m/cu m
0.571 kg/kg
1.900 kg/kg
2.471 kg/kg
-air component per unit of fuel-
42. 30 cu ft/cu ft
160. 1 cu ft/cu ft
202.4 cu ft/cu ft
0.571 Ib/lb
1.900 Ib/lb
2.471 Ib/lb
42. 30 cu m/cu m
160. 1 cu m/cu m
202. 4 cum/cu m
0.571 kg/kg
1.900 kg/kg
2.471 kg/kg
-unit of product per unit of fuel-
1.0 cu ft/cu ft
1.882 cu ft/cu ft
1.571 Ib/lb
1.900 Ib/lb
1. 0 cu m/cu m
1.882 cu m/cu m
1.571 kg/kg
1.900 kg/kg
10
-------
CARBON MONOXIDE, Cont.
English Units
Metric (SI) Units
160. 1 cu ft/cu ft
1.571 Ib/lb
1.900 Ib/lb
12. 5-74.2%
1128°F
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization
Octane Number
Research Method
Motor Method
Cetane Number
Toxicity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0.5 hr)
Comments
init of product per unit of fuel-
53. 45 cu ft/cu ft 53. 45 cu rri/cu m
130+
160. 1 cu m/cu m
1.571 kg/kg
1.900 kg/kg
608. 9°C
No odor
No irritation
No irritation
No coughing
100 ppm
400 ppm
1500 ppm
Normal transportation is in cylinders under pressure. Continued exposure
to concentrations of carbon monoxide greater than 100 ppm in air will cause
headache, palpitation of the heart, confusion of mind, and nausea. Doses
above 0.3% (in air) for 1 hr or more are often fatal.
11
-------
COAL (Northern Illinois, ASTM Rank-Class II, Group 5)
Chemical Analysis (ultimate) 61.8% C, 4.3% H2, 12% H2O, 9% Ash,
8% O2, 8,8% S, 1.2% N2
English Units Metric (SI) Units
Density
Solid
Specific Gravity
Solid
Heating Value, Solid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Solid Fuel
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion
Solid Ash
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
C02 Weight
H2O Weight
SO2 Weight
Flammability Limits (Coal Dust)
Ignition Temperature
Toxicity
Least Detectable Odor:
-84 Ib/cu ft
,1.346
940,800 Btu/cu ft
932,400 Btu/ cu ft
11,200 Btu/lb
11, 100 Btu/lb
1.345 kg/cu m
1.346
3505 X 104 kJ/cu m
3473 X !04kJ/cu m
2.605 X 104 kJ/cu m
2.583 X I04kj/kg
1927. 986 cu ft/cu ft 1927. 986 cu m/cu m
7295.838 cu m/cu m
9219.447 cu m/cu m
1.942 kg/kg
6.461 kg/kg
8.402 kg/kg
7295.838 cu ft/cu ft
9219.447 cu ft/cu ft
1,942 Ib/lb
6,461 Ib/lb
8.402 Ib/lb
7.56 Ib/cu ft coal
1625.624 cu ft/cu ft
549.743 cu ft/cu ft
36.836 cu ft/cu ft
2.264 Ib/lb
0. 501 Ib/lb
0. 176 Ib/lb (Min. )
121. Ill kg/cu m
1625. 624 cu m/cu m
549. 743 cu m/cu m
36.836 cu m/cu m
2. 264 kg/kg
0.501 kg/kg
0. 176 kg/kg (Min. )
50 oz coal/1000 cu ft 0. 044 g coal/cu m
air
1100°F
593°C
Solid Coal Chunks Nontoxic
Maximum Allowable for Prolonged Exposure:(dust) 50 X 106 particles/cu ft
Comments:
Bulk transportation in cars, trucks, barges, steamers, etc. Has been
transported by pipeline as a slurry. Locally in power plants as airborne
dust.
'Toxicity: Chronic inhalation of coal dust can cause lung disease. The
maximum allowable concentration or threshold limit of coal dust has not
been researched adequately.
12
-------
SOLVE NT-REFINED COAL.
(Pittsburgh and Midway Coal Mining Co.)
Chemical Composition: Composition of SRC varies with input composition
to solvent-refining process. For this sample, the
input is shown below:
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Ash
Moisture
Molecular Weight (approx)
Heating Value, Solid
Weight Gross
Weight Net
Air for Combustion, Solid Fuel
N2 Weight
O2 Weight
Air Weight
Products of Combustion, Solid Fuel
Raw Coal
70.7
4.7
1.1
3.4
10.3
7.1
2.7
12
English Units
15,768 Btu/lbm
15,120 Btu/lbm
9.10 Ib/lb
2.74 Ib/lb
11.83 Ib/lb
-Wt %
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Toxicity:
3.23 Ib/lb
0.464 IbAb
9.10 Ib/lb
0.024 Ib/lb
Solid SRC particles are nontoxic.
SRC
88.2
5.2
1.5
1.2
3.4
0.5
Metric (Si) Units
3.667 X 10* kj/kg
3.517 X 104 kJ/kg
9.10 kg/kg
2.74 kg/kg
11.83 Ib/lb
3.23 kg/kg
0.464 kg/kg
9.10 kg/kg
0.024 kg/kg
Comments:
Bulk transportation of solid SRC is the same as that for coal.
13
-------
DIESEL OIL
Chemical Formula
Hydrocarbon Mixture 86-87% C, 13-14% H,
0.5% S
Molecular Weight
Pour Point
Boiling Point
Density
Liquid (7. 12 Ib/gal)
Specific Gravity
Liquid
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Vapor
Weight Gross
Weight Net
Heat of Vaporization
Flash Point
Ignition Temperature
Flammability Limits
Cetane Number
Air for Combustion, Vapor Fuel
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid Fuel
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
165 to 240 (12 to 17 carbon atoms/molecule)
English Units Metric (Si) Units
20 to 32°F (max)
325-650°F
53.41 Ib/cu ft
0.856
1,046,301 Btu/cu ft
987,017 Btu/cu ft
19,590 Btu/lb
18,480 Btu/lb
19^,590 Btu/lb
18,480 Btu/lb
155 Btu/lb
100°F
490°F
0.7-5.0%
40-68
3.281 Ib/lb
10.919 Ib/lb
14.201 Ib/lb
2071 cu ft/cu ft
7839 cu ft/cu ft
9910 cu ft/cu ft
3.281 Ib/lb
10.919 Ib/lb
14.201 Ib/lb
-7 to 0°C (max)
160-343°C
855.63 kg/cu m
0.856
3897.764 X 104kJ/cu m
3676.915 X 104 kJ/cu m
4.556 X 104 kJ/kg
4.298 X 104 kJ/kg
4.556 X 104kJ/kg
4.298 X 104kJ/kg
360 kJ/kg
38°C
254°C
3.281 kg/kg
10.919 kg/kg
14.201 kg/kg
2071 cu m/cu m
7839 cu m/cu m
9910 cu m/cu m
3.281 kg/kg
10.919 kg/kg
14.201 kg/kg
14
-------
DIESEL OIL, Cont.
English Units
Products of Combustion, Vapor Fuel
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Products of Combustion, Liquid Fuel
CO2 Volumetric
H2O Volumetric
N2 Volumetric
SO2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
3.218 Ib/lb
1.057 Ib/lb
11,019 Ib/lb
0.007 Ib/lb
1469 cu ft/cu ft
1186 cu ft/cu ft
7911 cu ft/cu ft
2.3 cu ft/cu ft
3.218 Ib/lb
1.057 Ib/lb
11.019 Ib/lb
Metric (SI) Units
3.218 kg/kg
1.057 kg/kg
11.019 kg/k
0.007 kg/kg
1469 cu m/cu m
1186 cu m/cu m
79 11 cu m/cu m
2. 3 cu m/cu m
3.218 kg/kg
1.057 kg/kg
11.019 kg/kg
Toxicity
Least Detectable Odor
Maximum Allowable for Prolonged Exposure
Comments
25-100 ppm*
500 ppm
Normal transportation is by railway cars, trucks, barges, and pipelines.
^Amounts detectable by odor depend on impurities, aromatics, and sulfur
compounds. Diesel oil is fuel oil No. 1 or No. 2. Fuel oil No. 1 is very
similar to kerosene in chemical and physical properties. It is slightly toxic,
and inhalation of high concentration of vapor can cause headache, stupor,and
nausea.
15
-------
ETHANOL
Chemical Formula
Molecular Weight
Melting Point
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, -Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
Oz Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion,
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Vapor
46.067
English Units
-179°F
172°F
0. 1216 Ib/cu ft
48.98 Ib/cu ft
1.5890
0.785
1600. 3 Btu/cu ft
1450. 5 Btu/cu ft
13,161 Btu/lb
11,929 Btu/lb
644,678 Btu/cu ft
584,282 Btu/cu ft
13,161 Btu/lb
11,929 Btu/lb
Metric (SI) Units
77.7°C
1.948 kg/cu m
784.65 kg/cu m
1.5890
0.785
5.9616 X 104 kJ/cu m
5.4035 X 104 kJ/cu m
3.0610 X 104 kJ/kg
2.7745 X 104kJ/kg
2401.61 X 104 kJ/cu m
2176.62 X 104 kJ/cu m
3.0610 X 104 kJ/kg
2.7745 X 104 kJ/kg
air component per unit of fuel-
3 cu ft/cu ft 3 cu m/cu m
11.293 cu ft/cu ft
14.293 cu ft/cu ft
2.084 Ib/lb
6.934 Ib/lb
9,018 Ib/lb
11.293 cu m/cu m
14. 293 cu m/cu m
2.084 kg/kg
6.934 kg/kg
9.018 kg/kg
-air component per unit of fuel-
1208.4 cu ft/cu ft
4548.8 cu ft/cu ft
5757.2 cu ft/cu ft
2.084 Ib/lb
6.934 Ib/lb
9.018 Ib/lb
1208.4 cu m/cu m
4548. 8 cu m/cu m
5757. 2 cu m/cu m
2.084 kg/kg
6.934 kg/kg
9.018 kg/kg
"unit of product per unit of fuel-
2.0 cu ft/cu ft
3.0 cu ft/cu ft
11.293 cu ft/cu ft
922 Ib/lb
170 Ib/lb
934 Ib/lb
2. 0 cu m/cu m
3. 0 cu m/cu m
11.293 cu m/cu m
1.922 kg/kg .
1.170 kg/kg
6.934 kg/kg
16
-------
ETHANOL, Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
C02 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
-unit of product per unit of fuel-
805. 6 cu m/cu m
1208.4 cu m/cu m
805.6 cu ft/cu ft
1208.4 cu ft/cu ft
4548.7 cu ft/cu ft
1.922 Ib/lb
1. 170 Ib/lb
6.9341b/lb
3.28-18.95%
55°F
738°F
Heat of Vaporization at Boiling Point 1570 Btu/lb
Octane Number
Research Method
Motor Method
Cetane Number
106
89
4548. 7 cu m/cu m
1.922 kg/kg
1.170 kg/kg
6. 934 kg/kg
13°C
392°C
860 kJ/kg
Toxic ity
Least Detectable Odor 10 ppm
Least Amount Causing Eye Irritation 5000 ppm
Least Amount Causing Throat Irritation 5000 ppm
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure 1000 ppm
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normal transportation is by railway cars, tank trucks, individual drums, or
other size containers; ethanol could be transported in liquid pipelines.
Because it dissolves readily in water, ethanol is easily adulterated. By
law it must be denatured to prevent consumption as beverage.
17
-------
FUEL OIL (No. 6)
Chemical Formula
Molecular Weight
Melting Point
Boiling Range
Density
Vapor
Liquid
8.094 Ib/gal
Specific Gravity
Vapor
Liquid
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
A:iv for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
, N2 Weight
Air Weight
Hydrocarbon mixture 86% C, 10.6% H,
2% S, 0.3-0.4% Ash
350-975 (25-70 carbon atoms/molecule)
English Units Metric (SI) Units
600°F-1000°F
60.65 Ib/cu ft
0.972
315°-540°C
971 kg/cu m
0.972
1, 101,000 Btu/cu ft 4101.9 X 104 kJ/cu m
1, 030, 754 Btu/cu ft 3877. 1 X 104 kJ/cu m
18, 155 Btu/lb 4. 222 X 104 kJ/kg
17,l60Btu/lb 3.991 X 104 kJ/kg
air component per unit of fuel
3. 181 Ib/lb
10.586 Ib/lb
13. 767 Ib/lb
3.181 kg/kg
10.586 kg/kg
13.767 kg/kg
-air component per unit of fuel-
2.277 cu ft/cu ft
8. 626 cu ft/cu ft
10.903 cu ft/cu ft
3.181 Ib/lb
10. 586 Ib/lb
13.767 Ib/lb
2. 277 cu m/cu m
8.626 cu m/cu m
10.903 cu m/cu m
3.181 kg/kg
10.586 kg/kg
13.767 kg/kg
18
-------
FUEL OIL (No. 6) Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SOz Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization at 1 atm
Octane Number
Research Method
Motor Method
Cetane Number
unit of product per unit of fuel-
1560 cu m/cu m
2315 cu m/cu m
variable
1560 cu ft/cu ft
2315 cu ft/cu ft
variable
191 lb/cu ft
116 lb/cu ft
1.8 lb/cu ft
150°F
765°F
~85 Btu/lb
30.6 X 102 kg/cu m
18.6 X 102 kg/cu m
28.8 kg/cu m
66°C
407°C
40 kj/kg
15-30
Toxic ity
Least Detectable Odor Unknown
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure Unknown
Maximum Allowable for Short Exposure (0. 5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normal transportation is by rail tank cars, tank trucks, and barges in
drums. No. 6 fuel oil is a residual oil that is very viscous. It often
requires heating to allow flow or pumping. There is no legal limit on the
sulfur content, which typically varies from 1 to 2% by weight.
19
-------
GASOLINE:
Chemical Formula
Molecular Weight
Melting Point
Boiling Range
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
(
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
02 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Hydrocarbon mixture 84..9% C, 15% H,
0. 1% (or less) S
85-145 (6-10 carbon atoms/molecule)
English Units Metric (SI) Units
100°-400°F 38°-204°C
45. 5 Ib/cu ft
0.7275
20,700 Btu/lb
19,291 Btu/lb
941,850 Btu/cu ft
877,740 Btu/cu ft
20,700 Btu/lb
19,291 Btu/lb
728. 1 kg/cu m
0.7275
4.814 X 104 kJ/kg
4.487 X 104 kJ/kg
3508.655 X 104kJ/cu m
3269.827 X 104kJ/cu m
4.814 X 104kJ/kg
4.487 X 104 kJ/kg
-air component per unit of fuel-
3.455 Ib/lb
11.494 Ib/lb
14. 949 Ib/lb
3.455 kg/kg
11.494 kg/kg
14. 949 kg/kg
-air component per unit of fuel-
1858 cu ft/cu ft
7030 cu ft/cu ft
.8888 cu ft/cu ft
3.455 Ib/lb
11.494 Ib/lb
14.946 Ib/lb
1858 cu m/cu m
7030 cu m/cu m
8888 cu m/cu m
3.455 kg/kg
11.494 kg/kg
14.946 kg/kg
-unit of product per unit of fuel-
3.004 Ib/lb
1.342 Ib/lb
11.494 Ib/lb
3.004 kg/kg
1.342 kg/kg
11.494 kg/kg
20
-------
GASOLINE, Confr.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SOz Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point(range)
Ignition Temperature
Heat of Vaporization at 1 atm
Octane Number
Research Method
Motor Method
Cetane Number
unit of product per unit of fuel-
1156 cu ft/cu ft 1156 cu m/cu m
1280 cu ft/cu ft 1280 cu m/cu m
5. 1 cu ft/cu ft 5. 1 cu m/cu m
3. 11 Ib/lb
2.70 Ib/lb
0.002 Ib/lb
1.4-7.6%
-36° to-50°F
49 5° F
130 Btu/lb
92-100
84-92
18.0
3.11 kg/kg
2. 70 kg/kg
0.002 kg/kg
-38° to -45°C
257°C
300 kJ/kg
Toxic ity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0.5 hr)
Comments
10-50 ppm*
Unknown
Unknown
500 ppm
Normal transportation is by pipeline, railway cars, trucks, and drums.
Toxicity: detectable amount depends on sulfur content, additives, and
aromatic hydrocarbon content. Further, the maximum allowable level
for prolonged exposure is dependent on the aromatic hydrocarbon content.
21
-------
Chemical Formula
HYDRAZINE
N2H4
Molecular Weight
Melting Point
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor*
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
Nz Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
32.05
English Units
Metric (SI) Units
34.52°F
236. 3°F
1.4°C
113.5°C
0.0848 Ib cu/ft
63.0864 Ib/cu ft
1. 108
1.011
232. 33 Btu/cu ft
179. 55 Btu/cu ft
2597 Btu/lb
2007 Btu/lb
296,454 Btu/cu ft
271,784 Btu/cu ft
7090 Btu/lb
6500 Btu/lb
1.358 kg/cu m
1010.638 kg/cu m
1. 108
1.011
86.549 kJ/cu m
66.887 kJ/cu m
6040 kJ/kg
4667 kJ/kg
11,043,500 kJ/cu m
10, 124,500 kJ/cu m
16,490 kJ/kg
15, 118 kJ/kg
-air component per unit of fuel-
1.0 cu ft/cu ft
3.764 cu ft/cu ft
4. 764 cu ft/cu ft
0.998 Ib/lb
3.286 Ib/lb
4.301 Ib/lb
1. 0 cu m/cu m
3. 764 cu m/cu m
4. 764 cu m/cu m
0.998 kg/kg
3.286 kg/kg
4.301 kg/kg
-air component per unit of fuel—
744 cu ft/cu ft 744. cu m/cu m
2786 cu ft/cu ft
3530 cu ft/cu ft
0.998 Ib/lb
3.286 Ib/lb
2786 cu m/cu m
3530 cu m/cu m
0.998 kg/kg
3.286 kg/kg
4. 2 84 kg/kf
4.284 Ib/lb
unit of product per unit of fuel-
2 cu ft/cu ft
4. 764 cu ft/cu ft
1. 122 Ib/lb
4. 179 Ib/lb
2 cu m/cu m
4. 764 cu m/cu m
1.122 kg/kg
4.179 kg/kg
22
-------
HYDRAZINE, Cont.
English tJnits Metric (SI) Units
Products of Combustion, Liquid — unit of product per unit of fuel
CO2 Volumetric
H2O Volumetric 2651.773 cu ft/cu ft 2651.773 cu m/cu m
SO2 Volumetric
N2 Volumetric 4040.208 cu ft/cu ft 4040.208 cu m/cu m
CO2 Weight
H2O Weight 1.1221b/lb 1.122 kg/kg
N2 Weight 4. 179 lb/lb .4. 179 kg/kg
S02 Weight
Ash Weight
Flammability Limits 4.7-100.0%
Flash Point 100°F 36°C
Ignition Temperature See Comment 2 See Comment 2
Heat of Vaporization at Boiling Point 5^1 Btu/lb 1302 kj/kg
Octane Number
Research Method
Motor Method
Cetane Number
Toxicity
Least Detectable Odor Contact with an excess
Least Amount Causing Eye Irritation of 5% aqueous solution
causes severe injury.
Maximum Allowable for Prolonged Exposure 1 ppm
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0.5 hr)
Comments
Dangerous to transport in undiluted state, can dissociate without access to
air. Normally transported as a hydrate, N2H4-H2O, or fuming liquid that can
be dissolved in water for additional safety in handling. In hydrated form, it
can be used as fuel-cell fuel. Ignition temperatures vary probably due to
catalytic action: in contact with iron rust, 74 F (23 C); black iron, 270 F
(132°C); stainless steel, 313°F (156°C); glass, 518°F (270 C).
*Liquid heating value is for N2H4-H2O.
Vapor heating value is for N2H4.
23
-------
HYDROGEN
Chemical Formula
Molecular Weight
Melting Point
Boiling Point
Density
Vapor Gas at 2000 psi 0. 667
Liquid at N. B. P.
f
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
2.016
English Units
-430.85 F
-423.0 F
0.005327 Ib/cu ft
4.43 Ib/cu ft
0.06959
0.07099
325.0 Btu/cu ft
275.0 Btu/cu ft
61,100 Btu/lb
51,623 Btu/lb
270,274 Btu/cu ft
228,693 Btu/cu ft
61,100 Btu/lb
51,623 Btu/lb
Metric (SI) Units
-257.14 C
-252.78 C
0.08533 kg/cu m
70.968 kg/cu m
0.06959
0.07099
1.2107 X 104 kJ/cu m
1.0245 X 104 kJ/cu m
14.2108 X 104kJ/kg
12.0067 X 104 kJ/kg
1006.85 X 104 kJ/cu m
851.95 X 104 kJ/cu m
14.2108 X 104 kJ/kg
12.0067 X 104 kJ/kg
-air component per unit of fuel-
0. 5 cu ft/cu ft
1.882 cu ft/cu ft
2. 382 cu ft/cu ft
7.937 Ib/lb
26.406 Ib/lb
34.344 Ib/lb
0. 5 cu m/cu m
1.882 cu m/cu m
2.382 cu m/cu m
7.937 kg/kg
26.406 kg/kg
34.344 kg/kg
-air component per unit of fuel-
415.8 CU ft/CU ft
1565. 1 cu ft/cu ft
1980.9 cu ft/cu ft
7.937 Ib/lb
26.406 Ib/lb
34. 344 Ib/lb
415. 8 cu m/cu m
1565. 1 cu m/cu m
1980. 9 cu m/cu m
7.937 kg/kg
26.406 kg/kg
34.344 kg/kg
-unit of product per unit of fuel-
1. 0 cu ft/cu ft
1.882 cu ft/cu ft
8.937 Ib/lb
26.407 Ib/lb
1. 0 cu m/cu m
1.882 cu m/cu m
8.937 kg/kg
26.407 kg/kg
24
-------
HYDROGEN, Cont.
English Units Metric (SI) Units
—M unit of product per unit of fuel—'
831.6 cu ft/cu ft 831. 6 cu m/cu m
1565. 1 cu ft/cu ft 1565. 1 cu m/cu m
8.937 Ib/lb
26.407 Ib/lb
4.00-74.2%
1065°F
8.937 kg/kg
26.407 kg/kg
574°C
130+
Products of Combustion, Liquid
COz Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization
Octane Number
Research Method
Motor Method
Cetane Number
Toxicity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0. 5 hr)
Dangerous for Short Exposure (0.5 hr)
Comments
Normally distributed as a compressed gas in high-pressure container
(cylinder). Can be shipped by pipeline. Can also be transported as a
cryogenic liquid in insulated or vacuum-jacketed tanks. Trucks and
railroads are commonly used for long-distance bulk transport of hydrogen
as a cryogenic liquid. Hydrogen can be combined with many metals and
alloys to form metal hydrides. Titanium, iron, and magnesium are examples.
Hydrogen is an odorless, colorless, and nontoxic gas. It burns with a non-
luminous flame, and it can be easily combusted catalytically (without flame)
because of its low ignition energy. For safe use as a fuel, an odorant and
possibly an illuminant would be required.
No odor
No irritation
No irritation
No coughing
25
-------
KEROSENE
Chemical Formula
Molecular Weight
Melting Point
Boiling Range
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Hydrocarbon mixture, 85-86% C,
14-15% H, 0.5% S (max)
150-230 (11-16 carbon atoms/molecule)
English Units Metric (SI) Units
300°-480°F
50.61 Ib/cu ft
0.811
20,500 Btu/lb
19,092 Btu/lb
150°-250°C
810.87 kg/cu m
0.811
4.768 X 104 kj/kg
4.440 X 104 kJ/kg
1,037, 505 Btu/cu ft 3864.997 X 104 kJ/cu m
966.246 Btu/cu ft 3599.537 X 104 kJ/cu m
20,500 Btu/lb 4.768 X 104 kJ/kg
19,092 Btu/lb 4.440 X 104kJ/kg
lir component per unit of fuel-
3.455 Ib/lb
11.495 Ib/lb
14.950 Ib/lb
3.455 kg/kg
11.495 kg/kg
14.950 kg/kg
air component per unit of fuel
2066. 23 cu ft/cu ft 2066. 23 cu m/cu m
7820. 62 cu ft/cu ft
9886. 85 cu ft/cu ft
3.455 Ib/lb
11.495 Ib/lb
14.950 Ib/lb
7820. 62 cu m/cu m
9886. 85 cu m/cu m
3,455 kg/kg
11.495 kg/kg
14.950 kg/kg
-unit of product per unit of fuel-
3. 114 Ib/lb
1.341 Ib/lb
11.495 Ib/lb
3. 114 kg/kg
1.341 kg/kg
11.495 kg/kg
26
-------
KEROSENE, Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
COZ Volumetric
H20 Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization
Octane Number
Research Method
Motor Method
Cetane Number
of product per unit of fuel-
1347. 16 cu ft/cu ft 1347. 16 cu m/cu m
1426.38 cu ft/cu ft 1426. 38 cu m/cu m
7820.62 cu ft/cu ft
3. 114 Ib/lb
1.341 Ib/lb
11.495 Ib/lb
0.01 Ib/lb
0.7-5.0%
100°F
491°F
7820. 62 cu m/cu m
3.114 kg/kg
1.341 kg/kg
11.495 kg/kg
0.01 kg/kg
38°C
255°C
40-65
25-100 ppm*
500-1000 ppm
500-1000 ppm
500 ppm
Toxicity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normally carried in tanks or drums; can be transported by tank truck.
Could be pipelined in liquid (hydrocarbon) fuel pipelines.
*Toxicity: Leat detectable odor depends on impurities, aromatics, and
sulfur contents. Kerosene and No. 2 distillate oil are essentially the
same. The difference (if any) is that kerosene has a slightly higher gravity.
Inhalation of high concentrations of vapor can cause headache, stupor,
nausea, and vomiting.
27
-------
Chemical Formula
METHANE
CH4
Molecular Weight
Melting Point
Boiling Point
Density
Vapor at 2000 psi
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor (1 atm)
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Vohometric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
16.041
English Units
-296. 5°F
-258. 5°F
7.08 Ib/ft
26. 5 Ib/cu ft
0.5543
0.1135
1013 Btu/cu ft
913. 1 Btu/cu ft
23,879 Btu/lb
21,520 Btu/lb
16,9065 Btu/cu ft
152,362 Btu/cu ft
23,879 Btu/lb
21, 520 Btu/lb
Metric (SI) Units
-182. 5°C
-161.4°C
113.42 kg/cu m
424. 5 kg/cu m
0.5543
0. 1135
3.7745 X 104 kJ/cu m
3.4016 X 104 kJ/cu m
5.5539 X 104 kJ/kg
5.0052 X 104 kJ/kg
629.815 X 104kJ/cu m
567. 591 X 104 kJ/cu m
5. 5539 X 104 kJ/kg
5.0052 X 104 kJ/kg
-air component per unit of fuel-
2.0 cu ft/cu ft
7. 528 cu ft/cu ft
9. 528 cu ft/cu ft
3.990 Ib/lb
13.275 Ib/lb
17.265 Ib/lb
2. 0 cu m/cu m
7. 528 cu m/cu m
9. 528 cu m/cu m
3.990 kg/kg
13.275 kg/kg
17.265 kg/kg
-air component per unit of fuel-
333. 7 cu ft/cu ft
1256. 1 cu ft/cu ft
1589.9 cu ft/cu ft
3.990 Ib/lb
13.275 Ib/lb
17.265 Ib/lb
333. 7 cu m/cu m
1256. 1 cu m/cu m
1589. 9 cu m/cu m
3.990 Ib/lb
13.275 kg/kg
17.265 kg/kg
it of product per unit of fuel
1. 0 cu ft/cu ft 1. 0 cu m/cu m
2. 0 cu m/cu m
7. 528 cu m/cu m
2.744 kg/kg
2.246 kg/kg
2. 0 cu ft/cu ft
7. 528 cu ft/cu ft
2.744 Ib/lb
2.246 Ib/lb
13.275 Ib/lb
13. 275 kg/kg
28
-------
\
METHANE. .Cont.
English Units Metric (SI) Units
Products of Combustion, Liquid unit of product per unit of fuel-
CO2 Volumetric 166. 9 cu ft/cu ft 166. 9 cu m/cu m
H2O Volumetric 333. 7 cu ft/cu ft 333. 7 cu m/cu m
SOz Volumetric
N2 Volumetric 1256. 1 cu ft/cu ft 1Z56. 1 cu m/cu m
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits 5.00-15.00%
Flash Point
Ignition Temperature 1170°F 632°C
Heat of Vaporization at Boiling 219 Btu/lb 510 kJ/kg
Point
Octane Number
Research Method 130
Motor Method
Cetane Number
Toxic ity
Least Detectable Odor No odor
Least Amount Causing Eye Irritation No irritation
Least Amount Causing Throat Irritation No irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure 90,000 ppm
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normal transportation is by pipeline under pressure or as a cryogenic liquid
in bulk.
Methane is considered a nontoxic chemical. In concentrations above 9% in
air, it acts as a simple asphyxiant. When used as a gaseous fuel, it is
odorized by mercaptan compounds for recognition.
29
-------
METHANOL
Chemical Formula
CH3OH
Molecular Weight
Melting Point .
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
32.041
English Units
-143.82
148. 1°F
0.0846 Ib/cu ft
49. 72 Ib/cu ft
1.1052
0.796
867.9 Btu/cu ft
768. 0 Btu/cu ft
10,259 Btu/lb
9,078 Btu/lb
510,077 Btu/cu ft
451,358 Btu/cu ft
10,259 Btu/lb
9,078 Btu/lb
Metric (SI) Units
-97.68°C
64. 1°C
1.355 kg/cu m
796.51 kg/cu m
1.1052
0. 796
3.233 X 104 kj/cu m
2.8610 X 104 kj/cu m
2.3861 X 104 kg/kg
2. 114 X 104 kJ/kg
1900.18 X 104 kJ/cu m
1681.44 X 104kJ/cu m
2.3861 X 104 kJ/kg
2. 1114 X 104 kJ/kg
-air component per unit of fuel-
5 cu ft/cu ft
646 cu ft/cu ft
146 cu ft/cu ft
498 Ib/lb
984 Ib/lb
6.482 Ib/lb
1.5 cum /cu m
5. 646 cu m/cu m
7. 146 cu m/cu m
1.498 kg/kg
4.984 kg/kg
6.482 kg/kg
-air component per unit of fuel-
881. 56 cu ft/cu ft
3318. 1 cu ft/cu ft
4199.8 cu ft/cu ft
1.498 Ib/lb
4.984 Ib/lb
6.482 Ib/lb
881. 56 cu m/cu m
3318. 1 cu m/cu m
4199'. 8 cu m/cu m
1.498 kg/kg
4.984 kg/kg
6.482 kg/kg
1
2
5
1
1
4
30
-unit of product per unit of fuel-
0 cu ft/cu ft 1
0 cu ft/cu ft 2
646 cu ft/cu ft 5
374 Ib/lb 1
125 Ib/lb 1
984 Ib/lb 4
0 cu m/cu m
0 cu m/cu m
646 cu m/cu m
374 kg/kg
125 kg/kg
984 kg/kg
-------
METHANOL, Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization at Boiling
Point
Octane Number
Research Method
Motor Method
Cetane Number
unit of product per unit of fuel-
587.71 cu ft/cu ft 587.71 cu m/cu m
1175.4 cu ft/cu ft 1175.4 cu m/cu m
3318.1 cu ft/cu ft
1.374 Ib/lb
1. 125 Ib/lb
4.984 Ib/lb
6.72-36.50%
52°F
878°F
473 Btu/lb
106
92
3318.1 cum/cum
1.374 kg/kg
1. 125 kg/kg
4.984 kg/kg
470°C
1100 kJ/kg
Toxic ity
Least Detectable Odor 100 ppm
Least Amount Causing Eye Irritation Unknown
Least Amount Causing Throat Irritation Unknown
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure 200 ppm
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0.5 hr)
Comments
Normal transportation is in bulk or by container. Methanol dissolves
readily in water, so it is easily contaminated or adulterated. The main
toxic effect of methanol is on the nervous system, particularly the optic
nerves.
31
-------
METHYLAMINE
Chemical Formula
CH3NH2
5.833 Ib/gal
Molecular Weight
Melting Point
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
31.08
English Units
Metric (SI) Units
-134°F
20.3°F
0.0872 Ib/cu ft
43.638 Ib/cu ft
1.0797
0.699
1292 Btu/cu ft
1088.7 Btu/cu ft
14,819 Btu/lb
12,384 Btu/lb
646,671 Btu/cu ft
560,966 Btu/cu ft
14,819 Btu/lb
12,855 Btu/lb
-6.5°C
1.396 kg/cu m
699.0 kg/cu m
1.0797
0.699
4.813 X 104 kJ/cu m
4.056 X 104 kJ/cu m
3.447 X 104 kJ/kg
2.904 X 104 kJ/kg
2409.0 X 104 kJ/cu m
2069.8 X 104 kJ/cu m
3.447 X 104kJ/kg
2.904 X 104 kJ/kg
lir component per unit of fuel-
3. 667 cu ft/cu ft
13. 804 cu ft/cu ft
17.471 cu ft/cu ft
3.558 Ib/lb
11.776 Ib/lb
15.338 Ib/lb
3. 667 cu m/cu m
13.804 cu m/cu m
17.471 cu m/cu m
3.558 kg/kg
11.776 kg/kg
15.338 kg/kg
-air component per unit of fuel-
1835 cu ft/cu ft
6908 cu ft/cu ft
8743 cu ft/cu ft
3. 558 Ib/lb
11.776 Ib/lb
15.338 Ib/lb
1835 cu m/cu m
6908 cu m/cu m
8743 cu m/cu m
3.558 kg/kg
11.776 kg/kg
15.338 kg/kg
-unit of product per unit of fuel-
1. 630 cu ft/cu ft
4.074 cu ft/cu ft
14.617 cu ft/cu ft
2. 187 Ib/lb
2.223 Ib/lb
12. 370 Ib/lb
1.630 cu m/cu m
4. 074 cu m/cu m
14.617 cu m/cu m
2.187 kg/kg
2.223 kg/kg
12.370 kg/kg
32
-------
ME THY LA MINE, Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
—'• unit of product per unit of fuel-
815.8 cu ft/cu ft 815.8 cum/cum
2038:8 cu ft/cu ft 2038. 8 cu m/cu m
7315.2 cu ft/cu ft
2. 187 Ib/lb
2.223 Ib/lb
12.470 Ib/lb
4.9-20.7%
7315. 2 cu m/cu m
2.187 kg/kg
2.223 kg/kg
12.370 kg/kg
0°F
806°F
-18°C
430°C
790 kJ/kg*
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization at Boiling Point 340 Btu/lb*
Octane Number <
Research Method
Motor Method
Cetane Number
Toxicity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normal transportation is by bulk or container at moderate pressures.
Methyl amine readily dissolves in water so it can easily be contaminated
or adulterated. Synonyms: Monomethylamine, aminomethane. Is a strong
irritant to the respiratory tract. CH2NH2 is a colorless gas or liquid with
a strong ammoniacal odor.
0. 02 ppm
10-50 ppm
10-50 ppm
10 ppm
-Estimated.
. 33
-------
NAPHTHA
Chemical Formula
Molecular Weight
Melting Point
Boiling Range
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Hydrocarbon mixture 86-87% C,
13-14% H, 0-1% S
84-170 (6-12 carbon atoms/molecule)
English Units Metric (SI) Units
150-300 F
A.0.45 lb/cu ft
48 lb/cu ft
0. 77
9104.5 Btu/cu ft
8460. 5 Btu/cu ft
20,300 Btu/lb
18,864 Btu/lb
974,400 Btu/cu ft
905,472 Btu/cu ft
20, 300 Btu/lb
18,864 Btu/lb
65-150 C
7. 21 kg/cu m
769 kg/cu m
33.917 X 104kJ/cu m
31. 518 X 104 kJ/cu m
4.721 X 104 kJ/kg
4.387 X 104 kJ/kg
3629.9 X 104 kJ/cu m
3373. 1 X 104 kJ/cu m
4.721 X 104 kJ/kg
4.387 X 104 kJ/kg
-air component per unit of fuel-
18. 394 cu ft/cu ft
69. 619 cu ft/cu ft
88. 013 cu ft/cu ft
3.470 Ib/lb
11. 547 Ib/lb
15.018 Ib/lb
-air component
1968.6 cu ft/cu ft
7450.9 cu ft/cu ft
9419. 5 cu ft/cu ft
3.470 Ib/lb
11. 547 Ib/lb
15.018 Ib/lb
18. 394 cu m/cu m
69.6l9.cu m/cu m
88. 013 cu m/cu m
3.470 kg/kg
11.547 kg/kg
15.018 kg/kg
per unit of fuel
1968.6 cu m/cu m
7450.9 cu m/cu m
9419,5 cu m/cu m
3.470 kg/kg
11.547 kg/kg
15.018 kg/kg
--unit of product per unit of fuel-
11.896 cu ft/cu ft
12.886 cu ft/cu ft
69.619 cu ft/cu ft
3.103 Ib/lb
1.367 Ib/lb
11.547 Ib/lb
11. 896 cu m/cu m
12.886 cu m/cu m
69. 619 cu m/cu m
3. 103 kg/kg
1.367 kg/kg
11.547 kg/kg
34
-------
NAPHTHA. Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
S02 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization at 1 atm
Octane Number
Research Method
Motor Method
Cetane Number
-unit of product per unit of fuel-
1273.2 cu ft/cu ft 1273.2 cu m/cu m
1379. 0 cu ft/cu ft 1379. 0 cu m/cu m
7450.9 cu ft/cu ft
3. 103 Ib/lb
1.367 Ib/lb
11. 547 Ib/lb
0.90-6.00%
20°-50°F
450°-531?F
145 Btu/lb
60-70
50-60
7450.9 cu m/cu m
3.103 kg/kg
1.367 kg/kg
11.547 kg/kg
-7° to+10°C
232°-277°C
336 kJ/kg
Toxic ity
Least Detectable Odor 10-50 ppm*
Least Amount Causing Eye Irritation Unknown
Least Amount Causing Throat Irritation Unknown
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure 500 ppm
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normal transportation is by pipeline, tank truck, drums, or other closed,
containers.
*Toxicity: Detectable amounts depend on sulfur and aromatic hydrocarbon
content.
35
-------
PROPANE (Pure)
Chemical Formula
Molecular Weight
Melting Point
Boiling Point
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion,
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Vapor
44;092
English Units
-305.88°F
-43.7°F
0. 1196 Ib/cu ft
31.8 Ib/cu ft
1.5617
2590 Btu/cu ft
2,385 Btu/cu ft
21,661 Btu/lb
19,944 Btu/lb
688,645 Btu/cu ft
634, 138 Btu/cu ft
21,661 Btu/lb
19,944 Btu/lb
Metric (SI) Units
-187.71 C
-42.07 C
1.91599 kg/cu m
509.44 kg/cu m
1.5617
9.6485 X 104 kJ/cu m
8.8848 X 104 kJ/cu m
5.0380 X 104 kJ/kg
4.6387 X 104kJ/kg
2565.40 X 104 kJ/cu m
2362.34 X 104kJ/cu m
5.0380 X 104kJ/kg
4.6387 X 104 kJ/kg
-air component per unit of fuel-
5. 0 cu ft/cu ft
18.821 cu ft/cu ft
23. 821 cu ft/cu ft
3.629 Ib/lb
12.074 Ib/lb
15.703 Ib/lb
5. 0 cu m/cu m
18.821 cu m/cu m
23.821 cu m/cu m
3.629 kg/kg
12.074 kg/kg
15.703 kg/kg
-air component per unit of fuel-
1329.4 cu ft/cu ft
5004.2 cu ft/cu ft
6333.6 cu ft/cu ft
3.629 Ib/lb
12.074 Ib/lb
15.703 Ib/lb
1329.4 cu m/cu m
5004. 2 cu m/cu m
6333.6 cu m/cu m
3.629 kg/kg
12.074 kg/kg
15.703 kg/kg
--unit of product per unit of fuel-
3.0 cu ft/cu ft
4.0 cu ft/cu ft
18.821 cu ft/cu ft
2.994 Ib/lb
1.634 Ib/lb
12.074 Ib/lb
36
3. 0 cu m/cu m
4. 0 cu m/cu m
18.821 cu m/cu m
2.994 kg/kg
1.634 kg/kg
12. 074 kg/kg
-------
PROPANE (Purel Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization at Boiling
Point
Octane Number
Research Method
Motor Method
Cetane Number
unit of product per unit of fuel
797. 6 cu ft/cu ft 797. 6 cu m/cu m
1063. 5 cu ft/cu ft 1063. 5 cu m/cu m
5003.9 cu ft/cu ft
2.994 Ib/lb
1.634 Ib/lb
12.074 Ib/lb
2. 1-10. 1%
-156°F
808°F
150 Btu/lb
111
97
5003.9 cu m/cu m
2.994 kg/kg
1.634 kg/kg
12.074 kg/kg
-104°C
431°C
340 kJ/kg
Unknown'
No irritation
No irritation
3-5%
Toxic ity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normal transportation is pipeline, bulk, or containers at moderate pressure.
Liquid propane is contained at 110 psig at 70 F.
'Propane has a faint odor that varies with (trace) impurities.
37
-------
COMMERCIAL PRQPANE (LPG)
Chemical Formula
Molecular Weight
Melting Point
Boiling Point
Hydrocarbon mixture C3Hj, C4H10, C2H4,
C3H6 %
4.24 Ib/gal
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H26 Weight
N2 Weight
SO2 Weight
30-60
English Units
-50°F
0. 1169 lb/cu ft
31.8 lb/cu ft
1.52
0.509
2522 Btu/cu ft
2399 Btu/cu ft
21. 56 Btu/lb
20,51 Btu/lb
685, 068 Btu/cu ft
652,345 Btu/cu ft
21,560 Btu/lb
20,514 Btu/lb
Metric (SI) Units
-45°C
1.8735 kg/cu m
509.435 kg/cu m
1. 52
0. 509
9.395 X 104kJ/cu m
8.937 X 104kJ/cu m
5.014 X 104 kJ/kg
4.771 X 104kJ/kg
2554.09 X 104 kJ/cu m
2430. 17 X 104kJ/cu m
5.013 X 104kJ/kg
4.771 X 104 kJ/kg
-air component per unit of fuel-
4.9 cu ft/cu ft
18.49 cu ft/cu ft
23.4 cu ft/cu ft
3.60 Ib/lb
11.98 Ib/lb
15.58 Ib/lb
4. 9 cu m/cu m
18.49 cu m/cu m
23. 4 cu m/cu m
3.60 kg/kg
11.98 kg/kg
15. 58 kg/kg
-air component per unit of fuel-
1353.04 cu ft/cu ft
5115.87 cu ft/cu ft
6468.91 cu ft/cu ft
3.60 Ib/lb
11.98 Ib/lb
15.58 Ib/lb
1353.04 cu m/cu m
5115.87 cu m/cu m
6468. 91 cu m/cu m
3.60 kg/kg
11.98 kg/kg
15.58 kg/kg
•"unit of product per unit of fuel-
3 cu ft/cu ft
3.8 cu ft/cu ft
18. 5 cu ft/cu ft
3 Ib/lb
1.6 Ib/HT-
12 Ib/lb
3 cu m/cu m
3. 8 cu m/cu m
18.5 cu m/cu m
3 kg/kg
1.6 kg/kg
12 kg/kg
38
-------
LPG, Cont.
English Units
Metric (SI) Units
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
COZ Weight
H2O Weight
N2 Weight
SO2 Weight
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization at 1 atm
Octane Number
Research Method
Motor Method
Cetane Number
unit of product per unit of fuel-
815.47 cu ft/cu ft 815. 47 cu m/cu m
664. 65 cu ft/cu ft 664. 65 cu m/cu m
5129.84 cu ft/cu ft
3 Ib/lb
1.6 Ib/lb
12 Ib/lb
2.4-9.6%
-160° to-150°F
920°-1020°F
100 Btu/lb
108-111
95-98
5129.84 cu m/cu m
3 kg/kg
1.6 kg/kg
12 kg/kg
-107° to -100°C
493°-547°C
420 kJ/kg
About 1 ppm*
Unknown
Unknown
1% or more*
Toxicity
Least Detectable Odor
Least Amount Causing Eye Irritation
Least Amount Causing Throat Irritation
Least Amount Causing Coughing <•
Maximum Allowable for Prolonged Exposure
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0.5 hr)
Comments
Normal transportation is by bulk, or containers at moderate pressures.
^Commercial LPG is odorized with mercaptans; methyl mercaptans can
be detected by odor at 0.002-0.005 ppm. LPG in high concentrations can
act as an asphyxiant. Any toxic effects would result from contaminants
(gases other than propane, propylene, butane, or ethane).
39
-------
VEGETABLE (Cottonseed) OIL
Chemical Formula
Molecular Weight
Melting Point
Boiling Range
Density
Vapor
Liquid
Specific Gravity
Vapor
Liquid
Heating Value, Vapor
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Heating Value, Liquid
Volumetric Gross
Volumetric Net
Weight Gross
Weight Net
Air for Combustion, Vapor
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Air for Combustion, Liquid
O2 Volumetric
N2 Volumetric
Air Volumetric
O2 Weight
N2 Weight
Air Weight
Products of Combustion, Vapor
CO2 Volumetric
H2O Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
SO2 Weight
Carbohydrate mixture 77.2% C, 12% H,
10.8% O
Contains C16 (paluritic) and C18 (oleic and
linoleic) fatty acids
English Units Metric (SI) Units
23°-30°F
170 C and above
make point
56. 94 Ib/cu ft
0.9125
-5° to -1°C
300°C
17,270 Btu/lb
16, 113 Btu/lb
983,354 Btu/cu ft
917,474 Btu/cu ft
17,270 Btu/lb
16,113 Btu/lb
912. 18 kg/cu m
0.9125
4.017 X 104kJ/kg
3.748 X 104kJ/kg
3663 X 104 kJ/cu m
3418 X 104kJ/cu m
4.017 X 104kJ/kg
3.748 X 104 kJ/kg
-air component per unit of fuel-
2.896 Ib/lb
9.538 Ib/lb
12,434 Ib/lb
2. 896 kg/kg
9.538 kg/kg
12.434 kg/kg
-air 'component per unit of fuel-
1948. 7'cu ft/cu ft
7094.4 cu ft/cu ft
9043. 1 cu ft/cu ft
2.896 Ib/lb
9.538 Ib/lb
12.024 Ib/lb
1948. 7 cu m/cu m
7094. 4 cu m/cu m
9043. 1 cu m/cu m
2.896 kg/kg
9.538 kg/kg
12.024 kg/kg
-unit of product per unit of fuel-
2.830 Ib/lb
1.066 Ib/lb
9. 528 Ib/lb
2.830 kg/kg
1.066 kg/kg
9.528 kg/kg
40
-------
VEGETABLE (Cottonseed) OIL, Cont.
English Units Metric (SI) Units
unit of product per unit of fuel-
1377. 426 cu ft/cu ft 1377. 426 cu m/cu m
1275.691 cu ft/cu ft 1275.691 cu m/cu m
7293. 154 cu ft/cu ft
2.830 Ib/lb
1.066 Ib/lb
9. 528 Ib/lb
7293. 154 cu m/cu m
2.830 kg/kg
1.066 kg/kg
9.528 kg/kg
486°F
650°F
252°C
343°C
Products of Combustion, Liquid
CO2 Volumetric
H2O Volumetric
SO2 Volumetric
N2 Volumetric
CO2 Weight
H2O Weight
N2 Weight
S02 Weight -
Ash Weight
Flammability Limits
Flash Point
Ignition Temperature
Heat of Vaporization
Octane Number
Research Method
Motor Method
Cetane Number
Toxicity*
Least Detectable Odor Odorless
Least Amount Causing Eye Irritation Unknown
Least Amount Causing Throat Irritation Unknown
Least Amount Causing Coughing
Maximum Allowable for Prolonged Exposure Unknown
Maximum Allowable for Short Exposure (0.5 hr)
Dangerous for Short Exposure (0. 5 hr)
Comments
Normal transportation is in bulk or by containers. Cottonseed oil contains
fatty acids (C16, C18 molecules) distributed in a complex glyceride structure.
This oil is presented as an example of several vegetable oils that might be
used in external-combustion engines. Such oils are corn oil, peanut oil,
and soybean oil.
'Normally not considered toxic.
41
-------
Bibliography
The information contained in this appendix was extracted or deduced
from many source documents and reference works. The principal sources are
listed below.
1. Kirk, R.E. and Othmer, D. F. , Encyclopedia of Chemical Technology,
Vol. £>. New York: Inter science Encyclopedia, Inc. , 1951.
2. Leonardos, G. et. al. , "Odor Threshold Determination of 53 Odorant
Chemicals." Paper No. 68-13 presented at 61st Annual Meeting
of the Air Pollution Control Association, St. Paul, Minn. , June 23-27,
1968. Cambridge, Mass.: Arthur D. Little, Inc.
3. Nelson, W. L. , Petroleum Refinery Engineering, 4th Ed. New York:
McGraw-Hill, 1958.
4. Perry, J. H. , Chemical Engineer's Handbook, 3rd Ed. New York:
McGraw-Hill, 1950.
5. Sax, N. I. , Dangerous Properties of Industrial Materials, 3rd Ed. New
York: Reinhold, 1968.
6. Schmidt, Paul F. , Fuel Oil Manual , 3rd Ed. New York: Industrial Press
Inc., 1969.
7. Shnidman, L. , Gaseous Fuels. New York: American Gas Association,
1948.
8. The Matheson Company, Matheson Gas Data Book, 4th Ed. East Rutherford,
N.J., 1966.
42
-------
APPENDIX B. Detailed Process Descriptions and Economics
for Candidate Fuels From Coal and Oil Shale
Gasoline and Distillate Fuels From Coal
Three processing routes are employed to manufacture liquid fuels
from coal:
1. Pyrolysis involves heating the coal to drive out the naturally occurring
oils and volatile matter. The syncrude produced then is hydrotreated
for quality improvement and desulfurization. Pyrolysis processes
produce significant quantities of by-product gas and char that must
be disposed of economically. Three processes based on this principle
are under development: COED, TosCoal, and Garrett.
2. Selective hydrogenation of the coal involves destructive dissolution
(usually in a hydrogen-donor solvent), ash filtration, and hydro-
cracking to produce a liquid hydrocarbon fuel. In this process, pyritic
sulfur goes with the ash, which is insoluble in the solvent, and
organic sulfur goes with the liquid fuels because it is soluble in the
solvent. The syncrude produced then is treated with hydrogen to
improve its quality and, at the same time, to remove organic
sulfur. This route is very energy-efficient compared with other
methods for producing liquid fuels from coal. Four processes are
under development: CSF, H-Coal, Synthoil, and SRC. In SRC, a
solid fuel is produced if the syncrude is allowed to cool before
hydrotreatment.
3. Gasification of coal is carried out to produce synthesis gas. After
purification, the clean gas containing appropriate proportions of
carbon monoxide and hydrogen is converted by the Fischer-Tropsch
Process to hydrocarbon oil. The two chemical equations that
generalize the formation of hydrocarbons in the Fischer-Tropsch
synthesis are as follows:
nCO -I 2nH2 -» (CH2) + nH2O (B-l)
n
2nCO + nH2 -+ (CH2)n + nCO2 (B-2)
This process was demonstrated in the U.S. about 25 years ago. South
African Coal, Oil, and Gas Corp. , Ltd, (SASOL) built a Fischer-
Tropsch synthesis plant at Sasolburg, South Africa, to produce liquid
hydrocarbons from coal in 1955. At present, the plant utilizes about
13, 000 tons of coal/day (14. 9 million Btu/ton of coal) and produces
71 million SCF/day of 525 Btu/SCF of pipeline gas, in addition to
9000 bbl/day liquid fuels. The process block diagram is given in
Figure B-l, and the following two paragraphs describe the process
in brief.
43
-------
OXYGEN
ARGE
FIXED-BED
SYNTHESIS
ARGE
TAIL GAS
SYNTHESIS GAS
REFORMER |
KELLOGG FLUID-
BED SYNTHESIS
LIQUID
PRODUCTS
PRODUCT
KELLOGG TAIL GAS
LIQUID
PRODUCTS
A-94-1638
Figure B-l. FISCHER-TROPSCH SYNTHESIS AT SASOLBURG
Noncaking coal is crushed to 3/8 to 1-1/2 inches and dried. Dried
coal is converted to gas at 350-450 psi in a Lurgi gasifier. The
gas is quenched to remove tar and oil, and then carbon dioxide and
hydrogen sulfide are removed to produce synthesis gas. A part
of the synthesis gas is passed through a fixed catalyst bed contained
in vertical tubes (Arge synthesis). Released heat is absorbed by
boiling water outside the tubes. The feed gas has an hydrogen-to-carbon
monoxide ratio of about 2, and the operating conditions are 430°-490°F
and 360 psig. The ratio of recycled gas to fresh feed is about 2.4.
The products of fixed-bed synthesis are straight-chain high-boiling -
point hydrocarbons, with some intermediate-boiling-point oils,
diesel oil, LPG, and oxygenated compounds.
The portion of gas that did not go to Arge synthesis goes to a fluid-
bed reactor (Kellogg synthesis). A portion of the tail gas from the
Kellogg fluid-bed synthesis is reformed with steam to increase the
hydrogen-to-carbon monoxide ratio to about 3, and this gas is mixed
with the fresh synthesis gas. In the fluid bed, catalyst is circulated
along with the synthesis gas. The gas and catalyst leaving the reactor
are separated in cyclones, and the catalyst is recycled. The operating
conditions are 600°-625°F and 330 psig. The ratio of recycled gas to
fresh feed is 2. Products from the fluid-bed synthesis are mainly
low-boiling-point hydrocarbons (C^-C4) and gasoline, with little
intermediate- and high-boiling-point material. Substantial amounts
of oxygenated products and aromatics are produced. A portion of
the fixed-bed tail gas and a portion of a fluid-bed tail gas are removed
and used for utility gas.
The typical produce analysis for a fixed-bed process and a fluid-bed
process given in Table B-l. The overall yield per ton of coal fed
to the process is given in Table B-2.
44
-------
Table B-l. TYPICAL PRODUCTS OF SASOL PROCESS2
Fixed-Bed Fluid-Bed
Process Process
wt %
Liquid Product Composition
Liquified Petroleum Gas (C3-C4) 5.6 7.7
Petrol (C5-CU) 33.4 72.3
Middle Oils (diesel, furnace, etc.) 16.6 3.4
Waxy Oil or Gatsch 10.3 3.0
Medium Wax, mp 203°-206 °F 11.8
Hard Wax, mp 203°-206°F 18.0
Alcohols and Ketones 4.3 12.6
Organic Acids Traces 1.0
Fixed-Bed Fluid-Bed
Process Process
vol %
Liquid Product Composition
Paraffins 45 55 13 15
Olefins 50 40 70 60
Aromatic s 0 0 5 15
Alcohols 5565
Carbonyls Traces Traces 6 5
Table B-2. PRODUCT YIELD OF SASOL PROCESS
Products Yield, gal/ton
LPG 0.18
Gasoline 25.72
Kerosene 0.31
Diesel Fuel 2. 56
Fuel Oil 0.63
Wax Oil and Wax 2. 06
Methanol 0.11
Ethanol 2.17
Methyl Ethyl Ketone 0.15
Acetone 0. 12
34.01
Gas (500 Btu/SCF) 5500 SCF
45
-------
In this study, the CSF Process (Consol Synthetic Fuel) has been
selected for a detailed analysis because —
1. Not enough information is available for the SASOL Process in the
following areas:
a. Material and heat-transfer data for an energy balance to
determine process efficiency
b. Economic data.
2. The SASOL Process is designed to produce not only liquid fuels but also
pipeline gas and many other by-products.
3. The SASOL Process route (Fischer-T'ropsch) is less efficient than coal
dissolution routes.
Description of CSF Process
The CSF Process has been developed by Consolidation Coal Company.
A 70 ton/day pilot plant that was operational at Cresap, W. Va. , for 40
months with less than 500 hours of operating time was shut down in April
1970 for a detailed study of process and operating problems. The process is
designed to produce fuel oil and naphtha from coal. The liquid product can
be catalytically reformed in a refinery to produce gasoline and No. 2 fuel oil.
The process flow diagram is given in Figure B-2. The process setup and
data required for this study have been taken from Reference 7.
Coal Preparation and Extraction
The raw coal is crushed in hammer-mill crushers and partially
dried by contact with the flue gas. The partially dried coal is dried further
in fluid-bed dryers. Fines smaller than 14 mesh are recovered in multiple-
stage cyclones and bag filters. The crushed coal is combined with the
recovered fines and heated to 450°F in fluid-bed dryers to remove any
remaining moisture. The preheated coal then is slurried with a coal-derived
solvent and pumped at 150 psig through a tubular furnace, where it is heated
to extraction temperature, 765°F. Extraction mainly occurs in a stirred
extraction vessel. The hot vapor from the extractor is sent to the solvent
recovery area, and the slurry phase is sent to a residue separation section.
Residue Separation and Solvent Recovery
The untreated coal residue is removed from the slurry in the residue
separation section by two-stage hydroclones. Overflow from the first
46
-------
12.3 OC 6
TONS/OAT
RECYCLE SOLVENT
39.6917 TONS/DAY
DISTILLATE FUEL
MOISTURE
MAKEUP AND
RECYCLE
SOLVENT
FUEL GAS
BUTANE
^
4499 bM/OAT
»i
GASOLINE
49.84ODMTOY
njurrrutL
ASH
B-54-MI
CAStOCS STREAM
LWUIO STREAM
Q SOLID STREAM
Figure B-2.
FLOW DIAGRAM OF CSF-PROCESS PRODUCTION OF
GASOLINE (50, 000 bbl/Day) FROM COAL
-------
stage goes to the solvent recovery section, and the underflow passes to a
second stage. The overflow from the second stage is fed back to the first
stage; the underflow is sent to the low-temperature carbonization (JLTC)
system.
Solvent recovery is divided into two sections. The vapor from the
extraction section is condensed, the gaseous stream is sent to the gas-
cleanup section, and the recovered solvent is returned to the slurry mix
tanks. The hydroclone overflow from residue separation is fractionated
in a vacuum still. The distillate (including spent solvent and fuel oil) is
taken overhead from the fractionator, and a heavier cut from a side stream
provides most of the recycle solvent for the extraction section. The
bottoms, which contain the extract, residue, and tar, are sent to the extract
hydroconversion.
Low-Temperature Carbonization
The hydroclone underflow from residue separation is pumped to the
carbonizer, where it is reacted with steam and air. The overhead gaseous
product from the low-temperature carbonizer is quenched, and a gas stream
is separated from a solvent-tar stream. The solvent-tar stream is delivered
to the tar distillation section, and the gas stream is used as a plant fuel after
sulfur removal. Char from the LTC section is delivered to the Lurgi gasifica-
tion system for hydrogen production.
Tar Distillation and Extract Hydroconversion
The heavy liquids from the LTC section are vacuum-distilled in the tar
distillation section. The overhead product is distillate fuel, and the bottoms
are sent to the residue separation area. The extract from the solvent re-
covery section is hydrotreated to produce the donor solvent and product oil.
Extract hydrogenation is done in four stages operating at 3000 psig and 800°-
8Z5°F temperature'in the presence of a Co-Mo-Ni catalyst. The overhead
vapors are cooled to separate hydrogen from the light oils. The recovered
hydrogen is compressed and recycled to the reactors. The hydrotreated
liquid product is flashed to 5 psig. The fuel gas is sent to the gas-treatment plant,
and gas liquor is sent tq^the waste-water-treatment plant to recover ammonia
and hydrogen sulfide. The hydrotreated liquid product is stabilized to remove
C4 and lighter hydrocarbons and then is fractionated. In the fractionator,
hydrogen donor solvent is separated from the light product oil. The hydrogen
48
-------
donor solvent is sent to the slurry system for makeup solvent, and light
product oil is delivered to the refinery to produce gasoline.
Gas Treatment and Sulfur Recovery
The fuel gas is produced at various sections of the plant. This gas is
treated in the amine system to remove carbon dioxide and hydrogen sulfide.
Some of the fuel gas is used as a fuel for the plant and refinery operation,
and the remaining amount is by-product for sale. The hydrogen sulfide
stream from the amine system is passed through the sulfur recovery system.
The sulfur recovery system consists of a modified Glaus plant and a Beavon
tail-gas plant.
Hydrogen Production
Hydrogen can be produced from the coal char. To form the char into
the proper size pellets, a mixture of tar, char, and dried coal must be coked.
These pellets are fed to the gasifier. The raw gas produced is passed
through quench systems, shift systems, an acid-gas-removal section, and a
methanation section. The gas containing hydrogen and methane is passed
through cryogenic separation units to produce a 96%-pure hydrogen stream and
a methane-rich stream. A hydrogen stream is used to hydrotreat the extract,
and the methane-rich stream is used as a fuel gas. Tables B-3, B-4, and B-5
show the composition of the important streams for a 50, 000 bbl/day plant.
Gasoline Production
Gasoline can be produced in the refinery from naphtha and distillate
fuel, as shown in Figure B-3. The distillate fuel is first hydrocracked and
sent to the distillation section along with naphtha. The 180°-400°F fraction is
sent to a reformer to increase the gasoline octane number. Some butane, the
C5-180°F fraction, and reformate (C5-400°F) are blended, and then some
tetraethyl lead is added to meet the specified octane number. The product gas
is utilized in the production of hydrogen. Some additional fuel gas is required
for plant fuel and hydrogen production.
49
-------
Table B-3. COMPOSITION OF GASEOUS STREAMS FROM CSF PROCESS*
Stream Number
CO
C02
H2
H2O
CH4
C2H6
C3H8
£4^10
H2S
N2
02
Total
Mol/hr
106 SCF/hr
1
2.48
15,82
4.95
20.79
9.34
3.09
6.80
36.73
100.00
1934.3
0. 73
2*
0. 20
37. 90
50. 20
5. 60
3.40
--
--
2. 70
—
100. 00
13,061
4. 95
3 4
8.42
12.18
96.02
5.02
4.81* 2.48
__
__
__
0.79
68.45 1.50
0.33
100.00 100.00
15,173 32,548
5.75 12.34
5
8.49
12.28
--
5.06
4.85
--
.
.--
68.99
0.33
100.00
15,053
- 5.71
6
--
35.34
36. 13
10.83
8.28
--
3.31
6. 11
100.00
8005
3.03
7
--
--
—
--
--
--
--
79.00
21.00
100.00
13,087
4. .96
8 9
__
__
100.00
__
. __
__
__
0.54
99.46
100.00 100.00
47,593 11,521
18.04 4.37
-See Figure B-2.
Dry gas.
"Assumed C2H6.
-------
Table B-4. COMPOSITION OF LIQUID STREAMS FROM CSF PROCESS
Butane
Light Oil
Naphtha
Hydrodistillate,
C4/400°F
Tar Oil, -230° C
Tar, +230° C
Extract
Residue
Spent Solvent,
400°/750°F
Solvent,
400°/750°F
Total
Ib/hi
2.00
98.00
3.92
96.08
Stream Number
4.04
77.66
3.47
14.83
100.00
100.00
8.19
91.81
1.35
96.38
7.75
86.81
5.44
100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00
60,783 1,097,742 1,063,100 7867 125,417 136,608 497,017 144,475
* See Figure B-2.
-------
Table B-5. COMPOSITION OF SOLID STREAMS FROM CSF PROCESS
Stream Number
Ul
c
H
N
O
s
Moisture
Ash
Total
Ib/hr
Extract, Ib/hr
1
59.04
4.19
1.10
6.28
3.67
14.40
11.32
100.00
2,436,750
—
2
68.97
4.90
1.28
7.34
4.29
--
13.22
100.00
1,666,667
3
1IJ+ '
67.59
4.80
1.26
7.19
4.20
2.00
12.96
100.00
427,708
4
4
r
53.67
2.52
1.25
3.85
5.03
--
33.68
100.00
617,300
66,892
5 6
51.93
1.80
1.29
3.25
4.80
--
36.93 100.00
100.00 100.00
563,083 263,450
7
84.58
6.36
1.09
0.74
0.80
--
6.43
100.00
193,467
Solvent, Ib/hr
Tar, Ib/hr
Total
2,436,750
995,175
--_ --_ --_ --_ --_ 26,192
1,666,667 427,708 1,679,367 563,083 263,450 219,659
* See Figure B-2.
-------
oo
H2: 81.7 X I06 SCF/DAY
34,200
bbl/DAY
10.3 °API
4612 bbl/DAY
FUEL GAS
HYDRO-
CRACKING
(High
Severity)
13.200 bbl/DAY
DISTILLATION
SECTION
C4:4822 bbl/DAY^
8550 bbl/DAY
C5- I80°F
180°- 400°F
55.2 °API ^
C4:l370bbl/DAV
EXCESS HYDROGEN 80% PURITY STREAM
REFINERY FUEL
5424 bbl/DAY
1165 bbl/OAY
OUTSIDE FUEL
TOTAL OUTSIDE
FUEL GAS,
-6589 bbl/DAY OR
41.5 X I09
Btu/DAY
C4 4499 bbl/DAY
49,840 bbl/DAY
GASOLINE
•*•
(0.0044 wt %
Sulfur)
TETRAETHYL
LEAD
38.3 X I06SCF/DAY
A-54-839
Figure B-3. FLOW DIAGRAM OF 50, 000 bbl/DAY
GASOLINE REFINERY
-------
Overall Energy Balance and Efficiencies
The overall energy balance is presented in Table B-6.
Table B-6. ENERGY BALANCE FOR CSF-PROCESS COAL-TO
GASOLINE (50,000 bbl/Day) PLANT
106 Btu/hr
Input
Coal (as received)
(1218.4 tons/hr X 2000 X 10,820 Btu/lb) 26, 365
Output
Gasoline (2076. 7 bbl/hr X 5. 3 million Btu/bbl) 11, 007
Butane (187. 5 bbl/hr X 4. 3 million Btu/bbl) 806
Fuel Tar (4. 95 SCF/m X 819 Btu/SCF) 4, 054
Sulfur (43.68 tons/hr X 2000 X 398. 3 Btu/lb) 348
Ammonia (5. 37 tons/hr X 2000 X 9675 Btu/lb) 104
Cooling by Air and Water 3, 155
Other (by Difference)* 6, 891
Total N 26, 365
* Includes sensible heat of product streams, heating values of other
unaccounted products, and heat lost to the atmosphere.
The overall efficiency (including by-procluct credit) of the process is about
61%, and the coal-to-gasoline efficiency is about 42%. The overall efficiency
of the CSF Process producing naphtha and distillate fuel is about 67%, and the
efficiency of the refinery is about 91%. This 67% efficiency of the CSF Process
is achieved by using the Lurgi gasification system for the production of hydro-
gen. However, on the basis of the information given in Ref. 2, if the BI-GAS
gasification system instead of Lurgi is used for the production of hydrogen,
the overall efficiency can be improved by 4%. The use of the catalytic cracking
unit instead of the high severity hydrocracking unit could improve the efficiency
of the refinery section. However, the use of the catalytic cracker produces
more distillate fuel.
Pollution
About 93% of the total sulfur is recovered as elemental sulfur
in this process by using a Glaus plant with a Beavon tail-gas process. About
5% of the total sulfur is' recovered as elemental sulfur by using iron oxide
towers. The reaction of iron oxide with hydrogen sulfide forms iron sulfide
and water. The sulfur from the iron sulfide can be recovered by using a
suitable solution. The sulfur balance around the system is given in Table B-7.
54
-------
Table B-7. SULFUR BALANCE FOR CSF-PRQCESS COAL-TO-
GASOLINE (50,000 bbl/Day) PLANT
Ib/hr (as sulfur)
Input
Coal 89,482
Output
Elemental Sulfur (By-product)
Sulfur in Liquid Products
Sulfur in Refinery Off-Gas
Sulfur Compounds to Atmosphere From
Sulfur Recovery Plants
Sulfur in the Stack Gas
Total
87,367
24
580
80
1.431
89,482
The gas liquor, containing mainly ammonia and hydrogen sulfide, is
treated in the Chevron waste-water-treating process. The 99. 9%-pure
hydrogen sulfide stream and the 99%-pure ammonia stream are recovered.
The treated water contains less than 100 ppm ammonia and less than 20 ppm
hydrogen sulfide. Some of the effluent water, which may contain phenols
(about 30 mg/liter), is treated by biological oxidation. The process requires
about 120,000-180,000 gpm of cooling water. Table B-8 lists the wastes,
their sources, and the treatments required.
Table B-8. WASTES, SOURCES, AND TREATMENTS
FOR A COAL-TO-GASOLINE PLANT
Waste
Sources
Treatment
Coal Dust
Ash
Waste Water (Contains
Ammonia, Hydrogen
Sulfide)
Hydrogen Sulfide
Sulfur Dioxide
Coal-crushing system,
conveyor belt
Ga.sifier
Residue separation
Solvent recovery
Extract hydroconversion
system
Gasification system to
produce hydrogen
Refinery
Regenerator off-gas
Gas and liquid fuels
fired boilers, heaters,
and incinerators
Cyclone separators,
bag filter
Scrubbing and various
waste-water and solid
treatments
Modified Chevron
Process, Phenosolvan
Process, biological
treatments
Glaus plant with Beavon
tail-gas process,
Stretford Process, etc.
Lime treatment, Wellman-
Lord, etc.
55
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Economic Analysis
The economic analysis is performed by using the D'C'F method. The
investment and operating costs of a 50, 000 bbl/day gasoline plant are given
in Tables B-9 and B-10, respectively. The investment and operating costs
in Ref. 2 are based on those in 1972; therefore, these numbers have been
escalated to bring the costs to end-of-1973 levels. In this study, for the
production of hydrogen, a Lurgi gasification system is used, but according to
Ref. 2, a BI-GAS gasification system is somewhat cheaper compared with a
Lurgi system. According to our estimate, the investment cost of a refinery
for producing gasoline from naphtha and distillate is about $118 million.
This cost can be reduced by using a catalytic cracking unit rather than a
hydrocracking unit. However, the use of a catalytic cracking unit produces
by-product distillate fuel, so the amount of the gasoline produced is reduced.
The calculation method8 for the unit cost of the product is presented in Table
B-ll. This financing method includes the following factors:
• A 25-year project (synthesis plant) life
• Depreciation calculated on a 16-year sum-of-the-digits formula
• 100% equity capital
• A 48% Federal Income Tax rate
• A 12% DCF
• Plant start-up costs as expenses in year zero.
For 30^/million Btu coal, the production oost of the gasoline is about
$13. 85/bbl, or about $0. 33/gal. This unit cost will vary depending on the
accounting method used, feed cost, and variation in other financial factors; e. g. ,
by using the utility method,23 the unit cost of the product is $10. 6l/bbl, or
$0.253/gal.
56
-------
Table B-9. INVESTMENT COST FOR CSF-PROCESS
COAL-TO-GASOLINE (50,000 bbl/Day) PLANT
End-of-1973 Cost,
C omponents $1000
Coal Preparation 14,024
Extraction 11,002
Residue Separation 4,953
Solvent Recovery 6,783
Low-Temperature Carbonization 11,938
Tar Distillation 2,758
Extract Hydroconversion and Distillation 52,693
Fuel Gas Compression and Treatment 9,354
Hydrogen Production System (using Lurgi gasification
system) 130,425
Refinery and General Facilities for Refinery 117,480
Sulfur Recovery System 8, 599
Waste-Water Treatment 1,739
Boiler Feed Water Treatment, Steam, and Power
Generation System 28,377
Cooling Towers and Pumps 16, 500
Initial Catalyst and Chemicals 1,813
Power Distribution 3,030
General Facilities 28,515
Total Direct Cost of Plant Including Contractor's
Overhead and Profit 449,983
Contingencies (15%) 67,497
Total Plant Investment (I) 517,480
Interest During Construction (0.23676 X I) 122, 518
Start-up Cost (20% of gross operating cost) 24,332
Working Capital
Coal Inventory (60 days of feed at full rate) 11, 390
Materials and Supplies (0. 9% of total plant
investment) 4, 657
Net Receivables (1/24 X annual revenue received) 9,448
Total Capital Required 689,825
57
-------
Table B-10. OPERATING COST FOR CSF-PROCESS COAL-TO-
GASOLINE (50,000 bbl/Day) PLANT (90% Stream Factor)
Annual Cost,
Components $ 1000
Coal Feed (at 26, 365 X 106 Btu/hr), 30^/106 Btu 62, 358
Other Direct Materials, Catalysts, and Chemicals 6,954
Purchased Utilities
Raw-Water Cost (15,000 gpm X 30^/1000 gal) 1,220
Electric Power (50,033 kWhr/hr X 0. 9^/kWhr) 3, 550
Labor
Process Operating Labor (131 men/shift at $5/hr and 5,439
8304 man-hr/yr)
Maintenance Labor (1.5% of total plant investment) 7, 762
Supervision (15% of operating and maintenance labor) 1, 967
Administration and General Overhead (60% of total
labor, including supervision) 9,046
Supplies
Operating (30% of process operating labor) 1,632
Maintenance (l. 5% of total plant investment) 7, 762
Local Taxes and Insurance (2.7% of total plant
investment) 13,807
Total Gross. Operating Cost 121,662
By-product Credit
Butane (4499 bbl/day X 42 X 10^/gal) 6,207
Fuel Gas (4054'X 10* Btu/hr X 24 X 50jf/106Btu) 15,981
Sulfur (39 LT/hr X $10/LT X 24) 3,075
Ammonia (128. 9 tons/day X $25/ton) 1,059
Total By-product Credit 26,322
Net Operating Cost 95,340
58
-------
Table B-ll. CALCULATION FOR DETERMING UNIT PRODUCTION
COST BY DCF METHOD FOR CSF-PROCESS COAL-TO-
GASOLINE (50,000 bbl/Day) PLANT
Unit Cost of the Product
N + 0.23816 I + 0.1275 S + 0.23077 W
G
where
N« Net Operating Cost = $95,340,000
I = Total Plant Investment = $517,480,000
S t= Start-up Cost = $24,332,000
W = Working Capital = $25,495,000
G = Annual Product Production (49,840 bbl/day X 328. 5 days/yr)
UnitC°St=
= $0.3309/gal
= $2. 6l2/106Btu (high heating value)
= $2. 808/106 Btu (low-heating value)
Table B-12. CALCULATION FOR DETERMINING UNIT PRODUCTION
COST BY DCF METHOD FOR CSF-PROCESS COAL-TO-
GASOLINE-PLUS-DISTILLATE-OIL (50,000 bbl/Day) PLANT
Unit Cost of the Product
N + 0.23816,1+ 0.1275S+ 0.23077W
where
N = Net Operating Cost = $90,303,000
I = Total Plant Investment = $491,274, 000
S = Start-up Cost = $23,325,000
W= Working Capital = $24,811,000
G " Annual Product Production (49, 840 bbl/day X 328. 5 days/yr)
TT«4* ^«o4. $216,005,000 _ * 1Q,/KX1
Unit Cost= l6)372)44obbl = $13< !93/bbl
= $0.3141/gal
= $2. 356/106 Btu^iigh,heating value)
= $2. 511/106 Btu (low heating value)
59
-------
If, instead of gasoline (primarily), the coal oil is refined to produce
approximately a 50:50 product mix of gasoline and distillate oil (plus by-
products of tar, sulfur, ammonia), the resulting costs are reduced somewhat.
In this case, a catalytic cracking unit (instead of a hydrocracker) is used in the
refinery, and other refinery investments costs could be reduced slightly.
Certain operating costs also would be reduced.
The investment cost for the "Refinery and General Facilities for
Refinery" becomes about $100 million; the "Total Direct Cost of Plant"
becomes $427, 195,000, and the "Total Plant Investment" becomes $491,274,000.
Labor and supply costs also are reduced slightly and result in a "Total Gross
Operating Cost" of $116,625,000, and the "Net Operating Cost" becomes
$90,303,000. Table B-12 presents the corresponding DCF unit costs for a
50, 000 bbl/day gasoline-plus-distillate-oil plant (from coal). The exact
division of costs between gasoline and distillate oil has not been made (and
would be arbitrary within the scope of this study).
If a 10% (instead of 12%) DCF financing model is used for the synthesis
plant to produce gasoline and distillate oils from coal, the unit cost of the
product becomes $2. 27/million Btu (low heating value), rather than $2. 51/
million Btu.
60
-------
Gasoline and Distillate Fuels From Oil Shale
The technology for the production of gasoline from oil shale
exists today. The major steps required are as follows:
• Shale mining, crushing, and screening, and spent shale disposal
• Shale retorting to produce crude shale oil
• Crude shale oil upgrading to syncrude (to make it acceptable as a
conventional petroleum refinery feedstock and to facilitate handling
in pipelines)
• Refining of syncrude to produce gasoline and light distillates.
The final gasoline cost is strongly dependent on both the richness
(organic matter content) of the oil shale and the type of mining employed.
Flow sheets for the production of gasoline and light distillates from shale oil
are given in Figure B-4 and Table B-13.
Description of Gas Combustion Process
Mining Step
The first and physically largest part of the process comprises
mining, crushing, and screening and spent shale disposal. Both underground
and strip or open-pit surface mining have been considered for mining oil shale
in the Western United States. The areas considered — the Piceance Creek Basin
of Colorado and Uinta Basin of Colorado and Utah— are shown in Figure B-5.
Two basic methods of underground mining are envisioned — shaft and
adit entry. Adit entry would be used when the shale formation outcrops the
surface. In this case, the formation can be mined by tunneling from the site
of the outcropping. In the event of no outcropping, a shaft must be sunk.
Because the number of areas with shale outcroppings is small compared with
the number that would require shaft mines, adit mining was not considered here. 5
Nor was either method of surface mining (strip or pit) considered here, because
we assumed that, to be economically attractive the first plants would be based
on the high-quality resources for which underground mining generally is required.
Retorting Step
A number of processes for converting oil shale to oils have been studied
on a rather large scale; Table B-14 lists those processes being seriously
considered now.
61
-------
SHALE OIL AND GAS PRODUCTION
CRUDE SHALE UPGRADING TO SYN-CRUDE
SYN-CRUDE REFINING
ro
O GASEOUS STREAM
/\ LIQUID STREAM
O SOLID STREAM
CATALYTIC
HYDROGENATION
CATALYTIC
HYDROGENATION
CRUDE SHALE
OIL DISTILLATION
Figure B-4. FLOW DIAGRAM FOR PRODUCTION OF GASOLINE AND
LIGHT DISTILLATE (50,000 bbl/Day) FROM OIL SHALE
0-54-820
-------
Table B-13. PROCESS STREAMS FROM PRODUCTION OF GASOLINE AND
DISTILLATE FUELS FROM OIL SHALE*
Gaseous Streams
Liquid Streams
Solid Streams
OJ
Stream
No.
1
2
3
4
5
Description
Fuel gas
Light gases
Fuel gas
Hydrogen sulfide
Gas plus oil vapor
Flow, t
tons/CD
508
--
--
--
s
Description
Crude shale oil
Naphtha
Light oil
Heavy oil
Resdual oil
Flow, t
bbl/CD
57,083
•
--
--
—
Description
Run-of-mine shale
Sized Shale
Dust loss
Spent shale
Coke
Flow, +
tons/CD
85,780
84,650
1,130
65,713
932'
6 Process hydrogen
7 Steam
8 Process gas
9 Fuel gas
10 Process hydrogen
11 Fuel gas
12 Fuel gas
13 Fuel gas
14 Plant fuel gas
15 Ammonia 150
16
17
18
* See Figure B-4.
t CD = calendar-day.
* In 106 SCF/day.
Light oil and naphtha
Naphtha
Water
Water
Syncrude 54,521
Gasoline additives
Motor gasoline 25,193
Jet fuel 4,471
Distillate fuel 20,336
_ij-Butane to sales 1,613
Decant oil to sales 191
Decant oil to plant fuel
Sulfur, tons/CD 47
-------
GREAT
DIVIDE
BASIN
WYOMING
Rock Spring
WASHAKIE
I.BASIN
X-~ 1 SAND
V / WASH
^> BASIN
Salt Lake City
COLORADO
UINTA BASINi;;l
Naval Oil-Shale
Reserves land3
Naval Oil-Shale
Reserve 2
Battlement
Mesa
*mM\ Grand
::;!i=!;iiaiy Mesa
EXPLANATION
Area underlain by the Green
River Formation in which the
oil shale is unappraised or
low grade
Area underlain by oil shale
more than 10 feet thick, which
yields 25 gallons or more oil
per ton of shale
Figure B-5. GREEN RIVER OIL, SHALE FORMATION
OF COLORADO, UTAH, AND WYOMING (Source: Ref. 5)*
Reprinted with permission from the National Petroleum Council, ©1971.
64
-------
Table B-14. CURRENT OIL-SHALE-RETORTING TECHNOLOGY
I. Processes Requiring Mining of Oil Shale
A. Processes employing hot solids to supply the heat required for
retorting
1. TOSCO II Process (Colony Development Co. )
2. Lurgi-Ruhrgas Process
B. Processes employing internal gas combustion within the retort to
supply heat
1. Gas Combustion Process (U.S. Bureau of Mines)
2. Paraho Process (Development Engineering)
3. Rock-Pump Process (Union Oil Co.)
C. Processes employing external heat generation
1. Modified Paraho Process (Development Engineering)
2. Modified Rock-Pump Process (Union Oil Co.)
3. Petrosix Process (Petrobras)
4. IGT Process
II. In Situ Retorting Processes
A. U.S. Bureau of Mines
B. Occidental Petroleum Company
Separate flow sheets and economic studies for each of these processes
were not practical within the scope of this program. However, a number of
excellent reviews recently have been published describing all the various oil
shale conversion processes, 7> 9
We selected the Gas Combustion Process for study here; adequate
engineering data are available for detailed assessments. This process was
developed by the U.S. Bureau of Mines. Although operational difficulties were
encountered with the equipment used in tests prior to 1955, work was done in
a demonstration plant with a capacity as large as 150 tons/day. The Bureau's
large-scale equipment also was operated later by six petroleum companies,
and testing was continued until 1967 through a lease agreement with the Colorado
School of Mines Research Foundation. In the latter tests, shale feed rates as
high as 360 tons/day were achieved.
A simplified flow sheet of the process is given in Figure B-6. The heart
of this process is the retort itself. Here, raw shale in the 1-1/4 to 3-inch
size range is fed countercurrently to hot recycled product gas in a vertical,
refractory-lined retort. At the top of the retort, where the raw shale enters,
is a product cooling zone in which the raw shale is partially heated and the hot
65
-------
RAW SHALE
RETORT
VENT
GAS
'DILUTION
GAS
AIR
b
SPENT
SHALE
ELECTROSTATIC
PRECIPITATOR
nil
m
Mil
MULTICLONE
RECYCLE
GAS
PRODUCT OIL
Figure B-6. FLOW DIAGRAM OF GAS COMBUSTION PROCESS DEVELOPED
BY U.S. BUREAU OF MINES (Source: Ref. 4)
66
-------
gaseous and vaporized liquid products from retorting are cooled. The next
zone of the retort is the retorting zone in which the shale is finally heated
to retorting temperature by hot flue gas injected below this zone. This flue
gas is generated by burning a portion of the recycle gas with air in a combustion
zone. Some of the organic matter in the spent shale is also burned here to
provide part of the heat requirement. The spent shale then travels downward
through a heat recovery zone in which the hot solids transfer their heat to
recycle gas flowing counter currently upward.. The primary products of this
process are crude shale oil, a low-Btu product gas, and spent shale. Typical
yields and product properties are given in Tables B-15 and B-16, respectively.
Upgrading of Crude Shale Oil
Crude shale oil presents two major problems: Firsi; its high
viscosity and pour point make transport by pipeline difficult. Second, it has a
very high nitrogen content, so if shale oil were a large fraction of the refinery
feed, existing refinery processes could not use it directly. Therefore, crude
shale oil probably would be upgraded at the production site before being refined.
Techniques for upgrading crude petroleum fractions are applicable to
crude shale oils. The most likely process is catalytic hydrotreating, which
converts the nitrogen compounds to ammonia and the sulfur compounds to
hydrogen sulfide. In the process, not only is the sulfur content reduced to a
very small value, but the specific gravity and viscosity are reduced. Because
the crude shale oil must be distilled into various fractions before the catalytic
hydrotreating step, the oil is effectively thermally treated; this sufficiently
improves the pour point of the material so that it can be transported by
pipeline.
The major steps in a typical upgrading stage are shown in Figure B-4.
This is only one possible approach, however, and is based largely on the
flow sheet given in the NPC study.5 First, the crude shale oil must be distilled
to remove the heavy end fractions that could not be upgraded sufficiently. These
heavy end fractions are sent to a delayed coker with the coke (by-product) and gas
plus oil vapors (recycled to process) produced. Because different conditions
are required for hydrotreating the light and the heavy fractions, each is sent to
a separate hydrotreating stage. After treating, these two streams are
combined, and the water, hydrogen sulfide, and ammonia are separated.
Water is added to wash out the ammonia and hydrogen sulfide. After fractionation,
67
-------
Table B-16. PROPERTIES OF TYPICAL CRUDE SHALE OIL
Specific Gravity, "API
Pour Point, °F
Sulfur Content, wt %
Nitrogen Content, wt %
Viscosity, SSU at 100°F
Analysis of Fractions
Butanes 4- Butanes, vol % of total
C5to 350°F Naphtha
Vol % of Total Oil
Specific Gravity, "API
Sulfur Content, wt %
Nitrogen Content, wt%
350°-550 °F Distillate
Vol % of Total Oil
Specific Gravity, °API
Sulfur Content, wt %
Nitrogen Content, wt %
550°-850°F Distillate
Vol % of Total Oil
Specific Gravity, "API
Sulfur Content, wt %
Nitrogen Content, wt %
Above 850°F Residue
Vol % of Total Oil
Specific Gravity, "API
Sulfur Content, wt %
Nitrogen Content, wt %
28.0
75
0.8
1.7
120
4.6
19.1
50.0
0.70
0.75
17.3
31.0
0. 80
1. 35
33.0
21.0
0.80
1.90
26.0
12.0
1.0
2.4
Table B-15. TYPICAL RETORTING PRODUCT YIELDS*
Component
Oil
Butanes and Butenes
C5-C8 Hydrocarbons
Fischer Assay Oil
Total C4 -4- Oil
Gas
co2
H2S
\~* — C
Total Gas
I
Semiworks Plant
Fischer Assay
Product Balance
— Yield, lb/100 Ib Fischer Assay Oil-
Total Gas and Oil
Based on TOSCO II Process data.
2. 19
4.06
99.59
105.84
10.78
8. 58
1. 34
20. 70
126.54
1.84
2. 30
100.00
104. 14
11.72
9. 14
I. 14
22.00
126.14
68
-------
the water is recycled, the ammonia is liquefied for storage and sale, and
the hydrogen sulfide is sent to a Glaus-type sulfur plant, where it is converted
to elemental sulfur and sold. Hydrogen for hydrotreating is made by catalytic
steam reforming of natural gas or light naphtha. The properties of the final
sync rude are given in Table B-17. As shown, there is no fraction boiling
above 850°F.
Table B-17. PROPERTIES OF TYPICAL SYNCRUDE
Specific Gravity, ° API 46.2
Pour Point, °F .50
Sulfur Content, wt % 0 . 005
Nitrogen Content, wt % 0 . 035
Reid Vapor Pressure, psi 8
Viscosity, SSU at 100 °F 40 , •
Analysis of Fractions
Butanes and Butenes, vol % of total 9.0
C5to350° F Naphtha
Vol % of Total 27. 5
Specific Gravity, "API 54.5
Sulfur Content, wt % <0.0001
Nitrogen Content, wt % 0.0001
350°-550°F Distillate
Vol % of Total Oil 41.0
Specific Gravity, ° API 38.3
Sulfur Content, wt % 0.0008
Nitrogen Content, wt % 0.0075
550°-850°F Distillate
Vol % of Total Oil 22.5
Specific Gravity, "API 33.1
Sulfur Content, wt % < 0. 01
Nitrogen Content, wt % 0.12
Sync rude Refining
Because at this point the shale oil is upgraded to the equivalent of a
completely desulfurized crude, the next step is assumed to be a conventional
petroleum refining.
The light overhead stream is the equivalent of straight-run gasoline and
needs no further treatment other than the option of additives. The next heavier
stream goes to catalytic reforming for upgrading to gasoline with a fuel-gas
69
-------
by-product. The next two streams are jet fuel and distillate fuel. The bottoms
product goes to catalytic cracking, which results in several products: more
fuel gas, more distillate fuel, decant oil (one stream to sales and one stream to
plant fuel), and C3 and C4 olefins to an alkylation unit. The products from the
alkylation unit are isobutane and alkylate for more motor gasoline.
Overall Energy Balance and Efficiencies
The energy balance for the synthesis process is presented in Table B-18.
The efficiency (including by-product heat credit except heat credit of coke) of
the process is about 62. 5%, and the efficiency of oil shale-to-liquid products
(gasoline, jet fuel, and distillate fuel) conversion is about 60%. If the heat
credit of coke is taken, the overall efficiency of the synthesis process is about
68%.
Table B-18. ENERGY BALANCE FOR PRODUCTION OF 50,000 bbl/DAY
OF GASOLINE AND LIGHT DISTILLATE FROM 30 gal/TON
COLORADO OIL SHALE
106 Btu/day
Input
Oil Shale (85,780 tons/day X 2540 Btu/lb X 2000) 452,918
Electricity (92, 100 kWhr/day X 3413 Btu/kWhr) 314
Natural Gas (3,610,000 SCF/day X 1000 Btu/SCF) 3,610
Total Input 456,842
Output
Motor Gasoline (25, 193 bbl/day X 5. 3 million Btu/bbl) 133, 523
Jet Fuel (4471 bbl/day X 5. 4 million Btu/bbl) 24, 143
Distillate Fuel (20,336 bbl/day X 5. 6 million Btu/bbl) 113,882
i-Butane (1613 bbl/day X 4. 325 million Btu/bbl) 6,976
Decant Oil (191 bbl/day X 6 million Btu/bbl) 1, 146
Coke (932 tons/day X 2000 X 14,000 Btu/lb) 26,096
Sulfur (47 tons/day X 2000 X 3983 Btu/lb) 374
Ammonia (150 tons/day X 2000 X 9675 Btu/lb) 2,902
Spent Shale (65. 713 tons/day X 305 Btu/lb X 2000) 40,085
Cooling by Air and Water 64,852
Other (by Difference)* 42,863
Total Output 456,842
* Includes sensible heat of product streams, heating values of other
unaccounted products, and heat lost to the atmosphere.
Pollution
The largest pollutants from this process are the spent shale, the dust
from crushing the shale, the pollutants in the flue gases from the retorting of
70
-------
the sulfur and nitrogen compounds removed from the crude shale oil, and the
waste water used to wet the spent shale. The quality of the waste products from
the upgrading and refining steps should not be significantly different from that
of the products of present commercial processes. There is a considerable lack
of information about the retorting and spent shale disposal.
In general, however, we can expect to be able to remove all gaseous
sulfur compounds by conventional processing. This would involve a Glaus-
type plant with'one of the many tail-gas cleanup processes in series (such as
Scot, Beavon, etc. ). Similarly, ammonia removal should not be a problem.
The gas streams from retorting and catalytic cracking will contain dust, which
might require electrostatic precipitators. Also, the gas from retorting
may contain fine oil mist, which might require electrostatic precipitators.
The low-Btu stack gases probably will be used for plant fuel. The stack
gases from burning this gas could be sent to a Wellman-Lord Process to recover
sulfur dioxide, which, in turn, could then be fed to the Glaus plant to produce
more elemental sulfur. Table B-19 gives the sulfur balance around the system.
Table B-19. SULFUR BALANCE FOR PRODUCTION OF 50,000 bbl/DAY
OF GASOLINE PLUS LIGHT DISTILLATE FROM 30 gal/TON
COLORADO OIL SHALE
Analysis of Shale
Composition, dry basis
Organic Carbon
Mineral Carbon Dioxide
Hydrogen
Nitrogen
Oxygen (by difference)
Sulfur
Ash
Total
Input
Oil Shale to Retorting
Output
Spent Shale Dust
Sulfur From Sulfur Plant
Stack Gases
Gaseous Effluent Sulfur Plant
Total
Feed Shale
Spent Shale
13 61
15.87
2.06
0.46
0.45
0.75
66.80
Wt /u
4.94
14.74
0.27
0.28
—
0.62
79.15
100.00 100.00
Ib/hr (as sulfur)-
52,906
33,952
3,917
13,987
1,050
52,906
71
-------
The liquid-phase pollutants would be primarily the quench water used to
cool the spent shale and the resultant alkalinity. Because the Gas Combustion
Process is carried out at relatively high temperatures, substantial mineral
carbonate (primarily calcium and magnesium) decomposition and production of
calcium and magnesium oxides would be expected. When contacted with water,
these oxides will form basic calcium and magnesium hydroxides.
The process will use on the order of 600,000 gph of total makeup, cooling,
and process water. The waste water of the process may be contaminated with
hydrogen sulfide, other sulfide compounds, nitrogen compounds (principally
amines and ammonia), and oil shale fines (both from raw shale and spent shale).
There will also possibly be thermal pollution from the effluent cooling water.
The major solid waste environmental problem is the volume of the spent shale.
The inability to return all the spent shale to the mine (because the crushed shale
has on the order of 30% voids and some possible swelling during processing)
creates a severe problem in spent shale disposal. Dust from the mining
operation, as well as the spent shale, can be carried off by the wind and also
cause environmental problems. Table B-20 lists wastes arid their sources
and required treatments.
Table B-20. WASTES, SOURCES, AND TREATMENTS FOR AN OIL-
SHALE-TO-GASOLINE PLANT
Waste
Sources
Treatment
Shale Dust and Fines
Spent Shale
Waste Water (con-
taining dissolved sul-
fur and nitrogen com-
pounds and traces of
hydrocarbons)
Hydrogen Sulfide
Sulfur Dioxide
Shale crushing, spent shale
disposal, retort off-gases,
shale mining operations
Retorting
Mining, retorting, and re-
fining of crude shale oil
Retorting and refining off-
gases
Flue gases from combustion
of above retorting and re-
fining off-gases
Briquetting of fines, cyclone
separators, bag filters,
electrostatic precipitators,
scrubbers, etc.
Watering down to cool
and reduce dusting, com-
paction, and benching
Conventional biological and
chemical treatment. Also
separations to remove oil
droplets.
Typically, Claus Process
plus recent tail-gas clean-
up processes
Wellman-Lord lime treatment,
etc.
72
-------
Economic Analysis
The economic analysis is performed by using the DCF method. The
investment and operating costs of a 50,000 bbl/day plant are given in Tables
B-21 and B-22, respectively. The investment and operating costs are taken
from Refs. 3, 5, and 8, and these numbers have been escalated by an appropriate
factor to bring them to December 1973 levels. According to our estimate,
the investment cost of the refinery to produce gasoline and distillate fuel from
syncrude is about 1573 million. One-hctlf of the labor and supplies costs is
charged to mining to estimate the working capital for raw material inventory.
The calculation method8 for the average unit cost of the products is presented
in Table B-23. This financing method includes the following factors:
• A 25-year project (synthesis plant) life
• Depreciation calculated on a 16-year sum-of-the-digits formula
• 100% equity capital
• A 48% Federal Income Tax rate
• A 12% DCF rate
• Plant start-up costs as expenses in year zero.
The average production cost of gasoline and distillate fuel from oil shale
is about $10.33/bbl, or about $0.25/gal. The price differential between gasoline
and distillate fuel will set the exact price for these two fuels. Because both
the liquid products can be utilized as a motor fuel, the price differential could
be very small. This unit cost depends on the accounting method used, feed
cost, and variation in other financial factors; e. g. , by using the utility method, 8
the average unit cost of the products is $7.39/bbl, or about $0. 18/gal.
If a 10% (instead of 12%) DCF financing model is used for the synthesis
plant to produce gasoline and distillate oils from oil shale, the unit product
cost becomes $ 1. 81/million Btu (low heating value), rather than $2.05/
million Btu.
73
-------
Table B-21. INVESTMENT COST FOR THE PRODUCTION OF 50,000 bbl/DAY
OF GASOLINE PLUS LIGHT DISTILLATE FROM 30 gal/TON COLORADO
OIL SHALE
Components End-of-1973 Cost, $1000
Mining (initial investment and present worth
of deferred investment) 53, 772
Retorting (including crushing, screening, and
briquetting) 89,899
Crude Shale Oil and Gas Upgrading 78,815
Syncrude Refining for Production of Gasoline
and General Facilities for Refinery 73,415
Particulate Emission Control 5,740
Spent-Shale Disposal 17,000
Initial Catalyst 5,517
Utilities 28,837
General FacLlities 21, 486
Total 374,481
Contractor's Overhead and Profit (10%) 37,448
Total 411,929
Contingencies (15%) 61,789
Total Plant Investment (I) 473,718
Interest During Construction (0. 23676 X I) 112, 158
Start-up Cost (20% of gross operating cost) 11, 155
Working Capital
Raw Material Inventory (60 days of feed at full rate) 3,978
Material and Supplies (0.9% of total plant
investment) 4,263
Net Receivables (1/24 X annual revenue received) 7,070
Total Capital Required 612,342
74
-------
Table B-22. OPERATING COST FOR THE PRODUCTION OF 50,000 bbl/DAY
OF GASOLINE PLUS LIGHT DISTILLATE FROM 30 gas/TON COLORADO
OIL SHALE
Component Annual Cost, $ 1000
Direct Material, Catalysts, and Chemicals 4,400
Purchased Utilities
Raw Water Cost (9800 gpm X $0.3/1000 gal) 1,391
Electricity for Refinery
(92,000 kWhr/day X $0. 009/kWhr) 272
Natural Gas (3,610,000 SCF/day X $1.0/1000 SCF) 1,186
Labor
Process Operating Labor (150 men/shift at $5/hr and
8304 man-hr/yr) 6,228
Maintenance Labor (1.5% of total plant investment) 6,516
Supervision (15% of operating and maintenance labor) 1,912
Administration and General Overhead (60% of total labor,
including supervision) 8,794
Supplies
Operating (30% of process operating labor) 1,868
Maintenance (1.5% of total plant investment) 6, 516
Local Taxes and Insurance (2.7% of total plant investment) 11,7Z9
Spent Shale Disposal (at $0.23/ton X 65,713 tons/day) 4,965
Total Gross Operating Cost 55,777
By-product Credit
Sulfur (47 tons/day X 2000 tons/2240 LT
X $10/LT X 328. 5) 138
Ammonia (150 tons/day X $25/ton X 328. 5) 1,232
i-Butane and Decant Oil (1804 bbl/day X 42 X $0. 10/gal
X328.5) 2,489
Total By-product Credit 3,859
Net Operating Cost 51,918
75
-------
Table B-23. CALCULATION FOR DETERMINING UNIT PRODUCTION
COST BY DCF METHOD FOR 50,000 bbl/DAY OF GASOLINE PLUS
LIGHT DISTILLATE FROM 30 gal/TON COLORADO OIL SHALE
Unit Cost of the Product
N + 0.23816 14-0. 1275S + 0.230777 W
where
N = Operating Cost^ $51, 918, 000
I = Total Plant Investment = $473, 718, 000
S = Start-up Cost = $ 11, 155,000
W= Working Capital = $15,311,000
G = Annual Product Production [ (29. 664 bbl/day
gasoline + 20, 336 bbl/day distillate fuel) X
328.5 days/yr] = $ 16,425,000 bbl/yr
or " :
v on Btu Basis: (29, 664 bbl/day X 5. 3 X 106 Btu/
bbl + 20, 336 bbl/day X 5. 6 X 106 Btu/bbl) X
328.5 days/yr = $89,056,550 X 106 Btu/yr (high heating value)
Unit Cost = $1|?*ioe'nnn = $ 10- 33/bbl (average price of gasoline and
ib,^,UUU distillate fuel)
= $ 1. 905/106 Btu (high heating value)
= $2.048/106 Btu (low heating value)
76.
-------
Methanol From Coal
The reactions occurring in the process for making methanol are as
follows:
CO 4- 2H2 -» CH3OH (B-3)
CO2 + 3H2-4 CH3OH<4- H2O (B-4)
CO* 3H2 •* CH4 j- H2O (B-5)
CH3OH -» CO-* HCOOCH3 (B-6)
2CH3OH-* CH3OCH3 + H2O (B-7)
Reactions B-3 and B-4 are highly desirable, and the remaining
reactions are unwanted side reactions. For the production of methanol, the
synthesis gas (containing carbon monoxide, hydrogen, and carbon dioxide) is
required. The synthesis gas can be produced from coal, naphtha, natural gas,
or heavy oil and water. Its manufacturing cost is highly sensitive to the price
of raw material (cents/million Btu), and in the future coal may be the most
attractive raw material for the production of methanol, compared with other
conventional fuels, because of the faster increase in the prices of conventional
fuels.
For the production of synthesis gas (carbon monoxide, carbon dioxide,
and hydrogen) from coal, many gasifiers are available (e.g. , Lurgi, Koppers-
Totzek, Winkler, Wellman-Galusha). On the basis of energy requirements,
a high-pressure gasifier is more desirable than a low-pressure gasifier. In
high-pressure operation, only oxygen has to be compressed, not the entire
amount of synthesis gas. The amount of oxygen is only one-third or one-fourth
of the synthesis gas produced; as a result, the compression cost is reduced in
the high-pressure process. However, high-pressure processes make more
methane, compared with low-pressure processes; consequently, more gas has
to be purged from the methanol synthesis loop. However, this purge gas can
be utilized as a fuel, so this is not a major disadvantage. Also, at high-
pressure operation, oxygen consumption per ton of coal is less compared
with low-pressure operation. In this study a Koppers-Totzek gasifier, which
is a low-pressure gasifier, is used to produce synthesis gas. This process is
selected because more information is available; it does not produce liquid
products such as tars; and Lurgi is the only commercially available high-
pressure process, but it also produces tars, phenols, and other liquid
products.
77
-------
Description of Koppers-Totzek Gasifier and ICI Synthesis
The Koppers-Totzek gasifier can be operated on all types of coal without
pretreatment. Coal is dried and pulverized (70% through 200 mesh). A
homogenous mixture of oxygen and pulverized coal is introduced to the
gasifier through coaxial burners at each end. The gasifier is a refractory-
lined, horizontal, cylindrical vessel with conical ends, as shown in Figure B-7.
Oxygen, steam, and coal react at about atmospheric pressure and about
3300°F in the gasifier. Fixed carbon and volatile matter are gasified to
produce off-gas containing carbon monoxide and hydrogen. Coal ash is
converted into molten slag and some of this drops into a water-quench tank,
while the remainder is carried by the gas. Low-pressure steam is circulated
around burners and refractory to protect them from excessive temperature.
Gas leaving the gasifier is quenched with water to solidfy entrained
molten ash and prevent it from solidifying on the walls of the waste-heat
boiler. After passing through the waste-heat boiler, the gas is scrubbed in
a high-energy water-scrubbing system, which reduces its solids loading to
0.002-0.005 grains/SCF and lowers it stmperature to about 100°F. For this
kink of scrubbing, venturi scrubbers are used. Finally, prior to compression,
particulates are removed by electrostatic precipitation.
The gas composition does not vary much with type of coal used. The
extremely high temperatures ensure that any high-molecular-weight hydrocarbons
pyrolyzed from the original coal will be destroyed. The product gas contains
about 0.1% methane; 80% of the sulfur in the coal is converted to H2S, and the
rest appears as carbonyl sulfide (6-12%) and as sulfur in the fly ash. The
concentration of nitrogen oxides is about 5 ppm. Steam and oxygen consumption
in this case are 0. 248 ton/ton and 0. 798 ton/ton of coal, respectively. The
synthesis gas yield is about 70,400 SCF (on wet basis) and 61,4000 SCF (on dry
basis) per ton of coal fed to the gasifier.
The Koppers-Totzek gasifier has been commercially available since
1952, 20 plants using a total of 52 Koppers-Totzek gasifiers have been ordered.
It can be set up for alternate firing of coal and heavy oil. The most common use
for the gas has been for ammonia synthesis.
The scrubbed gas is compressed to 450 psig and passed through the shift
reactor to adjust the hydro gen-to-carbon monoxide ratio. In this case, the gas
is not purified before it enters the shift reactor (i. e. , it contains hydrogen sulfide
78
-------
TO
LOW PRESSURE
STEAM DRUM
PULVERIZED
COAL, STEAM
AND OXYGEN
BOILER FEED WATER
RAW GAS
PRODUCT
SLAG
BOILER FEED WATER
BURNER
COOLING WATER
IN
A-94-1627
Figure B-7. KOPPERS TOTZEK LOW-PRESSURE GASIFIER
-------
and carbonyl sulfide) so a catalyst tolerating sulfide s has to be used in the
reactor. The shifted gas goes to the purification system after waste-heat
recovery. In this case, a hot-carbonate-scrubbing system removes
hydrogen sulfide and carbonyl sulfide down to 10 ppm and carbon dioxide
down to about 7%, so that a ratio of H2^CO> 1. 5 CO2)= 2.05 can be achieved.
Regenerator off-gas goes to the sulfur recovery system (Claus and Wellman-
Lord Processes), and about 97% of the sulfur is recovered as an elemental
sulfur.
The purified gas is passed through an iron sponge drum and a sulfur
guard drum to remove traces of sulfur. The gas containing no sulfur is
compressed from about 385 to about 1500 psia for the manufacture of methanol.
Methanol can be produced from synthesis gas either by using a high-
pressure process (e. g., Japan Gas .Chemical Company Process), a low-
pressure process (e.g. , Imperial Chemical Industries low-pressure process,
Lurgi low-pressure process), or an intermediate-pressure process (e.g. , Nissui-
Topsoe Process).
In the high-pressure process, the synthesis gas is compressed to about
4300 psi. The compressed gas is combined with recycle gas and passed to the
methanol catalytic (zinc-chromium oxide catalyst) converter. The synthesis
gas entering the converter is preheated to the reaction temperature by heat
exchange with the product gas.
In the low-pressure process, the synthesis gas is compressed with re-
cycle gas and passed to the catalytic (highly active copper catalyst) converter.
The synthesis gas entering the converter is heated to 480°-570°F by heat ex-
change with the product gas.
In the intermediate-pressure process, the synthesis gas is compressed
to about 2300 psi. The compressed gas is combined with recycle gas and passed
to the catalytic (similar to Cu-Zn-Cr catalyst) converter. The synthesis gas
entering the converter is heated to 460°-540°F by heat exchange with the
product gas. In all the processes, the catalysts are vulnerable to sulfur
poisoning, so careful removal of sulfur compounds from the synthesis gas is
very essential.
The crude methanol is condensed and separated from the untreated gas,
which is recycled to the converter. The crude methanol is then let down to
80
-------
a lower pressure and dissolved gases are flashed off. Some of the flash gas
is purged to control the concentration of ineirts and nonreacting components,
and the remaining gas is recycled. If the concentration of inerts and non-
reacting components is very high, the high-pressure gas has to be purged.
The purged gas is used as a fuel in the methanol plant. The crude methanol
then is purified by distillation. Usually, two fractionation towers are required •
one to remove light end fractions such as dimethyl ether and methyl formate,
the other to remove high-boiling components such as water and higher alcohols.
The product may have purity as high as 99.95% methanol. Crude methanol
contains about 30 compounds with normal boiling points from—23.7°C to
174°C, as shown in Table'B-24. The purified methanol (99.85%) contains
about 900 ppm ethanol and about 500 ppm water. This 99.9% pure methanol
is known as chemical-grade methanol. The fuel-grade methanol need not be
99.9% pure. Usually, fuel-grade methanol is 98% pure containing about 2%
impurities such as water, ethanol, and higher alcohols.
Table B-24. COMPONENTS EXPECTED IN CRUDE METHANOL10
Normal Boiling
Components Point, °C
Dimethyl Ether —23.7
Acetaldehyde +20.2
Methyl Formate 31.8
Diethyl Ether 34. 6
n-Pentane 36.4
Propionaldehyde 48.0
Methyl Acetate 54. 1
Acetone 56.5
Methanol 64.7
Isopropyl Ether . 67.5
£-Hexane 69.0
Methyl Propionate 78.0
Ethanol 78.4
Methyl Ethyl Ketone 79. 6
t-Butyl Alcohol 83.0
n-Propanol 97.0
n- Heptane 98.0
Water 100.0
Methyl Isopropyl Ketone 101. 7
Acetal 103.0
Isobutanol 107.0
n- Butyl Ale ohol 117.7
Isobutyl Ether 122.3
Diisopropyl Ketone 123.7
n-Octane 125.0
Isoamyl Alcohol 130.0
4-Methyl Amyl Alcohol 131.0
n-Amyl Alcohol 138.0
ri-Nonane 150.7
n-Decane 174.0
The high-pressure, low-pressure, and intermediate-pressure methanol
synthesis processes are commercially available. However, compared with the
high-pressure process, the low-pressure process has lower operating and
capital costs. The biggest saving in the low-pressure process compared with
81
-------
00
tv
Table B-25. COMPOSITION OF GASEOUS STREAMS FROM A
COAL-TO-METHANOL (5000 Ton/Day) PLANT (Figure B-8)
Temperature.
•F
CO
CO,
H,
HiO
CH.
NI
Ar
H,S
COS
CH.OH
Oi
ToUl
Mol«»/hr
10' SCF/hr
1
2728
51.23
5.87
28.00
14. 83
0. 11
0. «3
0. 38
1.10
0.05
-.
--
100. 00
55. 311.5
20.95
2
350
49.74
7.36
29.49
11. 34
0. 11
0.4}
0.38
1.10
0.05
..
--
100.00
55, 311.5
20.95
3
115
50. 94
7. M
30. 10
9. to
0. 11
0. 44
0. 59
1.13
0. 05
.-
--
100. 00
54.006. 5
20. 45
4
280
45. 71
8.24
33.03
0. 70
0. 12
0.48
0.43
1.23
0.06
.-
--
100. 00
49. 382. 5
18. 70
5
625
55. 71
8.24
33.0}
0.70
0. 12
0.48
0.43
1.23
0.06
-.
--
100.00
49. 382. 5
IS. 70
6
220
16. 30
29.86.
47. 75
4. 41
0.09
0. 35
0. 31
0. 89^
0. 04/
.-
--
100.00
68.41%. 0
25.95
7
100
2). 4}
6.71
68. 54
0.25
0. 13
0. 50
0. 44
10 ppmv
-.
--
100.00
47. 551. 5
18.00
8
100
0.06
95. 73
0.43
0. 25
--
--
-.
3. 38
0. 15
..
--
100.00
18.008. 5
6. 85
9
100
23.43
6. 71
68. 54
0.25
0. 13
0. 50
0.44
;;
..
--
100.00
47. 551.0
18.00
10
340
23.43
6.71
68. 54
0.25
0.13
0. 50
0.44
;;
..
--
100.00
47. 551.0
18.00
11
500
17. 16
4. 35
66. 35
0. 13
1. 37
5. 36
4. 74
;;
0.54
"
100. 00
1.251.702. 5
474. 5
12
120
16.92
4.26
66.25
0. 13
1.42
5.55
4.91
_„
0. 56
—
100.00
4283.0
1.6
13
150
-•
--
--
--
0.07
1.43
__
.
99. 50
100.00
14.841. 5
5.6
14
250
--
--
100.00
"
"
--
,_
--
—
100.00
8196. 5
3. 1
15
450
_.
--
--
100.00
--
--
.-
"
--
--
100.00
24.176. 5
9. 15
-------
the high-pressure process is power cost. However, this difference is sub-
stantially reduced for a high-capacity methanol plant. In this study, calcula-
tions are based on ICI low-pressure methanol.
The compressed gas is mixed with recycled gas and heated to 500°F by
heat exchange with the product gas. The composition of the synthesis gas
satisfies the condition of H2/(CO +1.5 CO2) = 2. 05. The heated gas is passed
through a fixed-bed catalytic (highly active copper catalyst) converter. The
gas coming out is at about 580°F and is used in heating the feed gas. Then
the product gas is cooled down to about 120°F by heating the boiler feed water
and is sent to the separator for separation into methanol and gas. The portion
of the recycled gas is purged to control the concentration of the inerts and
unreactive components to about 10%. The purged gas is used as a fuel, and
recycled gas is compressed to 1500 psia... The pressure drop in the loop is
about 200 psi, and the conversion of carbon monoxide and carbon dioxide per
pass is about 5%. The crude methanol is let down to lower pressure, and
dissolved gases are flashed off. The flash gases are used as a fuel. The
crude methanol is purified to make fuel-grade or chemical-grade methanol.
Figure B-8 is detailed flow diagram for producing methanol from coal.
Tables B-25, B-26, and B-27 present the material balance around the system
and the composition of the important streams for a 5000 ton/day methanol
plant. The streams enumerated in Tables B-25, B-26, and B-27 are those
denoted by the flow diagram (.Figure B-8).
Table B-26. COMPOSITION OF SOLID STREAMS FROM A COAL-TO-
METHANOL (5000 Ton/Day) PLANT
Stream No.
Components
Ib/hr
C
H
0
N
S
H2O
Ash
tons/hr
1
,wt%
67.
4.
9.
1.
3.
4.
9.
Total 100.
594,958
297.
30 .
68
43
05
84
00
70
00
.5
48
2
67
4
9
1
3
4
9
100
0.
.30
.68
.43
.05
.84
.00
.70
.00
30
015
3
67.
4.
9.
1.
3.
4.
9.
100.
594,928
30
68
43
05
84
00
70
00
.5
297.465
4
15.
0.
1.
60.
22.
100.
138,549
69.
64
02
—
—
80
00
54
00
.5
27
5
100.
100.
26,478
13.
00
00
.0
24
83
-------
BFW STEAM
CXI
AIR STEAM
KOPPERS-TOTZEK
GASIFIER
WASTE-WATER
TREATMENT
WATER
KNOCKOUT
DRUMS
TO
ATMOSPHERE
SOLID
RESIDUE
SLOWDOWN
SEWAGE
RUNOFF
BFW= BOILER FEEDWATER
WHR= WASTE-HEAT RECUPERATOR
O GASEOUS STREAM
n SOLID STREAM
JAIR
GUARD DRUM
IRON
SPONGE
DRUM
X
FLASH
GASl
VCOOLING VMETHANOL
SYSTEM CONVERTER
FLASH.
DRUM
/
METHANOL
0-44-587
Figure B-8. FLOW DIAGRAM OF PRODUCTION OF METHANOL FROM COAL
-------
Table B-27. COMPOSITION OF PRODUCT FROM A COAL-TO-METHANOL
(5000 Ton/Day) PLANT
Methanol 5000 tons/day
Higher Alcohol 30 tons/day
Components, wt%
Methanol 98.0
Ethanol 0. 1
Higher Alcohols 0.5
Water 1.4
Total 100.0
Density, lb/gal at 60°F 6.64
Btu/lb 9760
Btu/gal 64,800
Heat of Vaporization, Btu/lb 473
Overall Energy Balance and Efficiencies
The overall energy balance is presented in Table B-28.
\
Table B-28. ENERGY BALANCE FOR A COAL-TO-METHANOL
(5000 Ton/Day) PLANT
106 Btu/hr
Input
Coal to Gasifier (297.5 tons/hr X 2000 X 12,120 Btu/lb) 7,211.5
Coal to Boiler (125.85 tons/hr X 2000 X 12, 120 Btu/lb) 3,050.5
Total Input . 10,262. 0
Output
Methanol [5000 tons/day X (2000/24) X 9760 Btu/lb] 4,066.5
Sulfur (14. 56 tons/hr X 2000 X 3983 Btu/lb) 116. 0
Isobutanol and Higher Alcohols (assuming mainly
isobutanol, 1. 23 tons/hr X 2000 X 15, 500 Btu/lb) 38. 1
Cooling by Air and Water 3, 100. 0
Other (by difference)* 2,941. 4
Total Output 10,260.0
*
Includes sensible heat of product streams, heating values of other
unaccounted products, and heat lost to the atmosphere.
The overall efficiency (including by-product heat credit) of the process is about
41%, and the coal-to-methanol efficiency is about 40%, which can be increased
by an additional 5% by using a high-pressure gasifier. In this low-pressure gasi-
fication process, 150,000 hp is required to compress the gas from atmospheric
85
-------
pressure to about 1500 psia, which is about 1300 million Btu/hr. In a high-
pressure gasifier, oxygen has to be compressed to the required pressure,
but its amount is one-third or one-quarter of the synthesis gas produced.
Consequently, about 900 million Btu/hr can be saved, which amounts to 5%
of the total energy required. Therefore, overall efficiency of the process
could be 46%. However, the investment cost in a high-pressure operation is
higher than that in a low-pressure operation.
The efficiency of the methanol loop in this case is about 73% and that
of the low-pressure gasification system is about 56%, making the overall
efficiency about 41%. The efficiency of synthesis gas production with the
high-pressure gasification system is about 60-65%, which makes the overall
efficiency of the coal-to-methanol process about 46%.
Pollution
Sulfur is the biggest pollutant resulting from the process. However,
90% of the total sulfur can be recovered as elemental sulfur balance by using
suitable processes. The sulfur balance is reported in Table B-29.
Table B-29. SULFUR BALANCE FOR A COAL-TO-METHANOL
(5000 Ton/Day) PLANT
Ib/hr (as sulfur)
Input
Coal to Gasifier 22,846.5
Coal to Boiler 9,665. 0
Total Input 32,511. 5
Output
Elemental Sulfur (by-product) 29, 120.0
Sulfur Compounds to Atmosphere From Sulfur-
Recovery Plant 881.0
Sulfides to Atmosphere From From Iron Sponge 16. 0
Sulfur to Atmosphere With Coal Dust 1.0
Sulfur With Soot in Waste-Water Recovery 2,493. 5
Total Output 32,511. 5
The stack gas from the boiler containing sulfur dioxide can be fed to the
Wellman-Lord Process to recover sulfur dioxide. This sulfur dioxide is
mixed with the hydrogen sulfide removed from synthesis gas and fed to the
Claus plant to recover elemental sulfur.
86
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About 2300 gpm of waste water requires treatment; it may contain
ammonia, sulfur compounds, traces of hydrogen cyanide, thiocyanate, and
ash. The process requires 100,000-200,000 gpm of cooling water, which is the
biggest source of heat pollution. Table B-30 lists wastes, their sources,
and possible treatments.
Table B-30. WASTES, SOURCES, AND TREATMENTS FOR A COAL-
TO-METHANOL PLANT
Waste
Sources
Treatment
Coal Dust
Soot and Ash
Waste Water (con-
taining alcohols,
ammonia, hydrogen
sulfide, hydrogen
cyanide)
Hydrogen Sulfide
Sulfur Dioxide
Coal-crushing system,
conveyor belts
Gasifier
Gasifier, compression,
gas-cooling system after
shift, purification, etc. ;
methanol distillation sys-
tem, boiler blowdown,
sewage ruin-off
Regenerator off-gas
Boiler flue gas
Cyclone separators, bag
filters, scrubbing, etc.
Scrubbing and various waste-
water and solid treatments
Biological treatments,
Phenosolvan, and modified
Chevron to remove hydrogen
sulfide, ammonia, etc.
Claus Process or any suitable
sulfur recovery process
Wellman-Lord lime treatment,
etc.
Economic Analysis
The economic analysis is performed by using the DCF method. The
investment and operating costs of a 5000 ton/day methanql-from-coal plant
are estimated in Tables B-31 and B-32, respectively. The calculation method8
for the unit production cost of the product is presented in Table B-33. This
financing method includes the following factors:
• A 25-year project (synthesis plant) life
• Depreciation calculated on a 16-year sum-of-the-digits formula
• 100% equity capital
• A 48% Federal Income Tax rate
• A 12% DCF rate
• Plant start-up costs as expenses in year zero.
For 30^/million Btu coal, the cost of methanol is about $71/ton, or
$0. 234/gal. This unit cost depends on the accounting method used, material
costs, and variations in other financial factors (e. g. , by using a utility
method,8 the unit cost of the product is $54/ton, or $0.179/gal).
87
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If a 10% (instead of 12%) DCF financing model is used for the synthesis
plant to produce methanol from coal, the unit product cost becomes $3. 51 /
million Btu (low heating value).
Table B-31. INVESTMENT COST FOR COAL-TO-METHANOL (5000 Ton/Day)
PLANT USING KOPPERS-TOTZEK GASIFICATION AND ICI METHANOL
PROCESSES
Components End-of-1973 Cost, $1000
Coal Storage 1,900
Syngas Train 33,000
Syngas Compressor I 11, 100
Carbon Monoxide 4, 730
Carbon Monoxide-Shift Waste-Heat Recovery 1,430
Hot Carbonate System 13,500
Trace Hydrogen Sulfide Removal 820
Syngas Compressor II 3,000
Methanol Loop 30, 170
Air Separation Plant 37,200
Oxygen Compressor 1,100
Steam Generation and Boiler Feed Water Pumps 18,380
Boiler Feed Water Treatment 7,600
Cooling Tower and Pumps 6, 100
Waste-Water Treatment 10,300
Particulate Emission Control 1,740
Sulfur Recovery 5,080
Wellman-Lord Stack-Gas Cleanup 12,270
Turbo Generator 3,330
Power Distribution System 4,000
General Facilities 5,000
Total 211,750
Contractor's Overhead and Profits (10%) 21, 175
Total 232,925
Contingencies (15%) 34, 900
Total Plant Investment (I) 267,825
Interest During Construction (0. 23676 X I) 63,410
Start-up Cost (20% of gross operating cost) 10,002
Working Capital
Coal Inventory (60 days of feed at full rate) 4,433
Materials and Supplies (0.9% of total plant
investment) 2,410
Net Receivables (1/24 X annual, revenue received) 4, 888
Total Capital Required 352,968
88
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Table B-32. OPERATING COST FOR COAL-TO-METHANOL (5000 Ton/Day)
PLANT USING KOPPERS-TOTZEK GASIFICATION AND ICI METHANOL
PROCESSES
Annual Cost,
Components $ 1000
Coal Feed (at 246,288 X 106 Btu/day), 30$j/106 Btu 24,272
Other Direct Materials, Catalysts, and Chemicals 1,947
Purchased Utilities
Raw-Water Cost (5000 gpm X 30(6/1000 gal) 710
Labor
Process Operating Labor (50 men/shift at $5/hr and
8304 man-hr/yr) 2,076
Maintenance Labor (1.5% of total plant investment) 4,017
Supervision (15% of operating and maintenance labor) 914
Administration and general overhead (60% of total
labor, including supervision) 4,204
Supplies
Operating (30% of process operating labor) 623
Maintenance (1.5% of total plant investment) 4,017
Local Taxes and Insurance (2.7% of total plant
in ve s tm ent) 7,231
Total Gross Operating Cost 50,011
By-product Credit
Sulfur (310 LT/day X $10/LT X 328.5) 1,018
Total Net Operating Cost 48,993
Table B-33. CALCULATION FOR DETERMINING UNIT PRODUCTION COST
BY DCF METHOD FOR A COAL-TO-METHANOL (5000 Ton/Day) PLANT
Unit Cost of the Product
N+ 0. 238161 + 0, 1275 S +0.239777 W
G
where
N = Net Operating Cost = $48,993,000
I = Total Plant Investment =$267,825,000
S = Start-up Cost = $10,002,000
W = Working Capital = $11,731,000
G = Annual Production (5000 tons/day X 328. 5 days/yr
4- 30 ton/day higher alcohol X 328. 5 days/yr)
$116,760,000 „,-,. ,,..
Umt cost = 5030X328.5 = ^0.66/ton
= $0.2342/gal
= $3. 88 I/million Btu (low heating value)
89
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SNG From Coal
The reactions occurring in the process for making SNG are as follows:
C 4- H2O-» CO 4 H2 endothermic (B-8)
C * O2 -» CO2 exothermic (B-9)
C 4= CO2 •+ 2CO endothermic (B-10)
C + 2H2-» CH4 exothermic (B-11-)
CO 4- H2O-» CO2 + H2 exothermic (B-12)
CO 4- 3H2-» CH4 + H2O exothermic (B-13)
CO2 + 4H2 -» CH4 * 2HP exothermic (B-14)
Methane is produced by Reactions B-ll, B-13, and B-14. The main
components of these reactions are carbon and hydrogen. The hydrogen is
produced by the highly endothermic reaction between carbon and steam. The
heat required for the reaction is supplied by combustion of a portion of the
coal with oxygen by other exothermic reactions or by some other means.
The reaction between carbon monoxide and hydrogen is highly exothermic, and
the reaction kinetics are highly sensitive to the partial pressure of hydrogen;
e.g., if the partial pressure of hydrogen is doubled, Reaction B-13 goes 8 times
faster. Therefore, Reactions B-13 and B-14 are highly favored at high pressure
and supply p'art of the heat required for endothermic Reaction B-8. Consequently,
the oxygen requirement is reduced in the high-pressure process. Another
advantage in the high-pressure process is some saving in compression of the
gas. In the high-pressure gasification process, only oxygen has to be compressed
to the required pressure, not the entire amount of synthesis gas. And the
amount of oxygen is only one-third or one-quarter of the synthesis gas
produced. However, the investment cost of the high-pressure operation is
higher than that of the low-pressure operation.
Many processes exist for gasifying coal. Some of the processes are in
commercial production (e. g. , Lurgi, Koppers-Totzek, Winkler, and Wellman-
Galusha); some are on a pilot-plant scale (e. g. , HYGAS, CO2-Acceptor, BI-
GAS, and Synthane); and some are in the development stage (e. g. , ATGAS and
Exxon). In this study, the Lurgi gasification process, a medium-pressure
(about 450 psia) process, is used. This process is selected because it is
commercially available and because it is operated at higher pressures than
other commercially available processes.
90
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The Lurgi gasifier was developed by the Lurgi MineralStechnik GmbH
of Frankfurt, West Germany. It is currently limited to noncaking coals.
Recent gasifier research has been directed toward mechanical modifications
to allow the use of mildly caking coals. Sixteen commercial Lurgi plants,
producing a gas of about 400-450 Btu/CF, have been built during the last
30 years, and some are still in operation. A plant with a capacity of about
288 million CF/day of SNG has been designed for the El Paso Natural Gas
Company on a site near Farmington, N. M. Process design work has been
completed and an environmental impact statement has been filed. To a
major extent, the process setup and data required for this study have been
taken from this filing. However, this study should not be considered
representative of El Paso's Lurgi plant because some (minor) modifications
are made in this presentation.
Description of Lurgi Process
Crushed (1/2 to 1-1/4 inch) and dried coal is fed to a moving-bed gasifier
in which gasification of coal takes place at 350-450 psi. DevoUtilization occurs
initially and is accompanied by gasification in the temperature range of
1150°-1400°F. The nominal residence time of the coal is about 1 hour. Steam
is the source of the hydrogen. Combustion of a portion of the char with oxygen
supplies the heat required for the carbon-steam (endothermic) reaction.
A revolving grate at the base of the reactor supports the fuel bed, removes the
ash, and introduces the steam and oxygen mixture. Crude gas leaves the
gasifier at temperatures between 700° and 1100°F (depending on the type of
coal) and contains tar, oil, naphtha, phenols, ammonia plus coal, and ash
dust.
A typical Lurgi pressure gasifier is shown in Figure B-9. The process
coal is fed through a lock hopper that holds about 6 tons of coal and that is cycled
once every 15 minutes when the gasifier is operating at full capacity. The
lock is pressurized with raw, cooled, product gas to feed the coal to the
reactor, and depressurization releases a fuel gas that is collected in surge
storage tanks, recompressed, and added to the main gas stream. Coal passes
down through the bed, moving through zones of increasing temperature in which
different types of chemical reactions occur; eventually, the ash is forced
through the water-cooled revolving grate (which also acts as a distributor
for oxygen and steam) into the ash lock hopper. The ash, which ranges from
91
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o
FEED COAL
RECYCLE TAR
DRIVE
GRATE
DRIVE
SCRUBBING
COOLER
GAS
WATER JACKET
STEAM *
OXYGEN tf
Figure B-9. LURGI PRESSURE GASIFIER (Source: Ref. 6)
92
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very fine particles to 4-inch lumps, is discharged fromthe ash hopper once
every 30 minutes. The carbon content of the ash is about 5%.
The solids and gas are contacted countercurrently in the gasifier; as
a result, relatively large quantities of liquid by-products are formed. The
raw product gas at 700°-llOO°F leaves t.'ie gasifier and passes through a
scrubber, in which it is washed by recirculating gas liquor and cooled to
saturation. Tars are condensed, and the wash water contains tars that
pick up particulates from the gas. The saturated gas is passed through a
waste-heat boiler in which waste heat is recovered at a temperature of
about 360°F. Some of the gas liquor condensed in the boiler is pumped to the
scrubber, and some is routed to a tar-gas liquor separator. The separated
tars can be recycled to the gasifier, hydrotreated to produce light hydrocarbon
liquids, or stored. The separated gas liquor is sent to the Phenosolvan
Process for treatment and recovery of ammonia and phenols.
Gasifier operating data and detailed stream compositions for the Navajo
steam coal (New Mexico) are given in Figure B-lO and in Tables B-34, B-35,
and B-36. The crude gas fromthe waste-heat-recovery system has a hydrogen-
to-carbon monoxide ratio of about 1:93. It contains about 11% methane.
Ninety-five percent of the sulfur in the coal is converted to (H2S + COS 4- CS2),
2-3% of the sulfur goes with the by-products (tars, tar oil, naphtha, etc.),
and the rest goes to ash. About 60% of the nitrogen fed to the gasifier is
converted to ammonia. Steam and oxygen consumption in this case are
0.92 ton/ton and 0.243 ton/ton of coal (as received), respectively. The crude
gas yield is about 42, 300 SCF (dry basis) per ton of coal (as received) fed
to the gasifier.
About 55% of the total crude gas goes to a two-stage, carbon monoxide-
shift reactors system, and the remaining amount of gas bypasses the shift and
goes directly to the gas-cooling system. In the shift reactor, carbon monoxide
and steam react in the presence of a nickel catalyst, producing carbon dioxide
and hydrogen. The hydrogen-to-carbon monoxide ratio in the shift product
gas is about 9:3, and the hydrogen-to-carbon monoxide ratio of the combined
stream is about 3:7. The hot shift product gas is cooled in countercurrent
heat exchangers with the shift feed gas. Then the converted gas, together
93
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SOUR
@ FUEL GAS
SULFUR
I5,562jb/hr
WASTES FROM FUEL GAS
PRODUCTION
TAR OIL TAR PHENOLS
48,588 Ib/hr 88,824 Ib/hr 11,271 Ib/hr
AMMONIA
SOLUTION(20%)
21,422 Ib/hr OF
AMMONIA
SNG
(288.6 million SCF/DAY)
O = GASEOUS STREAM
= LIQUID STREAM
D = SOLID STREAM
A-44-703
Figure B- 10. FLOW DIAGRAM OF LURGI-PROCESS PRODUCTION OF
SNG (288.6 Million SCF/Day) FROM COAL
-------
Table B-34. COMPOSITION OF GASEOUS STREAMS FROM COAL-TO-SNG (288.6 Million SCF/Day) PLANT*
sD
Components
C02
H2S
C2H,
CO
H2
CH<
N2 +Ar
02
Total (dry gas)
Moles/hr (dry gas)
10'- SCF/day
Water
Naphtha
Tar Oil
Tar
Crude Phenols
NH,
Total
*See Figure B-10.
Stream Number
1 2. 3
28.03
0.37
0.40
20.20
-- . 38.95
11.13
0.61
2.0 0.31
98.0
100.0 100.00
14,680.0 108,091.9
133.4 982.2
1,783,540 -- 1,394,960
20,005
28,007
7,314
9,127
17,629
1,783,540 -- 1,477,042
4
28.03
0.37
0.40
20.20
38.95
11.13
0.61
0.31
100.00
48,987.3
445. 1
632,196
9,066
12,693
3,315
4,136
7,989
5
36.95
0.32
0.36
5.03
46.80
9.75
0.53
0.27
100.00
67,451.2 118
612.9 1
357,765
10,939
15,314
3,999
4,991
9,640
402,648
6 7
32.36 97.53
0.34 0.75
0.39 0,24
11.70 0.17
43.63 0.43
10.70 0.56
0.59 0.32
0.29
100.00 100.00
,822.4 3b,6S1.7
,079.7 324.0
2,680
20,005
--
--
--
--
22,685
8 9 10
86.17 3.10 1.81
13.82
0.45
16.91 0.01
63.48 4.16
14.94 92.93
0.01 0.69
0.43 1.09
100.00 100.00 100.00
888.6 80,874.0 31,762.1
8.1 734.9 288.6
66
--
--
--
--
--
66
B-104-1805
-------
Table B-35.
COMPOSITION OF SOLID STREAMS FROM A COAL-TO-SNG
(288.6 Million SCF/Day) PLANT*
Components
C
H
N
S
O
Trace
1
. wt %
49. 19
3.60
0.85
0.69
10. 15
C omp ound s 0.02
Stream No.
2+
5.00
—
_ _
—
--
--
Moisture 16. 25
Ash
Ib/hr
19.25
Total 100.00
1,938,480
95.00
100.00
477,080
3
49.19
3.60
0.85
0.69
10.15
0.02
16.25
19.25
100.00
415,587
* See Figure B-10.
t Dry ash.
Table B-36. COMPOSITION OF LIQUID STREAMS FROM A COAL-TO-SNG
(288. 6 Million SCF/Day) PLANT*
Contains 0. 27 wt % sulfur
Contains 0. 15 wt % sulfur
20 wt % ammonia, and solution
contains 0.01 wt % sulfur
Contains 0. 20 wt %
Steam
1
2
3
4
5
* See
Component
Tar Oil
Tar
Phenols
Ammonia
Naphtha
Figure B-10.
Ib/hr
48,588
88,824
11,271
107, 110
20,005
gal/day
157,370
239,250
32,470
332,550
74,900
96
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with the bypass gas, flow to the gas-cooling area for waste-heat recovery and
cooling. Some of the gas liquor, tars, and tar oil are condensed from cooling
the gas streams. The condensate is sent to separators to recover tar and
tar oil. The separated gas liquor is sent to the Phenosolvan Process for
recovery of ammonia and phenols. This gas liquor contains hydrogen cyanide,
which is generated during gasification. The cyanide is withdrawn and sent to
the sulfur recovery stage for conversion to thiocyanate and then discarded.
The gas from the gas-cooling system goes to the purification system
to produce a gas free of impurities that may be harmful to the methanation
catalyst. Naphtha also is recovered almost completely in this section. The
sulfur compounds are reduced to a total concentration of less than 0. 1 ppmv,
and carbon dioxide is reduced from 33 to 3%. The gas from the gas -cooling
system is chilled and then washed by cold methanol to remove naphtha and
water. The naphtha-free gas enters the absorber where carbon dioxide,
hydrogen sulfide, and carbonyl sulfide are removed. Then the gas is passed
through an iron sponge to remove trace sulfur. The sulfur-free gas from
the gas purification system goes to the methane synthesis system. A lean
hydrogen sulfide acid gas stream is removed from methanol by multiflash in
the flash regenerator. The remaining acid gases are stripped from the
methanol in the hot regenerator, producing a hydrogen sulfide-rich gas stream.
The purified methanol is recycled. The lean and rich hydrogen sulfide gas
streams go to the Stretford Process for sulfur recovery. Hydrogen sulfide
is removed by a Stretford solution, and then the solution is regenerated by
contact with air, which also produces elemental sulfur as follows:
+ O2 -» 2H2O 4= 2S B
The gaseous stream from the Stretford unit contains hydrogen sulfide (about
10 ppm) and carbonyl sulfide, some of which are oxidized to sulfur dioxide
and vented to the atmosphere.
The purified gas is converted to methane -rich gas in a two -stage catalytic
methanator. Carbon monoxide and some of the carbon dioxide react with
hydrogen (Reactions B-13 and B-14) to produce methane. These reactions are
exothermic, and the heat of reaction is removed by generating process steam.
To control the temperature of the reactor, a portion of the product gas is
compressed and recycled. Then the product gas is cooled, and condensed
water is separated in the separator. The gas then is compressed to the required
pressure and dehydrated by a glycol solution. The product gas leaving the
97
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plant contains about 93% methane and has a higher heating value of
954.0 Btu/SCF.
The oxygen required for the process is manufactured onsite by El Paso
by using an air-separation plant. About 18% of the total coal feedstock supplied
for the process is used to produce a low-Btu (195 Btu/CF) fuel gas that is
used for the gas turbines and boilers for steam and electric power generation.
The low-Btu gas is produced in a Lurgi Gasifier by using air rather than oxygen.
Hydrogen sulfide from the fuel gas is removed, and sulfur is recovered by
using the pressure Stretford Process.
Overall Energy Balance and Efficiencies
The energy balance for SNG-from-coal production is presented in
Table B-37. The efficiency (including by-product heat credit, e. g; , for tar,
tar oil, sulfur, ammonia, etc.) of the process is about 70%, and the coal-to-
SNG efficiency is about 56%. If tar and tar oil are hydrotreated to manufacture
light oil, the overall efficiency is less than 70%.
Table B-37. ENERGY BALANCE FOR A COAL-TO-SNG
(288.6 Million SCF/Day) PLANT
106 Btu/hr
Input
Coal to Gasifier (969.24 tons/hr X 2000 X 8664 Btu/lb) 16,795.0
Coal for Fuel Gas (207.7935 tons/hr X 2000 X 8664 Btu/lb) 3,600. 6
Total Input 20,395.6
Output
Product Gas (288.6 X 106 SCF/day X 1/24 X 954 Btu/SCF) 11,471.9
Tar (88,824 Ib/hr X 16,670 Btu/lb) 1,480.7
Tar Oil (48,588 Ib/hr X 17,300 Btu/lb) 840.6
Phenols (11,271 Ib/hr X 14,021 Btu/lb) 158.0
Naphtha (20,005 Ib/hr X 18,400 Btu/lb) 368. 1
Ammonia (21,422 Ib/hr X 9598 Btu/lb) 205.6
Sulfur (15,582 Ib/hr X 3983.4 Btu/lb) . 62.1
Carbon in Ash (477,080 Ib/hr X 704. 3 Btu/lb) 336,0
Cooling Water 1,206.0
Other by Difference- 4,266. 6
Total Output 20,395.6
Includes sensible heat of product streams, heating values of other
unaccounted products, and heat lost to the atmosphere.
98
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Table B-38. SULFUR BALANCE FOR A COAL-TO-SNG
(288.6 Million SCF/Day) PLANT
Ib/hr (as sulfur)
Input
Coal to Gasifier 13,378
Coal for Fuel Gas 2,868
Total Input 16,246
Output
Elemental Sulfur (by-product) 15,582
Sulfur Compounds to Atmosphere From
Sulfur Recovery Plant 133
From Turbine, Boiler, and Heater Effluents
(sulfur dioxide discharged to atmosphere) 167
Sulfur Goes With By-products (i. e. , with tar, tar oil,
naphtha, ammonia solution) 364
Total Sulfur 16,246
Pollution .
About 95% of the sulfur in the coal goes with gaseous streams, mainly
as a hydrogen sulfide and some small amount as carbonyl sulfide and carbon
disulfide. Theis sulfur is recovered as an elemental sulfur by using the
Stretford Process. Sulfur from the fuel, gas is recovered by using the pressure
Stretford Process. The small amount of sulfur dioxide emitted by gas-fired
turbines, boilers, heaters, and incinerators does not require any treatment
because it is below the maximum allowable pollution limit. Overall sulfur
recovery in this process is about 95%. The sulfur balance around the system
is given in Table B-38. About 238 tons/hr of hot ash is quenched with water,
then dewatered, and disposed of in the mine area.
The gas liquor containing tar, tar oil, phenol, and ammonia is treated
in three stages. First, tar and tar oil are separated from the gas liquor; then
the gas liquor is passed through the phenol extraction area for the extraction
of phenol. Then in the gas liquor-stripping area, ammonia and other dissolved
acid gases are stripped out. The acid gas is passed through the sulfur
recovery area to convert hydrogen cyanide to thiocyanate. About 161,000
gpm of cooling water is required in the process, which is the biggest source
of heat pollution. About 5600 gpm of makeup water is required in the process.
Table B-39 lists wastes, their sources, and treatments required in the process.
99
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Economic Analysis
The economic analysis is done by using a DCF method. The investment
costs of a 288.6 million SCF/day plant are given in Table B-40, and much of
the required source data were taken from the El Paso filing. The operating
costs of the plant are given in Table B-41. The calculation method8 for the
unit cost of the product is presented in Table B-42. This financing method
includes the following factors:
• A 25-year project (synthesis plant) life
• Depreciation calculated on a 16-year sum-of-the-digits formula
• 100% equity capital
• A 48% Federal Income Tax rate
• A 12% DCF rate
• Plant start-up costs as expenses in year zero.
For 30^/million Btu coal, the cost of SNG is about $ 1. 93/million Btu (high
heating value), or about $2. 14/million Btu (lower heating value). This
unit cost depends on the accounting method used, the feed cost, and
variation in other financial factors; e. g. , by using the utility method, 8 the
unit cost of the product is $ 1.• 45/million Btu (high heating value) or $1.61/
million Btu (low heating value). If a 10% (instead of 12%) DCF financing
model is used to produce SNG from coal, the unit product cost becomes
$ 1. 93/million Btu (low heating value), rather than $2. 14/million Btu.
Table B-39. WASTES, SOURCES, AND TREATMENTS FOR
A COAL-TO-SNG PLANT
Waste
Sources
Coal Dust
Soot and Ash
Waste water, Quench system, gas-cooling
(containing phenols, system, shift converter,
ammonia, hydrogen purification system, corn-
cyanide, hydrogen pression, boiler blowdown,
sulfide, and oils) sewage run-off
Hydrogen Sulfide
Carbonyl Sulfide
Carbon Bisulfide
Sulfur Dioxide
Rectisol regenerator
Gas-fired turbines, boilers,
heaters, incinerators
Treatment
Coal-crushing system,
conveyor belts, lock hoppers
Gasifier and lock hopper
Cyclone separators, bag
filters, scrubbing, etc.
Scrubbing and various waste-
water and solid treatments
Biological treatments,
Phenosolvan, and modified
Chevron to remove hydrogen
sulfide, ammonia, etc.
Stretford Process or any suitable
sulfur-recovery process
In this case, amount of sulfur
dioxide below the allowable
pollution standard. Otherwise,
Wellman-Lord lime treatment,
etc.
100
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Table B-40. INVESTMENT COST FOR LURGI-PROCESS COAL-TO-SNG
(288.6 Million SCF/Day) PLANT
End-of-1973 Cost,
Components $ 1000
Gas Production System (including lock gas storage
and compression) 66,370
Carbon Monoxide 7,680
Gas Cooling and Heat Recovery 8,080
Gas Purification (including refrigeration) 40,640
Methane Synthesis 18,550
Product-Gas Compression and Dehydration 5,660
Gas-Liquor Treatment and By-product Recovery 18,650
Sulfur Recovery System 8, 160
Fuel Gas Production System 21,620
Fuel Gas Cooling and Treatment 5,320
Air Compression 20,470
Steam and Power Generation 30,200
Oxygen Production and Compression 28,930
Cooling-Water System 5,800
Raw Water Treatment System and Miscellaneous Plant
Utility Systems 11,940
Ash Dewatering and Transfer 6,320
Raw-Water Storage, Pumping, and Pipeline and River-Water
Pumping 14,210
Initial Catalyst and Chemicals 4,010
General Facilities 34, 720
Total Direct Cost of Plant Including Contractor
Engineer Fees, Licenses, and State Taxes 357,780
Contingencies (15%) 53,667
Total Plant Investment (I) 411,447
Interest During Construction (0. 23676 X I) 97,414
Start-up Cost (20% of gross operating cost) 17,234
Working Capital
Coal inventory (60 days of feed at full rate) 8,811
Materials and Supplies (0.9% of total plant investment) 3,703
Net Receivables (1/24 X annual revenue received) 7, 273
Total Capital Required 545,882
101
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Table B-41. OPERATING COST FOR LURGI-PROCESS COAL-TO-SNG
(288.6 Million SCF/Day PLANT (90% Stream Factor)
Annual Cost,
Component $1000
Coal Feed (at 489,495.3 X 106 Btu/day), 30^/106 Btu 48,240
Other Direct Materials, Catalysts, and Chemicals 3, 520
Purchased Utilities
Raw-Water Cost (at 7300 gpm X 30«f/1000 gal) 1,036
Labor
Process Operating Labor (62 men, shift at $5/hr and
8304 man-hr/yr) 2,574
Maintenance Labor (1.5% of total plant investment) 6, 172
Supervision (15% of operating and maintenance labor) 1,312
Administration and General Overhead (60 % of total labor,
including supervision) 6,035
Supplies
Operating (30% of process operating labor) 772
Maintenance (1.5% of total plant investment) 6,172
Local Taxes and Insurance (2.7%Jof total plant investment) 11, 109
Total Gross Operating Cos'i 86,942
By-product Credit
Tar Oil (48,588 Ib/hr X 24 X 17,300 Btu/lb
X $ 0.5/106 Btu X.328.5) 3,314
Tar (88.824 Ib/hr X 24 X 16,670 Btu/lb
X $0.5/106 Btu X 3.28.5) 5,837
Phenols (11,271 Ib/hr X 24 X $0.04/lb X 328.5) 3,554
Ammonia (21,422 Ib/hr X 24/2000 X $25/short ton X 328.5) 2, 111
Naphtha (20,005 Ib/hr X 24 X 18,400 Btu/lb X $0.5/106 Btu
X 328.5) 1,451
Sulfur (167 LT/day X $10/LT X 328. 5) 549
• 16,816
Total Net Operating Cost 70,126
102
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Table B-42. CALCULATION FOR DETERMINING UNIT PRODUCTION COST
BY DCF METHOD FOR A LURGI-PROCESS COAL-TO-SNG
(288.6 Million SCF/Day) PLANT
Unit Cost of the Product
N+ 0.2381614- 0.1275S4- 0. 230777 W
G
where
N = Net Operating Cost = $70, 126,000
I =• Total Plant Investment = $411,447,000
S = Start-up Cost = $17,234,000
W = Working Capital = $19,787,000
G = Annual Product Production (288.6 million SCF/day
X 954 Btu/SCF X 328. 5 days/yr) = 90,444,065.4 X 106 Btu/yr
Unit cost = 77° = $ L 934 /million Btu (high heating value)
= $1gi>|i5>73o = $2- 145 /million Btu (low heating value)
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105
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