EPA-650/2-74-072
A SASOL TYPE PROCESS FOR GASOLINE,
METHANOL, SNG, AND LOW-BTU GAS
FROM COAL
by
F. K. Chan
The M. W. Kellogg Company
1300 Three Greenway Plaza
Houston, Texas 77046
Contract No. 68-02-1308
ROAP No. 21ADE-010
Program Element No. 1AB013
EPA Project Officer: G. J. Foley
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
July 1974
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does n6t signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
11
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A SASOL TYPE PROCESS FOR
GASOLINE, METHANOL, SNG AND
LOW BTU GAS FROM COAL
TASK NO. 13 FINAL REPORT
Submitted To
CONTROL SYSTEMS LABORATORY
NATIONAL ENVIRONMENTAL RESEARCH CENTER
U.S. ENVIRONMENTAL PROTECTION AGENCY
CONTRACT NO. 68-02-1308
JULY, 1974
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en 21
RESEARCH AND ENGINEERING DEVELOPMENT
I KELLOGG
A SASOL TYPE PROCESS FOR
GASOLINE, METHANOL, SNG AND
LOW BTU GAS FROM COAL
TASK NO. 13 FINAL REPORT
Submitted to
ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH & DEVELOPMENT
CONTROL SYSTEMS LABORATORY
CONTRACT NO. 68-02-1308
Approved:
Proiect Direct
Manager
Chemical Engineering Development
Directed/
Research & Development
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THEM..*. KELLOGG COMPANY ,—/m\— PAGE NO.
A DIVISION OF PULLMAN INCORPORATED
RBSEAMCH ft ENGINEERING DEVELOPMENT REPORT NO.
A SASOL TYPE PROCESS
FOR GASOLINE, METHANOL, SNG AND
LOW BTU GAS FROM COAL
TASK NO. 13 FINAL REPORT
EPA-ORM-CSD CONTRACT NO. 68-02-1308
JULY, 1974
Staff: F.K. Chan, H.B. Goff (Consultant),
MWK Estimating Department
Period Covered: January, 1974 to April, 1974
RDO No.: 4118-13
Distribution: Copy No
Office of Research & Development (EPA) 1-100
L. C. Axelrod 101
J. S. Burr 102
F. K. Chan 103
C. F. Chatfield 104
A. E. Cover 105
W. C. Crady 106
C. J. Donovan 107
J. B. Dwyer 108
J. A. Finneran 109
L. D. Fraley 110
S. E. Handman 111
J. J. McKenna 112
W. C. Schreiner 113
A. G. Sliger 114
M. J. Wall 115
RID (4) 116-119
Author:
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TABLE OF CONTENTS
PAGE NO
I. Introduction 1
II. Basis of Evaluation 2
III. Summary 3
A. Gasoline-from-Coal
B. Methanol-from-Coal
C. Substitute Natural Gas-from-Coal
D. Low Btu Gas-from-Coal
IV. Process Description 16
A. Gasoline-from-Coal
a. Description
b. Process Consideration
B. Methanol-from-Coal
C. Substitute Natural Gas-from-Coal
D. Low Btu Gas-from-Coal
V. Discussion of Results & Recommendations 52
VI. References 57
VII. Appendices 58
A. Annualized Operating Cost for Gasoline from Coal
Total Capital Requirement 59
Annual Operating Cost 60
Unit Costs Base Case 62
Unit Costs Alternate Case 62
B. Annualized Operating Cost for Methanol from Coal
Total Capital Requirement 65
Annual Operating Cost 66
Unit Costs 67
C. Annualized Operating Cost for Substitute Natural
Gas from Coal
Total Capital Requirement 69
SNG Annual Operating Cost 70
Unit Costs 71
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TABLE OF CONTENTS (Cont'd.)
PAGE NO
D. Annualized Operating Cost for Low Btu Gas From
Coal
Total Capital Requirement 73
Annual Operating Cost 74
Unit Costs 75
Annual Operating Cost Alternate Case 77
Unit Costs Alternate Case 78
E. Description of Panhandle Eastern Accounting
Procedure 80
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LIST OF TABLES
TABLE NO. DESCRIPTION PAGE NO
1
2
3
4
5
6
7
8
9
10
11
Gasoline-From-Coal Investment Summary
Gasoline-From-Coal Production Rate
Methanol-From-Coal Investment Summary
Methanol-From-Coal Production Rate
Substitute Natural Gas-From-Coal Invest-
ment Summary
Substitute Natural Gas Production Rate
Low Btu Gas-From-Coal Investment Summary
Low Btu Gas-From-Coal Production Rate
Material Balance - Gasoline-From-Coal
Material Balance - Methanol-From-Coal
Material Balance - Substitute Natural
8
9
10
11
12
13
14
15
29
38
Gas-From-Coal 45
12 Material Balance - Low Btu Gas Production
From-Coal 50
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LIST OF FIGURES
FIGURE NO. DESCRIPTIOiM PAGE NO,
1 Block Flow Diagram-Gasoline & Other
Hydrocarbon Liquids Via Synthol Process 28
2 Block Flow Diagram-Methnaol-From-Coal 37
3 Block Flow Diagram-Substitute Natural
Gas-From-Coal 44
4 Block Flow Diagram-Low Btu Gas-From-Coal 49
5 Effect of Coal Price on the Production
Cost of Gasoline, Methanol, SNG and
Low Btu Gas 56
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I. Introduction
The work reported herein is an enlargement of Task 13 Preliminary
Report (1) and was performed for the Environmental Protection
Agency, Office of Research and Development under Task 13, Change
No. 2, Contract No. 68-02-1308.
Task 13 Preliminary Report describes the SASOL type process
for the production of gasoline-from-coal and presents the approximate
capital investment. The evaluation was based on published data
on the SASOL plant (2) and costs include the power supply to the
nearby village which houses the operating and supervisory per-
sonnel. To provide a basis for direct comparision with other
coal conversion processes, it was decided to extend the study
by modifying the basis such that power requirements for the
village were deleted. The modified gasoline-from-coal plant
is described in the appropriate sections in this report.
In addition to the modification cited above, the Environmental
Protection Agency (EPA) requested that Task 13 be enlarged to
include the following:
• Block flow diagrams and cost estimates for the pro-
duction of methanol, substitute natural gas and low
Btu gas via the SASOL-type process.
• Annualized Operating and production costs of the above
processes
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II. Basis of Evaluation
Basis of the estimates is a mine-mouth plant, Western U.S. coal,
with capital investment expressed in 1975 dollars. Flow sheets
and cost estimates were to be derived from existing information
and no detailed estimates were to be prepared.
The only fuel used in the plant is coal. Part of this coal is
used for steam and power generation, both of which are needed
to operate the plant and off-site facilities, and the remainder
is used for the production of synthesis gas and ultimately
from it the desired products.
The Western U.S. coal selected for this study is from a New
Mexico source and has properties used by El Paso Natural Gas
Company in their feasibility study of Burnham Coal Gasification
Complex for the manufacture of substitute natural gas (3). It
is fully expected that this coal will gasify well in either air-
or oxygen-blown Lurgi gasifiers.
Another assumption made at the outset and incorporated in the
block flow diagram was that only limited sulfur and hydrocarbon
emissions to the atmosphere would be permitted. Also clean-up
of liquid effluents would be required.
The quantity of water required by the plant was not estimated since
appropriate site information needed were not available. Items
such as wet and dry bulb temperatures, available water quantity
and quality, annual rain fall, percent run-off, soil conditions,
etc., must be known before estimates of water requirements can
be made.
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Ill. Summary
A. Gasoline-From-Coal
Deletion of the power supply to the nearby village reduces
the coal feed rate to the fuel gas manufacture (Section 1000)
by about 21%. Total coal feed to the plant is revised to 34,249
TPD. The block flow diagram for the gasoline-from-coal plant (MWK
Dwg. P3925-D) has been revised accordingly. No excess power produc-
tion is included and the plant is self-contained in that the only
input to the plant is coal, air and water. The revised capital
investment is estimated to be $505 million, 1975 dollars. Table
1 presents a complete breakdown of the capital investment by
individual sections. These figures, represent the capital investment
for a p]ant which produces 44,500 BPSD (Nominal) gasoline and other
hydrocarbon liquids from coal, have been derived from published
information (2, 3) and updated to 1975 by means of escalation
rates for both labor and material. It should be noted that overnight
construction of the plant is assumed. That is, it is assumed
that the complete plant can be designed and constructed in such
a short period of time that no additional increase in labor or
material will be encountered. In short, no forward escalation
has been included in the estimated cost of $505 million. In actual
practice significant increases in costs probably would be encountered
since several years would be required to build the plant.
Production rates of the various products are given in Table
2. Using a modified Panhandle Eastern accounting procedure which
is recommended for coal conversion facilities (4), the cost of
gasoline for a 20-year average price (excluding escalation) is
estimated to be $3.05/MMBtu or $15/barrel assuming all appropriate
byproducts are marketable. The price of coal which corresponds
to these gasoline costs is $3.60/ton (7). The effect of other coal
prices on the gasoline cost is given in Fig. 5. Using a different
accounting procedure with a fixed capital charge of 18.22% (6),
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the gasoline cost for a 15-year average price is estimated to
be $4.05/MMBtu or $20/barrel (with by-product credits).
Approximately 80% of the tar, oil and naphtha produced can
be further processed into gasoline product. Assuming addition
of such a conversion facility does not alter the total plant
investment significantly, gasoline cost can be reduced to $2.76/
MMBtu or $13.70/barrel using the Panhandle Eastern accounting
method. Such a process modification increases the gasoline
production rate by about 40%.
It should be pointed out that should the power generation
plant for the nearby village (housing the operation and super-
visory personnel) be included as an integrated part of the
gasoline-from-coal facility, the total coal consumption will
be increased to 37,665 TPD (1). Approximately 40% of the coal
is used for steam and power generation. The revised total
plant investment for the gasoline-from-coal facility including
the power plant and other offsites is estimated to be $533
million,1975 dollars.
B. Methanol-From-Coal
A block flow diagram has been developed and approximate
overall material and energy balances calculated for the
methanol-from-coal plant. Using the same coal feed rate to
the gasification section as used for the gasoline-from-coal
plant, the methanol production rate is 11,338 TPD (Table 4).
A maximum size train is estimated to produce 2,800 TPD of
methanol and the present plant, therefore, consists of four
such units in parallel.
Some seventeen sections are required for the methanol-
from-coal plant. Most of these sections are similar in design
as well as operation to those used in the gasoline-from-coal
plant and the costs for these sections are derived from figures
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given in the gasoline plant. Sections which are different from
those in the gasoline plant are the shift conversion, methane
reforming, synthesis gas compression and methanol synthesis and
recovery. Costs of these sections are derived from in-house
information for a smaller size methanol plant. Capital in-
vestment for the seventeen sections is estimated to be $472
million (Table 3), 1975 dollars assuming overnight construction
of the plant with no forward escalation. Based on this esti-
mate and using the modified Panhandle Eastern accounting pro-
cedure, the cost of producing methanol from coal is estimated
to be $1.80/MMBtu ($4.90/barrel) assuming all appropriate by-
products are marketable and a coal cost of $3.60/ton. For a
15-year plant life with a fixed capital charge of 18.22%, the
methanol cost is estimated to be $2.34/MMBtu or $6.40/barrel.
Appendix B presents the operating and annualized production cost
for the methanol-from-coal plant.
C. Substitute Natural Gas-From-Coal
A block flow diagram for the substitute natural gas (SNG)
from-coal plant have been developed and overall material and
energy balances calculated. The SNG-from-coal plant has the
same coal feed (21,274 TPD) to the gasification unit (Section
200) as the two previous coal conversion processes. In order
for the plant to be self-contained, an additional coal feed
rate of 5,435 TPD is required as input to the fuel gas manu-
facture section for steam and power generation. The corre-
sponding gas production rate is 258 MMSCFD (972 Btu/SCF).
Eighteen sections are required for the SNG-from-coal
plants. Most of these sections are similar in design to the
two previous coal conversion processes with the exception of
the methane synthesis and synthesis gas compression sections.
The cost for these two sections are derived from published
information (3).
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Capital investment for a SNG-from-coal plant producing 258
MMSCFD of gas is estimated to be $365 million, 1975 dollars
assuming overnight construction of the plant with no forward
escalation. Table 5 presents a detail breakdown of the capital
investment for individual sections. Based on this estimate and
assuming all by-products are marketable, the gas prices is
estimated to be $1.13/MMBtu using the modified Panhandle Eastern
accounting procedure and a coal price of $3.60/ton. The SNG
cost resulting from an alternative accounting procedure with
a 15-year plant life will be $1.50/MMBtu (with by-product
credits). Production rates of the various products are listed
in Table 6. Appendix C outlines the annualized production
and operating costs of the SNG-from-coal plant.
D. Low Btu Gas-From-Coal
A block flow diagram for a comparable low Btu gas-from-coal
plant has been developed and overall material and energy bal-
ances calculated. The low Btu gas facility has a coal feed
rate of 21,274 TPD to the gas manufacture section which is the
same rate used in the other three coal conversion processes.
In order for the plant to be self-contained, part of the fuel
gas manufactured is used in the steam and power generation
plant for process consumption. The remainder of the fuel gas
(960 MMSCFD @ 230 Btu/SCF) is transmitted as product.
The capital investment for the low Btu gas-from-coal
facility is estimated to be $218 million, 1975 dollars and is
derived from the fuel gas manufacturing and other corresponding
sections of the gasoline-from-coal plant. Table 7 presents a
complete breakdown of the capital investment for individual
sections of the low Btu-gas-from-coal facility. Based on
this estimate and assuming all by-products are marketable, the
low Btu gas cost is $0.86/MMBtu using the modified Panhandle
Eastern accounting procedure and a coal price of $3.60/ton.
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The low Btu gas resulting from the alternative accounting
procedure with a 15-year plant life is estimated to be $1.10/
MMBtu (with by-product credits). These costs of low Btu gas
are derived using an on-stream factor of 0.9. The production
costs for 0.7 on-stream factor have also been investigated as
typical for hook-up with power plants. The low Btu gas costs
for the lower on-stream factor are $1.10/MMBtu using the
modified Panhandle accounting procedure and $1.44/MMBtu using
the alternative (15-year plant life) accounting procedure and
with by-product credits. Figure 5 illustrates graphically
the sensitivity of on-stream factors on the low Btu gas cost.
Production rates of the various products from the low Btu gas-
from-coal plant are listed in Table 8. Annual!zed production
and operating costs of the low Btu gas-from-coal plant are
given in Appendix D for two cases: 0.9 and 0.7 on-stream
factors.
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Table 1
Gasoline-From-Coal Investment Summary
Section 1975, M$
100 Coal Preparation 38,000
200 Coal Gasification 48,000
300 Gas Purification 41,000
400 Methane Splitting 10,000
500 Synthesis 53,000
600 Product Recovery 28,000
700 Chemical Recovery 8,000
800 Hydrogen & Catalyst Manufacture 8,000
900 Oxygen Production 73,000
1000 Fuel Gas Production , 62,000
1100 Steam & Power 42,000
1200 Gas Liquor Treating 13,000
1300 Ash Disposal 8,000
1400 Effluent Water Treating 4,000
1500 Sulfur Recovery 9,000
1600 Raw Water Treating 6,000
1700 Cooling Water 15,000
1800 Offsite & General 39,000
TOTAL $505,000
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Table 2
Gasoline-From-Coal
Production Rate
Product
Gasoline**
Diesel Oil
Waxy Oil
Propane LPG
Acetone
Methanol
Propanol
i-Butanol
n-Butanol
M.E.K.
n-Pentanol
Tar, Oil, Naphtha***
Phenol
Ammonia
Sulfur
HHV of Products = 10 .
HHV of Coal 25.
= 41
#/hr
262,353
15,121
11,847
16,056
2,650
343
4,832
546
1,606
670
374
162,074
13,665
28,742
13,757
5053 x 100%
3209
.5%
BPD
25,495
1,233
925
2,000
230
30
412
46
136
56
32
13,230
716
--
TOTAL
HHV, 10 9 Btu/hr
5.2654
0.2913
0.2175
0.3412
0.0348
0.0033
0.0698
0.0085
0.0249
0.0097
0.0056
3.8804
0.0218
0.2763
0.0548
10.5053
** Gasoline with research octane number equals 86
***80% of tar, oil, naphtha can be further processed to gasoline product
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Table 3
Methanol-From-Coal Investment Summary
Section 1975, M$
100 Coal Preparation 36,000
200 Coal Gasification 48,000
300 Gas Purification 41,000
400 Shift Conversion 9,000
500 Methane Splitting 32,000
600 Synthesis Gas Compression 19,000
700 Methanol Synthesis & Recovery 65,000
800 Sulfur Recovery 8,000
900 Oxygen Production 43,000
1000 Fuel Gas Manufacture 51,000
1100 Steam & Power Generation 36,000
1200 Gas Liquor Treating 12,000
1300 Ash Disposal 8,000
1400 Effluent Water Treatment 4,000
1500 Raw Water Treatment 6,000
1600 Cooling Water 15,000
1700 Offsites 39,000
TOTAL 472,000
10
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Table 4
Methanol-From-Coal
Production Rate
Product
#/hr
BPD
HHV, 109 Btu/hr
Methanol
Tar, Oil, Naphtha
Higher Alcohols &
Dimethyl Ether
Phenols
Ammonia
Sulfur
927,748
151,684
4,452
13,052
27,453
11,323
81,433
12,382
367
684
—
TOTAL
9.2281
3.6798
0.0662
0.0209
0.2639
0.0451
13.3040
HHV of Products = 13.3040
x 100%
HHV of Coal
23.4912
= 56.6%
11
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Table 5
Substitute Natural Gas-From-Coal Investment Summary
Section 1975, M$
100 Coal Preparation 32,000
200 Coal Gasification 48,000
300 Shift Converter &
+
400 Gas Cooling 15,000
500 Gas Purification 41,000
600 Methane Synthesis 19,000
700 Gas Compression 7,000
800 Gas Liquor Separation (Included in 300
and 400)
900 Air Separation 43,000
1000 Fuel Gas Manufacture 29,000
1100 Steam & Power Generation 48,000
'1200 Phenol Recovery 10,000
1300 Ash Disposal 4,000
1400 Effluent Water Treatment 5,000
1500 Sulfur Plant 8,000
1600 Raw Water Treatment 5,000
1700 Cooling Water 15,000
1800 Offsites 36,000
TOTAL 365,000
12
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Table 6
Substitute Natural Gas
Production Rate
Product
#/hr
Production HHV, 10y Btu/hr
Substitute Natural Gas 474,069
Tar, Oil, Naphtha
Phenols
149,002
10,440
HHV of Products = 13.4437 x 100%
HHV of Coals
19.7462
68.1%
258 MMSCFD
12,160 BPD
550 BPD
10.4531
2.7565
0.0167
Ammonia
Sulfur
17,353 208 STPD
12,698 136 LTPD
Total
0
0
13
.1667
.0507
.4437
13
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Table 7
Low Btu Gas-From-Coal Investment Summary
Section 1975, M$
100 Coal Preparation 25,000
200 Coal Gasification & Gas
Purification (Hot Carbonate System) 98,000
300 Ash Disposal 3,000
400 Steam & Power Generation 38,000
500 Gas Liquor Treatment 8,000
600 Effluent Water Treatment 4,000
700 Raw Water Treatment 4,000
800 Sulfur Recovery 7,000
900 Cooling Water 5,000
1000 Offsites 26,000
TOTAL 218,000
14
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Table 8
Low Btu Gas-From-Coal
Production Rate
Product
Low Btu Gas
Tar, Oil, Naphtha
Phenols
Ammonia
Sulfur
#/hr
2,437,756
88,018
8,320
13,780
10,114
Production HHV, 109 Btu/hr
960 MMSCFD
7,185 BPD
436 BPD
165 STPD
108 LTPD
Total
9,1936
1.7247
0.0133
0.0403
0.1325
11.1044
HHV of Products = 11.1044 x 100%
HHV of Coal
15.728
70.6%
15
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IV. Process Description
A. Gasoline-From-Coal (MWK Dwg. P3925-D)
a. DESCRIPTION
A block flow diagram for the gasoline-from-coal plant is
given in the cited drawing. The process may be divided into
following steps:
• Coal Gasification and Raw Gas Purification
• Synthesis Gas Preparation
• Synthesis of Gasoline and Recovery
• Fuel Gas Manufacture - Steam & Power Generation
1. Coal Gasification and Raw Gas Purification
Coal received from the mine at section 100, Coal
Preparation, undergoes crushing, screening, stockpiling,
reclaiming and briquetting treatment according to needs
of the plant. The product from section 100 is conveyed
by belt to both section 200, Gasification, and section 1000,
Fuel Gas Manufacture. In both areas coal is gasified
essentially completely for manufacture of both synthesis
gas and fuel gas.
Ash from both sections 200 and 1000 is conveyed either
by belt or by water to section 1300, Ash Disposal. This
section includes thickeners and screens for the recovery
of water for reuse in ash quenching and/or sluicing.
Gasification in section 200 employs steam and oxygen
in a mixture introduced under the grates of multiples of
Lurgi Gasifiers. Operating under pressure of up to 500
psig, the Lurgi gasifier receives its coal input through
a lock hopper pressured by product gas. This lock hopper
is periodically filled from an overhead bunker when level
indicators show that the hopper has been emptied into
the gasifier. The gasifier proper is a water-jacketted
16
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pressure vessel equipped with a distributor for ttie coal
feed at the top and a water cooled grate at the bottom
which has the dual function of distributing the gasification
medium (steam and oxygen or air and steam) and discharging
the ash. Ash is discharged to a lock hopper which is
periodically emptied when the volume of ash builds to a
pre-set level.
In the gasifier, the falling fixed bed of coal supported
on the grate moves from coal to ash through stages of
devolatilization and combustion. The gas product is
principally the result of reaction between hot gases leaving
the combustion zone and the devolatilized coal. Gas
leaving the relatively cool top outlet of the gasifier is
quenched to knock down condensible carbonization products
and unconverted steam. Tar is separated from the gas
liquor by decanting at about the boiling point of water;
oil and naphtha are separated from gas liquor by decanting
at essentially room temperature. The gas liquor is princi-
pally water but contains both phenols and dissolved gases,
e.g., H S, CO and NH .
Gas released from the feed hopper, as the hopper is
depressured for refilling, is collected from a battery of
gasifiers and recompressed to gasifier pressure. Little
gas is involved in the cycling of the ash hopper as the
atmosphere under the grate is steam and oxygen, and the
steam is condensed before the vessel is opened for dis-
charge of the ashes.
Cooled raw gas is separated from its condensates and
sent to section 300, Gas Purification where it undergoes
scrubbing with a chilled polar solvent according co a version
of the Rectisol process first employed industrially at
SASOL. Stripping of the solvent is achieved both by flashing
and also by chilled nitrogen from section 900, Air Separation.
Off-gases comprise a hydrogen sulfide concentrate sent to
17
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section 1500, Sulfur Recovery, and a mixture of mostly
nitrogen and carbon dioxide, sent to the stacks of
section 1100, Steam and Power.
2 . Synthesis Gas Preparation
Pure gas from section 300 is the net feed to the syn-
thesis section but by virtue of having been generated in
a pressure Lurgi gasifier, contains methane which is an
unwanted component in the synthesis feed. In section
400, Methane Splitting, methane and other light hydrocarbons
produced by the synthesis are split into hydrogen and car-
bon monoxide which, of course, are the ingredients wanted
in the synthesis feed. The splitting is performed catalyti-
cally at high temperature with proper additions of steam
and oxygen to produce the desired synthesis feed. A
small fraction of the split gas is diverted to section 800,
Hydrogen Plant, where catalytic treatments of shift and
methanation produce a stream of 99% hydrogen for synthesis
catalyst reduction and other uses in the plant.
3 . Synthesis of Gasoline & Recovery
Synthesis gas from the methane splitting are fed to
the synthesis section to make gasoline via the Fischer-
Tropsch process. This process involves the catalytic
reaction of carbon monoxide with hydrogen according
to the following reactions:
2nH0 + n CO = (CH ) + n HO
£, £ n ^
nH + 2n CO = (CH) + n C0
Catalyst is made from either millscale or pure magnetite
in section 800, Catalyst Plant.
18
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Gas and oil products of the synthesis are washed with
water to remove water soluble chemicals. This water plus
the reaction water and its dissolved chemicals comprise
the feed to section 700, Chemical Recovery. The washed
gas and oil become the feed to section 600, Product Recovery
Hydrocarbon products are recovered in section 600 through
absorption/stripping operations. Light gases not re-
covered in the lean oil absorption are:
• vented to the fuel gas system of section
1100 for steam and power generation
• returned to the synthesis as aeration gas
• partly returned to section 400, Methane
Splitting, for the conversion of light
hydrocarbons to synthesis gas (external
recycle stream)
4. Fuel Gas Manufacture - Steam & Power Generation
Fuel gas is manufactured by the pressure gasification
of coal in steam-and-air-blown Lurgi gasifiers of section
1000, Fuel Gas Manufacture. Fuel gas manufactured is
free of fly arh and is purified in much the same way that
the synthesis gas was prepared and purified. Condensation
products from synthesis gas and fuel gas manufacture are
combined and treated. Section 1000 includes a hot carbon-
ate scrubbing system which removes most of the carbon
dioxide and hydrogen sulfide from the fuel gas. Foul
gas scrubbed from the fuel gas contains hydrogen sulfide
and is treated in section 1500, Sulfur Recovery, along
with the hydrogen sulfide concentrate from synthesis
gas purification. The sulfides are converted to elemental
sulfur and recovered as a solid product. Some of the
purified fuel gas is fed to gas turbines for the generation
of power; the remainder is burned in process furnaces and
in boilers raising steam for process and driver uses. Gas
turbines exhaust into the fire box of the boiler and these
19
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gases are disposed of along with flue gas via power plant
stacks. Section 1100 includes the treatment of water for
the make-up to the boilers, aeration and blow-down.
Cooling water inventory and circulation to the coolers
requiring water cooling are provided by section 1700,
which includes chlorination and blowdown. Makeup to this
section is from section 1600, Water Treatment, where water
is collected from various parts of the plant. For example,
one stream to section 1600 is from section 1400, Effluent
Water Treatment, where foul process condensate is purified
by activated sludge waste water treating.
b. PROCESS CONSIDERATIONS
It should be noted that a SASOL-type plant as presented in
this report is a plant representative of a twenty-year old
technology. Improvements in this technology have been made by
SASOL principally to suite their needs for fuels and chemicals.
Over the years these needs have changed as new products, (e.g.,
pipeline gas, ammonia, ethylene, synthetic rubber, etc.) were
added to the list manufactured from the raw material feeds, viz.,
coal, water and air. SASOL's continued study of processes in
their complex has doubtless given much fundamental information
that would be a real asset to a designer tailoring a coal-to-
gasoline facility twenty or more years after the original design
was committed. For circumstances plausible for such a plant,
changes could be called for in the synthesis catalyst manufacturing,
leading to a modified product spectrum to suit economic or other
circumstances for the projected plant. Optimization of any
such design would require information that is unlikely to be
found from any source other than SASOL. Lacking access to
SASOL's proprietary information for possible attempts at optimi-
zation of the facilities described in this report, the present
coal-to-gasoline plant can be presented only on the basis of
the twenty-year old technology with some minor updating modifi-
cations made public by SASOL in the intervening years.
20
-------
It is significant that the major process steps of the SASOL
plant have been proven to be compatible members of the complex
and that the complex is amply proven successful for the manu-
facture of gasoline from coal. It follows that each major
process unit is amply proven successful for its intended service.
Sections 200 and 1000 employ the Lurgi pressure gasification
process developed by Lurgi Gesellschaft fuer Waermetechnik
of Frankfurt, Germany. This process was selected for SASOL
in the belief, now confirmed by both pilot plant and later
commercial application, that this process and the South African
coal were suited for each other. For the present study there
is every reason to believe that the same suitability exists
for the process and the Western coal chosen. Of course there
are other gasification processes that might be used if properties
of the coal contemplated were not suited for large-scale
pressure gasification by the Lurgi process. Advantages or
disadvantages of such processes could only be assessed from a
complete knowledge of the coal properties plus possibly some
actual test gasification work. Conceivably a coal in question
would be handled most economically if pretreated to destroy
possibly caking tendencies, or coked to recover byproducts
of attractive sales value and then gasified by some process
best suited for the product coke.
Gasification by the Lurgi process leads to the production
of coal tars, oils, naphthas and phenols, that may or may not
have attractive values, and also leads to the formation of methane
in the gaseous product. The methane content of the fuel gas
is an asset as it gives the fuel gas a higher heating value;
however, for the synthesis gas methane is a liability as it
requires catalytic splitting with oxygen and steam to supply
the reactants needed in the Fischer-Tropsch synthesis. Conceivably
a proper choice of gasifiers would involve a low pressure process
for synthesis gas production and a pressure gasifier (e.g.,
Lurgi) for fuel gas production. On the other hand, the Lurgi
gasifier with its excellent record at SASOL is not easily
21
-------
replaced at this time by less experienced processes unless
it is not at all suited to the coal contemplated.
Gas purification is an important process step in the SASOL-
type gasoline-from-coal plant. The Rectisol process first
used commercially at SASOL has been an outstanding success
and its performance has been phenonenal. In this single contin-
uously-operating process, the wide-cut mixture of gases and
vapors is freed of resin formers and objectionable sulfur
compounds to mere trace proportions (less than 0.1 ppm total
sulfur) while being separated from most of the carson dioxide
contained at about 30% concentration in the raw gas from the
gasifiers. Extreme high purity is a requirement of the gas
feeding to the iron catalyst of the synthesis, the same as
it is for the iron catalyst of ammonia synthesis. This high
purity is achieved in an absorber/stripper process in which the
lean oil is a refrigerated polar solvent, e.g., methanol.
For the present plant design a departure from the SASOL Rectisol
design was made to achieve a more concentrated H S stream for
£
sulfur recovery and a nearly sulfur-free stream for discharge
to atmosphere. This departure involved the use of nitrogen
from the oxygen plant for stripping of foul methanol. This
is according to a variation of the Rectisol process proposed
by Gesellschaft fuer Linde's Eismaschinen, Hoellriegelskreuth,
Germany, developers of the Rectisol process.
Conversion of light hydrocarbons into Fischer-Tropsch
reactants (H? + CO) is another important operation in the
SASOL-type plant. The procedure whereby unwanted light
hydrocarbons and methane are converted into reactants is
a Kellogg development employing high temperature reforming
of the hydrocarbons in a steam atmosphere, oxygen being used
to supply the endothermic reaction heat. This is a regenerative
process in which the reaction feed streams are heated by the
reaction product stream. Unconverted steam is condensed as the
product gas is cooled to cooling water temperature. This con-
densate is sent for treatment preparing it for reuse in steam
22
-------
raising. Methane splitting in this plant, as at SASOL, is
accomplished in a fixed-bed catalytic reactor. The composition
of the synthesis feed gas is adjusted in this reforming operation
by proper choice of oxygen and steam rates corresponding to the
inlet gas composition and rate.
Although the H /CO ratio of the synthesis feed leaving the
methane splitter is essentially the ratio at which these
reactants are consumed in the synthesis reactions, the ratio
prevailing in the reactor is much higher. The reactor H /CO
^
ratio is made higher by the internal recycle of the synthesis
cycle, this gas being a light tail gas from the synthesis.
The mixture of feed and internal recycle is fed to the high
velocity fluid catalytic reactor especially developed by Kellogg
for the highly exothermic Fischer-Tropsch reaction. The mixed
stream, only slightly preheated above cooling water temperature,
contacts hot fluid iron catalyst descending a standpipe leg of
a catalyst loop circuit and becomes heated to a kindling tempera-
ture at which the reactions begin. This mixture of catalyst
and reacting gases rises vertically through the reactor leg of
the catalyst loop circuit, transferring reaction heat to an
external cooling medium through surfaces built into the reactor
leg. Although there is considerable shrinkage of the gas
volume through reaction, and a corresponding reduction in velocity,
the mixture travels completely through the vertical reactor and
over an inverted U-bend to the separator vessel in which the
catalyst disengages from the gas stream to complete the loop
via the bottom-connected standpipe leg. The product distribution
obtained in this reaction is dependent on the catalyst type
and activity as well as on the outlet temperature and the
reactor temperature profile. The high velocity fluid reactor
puts the important variables in easy control of the operator.
Heat removed from the reacting stream traversing the reactor
is used to raise steam at about 175 psig which in term is used
in turbine drives for compressors, e.g., internal recycle com-
pressors . Hot gas separated from the catalyst flows to an oil
23
-------
scrubber in which cooling and condensation is effected through
direct contact with circulating oil, dumping heat to boiler
feed water for boilers in the synthesis section. The oil
circulation circuit is followed by a water circulation circuit
that, through direct contact with the reactor gases and vapors,
effects further cooling and condensation of reactor products.
Tail gas following these condensation stages is split four
ways: 1) a large stream of internal recycle; 2) a net stream
that is to be subsequently processed into light gas for external
recycle; 3) a purge stream which is used as fuel in steam and
power generation section; and 4) a heavy hydrocarbon stream
feeding product separators.
Bottoms of the oil scrubber contain catalyst fines
washed down in the condensation process; these bottoms are
returned to the catalyst circulation. Just above the catalyst
settling zone of the scrubber, a heavy oil is decanted and sent
from the unit as a separate stream for further processing.
Light oil separated by gravity from the water circulation cir-
cuit is first water washed to remove water soluble chemicals and
then sent from the unit for further processing. Tail gas is
similarly water washed and then sent on to the product recovery
area. Aqueous streams condensed from the reactor product join
the wash water streams and become the feed to the Chemical
Recovery section 700.
Heavy oil decanted above the catalyst settling zone of the
synthesis unit oil scrubber enters section 600, Product Recovery,
where it is flashed to remove its very heavy components. The
lighter fractions of this oil join the lighter oil of the syn-
thesis production and together the mixture undergoes vapor phase
catalytic clay treatment for the removal of oil soluble chemicals
and mild catalytic cracking of the synthetic crude molecules.
The catalyst is regenerated in the usual way by burning off
carbon with a mixture of air and nitrogen.
Synthesis tail gas from section 500, Synthesis, is passed
24
-------
directly to the absorber of the section 600, Product Recovery.
Lean oil stripped in the lean oil distillation tower preferentially
absorbs the heavier fractions of the gas and only a small amount
of the lighter unwanted fractions. The unwanted fractions are
partly purged from the system to remove the inerts (e.g., N»
and Ar brought in with coal and oxygen) and mostly returned to
the Methane Splitter, Section 400, for conversion to CO and H?
for the synthesis. Absorbed components become feed for the
catalytic polymerization unit which, under high pressure and in
the presence of a catalyst, unites unsaturated molecules to
form high octane gasoline molecules. Some excess of stripped
molecules over those consumed by polymerization are liquefied
and transfered to LPG storage for eventual marketing. Part
of the cat poly feed is generated in the clay treating of the
synthetic oil.
A fractionator separates the liquids recovered from clay
treating and cat poly into gasoline, diesel oil and furnace,
or waxy, oil.
The aqueous stream from section 500, Synthesis, is treated
in section 700, Chemical Recovery, for the recovery of alcohols
and ketones. The first separation is made to dispose of the
acids and the bulk of the water. This mixture is sent to the
activated sludge treatment unit in section 1400. Overhead
product of the first separation is rich in alcohols and ketones
and this stream is separated into two main streams in the following
distillation tower. Both of these streams are processed further
in a system of eight distillation towers and two hydrogenation
reactors to yield ethyl alcohol, propyl alcohol, a stream of
heavier alcohols and a mixture of ketones as intermediate
products. The heavier alcohols are simply distilled to yield
butyl alcohol, pentyl alcohol and a small residue of heavier
alcohols, used as fuel. The mixture of ketones is first
caustic treated then distilled to recover acetone and MEK
(methylethyl ketone).
25
-------
Ethyl alcohol is blended with the gasoline product for the
octane benefits it supplies. All other products of section 700
are pumped to storage in the offsites. Section 600 products
are pumped to storage also with the gasoline getting the treat-
ment and/or additives it may require for marketing, e.g.,
color addition, inhibitor addition.
Sulfurous gases from sections 300, Gas Purification, and
1000, Fuel Gas Manufacture, become feed to the section 1500,
Sulfur Recovery Unit, which, employing a Stretford solution,
recovers the sulfur of H S as solid sulfur. The waste gas is
vented through stacks. Air for the oxidation is supplied by
a compressor incorporated in section 1500.
The steam and power section, 1100, is visualized in a
location close to air separation, section 900. Large compres-
sors of the air separation plant could thus be driven by gas
turbines exhausting into the firebox of boilers and steam
superheaters of section 1100. Steam systems have not been
sketched for the plant and for the section 1100 in particular.
It is very likely that steam generation, unlike steam generation
at SASOL, will be at high pressure, e.g., 1500 psig. Super-
heated steam at this pressure likely will be sent to topping
turbines for the generation of electrical power for the plant.
Exhaust of these turbines will supply the process
steam for gasification in sections 200 and 1000. Low level
steam generated in section 500 will doubtless find use for
turbine drives within the section, probably supplemented with
the process steam level established by the gasifiers. Still
lower level steam generated in waste heat boilers of the
gasification plant probably will supply boiler feed water
deaeration needs, reboiler duties, space heating requirements,
etc. Condensates will be collected in separate tanks
according to whether they are expected to be always clean or
whether possibly contaminated by gases or liquids reaching
the condensates, possibly through equipment leaks.
26
-------
It is possible that this plant could be redesigned for a
more interesting array of products from coal at a much
reduced plant cost. The prospects would be dependent upon the
product array sought and newer technology available than
were at hand for the SASOL plant design. This newer technology
may possibly exist with SASOL at the present or could result
from the aims of research and development that may need to be
undertaken. It is clear that the Methane Splitting could, for
example, be eliminated if the desired product array included
a reasonably high Btu gas. The external recycle would go to
fuel gas. Conceivably the Lurgi gas issuing from the gasifiers
could be reformed catalytically with oxygen addition at temperatures
high enough to convert the tars, phenols, oils and methane to
the reactants CO and H,,. Considerable savings would be made
if this step could be taken. Of course, the incentive would
depend on possible sales values of phenols and coal tar products.
Depending on product array desired, the catalyst may be
profitably altered with possible changes in amount or kind of
catalyst modifiers. Presumably there is knowledge and experience
to guide steps that may be taken to this end development.
Considerable savings could doubtless be made if coal fines
could be fired directly to the power plant and expensive stack
gas cleaning were not a requirement for the power plant.
Tie-ins with other industries may have some interesting
prospects for a gasoline-from-coal plant. Gases from a refinery
handling natural crude possibly could be processed with gases
from a synthesis plant to a mutual advantage. Gases or liquids
from a steel mill might be exchanged with products of the synthesis
to a mutual advantage. It should be remembered that the pro-
ducts of the synthesis are remarkably free of many troublesome
contaminants, e.g., metals, sulfur. The probable octane of the
gasoline from the subject plant is about 86 research. If
octane levels were important, the scope of operations would
probably have to be increased to include isomerization and
alkylation.
27
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B. Methanol-From-Coal (MWK Dwg . P3355-D)
A block flow diagram for the methanol-f rom-coal process is
given in the cited drawing. The process may be divided into three
steps :
• Coal Gasification and Raw Gas Purification
• Synthesis Gas Preparation
• Methanol Synthesis and Purification
1 . Coal Gasification and Raw Gas Purification
This step is identical to the one in the gasoline-f rom-
coal plant.
2 . Synthesis Gas Preparation
Feed gas introduced into the methanol synthesis loop
must contain the correct proportions of carbon monoxide ,
carbon dioxide and hydrogen according to the following over-
all reactions:
CO + 2H = CH3OH
Synthesis gas composition will be adjusted by shift reaction
and steam reforming. Raw synthesis gas from the purification
section contains methane which is an unwanted component in
the synthesis feed. The methane and other light hydrocarbon
produced are split into hydrogen and carbon oxides by steam
reforming. However, due to the relatively high concentration
of carbon monoxide in the raw synthesis gas, carbon may be
formed by disproportionation and deposit on the reforming
catalyst surface and render the catalyst inactive. Part
of the synthesis gas is sent to shift conversion and the
34
-------
remainder is by-passed. In the shift reaction carbon monoxide
reacts with steam to form equivalent amounts of carbon dioxide
and hydrogen. The shift reaction is exothermic and the shift
effluent is cooled against boiler feed water. Water condensed
in the cooling of the gas is separated and the cooled gas is
then sent to the methane reforming unit. Steam reforming of
methane is highly endothermic and heat is required as input
to the reformer. Reformer effluent exits at about 1600°F,
is cooled against the incoming feed and also used to boil
feed water. The final synthesis gas is adjusted to the com-
position desired by a carbon dioxide make-up stream from the
Rectisol unit.
3. Methanol Synthesis and Purification
Synthesis gas, containing hydrogen, carbon monoxide, carbon
dioxide and small amounts of nitrogen, argon and methane,
flows to the suction of the two-stage centrifugal feed
compressor. The compressor is driven by a steam turbine using
high pressure superheated steam. Fresh synthesis gas is com-
pressed to about 1370 psig in two stages with intercooling
between stages. Following cooling and separation of condensate,
the compressed synthesis feed gas joins synthesis loop recycle
gas containing about 0.3 percent methanol vapor. The combined
stream is then compressed by a single-stage, turbine-driven
centrifugal compressor to about 1485 psig and delivered to
the methanol converter. Prior to entering the converter, a
major portion of the feed flows to the interchanger which
preheats the gas by exchange with the hot methanol converter
effluent. The two overall reactions occuring in the converter
are those associated with the combination of hydrogen and carbon
monoxide to form methanol and the reaction of hydrogen and
carbon dioxide to form carbon monoxide and water. Other side
reactions involve the formation of dimethyl ether, ketones
and higher alcohols. The hot effluent is cooled by the inter-
changer and again by water-cooled exchanger to 100°F thus
condensing out the crude methanol product. The vapor/liquid
stream then flows to the catchpot for separation of vapor
35
-------
from liquid. Disengaged vapor, containing unreacted hydrogen,
carbon monoxide, carbon dioxide, methanol vapor, water and di-
methylether flows to recycle compressor suction where it is com-
bined with fresh feed make-up gas. Prior to compression, a
proportion of the recycle gas is vented continuously to the
fuel system to control the concentrations of methane, nitrogen
and argon in the synthesis loop. These components would other-
wise build up in the system and reduce the effective synthesis
pressure, which would be reflected by lower methanol conversion
per pass and reduced production capacity. Purge gas is delivered
to the fuel gas system for power and steam generation.
Crude methanol from the catchpot, containing methanol,
water and various impurities, flows to flash drums where the
stream is flashed at 50 psig for removing the bulk of gas dis-
solved in the stream. Flash gas from this pressure reduction
step also flows to the fuel system. Liquid from flash drums
flow to the crude methanol storage tank.
Purification of methanol is accomplished in a two-tower
distillation facility. The fractionation system consists of a
topping column whose primary purpose is to remove light-end
impurities such as dimethyl ether, ketones and aldehydes and
a refining column to remove the heavy ends including ethanol
and other higher alcohols from the methanol product. It should
be noted that a two tower purification system may not be necessary
for "fuel grade" methanol in which case the investment and operating
cost would be reduced slightly.
36
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C. Substitute Natural Gas-From-Coal (MWK Dwg. P3356-D)
A block flow diagram for the substitute natural gas (SNG)-
from coal process is given in the cited drawing. The process
may be divided into three steps:
• Coal Gasification and Raw Gas Purification
• Methane Synthesis
• Synthesis Gas Compression
1. Coal Gasification and Raw Gas Purification
This step is identical to the one in the gasoline-from-
coal process which is described previously. The only difference
from the gasoline-from-coal plant design is the addition of
a shift conversion area which is designed to produce hydrogen
by the "water gas shift" reaction:
CO + H20 = CC>2 + H2
Approximately one-half of the total crude gas from the gasifiers
is subjected to shift conversion; the remainder is bypassed
directly to the gas cooling area. The ratio of the two gas
streams will be adjusted to achieve the desired H2:CO ratio
for proper feed to the methanation unit. Crude gas feed to
the shift conversion area is quenched and washed first. The
washed gas is heated in a series of heat exchangers before
entering the first shift reactor where the bulk of carbon
monoxide is catalytically converted to equivalent amount of
hydrogen and carbon-dioxide. The first stage hot effluent is
cooled in counter-current exchange with the feed gas before
entering the second shift reactor where further conversion
of carbon monoxide will take place. Effluent gas from
the second shift reactor is cooled by indirect exchange with
the feed gas before leaving the shift conversion unit.
42
-------
2 . Methane Synthesis
The methanation step converts low Btu synthesis gas to
methane rich high Btu gas by the following overall chemical
reactions :
CO
Both of these reactions are highly exothermic and the heat
released is used to heat the incoming feed gas as well as
for steam generation in waste heat boilers. Hot feed gas,
after indirect exchange with the product gas, is passed through
a sulfur guard reactor to remove last traces of impurities
before entering the synthesis loop. The synthesis loop con-
sists of a methanator, waste heat boilers and a recycle com-
pressor. Feed gas composition to the methanator will be set
by combining the fresh feed gas stream with the gas stream
circulated by the recycle compressor. Reaction heat iro^.
the methanator is removed in the high and low pressure waste
heat boilers. Product gas from the synthesis loop is cooled
in a feed/recycle product heat exchanger and further cooled
in a final product cooler to ambient temperature. Condensed
water is removed in a product-condensate separator.
3 . Synthesis Gas Compression
Synthesis gas from the methanation area is compressed by
a steam driven centrifugal compressor from 225 psia to 600 psia.
The compressed gas is cooled to 90°F and sent to gas purification
for final acid gas removal and dehydration. Gas from the
gas purification area is returned to the second stage centrifugal
compressor where it is boosted to pipeline pressure.
43
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D. Low Btu Gas-From-Coal (MWK Dwg. P3357-D)
A block flow diagram for the low Btu gas-from-coal process
is given in the .cited drawing. The air blown gasification process
is adopted from Lurgi's design.
Coal is conveyed from the coal preparation area to coal
bunkers located above the coal gasifiers. Coal is fed to the
gasifiers through coal locks which are pressured by a slip stream
of the raw gas. Hot compressed air and process steam is mixed
and introduced into the gasifiers. Ash is removed at the bottom
of the gasifiers through ash locks and transported to ash disposal.
Hot raw gas leaving the gasifiers is cooled by quenching with
a gas liquor spray in wash coolers. Raw gas from the wash cooler
is further cooled and cleaned by gas liquor in wash scrubbers.
A purge stream of gas liquor is sent to the phenol recovery section.
After cooling, the gas liquor is flashed to atmospheric pressure
in an expansion vessel to remove dissolved gases. Coal tar is
separated from the gas liquor by gravity and sent to product
storage. A portion of the clarified gas liquor is recycled to
the wash scrubber as make-up. The remainder is sent to
phenol recovery where dissolved ammonia and phenol will be
removed.
Expansion gas and coal lock vent gas are compressed and com-
bined with the raw gas. Desulfurization of raw gas is accomplished
by a hot potassium carbonate system in which hydrogen sulfide
and the bulk of carbon dioxide are removed. Acid gas from the
regenerator is cooled and sent to the sulfur recovery section.
Part of the fuel gas produced is sent to steam and power generation
section for process requirement. The remainder of the fuel
gas is transmitted to pipeline as primary product.
48
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V. Discussion of Results and Recommendations
Using the specific processes shown in this report,gasoline,
methanol, substitute natural gas and low Btu gas can be manu-
factured from coal via a SASOL-type plant which utilizes Lurgi
air- and oxygen-blown gasification processes.
Cost ($/MMBtu) of manufacturing such products decreases in
the following manner:
Gasoline > methanol > SNG > Low Btu Gas
Incidentally, the order shown also represents the degree of
flexibility of these products. Gasoline and methanol being in
liquid form are less expensive for transportation and storage.
Gasoline having a higher heating value is a superior product
because it is the only proven and widely used automotive fuel
and has a greater market demand than methanol. SNG in turn
is superior to low Btu gas because it can be transported as
pipeline quality gas whereas low Btu gas cannot be transported
long distances and its use is therefore restricted to close-
coupled plants (e.g., utility boilers).
With respect to the technology involved, gasoline-from-
coal plant has been operated commercially by SASOL for more
than twenty years. At present a SNG-from-coal facility using
Lurgi air-and oxygen-blown gasification processes is yet to be
built. Although several are in design stages, large-scale methanol
from coal plants are only in planning discussion. Thus, the
technology of gasoline-from-coal is ahead of the other coal
conversion processes in that a commercial plant is in operation.
Methanol unquestionably can be manufactured from coal cheaper
than gasoline; however, the applicability of methanol as a fuel
should be explored carefully. Studies have shown that a methanol-
gasoline mixture of up to 10% methanol by volume burns more
efficiently than gasoline in automobiles and the emissions of
unburned hydrocarbons, carbon monoxides,nitrogen oxides are
52
-------
reduced drastically (5). In view of the current U.S. crude
shortage of about 8%, methanol can be explored as an additive
to gasoline provided the conversion cost of the engine for
burning gasoline-methanol mixture is insignificant. Alternatively,
the best use of methanol may be to displace fuel oil and natural
gas from utility and industrial boilers. The fuel oil thus
displaced could be converted to gasoline.
SNG or low Btu gas can be produced cheaper than gasoline
or methanol. However, either SNG or low Btu gas is basically
a different form of fuel and has a different applicability
than gasoline and methanol. Direct comparison of the costs
should only be made after one establishes usefulness of the
products as well as market demand.
It should be noted that both this report and Task 13 Prelim-
inarly Report did not include any optimization studies because
of the limited scope of the task. For example, when the desired
end product is SNG or low Btu gas, Lurgi gasification technology
is probably the best. For gasoline-or methanol-from-coal plant
where methane is an undesirable product in the raw gas synthesis,
however, the use of other gasification processes such as Kopper-
Totzek gasification unit (which produces practically negligible
methane) should be investigated for possible savings.
The use of fuel gas from coal gasification for steam and power
generation is undesirable if low sulfur coal can be burned
directly for this purpose. If high sulfur fuels are used for
auxiliary steam and power generation, installation of a stack
gas scrubbing unit may be required.
Production of a singular specialized product may not be the
best utilization of the SASOL-type process as reflected by SASOL
facility which includes the manufacture of a wide spectrum of
chemicals, plastics, oil, gas and fertilizers.
53
-------
In any event, the cost of manufacturing gasoline and methanol
from coal can be lowered by proper optimization of the process.
The gasoline-from-coal plant via a SASOL-type process merits a
much more detailed optimization study since it is the only
available gasoline-from-coal technology today. Such study should
include the latest operating technique of the SASOL plant as well
as the Synthol process by M.W. Kellogg.
The costs presented in this report should be considered
as having budget type accuracy. Also, the values presented
in the appendices for coal cost, hourly wage, interest rate,
etc., are assumed to be typical for a general evaluation but
would need to be refined for a specific application. Figure 5
presents the cost of the products for various coal costs as
well as the sensitivity of on-stream factors on the low Btu
gas cost.
The basis of the modified Panhandle Eastern accounting
procedure used in deriving the cost figures is given in Appendix
E. This short cut method is intended to be used for the financ-
ing of utility plant and may not be appropriate for the gasoline-
or methanol-from-coal plants, both of which are of chemical and
refinery type operation. In the absence of a comparative
accounting procedure for chemical and refinery plant, the modi-
fied Panhandle Eastern accounting procedure is used throughout
the report to generate compatible production costs of gasoline
and methanol. An estimated incremental increase of 1% in
the fixed total capital charge will raise the unit gasoline
and methanol costs by 5% (with by-product credits). For example,
using a sinking fund method with a 15 year plant life, the
fixed capital charge including depreciation, interim re-
placements, insurance, tax and cost of capital is 18.22% (6).
The resulting gasoline and methanol unit costs will be $4.05/
MMBtu and $2.34/MMBtu respectively, corresponding to an increase
54
-------
of about 30% over the previous prices derived from the modified
Panhandle Eastern accounting procedure. An estimated incremental
increase of 1% in the fixed total capital charge will raise the
unit SNG cost by 5% and unit low Btu gas by 4% (with by-product
credits). Using the same sinking fund method, the unit SNG and
low Btu gas costs will be $1.50/MMBtu and $1.10/MMBtu respectively,
55
-------
FIGURE 5: EFFECT OF COAL PRICE ON THE PRODUCTION
COST OF GASOLINE, METHANOL, SNG & LOW
BTU GAS
Mine-Mouth Coal Cost
On-Stream Factor = 0.9
For Gasoline, Methanol & SNG
p
EH
O
H
EH
U
D
a
s
CU
tt
O
CO
O
U
Low Btu Gas
On-Stream
Factor
4 —
1 —
2 —
10
11 12
COAL PRICE AT $/TON
1. Maximize gasoline production by including
the conversion of tar, oil, naphtha
56
-------
VI. Reference
"Gasoline From Coal via Synthol Process", Task No. 13
Preliminary Report, submitted to Environmental Protection
Agency by M.W. Kellogg Company, Research and Engineering
Development, January 1974 (unpublished internal report).
Govaarts, J. H., and Schutte, C. W. (SASOL), "The
Use of Low Grade Coal for the Production of Oil, Gas,
Fertilizers and Chemicals," Eigth World Energy
Conference, Bucharest, June 28-July 2, 1971,
paper No. 3.3-187.
El Paso Natural Gas Company application to Federal
Power Commission for Burnham Coal Gasification Complex
in New Mexico, November 7, 1972.
"The Supply - Technical Advisory Task Force - Synthetic
Gas - Coal", Final Report, April 1973.
Reed, T. B., and R. M. Lomer, Science, Volume 182,
December 28, 1973, Number 4119.
"Evaluation of SC>2-Control Process", Task No. 5
Final Report, submitted to Environmental Protection
Agency, Office of Air Programs, Division of Control
Systems by M. W. Kellogg Co., Contract No. CPA 70-68.
October 15, 1971.
"Steam-Electric Plant Factors", 1973 Edition, National
Coal Association, Washington, D.C.
57
-------
Appendix A
Gasoline-From-Coal Via Synthol Process
Total Capital Requirement
1975 M$
Total Direct & Indirect Cost of Plant
(Incl. Contractor & Eng. Fees,
Tax & Licenses) 505,000
Contingency 47,000
Total Plant Investment 552,000
Interest During Construction
Interest Rate (9.0%) x Total
Plant Investment x 1.875 years average
period 93,000
Plant Start-Up Cost
40% of Operating Cost for 1/2 year 9,000
Working Capital M$
Coal @ $3.60/ton** (64 day supply) 7,900
Catalyst & Chemicals (60 day supply) 1,000
Receivables less Payable (1/24 of
Annual Revenue from Gasoline
@ $3.05/MMBtu) 5,200
Total Working Capital 14,000
Total Capital Requirement 668,000
**Mine-Mouth Coal Cost.
This figure is taken from the average coal cost in New Mexico
as reported by Steam-Electric Plant Factors, 1973 Edition,
National Coal Association with escalation of 10% per year
to 1975.
59
-------
Appendix A (Cont'd.)
Gasoline-From-Coal Via Synthol Process
Annual Operating Cost
On-stream factor = 0.9
1975, M$/year
1. Raw Materials
Coal @ $3.60/ton 40,000
2. Purchased Utilities
Power
Raw Water 500
3. Labor
A. Operating Labor @ $8/hr 10,800
B. Maintenance Labor (1.5% of Total
Plant Investment) 8,300
C. Supervision (0.15 of A + B) 2,900
4. Supplies
A. Operating Catalyst & Chemicals 8,000
B. Maintenance (1.5% of Total Plant
Investment) 8,300
5. Administration & General Overheads
60% of Total Labor Including Supervision 13,200
6. Tax & Insurance at 2.7% of Total
Plant Investment 15,000
7. Total Operating Cost (Without By-Product
Credits) 107,000
60
-------
Appendix A (Cont'd.)
Gasoline-From-Coal Via Synthol Process
Annual Operating Cost
On-stream factor = 0.9
8. By-Product Credits
A. Tar, Oil, Naphtha
B. Phenols
C. Ammonia
D. Sulfur
E. Higher Alcohols
F. Acetone
G. M.E.K.
H. Diesel Oil
I. Waxy Oil
J. LPG
($8/Barrel)
($70/Ton)
($50/Ton)
($10/LT)
($100/Ton)
($150/Ton)
($200/Ton)
($10.5/Barrel)
($7.5/Barrel)
($6.5/Barrel)
Total By-Product Credit
MS/Yr. 1975, M$/Year
34,770
3,770
5,670
480
3,040
1,570
530
4,250
2,280
4,270
60,600
Net Operating Cost
(With By-Product Credit)
46 ,400
61
-------
Unit Costs Base Case
10. Gasoline Cost (with By-product Credits)
A. $/MMBtu 3.05
B. $/Barrel 15.11
11. Gasoline Cost (without By-product Credits)
A. $/MMBtu 4.55
B. $/Barrel 22.52
Unit Costs Alternate Case
12. Gasoline Cost (with By-product Credits)
A. $/MMBtu 2.76
B. $/Barrel 13.70
62
-------
Appendix A (Cont'd.)
Gasoline-From-Coal Cost
For 20 year Average Price
Without Escalation (Based on
Shortcut Method on Panhandle
Eastern Accounting Procedure)**
Gasoline Cost
= (Net Operating Cost + 0.1198 x Total Capital
Requirement + 0.0198 x Working CapitaD/Gasoline Production
Gasoline Production
= 41.5 x 106 MMBtu/Year (8.375 MM Barrels)
Gasoline Cost = 46.4 + 0.1198 x 668 + 0.0198 x 14
41.5
= $3.05/MMBtu (with By-Product Credits)
= $15.11/Barrel (with By-Product Credits)
Gasoline Cost = 107 + 0.1198x680 + 0.0198 x 14
41.5
= $4.55/MMBtu (Without By-Product Credits)
= $22.52/Barrel (Without By-Product Credits)
**Final Report of the Supply-Technical Advisory Task Force
Synthetic Gas From Coal, April, 1973
63
-------
Appendix A (Cont'd.)
Alternate Gasoline-From-Coal Cost
(By Further Processing the Tar
Oil, Naphtha to Gasoline Product)
Gasoline Production = 25495 + 13230 x 0.8 BPD
= 11.85 x 106 MM Barrel/Year
= 58.7 x 106 MMBtu/Year
Annual Operating Cost (Deletion of Tar, Oil, Naphtha By-Product
Credits)
= $81.2 Million/Year
Total Capital Required - $552 + $93 + $16 + $14 Million
= $675 Million
Alternate Gasoline Cost = 81.2 + 675 x 0.1198 + $14 x 0.0198
58.7
= $2.76/MMBtu (With Byproduct Credits)
= $13.70/Barrel (With Byproduct Credits)
64
-------
Appendix B
Methanol-From-Coal
Total Capital Requirement
1975, M$
Total Directs Indirect Cost of Plant
(Incl. Contractor & Engr. Fees
Tax & Licenses) 472,000
Contingency 42,OOP
Total Plant Investment 514,000
Interest During Construction
Interest Rate (9.0%) x Total Plant
Investment x 1.875 Average Year Period 87,000
Plant Start-Up Cost
40% of Operating Cost for 1/2 year 11,000
Working Capital A* M$
Coal @ $3.60/ton (64 days supply) 7,320
Catalyst & Chemical (60 days supply) 800
Receivables Less Payable (1/24 of
annual Revenue from Methanol
@$1.80/MMBtu 5,460
Total Working Capital 14,000
Total Capital Requirement 626,000
** Mine-Mouth Coal Cost. This figure is taken from the average
coal cost in New Mexico as reported by Steam-Electric Plant
Factors, 1973 Edition, National Coal Association with escalation
of 10% per year to 1975.
65
-------
Appendix B (Cont'd.)
Methanol-From-Coal
Annual Operating Cost
On Stream Factor = 0.9
1975, M$/Yr.
1. Raw Materials
Coal at $3.60/ton 37,600
2. Purchased Utilities
Power
Water 400
3. Labor
A. Operating Labor at $8/hr 10,800
B. Maintenance Labor (15% of Total Plant
Investment) 7,700
C. Supervision (0.15 of A+B) 2,800
4. Supplies
A. Operating Catalyst & Chemicals 6,000
B. Maintenance (1.5% of Total Plant Investment) 7,700
5. Administration & General Overheads
60% of Labor Including Supervision 12,800
6. Tax & Insurance at 2.7% of Total Plant
Investment 13,900
7. Total Operating Cost (Without By-Product
Credits) 99,700
8. By-Product Credits M$/Yr
A. Tar Oil, Naphtha ($8/barrel)32,500
B. Phenols ($70/ton) 3,600
C. Ammonia ($50/ton) 5,400
D. Sulfur ($10/LT 400
E. Higher Alcohols ($100/ton) 1,900
Total By-Product Credits 43,800
9. Total Net Operating Cost 55,900
66
-------
Unit Costs
10. Methanol Cost (with By-product Credits)
A. $/MMBtu 1.80
B. $/Barrel 4.90
11. Methanol Cost (without By-product Credits)
A. $/MMBtu 2.42
B. $/Barrel 6.58
67
-------
Appendix B (Cont'd.)
Methanol-From-Coal Cost
For 20 year average price without escalation
(Based on Shortcut Method on Panhandle
Eastern Accounting Procedure)
Cost of Methanol
(Net Operating Cost + 0.1198 x Total Capital
Requirement + 0.0198 x Working Capital)
Methanol Production
Methanol Production
= 72.75 x 106 MMBtu/year (26.75 MMBarrels)
Cost of Methanol
_ 55.9 + 0.1198 x 626 + 0.0198 x 14
72.75
= $1.80/MMBtu (With By-product Credits)
$4.90/Barrel (With By-Product Credits)
Cost of Methanol
_ 99.7 + 0.1198 x 635 + 0.0198 x 14
72.75
= $2.42/MMBtu (Without By-Product Credit)
$6.58/Barrel (Without By-Product Credit)
68
-------
Appendix C
Substitute Natural Gas Production
Total Capital Requirement
1975,M$
Total Direct & indirect Cost of Plant
(Incl. Contractor & Engr. Fees,
Tax & Licenses) 365,000
Contingency 34,000
Total Plant Investment 399,000
Interest During Construction
(Interest Rate (9.0%) x Total Plant
Investment x 1.875 years average period) 67,000
Plant Start-up Cost
40% of Operating Cost for 1/2 year 7,000
Working Capital **
Coal @ 3.60/ton (64 day supply) 6,150
Catalyst & Chemicals (60 days supply) 500
Receivables Less Payables - 1/24 of
annual revenue at $1.13/MMBtu) 3,900
Total Working Capital 11,500
Total Capital Requirement 484,000
** Mine-Mouth Coal Cost. This figure is taken from the average
coal cost in New Mexico as reported by Steam-Electric Plant
Factors, 1973 Edition, National Coal Association with escalation
of 10% per year to 1975.
69
-------
Appendix C (Cont'd.)
SNG Annual Operating Cost
Stream Factor =0.9
1975, M$/year
1. Raw Material
Coal at $3.60/ton 31,590
2. Purchased Utilities
Power @ 0.8C/KWH
Raw Water 300
3. Labor
A. Operating Labor at $8.00/hr 5,980
B. Maintenance Labor (1.5% of total
plant investment) 5,990
C. Supervision (15% of A + B) 1,780
4. Supplies
A. Operating Catalyst & Chemicals 3,000
B. Maintenance @ 1.5% of Total Plant
Investment 5,990
5. Administration & General Overhead
60% of total labor including supervision 8,250
6. Taxes & Insurance at 2.7% of total
Plant Investment per Year 10,773
7. Total Operating Cost (Without By-Product
Credits) 73,650
8. By-Product Credits
M$/Yr.
A. Tar, Oil, Naphtha ($8/Barrel) 31,960
B. Crude Phenols ($70/ton) 2,880
C. Ammonia ($50/ton) 3,420
D. Sulfur ($10/LT) 440
Total By-Product Credit 38,700
9. Net Annual Operating Cost 35,000
70
-------
Unit Costs
10. Substitute Natural Gas (with By-Product Credits)
A. $/MMBtu 1.13
11. Substitute Natural Gas (without By-Product Credits)
A. $/MMBtu 1.60
71
-------
Appendix C (Cont'd.)
SNG Gas Cost
For 20-year Average Gas Price Without
Escalation (Based on Short-Cut
Method on Panhandle Eastern Accounting
Procedure)
Gas Price
(Net Operating Cost + 0.1198 x Total
Capital Requirement + 0.0198 x
Working Capital)/ Gas Production
Gas Production
= 82.4 x 106 MMBtu/year
Gas Price
= 35.0 + 0.1198 x 484.0 + 0.0198 x 11.0
82.4
= $1.13/MMBtu (With By-Product Credit)
Gas Price
= 73.650 + 0.1198 x 494.0 + 0.0198 x 11.0
82.4
$1.60/MMBtu (Without By-Product Credit)
72
-------
Appendix D
Low Btu Gas Production
Total Capital Requirement
1975, M$
Total Direct & Indirect Cost of Plant
(Incl. Contractor & Engr. Fees
Tax & Licenses) 218,000
Contingency 20,000
Total Plant Investment 238,000
Interest During Construction
(Interest Rate (9%) x Total Plant
Investment x 1.875 Years Average
Period) 40,000
Plant Start-Up Cost
40% of Operating Cost for 1/2 year 5,400
Working Capital ** _M$
Coal at $3.60/ton (64 day supply) 4,900
Catalyst and Chemicals (60 day supply) 300
Receivable Less Payable (1/24 of
Annual Revenue at $0.8/MMBtu) 2,600
Total Working Capital 7,800
Total Capital Requirement 291,000
** Mine-Mouth Coal Cost. This figure is taken from the average
coal cost in New Mexico as reported by Steam-Electric Plant
Factors, 1973 Edition, National Coal Association with escalation
of 10% per year to 1975.
73
-------
Appendix D (Cont'd.)
Low Btu Gas Production
Annual Operating Cost
On Stream Factor = 0.9
1975M$/Year
1. Raw Materials
Coal at $3.60/ton
(Catalyst & Chemicals included with
supplies) 25,160
2. Purchased Utilities
Power
Raw Water 200
3. Labor
A. Operating Labor at $8/hr 3,990
B. Maintenance Labor at 1.5% of
Total Plant Investment 3,570
C. Supervision @ 15% of A+B 1,130
4. Supplies
A. Operating Catalyst & Chemicals 2,000
B. Maintenance @ 1.5% of total
plant investment 3,570
5. Administration & General Overhead
(60% of total Labor Including
Supervision) 5,210
6. Tax & Insurance at 2.7% of
Total Plant Investment per year 6,430
7. Total Operating Cost (Without
By-Product Credits) 51,260
8. By-Product Credits M$/Yr.
A. Tar, Oil, Naphtha ($8/barrel)18,880
B. Crude Phenols ($70/ton) 2,300
C. Ammonia ($30/ton) 2,710
D. Sulfur ($10/LT) 350
Total By-Product Credit 24,240
9. Net Annual Operating Cost 27,000
74
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Unit Cost
10. Low Btu Gas (with By-Product Credits)
A. $/MMBtu 0.86
11. Low Btu Gas (without By-Product Credits)
A. $/MMBtu 1.20
75
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Low Btu Gas Production
Gas Cost
For 20-year Average Gas Price Without
Escalation (Based on Short-Cut
Method on Panhandle Eastern Accounting
Procedure)
Gas Price = (Net Operating Cost + 0.1198 x
Total Capital Requirement +
0.0198 x Working Capital)/Gas Production
Gas Production = 72.5 x 106 MMBtu
Gas Price = (27 + 0.1198 x 291 + 0.0198 x 7.8)
72.5
= $0.86/MMBtu (With By-Product Credits)
Gas Price = (51.26 + 0.1198 x 296 + 0.0198 x 7.8)
72.5
= $1.20/MMBtu (Without By-Product Credit)
76
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Appendix D (Cont'd.)
Low Btu Gas Production
Annual Operating Cost
Alternate Case with On Stream Factor =0.7
1975M$/Year
Raw Materials
Coal at $3.60/ton
(Catalyst & Chemicals included with supplies) 19,570
P ur c ha s e d _ut.i li ti es^
Power
Raw Water 200
Labor
A. Operating Labor at $8/hr 3,990
B. Maintenance Labor at 1.5% of
Total Plant Investment 3,570
C. Supervision § 15% of A+B 1,130
Supplies
A. Operating Catalyst & Chemicals 2,000
B. Maintenance @ 1.5% of total
plant investment 3,570
Administration & General Overhead
(60% of total Labor Including
Supervision) 5,210
Tax & Insurance at 2.7% of
Total Plant Investment per year 6,430
7. Total Operating Cost (Without
By-Product Credits) 45,670
8. By-Product Credits M$/Yr.
A. Tar, Oil, Naphtha ($8/barrel) 14,700
B. Crude Phenols ($70/ton) 1,800
C. Ammonia ($30/ton) 2,100
D. Sulfur ($10/LT) 300
Total By-Product Credit 18,900
9. Net Annual Operating Cost 26,800
77
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Unit Cost
10. Low Btu Gas (with By-Product Credits)
A. $/MMBtu 1.10
11. Low Btu Gas (without By-Product Credits)
A. $/MMBtu 1.44
78
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Low Btu Gas Production
Gas Cost
Alternate Case with On Stream Factor = 0.70
For 20-year Average Gas Price Without
Escalation (Based on Short-Cut
Method on Panhandle Eastern Accounting
Procedure)
Gas Price = (Net Operating Cost + 0.1198 x
Total Capital Requirement +
0.0198 x Working Capital) /Gas Production
Gas Production = 56.4 x 106 MMBtu
Gas Price = (26.8 + 0.1198 x 291 + 0.0198 x 7.8)
= $1.10/MMBtu (with By-Product Credits)
Gas Price = (45.67 + 0.1198 x 296 + 0.0198 x 7.8)
1T&73
= $1.44/MMBtu (without By-Product Credit)
79
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Appendix E
Description of the Panhandle
Eastern Accounting Procedures**
Basis :
• 20-year project life
• 5% straight line depreciation on Total Capital Requirement
excluding Working Capital
• 48% federal income tax rate
• Debt/equit ratio of 75%/25%
• 9% percent interest on debt
• 15% percent return on equity
Derived Parameters ;
• Rate Base = Total Capital Requirement less Accrued Depreciation
(includes 1/2 depreciation for given year)
• Percent Return on Rate Base = Fraction Debt x Percent Interest
+ Fraction Equity x Percent Return on Equity
Cash Flows in Given Year:
• Return on Rate Base = Rate Base x (Percent Return on Rate
Base T 100)
• Return on Equity = (Fraction Equity x Rate Base) x (Percent
Return on Equity v 100)
• Federal Income Tax = Return on Equity x (Percent Tax Rate
r [100 - Percent Tax Rate])
• Depreciation = 0.05 x (Total Capital Requirement - Working
Capital)
• Total Revenue Requirement in Given Year =
Return on Rate Base + Federal Income Tax
+ Depreciation + Total Net Operating Cost
** Final Report of the Supply-Technical Advisory Force - Synthetic
Gas From Coal, April, 1973
80
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Appendix E. (Cont'd.)
Costs of Production:
• In given year: Total Revenue Requirement f Annual Production
• 20-year average: Total Revenue Requirement Over Project
Life T (20 x Annual Production)
Derivation of General Cost Equation
Definition of Terms:
C - Total Capital Requirement, Million $
W = Working Capital, Million $
N = Total Net Operating Cost, Million $
12
G = Annual Production, 10 Btu/year
d = Fraction Debt
i = Percent Interest on Debt
r = Percent Return on Equity
p - Percent Return on Rate Base
n = Year, 1 to 20
RR = Total Revenue Requirement in n Year
Calculate Rate Base in n Year:
Depreciable Investment = C-W
Accrued Depreciation @ Mid-Point of Year = 0.05 (n-0.5) (c-W)
Rate Base = C - 0.05 (n-0. 5) (C-W)
Calulate Percent Return on Rate Base:
p - (d)i + (l-d)r
= 0.75x9 + 0.25x15
= 10.5
81
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Appendix E (Cont'd.)
Calculate Cash Flows in n Year:
Return on Rate Base = 0.01 p [C-0.05 (n-0. 5) (C-W) ]
Return on Equity = 0.01 r (1-d) [C- 0.05 (n-0. 5) (C-W) ]
Federal Income Tax = ^ 0.01 r (1-d)[C- 0.05(n-0.5)(C-W)]
Depreciation = 0.05(C-W)
Total Net Operation Cost = N (excluding escalation)
Total Revenue Requirement (RR ) =
0.01 p [C-0.05(n-0.5)(C-W)]
+i| 0.01 r (1-d) [C- 0.05(n-0.5)(C-W)]
+ 0. 05 (c-W) + N
RR = N + 0. 0 5 (c-W)
n 48
+ 0.01 [p+|J (1-d) r] [C-0. 0 5.(n-0. 5) (C-W) ]
•f- -L
Calculate Production Cost in n Year:
Gas Cost in nth Year = RR /G ($/MMBtu)
n
Calculate 20-Year Total Revenue Requirement (excluding escalation)
20
RRn =2 ON + (C-W)
n=l
+ 0.01 [p+~
-------
Appendix E (Cont'd.)
Calculate 20-Year Average Production Cost Without Escalation:
Average Production Cost
= Total RR /(20 X G)
48
= N + 0.05. JC-W) + 0.005 [P + 5T (1~d)r] (C+W)
= N + 0.05 (C-W) + 0.005 0-5 + 5T (0'25) (15 (C+W)
= N + 0.05 (C-W) + 0.0698 (C+W)
G
or
Average Production _ N_+ 0.1198 C + 0.0198 W
Cost ($/MMBtu) G
83
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1.HEPOHTNO. 2.
EPA-650/2-74-072
4. TITLE AND SUBTITLE
A SASOL-Type Process for Gasoline, Methanol SNG,
and Low-Btu Gas from Coal
7. AUTHOR(S)
F.K. Chan
9. PERFORMING ORGANIZATION NAME AND
The M. W. Kellogg Company
1300 Three Greenway Plaza
Houston, Texas 77046
12. SPONSORING AGENCY NAME AND ADDR
EPA, Office of Research and
NERC-RTP, Control Systems
Research Triangle Park, NC
ADDRESS
ESS
Development
Laboratory
27711
3. RECIPIENT'S ACCESSION'NO.
6. REPORT DATE
July 1974
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADE-010
(34)
11. CONTRACT/GRANT NO.
68-02-1308 (Task 13)
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16.ABSTRACT rpne repOr^ gjves results of a study to assess costs and feasibility of
manufacturing gasoline, methanol, SNG, and low-Btu gas from coal, using the SASOLr
type process. This process is based on a SASOL plant which has been operated
commercially for more than 20 years for the manufacture of gasoline, fertilizers,
and other chemicals from coal in South Africa. The SASOL plant has been modified
slightly to suit the product spectrum of the projected plants. Capital investments for
plants producing various end products are estimates based on published or in-house
information on a mine-mouth plant using Western U.S. coal. The capital investment
is expressed in 1S75 dollars with no forward escalation. The total capital requirement
and the unit production cost are based on a shortcut version of the Panhandle Eastern
Accounting Procedure, recommended for coal conversion facilities. The capital
investment, as well as the unit production cost, decreases as follows: gasoline >
methanol > SNG > low-Btu gas. The SASOL-type process utilizes Lurgi air- and
oxygen-blown gasification systems exclusively; comparison with other gasification
systems is not included.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Air Pollution
Cost Effectiveness
Coal Gasification
Fuels
Gasoline
Carbinols
18. DISTRIBUTION STATEMENT
Unlimited
b.lDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
Stationary Sources
SASOL-Type Process
Lurgi Process
Methanol
SNG
Low-Btu Gas
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This page)
Unclassified
c. COSATI Field/Group
13B
14A
13H
21D
07C
21. NO. OF
9
PAGES
3
22. PRICE
EPA Form 2220-1 (9-73)
84
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