THE HIGH SULFUR COMBUSTOR. -A STUDY OF SYSTEMS FOR COAL REFUSE
PROCESSING. VOLUME I. NARRATIVE SUMMARY
Chemical Construction Corporation
New York, New York
February 1971
NATIONAL TECHNICAL INFORMATION SERVICE
'to foster, serve and promote the
nation's economic development
and technological advancement.'
U.S. DEPARTMENT OF COMMERCE
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BIBLIOGRAPHIC DATA 1 K. pun N,,. |2. 3. IUc.pi. nt'
SHEET APTD-0768 I
Arc, „,„„.%•„.
4. lull jnd lubmle S. lUport D.iu
The High Sulfur Combustor _ _ February 1971
Volume One (Narrative Summary)
7. Author(s) 8. Performing
». Pcriorrmns Organ, zatJon Name and Address .') ^-~ 10. FtO|tcf I
Consulting Division 1 ~> ~ Li \
Organization Kept
ask-VSork Unit No.
320 Park Avenue '' ^ H. Contract Gram .No.
New York, New York 10022 cpA 22.69.151
Division of Process Control Engineeringv Covered
National Air Pollution Control Administration
Environmental Health Service
U. S. Department of Health, Education and Welfare 14.
Washington, D. C. 20201 *
-:-" ^ i '.-u-J
15. Supplementary Notes DISCLAIMER- This report was furnished to the Office ofVir
Programs by Consulting Division, Chemical Construction Corporation. 32*0
Park Avenue, New York. New York 10022 in fulfillment of CPA 22-69-151
\6. Abstracts - The pyritic sulfur content of some bituminous coals- can be reduced by
gravimetric separation or "washing". The extraction of energy and sulfur value contained
in the reject fractions is technically feasible. Under favorable conditions the sale of
extracted energy and sulfur products will to some degree offset the cost of washing.
The purpose of this study is to select, design, and evaluate the high sulfur combustor
and sulfur recovery process with the greatest potential for utilizing high-ash, high-
sulfur coal reject material produced by the deep cleaning of coal . The report therefore
includes preliminary des igns and evaluations of several combustion and flue gas treating
systems for processing high sulfur fuels drawn off from rejects of coal washing. These
fuels, will need to be made up £0 specifications that depend on; the requirements of
available processes for sulfur value recovery, and on the limitations of combustion
equipment in respect of ash. The "HSC** Fuel" specif ications can be satisfied, by ap-
propiately re- combining selected portions of reject material from deep cleaning of coal .
Four specimen HSC Fuel compositions are tabulated along with product and cost data on
six processing systems for these fuels.
17. Key ttorjs and Document Ana.\sl< 17a Descriptors
Air pollution Materials recovery
Desulfulfurization Sulfur i
Pyrite Energy
Coal Combustion chambers
Coal preparation Expenses
Washing Furnaces
Cleaning Electric power generation
Market value Sulfur dioxide
17b. Identities Open-End
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Consulting Division
Chemical Construction Corporation
320 Park Avf-nuc
\ew York, \ew \ork 10022
FOREWORD
THE HIGH SULFUR COMBUSTOR
A Study of Systems
for
Coal Refuse Processing
Chemical Construction Corporation with assistance from Foster
Wheeler Corporation, Monsanto Enviro-Chem Systems Inc. and
Ehasco Services, Inc., has conducted a study of processing
systems lor extracting energy and sulfur values from the refuse
of coal cleaning. This is the Final Report submitted in accordance
with Contract Xo. CPA 22-69-151 dated June 30, 1969 as amended
VOLUME ONE
(NARRATIVE SUMMARY)
FINAL REPORT
to
I) VISION OF PROCES- CONTROL ENGIXEEHING
NA'IIONAL AIR POLLUTION CONTROL ADM INISTRA TION
ENVIRONMENTAL HEALTH SERVICE
U.S. DEPARTMENT
of
HEALTH, EDUCATION and WE LI ARE
CONTRACT NO. CPA 22-69-151
Februarv 1971
The Report is bound in two volumes, of which Volume One (Parts
I through X) is essentially a summary for highlight purposes, and
Volume Two (Parts XI through XVII) in which most of the study
detail is compiled
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HIGH SUI.rUR COMBUSTOR STUDY
CONTENTS
VOLUMK ONE - NARRATIVE SUMMARY
PART I
ABSTRACT
INTRODUCTION I-1
1. CONTRACT OBJECTIVE
2. STATEMENT OF CONTRACT WORK 1-2
3. CRITERIA FOR PROCESS SELECTION 1-4
Table [-1 - Criteria for Process Classification 1-5
Table 1-2 - Factors for Ranking Sulfur Oxides
Removal Processes
4. GEOGRAPHIC CRITERIA 1-6
5. SITE CRITERIA 1-7
6. PRINCIPAL BACKGROUND LITERATURE 1-8
Figure 1-1 - Pyrite-Coal Program 1-9
7. ACKNOWLEDGMENTS AND DOCUMENTATION 1-10
PART II
COAL PREPARATION II-1
1. PRESENT PRACTICE
2. THE OCCURRENCE OF SULFUR IN COAL II-2
3. COMMERCIAL TECHNIQUES II-4
4. DEEP CI EANING II-5
5. DEVELOPMENT ACTIVITY II-6
5. 1 Current and Completed Studies
Figure II-1 - Pyritic Sulfur Reduction 11-9
Figure II-2 - Total Sulfur Reduction 11-10
6. FLEXIBILITY OF CLEANING METHODS 11-11
Figure II-3 - Flow Sheet for Concentrating
Table Tests 11-13
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Page
PART II
COAL PREPARATION (Continued)
Figure II-4 - Flow Sheet for Pyrite Beneficiation Tests 11-14
Figure II-5 - Pyrite Beneficiation Circuit 11-15
8.
Tables II- 1 through II-5 - Concentrating Table
Test Results
PROCESS CONTROL OF REJECT STREAMS
7. 1 Tailor-made HSC Fuels
VALUE OF HSC FUELS
PART III
BASE PARAMETERS
1. ENERGY EXTRACTION
1. 1 Sulfur/Carbon Ratio
Figure III-l - Combustion of Sulfur/Carbon
Mixtures in 25% Excess Air
1. 2 Heating Value of HSC Fuel
1. 3 Limits of Study
1.4 Three Process Systems Examined
1.4.1 through 1.4.5- Five Cases
Figure III-2 - Coal, Energy and Sulfur Products
1. 5 Product Balance
2. SULFUR VALUE
2. 1 Sulfuric Acid
2.2 Sulfur
2. 3 Magnesium Sulfite and Liquid Sulfur Dioxide
Figure III -3 - Consumption of Sulfur in the U. S.
2.4 Trade-Off Basis
11-17 thru
11-21
11-22
III-l
III-2
III-3
III-5 thru
III-6
III-7
III-8
III-9
111-10
III-ll
HI-12
PART IV
FIRING OF HSC i'Ul I S
1. FUEL COMPOSITIONS
1. 1 Whole Refuse Fraction
Table IX -1 - Whole Refuse Fraction from live
ROM Coals
1.2 Blending of Fractions
1. 3 Heat Value Yield and Non-Pyritic Ash
1.4 Ash Fusion Temperature
1 5 Four HSC Fuel Specifications
Figure IV-1 - Ash Softening Temperature Depending
on Basic Content of Coal Ash
Table IV-2 - HSC Fuel Composition CASE A
Table IV-3 - HSC Fuel Composition CASE B
Table IV-4 - HSC Fuel Composition CASE C and D
Table IV-5 - HSC Fuel Composition CASE E
2. FURNACE TYPES
2. 1 Roasting Equipment
2.2 Fluidized Bed Combusrors
Stoker F umaces
Grate Furnaces
Crusned Coal-Fired
Pulverized-F uel Fired
FURXACF LOAD REQUIREMENTS
3 1 ^team Design
3. 2 Service Factor
FURNACE SELEC I ION 1USIS
4. 1 Dry Bottom Suspension Combustion
IV-1
IV-2
IV-3
IV-4
IV-5
IV-6
IV-7
IV-8
IV-P
IV-10
IV-11
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PART IV (Continued)
FIRING OF HSC FUELS
5. COMBUSTION PROCESS DESIGN IV-13
Figure IV-2 - Combustion Process Flow Sheet IV-14
Table IV-6 - Expected HSC fuel-Fired
Combustor Performance
Figure IV-3 - Combustion Effects of Pyrite Mixtures
Table IV-7 - Summary of HSC Combustion Processes IV-16
6. INDUSTRIAL BOILER IV-17
6. 1 Vertical Firing
6. 2 Steam Characteristics
Figure IV-4 - 500, 000 LB/HR Industrial Type
High Sulfur Combustor,
Sectional Side Elevation IV-18
Figure IV-5 - Foster Wheeler Anthracite Burner IV-19
6.3 Energy Distribution IV-20
Figure IV-6 - Distribution of Energy in 500, 000
LB-'HR Boiler for CASE A IV-21
7. THE 50 MEGAWATT PROTOTYPE BOILER FOR
CASE C IV-22
7. 1 Horizontal Firing
7. 2 Steam Characteristics
Figui-e-fY-7 - 5fl MW Prototype High Sulfur
Combustor, Sectional Side Elevation IV-23
Figure IV-8 - Horizontal Intervane Burner Equipped
for Pulverized Coa], fias and Oil Tiring IV-24
7 o Knergy Distribution [V-25
Figure IV-9 - Distribution of Fno-gv m the 50 MW
Boiler for CASE C IV-26
PART IV (Continued)
FIRING OF HSC FUELS
8. THE 500 MEGAWATT ELECTRIC UTILITY BOILER
8. 1 Horizontally Fired
8. 2 Steam Characteristics
Figure IV-10 - The 500 MW High Sulfur Combustor
Sectional Side Elevation
8. 3 Energy Distribution
Figure IV-11 - Distribution of Energy in the 500 MW
Boiler for CASE D
9. BOTTOM ASH AND FLY ASH
9. 1 Iron in Ash
Table IV-8 - Fly-Ash Collection Design Basis
PART V
ELECTRIC GENERATION
SIZING OF STEAM-ELECTRIC EQUIPMENT
CONVENTIONAL TURBINE CYCLE
CENTRAL STATION STEAM GENERATORS
Figure V-l - Pulverized HSC Fuel-Fired Steam /
Power Plant
Table V-l
- List of Central Station Steam
Generators
PART VI
SULFUR VALUE RECOVl.'H'i
1. FLUE GAS CLEANING
2. MARKETABLE END-PRODUCTS
3. STRONG CHEMISTRY WANTED
3. 1 High Sulfur \ nluo 1 leld
3.2 Adaptabilit\
3.3 Minimum Pollution Risk
IV-21
IV-28
IV-29
IV-30
IV-31
IV-32
V-l
V-3
V-4 thru
V-17
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PART VI (Continued)
SULFUR VALUE RECOVERY
4. AVAILABLE PROCESSES
4. 1 The "Contact" Process
4. 1. 1 Standard Process
4.1.2 The Cat-Ox Process
4.1 Other Sulfunc Acid Processes
4. 3 Concentration of Weak Gases to
Intermediate Levels
4.3.1 Remluft Process
4. 3. 2 Grillo Process
4. 3. 3 Magnesium Sulfite/Oxide Process
4. 4 Concentration of Weak Gases to High
(90/100M Level
4. 4. 1 .Aromatic Amme Absorbents
4.4.2 Basic Aluminum Sulfate
4.4.3 Thermal Cycle With Water
4. 4. 4 .Alkali-Metal Sulfite/Bisulfite
4. 5 Liquefaction of SO,
4. 6 Processes for Output of Elementary Sulfur
4. 6. 1
4. 6.2
4. 6. 3
4.64
46.5
Reduction of 100-~. SO,by Hot Coke
Reduction ol Dilute SO, with
Producer Gas
Reduction of SO9 with Methane
4. 6. 3. 1 Non-catalytic processes
4 6.3.2 Catalytic processes
Reduction of Dilute SO with
Reformed Natural Gas
Reduction of SO? with H,S
Page
VI-3
VI-4
VI-5
VI-6
VI -9
VI -10
VI -11
VI-12
VI-13
VI-14
VI-15
VI-16
VI-17
VI-18
VI-19
VI-20
PART VI (Continued)
SULFUR VALUE RECOVERY
5. EMISSION CONTROL
5. 1 Control of SO2 in Tail Gas
5. 2 Control of Ambient SO
5. 3 Control of Particulates
PART VII
SUMMARY OF HSC SYSTEMS
1. SUMMARY OF THE CASE A SYSTEM
Figure VII-1 - Summary Flov, SLee. C.nSE A
2. SUMMARY OF THE CASE B SYSTEM
Figure VII-2 - Summary Flow Sheet CASE B
3. SUAIMARY OF THE CASE C PROTOTYPE SYSTEM
Figure VII-3 - Summary Flow Sheet CASE C
4. SUMMARY OF THE CASE D SYSTEM
Figure VII-4 - Summary Flow Sheet CASE D
5. SUMMARY OF THE CASE E SYSTEM
Figure YII-5 - Summary Flow Sheet CASE E
PART VIII
ECONOMIC EVALUATION'
1 METHOD
1. 1 Valuation I ormula
1.2 Precombustion Costs vs Dumping
Page
VI-22
VII-1
VII-2
YII-3
VII-4
VII-5
VII-6
VII-7
vn-s
VII-9
VU-10
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PART VIII (Continued)
ECONOMIC EVALUATION
2. COSTS, PRICES AND ESCALATION VIIl-3
2. 1 Capital Costs
Table VIII-1 - Estimated Capital Cost
2.2 Costs of Operation or Extraction VIII-4
2.2.1 Utilities
2.2.2 Operating Labor and Supervision
2.2.3 Maintenance Cost VIII-5
2.2.4 Local Taxes, Insurance and the
Cost of Money
2.2.5 Depreciation VIII-5
2.2.6 Product Costing Basis VIII-6
Tables VIII-2 through VIII-6 - Estimated VIII-7 thru
Operating Costs of HSC Systems VIII-11
2.2.7 Pollution Control VIII-12
Table VIII-7 - Pollution Control as
Alternate to Sulfur Value Recovery VIII -13
2.3 Sales Value of Products VIII-14
2. 3. 1 Steam
2.3.2 Electricity VIII-15
2.3.3 Sulfur
Table VHI-8 - Sulfunc Acid - Estimated
Production and Shipments 1968 VIII-19
2.3.4 Sulfuric Acid VIII-20
2 3 4. 1 Major end-uses
2.3 4. 2 Sulfunc acid list prices VIII-24
Table VIII-8 - Sulfunc Acid -
Average price of Shipments
Table VIII-9 - Sulfuric Acid uses
in the United States VIII-27
PART VIII (Continued)
ECONOMIC EVALUATION
3. OPERATING ECONOMICS VIII-28
Table VIII-10 - Income from Sales, Costs of
Operation and Products, Gam
or Loss from Operation
4. VALUE OF HSC FUELC AND PAYOUT VIII-30
Table VIII-11 - Value of HSC Fuels, Offset
to Cleaning Cost, Payout of
Investment VIII-31
5. SHIPPING ECONOMICS VIII-32
5.1 End Product: Sulfuric Acid Delivered
3 2 Analysis of Sulfuric Acid Delivered Cost VIII-33
Figure VIII-1 - Linear Model for Analysis
of Production and Shipping
Economics
5.2.1 Input data: Production, Storage and
Transportation Costs VIII-34
Table VIII- 12 - Tabulation of Input Data
5.2.2 Solution favors CASE D3 and barge VIII-36
Table VIII-13 - Printout of Analysis
Table VIII-14 - Optimal Choice Index with
Barge VIII-3P
Table VIII-15 -Optimal Choice Index without
Barge VHI-41
6. CASE D VS. CASE D3 VIII-42
Table \ III-16 - D and D3 Capital and Operating
Costs and Gain Compared YUl-43
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PART IX
ABSTRACTS OF REFERENCE LITERA TURE
PART X
SUBJECT INDEX TO REFERENCE LITERATURE
Page
1 to 23
HIGH SULFUR COMBUSTOR STUDY
CONTENTS
VOLUME TWO - DESCRIPTIVE DETAIL
(Separately bound)
PART XI
FUEL SPECIFICATION AND COMBUSTOR DESIGN
(Foster Wheeler Corporation)
PART XII
ASH
PART XIII
CASE A SULFURIC ACID
Process Description
Process Flow Sheet
Summary of Capital and Operating Cost
PART XIV
CASE B SULFURIC ACID
Process Description
Process Flow Sheet
Summary of Capital and Operating Cost
PART XV
CASE C PROTOTPYE SULFUR
Process Description
Process Flow Sheet
Equipment List and Specification
Capital Cost Estimate
Summary of Capital and Operating Cost
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PART XVI
CASE D SULFUR
Process Description
Process Flow Sheet
Summary of Capital and Operating Cost
PART XVII
CASE E SULFURIC ACID
Process Description
Process Flow Sheet
Summary of Capital and Operating Cost
High Sulfur Combustor Study
ABSTRACT
The pyritic sulfur content of some bituminous coals can be reduced by
gravimetric separation or "washing". The extraction of energy and sulfur
value contained in the reject fractions is technically feasible. Under
favorable conditions the sale of extracted energy and sulfur products will
to some degree offset the cost of washing. The report includes preliminary
designs and evaluations of several combustion and flue gas treating
systems for processing high sulfur fuels that may be drawn off from the
rejects of coal washing. These fuels will need to be made up to specifica-
tions that depend first on the requirements of available processes for
sulfur value recovery, and second on the limitations of combustion
equipment in respect of ash. The "HSC" Fuel specifications can
evidently be satisfied by appropriately re-combining selected portions of
reject material from deep cleaning of coal. Four specimen HSC Fuel
compositions are tabulated on the following page together with product and
cost data on six processing systems for these fuels. The operating
context in each case is one of a number of typical site possibilities in
the bituminous coal-producing area comprised of Pennsylvania, Ohio,
West Virginia, Kentucky, Indiana and Illinois.
-------
Note "Cost" does nc
See PART VIII
In CASE A and
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8 8
ST OF ENERGY EXTRACTION
Steacn per M Lba
Electricity per MWH
ST OF SULFUR VALUE EXTRACTS
Sulfuric Acid per Net Ton
Sulfur per Lona Ton
S
M
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z c
TAL INVESTMENT IN HSC SYSTEMS
NUA L COST OF OPERA TION BEFOR I
C
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Forward estimates of selling prices of the four products are:
Steam per M Ibs
Electricity per KWH
Sulfur per LT
Sulfuric Acid per NT
0, 65
0.0075
25.00
12.75
If these prices prevail, the estimates of economic benefit, if any,
treated as credits to coal cleaning costs, are as shown below:
CASE A
M$
B
M$
Gam after Tax
1, 760
C
M$
420) (1. 960)
D
M$
D3
M$
Clean Coal:
M Ton/Year 7, 100 2, 300
920
E
M$
690 4, 700 4, 230
7, 100 7, 100 3, 500
Netback per Ton
of Clean Coal $0.25 ($0.18) ($2.13) $0.10 $0.66 $1,21
CASE C is intended for possible construction as a prototype or demonstra-
tion plant. The four other case studies, taken together, amount to a
preliminary exploration of the range of possible operating conditions. Any
specific coal cleaning situation will need to be examined in detail for
applicability of the high sulfur combustor idea. Washabilvty of the coal
and proximity to sulfuric acid consumers are shown to be major
determinants of the choice of technology and economic expectations. The
manufacture of sulfur for conversion after shipment to sulfuric acid
compares unfavorably with manufacture and shipment directly of sulfuric
acid unless very large tonnages are to be shipped long distances by rail
- 3 -
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THE HIGH SULFUR COMBUSTOR
I
INTRODUCTION
"The Division of Process Control Engineering of the National Air
Pollution Control Administration is developing processes for the
control of air pollution from stationary sources. A promising
technique for the control of sulfur dioxide pollution from coal-
burning installations is the removal of pyritic sulfur from the
coal prior to combustion. Although technology is available for
"deep" cleaning of coal for pyrite removal, the economics of
deep cleaning has prevented widespread use of the technology
for cleaning so-called "steam coals". Significant amounts of
carbon are lost in the reject material from the coal-cleaning
plant. A potential solution to the problem of carbon loss is the
utilization of mm high-ash, high-sulfur, carbon-bearing
reject material in a special combustor. The reject material
should have sufficient heat value for steam raising, and the
flue gas resulting from the combustion of the reject material
should contain a relatively high concentration of sulfur
compounds. Recovery of these compounds by the flue gas
processing would provide a useful and saleable product.
Feasibility studies conducted previously by NAPCA have
indicated that a high sulfur content in the flue gas may provide
the economic incentive for deep cleaning of steam coals. A
process that would produce sulfuric acid is only one of the
processes with potential value; another promising approach
would produce elemental sulfur.
I - 1
-------
2.
"Deep coal cleaning combined with utilization of reject materials
in a high-sulfur combustor with associated sulfur recovery
system needs to be evaluated. NAPCA has already underway a
program in which a prototype 500- to 1, 000-tpd coal-cleaning
plant will be built and a wide range of coals subjected to cleaning.
The economics and technical feasibility of the coal-cleaning
process will thus be established. Selection, design, and
evaluation of a high-sulfur combustor and by-product recovery
system needs to be accomplished to prove the economic
feasibility of deep cleaning of steam coals.
"The purpose of this study is to select, design, and evaluate the
high-sulfur combustor and .sulfur recovery process with the
greatest potential for utilizing high-ash, high-sulfur coal reject
material produced by the deep cleaning of coal. The economic
and technical feasibility of such a process will be established by
this study. "
STATEMENT OF CONTRACT WORK
2. 1 "Survey, analyze, select, and design a combustor system
that will utilize high-ash, high-sulfur, coal reject
material produced by the deep cleaning of coal as fuel
for the production of steam for power generation or
process use.
2. 2 "Select, analyze, and design a flue gas treatment process
that will recover sulfuric acid or sulfur from the SOg-
rich off-gases from the combustor. Primary considera-
tion should be given to commercial processes or those
I - 2
that are nearly commercial. In addition, recognition should
be given to marketability of sulfur products.
2. 3 "Determine those chemical and physical properties of the
reject materials that will influence the design of the
combustor system.
2. 4 "Establish the tests and procedures required to
characterize the reject material for use as a fuel.
2. 5 "Coordinate the efforts of the current NAPCA coal-cleaning
program with this proposed study. Specifically, correlate
with the Coal-cleaning program on those specifications of
the cleaning reject material that will make the material
usable as a fuel, and determine appropriate composition
ranges that are required and can be met by coal prepara-
tion techniques. In addition, recommend for the coal-
cleaning plant additional cleaning circuits that will result
in the production of a reject material of desired
composition.
2. 6 'Perform a conceptual design of a prototype plant and cost
estimate of the overall process, including coal cleaning,
the high-sulfur combustor for power/steam generation,
and the flue gas sulfur recovery system. Specifications
range of the reject material for use as a fuel will also
be established. The results of this task will provide the
basis for decision whether to build a high-sulfur
combustor and sulfur recovery prototype plant. Size of
prototype plant will be such as to demonstrate
commercial applicability.
I - 3
-------
2. 7 "A final task will be the extrapolation of data to conceptual
designs with cost estimates for full-scale industrial and
utility boilers (combustors), such as, a 500, 000 pounds
per hour (steam) industrial boiler and a 500-megawatt
utility station, both with sulfur recovery systems. "
3. CRITERIA FOR PROCESS SELECTION
Due attention has been paid to the emphasis in Item 2. 2 on the
selection of "commercial or nearly commercial processes"
to serve as many functions as possible of the combustor and
SO recovery systems under study. Such processes are
considered to be in the front rank of availability if otherwise
suitable for these systems. Where commercial processes
have appeared to be inaccessible •azu.rK>neJustent for some
functions of the systems, recourse has been had to processes
not yet commercialized. The selection of non-commercial
processes for analysis in this study has been guided by the
conception of diminishing "availability" in Table 1-1 and the
"ranking factors" of Table 1-2.
TABLE 1-1
"CRITERIA FOR PROCESS CLASSIFICATION
A. FIRST GENERATION
(1) Advanced pilot plant studies
(2) Active research and development
(3) Adaptability to U.S. market
(4) Available data on economic assessment
B. NEAR FIRST GENERATION
(1) General first generation criteria but:
(2) Less advanced pilot studies
(3) More interest and better adaptation by foreign nations
(4) Sulfur by-products not attractive to U.S. market
C. SECOND GENERATION
(1) Essentially bench studies
(2) Minimal pilot plant operations
(3) New concepts represented
(4) Process potential may exceed that of first generation
methods
(5) Economic assessment not yet practical"
(Ref. EE)
TABLE 1-2
'FACTORS FOR RANKING
SULFUR OXIDES REMOVAL PROCESSES
TECHNICAL FEASIBILITY
STATE OF DEVELOPMENT
PROCESS APPLICABILITY
RELATIVE ADVANTAGES
PROBLEM AREAS
ECONOMIC FACTORS"
I - 5
(Ref. EE)
I - 4
-------
3. 1 The clean coal and the energy and sulfur values extracted
from the reject material should be products of commercial
grade and realized in well balanced quantities so that none
of the three is outsize in terms of the market expected to
absorb it, or of too small a tonnage for good production
economy.
3. 2 Combustor design for steam-electric generation should be
conservative and for base-loading.
3. 3 Combustor design for 500, 000 pounds per hour of steam
output should be of industrial type with good turndown
characteristics.
3. 4 Processes for recovery of sulfur value should be capable
of high turndown ratios.
GEOGRAPHIC CRITERIA
Where necessary in this study for argument purposes to visualize
a high sulfur combustor system operating in a geographic
context, the frame of reference is the six-state area of
Pennsylvania, Ohio, West Virginia, Kentucky, Indiana and
Illinois. These states are the principal producers of steam
coal for electric utilities; they are also consumers of electric
energy in abundance, and moderate consumers of sulphuric acid.
The city of Cincinnati, roughly central to this area, has served
the study as a point of reference for certain shipping costs and
air pollution criteria.
5. At such a time as requires selection of an actual site on which to
locate a project of a type discussed in this study, consideration
may be given to:
5 1 The site of the mine expected to supply ROM coal. Such
a site might be preferred if, for example, coal cleaning
for sulfur reduction requires moderate crushing only so
that the low-sulfur clean coal is not too fine for shipping.
5. 2 The site of an existing electric utility complex to which
raw coal would be shipped and in which the cleaned coal
would be consumed.
5. 3 The site of a large chemical works, consumer of
steam and sulfuric acid, to which the special high
sulfur fuel would be shipped.
5. 4 A site on navigable water since water shipment of any
or all of the bulk coal and sulfur products will usually
yield an advantage.
It is especially to be noted that the coal processing systems discussed
in this report are all dependent on some degree of initial crushing and
grinding of the ROM. Since shipping of finely ground coal by rail in
open gondolas is costly as to loss by windage, the choice of
operating site may be consequently much influenced. There is
considerable evidence from current experimental work that
milling of coal to "pulverized coal" size prior to washing will in
most cases permit a greater sulfur reduction than can be effected
I - 6
I - 7
-------
ifP
on less finely milled coal. Where this is true of a particular coal
to be processed, a site in the first or second of the categories
above would seem to gain an advantage.
PRINCIPAL BACKGROUND LITERATURE
Several recent investigations in the coal cleaning arts, directed
particularly at reduction of pyritic sulfur and processing of the
high sulfur refuse, now underway or completed by the Bureau
of Mines, by others, and by private organizations under contract
to NAPCA, together with a number of subventions by NAPCA of
university research, represent a very substantial body of work
accomplished in support of continuing studies in this field. The
Program is illustrated in Figure I-1 following this page.
BECHTEL S
STANFORD
RES. INCT.
3
5-5
1 I
S m
%
o
o
o
TJ
10
O
O
S *
S
t__
Sc§
2*?
3 3) m
ss°
i?s
? s
"SS
2 n;S
"* 5 J2
,,Y
m
c:
p
g
I - 8
n
d
a
M
-------
7. ACKNOWLEDGMENTS AND DOCUMENTATION
Credits to published literature are entered in the text and
identified as follows:
In Volume One all referent abstracts are in Part IX.
In Volume Two, the reference material for the Foster
Wheeler report on fuels and combustors is included at
the end of that report in Part XI. The reference
material for the chapter on ASH, Part XII is listed at
the end of Part XII.
The work by Foster Wheeler Corporation was done under the
direction of R. W. Breyers.
I he contribution of Ebasco Services, Inc., was attended to by
P. J. Adams.
Messrs. Joseph G. Stites, Jr., and R. E. Zimmermann of
Monsanto Enviro-Chem Systems. Inc., prepared the Cat-Ox
study for CASES B and E.
John Beldmg of Chemical Construction Corporation, prime
contractor, was Project Director.
The National Air Pollution Control Administration was
represented by Mr. T. Kelly Janes and Mr. G.S. Haselberger,
Division of Process Control Engineering, who served the
project successively as Project Officers. Mr. R. P.Hangebrauck
of this Division was also especially interested and helpful.
Contributions of value have been made by many people not
mentioned by name.
The chapter on Coal Preparation, Part II, was reviewed for
factual content by Mr. A. W. Deurbrouck, U.S. Bureau of
Mines, and Mr. R. B. Saltsman, Bituminous Coal Research,
Inc.
I - 11
I - 10
-------
II
COAL PREPARATION
This term is applicable to any routine modification of a mined coal that
is intended to improve acceptance by the market or improve suitability
of the coal for a specific use. For the present purpose interest is
centered on modifications of coal that effect reduction of sulfur content
but questions of heat value yield, ash characteristics, sizing, etc.
are, of course, also involved.
1. PRESENT PRACTICE
Coal now supplied to utilities IB variously processed depending
on ROM characteristics and customers' requirements.
Emphasis on high heating value consistent with yield has followed
increased costs of shipping and stiffer competition from other
fuels. Coal "washing" to upgrade heat value has been practiced
many years, and to some degree elimination of the pyritic
source of ash (ferric oxide) has figured in this practice over a
long time.
But "Generally, coal preparation plants for cleaning steam
coals are not designed for maximum desulfurization. The
much smaller quantity of coal for metallurgical coke requires
lower sulfur limits. As a result, some of the steel companies
have developed some of the most efficient plants for desulfuriza-
tion", Ref. (B). Steam coal producers certainly have access to
most of the technology developed for ore dressing and metallurgi-
cal coal beneficiation, but applications to steam coal have been
limited by lack of economic incentive.
II - 1
-------
2. THE OCCURRENCE OF SULFUR IN COAL
"Sulfur occurs in coal in three principal forms: eulfate, organic,
and pyritic. The amount of sulfate sulfur in freshly mined coal
is normally small and of little significance. The organic sulfur
in coal is more or less uniformly distributed throughout the coal
substance in molecular combination, and cannot be removed even
partially without materially altering the nature of the coal
substance. The organic sulfur content of coal ranges from a low
of 20 per cent to a high of 60 per cent* of the total sulfur.
Obviously, the organic sulfur content of a coal is the prime
parameter in determining whether or not significant total sulfur
reductions can be made with a given coal by pyrite removal.
"Pyrite occurs in coal as discrete particles in a wide variety
of shapes and sizes.
"The principal forms are:
2. 1 Rounded masses called "sulfur balls" or nodules which
range in size from a small fraction of an inch to very
large.
2. 2 Lens-shaped masses which may be thought of as
flattened sulfur balls which vary greatly in thickness
and lateral extent.
2. 3 Veins of pyrite consisting of vertical or inclined veins
or fissures filled with pyrite ranging in thickness from
thin flakes up to several inches thick in some cases.
* Other observers report a high of 80 per cent.
H - 2
2.4 Small discontinuous veinlets of pvrite. a number of wh ich
sometimes radiate from a common center which may be
a small sulfur ball.
2. 5 Small particles or veinlets disseminated in the coal.+
"All coals contain forms . 3 and . 5, and some coals contain all five
of the principal forms.
"The total amount of pyritic sulfur varies greatly in different
coal beds, and also in different mines operating in the same coal
bed.
"Likewise, there is great variation in the size and shape of pyrite
inclusions in coals having a similar amount of total pyritic sulfur.
The degree of pyrite liberation at any given stage of crushing and
grinding also varies greatly among coals. With some coals, good
pyrite removal is obtained by merely washing the nominal sizes
produced in the mining operations, and little additional pyrite is
liberated by further size reductions. Other coals show some
pyrite liberation with each successive stage of reduction, while
still other coals show no significant pyrite liberation when they
are pulverized to conventional p. c. size (60 to 85 per cent
minus 200 mesh).
These fine particles range from a size easily viewed with the
naked eye to particles so small they they cannot be removed
without materially altering the nature of the coal substance.
Pulverized coal.
II - 3
-------
"These variations are directly related to the mode of occurrence
of the pyrite; this is the second important parameter in determin-
ing whether or not sulfur reductions are feasible through pyrite
removal. Coals which show little pyrite liberation when crushed
to their p.c. size are not amenable to sulfur reduction through
pyrite removal."
Ref. (KK) See also Ref. (N)
3. Some of the presently commercial coal processing techniques
are as follows:
3.1 "Modified Run of Mine Coal •
a) Large slate and large sulfur balls removed by hand
picking.
b) Large slate and large sulfur balls or large frag-
ments tbcxenf removed during the size-reduction
process utilizing a Bradford Breaker.
3. 2 "Full Cleaning
a) Low cost -wet cleaning of coarse sizes with a
Baum Jig and low cost dry cleaning of smaller
sizes with air tables.
b) More expensive but more efficient wet cleaning of
coarse sizes with heavy media separators and wet
fine coal cleaning on concentrating tables.
3. 3 "Partial Cleaning
a) Coarse or fine coal cleaning with cleaned fraction
being combined with the remainder m its run-of-
mine condition. " Ref (KK>
4. DEEP CLEANING
All of the processes mentioned will remove some of the liberated
pyritic sulfur, but it is a substantial removal of sulfur from the
cleaned coal that is needed for air pollution abatement, and a high
concentration of sulfur in the reject fractions that best serves the
combustor and recovery systems here visualized. This point of
view is implicit in the newly coined term "deep cleaning" (with a
connotation similar to "Full Cleaning" as in Item 3. 2 above) by
which, however, it is intended to identify processes directed at
reduction of sulfur particularly. While deep cleaning is a rather
new art, many of the techniques developed for beneficiation of
other minerals, as mentioned earlier, can be adapted to this
purpose. In addition to the float or sink separations in heavy
media vessels of several designs, and filmsizing on wet
,-.—icentrating tables, the techniques include ,
concentrators such as the Humphrey spiral, water cyclones,
air classifiers, etc. These and other devices, employed in
laboratory development studies, effect separations of crushed
ROM fractions by exploiting specific gravity differences which
are, for example:
Pyrite (FeS2>
Marcasite (FeS,,)
Slate
Bituminous Coal
Specific Gravity
5.00
4.87
2.5 to 2.8
1.2 to 1. 5
Froth flotation of coal fractions which does not depend on specific
gravity, is also a promising technique for certain purposes.
II - 4
II - 5
-------
5. DEVELOPMENT ACTIVITY
In recent years the Division of Process Control Engineering of
NAPCA has sponsored a major program of coal washability
studies directed at determining the supply of low sulfur coal
recoverable by deep cleaning. "Pyrite washability studies have
indicated significant potential for this air pollution control method.
Of coals from 250 mines tested to date, 35 percent have "organic
sulfur levels of 1. 0 percent or less and about half of the 35 per-
cent could easily be cleaned to 1 percent or less total sulfur.
An additional 25 percent of the coals have organic sulfur levels
of 1. 5 percent or less and of these about two-thirds could
readily be cleaned to 1. 5 percent total sulfur
5.1 "A list of studies completed or underway to determine the
availability of washable coals and to develop a coal-
cleaning and pyrite utilization process follows:
Feasibility Study of the Recovery of Sulfur and Iron From
Coal Pyrites PB 176-844 Ref. (C)
An Economic Feasibility Study of Coal Desulfurization
(Contractor: Paul Weir Company)
Vol. I, PB 176-845; Vol. II, PB 176-846 Ref. (E)
Occurrence and Removal of Pyritic Sulfur from
American Coals
(U.S. Bureau of Mines)
Removal of Pyritic Coal in a Humphrey Spiral of
Conventional and Modified Design
(U.S. Bureau of Mines)
II - 6
Removal of Pyrite from Coal by Tabling
(U.S. Bureau of Mines)
Field Studies of Coal Cleaning Equipment
(U. S. Bureau of Mines)
Desulfurization of Coal by Froth Flotation
(U. S. Bureau of Mines)
Detailed Coal Analyses
(U.S. Bureau of Mines)
Electrokinetic Separation of Pyrite from Coal
(U.S. Bureau of Mines)
Characteristics and Removal of Pyritic Sulfur from American
Coals
(U. S. Bureau of Mines)
An Evaluation of Coal Cleaning Methods and Techniques for
Removal of Pyritic Sulfur from Coal
(Contractor: Bituminous Coal Research)
PH-86-67-139 Ref. |JJ)
Sampling and Evaluation of Coal Mines in Illinois
(Contractor: Illinois Geological Survey)
See also Ref. (T)
Evaluation of Float-Sink Testing of Raw Coal Samples from
20 Mines Selected by the NAPCA
(Contractor: Commercial Testing and Engineering Company)
II - 7
-------
Sampling and Testing of Coals from Selected Mines
(Contractor: Commercial Testing and Engineering Company)
Process Cost and Economics of Pyrite-Coal Utilization
(Contractor: Bechtel Corporation)
Ref. (B)
Study of Process Costs and Economics of Pyrite-Coal
Utilization
(Contractor: A. D. Little, Inc.)
PB 182-303 Ref.
-------
FIGURE H- 2
8
o
t*.
i
100-|
90
80
70
60
50-
30-
20-
10-
CTECO 14 M«h x 0
Kit 30 Mesh x 0
•tECO 3/8 Inch x 100 Mtth
CTECO 1-1/2 Inch » 100
0-10 lOtjO IffM 3OiW 4C&O 50^60 tffO 7
-------
£1 - 11
more complex in the effort to maintain high yields, high heating
value and maximum rejection of sulfur.
For example, the wet concentrating table appears to be typically
versatile equipment. The table is a rhomboid plane surface
inclined a few degrees and riffled at right angles to the incline.
Crushed coal is introduced in a water slurry at an upper corner
while the table is mechanically vibrated to stimulate travel of
the coal. Low density particles tend to move directly down the
incline, high density particles tend to move parallel to the
riffles. Particles of intermediate density travel downward at
corresponding intermediate angles. The charge leaves the
table at the two edges opposite to the point of feed, see Figure
II-3. The particles are classified as to increasing order of
density all the way from lower left to upper right of the edges.
Selected portions of the streams leaving the table can be
diverted directly to shipment or to further processing by any
chosen method.
As earlier noted, the wet table is only one of the many devices
available to coal cleaners, but it well illustrates the potential
of flexibility in separation techniques based on specific gravity
differences. See, for example, Figure II-4, an experimental
arrangement of three tables in series for pyrite concentration,
or Figure II-5 in which concentrating tables, size classifiers
and size reduction mills are alternated in the flow sheet.
II - 12
•Q
5"
u>
I
1
«r
-------
FIGURE H-4
R.w R.O.M. Coal Cruthwf Flowsh«»t for Pyrif. Bwwficiation T«»t«, Mtat«> IV
•^ ^ /• :_~L u rt *
Hydraulic Cloffifivr in Syitcm
Ohio 1«9. 6 Sean, Colunbiana County,
Ohio BCR Sample No, 223lj
Pounds of Total Sulfur/Ton of
Run-of-Wne Coal
High Grade
Pyrrte
Pyrite Cotxentrftte
40 mwh » 0
BCR FORM 277
n-14
-------
si -n
T>
•<
31
ID
S
m
i
n
c-n
In Tables II-1 through II-5 are entered results of treatments
exerted on Sample 2234. Ohio No. 6 Seam. Note that the
sulfur concentration in a significant fraction exceeded 48%
(91% FeS.) in the run of 7-28-69, (rerun of Zone E from the
first tabling) while the precursor run of 7-1-69 captured 9. 5%
of the ROM in Zone E at more than 20% sulfur (38. 8% FeS2>.
BCR Lot No. 1820, from the same mine from which this
sample was taken, contained 2. 2% total sulfur (Ref. JJ -
p. A-120) of which pyritic sulfur accounted for 1. 8%. On
crushing to minus 30 mesh the pyrite liberation was excellent
since 86. 4% of the ROM floated at 1. 60 specific gravity and
contained only 0. 5% total sulfur. The sink amounted to 13. 6%
and contained 15. 1% sulfur corresponding to 28. 3% FeS2-
No doubt there are only a limited number of coals from which
pyritic sulfur can be so easily and completely separated as
from this Ohio No. 6 sample, but the deep cleaning
concept and a typical method of accomplishment are
sufficiently illustrated by this example.
* Ref (JJ)
II - 16
-------
TABLE II-1
TABLE II-2
Evaluation of Coal Cleaning Processes and Techniques
for Removing Pyritic Sulfur from Fine Coal
Concentrating Table Tests
Coal Identification Ohio
Raw Run-of-Mine
No. 6 Seam, Columbiana County, Ohio
Coal Crushed to
3/8 Inch x 0, Pyrite Precleanine
BCR Sample No. 2234
Table Products
Zone A
Zone B
Zone C
Float at 1. 60
Sink at 1.60
Composite
Zone D
Float at 1. 60
1. 60 x 2.95
Sink at 2.95
Composite
Zone E
Float at 2. 95
Sink at 2. 95
Composite
Composite of
Zones A, B, C
Composite of 1. 60
Float Fractions
Composite of 2. 95
Sink Fractions
Composite of
Table Products
Analysis of
Feed to Table
BCR Form No. 139R
10-69
6070
Product
Chemical Analysis, Dry
Basis, Weight Percent
Weight Float and Sink
Percent Weight Percent Ash
40.2
30.3
13.6
0.3
13.9
4.34
1.72
0.04
6. 1
5.9
3.6
9. 5
84.4
88.4
3.6
100.0
98.0
2.0
100.0
71.2
28.2
0.6
100.0
62. 1
37.9
100.0
6.50
6. 90
7. 68
45.4
8.43
15.8
44.4
63.4
24.22
63.9
61.4
64. 19
6. 96
7.27
61.42
13.45
14.8
Total Ultimate
Sulfur Carbon
0.76
0.88
0. 98
4.42
1.05
1.84
4. 60
26. 6
2.77
7.42
42.5
20. 72
0.85
0.89
42.33
2.86
3. 19
33. 5
41. 6
13. 9
35. 67
Run Date: 7-1-69
II - 17
Evaluation of Coal Cleaning Processes and Techniques
for Removing Pyritic Sulfur from Fine Coal
Concentrating Table No. 15-S Teats - Pyrite Beneficiation
Coal Identification Ohio No. 6 Seam, Columbiana County, Ohio
Zone D, 30 Mesh x 0 Run {7-28-69) Crushed to 60 Mesh x
0
BCR Sample No. 2234
Table Products
Zone A
Zone B
Zone C
Zone D
Zone E
Composite of
Table Products
Analysis of
Feed to Table
Product
Weight
Percent
36.3
15.0
7. 5
34.3
6.9
100.0
Chemical Analysis, Dry
Weieht Percent
Ash
72.4
72.8
73.2
71.2
65.4
71.63
72.40
Sulfur
17. 5
16.8
16.8
30.5*
48. 5
23.94
25,40
Basis,
Ultimate
Carbon
4.4
1.9
* Cut between Zones D and E should have favored zone D more
than it did.
BCR Form 172
Run Date: 8-21-69
II - 18
-------
TABLE II-3
Evaluation of Coal Cleaning Processes and Techniques
for Removing Pyritic Sulfur from Fine Coal
Concentrating Table No, 15-S Testa - Pyrite Beneficiation
TABLE fl-4
Coal Identification Ohio No. 6 Seam, Columbiana County. Ohio
Zone E, 3/8 Inch x 0 Run (7-1-69) Crushed to 30 Mesh x 0
Table Products
Zone A
Zone B
Zone C
Zone D
Zone E
Composite of
Table Products
Analysis of
Feed to Table
Product
Weight
Percent
52.9
3.2
0.5
29.2
14.2
100.0
BCR Sample No. 2234
Chemical Analysis, Dry Basis,
Weight Percent
Ash
52.2
71.6
69.6
72.4
64.4
60.54
64. 19
Total Ultimate
Sulfur Carbon
6.28
6.72
14. 10
25.40 5.4
48. 60 3. 9
17.93
20.72
BCR From 172
Evaluation of Coal Cleaning Processes and Techniques
for Removing Pyritic Sulfur from Fine Coal
Pyrite Beneficiation - Effects of Tvto-stage Cleaning
Coal Identification OHIO 110. 6. C01UMP.IAMA CCUKTY, OHIO
BCR Sample No
Pyrite Preeleanlng
Concentrating Table No. lit Test Run Date
Feed to Concentrating T«M«.- Rau Rur.-of-Mlr.p rjal rviiennri tn -lj^ Tn<-h if Q
Product, IChemlcal Analysis,I Dry Basis, Weight jt
Weight £ I Sih I Total Sulfur
Analysis of Feed to Table
Zone E (Pyrite Zone1!
100.0
-309_
20. 72
Pyrite Cleaning
Run Date
F"<»H to CoT10Aqt.rflt.ine TflM«»:&jr.e. ;,:, ~/~. roh v n ^-.;r . -1-rv.
}0 Mesh x 0
Analysis of Feed to Table
Zor.e E (Pyrite Zone)
Product,
Weight *
100.0
Chemical Anaivsis,
ASh
6~ 1.0
Concentrating Table No. 1S-S Test Run Date
\ rVM.crl.ui tr,
Dry Basic, Weight %
Total Sulfur
ao. '2
1*6.60
6 "1 (f,
Feed to Concentrating Table: 7xpne 0. ^0 ;-:esh x J Ru-. . -,>-6q) crushed to
bO Mesh x 0, Classifier Product
Run Date: 7-28-69
Analysis of Feed to Table
Zone E (Pyrite Zone)
Product,
Weight <
100.0
It .9
Chemical Analysis,
Ash
-l.'O
r6.3C
Dry Basis, Weight £
Total Sulfur
26.10
U6.?0
Two Stage Pyrite Product
Ii8.30
II - 19
BCR FORM 173
n- 20
-------
TABLE H-5
Evaluation of Coal Cleaning Processes and Techniques
for Removing Pyritic Sulfur from Fine Coal
Flowsheet Data for Pyrite Benefieiation Tests
Coal Identification: Ohio No. 6 Seam, Columbiana County, Ohio
BCR Sample No. 2234
Chemical Analysis, Dry Basis
Fraction
Model No. 14
Concentrating Table
Zone A
Zone B
Zone C
Zone D
Zone E
Model No. 15-s
Concentrating Table
Zone A
Zone B
Zone C
Zone D
Zone E
Model No. 15-s
Concentrating Table
Zone A
Zone B
Zone C
Zone D
Zone E
Composite of Fractions
Analysis of Feed Coal
Weight Percent
40.2
30.3
13.9
6. 1
9. 5
5.0
0. 3
0. 1
2.8
1.3
1.0
0. 4
0.2
1. 0
0.2
100.0
Ash
6. 50
6. 90
8.43
24.22
64. 19
52.2
71. 6
69. 6
72.4
64. 4
72.4
72. 8
73.2
71. 2
65.4
13. 09
14. 8
Weight Percent
Total Sulfur
0. 76
0.88
1.05
2. 77
20. 72
6.28
6. 72
14. 10
25.40
48. 60
17. 5
16. 8
16. 8
30. 5
48. 5
2. 54
3. 19
II - 21
7. PROCESS CONTROL OF REJECT STREAMS
It is clear that cleaning circuits such as illustrated in Figure
II-4 and II-5 can effect good separation of coal and liberated
pyrlte. This capability extends to circuits of other devices
and combinations of devices designed to bring about gravi-
metric separations. Both coal and pyrite can be separated
from liberated ash substances although less efficiently as specific
gravity differentials become smaller. From the technical point
of view, the key word is liberation *— which can be promoted, if
at all, only by size reduction (especially by crushing and grinding).
Refer again to Figure II-l in which summations of washing tests
on 70 samples show a clear improvement tendency in pyritic
sulfur reduction as a function of smaller sizing of the ROM.
7. 1 Thus, if size reduction will adequately liberate the
several fractions of a ROM, it is feasible:
a) To separate the fractions to recover a specifica-
tion coal low in pyritic sulfur, and
b) To recover pyritic fractions of low coal content,
and
c) By recombining b) with some of a) produce a high
sulfur fuel having a cortrolled ratio of pyritic
sulfur to coal, that is, a "tailor-made" or custom
specification fuel.
' 8. Thus, in general, any ROM coal containing pyritic sulfur
that can be processed to yield coal of lower sulfur content
I will yield at the same time a fuel of higher sulfur content
in which the sulfur/coal ratio can be controlled to any
specification within wide limits. This is the central
II - 22
-------
basis of fact in the present study. The remaining question
(limiting the point of view of the requirements of this study)
is the one of cost. Put another way, this question is:
What is the value of the fuel having the higher
sulfur to coal ratio?
But, no general answer to this question, such as would be
provided by a broad market, can be expected. The question
is meaningful only in a specific context in which the fuel is
processed and the energy and sulfur products sold.
Estimates of the value of such fuels, reflecting specific
processing and marketing assumptions, are included in Part
VIII of this study.
Ill
BASE PARAMETERS
ENERGY EXTRACTION
1. 1 The combustion in air (say 25% excess air which is a
parameter of the boiler designs discussed in Part IV and
in Volume Two) of a known mixture of sulfur and carbon
results in predictable sulfur dioxide concentration in the
combustion gas. For practical purposes this is also true
of known mixtures of sulfur and coal and of iron pyrtte
and coal when the composition of the coal is also known.
Figure III-l is a plot of the SCX concentrations to be
expected from combustion of sulfur/carbon mixtures in
the range S/C = 0. 02 to S/C = 6 by weight. The concen-
tration of SO from combustion of "organic sulfur" in
coal differs slightly from SO concentrations developed
from FeS2 (pyrite) combustion if conditions are otherwise
the same. The difference is the result of the consumption
of oxygen to form, in the latter instance, iron oxide ash
as well as SO.,. The SO concentrations can span the
— u
range from 0°1 for S/C = 0 to a little less than 13% for
S/C =oo(combustion of FeS0 in 25% excess air). The
Note that the use of the S/C ratio for this purpose avoids
the ambiguity of "percent sulfur in coal" which is
determinant of total sulfur but not of flue gas composition.
However, coal is not carbon and use of the S/C ratio
results in some minor inconsistencies herein.
II - 23
III - 1
-------
sulfuric acid. CASE A system will produce sulfuric acid only,
and only from a high S/C ratio fuel; CASE B and CASE E
systems function on lower S/C ratios but similarly are capable
of sulfuric acid output only. The technical options that are
suggested in Figure II1-2 are considered in more detail in
Part VI.
2.4 Trade-Off Basis
Since the object is to deliver sulfuric acid to a customer at
minimum cost the choice of process in any specific context
cannot be detached from the cost of shipment, the cost of
storage, etc. Both sulfur and sulfuric acid are high-lighted
in this study to establish a basis from which the particular
and specific situation can be judged. This a?-"-"-t.of the study
is put to a generalized analysis in Part VIII.
IV
FIRING OF USC FUELS
FUEL COMPOSITIONS
The development of the HSC Fuel Specifications is discussed in
Volume Two Part XI and summarized briefly here. First, it is
taken for granted that the specifications should be compatible
to whatever degree possible with optimum total yield of fuel
value from the cleaning plant. Second, however, the S/C ratio
of the HSC Fuel must be held to narrow limits to stabilize the
heating value of the fuel and to avoid penalizing the sulfur
recovery operation; and third, the non-pyritic ash content must
be controlled, in part to maintain specific heating value but more
importantly to avoid an unpredictable ash fusion temperature.
These are major considerations.
1. 1 Whole Refuse Fraction
Maximum cleaning plant yield would result from
extraction of heat and sulfur value from the entire
refuse fraction without waste. While this possibility
is unlikely to occur frequently, it is not unknown. A
review of some washability tests in current programs
has identified five samples taken from seams containing
substantial coal reserves that were crushed to 1. 5 inch
by 100 mesh and separated at * 1. 35 specific gravity.
The two fractions of each sample were analyzed with
results as shown in Table IV-1.
in - 12
IV - 1
-------
The HSC Fuel and consequent flue gas compositions are indicated
in Figure III-l, and with these as base parameters the diagram
of Figure III-2 shows the main related quantities. The various
fuel tonnages entered in the left hand columns, and the sulfur
value quantities in the right hand columns, are related by the
assumption that the ROM contains 3% pyritic sulfur and 1%
organic sulfur, that the pyritic sulfur would wash out completely,
and that the non-pyritic ash distribution would be as indicated in
the NOTES on the diagram.
It is clear, of course, that any change in fuel compositions will
affect all quantities. Thewhole diagram represents approxi-
mate arithmetic relationships that are adjusted for expected
operating efficiencies in combustion and SO, recovery. The
yields of pyritic sulfur and carbonaceous material from the
washing operation may be given effect in the diagram at levels
that are too high for any actual practice. These yields will
depend on washabilities that vary widely, of course, from one
coal to another. Yield of HSC Fuel and total heat value yield
will depend particularly on efficiency of non-pyritic ash separa-
tion Since the combustion products of the HSC Fuels are
exceptionally high in pyritic ash, the possibility of loading up
also with non-pyritic ash is not unlimited. The subject is
discussed in Parts IV and XI.
1. 5 The diagram of Figure III-2 does illustrate the heating value
effect of the varying proportions in the HSC Fuels of the low
heating value component (FeS,) and the high value component
(coal) CASES D and A for example, based on entirely different
technology, are intended to produce respectively 500 MW and
500, 000 Ibs/hour of steam (about 50 MW) - a ten-fold difference
in energy output, while the yield of sulfur value is similar as to
quantity, and the yield of "clean coal" a little over 7 million
tons per year from each. The choice here would evidently
depend on the market for energy. If a very large electric
capacity is wanted, say 1, 000 MW, the CASE D or E system
would be designed to operate on a lean flue gas of 0. 5% SOg
or less in order to avoid overproduction of sulfur value at one
location, and in order to realize a high output of clean coal at
the same time. If a low energy capacity will satisfy local
demand, a combustor and sulfur recovery system such as
illustrated by CASE A may suffice.
It is not overlooked that the 7 million ton clean coal magni-
tude may be too large to expect from one cleaning plant since
even the largest single bituminous mines are well under this
level of annual output. Several sources wo uld probably have
to contribute to such a volume of coal. The diagram of
Figure III-2 indicates for example that clean coal at about 3
million tons per year might be associated with the HSC Fuel
for a 500 MW capacity, a flue gas of 0. 4% SO2 and 250 tons
per day of sulfur value as sulfur.
2. SULFUR VALUE
2.1 SulfuricAcid
In this study it is assumed that the only important market
for "sulfur value" extracted from coal reject material is
III - 9
HI - 8
-------
I
FIGURE 1 11-2
HI6H SULFUR COMBUSTOR STUDY
COAL, ENERGY t SULFUR PRODUCTS
MILLION TONS/ YEAR
CASE
p
A
E
B
C
RUN OF
MINE
CLEAN
COAL
(CRY BASIS
9.7
8.1
5.8
2.8
1.3
7. 1
7.1
3.5
2.3
0.92
HSC
FUEL
2.3
0.64
2.1
0.*!
0.30
"°TES (1) ROM: 1* ORGANIC S, 35 PYRITIC S
13} NON-miTIC ASH.
(2) CLEAN COAL: t% ORGANIC s
s% Hcm-mmc ASH
(3) CLEAN COAL + HSC FUEL=95=! OF
ROM WEIGHT (DRY BASIS)
II.IMMM
HII.HIIt
/
utmmi
IMIIIII
11(11111
niMIH
1 i
llllfHIMI
*
<.<$?
rr
/
ttltlltim
•iiiiiiu^ni
/
y
s
s
/
iimiiimsiMiiiiiHi
7
**
04 0.5 07 1.0
(IIIIIMMMII
A
/
r
IIII1IIIMI
&
f\
........
/
/
.,..»
f
im
mm
3 « 5 P 7
10
&
8
7
e
3
•
0
HET TOHS/DAY
SULFUR
760®
640
510
230
,00s
SULFURIC
ACID
EQUIVALENT
2300
1830®
1420®
620®
291
MAGNESIUM
SULFITE
EQUIVALENT
25003
1980
1580
710
3,0®
LIQUID
SULFUR
DIOXIDE
EQUIVALENT
CASE
1520 0
1220
970
t
E
<»M) : B
i ,
190
C
•'DESIG" BASIS IN THIS STUDY
0 6
ft; TOTAL CLEANING LOSSES • 5? PERCENT S02 IN FLUE GAS
-------
1.4.3 CASE E employs SO recovery technology (Monsanto Cat-
Ox) similar to CASE B but this system is scaled to the
500 MW output level (more than 10 times the energy
capacity of CASE B) so that the combustion equipment
is quite different. The SO recovery trains operate on
relatively weak gas of 0. 7% SO which is generated by
an S/C ratio of 0. 12.
1. 4. 4 CASE D is also scaled to 500 MW energy output but the
SO recovery technology is quite versatile compared to
processes mentioned above. The acid intermediates:
liquid SO_, magnesium sulfite or sulfur, can be
produced for storage or shipment, or sulfur value can
uc ton verted directly to sulfuric acid, any of these by
available technology. The main design theme of CASE
D in this study is for output of sulfur at 770 net tons per
day from a 1% SO0 flue gas that requires an S/C ratio
£i
of 0.2.
1. 4. 5 CASE C is the reduced-scale prototype or demonstration
unit of CASE D, designed to operate on the same HSC
Fuel composition but at 50 MW energy capacity and
about 100 tons per day of sulfur.
Thus the five cases include two of industrial interest, two of
electric utility interest, and a prototype unit in the domain of
the latter.
Ill - 6
-------
JiSC FUEL
S/C Ratio
Percent SO.
in Flue
Low Sulfur High Sulfur
0.08 2
0.4 - 0. 5 6-7
7
13
87
12, 600
42
79
21
5, 300
On Non-Pyritic-Ash-Free Basis;
Percent S in fuel, ca.
Equivalent percent FeS,
in fuel, ca.
Percent coal combustibles
in fuel, ca.
Higher heating value of fuel
Btu/Pound, ca.
* Sulfur-free
It is believed that a coal cleaning plant can be designed to produce
low sulfur coal plus one or moire hr^, ^-'ifur fuels within the
range of compositions defined above. But this is a broad range
and any processing system of the types considered herein will
operate well only on a narrow range of fuel composition.
That is to say fuel held to a reasonably narrow specification that
must be one of the principal parameters of the process design.
The process systems will not, however, be designed around
the fuel specifications as is the normal procedure for fossil
fuel furnaces. The logic here is to design the process to fit
the market and to tailor-make the fuel to fit the process.
Available technology does not appear to include a single type of
process system that will do well enough with the diversity of
possible market situations that will dominate the recovered sulfur
value, and offer at the same time the design flexibility required for
III - 4
adaptation to output of 500, 000 Ibs/hr of steam at one location or
500 MW at another. (See Statement of Contract Work, p 1-2).
..4 Three process systems of presently available technology appear
to be no more than necessary to exploit all zones of the
opportunity that may be offered by the high sulfur combustor
thesis. These three have been developed into five case studies*
as follows:
1. 4. 1 CASE A system is designed for firing an HSC Fuel having
an S/C ratio of about 2 to produce 500, 000 Ibs/hr of
industrial quality steam and a flue gas of 6% SO
concentration which is directly converted to some
1, 800 tons/day of commercial grade sulfuric acid.
These outputs would be secondary coproducts of clean
coal produced at a rate of 7 million tons per year by
washing a run of mine coal containing 3% pyritic sulfur.
The actual clean coal output would, of course, depend
on the actual ROM composition and washability.
A system of this type is conceived to be of possible
value as an addition to an existing coal-burning utility
complex (See 1. 6. 2), Or existing chemical or steel-
making industry (See 1. 6. 3).
1.4.2 CASE B system will fire an HSC Fuel of about 0. 4 S/C
ratio (2% SO in flue gas). It is scaled to 500, 000 Ibs/
hour industrial steam as in CASE A, but much smaller
outputs of clean coal and sulfuric acid would be co-
produced.
Ill - 5
:= See Part I Abstract, or Table IV-7, for tabulated summary of the five
case studies.
-------
-t-
PERCENT S02 IN FLUE GAS
\
_
O — 0) O C
m z O ~" °5
I!
I
i-m
curves of Figure III-l show only the middle portion of this range
since interest here is limited to combustion of sulfur and coal in
mixtures, say, between the limits S/C = 0.08 and S/C = 2. These
limits will yield SO concentrations higher than result from burn-
ing "high sulfur" coal and lower than result from roasting iron
pyrite.
The rationale of this limitation is simply that since the HSC Fuels
can be "tailor-made" by the cleaning plant (as argued in Part II)
the specification should be cut to serve the downstream processes,
cost considered. Since these processes will be designed and
operated for economical production of valuable heat and sulfur
products, the HSC Fuel should be of reasonably high heating value
consistent with a substantial sulfur content.
1.2 In respect of heating value it is noted that combustion of iron
pyrite yields about 3, 000 BTU per pound while a low ash
bituminous coal may be 14, 900 BTU per pound or more.
Generally speaking, the available technology in the SO2
recovery arts is benefitted by high rather than low flue gas
concentrations of SO . This is true mainly because gas
purification equipment is more costly if larger rather than
smaller volumes of gas need to be handled,
1.3 These considerations, and others later discussed, are the
basis for confining this exploration within boundaries as
follows:
III - 3
-------
FIGURE IY-3
FES2 0
% COAL 100
S/C RATIO 0
80 «
tc.
ui
25
T5
0.18
50
50
0.53
75
25
1.6
100
0
cxa
COMBUSTION EFFECTS
OF
PYRITE-COAL MIXTURES
-------
FIGURE DZ-2
COMBUSTION PROCESS
FLOW SHEET
DISTRIBUTION OF PREHEATED AIR
BOILER f~\
/
/
/
(760° F)
nn
<900°F)
/ \/
\
1
1
1-^
AIR
r (5OO°F>
FROMRMCED
DRAFT FAN
TABLE IV-6
EXPECTED HSC FUEL-FIRED
COMBUSTOR PERFORMANCE
Composition of Fuel -
Combustibles Only:
% FeS2
% Coal
S/C Ratio
Heat Losses, %
Dry Flue Gas
Hydrogen + Water
in the fuel
Moisture in the A ir
Unburned Carbon
Radiation
Unaccounted for
Total
Boiler Efficiency %
Flue Gas/Fuel Weight Ratio
Air /Fuel Weight Ratio
MBTU per POUND ca.
Moisture in
Non-pyritic
Combustion
Humidity of
0
100
0
9.9
4.3
25
75
0.18
10.2
4.2
.23 .23
.1
.38
1.5
16.4
83.6
13.7
12.7
14
actual
ash in
in 25%
air 60',
.31
.38
1.5
16.8
83.1
11.4
10.5
11.3
HSC fuel 6%.
50
50
0.53
10.7
4.0
.24
.66
.38
1.5
17.5
82.5
9.0
8.3
8.5
75
25
1.6
11.8
3.6
.26
1.29
.38
1.5
18.8
81.2
6.7
6.1
5.8
100
0
oo
14.5
2.5
.32
3.2
.38
1.5
22.4
77.6
4.3
3.9
3.0
actual HSC Fuel 20%.
excess air.
6 RH at 80° F.
PRIMARY AIR FAN
IV- 14
IV - 15
-------
be unfavorable as discussed in Part XI, fluidized bed combustion
is not considered further in this summary section.
Cyclone furnaces while well developed are notable for high
maintenance costs which could be aggravated by the high
concentration of iron and sulfur in the HSC Fuel.
Suspension-fired furnaces, however, with either vertical or
horizontal burners are not objectionable on any of the foregoing
grounds, and emov also a long history of commercial success in
both dry and wet bottom designs.
Even so, a considerable study of the expected characteristics of
the HSC Fuels has been necessary to establish pulverized fuel
firing as most suitable and to develop the basis for selection of the
vertical or horizontal firing technique as a function of the pyritic
content of the HSC Fuels.
In an earlier section of Part IV it is argued that ash fusion
temperatures of the HSC Fuels must be stabilized in a
predictable range, and, in view of high iron concentrations,
this range should be higher than normal furnace temperatures.
Wet bottom furnaces are thus not suitable.
4. 1 Dry Bottom Suspension Combustion
By elimination, therefore, dry bottom pulverized fuel,
combustors are believed to be the relatively risk-free
type for all systems. This equipment can easily achieve
the necessary efficiencies and capacities; it is known to
be highly reliable and corrosion resistant. Horizontal firing
is the design choice for the lower S/C ratio fuels and vertical
down-firing for high S/C ratio fuels as discussed in Part XI.
5. COMBUSTION PROCESS DESIGN
Figure IV-2 is a generalized diagram of air and combustion gas
distribution that is typical of suspension firing of pulverized fuels.
A similar gas flow is employed in the combustors of CASE A, C
and D. The combustor of CASE D is suitable for CASE E with
minor changes. The CASE B combustor design has not been
developed for this study since funds were not provided for it, but
an estimate of capital cost based on a modified CASE A design is
indicated in Part XIV.
Table IV-6 is a theoretical representation of expected change in
Boiler Performance with change in FeS_ concentration in the
HSC Fuels. Note that decline in efficiency across the entire
range is not great. This relation is plotted in Figure IV-3. The
chart shows also that flue gas quantity and heating value increase
at about the same rate as the coal content in the pyrite-coal
mixture. Flue gas volume for a given heat output is thus indepen-
dent of the sulfur content of the fuel, and the SO- concentration in
the flue gas will be substantially controlled by the S/C ratio as
shown in Figure III-l.
Table IV-7 and the diagrams following are a summary of the
Boiler Specifications appearing in Part XI. Steam quality
specifications are established for typical industrial applications,
or as such specifications are usually laid down by manufacturers
of turbo-generators for driving with sub-critical steam.
IV - 13
IV - 12
-------
2. FURNACE TYPES
At this point consideration is given to available combustion equipment
with a view to reduction in the number of possible choices on
grounds easily established. Well recognized modern furnace types
are as follows:
2. 1 Roasting Equipment
a) Kiln
b) Multiple Hearth
c) Flash Roasters
2. 2 Fluidized Bed Combustors
2. 3 Stoker Furnaces
2.4 Grate Furnaces
2. 5 Crushed Coal-Fired
a) Cyclone Furnace
2. 6 Pulverized-Fuel Fired
a) Wet bottom furnace
b) Dry bottom furnace
Horizontally fired
Vertically fired
3. FURNACE LOAD REQUIREMENTS
The primary duty of the furnace or combustor will be production
of steam of high competitive quality for large volume requirements.
This is to say that steam output intended for industrial consumption
will be economical for all except specialized uses, and that steam
for electricity will efficiently drive large modern turbo-generators.
4.
3. 1
Steam Design
The steam design bases are as follows:
Type of
Boiler
Industrial
Utility ( 50 MW)
Utility (500 MW)
Temp.
°F
825
1,000
1, 005
Press.
PSIG
900
1, 450
2, 500
Quantity
M Ibs/hr.
500
500
3, 500
IV - 10
3.2 Service Factor
In keeping with the primary objective which is production of
clean coal and production of more rather than less, the
industrial and utility boilers are designed to be base loaded
as measured by a service factor of 8, 000 hours of full
capacity operation per year.
FURNACE SELECTION BASIS
The steam production requirement alone appears to eliminate furnace
types 2. 1, 2. 3 and 2.4 on page IV-6. None of these designs can be
fired at the necessary high temperatures. Fluidized bed
combustion may have a potential capability to produce this
quality and volume of steam, but it is not yet established
commercially and since certain other factors appear also to
IV - 11
-------
TABLE IV-5
TABLE IV-4
HSC FUEL COMPOSITION
HSC FUEL COMPOSITION
CASE C AND D
PROXIMATE ANALYSIS
Moisture
AshU)
Fixed Carbon
Volatile*2)
FeS
TOTAL
Moisture
Ash
Total Carbon
Total Hydrogen
Oxygen
Nitrogen
Sulfur
FeS
TOTAL
Higher Heating Value
Moisture - "
Ash
Total Carbon
Total Hydrogen
Oxygen
Nitrogen
Sulfur
TOTAL
As Received
6.0
18.9
32.6
21. 7
19. 5
100. 0%
6.0
18.9
43.0
2.9
7.0
1.6
. 8
19.8
100.0%
BTU/LB.
UTLIMATE
6.0
23.7
54.8
3. 6
8.8
2. 1
1.0
100. 0%
Moisture Free
Moisture Free Ash Free
20
36.4
23. 5
21. 1
100. 0%
ULTIMATE ANALYSIS
20
46
3.0
7.4
1. 7
.8
21. 1
100. 0%
9, 000
ANALYSIS (COAL COMPONENT
25.2<3>
58.4
3.8
9.4
2.2
1.0
100. 0%
44.2
29.4
26.4
100. 0%
57.5
3. 7
9.2
2.2
1.0
26.4
100. 0%
ONLY)
78.5
4.8
12.5
2.8
1.4
100. 0%
(1) "Ash" in this tabulation means non-pyritic ash. Ash specification is
discussed in Part XI.
(2) Volatile matter as derived from the coal component. One of the S
(3)
atoms in the FeS- is also "volatile" (labile) above about 750° F.
Total volatility may reach 36% of total combustibles in this fuel.
ROM coal may have only 5-107o non-pyritic ash, which may tend
to concentrate in the HSC Fuel.
Moisture
Ash
-------
TABLE IV-2
TABLE IV-3
HSC FUEL COMPOSITION
Moisture
Ash (1)
Fixed Carbon
Volatile'2*
FeS0
TOTAL
Moisture
Ash
Total Carbon
Total Hydrogen
Oxygen
Nitrogen
Sulfur
FeS,
TOTAL
Higher Heating Value BTU/LB.
Moisture
Ash
Total Carbon
Total Hydrogen
Oxygen
Nitrogen
Sulfur
TOTAL 100.0%
CASE
A
PROXIMATE ANALYSIS
As Received
6.0
18.8
10. 3
6.8
58. 1
100. 0%
6.0
18.8
13. 5
0.9
2.0
0.5
0.3
58.0
100. 0%
TU/LB.
ULTIMATE
6
23.7
54.8
3.6
8.8
2. 1
1.0
Moisture Free
__
20. 0
11. 0
7.3
61. 7
100. 0%
ULTIMATE ANALYSIS
__
20
14.4
1.0
2.2
0.5
0.3
61.0
100. 0%
4,424
Moisture Free
Ash Free
_„
--
13.8
9.2
77. 0
100. 0%
-_
--
18.0
1.2
2.8
0.6
0.4
77.0
100. 0%
ANALYSIS (COAL COMPONENT ONLY)
25.2(3)
58.4
3.8
9.4
2.2
1.0
--
78.5
4.8
12.5
2.8
1.4
HSC FUEL COMPOSITION
CASE B
100. 0%
100. 0%
(1> "Ash" in this tabulation means non-pyritic ash. Ash specification is
discussed in Part XI.
(2) Volatile matter as derived from the coal component. One of the S
atoms in the FeS_ is also "volatile" (labile) above about 750° F.
Total Volatility may reach 30% of total combustibles in this fuel.
PROXIMATE ANALYSIS
Moisture
Ash*1'
Fixed Carbon
Volatile<2>
FeS
TOTAL
Moisture
Ash
Total Carbon
Total Hydrogen
Oxygen
Nitrogen
Sulfur
FeS
TOTAL
Higher Heating Value B'
Moisture
Ash
Total Carbon
Total Hydrogen
Oxygen
Nitrogen
Sulfur
TOTAL
(1) "Ash" in this tabu)
discussed in Part
(2) Volatile matter as
As Received
6.0
18.8
26. 1
17.3
31.8
100. 0%
6.0
18.8
34.1
2. 1
5.5
1.2
0.5
31.8
100. 0%
FU/LB.
ULTIMATE
6
23.7
54.8
3.6
8.8
2. 1
1.0
Moisture Free
Moisture Free Ash Free
20.0
27.8
18.4
33.8
100.0%
ULTIMATE ANALYSIS
20.0
36.3
2. 2
5.8
1.3
0.6
33. 8
100. 0%
7,400
ANALYSIS (COAL COMPONENT
25.2(3)
58.4
3.8
9.4
2.2
1.0
100.0% 100.0%
Lation means non-pyritic ash. Ash specification
XI.
derived from the coal component. One of the S
34.8
23.0
42.2
100. 0%
45.4
2.8
7.3
1.6
0.7
42.2
100. 0%
ONLY)
78. 5
4.8
12.5
2.8
1.4
100. 0%
is
(3)
ROM coal may have only 5-10% non-pyritic ash, which may tend
to concentrate in the HSC Fuel.
(3)
atoms in the FeS, is also "volatile" (labile) above about 750° F.
Total volatility may reach 34% of total combustibles in this fuel.
ROM1 coal may have only 5-10% non-pyritic ash, which may tend
to concentrate in the HSC Fuel.
-------
the loading of non-pyritic ash (that is the component of the
total ash of the fuels that does not derive from iron pyrite)
must be limited by the capability of the furnace equipment
designed to burn it.
FIGURE H-l
The composition as well as the quantity of non-pyritic ash, of
course, matters of some complexity, are discussed in Part XI
in which theoretical and experimental criteria are analyzed in
order to establish the bases of the HSC Fuel Specficiations. Fuel
volatility, reactivity, ignition temperature, grindability,
corrosion and erosion are also among the critical properties
considered in the design of combustion equipment for the HSC
systems.
1. 4 Ash Fusion Temperature
Of special interest are ash fusion characteristics which are, in
the HSC Fuels, expected to be much influenced by the unusually
high concentration of iron, a basic constituent. The effect of
basicity is plotted in Figure IV-1. The HSC Fuel compositions
are intended to yield total ash having softening temperatures
rather high on the right hand side of this curve, i. e., 50%
"basic content" or greater. Among the important specified
limitations on non-pyritic ash is that it should not exceed 20
pounds per 100 pounds of dry HSC Fuel and that alkali metal
oxides, calculated as Na2
-------
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A very minor adjustment of these refuse or reject composi-
tions would produce the HSC Fuel required for the
combuBtor system of CASE C or D,
1. 2 Blending of Fractions
More often however, it Is expected that the reject material
will need to be cut into two or more fractions of which
portions will be blended, possibly with the addition of some
clean coal, to produce specification HSC Fuels.
1. 3 Heat Value Yield and Non-Pyritic Ash
Whatever the blending or adjusting procedure, the content
of non-pyritic ash will be a critical factor in the total
heat value yield of the cleaning plant and in the success of
the HSC Fuel itself in serving its Intended purpose. The
reasons are briefly:
a) High yield in cleaning operations depends on the
extent of utilization of middlings, that is coal from
which ash failed to separate. While high total yield
of heat value and optimum economic results are by
no means the same thing, low yield will certainly
result in bad economics. The usual incentive will
be to load up the HSC Fuels with as much ash as
possible in order to save the associated coal.
b) Since however the HSC Fuels are high ash anyway,
as a result of the inescapable iron oxide, 1. 25
pounds of it per pound of pyritic sulfur in the fuel.
IV - 3
-------
INDUSTRIAL BOILER
The Industrial Boiler of 500, 000 pounds per hour steam capacity, when
designed for suspension firing and dry ash, is adaptable to HSC Fuels
in the range S/C - 1 to S/C -2.5 provided the non-pyritic ash is not
excessive.
6. 1 Vertical Firing
The high sulfur, high total ash, slower combustion and slightly
reduced volatility of fuels in this S/C range, as compared to
commercial steam coals, dictate a preference for special
burners, Figure IV-5, fired vertically downward, as illustra-
ted in the boiler elevation drawing of Figure IV-4. This
arrangement permits a long flame path and allows introduction
of air along the path of combustion as needed in the event of •
variation in the combustton --v-it.° of the HSC Fuel. A portion
of the preheated primary air is diverted through the pulveriz-
ing mills to convey the fuel as shown in Figure IV-2. Ball
tube mills, a preferred type for heavy duty, appear to be
required for all the HSC Fueis in view oTthe low grindability
of iron pyrite. (See Part XI for elaboration.)
6. 2 Steam cycle design at 500, 000 Lbs/Hr output flow is:
Pressure
Temperature
Reheat
Feedwater
900 psig
825" F
None
300° F
The gas temperature is 500° F at the air heater exit. This
level is safely above the dew point of condensable acids in
the air heater but in this unit the economizer has been
eliminated in view of the exceptionally high acidic concentra-
tion in the flue gas.
IV - 17
-------
IV-I8
-------
•CVCLOWE ANTHRACITE BURNER
FIGURE IV-5
r-Air
Coal Mixture
Vent Control Dampers -
Auxiliary
Air Port
Ignition and
Observation
Tubes
Straightening Vane-1
Tertiary Air Supply—' Dampers-
IV -
-------
FIGURE IE-6
6. 3 The Energy Distribution Diagram of Figure IV-6
indicates that very little superheat is required.
Feedwater heating will occur in the drum which
should improve the circulation but increase the
furnace duty. The latter is compensated for in the
design by two boiler drums with a vertical,
convective evaporating section. Efficiency is
expected to be 81. 3% when burning the HSC Fuel
of S/C ratio 2 for CASE A.
DISTRIBUTION OF ENERGY
500.000 LB/HR BOILER
FOR CASE A
HSC FUEL S/C = 2
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IV - 20
ESZ-21
-------
7. THE 50 MEGAWATT PROTOTYPE BOILER FOR CASE C
All designs of the CASU C system are consistent with the conception
of an electric utility demonstration plant as described in Part I. 2. 6
of this volume. Although the energy output is of a magnitude similar
to the industrial boiler of CASE A, the steam pressure is substantially
higher, the efficiency slightly improved (82.3%), and a boiler design,
horizontally fired, that is much more nearly of conventional type.
7. 1 The Horizontal Intervene Burner illustrated in Figure [V-8
is included in the design. This burner is of conventional
type, thoroughly developed and reliable, and noted for high
efficiency in promoting the mixing of combustion reactants.
The resulting short flame path obviates risk of impingement
of unbumed matenai which is the object of suspension
firing.
7. 2 Steam cycle design at 500, 000 LBS/HR output flow is:
Pressure
Temperature
Reheat
Feedwater
Air-heater-Exit
Gas Temperature
1450 psig
1000° F
None
430° F
500° F
IV - 22
-------
-------
FIGURE IV-8
Tertiary Air
Oil Burner
Tube
INTERVANK BURNER
Secondary Air Distribution Ring
Coal/Primary
Air Inlet
Secondary
Air Vanes
Vane Operating
Mechanism
Secondary Air
IV - 24
-------
FIGURE H-9
7.3 The Energy Distribution diagram of Figure IV-9 is quite
different from that of the Industrial Boiler. A portion of
the superheat will be generated in a pendent superheater
located in the furnace cavity and the remaining portion of
the superheat will be generated in the horizontal tube
bundle in the convection pass. A combination of radiant
and convection transmission of superheat is expected to
result in a nearly flat superheater characteristic over a
wide range of loads. The economizer will be located
between the superheater and the air heater. The walls
of the convection pass will be cooled with evaporating
tubes. A furnace exit temperature will be maintained
at 2000° F.
DISTRIBUTION OF ENERGY
50 MEGAWATT BOILER
FOR CASE C
HSC FUEL S/C = 0.2
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-------
THE 500 MEGAWATT ELECTRIC UTILITY BOILER
While the boiler selected for this duty is to burn the same HSC
Fuel, S/C = 0. 2, specified for the prototype, CASE C, higher
quality steam for large turbo-generators is required. The
boiler design is natural circulation, pressurized, and fed by
back up with ball tube mills.
8. 1 Horizontally Fired
The intervane burners of Figure IV-8 and the
horizontally opposed arrangement of Figure IV-10
are judged suitable on the basis of large quantities
of combustibles in the HSC Fuel.
8. 2 Steam cycle design at 3. 5 million poi'ids per hour
output is shown below:
Pressure 2500 psig
Temperature 1005° F
Reheat:
Pressure In 580 psig
Temperature In 629° F
Pressure Out 555 psig
Temperature Out 1005° F
Feedwater 480° F
Flue Gas at Airheater Exit 500° F
IV - 27
-------
-------
8. 3 The Energy Distribution diagram of Figure IV-11 shows that
evaporation accounts for a small portion only of the total
boiler duty. In order to minimize startup problems, over-
heating of tubes and other undesirable effects, the super-
heater surface is to be installed as a partial division wall
in the furnace. A portion of the superheating will be
accomplished in the convection passes and the finishing
superheater will be installed in the furnace cavity. The
economizer is smaller than normal to enable a proper
ratio of superheater surface to reheater surface and
maintain control of the final steam temperature over a
range of operating conditions. The air heater inlet
temperature at 900° F will require construction material
of slightly greater than normal heat resistance. This
temperature level is necessary to evaporate all the
moisture in the fuel, assumed herein to be 6%. The
efficiency of this boiler is expected to be 82. 3% when
fired with the HSC Fuel S/C = 0. 2.
IV - 29
-------
FIGURE
DISTRIBUTION OF ENERGY
500 MW BOILER
FOR CASE D
HSC FUEL S/C'0.2
—
u-
c
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Heat to
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Latent
Heat
Superheater
H»heater ,___F
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^N L
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( > }' "
H«ot Absorbed in «' /
^ Air Pr»h«o1er o ./
I from H2
l-p in Fuel
'and Air
Incomplete
Combustion
-Radiation
9. BOTTOM ASH AND FLY ASH
Bottom ash and fly ash are to be collected mechanically and by
wet scrubbing from the boilers of CASE A, C and D Systems
in about the following proportions of the total ash:
Furnace Bottom
Cyclone Collector
Wet Scrubber
20%
65%
15ft
Total 100%
The dry cyclones in series with wet scrubbing is well justified
by reduction in the volume of ash that will need to be
processed through lime neutralization of the acidity of the
scrubbing liquor.
Fly ash is to be collected by electric precipitation in CASE B
and E Systems. The design basis for fly ash collection from
all systems is set forth in Table IV-8.
9. l While the iron content of the dry CASE A ash is as
high as 47% it is not likely to be a valuable source
of blast furnace charge. The other ashes are lower
in iron. Possibilities for development of economic
value from the ashes is discussed in Part XII.
IZ-30
rv-3i
-------
TABLE IV-8
FLY-ASH COLLECTION DESIGN BASIS
Case
Capacity
Gas Flow Ib/hr
Gas Temperature ° F
AP
Particle Loading
Total Ash, Grains /SCF
To Dust Collector
Grains/SCF
Ash Composition
23
A12°3
SiO_
Weight
=?-ercent
Remaining
Efficiency Required
Ash Size Distribution
500, 000 Ib/hr
895, 000
496
50
40
80
C D
50 MW 500 MW
675, 000 5, 170, 000
502 497
About 3" H20
85%
80%
65%
40%
23%
+ Nominal
* Percent under indicated micron size
17
13.5
80
17
75 - 80 %
45*
40»»
is*.
17
13. 5
80
17
3
ELECTRIC GENERATION
1. SIZING OF STEAM-ELECTRIC EQUIPMENT
The 500 MW unit is among the smaller of the popular sizes of
generating units purchased in very recent years, most of which
have ranged from 600 to 850 MW capacity per unit. Unit sizes of
300 to 500 MW were typical of new U.S. installations built during
the 7 or 8 years prior to 1967. These sizes were perhaps a little
better than the larger units. In any event they enjoy a reputation
for somewhat greater reliability. The choice of the 500 MW unit,
(specified in the statement of contract work) is a choice for
conservative technology which is a good companion to available
technology also emphasized in the statement of contract work.
For much the same reasons the 500 MW boiler is designed for
subcritical operation and is otherwise consistent with conserva-
tive technology.
The 50 MW boiler is also sub-critical and conservative and is
of a size now and then installed for municipalities, industrial
service and the like. While the steam pressure is much lower
than is common for boilers 10 to 20 times larger, it will be
completely adequate to demonstrate the technical feasibility of
converting the heat value in the HSC Fuel to electricity in
large scale equipment. Steam-electric generators much
smaller than 50 MW tend to be classified by manufacturers
as "special order" with a higher dollars per kilowatt price tag.
The 50 MW size thus appeared about right for the prototype plant.
V - 1
rv - 32
-------
2. A conventional turbine drive cycle is illustrated in Figure V-l
appropriate for both 50 and 500 MW units.
3. Central Station Steam Generators as installed in recent years
are listed in Table V-l. All units in the list are 100 MW or
larger.
V - 2
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VI
SULFUR VALUE RECOVERY
1. FLUE GAS CLEANING
Following absorption of heat on the walls and tube surfaces of the
boilers, the combustion gas is next relieved of the heavy load of
fly-ash. Mechanical separation followed by wet scrubbing is
employed in CASES A, C and D. Electric precipitators operating
at 900° F serve this function for CASES B and E. The cleaned
gases in each system are thereafter ready to be processed for
recovery of contained sulfur oxides.
2. MARKETABLE END-PRODUCTS
Of the many proposed processing methods, Ref (LL), (SS), a few
only have been worked up to commercial scale application and
not all of these are ot interest in the present study. Most of the
recovery processes that have been commercialized in Europe,
USSR and Japan will yield only ammonium sulfate, a nitrogen
fertilizer, that is not much favored in the United States. Even
so, the fertilizer element in this substance is nitrogen; the
sulfate serves as the packaging so to speak — a low value
contribution. With this exception the valuable end-products of
commercial operations or proposed end-products have nearly
all been sulfuric acid intermediates or sulfuric acid itself in
various concentrations.
In any event, it is clear that any large quantity of sulfur value
recovered from coal in the United States will be consumed
VI - 1
-------
ultimately as sulfuric acid, but manufacture of the acid, having
regard to the cost of shipping, is not necessarily best done at
the site of the high sulfur combustor. Acid intermediates, as
pointed out in Part 111-2, are of interest also.
3. STRONG CHEMISTRY WANTED
A recovery system should employ "strong chemistry" whereby
it will be capable of high efficiency in extracting sulfur oxides
from the combustor flue gas, and capable of high conversion
efficiency also. If these capabilities are inherent in the process
chemistry and economically applied, the recovery system will
provide:
3. 1 High sulfur value yield.
3. 2 Adaptability to a broad range of sulfur oxide
concentration in the primary gas.
3. 3 Minimum risk of objectionable pollution from
sulfur oxide emissions.
Here it should be noted that the merits of "strong chemistry"
are bought only at the cost of a high energy requirement to
disengage the SO from the absorbent of the recovery system
in some form that can be processed ultimately to salable
sulfuric acid.
4. AVAILABLE PROCESSES
These considerations together with the criterion of "availability"
(See Part 1-4) appear to limit the recovery process possibilities
to what is listed below:
VI - 2
4. 1 The "Contact" Process
Chemistry:
The sulfur dioxide and oxygen in the cleaned flue gas are brought
into contact (hence the name) with a solid catalyst on which they
react to form sulfur trioxide; this is in turn combined with water
to yield sulfuric acid. If insufficient oxygen is present in the
cleaned gas, more is added, usually as air. The base reactions are:
4. 1. 1
S0
1/200
H2°
so3
HJ5O,,
The "Standard" Contact Process
The process has been adapted to the treatment of SO,
containing gases from combustion of iron pyrites and
elementary sulfur, from the off-gas of sulfide ore
smelting, and many SO sources of lesser interest
such as the decomposition of ferrous sulfate and
calcium sulfate, refinery acid sludge and the like.
The process may be employed on gasses containing
a fraction of one percent SO, although until recently
about 4% was considered the practical lower limit.
This limit has evidently been extended as noted below.
Availability
The usual range of Contact Process application is
7 to 8% SO_ concentration up to about 13%.
Several dozen installations to recover smelter off-
gas are known to operate in the lower end of this
range. The usual design for acid production from
sulfur or pyrite employs the high end. As many as
a thousand plants of the latter type have been put in
VI - 3
-------
operation during the nearly 50 years of commercial
success of this process. It is thus incomparably the
most widely practiced and highly developed process
for recovery of sulfur value from SO^-containing gas
streams.
A standard Chemico Contact Process design,
modified to operate on a 6% SO_ gas, is submitted
£i
in this study as the recovery train of CASE A later
described in detail. The end-product is commercial
grade 93/98% sulfuric acid. Ref (R) The process is
commercially offered by Chemical Construction
Corporation. Similar processes are offered by
other engineering organizations.
4. 1. 2 The Cat -Ox Process
A modification of the Contact Process has been
developed in recent years by Monsanto Envirochem
Systems, Inc. and associates, especially for the
recovery of SO2 from fossil fuel combustion as a
means of abating air pollution. The process is
capable of treating SO concentrations in the range
2% down to a few tenths of 1%. Process detail for
two sizes is submitted herein to serve the SO
2
recovery functions of CASES B and E. The
immediate end-product of this process is 77/80%
sulfuric acid. Since this grade of acid does not
enjoy broad market acceptance, a standard type of
acid concentrator is included whereby the output of
CASES B and E is upgraded to 93% sulfuric acid.
VI - 4
Availability
The process has been pilot tested on a scale of about
15 MW. Ref (MM) A commercial scale (100 MW)
installation of this process is to be constructed with
NAPCA sponsorship at the Wood River station of
Illinois Power Co. Ref (NN) The process is now
commercially offered by Monsanto.
4. 2 Other Sulfuric Acid Processes
A number of schemes for conversion of dilute SOg to sulfuric
acid depend on liquid phase oxidation and represent radical
departures from the well perfected technology of the
"Contact Process".
Among these, one by Lurgi and one by Hitachi absorb SO
on activated char from which a weak sulfuric acid can be
washed off with water. While these two are rpported to have
been tested in small pilot plants, they appear to be not
available for the purpose of this study. Other proposals for
direct conversion of dilute SO- to sulfuric acid are still in
the second generation of development.
4. 3 Concentration of Weak Gases to Intermediate Levels
This type of treatment is of importance since such
concentrations can bridge the gap between the dilute
occurrences, say less than 3% SO,, and the established
processes for treating stronger gases.
VI - 5
-------
4. 3. 1 RBinluft Process
Chemistry:
Sulfur dioxide is absorbed on hot activated char and
converted to sulfuric acid by air and steam. Unlike
the proposals of Hitachi and Lurgi, the Reinluft char
is then regenerated by hot inert gas that also
effectively decomposes the adsorbed sulfuric acid to
SO and water. The SO, is thus concentrated to
about 25% by volume from which sulfnric acid or
acid intermediates can be made.
Availability:
Three commercial installations are or have been
in operation in Germany of which the largest is at
Wolfsburg designed to treat 50, 000 SCFM of dilute
SO2 gas. The Reinluft process, while evidently in
an advanced stage of development, is believed to be
still subject to some degree of explosion hazard.
The process is objectionable also in consequence of
ground-area requirements that are disproportionately
large, mainly because of the low space velocity of the
primary adsorption. Ref (R) (EE) (LL)
4.3.2 Grille Process
Chemistry:
Sulfur oxides in flue gas are absorbed in "mixed
metal oxides", typically manganese dioxide and
magnesium hydroxide on a coke carrier. The
VI - 6
absorbent is screened out of the coke, mixed with coal
and regenerated at 1, 650° F to produce a sulfur-
bearing gas stream that is burned to yield sulfur
dioxide suitable for manufacture of acid or acid
intermediates. The solid absorbent is water-
quenched and recycled.
Availability:
A pilot unit of 8 MW scale was operated in Cologne,
Germany by the sponsor, A.G. fur Zinkindustrie
vorm Wilhelm Grillo. This process like the process
of Reinluft is handicapped by large area requirements
and has probably not been developed to available
status. Ref. (LL)
-------
magnesium sulfur salts (principally MgSO ) are
u
intermediate to the 15% SO, gas product and can be
shipped for sulfuric acid manufacture at a distance,
for example to a central processing plant. The
chemistry is capable of high yield of sulfur oxides
treated since sulfate formation is reduced by the
coke in the calcination step.
Availability:
Some aspects of this process have been in operation
for a number of years in nineteen plants as an adjunct
to magnesium-base sulfite pulping of wood. The
chemistry exploited in the pulp industry is the some-
what weaker magnesium sulfite/bisOtfu- ^/cle but
the SO- absorption and the magnesium sulfite thermal
decomposition are analogous to features of the
magnesium oxide/sulfite cycle. Ref (QQ) This
auxiliary cycle for wood pulping was primarily a
joint development of Babcock and Wilcox Co., the
Weyerhaeuser Co., and the Canadian firm. Howard
Smith Paper Mills, Ltd. Babcock and Wilcox are
believed now to offer commercially for pollution
control a magnesium oxide wet scrubbing system
with SO2 recovery. Ref (Y) (HH)
Control of SO0 emissions from other sources using
£
the magnesium oxide/sulfite slurry in Venturi
absorbers has been pilot plant tested by Chemical
Construction Corporation on the sulfuric acid plant
emission of Olin Mathieson Company. Baltimore,
Maryland, and on flue gas of Canal Electric Co.,
Sandwich, Massachusetts. The scale of these tests
was about 2, 000 SCFM. During the last several
years an active design-development program has
been sponsored by Chemical Construction Corpora-
tion and Basic Chemicals Division of Basic
Incorporated, Cleveland, Ohio. The process is
commercially offered by Chemico-Basic, a joint
venture of these two firms. The Chemico-Basic
process will be installed at the 150 MW Mystic
station of Boston Edison Co. Ref (RR)
This process is the basis for the gas cleaning and
SO concentrating phase of the recovery systems
of CASE C and CASE D, summarized in Part VII
of this volume and presented in greater detail in
Volume Two.
4.4 Concentration of Weak Gases to High (90/100%) Level
Processes of this type have usually been employed for liquid
sulfur dioxide end-product. This compound can serve as
intermediate to sulfuric acid manufacture but is not so far
much used in this way since advantage would accrue only to
the shipping weight relation: 2 tons of liquid SO, will make
about 3 tons of acid. Liquid SO, enjoys a small market other
than for acid making, but the outlook for a large volume of
use appears to depend on increasing demand by acid
manufacturers.
VI - 8
VI - 9
-------
4. 4. 1 Aromatic Amine Absorbents
Chemistry:
Xylidine-water mixtures and dimethyl aniline have
been used as absorbents to concentrate SO, from
dilutions of 3. 5% and stronger. Absorption and
desorption are accomplished on a thermal cycle.
The gas concentrate is of high purity SO, suitable
for liquefaction. The aromatic vapors are recovered
by absorption in sulfuric acid and the resultant
amine sulfates are treated with soda ash to release
the amine. Sodium sulfate is discarded.
Availability:
.nijerican Smelting and Refining Co. installed the
DMA version of this process at three smelter
operations 20-25 years ago. Of these, two are
believed to be still in operation (on 4% SO, gas) but
the plants have remained small since the product
is sold m the liquid SO2 market, a minor factor in
this picture. Dimethyl aniline, xylidene and several
other organic materials, (dimethyl formamide, for
example) that have a substantial solvent capacity for
sulfur oxides may be in general less suitable than
alkali/water systems for treating large volumes of
hot gas at high velocities. The cost of solvent
losses and possible explosion hazard are unfavorable
factors. Ref (VV)
VI - 10
4. 4. 2 Basic Aluminum Sulfate
Chemistry:
This SO9 absorption medium is made by addition of
lime to aluminum sulfate solution to precipitate a
portion of the SO radical whereby the cool, clarified
o
liquor gams relatively great solvent power for SO,
which may be expelled by heating. The product
approximates 100% SO gas.
Availability:
This process, developed by Imperial Chemical
Industries, Ltd., England, was first commercially
used on the copper smelter emission of Outokumpu
Oy at Imatra, Finland in 1936. Ref (SS) The product
was 52 tons per day of 100% SO from 5% SO off gas.
ICI also conducted pilot testing at Billingham,
but this and the Imatra plant have long since been
dismantled. The process is currently operated at
Manchester, England, by Hardman & Holden, Ltd.,
who make 30 tons per day of liquid SO_ from
combustion of sulfur. The Manchester facility was
carefully examined for applicability of this process
to the CASE C and D combustor gases of this study
in order to gain advantage from the highly concentra-
ted SO gas as a feed material for sulfur production.
However, the basic aluminum sulphate concentrating
cycle as now operated is subject to a bothersome
lime-scaling of equipment, and to a considerably
diminished efficiency when used on very weak
VI - 11'
-------
gases. While this process may be the one of choice
for manufacture of liquid SO0 from an intermediate
2
concentration, the process combinations selected
for CASES C and D appear to be a better route to
sulfur making. The basic aluminum sulfate
absorbent may not be suitable for use directly on
coal combustion gases since there is some evidence
that metals such as arsenic, tellurium and antimony
are harmful to it. Ref (HH) (SS)
4. 4. 4 Alkali-Metal Sulfite/Bisulfite
Chemistry:
The principal reactions of the absorption are:
2MOH + SO,,
S0
H20
M2S°3
2MHSO,
H2°
The bisulfite can be steam-stripped to yield SO of
high purity. Ref
-------
Paulsboro, N. J., facility. The process as installed
at Paulsboro is reported to use a regenerative sodium
sulfite system that will recover as SO^ concentrate
not less than 90% of sulfur oxides treated,
and limit the final emission to less than 500 parts
per million. Operating data however have been
insufficient to evaluate this process for the
purpose of this study. Ref (UU)
4. 5 Liquefaction of SO
So far as known liquid SO2 is produced from strong (usually
90 to 100%) gas by cooling, drying, compressing and re-
cooling io -condense the liquid product. Engineering of
this process is readily available from experienced sources.
An effort by Canadian Industries, Ltd. to liquefy SO from
dilute gas was carried into the pilot plant stage but abandoned
because of high power cost. Ref (R)
4. 6 Processes for Output of Elementary Sulfur
Reduction of sulfur dioxide to sulfur has been practiced for
many years with commercialized technology under the
incentive of pollution control leavened by income from sale
of sulfur. A recent, comprehensive review of the state of
the art has been reported to NAPCA by Allied Chemical
Corporation, Ref (GG). The successful processes have
utilized one or another (or more than one) of the four
major reducing agents:
VI - 14
Hydrogen sulfide.
Carbon as coke.
Reformer or producer gas (mixtures of CO and
H derived from natural gas or coke).
Gaseous hydrocarbons, usually natural gas .
4. 6. 1 Reduction of 100% SO by Hot Coke
Chemistry:
Sulfur dioxide from the concentrating plant, diluted
with air to 50/60% SO2 strength, and preheated to
300° C, reacts with coke qualitatively as follows:
+ O
C
C
C
2CO + 2S
CO
2COS
Any moisture or hydrogen present will give rise to
HgS. The reactions are highly exothermic. The
gases leave the coke bed at 800/900° C with some
unconverted SO which is thereupon reacted over a
catalyst with CO, COS and HgS to yield more sulfur.
The liquid sulfur from this process is of high purity.
Availability:
The process was tested by Imperial Chemical
Industries Ltd., at Billmgham, England m a plant
having 5 to 6 tons per day output of sulfur. Develop-
ment work was completed and the unit was shut down
VI - 15
-------
for lack of a profitable outlook as of the late
1930's.
4. 6. 2 Reduction of Dilute SO2 with Producer Gas
Chemistry:
The reducing agents in "producer gas", which is
generally made from coke, are carbon monoxide
and hydrogen generated according to:
CO + H0
Reactions of these agents with SO are somewhat
complex; the following are typical:
so2
S°2 '
CO
C
H0 •
2
S02 -
S02 H
SO, H
4- 2CO } 2CO2
*• 2H0 > 2H->°
2 ^
K S » COS
H 2S » CS2
h S » H0S
2
K 2H2S » 2H2O
1- 2COS » 2CO2
h CS2 » CO,
+ S
+ S
+ 3S
+ 3S
+ 3S
A principal process exploiting this kind of chemistry
generates producer gas by diluting with wet air a
portion of the raw SO -containing smelter gas that
is to be treated, passing this mixture through red
hot coke, recombining the remainder of the raw gas
with the coke-reacted gas, and flowing the whole
over a catalyst to promote the equilibrium products
which are mainly carbon dioxide, water and sulfur,
with small amounts of unreduced sulfides that were
vented in early practice. This tail gas can be
oxidized and recycled in favorable circumstances.
See Part VI 5. 1.
Availability:
The process was developed by Bolidens Gruvaktiebolag,
and operated in their smelter works at Ronnskar,
Sweden, to make 25, 000 tons of sulfur annually
beginning in 1935. Some years later, it was replaced
by a process producing liquid SO- from flue gases of
iron pyrite roasting. Ref (SS)
A similar process was operated for output of 150 tons
per day of sulfur from 1935 to 1943 by Consolidated
Mining and Smelting Co. of Canada, Ltd., at Trail,
B. C. The plant was shut down for market reasons
in favor of direct oxidation of SO2 to ammonium
suLfate and sulfuric acid. Ref (WW)
4. 6. 3 Reduction of SO2 with Methane
Chemistry:
4. 6. 3. 1 A non-catalytic process (ASARCO) has
been developed for the treatment of hot
smelter off-gas containing 5 to 7% SO2
and 12 to 9% O.. Methane sufficient for
reduction of the SO2 and the O2 is added
to the off-gas as it enters a brick checker-
VI - 16
VI - 17
-------
work filled combustion chamber in which
the principal reaction yields carbon
dioxide, water and sulfur:
CO
2H20
Hydrogen sulfide and carbonyl sulfide occur
from side-reactions and are reduced to
sulfur in downstream catalytic reactors.
Sulfur recovery is reported to be 95% in
total. Ref (GG) (R) (XX)
Availability:
The n on-catalytic process (4. 6. 3. 1) was operated from
1940 to 1944 on a semicommercial scale by American
Smelting and Refining Co. High quality sulfur was
produced. Rel (XX) Interest declined for lack of a
profitable sulfur market.
The catalytic process of West was developed by Texas
Gulf Sulfur Co. and International Nickel Company in a
pilot plant. Ref (R)
4.6.3.2 Catalytic processes, especially that of
West (TGS), employ a direct reaction of
methane and SO over a catalyst. A
relatively low temperature is favorable,
and oxygen accompanying the SO., is
proportionately objectionable. Note that
the 15% SO concentrate of CASE C and D
contains very little oxygen and is thus
adapted to the type of catalyzed primary
reaction proposed by West and Yushkevitch
(low space velocities) and Kulcsar
(high space velocity). Ref (GG) The
process employed in the systems of
CASE C and D differs from these in
removing the reform reaction to a separate
zone, and in some other particulars.
(See Part VI 4. 6.4)
VI - 18
4. 6. 4 Reduction of Dilute SO with Reformed Natural Gas
(Methane)
Chemistry:
Since the reducing agents in gas from "reformed"
hydrocarbons are carbon monoxide and hydrogen, as
in producer gas, the reactions with SO are
qualitatively similar. (See Part VI, 4.6.2) The
equilibrium products are carbon dioxide, water and
suliur with minor amounts of volatile sulfides. In a
manner similar to the producer gas process, these
gases are reacted on catalysts to accelerate arrival
at the equilibrium conditions. The catalyzed reaction
of SO with reformed natural gas is the basis of
sulfur recovery from 15To gas concentrate in CASES
C and D and is described in more detail in Volume Two.
In this adaptation the initial reduction yields a mixture
of sulfidesf principally H^S, which together with SO
are thereupon treated in a Claus reactor. Sulfides
VI - 19
-------
remaining in the tail gas are reoxidized to SO. and
returned to the magnesium sulfite/oxide cycle.
Availability;
This process and catalyst have been developed by
Chemical Construction Corporation and pilot tested
at a scale of 25 pounds of sulfur per hour together
with life-testing of the catalyst. Similar work has
been carried out by Allied Chemical Corporation as
part of a comprehensive review of all known SO,
reduction chemistry. Ref (GG)
The reduction of SO with reformed natural gas is
reported by Allied to show "good, and very similar
economics" when compared to the ASARCO high
temperature methane reduction. Allied have
installed a process for sulfur recovery from smelter
gases at Sudbury, Onatrio, Canada, which is believed
to employ reformed natural gas as the reductant for
180, 000 short tons per year of sulfur output.
must be reduced to H_S to prepare the Claus feed-
£i
stock, and if carbon or hydrocarbon is used in this
reduction the occurrence of carbon disulfide (CS )
2,
and carbonyl sulfide (COS) is to be expected, tn a
manner analogous to Claus these compounds are
catalytically reacted with SO to form sulfur. Several
variants of Claus techniques have been developed to
serve particular upstream conditions. All processes
for reduction of SO_ to sulfur appear to require some
application of Claus chemistry.
Availability:
More than 200 Claus units have been put in operation,
for the most part in desulfurization of petroleum
fractions and "sour" natural gas. Engineering
services and catalyst for Claus units are offered by
several firms. Claus units are included in the
systems of CASE C and CASE D in this study.
4. 6. 5 Reduction of SO. with H.S
£i £
Chemistry:
The catalyzed reaction 2H2S + SO2—> 2H2O + 3S
is frequently employed on sources of H,,S. Usually
a portion of the H-S concentrate is burned in air to
2
SO which is remixed with H S in the required ratio.
£t £,
This process is named after the inventor, Claus.
When the primary source is SOg, a portion of it
VI - 20
VI - 21"
-------
5. EMISSION CONTROL
5. 1
5.2
5.3
All sulfur oxide emissions from the five high sulfur
combustor systems analyzed for purposes of this study
are limited by design to less than 100 ppm of volume of
total tail gas emission. CASE C and CASE D systems
provide for recycle of gaseous sulfur compounds from the
Glaus process exit, through the "incinerator" oxidation,
back to the flue gas scrubber and hence to the mam
absorber. However, a very low sulfur fuel, for example,
pipeline gas is needed for the magnesium salts drying
operation since the emission of the dryers goes directly
to the main stack for reheat purposes. See Part XIV.
The systems of CASE A, B and E include small venturi
absorbers, especially provided for tail gas cleanup,
but charged with calcium oxide instead of magnesium
oxide.
Stack heights and stack gas temperatures included in the
designs are intended to limit maximum 24-hour downwind
ambient sulfur oxide concentrations to 0. 1 PPM.
All particulate emissions are subject in the designs to
recommended criteria for control of interstate air
pollution in the Parkersburg, West Virginia-Marietta,
Ohio area as issued by Commissioner John T. Middleton
of the National Air Pollution Control Administration on
March 23, 1970.
VII
SUMMARY OF HSC SYSTEMS
SUMMARY OF THE CASE A SYSTEM
(Refer to diagram following)
A run of mine bituminous coal containing 3 to 4. 5% sulfur,
washable to lFc sulfur, is assumed. The reject is treated for
maximum yield 01 an HSC Fuel of the CASE A specification.
This fuel is pulverized and fired to raise 500, 000 Ibs/hr of
industrial quality steam and a flue gas containing 6% sulfur
dioxide and 4. 3\ oxygen. The gas is wet cleaned in a packed
tower, dried and converted catalytically to sulfur trioxide
which is reacted with water to make 987» sulfunc acid at the
rate of 1, 830 net tons (100^, basis) per day, 330 days per
year. Sulfur emission equals 0. 4{Fc of sulfur charged.
Sulfur not emitted equals 93 pounds per million Btu of heat
recovered in the CASE A System, or 2. 2 pounds per million
Btu of ROM coal charged to the cleaning plant.
CASE A is described in greater detail in Volume Two,
Part XIII.
VII - 1
VI - 22
-------
HIGH SULFUR COMBUSTOR STUDY
FUEL PREPARATION
ROM
JZ51
DRY BOTTOM COMBUSTION
»6»» 10* BTlVHH
MET HIAT OUTPUT
SULFURIC ACID PLANT
(2 TRAINS)
CASE A
ENERGY
PRODUCT
STEAM
900,000 LBS/HR
829* F 900/PSIG
TO TAIL 6AS
SCftUWINO
TRAJN
CLEAN COAL
BLEND DRY
a
CLEANING PLANT GRIND
FUELS COMPOSITION
WT. % DRY BASIS*
STEAM
BOILER
ASH SCRUBBER E.M.R
DISPOSAL
GAS COMPOSITION
VOL. % DRY BASIS
DRYER
CONVERTER ABSORBER
RUN OF
MINE
IRON PYRITE
ORGANIC SULFUR
TOTAL SULFUR 3 TO 4.9
COAL COMBUSTIBLES
NON-PYRITIC ASH
M TONS/YEAR
TONS/HR: IRON PYRITE
COAL COMBUSTIBLES
NON-PYRITIC ASH
SULFUR/COAL RATIO
BTU/LB
BTU/HR
CLEAN HSC
COAL FUEL
61.6
1.0 0.2
1.0 03.1)
18.2
ZOO
64O.O
493
147
I&O
1.8
4420
700 »IO*
SO*
SO,
02»»
COa
N2
HjO
TEMP.'F
M SCFM
ASH:
TONS/HR
% Ft
EXIT FURNACE
6.0
0.2
4.3
8.6
80.9
4.0
90O
177
48.8
47
FEED TO
CONVERTERS
5.0
7.1
7.2
80.7
205
STORAGE SHIPPING
CHEMICAL
PRODUCT
COMMERCIAL
GRADE 98 %
SULFURIC ACID
1830 TONS/DAY
100% BASIS
6% MOISTURE ASSUMED IN HSC FUEL AS FIRED
25% EXCESS COMBUSTION AIR
xu-2
-------
2. SUMMARY OF THE CASE B SYSTEM
(Refer to diagram following)
A run of mine bituminous coal containing 3 to 4. 5% sulfur,
washable to 1% sulfur, is assumed. The reject is treated for
maximum yield of an HSC Fuel of the CASE B Specification.
This fuel is pulverized and fired to raise 500, 000 Ibs/hr of
industrial quality steam and a flue gas containing 2% sulfur
dioxide and 4. 2% oxygen. The gas is cleaned of particulates
in an electric precipitator at 805° F and is then converted
catalytically to sulfur trioxide which is reacted with water to
make 77/80% sulfuric acid by the Cat-Ox process of
Monsanto at the rate of 624 net tons (100% basis) per day,
330 days per year. Sulfur emission equal 0 5% of sulfur
charged. Sulfur not emitted equals 33 pounds per million
Btu of heat recovered in the CASE B System, or 2. 0 pounds
per million Btu of ROM coal charged to the cleaning plant.
CASE B is described in greater detail in Volume Two,
Part XIV.
VII - 3
-------
HIGH SULFUR COMBUSTOR STUDY
CASE _B_
ENERGY
PRODUCT
STEAM
500,000 LBS/HR
825 F 900 PS16
FUEL PREPARATION
DRY BOTTOM
COMBUST I ON
ROM
PRECIPITATOR CONVERTER
MIST
ELIMINATOR
CLEAN COAL
CLEANING PLANT
FUELS COMPOSITION
WT % DRY BASIS*
v—
MONSANTO
CAT-OX
GAS COMPOSITION
VOL % DRY BASIS
IRON PYRITE
ORGANIC SULFUR
TOTAL SULFUR
COAL COMBUSTIBLES
NON PVR 1 TIC ASH
M TONS/YEAR
TONS/HR: FlS,
COAL
ft-P ASH
SULFUR/COAL RATIO
BTU/LB
BTU/MR
RUN OF CLEAN HSC
MINE COAL FUEL
33.8
0.5
3 TO 4.5 08.51
45.7
20.0
406
17.1
23.4
10. 1
0.4
7400
790 » I0e
so*
EXIT
FURNACE
2.0
SO,
O.I
4.2
CO;,
I4.O
J8z_
H20
TEMP»F 809
M ACFM 445~
* 6% MOISTURE ASSUMED IN HSC FUEL AS FIRED
M SCFM I 73
ASH
TON/HR 21.6
% FE 37
•NOMINAL MOISTURE CONTENT 4%
TO TAIL GAS
SCRUBBING
TRAIN
1
SHIPPING
CHEMICAL
PRODUCT
COMMERCIAL
GRADE 77/80%
SULFURIC ACID
624 TONS/DAY
IOO% BASIS
Stt-4
-------
3. SUMMARY OF THE CASE C PROTOTYPE SYSTEM
(Refer to diagram following)
A run of mine bituminous coal containing 3 to 4. 5% sulfur,
washable to 1% sulfur, is assumed. The reject is treated for
maximum yield of an HSC Fuel of the CASE C and D
specification. This fuel is pulverized and fired to raise
500, 000 Ibs/hr of subcritical steam which is fed to a turbo-
generator of 50 MW capacity. The flue gas containing about
1% sulfur dioxide and 4. 3% oxygen is wet-cleaned in a venturi
scrubber and led to a two-stage-ventun absorber in which
sulfur dioxide is reacted, essentially with magnesium oxide,
to produce magnesium sulfite. This salt is separated, dried,
and calcined to yield a 15"^ sulfur dioxide gas concentrate and
magnesium oxide which is recycled. The 15fo sulfur dioxide
is converted by catalytic reduction "to sulfur at the rate of
about 100 net tons per day, 330 days per year. Sulfur
emission equals 1. 3% of sulfur charged. Sulfur not emitted
equals 16 pounds per million Btu of heat recovered in the
CASE C Prototype System, or 2. 2 pounds per million Btu of
ROM coal charged to the cleaning plant.
CASE C is described in greater detail in Volume Two,
Part XV
VII - 5
-------
HIGH SULFUR COMBUSTOR STUDY
FUEL PREPARATION
DRY BOTTOM COMBUSTION GAS CLEANING 8 S02 ABSORPTION
S02 REGENERATION
ROM
551 x I06 BTU/HR
NET HEAT OUTPUT
r*
CLEAN COAL
FUELS COMPOSITION
WT % DRY BASIS*
RUN OF
MINE
CLEAN
COAL
IRON PYRITE
HSC
FUEL
20.8
FLUE GAS
VOL 70
DRY BASIS**
ASH
COMPOSITION
CALCINER
EMISSION
ORGANIC SULFUR
1.0
TOTAL SULFUR
3 TO 4.5
_06_
(11.7)
S0t
1.15
%Fc
29
NON-PYRITIC ASH
ae.s
so.
15.9
ZOO
SO,
"t
0.05
4.3***
TONS/HR
12.6
MM TONS/YEAR
298.0
CO,
1 5.4
CO,
13.6
TONS/HH: IRON PYRITE
7.7
N2
79.1
70.5
COAL COMBUSTIBLES
22.0
TEMP'F
NON PYRITIC ASH
SULFUR/COAL RATIO
7.4
5.QQ
MACFM
308
COMPRESSION
0.2
MSCFM
167
BTU/LB
BTU/HR
9000
670x10*
****MAGNESIUM SALTS MAY BE
SHIPPED BEFORE PROCESSING
*6% MOISTURE ASSUMED IN HSC FUEL AS FIRED
"NOMINAL MOISTURE
CONTENT 4%
•**25% EXCESS COMBUSTION AIR
-------
HIGH SULFUR COMBUSTOR STUDY
GAS CLEANING & S02 ABSORPTION SOZ REGENERATION
REDUCTION TO SULFUR
A
>D
V
X
REF
(NA1
— *
'OR MING
rURAL GAS)
1
(1
CLAUS
REACTION
1)
SOz
COMPRESSION REDUCTION SHIPPING
ASH DISPOSAL
FLUE GAS
VOL %
DRY BASIS*
MgO/MgSOj CYCLE
ASH
COMPOSITION
CALCINER
EMISSION
SOt
1.15
%Fe
29
15.9
SO, 0.05 TONS/HR 12.6
0,' 4.3 »**
CO, 1 5.4
Hi 79.1
TEMP»F 50Q
MACFM 308
MSCFM 167
C0t 13.6
N2 70.5
****MAGNESIUM SAL
SHIPPED BEFORE PROCESSING
*NOMINAL MOISTURE
CONTENT 4%
EXCESS COMBUSTION AIR
PROTOTYPE
SYSTEM
CASE C.
ENERGY
PRODUCT
ELECTRICITY
50MW CAPACITY
CHEMICAL
PRODUCT
COMMERCIAL
GRADE
SULFUR
102 NET TONS/DAY
-------
4. SUMMARY OF THE CASE D SYSTEM
(Refer to diagram following)
A run of mine bituminous coal containing 3 to 4. 5% sulfur,
washable to 1% sulfur, is assumed. The reject is treated for
maximum yield of an HSC Fuel of the CASE C and D specifica-
tion. The fuel is pulverized and fired to raise 3. 5 million
pounds per hour of subcritical steam which is fed to a turbo-
generator of 500 A1\V capacity. The flue gas composition is
identical to that of CASE C and is treated in an identical
manner to yield 770 net tons per day of sulfur. Sulfur
emission equals 0. 8ro of sulfur charged. Sulfur not emitted
equals 16 pounds per million Btu of heat recovered in the
CASE D System, or 2. 3 pounds per million Btu of ROM coal
charged to the cleaning plant.
CASE D is described in greater detail in Volume Two,
Part XVI.
VII - 7
-------
FUEL PREPARATION
DRY BOTTOM COMBUSTION
4.220x10° BTU/HR
NET HEAT OUTPUT
GAS CLEANING a S02 ABSORPTION S02 REGENERATION
(4 TRAINS)
(3 TRAINS)
ROM
CLEAN COAL
COMPRESS)'
RUN OF
M INE
IRON PYRITE
ORGANIC SULFUR
TOTAL SULFUR 3 TO 4.5
COAL COMBUSTIBLES
NON PVRITIC ASH
M TONS/YEAR
TONS/HR: IRON PYRI TE
COAL COMBUSTIBLES
NON PYRI TIC ASH
SULFUR/COAL RATIO
BTU/LB
BTU/HR
CLEAN HSC
COAL FUEL
20.8
0 6
(11.7)
56.6
20.0
2280
59.3
338.0
57.0
0.2
9000
5.128 «IOe
FLUE GAS
VOL %
DRY BASIS
SOz O.I
SO,
0.05
ASH CALC 1 NER
COMPOSITION EMISSION
%FE 29 SO? 15.9
TONS/HR 96.5
Oz 4.3 *ll»
COt 15.4
N2 79.15
TEMP'F
MACFM
MSCFM
""NOMINAL
CONTENT
50O
2,050
1,110
MOISTURE
4%
C02 13.6
N2 70.5
**** MAGNESIUM SALTS MAY BE
SHIPPED BEFORE PROCESSING
*6% MOISTURE ASSUMED IN HSC FUEL AS FIRED
K25% EXCESS COMBUSTION AIR
-------
COMBUSTION
GAS CLEANING S S02 ABSORPTION S02 REGENERATI ON
(4 TRAINS)
(3 TRAINS)
REDUCTION TO SULFUR
(2 TRAINS)
O-- CASE D.
ENERGY
PRODUCT
ELECTRICITY
REFORMING
(NATURAL GAS)
500 MW CAPACITY
COMPRESSION REDUCTION SHIPPING
FLUE GAS
VOL %
DRY BASIS**
SOz
O.I
_SOj_
0.05
4.3*"
19.4
TEMP'F
500
MACFM
2.050
MSCFM
I.IIP
NOMINAL MOISTURE
CONTENT 4%
ASH
COMPOSITION
%FE
29
TONS/HR 96.5
CALCINER
EMISSION
SO,
15.9
CO,
13.6
MAGNESIUM SALTS MAY BE
SHIPPED BEFORE PROCESSING
CHEMICAL
PRODUCT
COMMERCIAL
GRADE
SULFUR
770 TONS/DAY.
'25% EXCESS COMBUSTION AIR
3ZH-8
-------
5. SUMMARY OF THE CASE E SYSTEM
(Refer to diagram following)
A run of mine bituminous coal containing 3 to 4. 5% sulfur,
washable to 1% sulfur, is assumed. The reject is treated for
maximum yield of an HSC Fuel of the CASE E specification.
This fuel is pulverized and fired to raise 3. 5 million pounds
per hour of sub-critical steam which is fed to a turbo-
generator of 500 MW capacity. The flue gas containing 0. 7%
sulfur dioxide and 4. 2% oxygen is treated by the Monsanto
Cat-Ox process in a manner similar to CASE B, but in
multiple trams, to yield 1, 420 net tons (100% basis) of
77/80% sulfunc acid per day. Sulfur emission equals 1. 5%
sulfur ch"-7°d. Sulfur not emitted equals 10 pounds per
million Btu recovered in the CASE E System, or 2. 3 pounds
per million Btu of ROM coal charged to the cleaning plant.
CASE E is described in greater detail in Volume T*o,
Part XVII.
VII - 9
-------
HIGH SULFUR COMBUSTOR STUDY
CASE E_
ENERGY
PRODUCT
ELECTRICITY
500 MW CAPACITY
FUEL PREPARATION
DRY BOTTOM
COMBUST I ON
MIST
ELIMINATOR
ROM
PRECIPITATOR CONVERTER
4Z2O i IO* BTU/Hft
NET HEAT OUTPUT
TO TAIL GAS
KRUMIUA
TKAIN
CLEAN COAL
™r^^~Tm*
SHIPPING
MONSANTO
CAT-OX
FUELS COMPOSITION
WT % DRY BASIS*
GAS COMPOSITION
VOL % DRY BASIS
IRON PYRITE
ORGANIC SULFUR
TOTAL SULFUR
COAL COMBUSTIBLES
NON PYRtTIC ASH
M TONS/YEAR
TONS/HR: FiSg
COAL
N-P ASH
SULFUR/COAL RATIO
BTU/LB
BTU/HR
RUN OF CLEAN HSC
MINE COAL FUEL
13.2
0.9
3 TO 4.5 (7.9)
65.9
20.0
2133
35,2
178.0
53.3
0.12
9*60
5l50x 10"
so,
EXIT
FURNACE
0.7
SO,
0.02
2*_
4.2
C02_
15.9
Ni_
79.18
TEMP*F 650
M ACFM SO8O
M SCFM 1160
ASH
TON/HR 76.7
PRECIPITATORS
CONVERTERS
ECONOMIZERS
AIM HEATERS
AMCMIN8 TOWERS
MIST ELIMINATORS
NO. OF
UNITS
6
12
6
3
3
3
CHEMICAL
PRODUCT
COMMERCIAL
GRADE 77/60%
SULFURIC ACID
1420 TONS/DAY
100% BASIS
* 15% MOISTURE ASSUMED IN HSC FUEL AS FIRED
•'NOMINAL MOISTURE CONTENT 4%
2n-io
-------
VIII
ECONOMIC EVALUATION
1. METHOD
The High Sulfur Combustor is conceived as a salvage system to
: improve the economics of coal cleaning by the sale of energy and
| sulfur value extracted from the reject fraction. Sales income,
j less all costs of extraction and other expense, is a basis for
I , valuation of the HSC Fuels at the point of use of such fuels. The
"point of use" would normally be input to the pulverizing mills
but these fuels may have been milled to p. c. size prior to clean-
ing (see p. II-3). If so, the fuel would be fired directly in
modified equipment. In any event, some costs will have been
incurred upstream of this point of use during preparation of the
HSC FuelTrom \ne reject material, and for transportation,
storage and handling. Note, however, that these costs are partly
or wholly offset by the alternative cost of dumping all the reject
material.
1. 1 Valuation Formula
The HSC Fuel valuation formula adopted for the purpose
of this study can be summarized as follows:
HSC Fuel Value = SV - SE - EC - G&T - PTH + D
Where SV = Sales Value
SE = Selling and Commercial Expense
EC - Extraction Cost
G&T = General Expense and Income Tax
PTH = HSC Fuel Preparation, Transport and
Handling ("Precombustion" costs)
D = Cost of Dumping Refuse
VIII - I'
-------
1.2 Precombustion Costs vs. Dumping
Of the several terms in this valuation formula the last two
are least amenable to estimation out of context. The
composition of the coal to be cleaned, the characteristics
of the operating locality, proximity of the combustor to
the cleaning plant, are all cost determinants of importance.
While the cost of coal washing is not a term in the formula
it is nevertheless suggestive: 42£ per ton of clean coal
(at 90% yield) Ref (F), up to 76
-------
2. 2. 3
2.2 Costs of Operation or "Extraction"
2.2. 1 The utilities group of cost elements is largely
dependent on the cost of various energy forms.
Electricity is entered at 7. 5 mills/Kwh, the
same as estimated sales value discussed in a
later paragraph. The designs of the sulfur recovery
trams of CASE C and D require low-sulfur oil or
gas for magnesium sulfite drying, oil or gas that
may be high-sulfur for calcination, and a light
hydrocarbon fuel for reforming to effect SO
reduction. CASE B and E require gaseous fuel for
acid concentrating. Heat energy for these various
uses is costed at 40£ per million Btu in the
estimates. By comparison the average delivered
cost of steam coal reported by the American Coal
Association for the six-state area was 23. 8<; per
million Btu in 1969 -- probably about 25£ in late
1970. Steam where needed for process is entered
at the estimated sales value of $1. 30 per ton. No
credit is taken or given for condensate return
except for the high recovery of condensate from
the generator drives.
2.2.2 Operating labor and supervision are entered at the
high end of rates expected in 1971.
VIH - 4
2. 2.4
2. 2. 5
Maintenance cost estimates are based on FPC
studies of furnace and electric equipment
(adjusted upward for near future conditions on the
advice of Ebasco Services, Inc. and Foster
Wheeler Corporation). Maintenance of the sulfur
recovery equipment is entered at 4% annually of
the depreciable capital cost.
Local taxes and insurance, as operating cost
elements, will continue to increase in dollar amounts
as a function of fixed and working capital, and
probably at increasing rates, especially local taxes.
\
The cost of money is given effect in the operating
estimates at 9% annually on undepreciated invest-
ment as the resultant of estimates as follows:
Internal Capital
Debt Capital
Equity Capital
20% @ 7%
60% @ 7%
20% @ 15%
Average
1.40
4. 50
3.00
8.90%
Depreciation is figured, straightline, at 3. 6% (28
year life) on furnace and electric equipment, and
9. 1% (11 year life) on the flue gas treating trains;
that is the chemical equipment. These are
"guideline" rates from IRS Publication #456.
Capital (and capital related) charges to operations
are thus in the range 13 to 16% of total investment
annually. The variation within this range results
from the two depreciation rates.
vrn - 5
-------
TABLE VIII-2
CASE A SYSTEM
2.2.6 Product Costing Basis
In Tables VIII-2 through VIII-6 the estimated cost
of operation or extraction (that is "EC" in the
valuation formula) of each of the five systems is
set up in the conventional manner except that no
charge is entered for the HSC Fuel. Additionally,
since each system yields two products, energy and
sulfur value, an effort is made to cost each product
separately. For this purpose the combustor/
generator operation, that is, -everything up stream
of the cooled flue gas, is cliarged to energy output,
and the SO recovery train, donmstream of tfa'e
£
cooled flue gas, is charged to recovered sulfur
value. CASE B and E systems recycle some iheat
value from the acrd -converters back to the boilers.
An adjustment is entered for this.
[ ESTIMATED OPERATING COST
STEAM
Unit
Production
Energy N. T.
Sulfur Value N. T.
Utilities, etc.
Electricity MWH
t Cooling Water MMgal.
' Boiler Feed
Water Mgal.
Process Water Mgal.
Steam N. T.
Chemicals
Waste Disposal N. T.
Labor
Unit Units
Value Per Year
2, 000, 000
$7.50 6,080
8. 00
0. 60 475
0.40
1. 30
2. 00 390, 000
Supervision Manhour 8. 00 4, 380
Operators and
Helpers Manhour 5.50 15, TOO
Maintenance
Plant General Ejqpense
Factory
Overhead 80% of Direct Lateor
Taxes and
insurance 2. S% of
i
Total Before Depreciation and
Depreciation
Total Capital
Interest M
Guideline Life 11 Years 9.1%
Interest (Average)
Depreciable Capital
Non-Depreciable Capital
Cost Before HSC Fuel Charge
4. 9?o
9 5>
(Rounded) M
Annual
Cost
MS 46
285
780
35
83
140
66
152
$1,587
S64
275
17
$2,_540
SULFURIC ACID
Units Annual
Per Year Cost
610, 000
24,630 M$ 185
1,400 11
9 40
389, 000 506
413
120, 000 240
4, 380 35
11,000 61
450
49
306
M $2,296
970
533
17
M $3, 820
VIII - 6
VIII - 7
-------
TABLE VIII-3
TABLE VIII-4
CASE B SYSTEM
ESTIMATED OPERA TING COST
STEAM SULFURIC ACID
Unit Units Annual Units
Production
Energy
Sulfur Value
Utilities, etc.
Electricity
Cooling Water
Boiler Feed Water
Fuel Gas
Catalyst
Chemicals
Waste Disposal
Labor
Supervision
Operators and
Helpers
Maintenance
Unit
N.T.
N.T.
MWH
MMgal.
Mgal.
MMBtu
N.T.
Annual
i^aoc. \~ DiQijKm
I ESTIMATED OPERATING COST
, ELECTRICITY
Value Per Year Cost Per Year Cost !
$7.
8.
0.
0.
2.
Manhour 8.
Manhour 5.
2,
50
00
60
40
00
00
50
000, 000
208, 000
5, 000 MS 38 115, 400
2, 854
479, 000 287
294, 000
140,000 280 20,350
4, 380 35 4, 380
15, 000 83 11, 000
140
M$ 870
23
118
25
194
41
35
61
464
Plant General Expense
Factory
Overhead
Taxes and
Insurance
80% of Direct
2. 5% of
Total Before Depreciation and
Depreciation
Guideline Life
Interest (Average)
Total
Labor
Capital
Interest
11 Years 9. ITo
Depreciable Capital
Non -Depreciable Capital
Cost Before HSC Fuel
Charge
4. 5%
9
%
— 66
113
M $1,042
553
274
10
49
351
$2,231
1, 109
548
21
| Production
Energy
Sulfur Value
i Utilities, etc.
Electricity
: Cooling Water
, Boiler Feed Water
Process Water
i Fuel Gas
1 Chemicals
Waste Disposal
1 Labor
Supervision
Operators and
j Helpers
Maintenance
Unit
MWH
L. T.
MWH
MMgal.
Mgal.
Mgal.
MMBtu
N. T.
Manhour
Manhour
Unit Units
Annual
Value Per Year Cost
$7.
8.
0.
0.
0.
2.
8.
5.
400, 000
50 3, 360
00 21,600
60 5
40
40
00 110,000
00 8, 760
50 44, 000
M$ 25
173
3
220
70
242
280
SULFUR
Units Annual
Per Year Cost
30, 910
37, 360 M$ 280
268 2
113,000 45
2, 100, 000 840
81
25, 400 51
8, 760 70
32, 000 176
430
j Plant General Expense
Factory
Overhead
| Taxes and
Insurance
80% of Direct
2. 5% of Total
Labor
Capital
1 Total Before Depreciation and Interest
!
Depreciation
1 Guideline Life
( Guideline Life
Interest (Average)
11 Years
28 Years
j Depreciable Capital
1 Non -Depreciable Capital
(Rounded)
M $*. 880
M $3, 910
) Cost Before HSC Fuel
9. 1
3. 6
%
%
4.5%
9
%
194
403
M$l, 610
578
723
153
Charge (Rounded) M$3. 060
141
329
M$2, 445
1, 174
581
126
M$4,_330
VIII - 8
VHI - 9
-------
TABLE VIII-5
TABLE VIII-6
CASE D SYSTEM
CASE E SYS TEM
ESTIMATED OPERATING COST
ELECTRICITY SULFUR
Production
Energy
S ulfur Value
Utilities, etc.
Electricity
Cooling Water
Boiler Feed Water
Process Water
Fuel Gas
Chemicals
Waste Disposal
Labor
Supervision
Operators and
Helpers
Maintenance
unit
MWH
L.T.
MWH
MMgal.
Mgal.
Mgal.
BtuxlO
N. T.
Manhour
Manhour
Unit Units Annual Units
Value Per Y
4, 000,
$7. 50 24,
4. 00 86,
0. 60
0.40
400.
2. 00 853,
8. 00 8,
5. 50 65,
;ar ^USL rcr i.car
000
233, 300
M
000 $ 180 282, 300
400 346 4, 000
50 30 6
852, 000
17, 830
100
800 1, 708 192, 000
760 70 8, 760
000 360 48, 000
1, 080
Annual
Cost
M
$ 2, 117
16
4
341
7, 132
535
384
70
264
1, 760
Plant General Expense
Factory
Overhead
Taxes and
Insurance
80% of Direct Labor
2. 5% of Total Capital
Total Before Depreciation and Interest
Depreciation
Guideline Life
Guideline Life
11 Years
28 Years
Interest (Average)
Depreciable Capital
Non-Depreciable Capital
Cost Before HSC Fuel
9. 1%
3.6%
4.5%
9 %
Charge (Rounded)
288
1, 992
M$6, 154
2, 816
3, 545
81
M$12, 600
211
1, 221
M$14, 055
4, 353
2, 173 i
50
M$20, 630
Production
Energy
Sulfur Value
Utilities, etc.
ESTIMATED OPERA TING COST
ELECTRICITY
Unit
MWH
N. T.
Electricity MWH
Cooling Water MMgal.
Boiler Feed Water Mgal.
Fuel MMBtu
Chemicals N.T.
Waste Disposal N. T.
Labor
Supervision
Operators and
Helpers
Maintenance
Manhour
Manhour
Unit Units
Value Per Year
4, 000, 000
$7. 50 20, 000
4.00 86,400
0. 60 50
0.40
2.00 614,000
8. 00 8, 760
5. 50 65, 000
Annual
Cost
M$ 150
346
30
100
1, 228
70
360
1, 080
SULFURIC ACID
Units Annual
Per Year Cost
473, 300
222, 000 M$ 1, 665
26, 500 106
730, 000 292
505
492, 000 984
8, 760 70
16, 000 880
1, 668
Plant General Expense
Factory
Overhead
Insurance
80% of Direct Labor
2. 5% of Total Capital
Total Before Depreciation and Interest
Depreciation
Guideline Life
Guideline Life
Interest (Average)
11 Years
28 Years
Depreciable Capital
Non -Depreciable Capital
Cost Before HSC Fu
9. 1%
3. 6%
4.5%
9.0%
el Charge (Rounded)
288
1, 883
M$ 5, 535
2, 673
3, 342
76
M$ll. 630
704
1, 256
M$ 8, 130
4, 541
2, 246
51
M$14, 970
VIII - 10
VIII - 11
-------
2.2.7 Pollution Control
The foregoing product costing basis is oversimplified
to the extent that it leads, as expected, to an apparent
low cost of energy extraction and a high cost of sulfur
value recovery. But, of course, it does not follow
that the energy alone could be produced and sold while
avoiding the cost of sulfur value recovery, or at least
the cost of pollution control, since in any event the
SO- and particulate matter will have to be cleaned out
£
of the combustion gases. A separate estimate of the
cost of "pollution control" has therefore been developed
for each system sufficient to reduce the fly ash and the
SO_ to wet inert solid material for dumping. The
2 ' '
estimates reflect the use of venturi-type scrubbers
circulating calcium oxide slurry to capture particulate
matter virtually completely and reduce the final stack
emission of SO, to less than 200 ppm. The estimated
investment and annual operating cost applicable to the
combustion gas of each system is as shown in Table
VIII-7.
Note particularly that both investment and operating
costs exhibited in Table VIII-7 are very high by com-
parison to pollution control costs on conventional coal-
fired steam generators of similar sizes, even though
flue gas volumes are not greatly different. Investment
cost differences result principally from the multi-stage
scrubbing required to reduce these high SO- concen-
trations to an acceptable level, and provide equipment
for handling waste solids several times greater than
usual. The higher operating costs are mainly a result
of calcium oxide cost and waste disposal cost.
VIII -12
El - MIA
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-------
2. 3 Sales Value of Products
Unit prices of HSC products that are given effect herein,
have been determined by a canvass of buyers and vendors
now in business in the six-state area.
2. 3. 1 Steam of 825° F and 900 psig at the rate of 500, 000
Ibs/hr is a product of CASE A and CASE B to be
consumed at the producing site or close thereto.
While low pressure steam is sold as a public
utility in cities, for example Chicago, Rockford,
Indianapolis, to schools, hospitals, small industry
and the like, the steam is usually a bleed product
from generator drive-turbines, and the cost of
distribution is too great for any but densely
populated areas. Most of the steam now sold in
this way is distributed through long existing pipe
facilities. Prices appear to vary from $1. 20 to
$3. 00 per ton depending on quantity and load
factor.
The realistic market possibility is an existing
sfeam-electric plant or a large industrial
consumer, more likely the latter. Chemical and
. metallurgical works are typically users of steam
in substantial quantities. Questions concerning
steam use and value were made a feature of the
field inquiry into sulfur and sulfuric acid manufac-
ture and use. Much of the traffic in industrial steam
involves payment with off-gases, petroleum
residues and the like, but a consensus favors the
neighborhood of $1. 30 per ton for near future real
value. This figure is used.
2. 3. 2 Electricity is priced for sale at $7. 50 per mega-
watt hour, (7. 5 mills/kwh) as a median between
a generally prevailing level of $9. 00 for peak
power and $6. 00 for off-peak. Both values will
move upward with increase in fuel and other costs,
but certainly less fast than the increases expected
in new plant costs. A negotiated sale of power in
the six-state area would reflect the demand pattern
of the expected resale market. Substantial differ-
ences prevail between urban and rural, north and
south.
2. 3. 3 Sulfur was shown in Figure III-3 to be consumed at
a rate approaching 10 million long tons per year in
the U.S. Of this amount about 7 million long tons
was produced from U.S. Frasch process sources,
down about 5% from 1969. At the same time
Canadian production increased about 0. 6 million
long tons over 1969 to a 1!)70 total of 4. 4 million
long tons. A pattern of declining U.S. and Mexican
production of newly mined sulfur and increasing
recovery of by-product sulfur in Canada and in the
U.S. is expected to continue indefinitely, [n 1970
for the first time total world output of recovered
sulfur exceeded Frasch process output. But
VIII - 14
VIII - 15
-------
whatever the source of elementary sulfur, more than
90% of production is converted to sulfuric acid and
used as such; and the recovery of sulfuric acid
directly from waste acids and waste SO is also in
an up-trend that will continue indefinitely. These
trends, now visible in initial stages, are in large
part a consequence of the effort to control emission
of sulfur oxides from furnaces, smelters and the
like. As this effort continues and gains in scope, a
very extensive change will occur in the historical
basis for sulfuric acid production. With the
exception of elementary sulfur recovered during
the preparation of sour natural gas for market,
Frasch process sulfur has been the least costly
source; an extr?r'"in cost of $7 per long ton has
been estimated for sulfur from the best Gulf Coast
mines. Sulfur from sour gas was offered at $C9. 33
per long ton f.o.b. Alberta, Canada in late 1970.
The actual cost of sulfur recovery from sour gas
is usually less than this. With this background
recent delivered prices of sulfur were as follows:
Gulf Region
Tampa Area
Atlantic Seaboard
No. Central States
VUI - 16
Per LT
Delivered
$25 - $27
27 - 29
29 - 35
24 - Plus
Sulfur delivered to the six-state area of special
interest in this study (Pennsylvania, Ohio, West
Virginia, Kentucky, Indiana and Illinois) originates
mostly in Alberta for the north and west of this
region and Gulf Coast sources for the south and
east. Late 1970 delivered prices of Canadian
sulfur were:
Chicago, 111. )
Madison, Wise. )
Hammond, Ind. )
Detroit, Mich. )
St. Louis, Mo. )
Cleveland, Ohio )
Cincinnati, Ohio )
Per LT
Delivered
S24. 51
$26. 75
S28.09
All the foregoing were based on $U.S. 9. 50 per LT
f.o.b. Alberta, Canada. Sulfur shipments to such
points have increased steadily from 568, 000 long
tons in 1964 to 907, 000 long tons in 1969. Delivered
prices of sulfur in the south and east of this region
reflect a Gulf Coast price of about $25 per long ton
plus $3 to $5 delivery cost. Deliveries are mostly
as liquid by barge to producers' barge terminals
and locally by tank truck.
The six-state region may consume upwards of
1, 000, 000 long tons per year of sulfur in acid
making. See Table VIII-1. A sulfur recovery unit
such as CASE D, capable of producing 233, 000 long
VIII - 17
-------
tons per year can account by itself for one fifth or
more of this requirement. A new source of supply
of such magnitude will depress sulfur price in these
areas even against the general price inflation looked
for in the next few years. Note, however, that Gulf
Coast sulfur vendors have retreated rather than
compete in a drastic price war with Canadian
imports. The sticking point, for example at
Cincinnati, appears now to be about $28 per long ton
corresponding to a Gulf Coast price of $23. Continued
pressure may result in some reduction in this level
but fact and opinion combine to indicate that
domestic price will not go below $20 f.o.b. Gulf
port. This view is confirmed by private communica-
tion with two major sulfur vendors. Accordingly,
the sulfur sales value given effect in this study is
$25 per long ton delivered to points in the six-
state area.
61 - II1A
VIII - 18
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2.3.4 Sulfuric Acid
The versatility and low cost of this product have made
its usefulness almost coextensive with all industrial
activity; the long term growth of consumption has
substantially exceeded the growth of GNP. The six-
state area is not a huge consumer of sulfuric acid,
however, since more than 40% of U.S. production
(See Table VIII-9) is used in phosphate fertilizer
manufacture which is practiced only m Illinois of the
six-states. The outlook for growth of consumption in
this area during the 1970's is now estimated at 3 to
5% annually even though some important uses are
declining and will probably continue to decline.
2. 3. 4. 1 The major end-uses of sulfuric acid in
the six-states are as follows:
Phosphate rock processing for fertilizer
may consume as much as 70% of the
sulfuric acid made in Illinois which is,
by reason of this single demand, the big
acid producer among the six-states. This
use thus accounts for 1. 2 million tons per
year; but is currently declining with the
general decline in fertilizer use in recent
years. This trend is not expected to
continue for long.
VIII - 20
All of the rock processors in Illinois are
also manufacturers of sulfuric acid.
Ammonium sulfate, is made from coke-oven
ammonia in Pennsylvania, West Virginia,
Indiana and Ohio, and is made also in the
area as a byproduct of caprolactam
manufacture. A big drop in sulfuric acid
price might slow down the declining output
trend in this product, demand for which is not
brisk since it is mainly a source of nitrogen
for fertilizer and rather dilute for this
purpose. Even so ammonium sulfate may
account for 400, 000 tons per year of sulfuric
acid consumption m the six-states.
Coke-oven ammonia is treated alternatively
with phosphoric acid to make diammonmm
phosphate, a concentrated and popular
fertilizer. This practice may grow and
ultimately increase demand for coke-oven
ammonia for fertilizer. If so the use of
sulfuric acid will be sustained since the
tonnage required is about the same for either
the phosphate or sulfate salt of ammonia.
The use of sulfuric acid for iron and steel
pickling is still large in Pennsylvania,
Indiana and Ohio although hydrochloric acid
is invading this domain and probably now
VIII - 21
-------
accounts for 30% of total pickhng acid.
Hydrochloric acid, initially used as a
substitute during the period of rapidly
increasing sulfuric acid price (1965-1969),
is now claimed by many to do a better job.
Probably the expected lower, future cost
levels of sulfuric acid will slow down or
reverse the trend to hydrochloric. Sulfuric
acid consumption for pickling is estimated
at 600, 000 tons per year in the six-states.
Petroleum refining and Petrochemistry
consume sulfuric acid as a catalyst in
production of alkylates (antiknock compounds)
for gasoline, and in sulfonation of lube oils.
Alkylation spent acid is usually reworked,
but net sulfuric acid consumption for this
purpose should increase as the use of
alkylated lead compounds gives way to
growing pressure for pollution abatement.
Sulfuric acid is also used to make hydro-
fluoric acid which, among many uses, is in-
creasing in demand for manufacture of motor
fuel alkylates. The outlook for growth of
hydrofluoric acid manufacture is dimmed by
the possibilities for increased recovery of
hydrofluoric acid from phosphate rock
processing, also a pollution abatement
measure.
Sulfonated and sulfated surfactants and
alcohols derived from petroleum fractions
consume sulfuric acid importantly in the
six-state area. The surfactants are the
active components in wetting agents and
detergents and have good growth potential
among the biodegradable types.
The foregoing uses in organic chemistry
probably account for 10% of acid consumption
in the six-states, say 420, 000 tons per year.
The major end-uses listed above appear to account for
2. 6 million tons of sulfuric acid annually in the six-
States, about 60To of 1968 production. A large number of
uses are to be credited with the balance of consumption,
of which alum, dyes and intermediates, and explosives
manufacture, are significant in this area.
VIII .- 22
VIU - 23
-------
2.3.4.2 Sulfuric acid list prices in the United States
increased gradually from $16/17 per net ton
during the years 1930-1948, increased
steadily thereafter to $23 that prevailed dur-
ing the period 1953 to 1^64, and increased
rapidly to $28 per net ton in 1968. During
all this time the acid prices rather faithfully
paralleled the trend of sulfur prices.
Discounts from list prices were always avail-
able to large volume buyers.
Sulfuric acid prices in the four major produc-
ing states of the six-state area tended to run
above the national average as indicated below:
SULFURIC ACID
(Average Price of Shipments per'^net -tail FOB)
From Plants
1964
1965
1966
1967
TABLE VIII-8
1968
in:
Pennsylvania
Ohio
Indiana
Illinois
U. S. Average
$17. 72
20.26
19.00
16.72
$17.92
22. 31
19.85
16. 76
$18. 11
22.89
20. 14
18.92
17.39
$20.08
24. 77
19. 34
18. 68
$22. 99
27. 99
20. 56
21.33
A late 1970 field investigation indicated that
average price for medium to large volume
contract purchases in markets such as
Pittsburgh, Cleveland, Chicago and St. Louis
is $25 to $28 per net ton, freight equalized.
This is roughly equivalent to $22 to $26 FOB
production point. Smaller volume sales are
priced at $33 to $34 per netton delivered.
The future price trend is certainly down-
ward from the current leveLwith ever-
stiffer competition from by-product sources.
Perhaps most immediately significant to the
northern portion of the six-state area (where
most of the Sulfuric acid is used) is the huge
acid recovery operation planned for the
nickel refineries to be built in Ontario. By
1975 as much as 5 million tons pery ear of
acid capacity may be installed — an amount
of acid capacity about twice the present level
of Canadian consumption. Since freight costs
seriously limit the quantities that can be
shipped overseas, it is assumed that one or
more million tons per year will be offered to
nearby consumers in the U.S. at very low
prices, especially to consumers accessible
by water. Developments in pollution control,
such as "central processing" of magnesium
salts (Ref RR) carrying SO2 recovered from
combustion gases of fossil-fuel burning utility
stations, more complete recovery of sulfide
ore smelter gases, and the like, promise to
add big new sources of Sulfuric acid within
the U.S. It is possible but believed not
probable that competition from byproduct
VIII - 24
VIII - 25
-------
sources will drive sulfunc acid price well
below the level at which production from
Frasch process sulfur can profitably continue.
This level for the six-state area is estimated
as follows:
Sulfuric acid requires on the average
0. 31 long tons of sulfur per net ton of
100% acid. If, as argued m VII-2. 3. 3,
Frasch process sulfur will not be priced
below $25 per long ton delivered, the
minimum FOB price of acid from large
sulfur based plants is indicated to be --
Sulfur @ $25 x 0.31
Conversion Cost
Factory Cost
Overhead and Profit
Minimum Price Per Net
Ton lOO^o H9SO
Net
Ton
$7. 75
2. 00
$9. 75
3.00
This price is taken to be a conservative mini-
mum since it is believed that Frasch Process
sulfur or elementary sulfur from other
sources will not be offered, in the six -
state area, significantly below $25 per long
ton. The market ought then to absorb by-
product acid at this price or thereabouts.
Normal growth of existing uses for sulfunc
acid, and new uses stimulated by so low a price,
will help. This price, $12.75, is given effect
in the income estimates of Table VIII-9.
I gS 3
3 M -~ •
!§ -
U £ Z a.
V1I1 - 26
-------
3. OPERATING ECONOMICS
In Table VIII - 10 Income from Sales reflects the unit prices discuesed
in VIII - 2. Sulfuric acid recovered in CASE B and CASE E is of
93% concentration and entered at the same sales value as the 98%
acid of CASE A. Both capital and operating cost estimates of CASE
B and E include provision for concentration, in gas-fired drum-con-
centrators( of the Cat-Ox 77/80% acid (see pages VII-8 and VII-9)
to 93%.
Selling and Commercial Expense are entered at a nominal 1% of
sales value for the energy products on the theory that long term
sales contracts would have been negotiated before location of the
facility. Selling the sulfur products may be more continuously
difficult - 5% of sales value is provided in the estimate.
"Operating Cost" carried forward from Tables Vm-2/6( includes
interest but no charge for the HSC Fuel:
General & Administrative is entered at 2% of sales value.
The "Adjustment for Pollution Control (from Table VIII-7) is entered
as a charge to energy recovery and a credit to sulfur value recovery.
In CASE A and CASE B the credit is larger than the whole cost of
sulfuric acid recovery. Note in CASE A, especially, the elimination
of SO, from the flue gas for dumping as an inert solid is twice as
costly as recovery of sulfuric acid for sale. Note also that the
adjustment serves only the purpose of shifting the burden of
"pollution control" from sulfur recovery to energy extraction in
each CASE without affecting combined income, cost and gain.
VIII - 28
Per Megawatt Hour
Incremental Cost ol Sulfur Value
Unit Cost of Sulfur Products
Per Long Ton of Sulfur
Per Net Ton of Sulfuric Ac
Combined Sales Value of Producti
All Coats Before U S Income Ta
Gam or (Loss* Before U.S Incorr
5 « ~ - as
M & 3
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Adjustment for "Pollution Conlro'
Add
Deduct
Adjusted Coat of Energy Extractn
Unit Cost of Energy Products
Per Net Ton ot Stmm
s 2 s
$ X
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IE - HIA
4. VALUE OF HSC FUELS AND PAYOUT
The footings of Table VIU-10 are carried forward to Table VIII-11
a 48% U.S. income tax rate is applied, the estimated remaining Gain
(Or Loss) is taken to be an evaluation of the HSC Fuels according to
the formula in Part VIII-1. In CASES A, D and E the values are
positive and amount to a direct offset to the cost of cleaning the ROM
coal.
CASE B is uneconomk^ but the CASE B study is not conclusive as
to the economics of intermediate concentrating technology applied
to the 2 fc SO_ gas of the CASE B System.
The economics of CASE C are not significant since this system is
scaled to prototype dimensions.
Investment Payout is shown after interest cost in the conventional
manner.
Cash Flow
Total Investment
Payout - Years
^«
en P3 w
V U> os
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VIII - 30
-}
ABLES V
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ro
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<
-
-------
5. SHIPPING ECONOMICS
A modern steam/electric station is studiously designed and located for
access to its expected fuel supply and market. Even so, the manager
of a coal- or oil-fired station usually seeks to avoid dependence on a
single fuel supplier, and often this can be done, especially if the fuel
is oil. The design and operation of an HSC System appears to be
relatively less flexible since the fuels will be expensive to ship no
matter if offered by many suppliers, and a sulfur product has to be
marketed in addition to energy. As to the delivery of fuel and market-
ing of energy no very unusual problems are foreseen. The marketing
of sulfur value deserves some further comment, however:
5. 1 End-Product is Sulfuric Acid Delivered
In Part III-2, it was noted that sulfuric acid is the "sulfur
value" of importance to this study, and since delivered price
is by far the important factor in marketing sulfuric acid, the
delivered cost is critical. A flue gas treating process of the
type employed in CASE D offers some options for alternative
processing of the dry magnesium sulfite or the 15% SO gas
concentrate whereby sulfuric acid can be made directly and
shipped (or stored), or one of several acid intermediates can
be made, shipped (or stored) and then converted to acid at
the receiving end. Of these intermediates, elementary sulfur
is the most important; it is cheap to ship and store, and
enjoys a major status in the market. For this reason the
CASE D System was presented heretofore as a sulfur making
system, but since the initial process of this system can be
adapted to output of any of the alternate products, it is of
interest to see if "delivered cost" of sulfuric acid can be
improved by traversing one or another of the alternate
routes, or whether in every case the acid is best made
directly from the dry magnesium sulfite.
5. 2 Analysis of Sulfuric Acid Delivered Cost
The question of delivered cost is generalized in the flow
diagrams of Figure VIII-1. The feed material to each
alternate route is dry magnesium sulfite (or more
accurately "magnesium sulfur salts") which are harvested
from the flue gas scrubbing cycle. Four combinations of
process routes are depicted in Figure VIII-1 by which
sulfuric acid can be delivered to customer's tank in each of
five daily tonnages over each of seven shipping distances by
each of three different modes of transport.
VIII - 32
VIII - 33
-------
HIGH SULFUR COMBUSTOR
SO; IN FLUE GAS
CONCENTRATED BY
MgO— ^-MgSOj CYCLE
j
<
1
\
15 % S02 GAS
-------
SULFUR COMBUSTOR
ALTERNATE "D,"
MILES
- 25 —
- 75 —
- 150 —
-300-
S02 IN FLUE GAS
:ONCENTRATED BY
|0-»MaS03 CYCLE
r
.
I 5 % SO, GAS
ALTERNATE "D2"
oooo
oo o o
t
MILES
75
300-
FIGURE M- I
HIGH SULFUR COMBUSTOR STUDY
SULFURIC ACID 8 INTERMEDIATES
LINEAR MODEL FOR ANALYSIS
OF
PRODUCTION & SHIPPING
ECONOMICS
ALTERNATE "D3"
-*• 0
t
MILES
• 75-
- I5O-
- 3OO-
• 6OO-
"I2OO-
-24OO-
END
PRODUCT
OF ALL
SYSTEMS
H2SO«
IN
CUSTOMERS
STORAGE
-------
5.2. 1 Input data for production, storage and transportation
costs are exhibited in Table VIII-12. Production
costs include all operating and capital charges
downstream of the combustor economizer in the
manner of charges to sulfur product in Table VIII-5.
Storage costs are entered in Table VIII-12 to reflect
barge shipping and non-barge shipping. The former
costs are uniformly higher since the cost of dockage
is included. The cost of transport oy barge is
relatively so low that this additional charge to
storage is easily offset.
Transportation costs are listed in dollars per
short-ton-mile for convenience, and include all
elements of price as if offered by an interstate
carrier. The differing rail rates for liquid SO and
H SO result from the more expensive equipment
£ 4
required for the former.
VIII - 34
-------
S£ - IIIA
I r
ro t-i
IT c
o c
SFJ
l/i \f>
M o
Z TV
OO CO'
5.2.2 The linear program diagrammed in Figure VIII-1 is
solved in the printout of Table VIII-13 in which by
inspection (3rd column from the right) the minimum
costs for all tonnages and distances accrue to
CASE D3, e. i., direct manufacture of sulfurtc acid
at the site of the combustor, and shipment by barge.
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VUI - 36
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This result IE again demonstrated in Table VIII-14,
in which also the second lowest cost is shown to be:
a) Manufacture of sulfuric acid and shipment by
rail on hauls up to the 300/600 mile range, and
b) Shipment of magnesium sulfur salts by barge
for distances greater than 600 miles, followed
by manufacture of sulfuric acid at customer's
site.
VIII - 38
-------
6E - niA
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Since an HSC facility may well be located with no
access to navigable waterway, the costs listed in
Table VHI-13 were searched for minima by rail
and truck haulage, with results as shown in Table
VIII-15. Again sulfuric acid manufacture and
shipment is indicated except for the very large
tonnage and long distance at the bottom of the
"Optimal Best" column, which points to sulfur as
the choice for production and shipment, and
conversion to acid at customer's site. Rail
shipment is cheaper than truck in all instances.
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VIII - 40
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6. CASE D vs. CASE D3
Since sulfuric acid is shown to be the most economical form of
recovered sulfur value, it is of interest to analyze the modification
of CASE D designed for output directly of sulfuric acid (CASE D3)
instead of sulfur. Two SO2 recovery trains of the general type
designed for CASE A would suffice to oxidize the 15% SO2 gas
concentrate to sulfuric acid. In CASE D this concentrate is
reduced to sulfur. Upstream of the gas concentrate the CASE D
and D3 systems would be substantially identical, scaled to 500 MW.
Estimated capital and operating cost of CASE D3 LS shown in
Table VIII-16. The corresponding figures for CASE D are
repeated for comparison.
VIII - 42
-------
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7. RECAPITULATION
The High Sulfur Combustor, if well adapted technically to a deep
cleaning operation, is evidently feasible economically provided the
energy and sulfur products can be sold at, or higher than, the price
levels forecast in this study. Economic netback to offset coal clean-
ing cost varies widely among the several "cases" analyzed, [n
general it is assumed that a large tonnage of sulfur processed
corresponds to a large tonnage of coal cleaned CASE A and
CASE D are respectively low- and high-energy output systems
that recover about the same amount of sulfur by processing the
reject material from about 7 million tons per year of clean coal.
Sulfuric acid as a commercial form of recovered sulfur value
appears to be much more attractive than intermediate recovery
of sulfur itself, but this would be true only if the Sulfuric acid
moves continually to market without great price concessions.
Sulfur may afford the producer some relief from a bad local
market for acid in that seasonal storage and long distance shipping
of sulfur can be practiced if warranted.
VIII - 44
-------
IX
REFERENCE LITERATURE
HIGH-SULFUR COMBUSTOR STUDY
.ABSTRACTS
(A) U.S. Public Health Service. A digest of state air pollution laws,
1966. Public Health Service Publication 711, 1966,292pp.,
U.S. Govt. Printing Off ice, Washington, D. C. 20402, $1.50.
In all of the United States, 21 states have established distinct air
pollution control comissions or boards. In other states, the
functions of air pollution control are included in the duties of the
Department ol Health. In only two states the air quality standard
has been partly specified; in other states, the measures are only
in the most general terms such as laws against excessive smoke
and fumes and against emissions of particles that constitute a
danger to public health.
(B) Bechtel Corp. Process costs and economics of pyrite-coal
utilization. A report to U. S. Dept. of Health, Education and
Welfare. Contract PH 86-27-224, December, 1968. 182 pp.
The methods for recovering values from the tailings of coal
beneficiation are reviewed.
For maximum desulfurization by mechanieal means, it is
possible: (1) to grind the run-of-mme coal to about 14-mesh,
(2) to separate the ground coal into 2 fractions, (3) to treat the
+28 mesh material in Baum Jigs at a separating gravity of 1. 60,
(4) to reject the heavy fraction as tailings, (5) to treat the minus
28 mesh material in dense-media cones and hydroclones at
separating gravity of J. 45 to 1. 35, (6) to reject the heavy
fraction as tailings, (7) to treat the remainder by hydrocloning
and froth flotation, and (8) again to reject the heavy fraction.
However, operating conditions may vary appreciably as required
by the nature of the particular type of coal being processed.
- 1 -
-------
(C)
Mechanical methods of desulfurization remove only the pyritic S
in coal. The organic S, which amounts to 30-40% of total S,
would remain in the treated coal. To remove the organic S,
some chemical methods, such as hydrosulfurization, must be
used. The tailings from the mechanical separation methods
contain a high S content in the form of pyrites. The utilization
of these high S tailings is discussed. The currently known
methods aim at the production of saleable SO,, H SO , H_S
and/or elemental S. Since the tailings are not high-grade
pyrites, only those processes which can handle low-grade
pyrites can be used. These processes are:
(1) combustion followed by SO_ removal, (2) carbonization
followed by desulfurization, (3) solvent extraction, (4)
preferential oxidation, and (5) two-stage gasification. These
processes are described, and processes (1), (2) and (3) are
evaluated for adoption in a commercial-scale operation.
Capital requirements and operation costs are estimated.
Commercial operations to utilize the S values in the high-S
coal invariably involve the installation of both power generat-
ing plants and sulfunc acid plants and possibly also fertilizer
plants. These are considered in detail.
Paul Weir Co. (Chicago, 111.) A feasibility study of the recovery
of sulfur and iron from coal pyrites. A report to U.S. Dept. of
Health, Education and Welfare, Contract PH 86-65-29, May,
1966, 40 pp. : PB 176844, Clearinghouse, Springfield, Va.,
22151, $3.00.
H,SO accounts for 75% of all S consumed in the U. S. 70% of
U. S. S comes from the Gulf States as elemental S from the
mines. On a world-wide basis, 40% of S consumed as H SO
comes from pyritic minerals. The reserve of coal pyrites in
the U. S. is estimated at about S billion tons in available sources.
When high-S coals are processed by modern methods, the
pyrite content m the coal-washing tailings is as high as 28%
and averages about 15%. By fine crushing, this may reach 50%.
These tailings may be further beneficiated to give a product
containing S 42-48% and carbon less than 5%,
The high-S coal-washing tailings may be processed to recover S
as H SO and Fe as cmtered Fe 0 suitable for use by the steel
makers. Processes for utilizing coal pyrites are illustrated
with flow diagrams, and costs are estimated on full-scale
production plants and their operations.
(D, Paul Weir Co. (Chicago, 111. ) An economic feasibility study of coal
E) desulfurization. I-II. A report to U. S. Dept. of Health, Education
and Welfare, Contract PH 86-65-29, Oct., 1965, 57 + 130 pp.;
PB 176845, 176846, Clearinghouse, Springfield, Va., 22151. $6.00.
Coal consumption and use pattern in the U. S, 1, OOP tons
1960 1962 1964*
Electric utilities
Coke and gas plants
Retail dealers
Others
Total (bituminous
and lignite)
Anthracite
* Preliminary
173, 882
81, 015
30, 405
95, 127
190, 833
74, 262
28, 188
94, 491
226, 000
89, 000
20, 000
100, 000
380, 429 387, 774 435, 000
17, 600 14, 000
The sulfur content of the various sources of coal in the U. S. is
presented m detailed localities and coal seams. They range from
0. 3 to 7. 6%, but most commonly between 0. 8 and 4. 5%. The high
sulfur coals, e. g., containing 2. 0 to 7. 6% sulfur, were further
examined for the form of sulfur, i. e., pyritic, organic and sulfate.
In general, the sulfate form is very small (0. 01-0. 13%), but pyritic
sulfur accounts for about 2/3 of the total, with the remainder in the
form of organic sulfur.
Crushing the coal followed by gravity separation (e. g., washing
with water) removes a large part of pyritic sulfur but not the
organic sulfur. For example, a West Virginia coal containing total
sulfur 4. 05% (pyritic 2. 59, organic 1. 44 and sulfate 0. 02%) is
crushed to minus 3fl-mesh, and washed to discard 22. 6% tailings,
gave a product (77. 4%) containing 2. 31% total sulfur. Thus, the
reduction of sulfur content was about 43%. The sulfur removal
efficiency decreases rapidly as the size of the crushed coal
increases. For example, the same West Virginia coal when
crushed to minus 1-1/2 inch pieces gave a yield of 82. 8%, a
sulfur content of 3. 9% in the product (a reduction of S of only 3. 7%).
- 3 -
- 2 -
-------
About one-half of all coals consumed in the United States is burned
for power generation. In the majority of cases, no attempt was
made to reduce the sulfur content. Coal -washing, however, is
generally applied to coals destined for metallurgical coke making or
for gas production. The cost of coal washing including cost of
crushing to minus 14-mesh is estimated at about $0. 42 per ton of
product (based on a yield of about 79%). The efficiency of sulfur
removal by washing varies greatly with different sources of coal on
account of different nature of sulfur in the coal.
Case studies are given for the partial removal of sulfur from
several coals containing more than 2% total sulfur, including coals
from Illinois, West Kentucky, Ohio and West Virginia. Process
flow diagrams are given in each caee.
Arthur D. Little, Inc. (Cambridge, Mass.) A study of process
costs and economics of pyrite-coal utilization. A report to U. S.
Dept. of Health, Education and Welfare, Contract PH 86-27-258,
Mar., 1968, 266 pp. ; PB 182 303, Clearinghouse, Springfield, Va.,
22151, $3.00.
In order to meet the requirement of air pollution control in densely
populated localities in the U. S., it would be more economical to
remove the S in the fuel at the source than to remove the SC< in the
flue gas after burning the high-S fuel. In the case of high-S coal,
an economic gain is possible by treating the coal to decrease its S
content to below 1% and converting the pyrites in the tailing to
H-SO . Detailed estimates were made on the costs of S removal
from coal, H-SCX manufacture from the pyritic refuse from coal,
and iron oxide recovery from the pyrite cinders. Full utilization
of the pyritic refuse includes a large-capacity phosphate fertilizer
plant to absorb the H,SO produc ed. Suitable plant locations for
nrfthe4
the whole project and
: capital investments are discussed.
(G) Spencer, J.D. Review of Bureau of Mines coal program, 1968.
U.S. Bur. Mines, Inf. Circ. 8416. 1969, 94pp.
In the field of coal research the U. S. Bureau of Mines in 1968 was
continuing in the following fields: (1) Coal mines environment
studies; (2) coal mining technology; (3) coal mine hazards and
safety; (4) coal cleaning: (5) coal transportation; (6) coal burning
methods; (7) coking and carbonization; (8) coal gasification; (9)
chemical products from coal: (10) chemistry and structure of
coal; (11) Analytical and testing methods for coal.
- 4 -
(H) U.S. Office of Coal Research. Annual Report 1969. U.S. Dept.
Interior, Office of Coal Research, 1969, 65 pp. ; Govt. Printing
Office, Washington, D. C. 20402, $0.70.
Activities of the Office of Coal Research during the calendar year
1968 are briefly reported covering coal mining, coal preparation,
coal and lignite gasification, ash utilization, and sulfur dioxide
control in furnaces.
(J) Mining Information Services. U.S. coal production by company,
1968. McGraw-Hill, Inc., New York, N.Y. 1969, $5.00.
Major coal-producing companies in the U.S. who during 1968
produced 100, 000 tons or over, are listed with the location of
mines and production figures. There are about 630 such
companies. U.S. production of anthracite in 1968 was
11, 025, 482 tons and bituminous and lignite together 545, 000, 000
tons.
(K) National Coal Assoc. Steamelectric plant factors, 1968, 8th ed.,
110pp., National Coal Association, Washington, D. C. 20036,
$5.00.
The statistics of U. S. power plants burning coal, oil. and natural
gas are presented. Operating data of 397 plants are tabulated
with information on capacity, "dependable power", net generation
(kwh for the year), fuel consumed, cost of fuel, ($/MM P,tu). Also
given is a list, by city and state, of Steamelectric power plants
under construction and in the planning stage.
(L.) EBASCO Services, Inc. 1968 Business and economic charts.
Ebasco Industries Co., New York, N. Y., 1969, 45pp.
Statistics are presented in graphic form covering the following
subjects:
1. U.S. Population.
2. Gross national product
3. New home building
4. Industrial capital outlays
5. Power plants
a. Public
b. Private
c. Cooperative
- 5 -
-------
6. Power plants capacities, 1948-1969
7. Electric power consumption
8. Energy sources: Coal, oil, gas, hydro, nuclear
9. Utility companies financial sources
10. Utility company taxes
11. Power generating costs
12. Power transmission costs
13. Power rates
(M) Bishop, J.W., Robinson, E.B., Ehrlich, S., Jain, A.K., and
Chen, P. M. Status of tne- direct contact heat transferring
fluidized bed boiler. Paper presented at the ASME Winter
Meeting, New York, N. Y., December 1-5, 1968, Paper No.
68-WA/FU-4, 13 pp. ; Am. Soc. Mech. Engrs., New York, N. Y.
10017, $1.50.
The recent fluidized bed boiler development work sponsored by
the U. S. Office of Coal Research involves replacement of the
conventional boiler furnace with fluidized suspension of inert
material (e. g. sintered coal and crushed and screened to a
uniform suitable particle size) into which coal is injected and
burned. The water tubes and superheaters are suspended at
suitable levels in the fluidized bed. High heat releases and heat
traisfer direct from bed material to h« ting surface obtained by
this method result in very high steaming capacities from an
exceptionally small boiler. Because of the extremely high heat
transfer rates, an upper limit must be set for the heat exchange
surface to oxidizing fluidized bed volume ratio, otherwise the
flame would be quenched and operation would be unstable. From
experimental data derived in operation of a full-scale single-
module boiler, packaged railroad transportable units can be
built up to 300, 000 Ib/hr capacity or larger. The envisioned
utility boilers of 2, 000, 000 Ib/hr and larger, represent about
15% of the overall size of a similar-capacity pulverized coal
unit. Envisioned large cost savings should make coal more
competitive as a boiler fuel. The use of limestone for s ulfur-
oxide abatement in this system is far more effective than the
conventional boilers. Reductions in about 65% of SO, emissions
have already been accomplished and greater reductions are
anticipated.
(N) Walker, F.E., and Hartner, F.E. Forms of sulfur in U. S.
coals. U.S. Bureau of Mines, Inf. Circ. 8301, 1966, 51pp.,
$0.35.
- 6 -
The sulfur contents of approximately 2, 900 samples of coals from
30 states in the U.S. have been analyzed and are reported as
organic, pyritic, and sulfate sulfur, respectively. The coals
are classified under 11 types such as anthracite, semi-anthracite,
bituminous, subbituminous, lignite, etc.
(P) Chemical Construction Corp., (New York, N. Y.). Report to
Bituminous Coal Research, Inc., Investigation of processes to
remove SO and recover sulfur compounds as salable products
from boiler flue gases. June 20, 1968.
Exploratory investigation of SO_ control processes, preliminary
design and economic evaluation, intended to highlight relatively
promising areas for further study.
(Q) MSA Research Corp. (Evans City, Pa.) and Singmaster and
Breyer (New York, N. Y. ) Inorganic liquids for removing SOg
from flue gaees. Phase I. National Air Pollution Control
Administration, Interim report, April 9, 1969, in connection
with contract PH 22-68-11, 181 pp. : PB-183974, Clearinghouse,
Springfield, Va. 22151, $3.00.
A literature survey was made on the absorption of SO, from fuel
gas by inorganic liquids in the temperature range 200-600° F,
covering molten salts and molten alloys. Experimental work was
carried out on the following proposed methods for SO removal:
(1) A Pb-Sn eutectic was used as the absorbent at 400* F. The
SO, produces a dross of sulfates. The dross was separated and
heated at a higher temperature to decompose the sulfate and to
regenerate the Pb-Sn alloy. (2) Limestone powder was mixed
with a molten eutectic KNO.-LiNO, and was used as SO2
absorbent at 250°F. CaSO. was produced in theprocess. It
was filtered off and discarded. (3) CaO was dissolved in molten
KNOg-LiNO eutectic, and the molten solution was used as the
absorbent of SO,. The pregnant absorbent is heated to
decompose CaSO, and to regenerate the CaO in the molten
solution. (4) MgSO4 was dispersed in a molten entectic system
and was used as the absorbent for SO, and SO,. It was
regenerated by steam stripping. Preliminary economic
evaluation was made for each of the four proposed methods
based on a hypothetic power plant of 800 megawatt capacity.
Operating costs thus estimated seem to be in the range of
feasibility for some of the proposed methods.
- 7 -
-------
(R) Arthur G. McKee & Co. (San Francisco, Calif.) Systems study tor
control of emissions of the primary nonferrous smelting industry.
National Air Pollution Control Administration, McKee Report No.
993; Final report under contract PH-86-65-85; June, 1989. In
three vol., 187 + 180 + Z18 pp. resp. ; PB-184 884-5-6,
Clearinghouse, Springfield, Va., 22151, $9.00.
Some 2, 800, 000 tons of sulfur are contained in the oxide gases
generated annually at the smelters in the U. S. About 31% of this
sulfur is recovered mostly as sulfuric acid. The remaining
1, 920, 000 tons per year are emitted to the atmosphere. Copper
smelters are the source of 76. 5% of this. Lead and zinc smelters
emit the balance. Over 97% of all emissions are from smelters
west of the Mississippi River, The problems of reducing the
emissions from the nonferrous smelters seem at present very
difficult economically.
Neither now nor in the period up to at least 1975 can all of the
potentially recoverable sulfur in the west be sold as sulfiiric acid.
All of it might be sold if a portion could be converted fj:om sulfur
oxides to elemental sulfur at a cost that is low enough to be
competitive. The area of Arizona-New Mexico-West Texas has
the largest potential production of sulfur by-products but a
relatively small market for them, especially for sulfuric acid.
Production of sulfuric acid from the more concentrated gases can
be profitable where a market for acid exists. The production cost
for converting sulfur oxides in the gases to elemental sulfur by
modern processes is not yet defined. Production of sulfur for
sale at competitive prices will probably be possible only by
recovery from gases containing high concentrations of sulfur
oxides.
Therefore, the major technical and economic problem is the
treatment of offgases containing low concentrations of sulfur
oxides. Present technology is not adequate to economically
recover sulfur oxides from these weak off gases. Economic
emission control seems to lie in the direction of process or
practice changes that have the effect of curtailing generation
of weak offgases and delivering other offgases to sulfur oxide
conversion units at the highest feasible concentration.
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(S) Federal Power Commission. Air pollution and the regulated
electric power and natural gas industries. Federal Power
Commission Staff Heport, September 1968, Washington, D. C.,
366 pp.
The overall picture of energy sources, supplies and consumption
in the U.S. is presented for the period 1937-1965 and projected
to 1980. The urgency of environmental care and management
calls for surveillance of the quality of fuels, such as coal, coke,
and oil, which are burned to produce heat and electricity.
Toward this objective legislation is now proceeding at federal,
state and municipal levels to set standards for air quality and to
control the amounts of air pollutants, especially sulfur oxides
both in the fuels delivered to the locality and in the gases dis-
charged from burners and furnaces, and in the air in the vicinity
of fuel burning installations. Cities that already have laws for
air pollution control are listed. In order to comply with these
laws, the fuel-burning and waste material-burning establishments,
such as power stations, apartment houses, and incinerator plants,
must either install sulfur oxides (and nitrogen oxides, hydro-
chloric acid etc.) removal devices, or limit the sulfur content of
the fuel used. Just what is to be done to improve the existing air
quality and to maintain a certain standard, and the costs involved
are discussed. A study of a specific case, the St. Louis, Mo.,
area has been made and the results are presented in detail.
(T) Helfinstine, R.J.. Shimp, N.F., and Simon, J.A. (Illinois State
Geological Survey, Urbana, 111.) Sulfur varieties in Illinois
coals - Float-sink tests. U.S. Public Health Service Contract
No. PH-86-67-206, Beport August 10, 1969; 9 + 87 pp.
Results of laboratory tests and analyses of some 1, 200 samples
of coal from more than 800 mines in the State of Illinois are
reported in 8 tables and 240 graphs. Special attention was paid
to the chemical and physical properties, sulfur content, (sulfate,
organic and pyritic), washability and ash fusion temperature.
The run-of-mine coal contains total sul/ur from below 1. 5% to
as high as 6. 99%.
Each sample was divided into float and sink fractions as in
coal washing. Analyses of the float and s nk fractions
indicated that only about 1/4 of the Illinois coal can be washed
to give a product at 80% recovery containing 2. 5% S or less. Only
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a few mines give coal that can be washed to give a practical
percentage of recovery and a S content of 1. 5% or less.
The float fraction usually had less sulfur in the smaller
particle sizes, but the differences were not great enough to make
fine grinding a practical means of sulfur reduction.
The maximum sulfur in the 1. 60 specific gravity sink fraction
for the 40 Illinois coal samples tested was 26%. Five of the 40
samples testd had more than 20% sulfur in the 1. 60 sink
fraction. These sink products indicate that the mine refuse
from some Illinois mines is a potential source of sulfur.
(U) National Air Pollution Control Administration. Air quality
criteria for particulate matter. U.S. Dept. of Health,
Education and Welfare, National Air Pollution Control
Administration, Publication No. AP-49, January 1969,
Washington, D.C., 211pp.
By the Congressional Air Quality Act of 1967 the Secretary of
Health, Education and Welfare has the responsibility of issuing
to the States criteria of air quality to guide them in the legislation
and promulgation of laws for the protection of people from
adverse effects of air pollution.
This report is concerned chiefly with particulate matter in ambient
atmosphert, its sources, its effects on health, both human and
animal, on vegetation, and on materials and buildings, and the
desirability of its abatement and control for health, economic
and aesthetic reasons. It is observed that under the Conditions
prevailing in localities where studies were made, adverse
effects were noted when annual geometric mean levels of
particulate matter exceeded 80 micro g. /cu. m. for health, and
60 micro g. /cu. m. for materials and buildings. Visibility
reduction to about 5 miles was observed at annual mean exceed-
ing 150 micro g. /cu. en. It is recommended that when setting
up ambient air quality standards, consideration should be given
to requirements for margins of safety which take into account
long-term effects on health and materials occurring below the
above mentioned levels. With subject index.
(V) National Air Pollution Control Administration. Air quality
criteria for sulfur oxides. U.S. Dept. of Health, Education
(W)
and Welfare, National Air Pollution Control Administration
Publication No. AP-50, January, 1969, Washington, D. C., 178pp.
As a part of the Air Quality Criteria issued to the States by the
Department of Health, Education and Welfare in accordance with
the Air Quality Act of 1967, this report concerns chiefly with
sulfur dioxide in ambient atmosphere, its sources, its effects on
health, both human and animal, on vegetation, and on materials
and buildings, and the desirability of its abatement and control for
the protection of people and their health and for environmental
wholesomeness. Furthermore, in addition to health considera-
tions, the sulfur dioxide in the air must be abated and controlled
for economic and aesthetic reasons. It is noted that under the
conditions prevailing in localities where studies were made,
adverse health effects were observed when 24-hour average
levels of SO exceeded 300 micro g. /cu. m. (0. 11 ppm).
Visibility reduction to about 5 miles was observed at 285 micro
g. /cu. m. (0. 10 ppm); adverse effects on materials and buildings
were observed at an annual mean of 345 micro g. /cu. m. (0. 12
ppm); and adverse effects on vegetation were observed at an
annual mean of 85 micro g. /cu. m. (0. 03 ppm). It is recommended
that when setting up ambient air qualify standards, consideration
should be given to requirements for margins of safety which take
into account long-term effects on health, and materials occurring
below the above-mentioned levels. With subject index.
National Air Pollution Control Administration. Control techniques
for particulate air pollutants. U.S. Dept. of Health, Education
and Welfare, National Air Pollution Control Administration,
Publication No. AP-51, January 1969, 215 pp.
In accordance with the Congressional Air Quality Act of 1967, the
U. S. Department of Health, Education and Welfare has compiled
this manual of control techniques for particulate air pollutants.
It encompasses the control techniques at the sources of emission,
methods and equipment for removal of particulate matter from air
discharge streams, disposal of collected particulate wastes,
capital costs of equipment and operating costs. Among the
various types of particles removing equipment described are
baffles, cyclones, entrainment removers, mist eliminators, high
and low-voltage electrostatic precipitators, fabric filters and
afterburners. With subject index.
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(X)
(Y)
(Z)
National Air Pollution Control Administration. Control techniques
for sulfur oxide air pollutants. U.S. Dept. of Health, Education
and Welfare, National Air Pollution Control Administration
Publication No. AP-52, January 1969, 122 pp.
In accordance with the Air Quality Act of 1967, the U.S. Dept. of
Health, Education and Welfare has compiled this manual of control
techniques applicable to the sulfur oxides in the atmosphere, tt
encompasses the control techniques at the source, processes,
methods, and equipment for removal of sulfur oxides from exhaust
gases, capital costs of equipment and operating costs. Among the
various processes described are the alkalized alumina process,
the limestone and dolomite injection process, the Beck-well SO2
recovery process, and the catalytic oxidation process. The evalua-
tion of these processes is discussed. With subject index.
Babcock & Wilcox Co. Air pollution control program.
Wilcox Brochure BR-905, June 1969, 8 + 2 pp.
Babcock &
A brochure addressed to utility companies and other interested
groups soliciting financial support for a comprehensive test
program of a system cf air pollution control for power boilers.
A preliminary study comparing several proposed processes has
convinced Babcock-&48Tilcox Co. that the process proposed by
Esso Research & Etig. Co. using a dry regeneratable sorbent
would fit into a system (designed as B&W-Esso system) that
would fulfill a long-term need of the utility companies, Babcock
(t Wilcox is proposing a four-year development program in three
stages or phases. Phase I: Process designing, sorbent material
testing, sorbent regeneration technique improvement. Phase II:
Pilot plant erection (25 Mw capacity), pilot plant operation, and
sulfur oxides recovery study. Phase III: Prototype plant design-
ing based on an 800 Mw coal-fired power station, erection of the
prototype plant, and operating it.
The goal of Phase HI is to achieve a particulate pollutant removal
of 99%, a sulfur oxides removal of 90%, a nitrogen oxides
reduction, the production of byproduct H-SO and a low overall
cost of the system (capital and operating;. An estimate of the
financial requirements ($6, 750, 000) for the program is given.
Nat'l Air Pollution Control Admin. A status report: process
control engineering, R&D for air pollution control. U.S. Dept.
Health, Education and Welfare. Nat'l Air Pollution Control
Admin., Cincinnati, O., Nov. 1969, 45pp.
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(A A)
The Nat'l Air Pollution Control Admin, through its Process Control
Engineering Section (PCE) continued in 1969 its programs of
research and development in the field of controlling emissions of
SO, and other pollutants from stationary sources. Specific studies
have been undertaken in collaboration with other organizations: the
principal ones are the following-
1.
2.
3.
4.
5.
6.
7.
Limestone injection to control SO • with Tennessee
Valley Authority.
Removal and utilization of pyrite sulfur in coal:
with U. S. Bur. Mines.
Fluidized bed combustion combined with limestone
additive- with Office of Coal Research, and U. S.
Bur. Mines.
Meteorological research related to air pollution:
with Environmental Science Services Admin.
Power industry needs: with Atomic Energy
Commission.
Using "red mud" as absorbent for SO2 in flue gas:
with the City of Chicago.
Coal reserves and sulfur in the coals: with the
States of Illinois, Ohio, Montana, New Mexico, Utah,
Indiana and Mississippi.
8. Washability of Illinois coal: with the State of Illinois.
As of June 30, 1969, PCE had 47 active contracts with private
firms and institutions outside of the Federal government to
carry out specific studies and research.
Internationally, PCE has an agreement with the National Coal
Board of England for exchange of basic information on fluidized-
bed combustion of coal.
National Air Pollution Control Admin. The cost of clean air.
First report of the Secretary of Health, Education and Welfare
to the Congress, June 1969, 111 pp. : U.S. Dept. Health,
Education and Welfare, Washington, D. C., NAPCA-FS-1. 35:969.
For the fiscal years 1970-1974, the costs of the air pollution
control program in the United States, cowering government
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expenditures at the federal, state and local levels, are estimated
as follows:
Millions of Dollars
1969
1970
1971
1972
1973
1974
These expenditures comprise research and development as well
as abatement, and control.
For expenditure on the part of industry based on substituting low-
sulfur coal for high-sulfur coal and substituting 1%-sulfur fuel oil
for high-sulfur fuel oil, along with maximum control of
particulate emissions, the total cost of air pollution control in 85
metropolitan areas .ar.e,estimated as follows, the low and high
estimates indicating differences in costs of equipment and in
operating costs involved in the fuel desulfurization processes and
in flue gas treatment processes:
Fossil fuel burning
power plants
Chemical, metallurgical
and manufacturing plants
1971
1972
1973
1974
Low
401. 6
635. 2
662. 1
689.3
High
455.0
730.8
766. 7
801.4
Df dollars)
Low
41.7
73.3
74.5
76.5
High
82. 3
137.4
139.8
140. 8
It ie noted that the highest estimate of annual costs for controlling
sulfur oxides and particulate emissions from central power
stations is less than 0. 5% of the operating revenues, and that of
industrial plants less than 2% of the value of shipments from such
plants. The only exception is the sulfuric acid industry, in which
case the "high" estimate for the year 1974 will be 12. 66% of the
value of shipments excluding credit for values recovered in
connection with emission control measures. This credit could
substantially off-set the cost of emission control.
(BB) Rallo, T.V. (Foster Wheeler Corp., Livingston, N. J. > Technology
and economics for domestic boiler and power plant designs. Foster
Wheeler Corp. Report, June 12, 1969; Contract 15 + 24 pp.
The technology and economics of steam power plants in size range
of 50-400 Mw burning normal fuels have been studied with a view of
determining such designs as most amenable to combination firing of
refuse and fossil fuels. Design concepts of ten examples in the said
size range are presented illustrating the state-of-the-art in the
United States. The boilers of the ten power plants are: 2 oil-, 3
gas-, and 5 coal-fired; steam rates range 500-2, 390 M Ib. /h. ;
superheat steam temperature 950-1, 050° F, pressure 1, 275-2, 486
psig; boiler efficiency 84. 23-89. 32%; total plant costs including
turbine-generator equipment accessories and structures $203-108
per kw, resp., electricity production costs $0. 01043-0. 00645 kwh.,
resp., including operating costs, fuel costs, and fixed charges.
Detailed analyses of these figures are given. Sketches of the ten
steam generators are shown. A special burner, the FW multi-fuel
burner, is also shown. This burner is adaptable to all kinds of
fuels including gas, oil, and coal, burned interchangeably or
simultaneously.
(CO Zimmerman, R.E. (Paul Weir Co., Chicago, 111.) The economics
of desulfurization coal by conventional coal preparation methods.
Paper No. 24D presented at the 59th National Meeting of A.I. Ch. E.,
Columbus, O., May 15-18, 1966, 18 _ 9 pp.
Various methods in conventional coal washing are investigated.
The washing operation reduces the sulfur content of coal by
removing a part of the pyrites and marcasites which constitute
the pyritic sulfur, as against organic sulfur which is immune to
washing operation. But the organic sulfur may amount to as much
as 50% of total sulfur in coal. Therefore, sulfur removal by wash-
ing has substantial limitations. Within the limitations, the
effectiveness of washing improves as the size of the coal particles
decreases and as the specific gravity of the separation is lowered.
But this improvement is only possible at the expense of coal
recovery. If low-sulfur coal is sold at a premium, that premium
is balanced by the cost of the washing operation plus the cost of
combustible values left in the coal refuse, that is, the lower the
sulfur content the greater the amount of coal refuse. Capital and
operating costs of coal washing are Illustrated.
(DD) Deurbrouck, A.W., and Palowitch, E.R. Survey of sulfur
reduction in Appalachian region coals by stage crushing. U.S.
Bur. of Mines Inf. Circ. 8282, 1966, 37 pp.
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The sulfur, particularly the pyritic form, in coal can be reduced to
a certain extent by crushing the coal to liberate the pyrite-rich
particles followed by gravity separation in aqueous medium. This
method was applied to the coal from the Appalachian region in
Pennsylvania, Ohio and Tennessee. Lab. tests show that, when
the coal is crushed to pass 14-meeh, followed by washing, the
sulfur content of the product is significantly lower than in the
original coal (e. g. 1. 5% vs. 3, 0%) while coal recovery is about
84%. However, there are many exceptions to these figures,
depending on the location of the coal beds, even if they are in the
same general region.
(EE) Dennis, R., and Bernstein, R.H. (reap., GCA Corp., Bedford,
Mass., and Chas. T. Main, Inc., Boston, Mass.) Engineering
study of removal of sulfur oxides from stack gases. - Final
report. Am. Petr. Inst., Air and Water Conservation Committee
Report, Aug. 1968, 69 + 5 pp.
Four processes for the removal of SO from the powerplant stack
gases were selected for detailed study from the economic and
engineering standpoint. They are: (1) Dry dolomite (limestone)
injection followed by wet scrubbing, (2) Catalytic oxidation
followed by absorption in water, (3) Alkalized alumina process,
and (4) Reinluft process. As a result of this study, the capital
investment and operating costs of SO, removal are estimated
based on an oil-fired power plant rated at 800 Mw and operated
at 60% load factor, as follows:
PROCESS
Cost
Capital Cost
106$
$/kW
Operating Cost
Mills/kWhr
$/bbloil
Dolomite
Inject ion -Wet
Scrubbing
0.51
0. 50-0. 63
Catalytic
Oxidation
14. 0
17. 50-19. 00
Alkalized
Alumina
10.0
11. 50-13.00
Reinluft
13. 1
16. 50-17. 00
0.20
0.14
0.59
0.41
0,73
0,51
0.58
0.41
(FF) Argenbright, L.P., and Preble, B. (Arthur G. McKee&Co., San
Francisco, Calif.) Sulfur oxides from western smelters.
I. Quantities, sources, and costs of recovery. Paper presented at
the 158th Nat'l Meeting of Am. Chem. Soc., New York City, Sept.
7-12, 1969, 17 + 9 pp. (Based on a study performed for National
Air Pollution Control Administration under Contract PH-86-65-85. )
Some 2. 2 million long tons per year of sulfur is contained in the
sulfur oxide gases generated in the operation of copper, zinc, and
lead smelters in the western U.S. Nearly 23% of this is recovered,
almost all as slufnric acid. More acid can be made where
markets are available, but many smelter gas flows are too dilute
for economic acid manufacture. Costs for concentration of these
gases by presently known processes are excessive. Estimated
costs of sulfuric acid made from the smelter gases are given
based on the SO, concentration in these gases. These estimated
costs are compared with that of sulfuric acid made from elemental
sulfur. Development of improved smelting processes that would
produce more concentrated gases could eventually lead to recovery
of over a million tons of sulfur values now wasted. Costs are given
for sulfur oxide recovery by the Cominco process and by the Asarco
process, respectively. The Cominco process ends up with
concentrated SO , and the Asarco process ends up with liquid
elemental sulfur. It seems a low cost process is needed to convert
the SO, from the smelters to elemental sulfur, which could be
more economically stored and shipped than equivalent quantities
of sulfuric acid.
(GG) Yodis, A.W., Boucher, S.B., Edgecomb, R.H., Falk, G. B.,
Harrer, T.S., and Park, R.S. (Allied Chem. Corp., New York,
N. Y.) Applicability of reduction to sulfur techniques to the
development of new processes for removing SO2 from the flue
gases. National Air Pollution Control Administration, Contract
No. PH 22-68-24, Interim Report Sept. 26, 1969; 379 - 4 pp.
The literature related to the reduction of SO, to elemental sulfur
is reviewed. The established processes were studied with the
object of economic evaluation if they should be selected for the
treatment of flue gases containing SOj. These studies cover the
following processes:
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(1) Hot carbon reduction
(2) Reduction with methane
(a) The Asarco process
(b) The West process
(c) Kulcsar process
(3) Reduction with CO + HZ mixture
(4) The normal Claus process
(5) The low-temperature Claus process
Thermodynamic and equilibrium calculations for the above
processes are presented. Industrial plant-scale layouts are
proposed. Capital investment and operating costs are
estimated.
(HH) Aerojet-General Corporation. Applicability of aqueous solutions
to the removal of SO from flue gases. National Air Pollution
Control Administration, Contract PH 86-68-77, Final Report
Volume I, October 1970.
The feasibility of using aqcreoae systems for removing SO_ from
flue gases is appraised. Assessment of methods, literature
survey, preliminary economic evaluation, selection of candidate
processes are included. Thirty processes are identified and 22
evaluated. The economic evaluation basis is a flue gas contain-
ing 0. 3 vol. % SO from a coal burning steam-electric station
of 120 MW capacity.
(JJ) A Bituminous Coal Research, Inc. Report. An evaluation of coal
a cleaning processes and techniques for removing pyritic sulfur
from fine coal. National Air Pollution Control Administration
Report 1970 (BCR-L-339; Contract No. PH-86-67-139), 265 +
17pp.
The methods of pyritic sulfur removal from coals were investi-
gated based on 70 utility coals from various seams in Illinois,
eastern Ohio and western Pennsylvania. These methods include
(1) compound water cyclone, (2) concentrating spiral, and (3)
concentrating table. Tests were made on two fine sizes of coal
(a) minus 30 mesh (corresponding to recycle of a utility
pulverizer) and (b) p. c. grade (corresponding to the "as fired"
pulverized coal). The results of the testB*bhow that the pyrttlc
sulfur in No. 6 Ohio coal ground to minus 30 mesh can be
reduced 93. 7% and for Illinois No. 6 coal the reduction was
(JJ)
b
only 51. 2% at the same particle size range. At the p. c. grind,
the Pennsylvania Lower Freeport coal showed a pyritic sulfur
reduction of 95. 0%, but the Pennsylvania Middle Kittanning coal
only 54. 5%. The pyritic sulfur in the coals tested vary greatly
even from the same seam; for example, the Middle kittanning
seam showed a low of 0. 22% at Clarion County and a high of 8. 45%
at Clearfield County, r.o.m., minus 1. 5 inch basis. The
adaptability of the 3 methods of coal cleaning was found to vary
with the particular types or sources of coal. The method of air
classification was briefly tested; results are preliminary.
Bituminous Coal Research, Inc., Final Report. An evaluation
of coal cleaning processes and techniques for removing pyritic
sulfur from fine coal. National Air Pollution Control Adminis-
tration. Contract No. PH-86-67-139.
Material contained in the earlier report, (JJ)a see abstract
above, is repeated in somewhat abbreviated form together
with data on washability of 20 additional coals from "Southern,
Western and Mid-Western" states. But the majority of the 20
additional coals "were quite different from the 70 coals" earlier
evaluated. Of the 20 coals, the few that were high in pyritic
sulfur were high also in organic sulfur "so that total sulfur
reductions obtained were not as impressive as previously
reported reductions".
(KK) Salts man, R.D. (Bituminous Coal Research, Inc., Monroeville,
a Pa.) The removal of pyrite from coal. Paper presented at Am.
Soc. Mech. Engrs. Annual Meeting, New York, N. Y., Dec.
1-5, 1968; ASME preprint 68-WA/FU-2, 8pp.
The occurrence of pyrite in coal is discussed and a brief
review is made of previous work at Bituminous Coal Research,
Inc., on pyrite removal that led to two substantial projects.
The first of these projects, cosponsored with 12 Eastern
utilities, is a program to evaluate methods for optimizing pyrite
removal from the pulverizing mill prior to combustion. The
second project is sponsored by the U.S. Public Health Service
and is an evaluation of coal cleaning methods and techniques for
removal of pyritic sulfur from fine coal. Results from these
projects are discussed.
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(KK) Saltsman, R.D. (Bituminous Coal Research, Inc., Monroeville,
b Pa.) The removal of pyrite from selected Pennsylvania coals.
Paper presented at Fall Meeting, Power Generation Committee.
A review of the BCR investigation of coal washability at 30 mesh
x 0 and p. c. sizes as reported in (JJ)a and (JJ)b, with
emphasis on the 29 coals that originated in Pennsylvania out of
a total of 90 tested.
(LL) Chemical Construction Corp. (New York, N. Y.) Engineering
analysis of emission control technology for sulfuric acid
manufacturing processes. National Air Pollution Control
Administration Report March 1970, (Contract CPA -22-69-81)
in 2 volumes; Vol. 1 PB-193 393, 324pp., Vol. 2, PB-190 471,
144 pp.
Vol. 1 gives a survey of more than 70 systems and devices for
the control of emissions of SO2, H2SO4 mist and nitrogen oxides
from sulfuric acid plants. It is concluded that adequate control
can be achieved at almost any H2SO4 plant from a technical
viewpoint, but not always economically. Analyses of 20 of the
more advanced and potentially promising systems show the
estimated costs of emission control under various plant
conditions. It is noted that systems suitable for emission
control in power plants are not Tiecessarily suitable and economical
for H2SO4 plants. Further study of the problems of emission
control in H.SO plants is recommended.
Vol. 2 is a survey of literature giving three bibliographies with
abstracts: (2) Removal and recovery of sylfur oxides from
H-SO -plant tail gases, 1955-1967; {b) SC«3 and H2SC«4 mist
emissions and their control, 1907-1967; (c) Removal of nitrogen
oxides from Chamber and Mills-Packard H-SO. plant tail gases,
(1907-1968).
(MM) Stites, J.G., Jr., Horlacher, W.R., Jr. (Monsanto Co., St.
Louis, Mo.), Bachofer, J. L., Jr. and Bartman, J. S.
(Metropolitan Edison Co., Portland and Reading, resp., Pa. )
Removing SO. from flue gas. Chem. Eng. Prog. £5, Oct. 1969,
p. 74-79.
The Monsanto process for SO2 removal by catatytic oxidation
was put through pilot plant test at Metropolitan Edison
- 20 -
Company's generating station at Portland, Pa. Operation started
in August 1967, with a flue gas capacity of 1. 440, 000 SCF/hr.
which was about 1/16 of the total flue gas from the 250, 000 kw.
No. 2 generating unit. The flue gas was first freed from fly ash
and was passed through the catalyst bed at about 650° F whereby
the SO2 in the flue gas was about 90% oxidized to SO,. The SO,
combinea with the moisture in the flue gas to form HLsO.. The
effluent gas was cooled by heat exchanger to about 45u° F and
was scrubbed with cold 80% HqSO in a packed column main-
tained at 225° F. After that the gas was passed through a Brink
mist eliminator and the residual gas was vented. A slip-stream
of the acid from the bottom of the absorption column was taken
as the product acid containing 80% H2SO.. The SO. removal
efficiency was 90%, and HjSO recovery was 99. 5% based on SOg.
The installation cost of the Monsanto system was estimated at
$20-$30 per kw power plant capacity. The operating cost would
be balanced by the value of recovered HgSO^ based on a coal
containing 3% S and a. 100% H_SO. price of ^13. 50/sh. ton.
(NN) Anon., Chemical Week, Vol. 104 No. 4, July 22, 1970. Anon.,
Chem. and Eng. News, Vol. 48 No. 30, July 20, 1970.
Illinois Power Company filed proposal with Illinois Commerce
Commission to install a demonstration unit of Monsanto
Envirochem Systems, Inc. Cat-Ox method for removing sulfur
oxides and particulates from plant stack emissions at IP's Wood
River station No. 4. The Cat-Ox system will recover sulfur as
sulfuric acid. The facility is expected to cost $6. 8 million,
which will be funded $3. 3 million by IP and $3. 5 million by
NAPCA. '
(PP) Shah, I.S., The removal and recovery of sulfur dioxide and acid
mist from sulfuric acid plant stack gas using Venturi Scrubbers,
A.I. Ch.E.-IMIQ 3rd Joint Meeting, Denver, Colorado, August
1970.
Sulfur dioxide, trioxide and sulfuric acid mist are atmospheric
pollutants from combustion of sulfur bearing fossil fuels, smelt-
ing of sulfide ores, sulfuric acid plants and other processes.
The venturi scrubber is capable of high efficiency in treating
sulfur oxide and mist containing gases. The magnesium base
SO. removal and recovery process can limit outlet SO, concen-
trations to 50-250 ppm. Dried magnesium sulfur salts heated
in the presence of coke will release SO, when directly heated to
yield a 15% SOg concentration in the combustion gas, and
regenerate magnesium oxide for recycle to the scrubbers.
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(QQ) Cronan, C.S., Magnesia pulping breaks pollution saltemate.
Chemical Engineering, Sept. 8, 1958.
New magnesia-base sulfite pulping on stream at Brown Paper
Co., uses Mg(OH) liquor in Venturi scrubbers to recover
1-2% SO2 from flue gas of 160 M Ib/hr boiler.
(RR) Anon., Chemical Week, Vol. 104 No. 3, July 15, 1970.
Sulfur dioxide removal system developed by Chemical
Construction Corporation and Basic Chemicals Division of
Basic, Inc., will be installed at the 150 MW Mystic station of
Boston Edison Co. The sulfur dioxide will be converted to
magnesium sulfur salts at the Mystic plant and shipped to Essex
Chemical Corp. at Rumford, R.I. for regeneration as sulfuric
acid and magnesium oxide. The latter will be returned to the
power plant for reuse. The cost of the facility is estimated at
$5 million to be funded jointly by NAPCA and the other
participants.
(SS) Sulphur Patents Limited, Billingham, England, Brochure:
The recovery of sulphur from smelter gases, DO date, 28 pages,
4 figures.
Absorption and discharge of SO from solutions of basic
aluminum sulfate is described, and account of installation at
Imatra, Finland.
Also an account of the Boliden process for reduction of SC< to
sulfur with producer gas from coke. Chemistry is described.
(TT) Watt, S.G., Wellman-Lord SO recovery process, Brochure:
Wellman-Lord, Inc., undated, 19 pages, incl. simplified flow
sheet.
The Wellman-Lord SO- recovery process is based on absorption
of SO in potassium sulfite solution, crystallization of K S O
from this solution, and conversion of K2S GS to KHSOg By2
dissolving the Crystals in water. SO, is stripped from the
KHSO, solution and can be used as a gas or compressed for
shipment. The 3 year development program included a 1 MW
pilot plant at Tampa Electric'a Gannon Station and a 25 MW
demonstration plant in operation at Baltimore Gas and
Electric'a Crane Station. Technical and economic performance
- 22 -
have been promising. Tests have been conducted at a metallurgical
smelter and this process concept is held to have wide application.
An alternate sodium sulfite system is available. Pilot plant tests
to produce elemental iulfur are in progress.
(UU) Craig, T.L., Hughes, F., Watt, W. G., Commercial experience
- Wellman-Lord SO- recovery process, Third joint meeting
A.I.Ch.E.-IMIQ Denver, Colorado August 30/Sept. 2, 1970.
Brief history of Wellman-Lord development activity with alkali
metal SO absorbent systems and preliminary comment on
operation of prototype (45, 000 SCFM) unit at Paulsboro for
control of sulfur oxide emissions from refinery acid regeneration.
(VV) Kohl, A.L. and Riesenfeld, F.C., Gas Purification, McGraw
Hill Book Co., Inc., N.Y., 1960; pp 199/210 incl.
Sulfur dioxide recovery processes employing aromatic amines
are discussed. Xylidine-water mixtures of the "Sulphidine"
process and dimethylaniline as used by Falconbridge Nickel
Company and Americai Smelting and Refining Co. in analogous
chemistry based on formation of the sulfites of the aromatic
amines and stripping with heat in counterflow exchangers. The
xylidine-water absorbent is more efficient at SO2 gas concentra-
tion below about 2%. DMA is competitive or superior at higher
concentrations.
(WW) King, R.A. Economic utilization of sulfur dioxide from metal-
lurgical gases, Industrial and Engineering Chemistry, Vol. 42,
No. 11 November 1950.
The market oriented history of sulfur dioxide recovery at Trail,
B.C. is reviewed. Sulfuric acid, ammonium sulfate and sulfur
manufacture is described.
(XX) Fleming, E.P. and Fitt, T.C., Industrial and Engineering
Chemistry, Vol. 42, No. 11, November 1950.
Direct reduction of sulfur dioxide in metallurgical gases by
reaction at high temperature with methane as practiced by
American Smelting and Refining Co.
- 23 -
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X
HIGH SULFUR COMBUSTOR STUDY
Review of Literature
SUBJECT INDEX
Aerosol emissions from sulfuric acid plants (U 25, 151)
Air classifiers for pyritic sulfur removal from coal (JJ 101)
Air cleaning by wet scrubbing (Z33)
Air cleaning systems cost calculation (W166)
Air filters, wet type (W 70)
Air pollution control credit of low-sulfur coal (F ii-4)
Air pollutant emissions from coal- and oil-fired
boilers (Z 25)
Air pollutant emissions from non-ferrous smelting (Z 24)
Air pollutant emissions from sulfuric acid plants (Z 25; AA 79)
Air poiiirumts produced in U. S., 1965 (S p. H)
j Air pollution control costs (AA 2, 3. 25, 27)
Air pollution control costs to industry (AA 27)
! Air pollution control for fluid-bed furnaces (Z 28)
j Air pollution control in fluidized-bed boiler plants (M 10)
Air pollution control in power stations, coats (AA 37)
Air pollution control in sulfuric acid plants, costs (AA 79, 81)
Air pollution control laws (U. S.) (A)
Air pollution control regulations (A 27, 43, 44)
Air quality criteria for duet (V 188)
j Air quality criteria for paniculate pollutants (U 189)
Air quality improvement costs (S 315)
Air quality improvement methods (S 314)
Air quality standards (A 27, 43, 44)
Alkalized Alumina process capital investment (EE 28)
Alkalized Alumina process for SO2 removal (EE ii, 6. 18; GG 328)
Alkalized Alumina process, operating costs (EE 28, 48)
Alkalized alumina process (X 49)
Alkalized Alumina process for SO, removal (S 147)
Alkalized Alumina process for suuur oxides removal (Z 40. 41)
Alkalized Alumina process - W.R. Grace & Co.
report (Z 41)
Alkalized Alumina process - M. W. Kellogg report (Z 41)
Alkalized Alumina process - Oak Ridge National
Laboratory report (Z 41)
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High Sulfur Combustor Study - Review of Literature
Page Two.
High Sulfur Combuator Study - Review of Literature
Page Three.
Alkalized Alumina process operating costs
Alkalized Alumina process - U.S. Bureau of Mines
reports
Alkalized Alumina process - Avco report
Allied Chemical Corporation
Allied Chemical process for sulfur recovery from
roaster gases
Anthracite refuse utilization
Asarco process flow diagram
Asarco SCv reduction capital costs related to SO,
concentration
Asarco process operating costs
Asarco SO2 reduction operating costs related to
SO concentration
Asarco i'rocess capital investment
Asarco Process for SO reduction
Asarco process for SOL reduction, flow diagram
Asarco process for sulfur recovery from smelter
gases
Ash content of U. S. coals
Atomics International (molten carbonate) process
for SO- removal
Avcrbukh's data on SO» reduction by methane
B
B&W-Esso - MgO system for sulfur oxides
recovery flow diagram
B&W-Esso - system of sulfur recovery
B&W-Esso - system of sulfur oxides recovery,
flow diagram
B&W - MgO system of sulfur recovery
Babcock & Wiloox Co.
Bag filters
Battelle Memorial Institute
BCR process for coal gasification
Bechtel Corporation
Beckwell process for SO2 recovery
Belco Industrial Equipment Company
Bituminous coal compositions, eastern U. S.
Bituminous Coal Research, Incorporated
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High Sulfur Combustor Study - Review of Literature
Page Four.
High Sulfur Combustor Study - Review of Literature
Page Five.
Claus process (normal) for sulfur from H,S
Glaus process (normal), operating costs
Claus process (low temperature), capital investment
Claus process using moving beds
Coal analysis. U.S.
Coal ash composition. U.S.
Coal ash fusion tempera ture
Coal ash utilization
Coal beneficiation by deep cleaning
Coal burning in fluidized bed
Coal-burning, powdered coal
Coal cleaning by dense medium cones
Coal cleaning by froth flotation
Coal cleaning data on U.S. coals
Coal cleaning equipment study
Coal cleaning methods
Coal cleaning potentials
Coal cleaning .plant cost analysis
Coal cleaning processes
Coal composition, U.S.
Coal composition, U.S. coals
Coal consumption by power plants in U. S.
Coal consumption by power plants, U. S. 1967,
by state
Coal consumption in U. S.
Coal consumption in U.S. by regions
Coal consumption, U.S.
Coal, deep-cleaned, composition
Coal desulfurization
Coal desulfurization
Coal desulfurization by froth flotation
Coal desulfurizetion processes compared
Coalfields. U.S.
Coal float-sink tests
Coal heating values, U.S.
Coal mines in Illinois
Coal mining companies, U. S.
Coal mining flow diagram
Coal preparation
Coal preparation, commercial practice
Coal price appreciation due to sulfur removal
Coal processing for sulfur removal
Coal pulverization
(GG 7, 19, 54. 313)
(GG 153)
(G 208, 211, 213,
216, 219. 222, 263,
274)
(GG 74. 86)
(D 11, E 14)
(H 52)
(T8. 36)
(H46)
(B iii-5)
(G52)
(G 51)
(G 40)
(G40)
(JJ 181)
(Z 14)
(KK 5)
(X36)
(Z 16)
(Z 13)
(B A-2; E 14)
(Z 15)
(AA 42)
(K49, 51)
(CC f-1)
(CC t-1)
(D 8, 10; E 8, 10)
(BA-2)
(S 91. 94, 101, 104)
(X 34. 109. 117)
(Z 15)
(Z 14)
(X 10)
(CC 5, f-1, f-5)
(D 11; E 14)
(Z 15)
(J7)
(H - inside cover)
(H - inside cover)
(B iii-4)
(F ii-2)
(E 48; F iii-20)
(G 38)
Coal pyrites, grades and analysis
Coal pyrites processing feasibility
Coal refuse
Coal refuse disposal
Coal reserves, U.S.
Coal residue sulfur content, Illinois
Coal tailings composition
Coal tailings, recoverable values
Coal tailings roasting in fluidized bed
Coal up-grading by washing
Coal washability
Coal washing
Coal washing, capital investment
Coal washability data
Coal washability graphs
Coal washing for sulfur removal
Coal washing operating costs
Coal washing plant flow diagrams
Coal washing vs. specific gravity
Coals in Appalachian region
Coals in U.S. by rank
Coals, U.S., ash and sulfur content
Combustion emissions control
"Combust ion-SO, removal" process for coal tailings
Cominco process flow diagram
Cominco process for SO recovery, capital
investment
Cominco process for SO^ recovery,
flow
diagram
Cominco process for SO2 recovery from smelter
gases
Cominco process for SOj recovery operating costs
Cominco process for up-grading SO, gases
(B i-2, iii-6, vii-9
app. A-2; F iii-50)
(Z 14)
(See also under coal
tailings)
(X91)
(Xll)
(T 9, 38)
(B i-2, iii-6, vii-19-20,
app. A-l-2; F iii-50)
(B i-13ff, vii-21, vii-38,
vii-40)
(B v-2)
(T 9, 38)
(Z 13)
(CC 4, f-4, f-g, t-2,
t-3; DD 8; G 38, 40)
(CC t-4. t-5)
(E 62. 75, 82, 89. 92.
100, 107)
(E 66, 76, 81, 83, 88.
90, 94, 99, 101, 106,
108)
(D36)
(CC t-4, t-5)
(E 71. 77, 84, 91.
102. 109. 112. 114,
116. 128; X 35, 36,
38)
(CC f-2. f-3. f-4)
(DD4)
(N4, 5)
(CC t-3)
(Z26)
(B i-3ff. v-12)
(S vi-a-9)
(FF 13, f-5)
(FF f-1)
(FF 7, f-1)
(FF 14, f-6, f-7)
(R iii-2, via-8)
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High Sulfur CombuBtor Study - Review of Literature
Page S ix.
High Sulfur Combustor Study - Review of Literature
Page Seven.
Commercial Testing and Engineering Company (Z 15)
Compound water cyclone for pyritic sulfur removal
from coal (JJ 6, 69, 73)
Concentrating spiral for pyritic sulfur removal
from coal (JJ 6, 86, 91)
Concentrating table for pyritic sulfur removal
from coal (JJ 6, 35, 37)
Cyclones for dust removal (W 9, 44, 50)
DAP-Manganese process for SO2 removal (S 148)
DAP-Manganese process for SO, removal (EE 6)
Dimethyalaniline (DMA) process for SO, recovery (R iii-3, vi-a-1,
vi-a-7) .
Dust removal equipment (wet type) costs (W 158)
Dust removal equipment efficiencies (W 155)
Dust removal from gases (S 136)
Dust removal from flue gases, costs (S 138)
Dust removers, centrifugal type (W 44)
Dust removers, venturi type (W 58)
Dust removers, wet types (W 50)
Economic gains through coal desulfurization (F ii-22, in-15)
Electrostatic precipitation high-voltage type (W 81)
Electrostatic precipitation low-voltage type (W 96)
Electrostatic precipitators (Z 33. 34)
Electrostatic precipitators for high-resistivity dust (Z 34)
Energy consumption, U.S., 1950-1955 (L 13)
Energy cost calculation (BB 13 t-3)
Float-sink test data on U.S. coals (JJ HI)
Float-sink testing of coals . (Z 15)
Float-sink tests for coal (CCS, f-1, f-5)
Fluidized-bed coal burning boilers (M 1)
Fluidized-bed combustion (Z 27)
Fluidized-bed fuel diluent material (M 3)
"Fluidized-bed roasting" process for pyrites (B i-7)
rVash bricks (H 46)
Flyash removal (S 139)
Flyash utilization (S 141)
Gravity separation for pyrite removal from coal
Grill (Mn-Mg Oxide) process for SO2 removal
Grillo process for SO removal from flue gas
2
H
Hardgrove grindability, Illinois coal
Heating required for making H2SO4 from low-SOg
gases
High-sulfur coals utilization with coal beneficiation
High-sulfur combustor study
Hitachi (active carbon) process for SO removal
Humprey spiral for pyrite removal from coal
Hydrogen sulfide from reformer natural gas -
Sulfur Reaction
Hydrogen sulfide - reformed natural gas reaction
equilibrium
Hydrogen Sulfide synthesis from SO, and methane
Illinois coal ash fusion temperature
Illinois coal sulfur content
Illinois Geological Survey
Iron from coal tailings
Iron oxide content in coal tailings
Iron oxide reduction in pyrite cinders
Iron oxide (Siemens Schuckerwerk, Germany)
process for SO2 removal
Iron recovery from coal pyrites
Iron recovery from pyrite cinders, process flow
diagram
Iron recovery from coal pyrite, process flow
diagram
Kiyoura-TIT (catalytic oxidation-NH, injection)
process for SO, removal
Kiyoura-TIT process for SO2 removal
(B iii-3)
(EE 11)
(X 57)
(T 9, 37)
(R vi-a-5)
(B i-11)
(Z 16)
(EE 10)
(Z 14)
(GG 199, 202)
(GG 200)
(GG 131, 198)
(T 8, 9, 36)
(T 5, 11, 31, 33,
34, 38)
(Z 9, 15)
(B iii-8)
(B vii-20)
(Bv-7)
(EE 12)
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High Sulfur Combuetor Study - Review of Literature
Page Eight.
High Sulfur Combustor Study - Review of Literature
Page Nine.
Kulscar process, capital investment
Kulscar process, flow diagram
Kulscar process for SO2 reduction
Kulscar process opera ting costs
Low-sulfur coal reserves, U.S.
Lurgi process for SO_ removal from flue gases
M
Arthur G. McKee & Company
Mitsubishi (Red Mud) process for SO, removal
Molten carbonate process for SO removal from
flue gases
Molten salt process for coal gasification
Monsanto (catalytic oxidation) process for SO,
removal
Monsanto process for SO. recovery
Municipal air pollution control laws
Organic sulfur in Illinois coal
Organic sulfur in U. S. coals
Outokumpu process for high-sulfur coal
Outokumpu process for pyrites
Particle-size effect on coal washing
Particulate measurements for combustion products
Participate pollutant emissions from burning coal
Pope, Evans and Bobbins, Incorporated
Power Plant costs based on burning coal refuse
Power plant operating costs. U. S., 1955-1968
Princeton Chemical (SO2 reduction) process for
SO, removal
Pyrite Beneficiation
Pyrite cinders composition
Pyrite concentration
(GG 178, 259)
(GG 172)
(GG 37, 46, 172. 173,
178, 183, 271)
(GG 184, 258)
(S51)
(X57)
(Z24)
(EE 13)
(X57)
(X 116)
(EE 5)
(B i-13; EE 5)
(S 176, 183, 332)
(T 34)
(D 11; E 27| JJ 111)
(B v-22)
(B i-9. v-14)
(DD 8)
(Z37)
(W 3, 7, 150)
(Z28)
(B app. D-l)
(L26)
39;
(EE 13)
(B iii-5; C 15,
F iii-20)
(F iii-101)
(B iii-5; C 15, 39
F iii-20)
Pyrite content in coal refuse
Pyrite from coal refuse, analysis
Pyrite recovery from coal
Pyrite removal from coal
Pyrite removal from fine coal
Pyrite removal methods for fine coals
Pyrites in coal beds
Pyrites in Illinois coal
Pyrites removal from coal by tabling
Pyrites removal from coal
Pyrites removal from coal by kinetic separation
Pyritic sulfur in U.S. coals
Pyritic sulfur fremoval from U. S. coals
Pyritic sulfur removal from coal
Pyrites removal from U. S. coals
Pyritic coal utilization economics
Red Mud (Mitsubishi) process for SO, removal
Reinluft (carbon adsorption) process Tor SO2
removal
Reinluft process capital investment
Reinluft process for SO, removal from flue gases
Reinluft process operating costs
Roberts and Schaefer Company
Showa Denko (ammonia scrubbing) process for SO2
removal
Spiral concentrator for pyritic sulfur removal
from coal
Stack costs
Stack location evaluations
State air pollution control laws
Steam generator emission control by alkaline
solution scrubbing
Steam generator, pulverized coal fired
Steam generators, capital costs
Steam generator emission control by MgO slurry
Steam power plants, capital costs
Steam power plants, fuel costs
(C3)
(C 6. 7)
(C 15, 39; F iii-20)
(KK 1)
(KK 4)
(Z 15)
(KK 1)
(T34)
(Z 14)
(Z 13)
(Z 15)
(JJ 111; KK 6; D 11;
E 27; N 5)
(Z 14, 15)
(X35)
(Z 14. 15)
(Z 15, 16)
(EE 13)
(EE ii, 6, 23)
(EE 28, 48)
(X 56)
(EE 28, 49, 50)
(Z 16)
(EE 9)
(JJ 6. 86, 91)
(X 101)
(X99)
(S 175, 179)
(Y 5)
{BB f-8, f-12, f-14,
f-15; f-16. f-18)
(BB t-2, f-20)
(Y3, 5)
(BB 11, t-2)
(BB 13, t-3)
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High Sulfur Combustor Study - Review of Literature
Page Ten.
High Sulfur Cotnbuator Study - Review of Literature
Page Eleven.
Steam power plants, operating costs
Steam turbines - electric generators, capital costs
Stone & Webster-Ionic (sodium eulfite) process for
SO, removal
Sulfacid process for SO, removal
Sulfur consumption, U.S., 1945-1970
Sulfur content in coal refuse
Sulfur dioxide content in H SO4 plant tail gases
Sulfur dioxide content of gas from burning coal pyrite
Sulfur "dioxide gas up-graded by DMA process
Sulfur dioxide, liquefied market
Sulfur dioxide-methane reaction equilibrium
Sulfur dioxide minimum concentration required for
economic H_SO4 production
Sulfur dioxide recovery by ammonium sulfite
solutions
Sulfur dioxide recovery from smelter gases,
Cotninco process
Sulfur dioxide recovery systems for HgSO. plant
tail gases
Sulfur dioxide reduction, Asarco process costs
Sulfur dioxide reduction by carbon,
thermodynamics
Sulfur dioxide reduction by coke
Sulfur dioxide reduction by coke, .capital investment
Sulfur dioxide reduction by coke, operating costs
Sulfur dioxide reduction by hydrocarbons
Sulfur dioxide reduction by H,-CO mixed gases
Sulfur dioxide reduction by H_S, flow diagram
Sulfur dioxide reduction by methane
Sulfur dioxide reduction by methane, flow diagram
Sulfur dioxide reduction by methane. Yushkevich
process
Sulfur dioxide reduction by reformed natural gas
Sulfur dioxide reduction costs
Sulfur dioxide removal by B&W-Esso process
Sulfur dioxide removal by moltan alkali carbonates
Sulfur dioxide removal by Na2SO,-ZnO process
Sulfur from hydrogen sulfide, Claus process
(BB 13, t-3)
(BB t-2, f-21)
(EE 14)
(LLI-iv-37, I-iv-f-21)
(EE 32)
(D 48, 53; E 48;
F iii-20)
(R vi-a-5)
(F iii-71)
(H iii-3)
(R iii-4)
(GG 131. 165, 185,
268)
(R vi-a-4}
(FF 7, f-1)
(FF 6, f-1)
(LL I-iv-60)
(H iii-3, vi-a-11)
(GG 13)
(GG 6, 13, 110, 111)
(GG 120, 124, 127,
130)
(GG 122. 126, 128,
156. 159)
(GG 19. 24. 25. 309)
(GG 7. 290)
(GG 202)
(FF 10. f-2; GG 6,
19. 24. 25)
(GG 225. 228, 229)
(GG 162, 163)
(GG7, 48, 50)
(GG7)
(Y 5)
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High Sulfur Combustor Study - Review of Literature
Page Twelve.
Texas Gulf Sulfur (TGS) process for SO. reduction
6
(FF 10; GG 34, 43,
46)
W
Washability test data on U.S. coals
Paul Weir Company
Wellman-Lord process for SO. removal
Wellman-Lord process (sodium sulfite) for SO
removal
West (T GS) process for SO reduction
(JJ 18, 25, 181)
(Z 14)
(S 154)
(EE 7)
(GG 34, 46, 164,
170)
Yushkevich process for sulfur recovery from SO,
(GG 162, 163)
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