EPA-R2-73-188
April 1973 Environmental Protection Technology Series
Characterization
of Glaus Plant Emissions
Office of Research and Monitoring
U.S. Environmental Protection Agency
Washington, D.C. 20460
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EPA-R2-73-188
Characterization
of
Glaus Plant Emissions
by
W. D. Beers
Processes Research, Inc.
2912 Vernon Place
Cincinnati, Ohio 45219
Contract No. 68-02-0242, Task No. 2
Program Element No. 1A2013
EPA Project Officer: G. S. Haselberger
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND MONITORING
U. S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, B.C. 20460
April 1973
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This report has been reviewed by the Environmental Protection Agency
and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
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ACKNOWLEDGMENT
The author wishes to acknowledge the assistance of Messrs. R. I. Tarver
and G. N. Thomas in the development of this report, the helpful guidance and
critique by Messrs. G. S. Haselberger and M. R. Jester, and the contributions
to the report by firms whose information appears in the Appendix. In addition,
the author wishes to acknowledge the many sources of information used and
referred to in the Bibliography.
W. D. Beers
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CHARACTERIZATION OF
CLAUS PLANT EMISSIONS
INDEX
Section
I
II
III
Title
Introduction
IV
Summary
Claus Sulfur Plant Technology
A. Claus Process Variations
B. Feed Gas Concentration
C. Product Sulfur Capacity
D. Claus Sulfur Recovery
E. Claus Tail Cas
F. Information from Claus Plant Operating and
Design Firms
Claus Sulfur Plants in the United States
Page
1
2
4
7
8
9
9
10
V
VI
A. Claus Sulfur Production
B. Claus Plant Emissions
C. Companies Operating Claus Plants
D. Claus Plant Design Firms
Claus Sulfur Plants in Canada
Reduction of Claus Plant Emissions
A. Flue Gas Desulfurization Processes
B. Beavon Sulfur Removal Process
C. Cleanair Sulfur Process
D. Institut Francais du Petrole Process
11
11
13
14
15
16
17
17
19
19
Appendix
A
B
C
D
E
Map of United States Claus Plants
Claus Process Flow Diagrams
Claus Sulfur Plant Data
Claus Sulfur Plants in Canada
Amoco Production Company Information
iv
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Appendix Title
F Elcor Chemical Corporation Information
G Shell Oil Company Information
H Stauffer Chemical Company Information
I Ford, Bacon & Davis Information
J The Ralph M. Parsons Company Information
K J. F. Pritchard & Co. Information
L Chiyoda Chemical Engineering & Construction Co., Ltd.
Information
M Institut Francais du Petrole Information
N Wellman-Power Gas Information
0 Bibliography
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SECTION I - INTRODUCTION
Glaus plants produce sulfur from hydrogen sulfide and sulfur dioxide by gas
phase reactions. Numerous Claus sulfur plants are operated in the United States
in connection with natural gas and petroleum refining.
Because of the apparent potential for atmospheric pollution from unconverted
hydrogen sulfide and sulfur dioxide in Claus plant tail gas, a survey was under-
taken to collect information concerning Claus sulfur plant emissions and control.
The present report is based on review of literature, supplemented with data
from companies operating and/or designing Claus plants.
In view of the rapid pace at which changes are taking place in Claus plant
technology and applications, the plant inventories and bibliography presented in
this report should be dated. The inventory of Claus plants in Canada was com-
pleted in December 1971. The inventory of Claus plants in the United States, and
the bibliography were completed in June 1972, based on current publications.
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SECTION II - SUMMARY
Glaus sulfur plants convert hydrogen sulflde and sulfur dioxide to sulfur
by gas phase reactions near atmospheric pressure, using catalysts in the final"
stages. A number of Claus process variations are used to accommodate various
concentrations of acid gas feed.
There are 169 Claus sulfur plants in the United States having rated daily
capacities totaling over 15,800 long tons. Most of these plants are based on
acid gas from natural gas or petroleum refining.
Claus plants are found in 31 states. The number in each state is shown on
the map of the United States in Appendix A.
The tail gas from a Claus plant contains hydrogen sulfide (l^S) and sulfur
dioxide (S02>, but the tail gas is usually burned, converting the H2S to sulfur
oxides. The annual emissions from Claus sulfur plants in the United States are
estimated to total 875,000 short tons of SC-2 equivalent. The estimated Claus
plant emission for each state is shown on the map in Appendix A.
These estimates assume that the Claus sulfur production averages 60 percent
of the rated plant capacity and that the Claus sulfur recovery averages 90 per-
cent. Additional catalytic stages could increase the Claus sulfur recovery to
about 97 percent, eliminating 70 percent of the Claus plant emissions.
The Beavon Sulfur Removal Process and the Cleanair Sulfur Process are claimed
to increase sulfur recovery to more than 99.9 percent, eliminating about 99 percent
of Claus plant sulfur emissions. The investment and operating costs for Claus-
Beavon plants or Claus-Cleanair plants are about twice those for Claus plants
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alone. Hence, the production costs for Claus-Beavon sulfur or Claus-Cleanair sul-
fur are about twice those for Glaus sulfur.
The Institut Francais du Petrole (IFF) Process is claimed to increase the
sulfur recovery to more than 99 percent, eliminating about 90 percent of Glaus
plant emissions. The investment and operating costs for an IFF addition is about
half of those for the Glaus sulfur plant alone. Accordingly, the production costs
for Claus-IFP sulfur are about 50 percent higher than those for Glaus sulfur.
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SECTION III - GLAUS SULFUR PLANT TECHNOLOGY
Glaus plants produce elemental sulfur from the t^S in acid gas obtained
principally from natural gas and petroleum refining. They are named after an
English chemist, C. F. Glaus, who, about 1885, initiated development of the gas
phase process used in such plants.
The number of Glaus sulfur plants in each state and annual sulfur emissions
are shown on the map of the United States in Appendix A. The basis of the Glaus
plant emissions shown is explained later in this report.
A. GLAUS PROCESS VARIATIONS
Flow diagrams presented in Appendix B are typical of the four principal
variations used in Glaus sulfur plants in the United States, as follows:
Direct oxidation
Split flow
Straight through
Sulfur recycle
These are gas phase processes as distinguished from liquid phase processes such
as the Deal-Sulfolane (Shell Oil Company), Giammarco-Vetrocoke, Ferrox, Lacy-
Keller, Perox, Stretford, Thylox, and Townsend processes for producing elemental
sulfur from l^S.
A Glaus sulfur plant usually operates near atmospheric pressure with
only enough extra pressure to overcome the pressure drop through the plant.
1. Direct Oxidation. In the original Claus process, called "direct
oxidation," H2S was partially oxidized with air over a bauxite or iron ore
catalyst in a single reactor, as follows:
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3H2S + 1.502 > 3S + 3H20 + 159,000 calories
Excessive temperatures experienced with this highly exothermic reaction resulted
in poor yields. This soon led to partial recycle of the tail gas to control the
temperatures for acceptable yields.
This process is used in modern plants having dilute acid gas feed.
The sulfur recovery is increased by adding catalytic stages.
2. Split Flow. About 1937, I. G. Farbenindustrie A. G. initiated two
improvements in the Claus process, one or the other of which appears in many
Glaus plants in the United States. In the first of these, called "split flow,"
one third of the H2S is burned completely to sulfur dioxide (S02) in a waste
heat boiler, as follows:
H2S + 1.502 > S02 + H20 + 131,000 calories
The S02 is then reacted with the other two thirds of the H2S over bauxite at
about 385C, as follows:
2H2S + S02 > 3S + 2H20 + 28,000 calories.
Thus, only about one fifth of the heat is evolved in the catalytic reactor. Satis-
factory temperatures are attained in much smaller reactors, and much of the heat
of combustion is recovered as useful steam.
3. Straight Through. The second I. G. Farben improvement, called
"straight through," is the noncatalytic partial oxidation of the H2S to sulfur
with air at temperatures up to 1000C in a waste heat boiler. About 60 percent
conversion to sulfur is achieved, and the flue gas is cooled and passed to the
catalytic reactor for the remaining conversion. In this variation of the Claus
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Process, much of the reaction heat is recovered as useful steam, and some sulfur
may be condensed from the flue gas to improve the conversion in the catalytic
reactor.
4. Sulfur Recycle. The acid gas streams feeding Claus plants sometimes
contain so little H2S that reaction temperatures cannot be maintained without
supplemental heat. This gives rise to additional Claus plant variations, includ-
ing addition of hydrocarbons to acid gas ahead of the burner and/or indirect
preheating of the acid gas and/or air ahead of the burner or catalytic reactor.
One Claus plant variation, particularly useful for dilute acid gas
having low sulfur oxide content, is called "sulfur recycle." In this, some
product sulfur is burned with air to produce SC>2 and heat.
The acid gases fed to Claus plants in the United States usually con-
tain little or no sulfur oxides, because they are from the "sweetening" units of
natural gas plants and petroleum refineries. These sweetening units usually
capture the H2S and the carbon dioxide, but seldom remove sulfur oxides from the
natural gas or refinery gas.
On the other hand, the acid gas fed to a Claus plant from a smelter
contains sulfur oxides as well as l^S. The "direct oxidation" process probably
would be ideal for such a feed gas.
5. Conversion Incomplete. The Claus Process reactions are reversible,
and complete conversion to sulfur is prevented by the sulfur vapor and water
vapor produced. Attempts to improve conversion by operating the catalytic re-
actors at temperatures below the sulfur dewpoint have not succeeded. The liquid
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sulfur apparently blocks the catalyst. Instead, improved conversion is achieved
by condensing sulfur from the gas stream between Claus stages. With a dilute acid
gas stream feeding a Claus plant, less sulfur need be condensed between the Claus
stages to keep the sulfur dewpoints below the catalyst surface temperatures.
Nevertheless, improved conversion for such a dilute feed will still result from
condensing sulfur between Claus stages. In a modern Claus plant, more than half
of the sulfur is condensed ahead of the final catalytic stage.
Removal of water vapor to improve conversion to sulfur has also been
tried by condensing water from the gas stream between catalytic stages. Because
of plugging and highly corrosive conditions, these attempts have all been unsuc-
cessful.
6. Reheat Variations. The reheating of the gas stream after condensing
sulfur presents several Claus plant variations, as follows:
a_. External-fired heat exchange.
b_. Internal gas-to-gas heat exchange.
c_. Injection of hot gas from hydrogen sulfide burner.
d_. Injection of hot gas from a hydrocarbon burner.
e_. Injection of hot gas from upstream.
While the choice of reheating methods is important in adapting the
Claus Process to particular plant circumstances, these variations appear to have
little effect on the sulfur recovery efficiency of Claus plants.
B. FEED GAS CONCENTRATION
1. Process Choice. The optimum process arrangement for a Claus plant
depends largely on the hydrogen sulfide concentration in the acid gas feed. For
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high HoS concentrations, such as 90 mole percent, the "straight through" process
is preferred. For intermediate concentrations, such as 50 mole percent H2S, the
"split flow" process is suitable. Low l^S concentrations, such as 15 mole per-
cent, favor the "direct oxidation" process, or sometimes the "sulfur recycle"
process.
2. Claus Plant Costs. The greater gas volumes involved with more
dilute acid gas increase the Claus plant investment and sulfur production costs
somewhat. For typical Claus plants, each to produce 100 long tons of sulfur
daily, the investment and sulfur production costs for various acid gas concentra-
tions are approximately as follows:
Mole Percent H2S
In Acid Gas Feed
15
50
90
PRODUCT SULFUR CAPACITY
Claus Plant
Investment
$1,400,000
$1,000,000
$ 900,000
Sulfur Production
Cost Per Long Ton
$14
$11
$ 9
Product sulfur capacity has a more pronounced effect on Claus plant
investment and sulfur production costs. For typical Claus plants fed with
50 mole percent H2S feed gas, the investment and sulfur production costs for
various capacities are approximately as follows:
Product Sulfur
Daily Capacity Claus Plant Sulfur Production
(Long Tons) Investment Cost Per Long Ton
10 $ 300,000 $26
100 $1,000,000 $11
1000 $4,300,000 $ 8
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D. GLAUS SULFUR RECOVERY
The percent conversion to sulfur is affected by the number of catalytic
stages in Claus plants. For Glaus plants fed with 90 mole percent H2S, the
sulfur recovery variation relative to the number of catalytic stages is approxi-
mately as follows:
Number of Catalytic Stages Percent Sulfur Recovery
1 85
2 94
3 97
The percentage of sulfur recovery also varies with the concentration of
the acid gas fed to the Claus plant. For Claus plants having two catalytic stages,
the sulfur recoveries for various acid gas concentrations are approximately as
follows:
Mole Percent H2S Percent Sulfur Recovery
In Acid Gas Feed Two Catalytic Stages
15 90
50 93
90 94
E. CLAUS TAIL GAS
The unrecovered sulfur appears in the Claus plant tail gas principally
as H2S, elemental sulfur, and S02 with lesser amounts of other sulfur compounds.
Some of the early Claus plants vented the tail gas directly to the atmosphere.
Others scrubbed the tail gas in towers packed with limestone wetted with water.
Incineration of the tail gas is the method most often used in United States
Claus plants treating the tail gas. Incineration converts the unrecovered sulfur
almost entirely to sulfur oxides.
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For a Claus plant recovering 100 long tons of sulfur daily, the incin-
erator stack gas sulfur dioxide equivalents, for various numbers of catalytic
converters, and various acid gas feed concentrations, are approximately as
follows:
Number of Mole Percent H2S Stack Gas S02
Catalytic Stages In Acid Gas Feed Short Tons Daily
1
2
2
2
3
INFORMATION
90
15
50
90
90
FROM CLAUS PLANT OPERATING AND
39
25
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7
DESIGN FIRMS
In response to questionnaire letters, information regarding Claus sulfur
plants was submitted by the following operating firms and design firms:
Amoco Production Company
Elcor Chemical Corporation
Shell Oil Company
Stauffer Chemical Company
Ford, Bacon & Davis
The Ralph M. Parsons Company
J. F. Pritchard & Co.
Information submitted by these firms is presented in Appendices E, F, G, H, I,
J, and K, respectively.
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SECTION IV - GLAUS SULFUR PLANTS:IN THE UNITED STATES
The rated sulfur capacities are published for many United States Claus plants.
These are listed in Appendix C. In addition to the operating company names and
locations, the Claus plant ages and sources of acid gas feeds are listed for most
of the plants. For the 169 plants listed, the rated daily sulfur capacities total
more than 15,800 long tons.
A. CLAUS SULFUR PRODUCTION
The annual sulfur production is published for twenty-three Claus plants
based on natural gas, having rated daily sulfur capacities totaling 2,068 long
tons. The annual sulfur production from these recently totaled 456,000 long
tons. If this proportion is typical for all United States Claus plants, bearing
in mind that some are standby and others not yet in operation, the annual sulfur
production from United States Claus plants totals approximately 3,500,000 long
tons.
B. CLAUS PLANT EMISSIONS
The acid gas feed composition, number of catalytic stages, and tail gas
treatment, if any, are seldom published for United States plants. However, it
seems probable that the typical Claus plant in the United States has two cataly-
tic stages and the tail gas is burned.
Assuming that the sulfur recovery averages 90 percent, bearing in mind
that many plants appear to have excess sulfur capacity, improving their perform-
ance, the annual emissions from United States Claus plants are equivalent to
approximately 875,000 short tons of S02.
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On this basis, Che emissions from Glaus plants in various areas of the
United States are approximately as follows (a plus sign, + , denotes some plant
capacity not reported):
Area
Alabama
Alaska
Arkansas
Los Angeles
Other California
Colorado
Delaware
Florida
Hawaii
Illinois
Indiana
Kansas
Louisiana
Michigan
Minnesota
Mississippi
Missouri
Montana
New Jersey
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
£1 Paso, Texas
Midland, Texas
Lubbock, Texas
Amarillo, Texas
San Antonio, Texas
Corpus Christi, Texas
Houston, Texas
Beaumont, Texas
Dallas, Texas
Utah
Virginia
Washington
Number of
Glaus Plants
2
1
4
14
6
1
2
4
1
4
3
2
6
3
2
5
1
3
8
7
1
2
3
2
6
2
20
5
3
7
1
5
5
10
2
1
1
Combined Daily
Sulfur Capacity
(Long Tons)
386
9
185
1,794+
902
18
775
664
+
569
414
44
570
89
170
1,327+
80
233
647+
147
50
243
95
23
452
1,009
592
93
76
276
85
696+
358
1,685
22
50
20
Computed
Annual Emission
S02 Equivalent
(Short Tons)
21,400
500
10,200
99,300+
49,900
1,000
42,900
36,700
+
31,500
22,900
2,400
31,500
4,900
9,400
73,500+
4,400
12,900
35,800+
8,100
2,800
13,500
5,300
1,300
25,000
55,800
32,800
5,200
4,200
15,300
4,700
38,500+
19,800
93,300
1,200
2,800
1,100
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Area
West Virginia
Wisconsin
Wyoming
Total United States
Total Texas
Total California
Number of
Claus Plants
1
1
12
58
20
Combined Daily
Sulfur Capacity
(Long Tons)
27
15
919
15,809+
4,870+
2,696+
Computed
Annual Emission
S02 Equivalent
(Short Tons)
1,500
800
50.900
875,000+
269,600+
149,200+
The number of Claus plants and annual Claus plant emission for each state
are shown on the map of the United States in Appendix A.
C. COMPANIES OPERATING CLAUS PLANTS
The leading operators of Claus sulfur plants in the United States include
the following companies:
Allied Chemical Corporation
Amarillo Oil Company
American Oil Company (Standard Oil Company, Indiana)
Amoco Production Company (Standard Oil Company, Indiana)
Ashland Oil, Inc.
Atlantic Richfield Company
BP Oil Corporation (Standard Oil Company, Ohio)
Chevron Oil Company (Standard Oil Company of California)
Cities Service Oil Company
Continental Oil Company
Getty Oil Company
Gulf Oil Corporation
Humble Oil & Refining Company
Marathon Oil Company
Mobil Oil Corporation
Monsanto Company
Olin Corporation
J. L. Parker Company
Phillips Petroleum Company
Shell Oil Company
Signal Oil & Gas Company
Stauffer Chemical Company
Sun Oil Company
Texaco, Inc.
Union Oil Company of California
Warren Petroleum Corporation
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D. GLAUS PLANT DESIGN FIRMS
A number of firms are experienced designers of Glaus sulfur plants in
the United States, including the following:
Black Sivalls & Bryson, Inc.
Delta Engineering Corporation
Dresser Engineering Corporation
Fluor Corporation
Ford, Bacon & Davis, Inc.
Howe-Baker Engineers, Inc.
Hudson Engineering Corporation
The Ortloff Corporation
The Ralph M. Parsons Company
J. F. Pritchard & Company
Pona Engineers, Inc.
Steams-Roger Corporation
Weatherby Engineering Corporation
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SECTION V - CLAUS SULFUR PLANTS IN CANADA
Information regarding Claus sulfur plants located in Canada is presented in
Appendix D. The daily sulfur capacities of the 66 Canadian plants listed total
more than 25,400 long tons. This is about 60 percent more than the combined daily
sulfur capacity of 169 Claus plants located in the United States.
About 93 percent of the Canadian Claus sulfur capacity is based on Alberta
natural gas, and are located upwind of the population centers in the northern
United States,
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SECTION VI - REDUCTION OF GLAUS PLANT EMISSIONS
Beyond the addition of Claus catalytic stages, the following methods have
been proposed to reduce sulfur emissions from Claus plants in the United States:
Alberta Sulfur Research, Ltd. Sulphoxide Process
Rhodia, Inc. Cataban Process
Union Carbide Process
Chiyoda Thoroughbred 101 Flue Gas Desulfurization Process
Wellman-Lord Sulfur Dioxide Recovery Process
Monsanto NOSOX Process
Takahax Process
Beavon Sulfur Removal Process
Cleanair Sulfur Process
Institut Francais du Petrole Process
The Alberta Sulfur Process, Ltd. Sulphoxide Process is claimed to reduce
Claus tail gas sulfur contents to less than 1000 ppm. This process uses an
organic sulphoxide as a liquid catalyst medium in which to react the H2S and S02
to form elemental sulfur. The COS and CS2 are converted to C02 and sulfur. The
process has been operated in the laboratory. Application to a full-scale plant
remains to be done.
The Rhodia, Inc. Cataban Process, which has been developed through the pilot
plant stage, uses an aqueous solution of a chelated iron salt as a liquid phase
catalyst, oxidizing hydrogen sulfide to elemental sulfur. Texas Gulf Sulfur and
another company are reported to be investigating the use of this process for re-
ducing Claus plant sulfur emissions.
The Union Carbide Process is reported as using a new catalyst in an absorp-
tive operation. It is claimed that this process can reduce Claus tail gas sulfur
contents to about 50 ppm0 Union Carbide Corporation is expected to announce soon
further information about this process.
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A. FLUE GAS DESULFURIZATION PROCESSES
Numerous processes being developed for removal of sulfur dioxide from
power plant stack gas appear applicable to incinerated Claus tail gas. As the
S02 concentrations are several times higher in incinerated Claus tail gas than
in power plant stack gas, the treatment of the incinerated Claus tail gas appears
somewhat easier.
1. Two such processes now being vigorously advocated in the United
States are the Chiyoda Thoroughbred 101 Flue Gas Desulfurization Process and the
Wellman-Lord Sulfur Dioxide Recovery Process.
Information regarding the Chiyoda process was submitted by Chiyoda
Chemical Engineering & Construction Co., Ltd., in connection with their adver-
tisement in Hydrocarbon Processing. This information is presented in Appendix L.
Information regarding the Wellman-Lord process was obtained by
Environmental Protection Agency personnel on visits to plants in Japan where this
process is in operation. This information is presented in Appendix N.
2. Monsanto Enviro-Chem Systems, Inc., is reported to be developing its
NOSOX Process to remove sulfur dioxide from incinerated Claus tail gas.
3. Ford, Bacon & Davis has recently been licensed to use the Takahax
Process of Tokyo Gas Company. This process is reported to use an alkaline solu-
tion to scrub the Claus tail gas and to produce elemental sulfur.
B. BEAVON SULFUR REMOVAL PROCESS
The Beavon Sulfur Removal Process is reported to have been proven in a
pilot plant by cooperation of The Ralph M. Parsons Company and Union Oil Company
of California. Union Oil is said to be planning to use this process at their
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Los Angeles refinery (Wilmington, California), where Union Oil already has a
Claus sulfur plant.
The process is named for David K-. Beavon, Director of Process Operations
for The Ralph M. Parsons Company.
A flow diagram for this process is presented in Appendix J, together
with information submitted by The Ralph M. Parsons Company. The process is
claimed to reduce the tail gas sulfur content to 40 to 80 ppm equivalent S02,
depending on the sulfur content of the Claus tail gas before treatment.
In the Beavon Process, the Claus plant tail gas is mixed with hot com-
bustion gas produced by burning fuel gas with air. The resulting reducing mixture
is passed through a catalytic reactor resembling that of a Claus plant. On the
cobalt-molybdate catalyst, all of the sulfur is hydrogenated to H2S. Water is
then condensed from the gas. The cooled gas stream is passed to a Stretford
section in which the l^S is removed from the gas and converted to elemental sul-
fur. The Stretford process is widely used outside of the United States and one
Stretford unit was recently installed at Long Beach, California, to sweeten natural
gas.
The Beavon Sulfur Removal Process addition to an existing Claus plant
costs about as much as the Claus plant itself. With the doubled fixed costs and
added utilities costs, the production cost for Claus-Beavon sulfur is approximately
twice that for Claus sulfur. Hence, the inventor is promoting this process, not
as an economical method for producing sulfur, but strictly as a pollution abate-
ment alternative.
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C. CLEANAIR SULFUR PROCESS
The Cleanair Sulfur Process of J. F. Pritchard & Co., was developed with
Texas Gulf Sulfur Company at the Okotoks, Alberta, Canada Claus sulfur plant.
This process is being used in a revision of the sulfur plant in the Gulf Oil
Corporation refinery at Philadelphia, Pennsylvania. This process is claimed to
reduce the tail gas sulfur content to less than 250 ppm by volume of equivalent
S02 without incineration or dilution. This would indicate an overall Claus-
Cleanair sulfur recovery of approximately 99.9 percent.
Information regarding the Cleanair Sulfur Process submitted by J. F.
Pritchard & Co., is presented in Appendix K. This process includes a Stretford
section, as does the Beavon Sulfur Removal Process already described. The Long
Beach, California, Stretford unit previously mentioned was built by J. F.
Pritchard & Co.
For a Claus-Cleanair sulfur plant, the investment and operating costs
are about twice those for a Claus plant having the same sulfur production capacity,
D. INSTITUT FRANCAIS DU FETROLE PROCESS
The Institut Francals du Petrole (IFP) Process has been in operation in
a Japanese refinery for several months, recovering sulfur from Claus tail gas.
Four more IFP units, three in Japan and one in Canada, are reported to be starting
operation. Information regarding this process submitted by Institut Francais du
Petrole is presented in Appendix M.
The IFP process is claimed to reduce the incinerator stack gas sulfur
content to about 1500 ppm S02 for an overall Claus-IFP sulfur recovery of about
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99 percent. The residual sulfur emission occurs principally because the carbonyl
sulfide (COS) and carbon disulfide (CS2> in the Claus tail gas are not converted
by the IFF process. The investment and operating costs for an IFF unit are about
half of those for the Claus sulfur plant alone. Hence, the addition of the IFF
unit results in Claus-IFP sulfur production costs about 50 percent higher than
those for Claus sulfur.
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APPENDIX A - MAP OF UNITED STATES CLAUS PLANTS
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AMHUAL CLAUS SULFUR PLANT
BY STAT£S>
N>
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APPENDIX B - GLAUS PROCESS FLOW DIAGRAMS
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109
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PROCESSES RESEARCH, IMC. F.I, HO
Lo< Jlion
INDUSTRIAL PLANNING
AND RESEARCH
CINCINNATI
NEW YORK
Checked by
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PROCESSES RESEARCH, INC. f,ie No
Location
Subject
UN tree*
INDUSTRIAL PLANNING
AND RfSEARCH
CINCINNATI
NEW YORK
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109
Job
UNITSD STATES
location
PROCESSES RESEARCH,INC.
INDUSTRIAL PLANNING
AND RESEARCH
CINCINNATI
File No
Checked by
No
QB
NEW YORK t"":P«'^ hv.
Acio
CLAUS
26
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PR 109
Job.
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Location
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING
AND RESEARCH
CINCINNATI
NEW YORK
f i le No
Cheded by
Computed hy [JJ
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27
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX C - GLAUS SULFUR PLANT DATA
28
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
ALABAMA
Humble Oil & Refining Co.
Flomaton, Escambia
Stauffer Chemical Co.
LeMoyne
Expansion
ALASKA
Energy Co. Alaska
Fairbanks, North Star
ARKANSAS
Arkla Chemical Corpo
Magnolia, Columbia
Expansion
The Bromet Co.
Magnolia, Columbia
Monsanto Co.
Eldorado, Union
Olin Corp.
McKamie, Lafayette
CALIFORNIA
Monsanto Co.
Avon
Union Oil Co. of California
Santa Maria, Santa Barbara
Allied Chemical Corp.
Richmond, Contra Costa
Expansion
Humble Oil & Refining Co.
Benicia, Solano
Shell Oil Co.
Martinez, Contra Costa
Union Oil Co. of California
San Francisco, San Mateo
Expansion
Allied Chemical Corp.
El Segundo, Los Angeles
Expansion
Atlantic Richfield Co.
Wilmington, Los Angeles
Collier Carbon and Chemical Corp.
Los Angeles, Los Angeles
Year
Sulfur Acid
Production Gas
Started So.urce
Daily
Sulfur
Capacity
Long
Tons
1972
Before 1962
Before 1972
1972
Natural Gas 136
Natural Gas 127
Natural Gas +123
Refinery
Before 1962
1962
1970
Before 1961
1944
Before 1967
1954
Before 1962
1968
1969
1966
1955
1971
1959
1964
1967
Before 1972
Natural Gas
Natural Gas
Chemical
Refinery
Natural Gas
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
19
+11
30
25
100
132
55
100
+100
270
100
70
+75
175
+100
65
Not
Two Trains
Standby
Reported
29
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
CALIFORNIA
Continental Oil Co.
Paramount, Los Angeles
Fletcher Oil & Refining Co.
Wilmington, Los Angeles
Golden Eagle Refining Co. Inc.
Torrance, Los Angeles
Gulf Oil Corp.
Santa Fe Springs, Los Angeles
Expansion
Expansion
Lomita Gasoline Co.
Long Beach, Los Angeles
Mobil Oil Corp.
Torrance, Los Angeles
Expansion
Powerine Oil Co.
Santa Fe Springs, Los Angeles
Standard Oil Company of California
El Segundo, Los Angeles
Stauffer Chemical Co.
Wilmington, Los Angeles
Expansion
Expansion
Expansion
Expansion
Expansion
Texaco, Inc.
Los Angeles, Los Angeles
Union Oil Co. of California
Willmington, Los Angeles
Expansion
Expansion
COLORADO
Continental Oil Coo
Denver, Adams
DELAWARE
Getty Oil Co.
Delaware City, New Castle
Stauffer Chemical Co.
Delaware City, New Castle
Expansion
Year
Sulfur
Production
Started
Acid
Gas
Source
Daily
Sulfur
Capacity
Long
Tons
1966
Before 1962
1959
Before 1961
Before 1962
1964
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
9
7 Standby
4 Standby
8
9
13
1971
Before 1962
1952
1962
1973
1968
1956
Before 1962
Before 1972
Natural Gas Not Reported
1967
1973
1967
1972
Before 1962
Before 1962
1962
1964
1967
Before 1972
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
85
Not
20
450
100
+20
+140
+8
+132
+50
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
50
49
+100
+200
18
375
260
+140
30
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
FLORIDA
Amerada Hess Corp.
Jay, Santa Rosa
Humble Oil & Refining Co.
Jay, Santa Rosa
Expansion
Louisiana Land & Exploration Co.
Jay, Santa Rosa
Louisiana Land & Exploration Co.
Escambia County
HAWAII
Dillingham Petroleum Corp.
Barbers Point, Honolulu
ILLINOIS
Anilin Company of Illinois
Wood River, Madison
Marathon Oil Co.
Robinson, Crawford
Mobil Oil Corp.
Joliet, Will
Union Oil Co. of California
Lemont, Cook
Expansion
Expansion
INDIANA
American Oil Co.
Whiting, Lake
Expansion
Expansion
Expansion
Atlantic Richfield Co.
East Chicago, Lake
Cities Service Oil Co.
East Chicago, Lake
KANSAS
Farmland Industries, Inc.
Coffeyville, Montgomery
Phillips Petroleum Co.
Kansas City
LOUISIANA
Cities Service Oil Co.
Lake Charles, Calcasieu
Year
Sulfur
Production
Started
1972
1971
1972
1972
1972
1972
1960
1970
1972
Acid
Gas
Source
Daily
Sulfur
Capacity
Long
Tons
Natural Gas 120
Natural Gas 14
Natural Gas +360
Natural Gas 82
Natural Gas 88
Refinery
Refinery
Refinery
Refinery
Not Reported
150
40
300
Before 1961
1964
1971
1952
1964
1972
1972
1971
1972
1968
1968
1972
Refinery 20
Refinery +34
Refinery +25
Refinery 64
Refinery +40
Refinery +43
Refinery +132
Refinery
Refinery
Refinery
Refinery
Refinery
85
50
6
38
100
31
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City. County
LOUISIANA
Gulf Oil Corp.
Belle Chasse, Plaquemines
Humble Oil & Refining Co.
Baton Rouge
Expansion
Stauffer Chemical Co.
Baton Rouge
Shell Oil Co.
Norco, St. Charles
Texaco, Inc.
Paradis, St. Charles
MICHIGAN
Leonard Refineries, Inc.
Alma, Gratiot
Marathon Oil Co.
Detroit
Expansion
Expansion
Mobil Oil Corp.
Uoodhaven, Trenton
MINNESOTA
Great Northern Oil Co.
Pine Bend
Expansion
North Western Refining Co.
St. Paul Park, Washington
MISSISSIPPI
Elcor Chemical Corp.
Canton, Madison
Shell Oil Co.
Jackson
Gulf Oil Corp.
Purvis, Lamar
Shell Oil Co.
Goodwater, Clarke
Chevron Oil Co.
Pascagoula, Jackson
MISSOURI
American Oil Co.
Sugar Creek, Jackson
Year
Sulfur Acid
Production Gas
Started Source
1972
Refinery
1956
Refinery
1962
1955
1963
1968
1965
1972
Before 1961
1971
1972
1971
Refinery
Refinery
Refinery
Refinery
Daily
Sulfur
Capacity
Long
Tons
40
1967
1972
1950
1965
1966
Refinery
Refinery
Refinery
Refinery
Refinery
10
+300
30
40
50
12
Before 1961
1962
1968
Refinery
Refinery
Refinery
27
+8
+34
60
+70
40
Natural Gas 12 Standby
Natural Gas 1250
Refinery 30
Natural Gas 35
Refinery Not Reported
Refinery
80
32
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
MONTANA
Farmers Union Central Exchange
Laurel, Yellowstone
Montana Sulfur & Chemical Co.
East Billings, Yellowstone
Montana Sulfur & Chemical Co.
Billings, Yellowstone
Expansion
NEW JERSEY
Allied Chemical Corp.
Elizabeth, Union
American Cyanamid Co.
Bound Brook, Somerset
Expansion
American Cyanamid Co.
Linden, Union
Anilin Company of New Jersey
Perth Amboy, Middlesex
Expansion
Amerada Hess Corp.
Fort Reading, Middlesex
Humble Oil & Refining Co.
Linden, Union
Freeport Sulfur Co.
Westville, Camden
Mobil Oil Corp.
Faulsboro, Camden
Expansion
NEW MEXICO
Amoco Production Co.
Artesia, Eddy
Cities Service Oil Co.
Milnesand, Roosevelt
Climax Chemical Co.
Oil Center, Lea
El Paso Natural Gas Co.
Eunice, Lea
Marathon Oil Co.
Indian Basin, Eddy
Northern Gas Products Co.
Hobbs, Lea
Year
Sulfur
Production
Started
1969
Before 1972
1956
1964
1958
1967
1972
1972
1957
1962
Before 1967
1970
Before 1961
Before 1961
1972
1960
1967
1962
Before 1961
1967
1969
Acid
Gas
Source
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery &
Chemical
Chemical
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
28
120 Standby
40
+45
30 Standby
12
Not Reported
Not Reported
35
+15
40
300 Two Trains
30
95
+90
26
20
18
30
36
13
33
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
NEW MEXICO
Warren Petroleum Corp.
Taturn, Lea
NEW YORK
Ashland Oil, Inc.
Buffalo
NORTH DAKOTA
Signal Oil & Gas Co.
Tioga, Williams
Expansion
Expansion
Texaco, Inc.
Lignite, Burke
OHIO
Ashland Oil, Inc.
Canton, Stark
Republic Steel Corp.
Cleveland, Cuyahoga
Sun Oil Co.
Toledo
Expansion
OKLAHOMA
Pioneer Natural Gas Co.
Madill, Marshall
J. L. Parker Co.
Madill, Marshall
PENNSYLVANIA
Atlantic Richfield Co.
Marcus Hook, Delaware
Expansion
Atlantic Richfield Co.
Philadelphia, Philadelphia
Expansion
BP Oil Corp.
Marcus Hook, Delaware
Gulf Oil Corp.
Philadelphia, Philadelphia
Sun Oil Co.
Marcus Hook, Delaware
United States Steel Corp.
Pittsburgh, Allegheny
Year
Sulfur Acid
Production Gas
Started Source
Daily
Sulfur
Capacity
Long
Tons
1961
1969
1953
1963
1967
1961
Natural Gas
Refinery
Refinery
Refinery
Refinery
Natural Gas
50
50
+23 Standby
+150
20
1970
1961
1958
1972
1967
Before 1961
Before 1961
1962
1964
1971
Before 1972
Before 1961
1955
Before 1967
Refinery
Chemical
Refinery
Refinery
Natural Gas
Natural Gas
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Chemical
50
6
12
+27
8
15 Standby
20
+32
38
+35
52
135
30
110
34
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City. County
TEXAS
American Smelting and Refining Co.
El Paso, El Paso
Elcor Chemical Corp.
Van Horn, Culbertson
Amarillo Oil Co.
Waha, Pecos
Marathon Oil Co.
Raan, Pecos
Mobil Oil Corp.
Coyanosa, Pecos
Texas American Sulfur Co.
Sand Hills, Crane
Phillips Petroleum Co.
Crane County
Expansion
Warren Petroleum Corp.
Waddell, Crane
Expansion
Warren Petroleum Corp.
San Hills, Crane
Northwest Production Corp.
Big Lake, Reagan
Expansion
Sid Richardson Carbon & Gasoline Co.
Kermit, Winkler
Wanda Petroleum Co.
Kermit, Winkler
Amarillo Oil. Col.
Goldsmith, ECtor
Amoco Production Co.
North Cowden, Ector
Odessa Natural Gasoline Co.
Odessa, Ector
J. L. Parker Co.
Penwell, Ector
Phillips Petroleum Co.
Goldsmith, Ector
Elcor Chemical Corp.
Midland, Midland
Amoco Production Co.
Midland Farms, Andrews
Year
Sulfur
Production
Started
1972
1969
1971
1967
1967
1966
Before 1961
1962
Before 1961
1968
1964
Before 1962
1962
Before 1961
1967
1967
1952
1961
Before 1962
Before 1961
1958
1956
Acid
Gas
Source
Smelter
Gypsum
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
Pilot
9 Plant
1000 Standby
2
13
29
15
100
+65
50
+45
50
3
+5
5
18
5
26
13
30
75
1 Standby
11
35
-------
PROCESSES RESEARCH,
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
TEXAS
Amoco Production Co.
South Fullerton, Andrews
J. L. Parker Co.
Andrews, Andrews
Sulpetro Corp.
Big Spring, Howard
Amoco Production Co.
Sundown, Hockley
Cities Service Oil Co.
Welch, Dawson
Cities Service Oil Co.
Seminole, Gaines
Cities Service Oil Co.
Lehman, Cochran
Cities Service Oil Co.
Lehman, Cochran
Diamond Shamrock Corp.
Sunray, Moore
Texas Sulfur Products Inc.
Dumas, Moore
Phillips Petroleum Co.
Borger, Hutchinson
Trans-Jeff Chemical Corp.
Tilden, McMullen
Expansion
Atlantic Richfield Co.
Fashing, Atascosa
Elcor Chemical Corp.
Fashing, Atascosa
Humble Oil & Refining Co.
Jourdanton, Atascosa
Warren Petroleum Corp.
Fashing, Atascosa
Shell Oil Co.
Person, Karnes
Expansion
Coastal States Gas Producing Co.
Kenedy, Karnes
Coastal States Petrochemical Co,
Corpus Christ!, Nueces
Year
Sulfur
Production
Started
1968
Before 1961
1966
1951
1970
Before 1961
Before 1972
1962
1951
1966
1968
Before 1962
1962
Before 1961
1960
1967
Before 1962
1962
1965
1968
1972
Acid
Gas
Source
Natural Gas
Natural Gas
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Refinery
Daily
Sulfur
Capacity
Long
Tons
6
15
10
48
4
28
4
9
&
30
13
33
20
+80
10
55
22
45
12
+23
9
85
36
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
TEXAS
Phillips Petroleum Co.
Sweeny, Brazoria
Atlantic Richfield Co.
Houston, Harris
Expansion
Signal Oil & Gas Co.
Houston, Harris
Expansion
Shell Oil Co.
Deer Park, Harris
Expansion
Expansion
Stauffer Chemical Co.
Baytown, Harris
Expansion
Atlantic Richfield Co.
Port Arthur, Jefferson
Expansion
BP Oil Corp.
Port Arthur, Jefferson
Gulf Oil Corp.
Port Arthur, Jefferson
Expansion
Mobil Oil Corp.
Beaumont, Jefferson
Olin Corp.
Beaumont, Jefferson
Amoco Production Co.
Edgewood, Van Zandt
Cities Service Oil Co.
Myrtle Springs, Van Zandt
American Petrofina
Mount Pleasant, Titus
Amoco Production Co.
West Yantis, Wood
Elcor Chemical Corp.
Queen City, Bowie
Getty Oil Co.
Cayuga, Anderson
Getty Oil Co.
Winnsboro, Franklin
Year
Sulfur
Production
Started
1967
1960
1970
1963
1967
Before 1962
1966
1970
1953
1962
1961
1967
1972
Before 1961
1962
Before 1962
1959
1964
1968
1969
1963
1966
Before 1972
1969
Acid
Gas
Source
Refinery
Refinery
Refinery
Refinery
Ref inery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
25
30
Not Reported
40
10
50
+50
+300 Two T rains
70
+121
38
+35
35
75
+75
50
50 Standby
576
270
16
80
30 Dismantled
130
224
37
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
TEXAS
Shell Oil Co.
Bryan's Mill, Case
Texaco, Inc.
Dunbar, Rains
Warren Petroleum Corp.
Sulphur Springs, Hopkins
UTAH
Chevron Oil Co.
Salt Lake City
Union Oil Co. of California
Lisbon, San Juan
VIRGINIA
American Oil Co.
Yorktown, York
WASHINGTON
Rayonier, Inc.
Hoquiam, Grays Harbor
WEST VIRGINIA
PPG Industries, Inc.
South Charleston, Kanawha
WISCONSIN
Murphy Oil Corp.
Superior, Douglas
WYOMING
Amoco Production Co.
Riverton, Fremont
Atlantic Richfield Co.
Riverton, Fremont
Western Nuclear, Inc.
Riverton, Fremont
Amoco Production Co.
Powell, Park
Chem-Gas Products Co.
Powell, Park
Husky Oil Co.
Ralston, Park
Expansion
Amoco Production Co.
Worland, Washakie
Year
Sulfur
Production
Started
1962
1966
1965
1972
1967
1957
1962
1960
1972
1965
1963
1968
1949
1961
1964
1966
Acid
Gas
Source
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Refinery
Chemical
Chemical
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
200
70
89
12
10
50
20
27
15
70
12
5
110
14
32
+15
1958
Natural Gas 22 Standby
38
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County
WYOMING
Texas Gulf Sulfur Co.
Worland, Washakie
Jefferson Lake Sulfur Co.
Handerson, Big Horn
Atlantic Richfield Co.
Sinclair, Carbon
Signal Oil & Gas Co.
Nieber Dome
Texas-Seaboard Inc.
Silvertip
Year
Sulfur Acid
Production Gas
Started Source
1950
Before 1959
Before 1962
Before 1962
1957
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
400 Standby
113 Standby
26
50
50 Standby
39
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX D - GLAUS SULFUR PLANTS IN CANADA
40
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
Province/Company/City
ALBERTA
Amerada Hess Corporation
Calgary
Amerada Hess Corporation
Olds
Expansion
Amoco Canada Petroleum Company Ltd.
Blgstone
Amoco Canada Petroleum Company Ltd.
East Crossfield
Amoco & Texas Gulf Sulfur Co.
West Whitecourt
Expansion
Expansion
Aquitaine Company of Canada Ltd.
Rainbow Lake
Expansion
Aquitaine Company of Canada Ltd.
Rocky Mountain House
Atlantic Richfield Canada Ltd.
Gold Creek
Canadian Delhi Oil Ltd.
Minnehik
Expansion
Canadian Fina Oil Ltd.
Cochrane
Canadian Industrial Gas & Oil Ltd.
Kessler
Canadian Superior Oil Ltd.
Harmattan
Canadian Superior Oil Ltd.
South Lone Pine Creek
Chevron Standard Limited
Fox Creek
Chevron Standard Limited
Nevis Before
Great Canadian Oil Sands Ltd.
McMurray
Gulf Oil Canada Limited
Braeburn
Year
Sulfur
Production
Started
1970
1964
1967
1968
1968
1962
1965
1968
1968
1973
1972
1971
1967
1972
1961
1962
1966
1972
1972
1972
1967
1965
Acid
Gas
Source
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
400
153
+33
370
1660
700
+525
+650
75
+75
2032
106
26
+9
106
10
817
133
3065
155
350
3
41
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
Province/Company/City
ALBERTA
Gulf Oil Canada Limited
Calgary
Gulf Oil Canada Limited
Nevis
Expansion
Expansion
Gulf Oil Canada Limited
Pincher Creek
Expansion
Gulf Oil Canada Limited
Rimbey
Expansion
Gulf Oil Canada Limited
Strachan
Gulf Oil Canada Limited
Turner Valley
Home Oil Co., Ltd.
Carstairs
Expansion
Expansion
Hudson's Bay Oil & Gas Co. Ltd.
Brazeau River
Expansion
Hudson's Bay Oil & Gas Co. Ltd.
Caroline
Hudson's Bay Oil & Gas Co. Ltd.
Carstairs
Expansion
Hudson's Bay Oil & Gas Co. Ltd.
Ed son
Expansion
Hudson's Bay Oil & Gas Co. Ltd.
Fox Creek
Hudson's Bay Oil & Gas Co. Ltd.
Fox Creek
Hudson's Bay Oil & Gas Co. Ltd.
Sturgeon Lake
Hudson's Bay Oil & Gas Co. Ltd.
Sundre
Hudson's Bay Oil & Gas Co. Ltd.
Sylvan Lake
Year
Sulfur
Production
Started
1967
1960
1966
1970
1957
1962
1961
1965
1972
1952
1960
1967
1973
1968
1969
1968
1967
1969
1965
1971
1970
1970
1970
1968
1969
Acid
Gas
Source
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
50
76
+50
+50
225
+450
246
+120
830
35
42
+8
+52
21
+29
16
102
+72
225
+64
1044
1030
50
18
11
42
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
Province/Company/City
ALBERTA
Imperial Oil Ltd.
Imperial Oil Ltd.
Quirk Creek
Redwater
Year
Sulfur
Production
Started
1971
1956
Acid
Gas
Source
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
200
9
Jefferson Lake Petrochemicals of Canada Ltd.
Balzac
Expansion
1961
1967
Natural Gas
Natural Gas
870
4-1100
Jefferson Lake Petrochemicals of Canada Ltd.
Mobil Oil Canada,
Shell Canada Ltd.
Shell Canada Ltd.
Shell Canada Ltd.
Shell Canada Ltd.
Shell Canada Ltd.
Shell Canada Ltd.
Shell Canada Ltd.
Coleman
Ltd.
Wimborne
Burnt Timber
Innisfail
Jumping Pound
Expansion
Jumping Pound
Simonette
Waterton
Expansion
Waterton
1961
1964
1971
1960
1951
1971
1967
1971
1962
1967
1972
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
377
335
120
100
90
4-240
140
90
1200
4-450
1230
Tenneco Oil & Minerals, Ltd.
Texas Gulf Sulfur
Texas Gulf Sulfur
BRITISH COLUMBIA
Nordegg River Before
Co.
Okotoks
Co.
Wild Horse Creek
Expansion
1972
1959
1966
1968
Natural Gas
Natural Gas
Natural Gas
Natural Gas
40
380
30
4-620
Gulf Oil Canada Limited
Port Moody
1972
Refinery
25
Jefferson Lake Petrochemicals of. Canada Ltd.
Shell Canada Ltd.
Taylor
North Burnaby
1957
1968
Natural Gas
Refinery
325
15
43
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
Province/Company/City
MANITOBA
Imperial Oil Ltd.
NEW BRUNSWICK
Irving Refining, Ltd.
NEWFOUNDLAND
Newfoundland Refi
NOVA SCOTIA
Imperial Oil Ltd.
Imperial Oil Ltd.
QUEBEC
Imperial Oil Ltd.
Laurentide Chemic
ONTARIO
Allied Chemical Corp.
S
Cornwall Chemicals Ltd.
Cor
Gulf Oil Canada Limited
Imperial Oil Ltd.
Shell Canada Ltd.
Shell Canada Ltd.
Sun Oil Co. Ltd.
SASKATCHEWAN
Dome Petroleum Limited
Steelman
Year
Sulfur Acid
Production Gas
Started Source
Winnipeg
k •
St. John
ig Co., Ltd.
Come By Chance
Dartmouth
Halifax
Montreal
i and Sulfur Ltd.
Montreal
Expansion
>.
Sudbury
f-H
I UU •
Cornwall
t*aH
.L6U
Clarkson
Sarnia
Expansion
Oakville
Sarnia
Sarnia
1966
1962
1973
1966
1966
1965
1958
Before 1972
Before 1972
1965
1963
1964
1968
1963
1966
1970
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Smelter
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Daily
Suflur
Capacity
Long
Tons
14
28
25
35
25
35
100
+200
275
75
40
25
+60
46
35
13
1965
Natural Gas
15
44
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX E - AMOCO PRODUCTION COMPANY INFORMATION
45
-------
February 15, 1972
Dr. Paul F. Bavley
Pa tut Director
Amoco Production Company
Sox 591
Tula*, Oklahoma 74102
Subject: Claua Sulfur Plant
Perforaeaee
Dear Or. dawlay:
Several of tha netheda being conaidared for abatement of aulfur eolaaiona
to tha ataoaphere laelnda Claua aulfur unit*. Tha Environmental Protection
Agono? Offim of Air Program* ha* cng«s*d Prooaaaaa Haaearch, lac., to atudy
tha affifiMT o* Claiia a«lf«r plaati la pollution abataaaat (Cootract No. 68-
02-0242).
Ua undarataad tbm yoer eaa^aaqr Ofarataa Clma oaita recovering aulfur which
would othatvia* b« emitted Ca tba ataaeetoro. Plaaaa let ua have available
inforttatlAB) tetartint the p«rfor«ane« of thaaa unite, aa follova. Tha Office
of Air Pvegrena iaeexeat ia in davalaflns pollution control withoda and tha
requaaend iniomatioa ia for uaa ia theaa afforte.
1. Loeatlon. daily aulfur capacity, daya of operation annually and annual
aulfor prodvotlon.
2. Clauc precaaa ^aviation tned: atraight tthroamh, avlit flow, direct
oxidation, sulfur reayole, etc.
3. Number of catalytic ateana and nathod of reheating prooeaa vapor.
4. Source, quantity and oonpotition of ael
-------
Dr. Paul P. Uavley
February 15, 1972
Page 2
7. Frequency of catalyst change and aatntenaneo.
8. Operator attendance and trouble.
9. Consuaption and generation of fuel, water, power and •teen.
If soae of this Information is available for on* ov oore of your Claos unit*,
please let tui know when ve nay expeet to receive it. We thank you for your
cooperation.
very truly yours,
PROCESSES RESEARCH. INC.
w. D. Keers
Project Manager
WDB:jd
ec: G. S. Hsaelbevger
H. R. Jester
P. V. Spelts
-------
Amoco Production Company
Amoco Building
xP.O. Box 591
}Tulsa, Oklahoma 7-110?
Producing Department
M. S. Kraemer
Chiol Engineer
May It, 1972
Mr. V. D. Beers
Project Manager
Processes Research Inc.
2912 Vernon Place
Cincinnati, Ohio 5^210
Dear Mr. Beers:
Subject: Sulfur Plant Performance
Your letter of February 15, 1972 to Dr. Paul F. Hawley has been referred
to me for a reply. You have indicated that you are making a study of
Glaus sulfur plant efficacy in pollution abatement under contract with
the Environmental Protection Agency. For your study a summary of data
concerning the plants operated by Amoco Production Company is attached.
However, the information will soon be out of date for many of the plants
since studies are underway to modify them to meet recently revised state
emission regulations.
All these plants recover sulfur from hydrogen sulfide which has been ex-
.tracted from natural gas to reduce emission of sulfur to the atmosphere.
The acid gas feed normally contains hydrogen sulfide, carbon dioxide,
hydrocarbons and water. The plant tail gas before incineration is pre-
dominately nitrogen, carbon dioxide and water vapor with small quantities
of hydrogen sulfide .(0.5-1-5 mol$), sulfur dioxide (0.25-0.75 mol#), car-
bonyl sulfide (0.01-O.OU molSO, carbon disulfide (0.01-0.05 mol$), plus
fractions of a percent of hydrogen and carbon monoxide and elemental
sulfur (vapor and entrained). Incineration converts the sulfur compounds
to sulfur dioxide.
These plants have low maintenance requirements and low operating costs
which combined amount to about 8 to 15$ of capital investment per year.
Catalyst life is normally about ten years. Changes are otherwise made
only in the event of plant upsets which result in damage to the catalyst.
Operator attendance requirements vary depending upon the design of the
plant and the amount of other duties assigned. Full time operator atten-
dance is not required.
-------
Mr. W. D. Beers
May ii, 1972
Page 2
For a more detailed discussion of sulfur plants, please refer to the
attached copy of "Why Recover Sulfur from
Yours truly,
Attachment
cc - Dr. P. F. Hawley
-------
OF 3
AMOCO PRODUCTION COMPANY
Sulfur Recovery Plants
(As of April 1972 - Plant Revisions nov being studied for compliance
with new state 'air conservation regulations as soon as approved by EPA)
LOCATION: County
State
Dally Sulfur Capacity, LTD
of Operation, Annually
;vnnual Sulfur Production
11971) LT
I'roceos, Glaus
[lumber of Catalytic stages
I;ohcat Method
y.cid Gas Feed
Source
Quantity, MMCFD
Composition, mol jfa^S
I'lant Tail Gas
Quantity MMCFD
Tail Gas Treatment
Catalyst Change Frequency
Utilities
Cooling Water MMBtu/hr.
Steam #/hr..consumed*
" " " generated
Beaver
Creek
Fremont
Wyoming
Elk
Basin
Park
Wyoming
Empire
Abo
. Eddy
N. Mex.
70 110 26
365 less downtime.for required maintenance.
(Usually about 360 days/years).
12,860
9,586
st. thru
2
bypass
split flow st. thru
2 2
inline htr. bypass
Natural Gas Natural Gas Natural Gas
1.2 2.0 1.1
88 60 65
3.3 •
3.7
None
None
2.68
None
- Only in the event of catalyst damage -
10,700
.10,900
-2 7,000
Fuel gas MMCFD
Instrument air (negligible)
Electrical KW*
'(Approx. 2 HP/LT/D for blower steam or electrical)
50
-------
. AMOCO PRODUCTION COMPANY '
• Sulfur Recovery Plants
(As of April 1972 - Plant Revisions now being studied for compliance
with new state'air conservation regulations as soon as approved by EPA)
LOCATION: County
State
Daily Sulfur Capacity, LTD
of Operation, Annually
Edgewood
Van Zandt
Texas
Midland
Farms
Andrews
Texas
North
Cowden
Ector
Texas
/vnnual Sulfur Production
'1971) LT
i'roceas, Glaus
[lumber of Catalytic stages
Iieheat Method
/.cid Gas Feed
Source
Quantity, MMCFD
Composition, mol /Cl^S
I'lant Tail Gas
Quantity MMCFD
Tail Gas Treatment
Catalyst Change Frequency
Utilities
Cooling Water MMBtu/hr.
Steam #/hr.,consumed*
" " " generated
Fuel gas MMCFD
Instrument air (negligible)
Electrical KW*
576 11 26
365 less downtime for required maintenance.
(Usually about 360 days/years).
3,018
120,959
9,352
st . thru
2
bypass
exchanger
Natural Gas
10.2
86
st. thru
2
bypass
\ i
Natural Gas
0.5
52
st . thru
2
inline htr.
Natural Gas
2.1
61
29.U .93 2.8
Incineration . • None __ Ndne
- Only in the event of catalyst damage -
88,000
500
0
2,600
7,700
'(Approx. 2 HP./LT/D for blower s'team or electrlem
51
-------
AMOCO PRODUCTION COMPANY
SMEET
OF
Sulfur Recovery Plants
(AB of April 1972 - Plant Revisions now being studied for compliance
with new state'air conservation regulations as soon as approved by EPA)
LOCATION: County
State
Daily Sulfur Capacity, LTD
Days of Operation, Annually
/vnnual Sulfur Production
'1971) LT
Process, Claus
Number of Catalytic stages
Ileheat Method
y.cid Gas Feed
Source
Quantity, MMCFD
Composition, mol
I'lant Tail Gas
Quantity MMCFD
Tail Gas Treatment
Catalyst Change Frequency
Utilities
Cooling Water MMBtu/hr.
Steam #/hr.,consumed*
" " " generated
Fuel gas MMCFD
Instrument air (negligible)
Electrical KW*
Slaughter
Hockley
Texas
South
Fullerton
Andrews
Texas
West
Yontis
Wood
Texas
80
365 lesu downtime for required maintenance.
(Usually about 3oO days/years),
13,033
1,1*06
9.32U
split flow
2
bypass
Natural Gas
6.3
23
st. thru
2
bypass
Natural Gas
.U
te
8t. thru
2
bypass
Natural Can
1.75
Ul
7.5
0.5
None
None
3.3
Incineration
- Only in the event of catalyst damage -
2.U
10,400
—
0
1100
—
7,900
35
'(Appro*. 2 HP/LT/D for blower steam or electric
cal
52
-------
INTEREST in the recovery of sulfur
from hydrogen sulfide has never been
higher. Here's why:
• World demand for sulfur is high
and continuing to increase.
• New reserves of natural gas con-
taining hydrogen sulfide have been dis-
covered.
• A number of city, state, and
federal air-quality-control laws have
been enacted.
• Sulfur prices are high, and should
go higher.
So, several incentives, both eco-
nomic and legal, exist for increasing
sulfur recovery from sour gas. It
would be expected lhat recent plant
construction would show an increase
over that recorded previously.
A comparison reveals some interest-
ing facts.
By the end of 1968, there wilt have
been constructed 132 plants of this
type in the United States, plus 29
expansions of existing plants, many of
which are really new parallel plants.
Of these, 78 were built in 1961 or
before, and 83 since. At the end of
1968, as in 1961, 58% will be in
refineries (or chemical plants) and the
remainder in natural-gas processing
plants. Table 1 shows a list of all
U.S. sulfur plants.
The largest plant before 1961 was
Texas Gulf Sulphur's Worland, Wyo.,
plant which began operating in 1950
and shut down in 1967. It had 400
long tons/day (LT/D) capacity. The
largest U.S. plant today (580 I.T/D) is
Pan American Petroleum's Edgewood,
Tex., plant completed in 1964.
Pan American Petroleum also op-
erates the largest number of plants.
nine, closely followed by National
Sulfur (Elcor Chemical Co.) with six.
Pan American, National Sulfur and
other licensees of Pan American's
patents and know-how ac -ount for
49% of the sulfur recovery capacity
built in the United States since 1961.
The average per-plant capacity of
the U.S. operating plants and expan-
sions constructed has remained sub-
stantially unchanged in recent years
(in 1961 and before. 54 LT/D in nat-
ural gas plains and 62 LT/D in re-
fineries; since 1961, 54 LT/D in nat-
ural gas plants and 52 LT/D in re-
fineries).
Fi,. I
Processes for sulfur recovery from H,S
Itralfhl
through
% wHur „ ,.
rKonrtd 13-1S+
40-93+
75-90+
75-90+
H. GREKEL
J. W. PALM
AND
J. W. KILMER
Pan American Petroleum Corp.
Tulsa, Okla.
In 1961, only 13% of the plants in
operation were of greater than 100
LT/D capacity and at year-end 1968.
only 17%. The overall percentage of
plants with 25 LT/D or smaller capac-
ity was 357o in 1961 and will be 33%
at the end of 1968.
The capacity of u.s. plants to re-
cover sulfur from hydrogen sulfide
increased 40% from 1,659,000 long
tons/year (LT/YR) at (he end of 1961
to 2,737,000 LT/YR at end of 1967.
At year-end 1968, ihc capacity of
3,036,000 LT/YR will be nea-.l/ double
the 1961 recovered sulfur capacity.
The actual production of recovered
sulfur in 1961 of 858,000 LT and
1967 of 1,244,000 LT represented only
52 ami 45%, respectively, of ;he ycar-
enJ sulfur recoverv cap.'icity.
By contrast, the Canadian plant ca-
pacity "ill have more ihan qujJrupleJ
from 1961 to 1968. Production in
1961 of 486,000 LT was 43% of the
1,140,000 LT/YR capacity and in 1967
the 2,200,000 LT production was 51%
of the year-end 4,300.000 LT/YR plant
capacity. At (he end of 1968. Cana-
dian recovered sulfur plant capacity
will be 5,034,000 LT/YR.
The Canadian sulfur plant size and
balance between natural gas and re-
fineries are much different from the
pattern in the United States. Table 2
is a list of Canadian sulfur plants.
In 1961, the 14 sulfur plants based on
natural gas averaged 214 LT/D.
The largest plant was the Pctrogas
Balzac, Alta., plant at 870 LT/D. It
is still the largest, having expanded in
1967 to 1,970 LT/D.
In Canada, 45% of the plants are
over 100 LT/D and only 20% under
25 LT/D. There will have been built
50 plants plus 10 expansions by the
end of 1968.
The average capacity of Canadian
plants at the end of 1968 will have
increased somewhat, averaging 357
LT/D for the 36 natural gas-based and
67 LT/D for the 14 refinery-based
sulfur plants.
Tne average size in refineries is
influenced greatly by the 350 LT/D
Great Canadian Oil Sand sulfur plant
added in 1967.
(Continued on p. 93)
THE OIL AND GAS JOURNAL
53
-------
Fig. 2
Sulfur-recovery plant investment
10
10 100
Product capacity, LT/D
1,000
Fig. 3
Sulfur-plant operating cost
f~
10
•Q
t—
•N.
«A
S 1
O)
E
I"
0.1
V
v
X
•Plant operating of c
19M-W7 data
&
S.A
>^4
AA
opocJty
\
X
10 100 1,000
Piodurt (opacity, 11/0 J
There will be in Alberta at the close
of 1968 four plants of over 1,000
LT/D capacity.
The fourth, at 1,480 LT/D capacity,
started up in February 1968,-is now
operated at East Crossfield by Pan
American Petroleum Corp.
Historically, sulfur recovered from
H2S has been a by-product whose
economics have been dependent only
on the last step of the recovery proc-
ess. The removal of the H:S from
natural gas or refinery gas was justi-
fied by the value of the sweet fuel.
Even at sulfur prices as low as
S17/LT, the sulfur recovery plant
could be justified economically down
•to 4 LT/D.
At today's Oil, Paint and Drug
Reporter sulfur price posting of
S42/LT (fob Gulf Coast for bright
sulfur), even small by-product sulfur
plants can be justified.
In contrast, high sulfur prices have
made attractive the construction of
several large Canadian sulfur plants
where the residue gas value would not
support the sweetening plant costs.
Value of sulfur production may be
90% of the total income—enough to
justify the entire project.
The need and desirability ot re-
covering sulfur have led to develop-
ment of revised methods of recovering
sulfur from more dilute streams of
hydrogen sulfide. Economic designs
have been developed for recovery of
sulfur from acid gas containing' as
little as 2 vol 7< H,S.
Straight-through process. If the hy-
drogen sulfide concentration of the
feed gas is high enough that stable
OCTOBER 28, 1968
Fig. 4
Total sulfur-recovery cost from acid gas
I 100
t?
o
1 "
J
3
. a
•£
1
1 ««!«•/. H,l
' In add gai
• 10 ^
100 ^K
Coo liKludti operating ir
capital diorgi it 30% ol
ptr iiw. wllvr plant mly
^
»nu pliH
Inviitintnt
—-
10 1 0
Sulfur product, capacity, LT/D
combustion of the total stream is ob-
tainable, then the total stream is fed
to (he burner in a furnace or boiler
as shown for the straight-through
process in Fig. 1. Air is fed to the
burner to provide oxygen for the over-
all reaction: HjS + 'A O. -* S + H2O
In addition, air is provided to react
with hydrocarbons in the ac-d-gas
feed. Sulfur is produced in the flame,
but sulfur dioxide is also formed, and
some H,S is unrcacted.
The gases leaving the furnace are
cooled, usually condensing sulfur from
the gas, which is then preheated and
fed to a catalytic reactor containing
bauxili; catalyst where the Claus re-
action occurs.
2H2S + SO2 -» 3S + 2H:O
The gas then passes to a condenser
to remove liquid sulfur. Usually a
second reactor and condenser (and
sometimes a third) are user! to get
higher yields. Typical recovery levels
for the straight-through process and
other processes are shown in Fig. 1.
Split-flow process. If the hydrogen
sulfide concentration of the acid bas
is so low that the gas will not burn
using the straight-through process,
then as much as two-thirds of the gas
may be bypassed around the furnace
as shown for the split flow process
in Fig. 1.
In this case, most of the hydrogen
sulfklc fed to the furnace is oxidized
to sulfur dioxide and little or no sulfur
is produced in the furnace.
The hot gas from the furnace is
54
-------
cooled and blended with the bypass
gas to obtain the desired preheat tem-
perature for the reactor, where the
hydrogen sulfide from the bypass gas
reacts with the sulfur dioxide from
the furnace by the Claus reaction over
bauxite catalyst to produce sulfur.
The reactor and condenser train are
similar lo that of the straight-through
process. Preheating of the feed gas
may be used to permit processing by
this method of feed gas containing
less than IS mole % H2S.
These two methods can be used
for handling acid gas which is too
lean to achieve stable combustion in
the split flow process:
1. Sulfur recycle process
2. Direct oxidation process
Sulfur-recycle process. In the sulfur-
recycle process, product sulfur is re-
cycled to the furnace and burned with
air to produce sulfur dioxide. Some of
the feed H3S may also be burned in
the furnace to produce sulfur dioxide.
The sulfur dioxide formed in the
furnace is fed with acid-gas feed to
the Claus reactors as shown in Fig.
1. The reactor-condenser train would
again be similar to the straight-through
process.
Direct-oxidation process. In the di-
rect-oxidation process, the acid-gas
feed is preheated, mixed with air, and
passed directly to a catalytic reactor,
as shown in Fig. 1. The oxygen reacts
with the hydrogen sulfide to produce
sulfur dioxide and sulfur.
Most direct oxidation plants require
two or three reactors. Further details
concerning this process have been pub-
lished previously.1 3
Limitations of processes. The
straight-through and split-flow proc-
esses are limited by process considera-
tions to those gases which contain a
high enough concentration of H2S to
obtain stable combustion.
The sulfur-recycle process and di-
rect-oxidation process have practically
no lower limit on the hydrogen sulfide
U.S. sulfur-recovery plants from HzS
Feed
Source
Tear Chemical
started up Refinery
'or earlier Natural Cap.
.Oparatlng company
Allied Chemical
Amarillo Oil
American Cyanamid
American Oil
Anlln Co. of III.
Anlin Co. of NJ.
Arkla Chem. Corp.
Atlantic-Richfield.
Arco Chemical Co.
Div.
Cities Service
Climax Chemical
Coastal States Gas
Production Co.
Continental Oil
Diamond-Shamrock
El Paso Natural Gas
Farmer's Union Cen-
tral Exchange
Farmland Industries,
Inc.
Fletcher Oil
Freeport Sulfur
Getty Oil
Golden Eagle Re-
finery
Great Northern Oil
Gulf Oil
Hess Oil
Hess Oil & Chemical
Plant location
Elizabeth, NJ.
El Segundo, Calif.
General Chem. Div
Richmond. Calif.
Expansion
Goldsmith, Tex.
Bound Brook, N.I.
Whiting, Ind.
Expansion
YoiMown, Va.
Wood River, III.
Perth Amboy, NJ.
Expansion
Magnolia, Ark.
expansion
Philadelphia, Pa.
Port Arthur, Tex.
Riverton, Wyo.
Watson, Calif.
Myrtle Springs, Tex
Milnesand, N.M.
Seminole, Tex.
Oil Center, N.M.
Kennedy, Tex.
Denver, Colo.
Paramount, Calif.
Sunray, Tex.
Eunice, N.M.
Laurel, Mont.
Coffeyville, Kan.
Wilmington, Calif.
Westville, NJ.
Delaware City, Del
Winnsboro, Tex.
Torrance, Calif.
Pine Bend, Minn.
Expansion
Philadelphia, Pa.
Port Arthur, Tex.
Expansion
Purvis, Miss.
Santa Fe Springs,
Calif.
Expansion
Expansion
St. Croix-Virgin Is
(S-shutdown, yr)
1958 (S, 1967)
1959(5,1967)
1964
1961*
1968
1967
1967
1952
1964
1957
1960
1957
1962
1961'
1962
1964
1961
1963
1967
1968
1967
I960'
1962
1968
1968
1966
1951
I960*
1968
1961'(S, 1967)
I960'
1956
1969
1 959 (S, 1967)
1955
1963
I960'
I960*
1962
I960'
I960'
1961*
1964
1967
Gas
R
R
R
R
R
N
R-C
R
R
R
R
R
R
N
N
R
R
N
R
N
N
N
N
N
R
R
N.R
R
R
R
R
R
R
N
R
R
R
R
R
R
R
R
R
R
R
LT/D
30
175
100
100
+ 100
7
12
64
+ 40
50
150
35
-1-15
19
+ 11
38
.38
12
65
228
20
28
18
9
18
9
30
30
28
6
7
30
375
224
4
60
+ 70
135
75
+ 75
30
8
9
13
40
Operating company
Corp.
Humble Oil & Re-
fining
Husky Oil
Jefferson Lake
Sulphur
Leonard Refineries,
Inc.
Marathon Oil
Mobil Chemical
Monsanto Chemical
Montana Sulphur &
Chemical
National Sulfur
Northwest Produc-
tion Corp.
Northwestern Re-
fining
Odessa Natural
Gasoline
Olin Matheson
Pan American Petro-
leum Corp.
Plant location
Port Reading, NJ.
Baton Rouge, La.
Benicia, Calif.
Jourdanton, Tex.
Ralston, Wyo.
Expansion
Manderson, Wyo.
Alma, Mich.
Detroit, Mich.
Expansion
Expansion
Indian Basin, N.M.
Iraan, Tex.
Beaumont, Tex.
Paulsboro, NJ.
Coyanosa, Tex.
Woodhaven, Mich.
Torrance, Calif.
El Dorado, Ark.
Lion Oil Div.
Avon, Calif.
Billings, Mont.
Expansion
Midland, Tex.
Fashing, Tex.
Lehman, Tex.
Canton Miss.
Crane County, Tex.
Queen City, Tex.
Madill, Okla.
Reagan County, Tex
Expansion
St. Paul Park, Minn
Odessa, Tex.
Beaumont, Tex
McKamie, Ark.
Beaver Creek
Riverton, Wyo.
Cottonwood Creek
Worland Wyo.
Edgewood, Tex.
Elk Basin,
Powell, Wyo.
Empire Abo
Artesia, N.M.
Feed
Source
Year Chemical
started up Refinery
'or earlier Natural
(S-shutdown, yr)
1966'
1967
1968
1967
1964
1966
1958'(S, 1960)
195S
I960*
1962
1968
1967
1967
1961*
I960*
1967
1962
1967
I960*
1966'
1956
1964
1958(5.1960)
1960
1962
1965
1966
1966
1967
1961'
1962
1968
1961
1959(5)
1944
1965
1958(5,1964)
1954
1949
1960
Gas
R
R
R
N
N
N
N
R
R
R
R
N
N
R
R
N
R
R
R
R
R
R
N
N
N
N
N
N
N
N
K
R
N
N
N
N
N
N
N
N
Cap.
LT/D
40
10
270
22
32
15
113
12
27
+8
+34
36
11
50
95
29
8
85
25
132
40
+45
1
55
9
12
15
30
8
3
+5
40
12
50
100
70
22
5SO
110
22
THE OIL AND GAS JOURNAL
55
-------
content of. the gas to be processed
from a standpoint of operability.
However, there are economic limits.
The lower economic limit on hydrogen
sulfide is presently in the neighbor-
hood of 2 to 10 mole % depending on
the feed-gas rate and sulfur netback
at the plant.
Contaminants In feed gas. A typical
acid gas from an amine-type natural-
gas-sweetening unit which comprises
the feed to a sulfur recovery plant
contains hydrogen sulfide plus carbon
dioxide with about 1 to 2 mole %
hydrocarbons.
The HjS/COj ratio depends pri-
marily on the ratio of these compo-
nents in the feed gas to the sweetening
unit since both compounds are ab-
sorbed practically quantitatively from
the sour-gas stream.
Hydrocarbons in the feed gas to
the sulfur plant are usually detrimental
for these reasons:
1. In the straight-through process,
air must be supplied to the furnace
for combustion of the hydrocarbons
in the feed gas. The added water and
inert gas associated with burning the
hydrocarbons increase the size of-the
sulfur-plant equipment and lower the
sulfur recovery.
2. In the split-flow process, hydro-
carbons in the feed gas to the furnace
have a beneficial effect in helping to
maintain flame stability. However, the
hydrocarbons in the gas bypassed to
the reactor tend to crack over the
bauxite catalyst, producing a carbona-
ceous product which fouls the catalyst
and contaminates the product sulfur.
The rate of cracking increases with
increasing molecular weight of the
hydrocarbons.
3. Higher-molecular-weight hydro-
carbons in the feed to the sulfur re-
cycle process or the direct-oxidation
process also are detrimental because
of cracking on the bauxite catalyst.
New gas-sweetening solvents have
been developed to obtain higher acid-
Table 1
Feed
Source
Year Chemical
started up Rellnery
"or earlier Natural
Operating company
). I. Parker
Phillips Petroleum
Pittsburgh Plate
Glass
Powerine Oil
Rayonier
Republic Steel
Sharpies, Purvin &
Gerb
Shell Oil
Shell Chemical
Plant location
Midland Farms
Midland, Tex.
North Cowden
Odessa, Tex.
Slaughter
Sundown, Tex.
South Fullerton
Texas
West Yantis
Tyler, Tex.
Andrews, Tex.
Madill, Okla.
Penwell, Tex.
Borger, Tex.
Crane County, Tex
Expansion
Goldsmith, Tex.
Kansas City, Kan.
Sweeney, Tex.
S. Charleston
W. Virginia
Santa Fe Springs,
Calif.
Hoquiam, Wash.
Cleveland, Ohio
Powell, Wyo.
Bryan's Mill, Tex.
Martinez, Calif.
Person, Karnes
County, Tex.
Expansion
Norco. La.
(S-shutdown, yrt
1956
1952
1951
1968
1963
I960'
I960* (S)
1961'
1968
I960*
1962
I960*
1968
1967
1960
1967
1962
1961
1961
1962
1966
1962
1965
1965
Gai
N
N
N
N
N
N
N
N
R
N
N
N
R
R
Ch
R
Ch
Ch
N
N
R
N
N
R
Cap.
LT/0
11
18
48
6
80
15
IS
30
33
100
465
75
38
25
27
20
25
6
14
180
100
12
-1-23
40
FNd
Source
Year Chemical
iterted up Refinery
•or earlier Natural
Operating company
Stauffer Chemical
Sulpetro Corp.
Sun Oil
Texas-Seaboard, Inc.
Texaco Inc.
Texas Gulf Sulfur
Texas Sulfur Prod-
ucts, Inc.
Trans-Jeff. Chem.
Corp.
Union Oil
Union Oil Co. of
Calif.
Deer Park (Houston)
Sid Richardson Car-
bon & Gasoline
Signal Oil & Gas
Sinclair Oil Cor-
poration
Texas
Expansion
Winkler County,
Texas
Houston, Tex.
Expansion
Nieber Dome, Wyo
Tiqga, N.O.
Expansion
Expansion
Fashing, Tex.
Houston, Tex.
Marcus Hook, Pa.
Expansion
1961*
1966
1960*
1963
1967
1961*
1953t
1963 (S, 1967)
1967
1960*
1960*
I960*
1962
R
R
N
R
R
N
R
R
R
N
R
R
R
50
50
5
40
10
50
72
+23
+ 150
10
30
20
+32
U.S. Steel
Wanda Petroleum
Warren Petroleum
W. R. Grace
Western Nuclear,
Inc.
Plant location (S-shutdown, yr)
Sinclair, Wyo.
Baton Rouge, La.
Baytown, lex.
Expansion
Delaware City, Del.
Le Moyne, Ala.
Watson, Calif.
Expansion
Expansion
Expansion
Expansion
Big Spring, Tex.
Toledo, Ohio
Marcus Hook, Pa.
Silver Tip Field,
Wyo.
Los Angeles, Calif.
Lignite, N.D.
Dunbar, Tex.
St. Charles Parish,
La.
Worland, Wyo.
Dumas. Tex.
Tilden, Tex.
Expansion
San Juan County,
Utah
Lemont, III.
Expansion
Oleum, Calif.
Santa Maria, Calif.
Wilmington, Calif.
Expansion
Pittsburgh, Pa.
Kermit, Tex.
Fashing, Tex.
Waddell, Tex.
Expansion
Sand Hills, Tex.
Sulfur Springs, Tex
Tatum, N.M.
Puerto Rico, W.I.
Riverton, Wyo.
1961*
1950
1953
1962
1961*
1961*
1961*
1961*
1962
1964
1967
1966
1958
1955
1957 (S, 1963)
1961*
1961
1966
1966
1950 (S, 1967)
1966
1961*
1962
1967
I960*
1964
1955
1954
1952
1962
1966*
1967
1961*
1960*
1968
1964
1965
1961
1966
1968
Gill
N
R
R
R
R
R
R
R
R
R
R
R
R
R
N
R
N
N
R
N
N
N
N
N
R
R
R
R
R
R
Ch
N
N
N
N
N
N
N
R
N
Cap.
LT/D
26
30
70
121
260
127
100
+20
+ 140
+ 8
+ 132
10
12
30
50
50
20
70
50
400
.13
20
+80
10
20'
+34
70
55
49
+ 10
110
18
45
50
+ 45
50
89
4
2
5
NOTE: Refinery sulfur plants noted as shut down are assumed to be
on standby and not abandoned as
the natural gas-based
plants are when the field is shut in. tOerated
to 50
sulfur
1967.
OCTOBER 28, 1968
56
-------
gat loadings and reduce sweetening
costs. These may also increase the
pickup of hydrocarbons in the solvent
and result in a higher concentration
of hydrocarbons in the acid gas.
Therefore, sweetening solvents
which reduce the cost of sweetening
need to be evaluated also in terms of
how much they may add to the sulfur
plant investment or operating costs.
Investment costs for sulfur recovery
units have shown a definite downward
trend as technology has improved. A
large part of the reduction in invest-
ment cost resulted from using the
patented package-plant concept which
was developed by Pan American Pe-
troleum Corp. in 1956.
This concept resulted in a cost
reduction of about 50% in plant-
investment costs at the time it was
introduced.
Table 3 compares the actual invest-
ment cost of plants built in 1952 with
the present cost for an equivalent
plant. Today's plant costs (1967) are
62-87% of the actual 1952 plant costs.
When the increase in construction
cost is considered, 1967 plant costs
are 36-50% of today's cost for the
1952 sulfur-plant design. Therefore, as
W. L. Nelson has also reported, im-
proved technology has reduced the
contract cost despite a 75% increase
in construction costs caused by in-
flation.8
Fig. 2 shows typical investment
costs for sulfur recovery plants. These
curves represent the contract price for
a one-train, two-reactor plant as illus-
trated by Fig. 1 (straight-through or
split-flow). Individual plants may vary
plus or minus 20% from these typical
curves.
If the feed gas on a dry, hydro-
carbon-free basis contains about 20
mole % hydrogen sulfide, the plant
cost is about 40% higher than for a
100% H2S acid-gas feed.
Fig. 3 shows the operating costs for
several sulfur-recovery plants which
aie operated in conjunction with other
gas-processing operations.
These costs include operating and
maintenance labor and materials and
catalyst, but do not include the cost
of loading the sulfur, power for the
air blower, or fuel and other operating
costs for incinerator and dispersal
stacks.
The air-blower power will vary with
the ratio of hydrocarbon to hydrogen
sulfide in the acid gas, type of plant,
and the design pressure drop.
The charge for power will also de-
pend on whether electric motor or
steam turbine drive is used and what
the plant steam balance is. A good
average power charge for preliminary
evaluation would.be S0.35/LT based
on 2 hp/daily LT sulfur.
It has been Pan American's expe-
rience that even sulfur-recovery plants
having capacities of several hundred
Canadian sulfur-recovery plants from HjS
Operating company
Amerada
Banff Oil, Ltd.
British American Oil
Co., Ltd.
Canadian Delhi
Canadian Fina Oil
Ltd
Canadian Superior
Chevron Standard
Cornwall Chemicals
Great Canadian Oil
Sands, Ltd.
Home Oil
Hudson's Bay Oil &
Gas
Imperial Oil
Plant location
Olds, Alberta
Expansion
Rainbow Lake, Alberta
Pincher Creek, Alberta
Expansion
Clarkson, Ontario
Braeburn, Alberta
Nevis, Alberta
Expansion
Rlmbey, Alberta
Expansion
Turner Valley, Alberta
Calgary, Alberta
Buck Lake, Alberta
Wildcat Hills, Alberta
Harmattan, Alberta
Nevis North, Alberta
Expansion
Ontario
McMurray, Alberta
Carstairs, Alberta
Expansion
Biazeau River,
Alberta
Caroline, Alberta
Edson, Alberta
Lone Pine Creek,
Carstairs, Alberta
Sundre, Alberta
Dartmouth. Ontario
Halifax, Nova Scotia
Montreal, Quebec
Redwater, Alberta
Sarnia, Ontario
Expansion
Winnipeg, Manitoba
Refinery
or
Year natural Capac-
start- gas Ity
ad up tource LT/0
1964
1967
1968
1957
1962
1963
1965
1960
1966
1961
1965
1952
1967
1967
1961
1966
1959
1967
1965
1967
1960
1967
1968
1968
1965
1967
1968
1966
1966
1965
1S5C
1964
1968
1966
N
N
N
N
N
R
N
N
N
N
N
N
R
N
N
N
N
N
R
R
N
N
N
N
N
N
N
R
R
R
N
R
R
R
153
+ 33
75
225
+ 450
40
3
76
+ 50
246
+ 120
35
50
26
106
817
120
+ 30
75
350
42
+ 8
21
16
225
102
18
35
25
35
9
25
+ 60
14
Operating company
Irving Refinery
Uurentide Chemical
and Sulphur, Ltd.
Mobil Oil Canada, Ltd.
Pamoil
Pan American Pe-
troleum
Petrogas Processing,
Ltd.
Saratoga-Jefferson
Lake Sulphur
Shell Canada, Ltd.
Steelman Gas Ltd.
Texas Gulf Sulphur
Westcoast-Jefferson
Lake
Plant location
St. John, New
Brunswick
Montreal, Quebec
Wimborne, Alberta
Kessler, Alberta
Bigstone, Fox Creek
Alberta
East Crossfield,
Alberta
Balzac, Alberta
Expansion
Coleman, Alberta
Innisfail, Alberta
Jumping Pound,
Alberta
Jumping Pound West,
Alberta
Oakville, Ontario
Sarnia, Ontario
N. Burnaby, B. C.
Waterton, Alberta
Expansion
Estevan, Sask.
Okotoks, Alberta
West Whitecourt,
Alberta
Expansion
Expansion
Wildhorse Creek,
Alberta
Expansion
Taylor, B.C.
Table 2
Refinery
or
Year natural Capac-
itart- gas Ity
edup source LT/0
1961*
1958
1964
1962
1968
1968
1961
1967
1961
1960
1951
1967
1963
1966
1968
1962
1967
1965
1959
1962
1965
1963
1966
1968
1957
R
R
N
N
N
N
N
N
N
N
N
N
R
R
R
N
N
N
N
N
N
N
N
N
N
28
100
335
10
320
1480
870
+ 1100
377
100
90
140
46
35
-.5
1200
+ 450
15
380
700
+ 525
+ 650
30
+ 620
325
OCTOBER IS, 1968
57
-------
Investment costs for sulfur recovery units
Tiblo 3
Production capacity, IT/D
Acid-gas analysis, mole % H,S (dry basis)
Actual contract cost', 1952
Contract cost escalated to 1967 construction
Cost Index (1.75 x 1952 cost)
Contract cost in 1967 tor present design
Percent of 1952 plant cost
Percent of 1967. cost for 1952 plant design
18
62
$260.000
$450,000
$160,000
62
36
52
17
$491,000
$860,000
$430,000
87
50
'Both plants had two reactors. Contract cost does not Include land, Inventory and working
capital, owner's overhead and engineering, boiler feed water treating, steam condensation,
or Incinerator and stack.
Example economics of third
Number of reactors per train
Theoretical sulfur recovery, %
Long tons/day
Investment, U.S. basis
Incremental costs for third reactor, annual
Operating expense
Capital charge at 20% of incremental
investment per year
Total
Incremental sulfur production, LT/YR
Netback sulfur price at plant, $/LT, required
to pay incremental operating expense
and capital charge
reactor
2
95.0
658
$1,940,000
$ 47,000
$ 66,000
$ 113,000
2,800
40
Note: Operating expense includes power for additional blower horsepower,
nance, and insurance.
Table 4
3
96.0
665
$2,270,000
catalyst, malnte-
LT/D do not require the full-time atten-
tion of an operator.
The amount of the operator's time
assigned to the sulfur recovery plant
will often depend on the other duties
which are assigned to him in other
parts of the overall operations, and
how much automation is built into the
sulfur plant.
Outside of occasional tests of the
residue gas and inspection of the con-
trols, a sulfur-recovery plant normally
requires little attention.
However, if the hydrogen sulfide,
hydrocarbon, or water content of the
acid gas varies, more operating labor
or automatic analysis and automatic
control of the air rate will be required
to maintain high recovery efficiency.
Loading operations are often done
by contract labor on a per ton basis.
Loading costs for tank cars will vary
from 10 to 154/LT depending on the
amount of sulfur to be loaded, where-
as the costs for loading solid sulfur
will vary from 55 to 65^/LT where
gondola cars are used and the sulfur
must be crushed to size, costs are
somewhat higher.
A simplified method of evaluating
projects is based on the observation
that a 12% rate of return (after tax)
on 100% equity investment is ob-
tained if the annual net income before
tax is 20% of the investment. This
assumes constant income for 20 years,
at an income tax rate of 50% and
7% investment tax credit.
The relationship would of course
be different for a declining production
pattern as would prevail in many nat-
ural-gas-processing applications or if
the uncertainty of acid-gas feed-supply
quantity required a higher rate of
return.
On this basis, Fig. 4 summarizes the
effect of plant size and feed-gas com-
position on economics. An example of
the calculation method for Fig. 4 is:
Sulfur product rate, LT/ D 50
LT/YR 17,350
Investment (70 mole % H,S In feed)
Contract price (Fig. 2) $270,000
Allowance for owners' overhead
and engineering, boiler feed-wa-
ter facilities, and land at 15% $ 40,500
Total $310,500
Annual capital charge at 20% of
investment $ 62,100
Capital charge, $/LT $ 3.60
Operating expense, J/LT (Fig! 3) $ 1.50
+ electric power for air blower $ 0.35
Total production cost, $/LT .... $ 5.45
Since investments and operating ex-
penses vary with local conditions and
specific design requirements, the
values in Fig. 4 should be considered
as approximate.
In the above calculation, no charge
is included for the acid-gas feed to
the sulfur recovery plant and no credit
is taken for the value of the produced
steam since these factors will vary
greatly depending on the specific plant.
The investment and operating cost
of an incinerator and dispersal stack
are not included, because, depending
on the situation, these could be either
(a) very expensive, (b) not needed, or
(c) represent a net credit, because the
sulfur recovery plant reduced the cost
of incinerator and stack which air-
control regulations would otherwise
have required. These factors must be
taken into account as appropriate in
evaluation of a specific case.
Third reactor. One method of in-
creasing the recovery is installation of
an additional reactor and condenser
system in series.
Three-reactor plants can be de-
signed to achieve recoveries of 96-
97%. Table 4 shows an example of
the effect of a third reactor on recov-
ery and economics for a 658-LT/D
plant which processes a rich acid gas
(90 mole % H2S).
The third reactor and condenser
increases the investment 17% and the
plant recovery 1.0%. The additional
reactor would yield a 12% return on
investment at a sulfur netback at the
plant of about S40/LT.
In smaller plants the sulfur price
required to justify use of a third re-
actor is higher.
Highly sophisticated computer pro-
grams have been developed for opti-
mization of the many flow sheet
options and operating variables. For
example, the recovery of a two-reactor
plant can be increased by design
changes which add to the plant cost.
It was previously reported1 that use
of gas-to-gas exchange or an in-line
burner instead of reheat gas (injection
of hot gas from some upstream point
in the process) for preheating reactor
feed gas can increase the recovery
about 0.5% in a two-reactor plant.
Recovery can also be increased by
optimization oi various plant tempera-
tures. The higher investment required
for these design changes can often be
justified at present sulfur sales prices.
Product purity. Sulfur recovered
from acid gas in a Claus-type recov-
THE OIL AND GAS JOURNAL
58
-------
cry plant usually has a purity above
99.9%. To maintain this purity re-
quires caie in handling, particularly
if the material is shipped as a solid.
Availability of material having this
purity is advantageous to the sulfuric
acid manufacturer since it enables him
to reduce his plant inveitment by elim-
inating the liquid sulfur inlet filter.
Where storage of sulfur in the solid
form at the producing plant is prac-
ticed, however, it may be necessary to
provide sulfur filtration facilities to
assure that remelted sulfur will meet
customer specifications.
Since shipment of solid sulfur in
gondola cars is common, contamina-
tion during shipment is possible. It is
therefore important for buyer and
seller to agree on the manner of
sampling and the point at which the
shipment is to be sampled.
Because of the inherent high purity
of recovered sulfur, the analytical
techniques used to detect impurities
require more care and precision for
accurate results. Larger sample sizes
than used for Frasch sulfur samples
are generally advisable, often by
factors as large as 20:1.
Off-color sulfur or high organic ash
is generally a sign that hydrocarbons
are present in the feed to the unit in
excess amounts. Heavy hydrocarbons
from the plant inlet stream or exces-
sive carry-over of acid-gas solvent are
generally the source of carbonaceous
materials that color the sulfur.
Inorganic ash in the as-produced
sulfur may result from attrition of the
•catalyst or from wind-borne dust sift-
ing into the storage pits. Where solid
sulfur is stored in open blocks, the
possibility of atmospheric contamina-
tion increases. Care must be taken
during the loading of solid sulfur to
avoid inclusion of soil from the load-
ing area in the shipment.
Although most specifications for
arsenic, selenium and tellurium read
"shall be commercially free of arsenic,
selenium and tellurium," no literature
references are readily available to de-
fine the absolute limits.
Communication with analysts whose
experience goes back many years or
whose experience includes analysis of
sulfur recovered from pyrites would
indicate that contents less than 0.25
ppm of arsenic, and 2.0 ppm of se-
lenium or tellurium can be considered
to be "commercially free."
These limits are given by Texas
Gulf Sulphur in their sulfur manual
as being maximums for Frasch sulfur
OCTOBER 28. 1968
as well. It is essential that large-size
samples be used, and that blank de-
terminations be run on all reagents.
In the past IS years, the authors have
not encountered any recovered sulfur
which exceeded these limits.
Plant location and customer require-
ments may heavily .affect storage re-
quirements at sulfur recovery plants.
Normally, 3-5 days storage is pro-
vided for liquid sulfur and an area
set aside for several months' storage
of solid sulfur.
In past years, when sulfur was in
oversupply, it was not unusual for a
customer to expect the supplier to
carry several months' supply in storage
in order to be considered an accept-
able source.
In the recent short-supply situation;
customers considered themselves for-
tunate if they could supply their entire
demand without allocation.
Plants from which offshore ship-
ments are made may require more
solid storage than would otherwise be
required. Cargoes of sulfur are gen-
erally in multiples of 10,000 metric
tons.
Storage of at least this amount will
be needed either at the plant or at the
port unless the outputs of several small
plants can be dedicated to a specific
shipment.
The latter requires coordination of
both production and shipping facilities
if excess demurrage and port storage
charges are to be avoided.
Location of solid storage areas
should be chosen, keeping in mind:
1. Location of recovery facilities.
2. Accessibility to rail and truck-
loading facilities.
3. Wind direction.
4. Proximity to land under cultiva-
tion.
More production. The increase in
range of H2S concentration in acid
gas to be processed is due to two fac-
tors; increase in sulfur prices and air-
quality regulations.
Recovered sulfur has come largely
from acid gas removed'from natural
gas or from refinery gases. Another
source of sulfur with vast poicnl.J is
stack gases. It has been estimated that
12,700,000 LT of sulfur from all
sources was emitted to the atmosphere
in the United States in 1966.'
Many processes for removal1 of
sulfur compounds from stack gases
are being proposed. All of the proc-
esses proposed to date, however, are
expensive.
Because of regulations restricting
SO2 emissions in the more populated
areas of the U.S., it is probably that
economic methods to process stack
gases to recover sulfur will be de-
veloped.8
According to Archie V. Slack of
TVA in, a paper delivered.at the 154th
National Meeting of the American
Chemical Society, sulfur recovered
from power-plant stack gases could
become a' major raw material source
for the fertilizer industry.
Mr. Slack estimates that by 1970
sulfur dioxide equivalent to 8 million
tons/year of sulfur will be emitted
from power plants alone burning coal
and fuel oil.
However, because of the rapidly in-
creasing world demand, sulfur recov-
ered from this source should remain
a small percentage of the world sulfur
consumption.
Increased prices have also stimulated
increased interest in sulfur exploration,
particularly offshore in the Gulf Coast
and in West Texas. Results offshore
to date have not been outstanding.6
In the Federal Offshore-Texas Sulfur
lease sale held in December 1965, a
total of 70,560 acres were purchased
for $33,740,000 for an average of
$4807 acre.
No announcement of a sulfur dis-
covery has been made by any of the
leaseholders. Elcor Chemical Co. has
announced7 a new process for recov-
ery of 1,000 long tons/day of sulfur
from gypsum in Culberson County,
West Texas. New, unique Frasch oper-
ations are starting for the first lime in
the U.S., where the Frasch method
has been used on a deposit not asso-
ciated with a salt dome.
The Duval Corp. has let a contract
to construct8 a Frasch operation in the
same county, which will recover
2,500,000 LT/VR. Duval will complete
expansion of the Pecos County Frasch
operation to 350,000 LT/YR. Sinclair
has a smaller Frasch operation in the
same general area.
References
I. H. Grekel, L. V. Kunlcel, R. McGal-
liard, Chcra. Eng. Progress, September !?65.
p. 70.
2. R. Mungen, Proceeding Gas Condition-
ing Conference. University of Oklahoma,
April 4-5. 1967, Paper E.
3. W. L. Nelson, The Oil and Gas Journal,
May 27, 1968, p. 111.
4. Sulfur, No. 73, November/ December
1967. p. 20.
5. Sulfur, No. 73, November/ December
1967. p. 24.
6. The Oil and Gas Journal, Aug. 12,1968,
p. 123.
7. Business Week, July 20. 1968, p. 113.
8. Chemical Week. July 27, 1968. p. 23.
59
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX F - ELCOR CHEMICAL CORPORATION INFORMATION
60
-------
February 16, 1972
Mr. Villiaa Haggard
Eleor Cheaical Corporation
Wllco Building
Midland. Teaas 79701
Subject: Claus Sulfur Plant
Performance
Dear Mr. Haggard:
Sovoral of the Methods being considered for abatement of aulfur emissions
to tho ataosphere include Claus •olftir units. The Environmental Protec-
tlon Agency Offlea of Air Program ha* engaged Procesees teaeareh. Inc.,
to study th« afflcaey of Clans aulfur plants IB pollution abatoaant (Con-
tract Ho. 68-01-0242).
Wa undaratand that yoor eoapaay oparotaa Claua uaita rccorarlog sulfur
which would othanrise ba oaittad to tha atnoaphara. Plaasa lat us hava
available ioforaatioo regarding tha parfontaaea of thaaa units, aa follow*.
Tha Offica of Air Pregras* iataraat ia in davaloping pollution control
nathods and tha raquastad inforaatioa is for usa in tbaaa afforts.
1. Location, daily sulfur capacity, days of operation annually and annual
sulfur production.
2. Claua process variation ueedj straight through, split flow, direct
oxidation, aulfur recycle, etc.
3. Huaber of catalytic atages and nethod of reheating procaaa vapor*
4. Source, quantity and composition of acid gas food.
5. Quantity and composition of tail gaa.
6. Incineration or other tail gas treatcent.
7. Frequency of catalyat change and aalnteaoace.
61
-------
Mr.
February IS, 1972
2
A. Operator atteadance and trouble.
9. Conauttption and geatratloa of fuel, water, power and stem.
If ae»a of thia Infomatioa !• available for ««• er nora of yoer Claua
unlta. plaaae let us know when va ajar expect to receive it. We thank
you for your cooperation.
Vary truly roura,
FBOCESSE8 RESKABCH. INC.
WDB/nk
cc: G. S. Haaelberger
M. R. Jeeter
P. V. Sprite
\;. D. beera
Project Manager
62
-------
ELCiOR
CHEMICAL CORPORATION
WILCO BUILDING HIDLAND,TEXAS 79701 9IS 683-4271
March 3, 1972
Mr. W. D. Beers
Process Research, Inc.
Industrial Planning and Research
2912 Vernon Place
Cincinnati, Ohio 45219
Dear Mr. Beers:
In answer to your letter of February 18, 1972, we are
pleased to supply information regarding Glaus sulfur
plant performance:
1. We have one sulfur plant in operation, the Fashing
Plant located in Atascosa County, Texas, which we
designed and constructed. It has a capacity of
approximately 55 long tons per day but is limited
by available feed gas to approximately 40 tons per
day. It operates throughout the year except for
occasional down time for maintenance. Sulfur pro-
duction during 1971 was 13,500 L.T.
2. The process used is the Split Flow.
3. The plant has two catalytic stages and uses bypass
reheating .
4. The source of feed to the sulfur plant is the acid
gas stream removed from Lone Star Gas Company's
Fashing gas processing plant. The composition is
approximately 821 carbon dioxide and 18%
5. We do not have a recent analysis of the tail gas,
but it is essentially all nitrogen carbon dioxide
and water vapor.
-------
Mr. W. D. Beers Page 2
6. There is no additional treatment beyond the two
catalytic reactors.
7. Catalyst change is required every five to seven
years.
8. The plant is relatively trouble free.
9. The plant is essentially self-sufficient except
for minor amounts of fuel, water and steam supplied
by the adjacent Lone Star Plant and the electrical
power supplied by the local power company.
I hope this information is of some assistance in your
analysis of the Glaus process.
Very truly yours,
ELCOR CHEMICAL CORPORATION
WJII: jm
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX G - SHELL OIL COMPANY INFORMATION
65
-------
February 18, 1972
Mr. L. P. Ha»by
Manager of Environmental Conservation
Shell Oil Company
One Shell Plaza
P. 0. Box 2463
Houston, Texas 77001
Subject: Glaus Sulfur Plant Performance
Dear Mr. Haxby:
Several of the methods being considered for abatement of sulfur
emissions to the atmosphere include Claus sulfur units. The
Environmental Protection Agency Office of Air Programs has en-
gaged Processes Research, Inc., to study the efficacy of Claus
sulfur plants in pollution abatement (Contract Ho. 68-02-0242).
We understand that your company operates Claus units recovering
sulfur which would otherwise be emitted to the atmosphere.
Please let us have available information regarding the perform
ance of these units, as follows. The Office of Air Programs
Interest is In developing pollution control methods and the re-
quested information is for use in these efforts.
1. Location, daily sulfur capacity, days of operation annually
and annual sulfur production.
2. Claus process variation used: straight through, split flow,
direct oxidation, sulfur recycle, etc.
3. Number of catalytic stages and method of reheating process
vapor.
4. Source, quantity and composition of acid gas feed.
5. Quantity and composition of tail gas.
6. Incineration or other tall gas treatment.
7. Frequency of catalyst change and maintenance.
66
-------
Mr. L. P. Haxby
February 18, 1972
Page 2
8. Operator attendance and trouble.
9. Consumption and generation of fuel, water, power and steam.
If some of this Information is available for one or taore of your
Claua units, please let us know when we may expect to receive it.
We thank you for your cooperation.
Very truly yours,
PROCESSES RESEARCH, INC.
W. D. Beers
Project Manager
WDBtmer
cc G. S. Haselberger
M. R. Jester
P. W. Spaite
67
-------
RECEIVED
SHELL OIL COMPA;WV !l''°
°N'SH!U'UiA APR 19 JH 9:3
P.O. BOX
HOUSTON, TEXAS 77001
A.-l. KINNtY. INC.
April 17, "~ SEARCHING.
Mr. W. D. Beers
Project Manager
Processes Research, Inc.
2912 Vernon Place
Cincinnati , Ohio 1*5219
Dear Mr. Beers:
Please refer to your letter of February 18, 1972, requesting certain
operating data on commercial Glaus sulfur units for inclusion in a report
you are preparing for the Environmental Protection Agency (Contract No. £8-
02-02U2). On the basis of your letter and subsequent telephone contacts with
Mr. Thomas of your company, we understand that the purpose of the study you
are conducting is to assess the efficacy of such type units in emission
abatement programs. We further understand that, for your purposes, it is
not necessary that the location of the plants be disclosed.
In the belief that it would prove useful in your report to include
data on plants of various sizes, we requested our operating groups to supply
information on each; a large, medium, and relatively small sized unit. These
data now have been made available to us and, at this time, we are transmitting
them to you, attached. We hope the delay has not interfered seriously in
meeting your "deadlines". As you will note, our data are arranged, in the
interest of uniformity, in the same context as were the several points you
raised in your letter.
We trust this information will suffice for your needs. Please let
us know if we can be of further assistance.
Very truly yours,
EWS:sw L. P. Haxby, Manager
Environmental Conservation Department
Attachment
cc - Mr. Thomas, Process Research, Inc.
-------
GLAUS SULFUB PLANT UNITS
Plant B
Plant C
1.
2.
3.
I;.
6.
7.
8.
a) operator attendance
b) operating troubles
9. utilities
a) fuel gas, MCF/day
b) steam generated, Ibs/hr.
a) daily sulfur production,
long tons/day
b) days of operation annually
c) annual sulfur production,
long tons/yr.
a) process "variations" +
a) number of stages 3
b) method of reheating vapor note 1
a) acid gas feed source
b) quantity, MCF/D
c) composition, % (note 5)
H2S
C02
hydrocarbons
a) tail gas quantity, MCF/D
b) tail gas composition, %
H2S
N2
C02
CO
so2
H20
a) tail gas treatment
a) catalyst change frequency note 6
185
353
65 ,000
120
31,5
1*1,500
about kO
320
11,600
straight through
steam
hot by-pass
note 2
7,600
68
30
2
note 3
2,300
90
8
2
note U
1,500
71
25
U
lU.OOO
6,500
U.OOO
o.Uo
79-
17.5
2.5
0.2U
-
1.
65.
3.5
—
0.5
30.
incineration -
-
-
-
-
8,000-10,000 ppm
—
•
ca. 18 mos. note 6
126/hrs/wk 168 hrs/wk 78 hrs/wk
note 7
500
3U.OOO
note 8
192
35,000«
note 9
250
8000-9000
note 1 side stream of acid gas is burned in in-line burners after condenser
note 2 sulfinal process gas sweetening plant discharge
note 3 crude oil refining process
note U DEA scrubber/ethylene plant
note 5 excludine trace amounts, if any, of N2 and H20
note 6 approximately once every three years
note 7 regeneration of catalyst beds, maintenance of 2:1 ratio; of H2S to S02,
maintenance of hydrocarbon recovery unit which is required;.to minimize
carry-over of hydrocarbons to sulfur plant
note 8 none reported
note 9 low throughput lowers efficiency, ineffective demister mat.
•consisting of about 26,500#/hr of 300 psig steam and about 9,00#/hr of 50 psig steam.
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX H - STAUFFER CHEMICAL COMPANY INFORMATION
70
-------
?o»r«ary 18. 1972
Mr. o. a, Boborto
Vie* Proaidoat of Bnginoorlag
Stanffor Qtottiool Corporation
J. B. Coecoo Englnoorlnt Canter
Dobb* Perry. Sow Tork 10S22
CUo* 8vlf«r Mant Porfontaeo
Mr. Bobortat
Several of eh* aothoda being considered for abet event of ottlfur caleaioaa
to tfao otKOopboro ioelu4* Claw owlfior onit*. Tfco KikTiroojMatal Protoetioa
Offieo of Air rrognHW hao «a§«t«4 Proooooo* Booooveii. !••., to
tho offieaey of Clatto cvlfur plant* to •ollntloa aoatoMat (Cootraet
HO. 66X12-0242).
W« oa4oMtaa4 that your eo^aoy oporatao Clou onlta rooovoriai ralfwr which
woold othorwioo bo omitted to tho atMophoro. Ploaoo lot u» h*v» avaULablo
ioforwitioa rosar^iog tho porfonuneo of thooo oalto, a> follow*. Tho Offieo
of Air Prosroo* latoroat io is do^oloping pollatioo control oatfcoa* a«4 tho
iftfonoitioa io for ooo ia thooo off ore*.
1. Location . daily avlfiur capacity, daya of oporotioa aaaoally and aanoal
•ttlfur protfttctloa.
2. Claoa procoao variation osod: otralgbt throBgh, oplit flow, dinot
oxidation, •vlfar rooyelo, ote.
3. Koobor of catalytic otogoo and nothod of rohoatins proooo* vapor.
4. Soorco. quantity aad eonpooition of acid can food.
5. Qttaatity and eoapooltion of tail aaa.
6. Xoclnoratioa or othor tail (ao troat«Mt.
7. Proqnoney of catalyst ohango and •aiatonanco.
8. Operator attendance and erovblo.
9. Conaviption aad gonoration of f«al, vator, power and •ton*.
71
-------
Stauffer Chemical Corporation
Page 2
February 18, 1972
If some of this information is available for one or more of your Claus
units, please let us know when we may expect to receive It. We thank
you for your cooperation.
Very truly yours,
PROCESSES RESEARCH, INC.
W. D. Beers
Project Manager
WDSrfj
cc: G. S. Haselberger
M. R. Jester
P. W. Spaite
72
-------
. B. r.HT.UN
'Nh !"NG H.NIFR
staler Staulffe¥-yC?.hemical Company
1 ^^*^ j Dobbs Ferry, New York 10522 / Telephone (Area Code 914) OWens 3-1200
'72 APR 3 AM |Q:
March 21, 1972
A.I-.;. KINHLr. u-IC __ .
FRO. RJZStAliCH INC-
Mr. W. D. Beers
Project Manager
Processes Research Inc.
Industrial Planning and Research
2912 Vernon Place
Cincinnati, Ohio 45219
Subject: Glaus Sulfur Plants
Reference: Letter from W. D. Beers to D. H. Roberts dated
February 18, 1972
Gentlemen:
The following information is from various Stauffer Chemical Company
Claus Sulfur Recovery Plants. The data as listed is in accordance
with the referenced letter.
1. a. Plant Baytown,
Location Texas
b. Daily 100
Sulfur
Capacity
T/D
c. Day of 335
Operation
Annually
d. Annual 33,500
Sulfur
Pro-
duction
2. Claus Process Straight
Variation Through
3. Number of 2
Catalytic
Stages
Delaware City, Le Moyne, Long Beach,
Del.
400
Ala.
250
Calif.
450 (4 units)
335
134,000
Straight
Through
335
83,750
Straight
Through
335
150,750
Straight
Through
73
-------
Mr. W. D. Beers
Processes Research Inc.
March 21, 1972
Page Two
ta. Method of
Reheating
Process
Vapor
4. a. Acid Feed
Gas Source
b. Uuantity-
SCFM
c. Composition-
% H2S
N2
co2
CH4
H20
cs2
NH3
5. a. Tail Gas-
Quantity-
SCFM
ta. Composition-
% H2S
S02
s
co2
N2
H20
6. Gas Treat-
ment
In-line
Burners
Refinery
2800
50.3
1.0
46.1
2.5
-
-
-
6250
0.7
0.3
0.2
21.8
51.5
25.5
Incin-
eration
In-line
Burners
CS2 Plant
7680
96.3
0.2
0.2
3.2
0.2
-
20,760
0.9
0.4
0.3
1.1
64.2
33.1
Incin-
eration
In-line
Burners
CS2 Plant
4130
95.5
0.4
0.6
3.4
-
0.5
-
13,200
1.0
0.5
0.3
1.3
64.3
32.6
Incin-
eration
In-line
Burners
Refiner
4480
83.5
0.4
11.5
0.5
4.0
-
0.1
25,320
0.8
0.4
0.3
4.4
60.2
33.9
Incin-
eration
7. Frequency of
Catalyst Change
Approx. Years
-------
Mr. W. D. Beers
Processes Research Inc.
March 21, 1972
Page Three
8. a. Operator Attendance-
Time
b. Trouble
1/4 1/4 1/4 1/4
Very low Very low Very low Very low
191
130
9. Consumption/
Generation
a. Gas SCFM
b. Steam
c. Power
I hope the above information will satisfy your requirements in
completing your study under Contract No. 68-02-0242.
460
Consumed
within
Plant
Consumed
within
Plant
Consumed
within
Plant
Consumed
within
Plant
Very truly yours,
STAUFFER CHEMICAL COMPANY
A A: ,
LLZ:gm
Encl.
L. L. Zuber
Sr. Project Engineer
75
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX I - FORD, BACON & DAVIS INFORMATION
76
-------
, Bacon
Sulfur Recovery Plants
77
-------
CZJ
i»fc_4ircONOENSING PASS
=—"• 'CONDENSING PASS
ACID CAS
REACTION GAS WITH
SULFUR PRODUCT
REACTION FEED GAS
SULFUR PRODUCT
BOILER FEED WATER
Typical Combination Boiler-Condenser Unit (Three Reactors)
Ford, Bacon & Davis
Sulfur Recovery Plants
are a modern-day improvement of the original Claus
process for recovering sulfur from hydrogen sulfide
gas. There are more of these type plants being
installed domestically than any other, Ford, Bacon
& Davis having completed more than 45 projects.
Most of Ford, Bacon & Davis' plants have been
custom-designed and constructed for refinery and
chemical plant applications to process the actual
gas stream available. Except for the very smallest
units, custom-designed plants have proven to pro-
vide a much more satisfactory installation than a
skid-mounted or an off-the-shelf design, which
often compromise efficiency and operation of the
plant for the sake of compactness.
FB&D plants are exceptionally flexible, and nor-
mally can be operated at a rate of as low as one-
third of design capacity. Special-design plants allow
operation at even lower capacities.
Ford, Bacon & Davis, as a national engineering-
contractor, offers complete process design, detail
engineering, procurement, construction, and start-
up services, anywhere in the Northern Hemisphere,
and design and procurement services anywhere in
the world.
The principal feature of the process described
herein is a unique, patented vessel arrangement
referred to as a boiler-condenser. This vessel, illu-
strated above, combines into one piece of equip-
ment several functions, such as burning the HaS
gas, cooling and condensing the sulfur, separating
the sulfur product from the gas, and producing
steam. This design has been proven to provide a
high-quality unit with maximum recovery levels
and easy operation at much lower costs than is pos-
9 I CAM
tiL
.„»
sible with the older-style Claus plants that require
as many as six vessels to accomplish the various
functions.
In very large plants where a single vessel would
be too large, or where high-pressure steam genera-
tion is desired, a boiler and a single, separate con-
denser can be provided as shown on Page 3. This
also provides extensive cost savings and simplicity
of operation, compared to using several separate
condensers.
The reactors are also combined in a single vessel,
as shown above, unless the size of the vessel
becomes impracticable, in which case they are sep-
arated as shown on Page 3. Also, because of increas-
ingly-strict pollution requirements, the use of three
reactors is now often required to meet codes (in
certain areas the third reactor is mandatory). In
many applications, the third reactor can be justified
economically, because the stack height can be re-
duced due to the higher recovery levels.
In addition, we have also designed a number of
plants to process gas streams that contain poten-
tially-troublesome components such as ammonia,
hydrocarbons, CSz, and COS. The process shown
on Page 3 also includes a separate combustion
chamber which is provided as part of the design
where required to properly handle large concentra-
tions of these components.
Cost estimates and utility requirements can be
furnished from these data: Feed gas analysis (vol-
ume; temperature; pressure), steam pressures avail-
able or desired, utilities available, site location and
ambient conditions, storage requirements, and
recovery and SO* limitations (if any).
O CamrlaU 1171, Ford. Bmnm * Oant. /«<•. • />ri»(.-J in VJS.A.
78
-------
Typical Separate Sorter and Condenser Unit (Two Reactors)
How the Plants Operate
The Claus process involves the combustion of
approximately one-third of the HaS to SO? and the
subsequent reaction between the remaining HsS
and the produced SOj to form sulfur and water
vapor, with the subsequent recovery of the sulfur
product.
Ford, Bacon & Davis offers the modernized Claus
process in two basic process schemes, referred to as
straight-through and split-flow. The most common
application is the straight-through process, which
is illustrated in two versions (above and on the
facing page), wherein all of the acid gas is fed
through the burner. This process is used for most
acid gas streams that contain high concentrations
of HzS, generally in the range of 50 per cent or
higher, such as the off-gas from a typical amine
unit in a refinery. Our process can provide the
highest recovery level available from the Claus-type
process. Also, we are licensed for various other
processes to recover additional sulfur from the tail
gas from the Claus process, which provide even
higher recoveries.
The split-flow process is required for lean acid
gas streams of less than 50 per cent HjS, such as
are found in certain gas fields where high concen-
trations of CO- are present. In the typical split-flow
unit, as much of the acid gas as possible, without
adversely affecting combustion, is fed to the burner
in the combustion chamber with air, where a large
percentage of the HzS is combusted to SO;. The
remainder of the acid gas is mixed with the boiler
effluent and fed directly to the reactor. The process
is designed in this way since the flame could not be
maintained if all of the acid gas were fed to the
burner, as in the design of a straight-through unit,
due to the inerts present.
In the straight-through process, all of the acid
gas and the combustion air are fed through a spe-
cial burner where one-third of the HiS is burned to
SOz. 'Effluent from the second cooling pass, con-
taining sulfur vapor created from the non-catalytic
reaction between the HSS and 80s in the first two
passes, is condensed in the first condensing pass.
The sulfur product, which is recovered in the first
separator, is drained to storage. Gases from the first
separator are reheated with a hot gas by-pass
stream from the second boiler pass to provide the
necessary reaction temperature. This is also the
reheat method used on the second reactor feed.
Other reheat methods can be used which provide
higher recoveries, but at relatively higher costs.
Sulfur vapor is produced in the first reactor from
the reaction between the H»S and SOj in the pres-
ence of a bauxite catalyst. The resulting sulfur
vapor from the catalytic reaction is condensed in
the second condensing pass, separated in the second
separator, and drained to storage. The conversion
and recovery cycle is repeated in the second and
third reactors and the other condensing passes and
separators. When a third reactor is used, the reac-
tion feed gas is normally heated in a reheat ex-
changer to reaction temperature by using the first
reaction effluent.
The incinerator converts the sulfur compounds
remaining in the tail gas from the plant to 80s.
The design normally provides for a tail gas stack
of sufficient height to meet local pollution code
limitations on 80s concentration at grade.
Normally, a concrete sulfur storage pit is pro-
vided to store the sulfur in a molten state for load-
ing into trucks or rail cars. The sulfur is kept
molten with steam produced in the plant. A steel
storage tank is sometimes used on smaller or skid-
mounted units.
79
-------
Two 135 LTD sulfur recovery units with 300" derrick-supported stacks • Humble Oil and Refining Co., Bay way Refinery, Linden, New Jersey
Operating and Maintenance Costs
Extensive automatic controls are provided to allow
FB&D plants to operate virtually unattended and
to shut down the plant in the event of a hazardous
malfunction. Only one to two manhours of super-
vision per twenty-four hours of operation are
normally needed.
Utilities required for the plant are nominal. The
connected electric load is approximately 2 horse-
power per ton of production, most of which is
required for the air blower, with a small amount
required for the intermittent operation of the sul-
fur pump, lighting, etc. Fuel gas is required only
for start-up of the sulfur plant and operation of
the tail gas incinerator. Instrument air or gas of
3 to 4 s.c.f.m. and treated boiler feed water for the
quantity of steam produced are the only other
utilities required.
The unit will produce approximately 250 pounds
of steam per hour per ton of sulfur production. The
value of the steam that is produced will normally
offset the cost of the utilities required for the unit.
If the steam cannot be used, it can be condensed
and returned to the boiler-condenser.
The most economical plant is a single boiler-con-
denser producing all the steam in the 20 to 150
p.s.i.g. range. In the larger units, or where high-
pressure steam is required (wherein the boiler is
separated from the condenser), as much as two-
thirds of the steam can be produced at higher pres-
sures (up to 550 p.s.i.g.).
Maintenance costs are normally less than 1 to
2 per cent per year of installed cost, due to the
small amount of rotating equipment, lack of cor-
rosion, etc. Catalyst is inexpensive, and normally
has a minimum life of from three to five years.
80
-------
Two 135 LTD sulfur recovery plants • Humble 0/1 and Retini
18 LTD sulfur recovery plant with guy-supported tail gas stack • Hudson's Bay Oil and Gas Co. Ltd., Si
, California
81
-------
Sulfur recovery and amine treating units specifically designed to
process 5 to 50 tons of sulfur per day (Canton, Ohio). A duplicate
facility was also completed at Buffalo, New York • Ashland Oil Co.
Amine Treating and Related Projects
Ford, Bacon & Davis also offers extensive experi-
ence in amine treating and related facilities as well
as in sulfur recovery. We are also licensed to use
various treating processes, such as Shell's Sulfinol,
and many gas sweetening units of all types have
been completed in connection with sulfur recovery
facilities, including both MEA and DBA. A DEA
(amine) unit will be required for refinery installa-
tions where CS2, COS, or other contaminants are
present which would cause problems such as fouling
an MEA solution. The MEA (amine) unit is nor-
mally used in natural gas service and where certain
contaminants are not present in refining units.
Since amine treating or other gas sweetening
units normally are required in conjunction with,
and are adjacent to, sulfur recovery facilities, there
is merit in considering the award of a single con-
tract to include these units with the sulfur plant.
One very important advantage in combining
more than one unit into a single contract is the
ability to manage the construction as a single proj-
ect, which greatly reduces the indirect field and
home office costs when compared to two separate
projects. The majority of the turn-key facilities we
install include both amine and sulfur plants as a
single project. Thus our experience is comparable in
both areas.
Tail Gas Recovery Processes
Ford, Bacon & Davis is also licensed for various
processes to recover sulfur compounds from the tail
gas of sulfur plants, in order to increase recovery
levels, and to meet increasingly stringent air pol-
lution codes (S02 emission). These processes can
be installed in conjunction with Ford, Bacon &
Davis sulfur recovery plants when built, or for exist-
ing sulfur plants.
82
-------
flmme treating and
Sulfur recovery
units • Farmers' Union
Central Exchange,
Laurel. Montana
recovery plant and refinery
gas sweetening unit (Douglas Oil
Paramount, California). A similar
facility was also completed at
Colorado • Continental 0/1
83
-------
Expansion of reformer
facilities • SteHy Oil
Co., El Dorado, Kansas
, ,»5ilCOn &.^IVI6 has a wide range of experience in process design,
engineering, and construction in a wide range of related facilities —
• Petrochemical Plants • Oil Refining and Processing Plants • Natural Gas Processing /nsta/lations
• Compressor Stations • Off site facilities • Industrial Plants • Mining and Materials-Handling Facilities
1 Power Plants • Pipe Lines • Municipal Facilities • Paper Mills • Industrial Engineering • Appraisals and Valuations
PROCESS PUNT DIVISION: 2908 National Drive (Garland) « P.O. Box 38209 • Dallas, Texas U.S.A. 75238 • 214/278 8121
Also Monroe • Tulsa • Baton Rouge • New York • Calgary • Brisbane
Major refinery expansion • Continental Oil Co., Colon, Panama
84
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX J - THE RALPH M. PARSONS COMPANY INFORMATION
85
-------
PR 109
Job
£PA - OAP
local ion
SubjecI
PL.A+JTS
PROCESSES RESEARCHING.
INDUSTRIAL PUNNING
AND RESEARCH
CINCINNATI NEW YORK
Che
-------
February 21, 1972
Mr. 0. C. Roddey
Vice President, Precontract and
The Ralph H. Parftens Coapany
(>17 West Seventh Strict
Los Angela*, California 90017
SubJact: Glaus Sulfur Unita and Tail Gas Tr*ats*nt
Dear Mr. Roddey:
Several of the nethoda being considered for abateoent of aulfur eniaelons
to the atmosphere include Claua sulfur unita. The Environnental Protection
Agency Office of Air Prograea has engaged Proeeasea Research, Inc., to
study the efficacy of Clans aulfur planta in pollution abatement (Contract
tlo. 68-02-0242).
Me underatand that yoor coapany la a proadnent designer of Claua units
worldwide and has developed, with Union Oil Company of California, a
procesn for Claua tail gaa pollution abAfceaettt. We are referring to your
Beavoo Sulfur Rwnoval Proeoas, deaeribed in the February 7, 1972. iaaue of
the Oil and Gaa Journal. Pleaae let us have inforoatiea available regard-
Ing typical Claua sulfur unita and the Beavon procaaa, aa follows:
1. fcr typical Clann sulfur unite, auch as thoae baaed on natural Ran
(dully aulfur capacities of 10 tone, 100 tone, and 1000 tone, and
gao feed concentratlone of 13 aole nercent, SO «ole percent, and 90
nole percent 1325, and units havi»n two and three Claua catalytic
stages are of particular interest);
,a. Percentage sulfur recoveries and tall gas cexpositions for varioua
acid gaa feed concentrations and varioua ntnbera of catalytic
stagea.
b_. Variation of aulfur recovery during the uaual life of the catalyst.
£. Variation of aulfur recovery with acid gaa feed at lass than full
capacity such as half of full feed rate.
d. Approximate inveatajent, royalty, catalyst costs, and consusjption
and generation of fuel, water, power and stead for varioua dally
sulfur capacities, varioua acid gaa feed concentrations and
varioua Quakers of Claua catalytic stages. (Do these include
the acid gaa recovery unita* acid gaa blovora, air blowers, and
tall gaa incineratorsT).
87
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Mr. 0. C. Boddey
Page 2
February 21. 1972
e. Operator attendance requirement* for various dally sulfur capac-
ities, and unbar of daye of operation Co be expected annually.
For Beavon Sulfur Removal Process Units treat Ing Claus call gaa (daily
sulfur capacities of 1 ton, 10 tons and 100 tons, end Claus tail gaa
fesd concentrations of 0.) mole percent, 1 sole pareeat and 4 awl*
percent H2S + S02 + S •»• COS + €83 are of particular Interest):
a. Approximate investment, royalty, catalyst costs, sad constant ion
of fuel, water, power and st«aa for various dally sulfur capac-
ities and various Claua tail gas feed con cent rations. (Do these
include the stripping of the H2S from the coadenaateT).
b. Operator attendance and maintenance requirements.
£. Percentage sulfur recoveries and off gas compositions for various
Cleus tail gas feed concent rations.
d. Variation of sulfur recovery during the usual life of the catalyst.
e. IB the quality of the sulfur recovered by the Beavoa process equal
to that of Claus sulfur?
f. What* if any, air pollution is presented by ontralnnent of catalyst
overhead from the Stretford tower? Is incineration of the off gas
advisable?
g. A principal cause of poor sulfur recovery in Glaus plants is de-
~ viatlen froa the optimum feed ratio of air to H2S, resulting from
inadequate instrumentation or careless operation. This also
results in variations froa the stoichlometrlc balance of I^S end
SO 2 in the tail gas. Therefore, tall gases from Cleus units having
the greatest need for pollution abatement are likely to contain
unbalanced and erratic quantities of U2S tod S°2- Tha Beavon
process appears to be insensitive to such feed fluctuations. Do
you concur in this observation T
h. Per a new Claus unit, should the Beavon process replace the third
Clans stage? Should the Beavoa process replace the Claus unit
eltogether?
i. For an add gaa baring an excessive ratio of SOi to HjS. should
the Beavon hydrogenatlon step be uoed to adjust the ratio for
feeding the Claua unit? Is this more advantageous than catching
the excess S<>2 in the Cleus tall gas treatment?
88
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Mr. 0. C. Roddey
Page 3
February 21. 1972
Wo will appreciate receiving •!! of the above Info rant Ion which yoo can
aake available Co u*. Pleaao let us know when we can expect to receive
It •
Wo thank you for your cooperation.
Vary truly yours.
PROCESSES RESEARCH, IHC.
W. D. B«er»
Project Manager
Wi)B:fj
cc: C. S. Uaaalbergar
K. R. Jaatar
P. W. Spalte
89
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The Ralph M. Parsons Company
Engineers ' Constructors
6l7 IV K S T SEVENTH S T K K K T, I. O S \ N <: K I. K S, "c A L. 1 F O R- N I A
March 23, 1972
M/XII. Anni
''• "• ""x
I.OS ANCKI.K5
Mr. W. U. Beers
Project Manager
Processes Research, Inc.
2912 Vemon Place
Cincinnati, Ohio 45219
SUBJECT: Claus Sulfur Units and Tail Gas
Treatment
Your OPA Contract No. 68-02-0242
Uear Mr. Beers:
Thank you for your letter of February 21, 1972. We are pleased
that you have come to us for assistance in this project; we
have made every effort to be as complete as possible in preparing
answers for your many questions.
For ease of reference we will follow your format as closely as
possible in presenting our responses.
1. Claus Sulfur Units
(a) Depending upon the design of the sulfur plant and the
nature of the impurities accompanying the feed H2S, a
considerable range of sulfur plant recoveries is
possible. More or less in the middle of the range, it
might be said that a 50 percent H2S feed gas would result
in about 93 percent recovery from a well-designed Claus
plant with two catalytic stages, or 95 percent with three
catalytic stages. Similarly, a 90 percent H2S feed gas
would yield about 94 percent recovery from a two-stage
Claus unit or 96 percent from a three-stage unit. An
I12S feed gas of only 15 percent purity requires a special
design of the Claus plant and it is preferable not to
generalize on the recovery from such a plant because the
ratio of H2S to impurities such as hydrocarbons is so low
that the recovery has to be estimated on a case-by-case
basis. It is evident that the recovery from such a low
purity H2S is low, and usually in the range of 80 per
cent to 90 percent.
90
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THE RALPH M. PARSONS COMPANY
Mr. W. L). Beers
Processes Research, Inc. -2- March 23, 1972
(b) It is customary to regenerate Claus plant catalyst after
it has lost activity or become fouled. The life of the
catalyst may range up to twelve years, with typically
about one regeneration annually. After regeneration the
catalyst should return to substantially its original
activity, except for a permanent loss in activity for
the hydrolysis of COS and CSo which may or may not be
important in a particular plant. It is reasonable that
catalyst would be discarded if regeneration fails to
return it to within one or two percent recovery compared
to its new performance. The frequency of regeneration,
on the other hand, is very dependent upon local circumstances,
including air pollution regulations. In some instances,
a catalyst regeneration would occur with a loss of less
than 1 percent in recovery; in other instances, the
recovery might be allowed to slip as much as 10 percent
before the catalyst is regenerated. Perhaps an overall
industry average would find catalyst being regenerated
after the yield has declined two or three percent.
(c) Turning down a sulfur plant to operate at less than full
capacity usually causes a loss in percentage recovery;
the amount of loss is highly dependent upon the design
of the plant, and particularly depends on the method used
for reheating the gases ahead of each Claus converter.
With the method of reheat most often used by Parsons, a
sulfur plant will typically lose two or three percent in
recovery when turned down to 20 percent of design capacity.
(d) Approximate Investment
Includes royalty. Does not include acid gas recovery units
or acid gas blowers. Does include air blowers, incinerators,
and stacks.
Gas Strength Investment - $MM
and Capacity 2-stage5-stage
90% H2S
10 LT/D 0.34 0.39
100 LT/U 0.80 0.90
1,000 LT/U 3.60 4.20
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THE RALPH M. PARSONS COMPANY
Mr. W. D. Beers
Processes Research, Inc.
-3-
March 23, 1972
Gas Strength
and Capacity
50% H2S
10 LT/U
100 LT/L)
1,000 LT/U
Investment - $MM
2-stage
0.37
0.90
4.10
5-stage
0.43
l.OS
4.90
H2S
10 LT/U
100 LT/U
1,000 LT/D
Catalyst Cost
0.55
1.75
10.0
0.65
2.00
11.5
The typical cost of bauxite catalyst for a two-stage sulfur
plant feeding 90 percent H2S is about $30 per daily long
ton capacity. This cost would be increased by about 30 per
cent for a 50 percent H2S feed gas. Adding a third Claus
converter stage would increase the catalyst cost by 50 per
cent. Using synthetic alumina catalyst would increase the
cost by about 70 percent. Thus, the cost of catalyst for
a three-stage sulfur plant feeding 50 percent I12S and using
alumina catalyst would be about $100 per daily long ton
capacity.
Utilities Consumption
Using a 90 percent H2S feed gas as a basis for the production
of one long ton per day of sulfur, the process would require
about 0.6 gallons per minute of boiler feedwater. Electric
power is needed only for lighting and miscellaneous purposes,
since the air blower is driven by steam produced in the
process at 150 psig pressure and exhausted at 50 psig. Fuel
gas is needed for start-up and regeneration only. Net pro-
duction of useable steam is 140 Ibs. per hour at 150 psig
and 140 Ibs. per hour at 50 psig. The incinerator is excluded
from the above statements. The above steam quantities may be
used with reasonable accuracy for 50 percent H2S feed gas, and
they are essentially independent of plant size.
92
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THE RALPH M. PARSONS COMPANY
Mr. W. U. Beers
Processes Research, Inc. -4- March 23, 1972
(e) Operator Attendance and On-stream Factor
Sulfur plants up to about 100 LT/U capacity usually require
the attendance by a man about 20 percent of the time. This
depends of course on the location of the plant, degree of
instrumentation, and other factors. Larger plants will
tend to require somewhat more attention.
A Parsons sulfur plant typically has an on-stream factor
in excess of 95 percent.
2. Beavon Sulfur Removal Process Units
As a general comment, we have never seen a Claus tail gas contain-
ing as little as 0.3 mol percent offl^S + S02 + S + COS + CS2);
this includes the tail gas issuing from the IFF and Sulfreen tail
gas processes. Our remarks are therefore directed to tail gases
containing either one or four mol percent equivalent H2S.
(a) Approximate Investment
Includes royalty. Our current design does not require
condensate stripping. Sulfur produced in molten form.
Total Sulfur Content
and Capacity Investment - $NIM
1.0% S Equivalent
1 LT/D 0.69
10 LT/U 1.40
100 LT/D 5.80 *
* Multiple hydrof;enation and Stretford trains
4.09o S Equivalent
1 LT/D 0.61
10 LT/U 1.20
100 LT/D 3.50 **
** Multiple Stretford trains
93
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THE RALPH M. PARSONS COMPANY
Mr. W. U. Beers
Processes Research, Inc. -5- March 23, iy?2
Catalyst Cost
The cost of a catalyst fill is approximately $70 per daily
long ton of Claus plant capacity. The catalyst is expected
to have a three-year life.
Utilities Consumption
Utilities consumption is as follows:
Quantity basis
Fuel gas 1.25 MSCFL) per daily ton parent sulfur plant
capacity
50ff steam 25 #/Hr per daily ton parent sulfur plant
(produced) capacity
Power 85 HP per ton sulfur in tail gas
Soft water 2,500 gal. per ton sulfur in tail gas
Chemicals $8 per ton sulfur in tail gas
The foregoing utility figures apply to an advanced version of
the flow scheme in which condensate is not produced as such
and therefore stripping of the H2S from it is obviated.
(bj Operator Attendance
For all but very large plants the attendance of an operator
is required between 25 percent and 50 percent of his time.
Maintenance requirements are expected to be modest. Operating
temperatures and pressure are comparatively low and no inherently
corrosive or erosive conditions prevail. Materials of construc-
tion are essentially all carbon steel, with epoxy coatings in
several areas.
(c) Recoveries and Tail Gas Compositions
Tail gas containing about four percent equivalent H2S contains
less than 80 ppm equivalent SC>2 after treatment, with COS
constituting the major part of the combined sulfur and with
H2$ contributing less than 1 ppm. Treatment of a tail gas
containing 1 percent equivalent H2S is expected to yield a
final tail gas containing less than 40 ppm equivalent S02-
9 4
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THE RALPH M. PARSONS COMPANY
Mr. W. U. lieers
Processes Research, Inc. -6- March 23, 1972
(d) Variation in Recovery
No detectable variation of sulfur recovery is expected
over a one-year period between catalyst regenerations.
(ej Sulfur Quality
The sulfur recovered by the lieavon process is expected
to be somewhat better than 99.8 percent pure, while Claus
sulfur usually is at least 99.98 percent pure. Either
the Beavon process sulfur or the mixture of it with Claus
sulfur meets all usual specifications for commercial
sulfur.
(f) Stretford Entrainment
Entrainment of catalyst overhead from the Stretford tower
is avoided by proper design of the tower internals, and
the vent gas stream is expected to meet all known air
pollution standards. Incineration of the off gas may be
practised, but in our opinion it is unnecessary and
inadvisable because of the substantial cost for fuel if
an incinerator is operated.
Cg) Process Sensitivity
Because of broad experience in the design and construction
of many refineries and more than 160 Claus plants,
The Ralph M. Parsons Company is well aware that the sulfur
plant is at the very end of the train of refinery processes,
and is subject to continual disturbance because of varia-
tions in the up-stream units. These variations make it
very difficult to control a refinery sulfur plant with an
exact stoichiometric balance of h^S to SC^. A prime
requisite in the development of our process was that it
be essentially immune to upsets caused by such variations.
This immunity is brought about by the fact that an excess
of hydrogen is at all times available to drive the desired
reactions to completion, and this excess of hydrogen may be
emitted to the atmosphere without causing air pollution.
In many months of pilot unit testing on the tail gas of
commercial sulfur plants, in both oil refinery and natural
gas treating installations, we have found that the process
is indeed virtually immune to any problems resulting from
such fluctuations. The tail gas is always purified, and
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THE RALPH M. PARSONS COMPANY
Mr. W. U. Beers
Processes Research, Inc. -7- March 23, 1972
the worst result we have observed is a very small consump-
tion of alkali when the parent sulfur plant was extremely
upset and insufficient hydrogen was available. This
insufficiency resulted only from the fact that no analytical
instrument was available on the pilot unit to give warning;
analytical instruments will, of course, be provided on
commercial units.
We concur in your observation that the Beavon process is
insensitive to feed fluctuations.
(h) For a new Claus unit the Beavon process probably should
replace the third Claus stage in all but very large units
(probably larger than about 500 LT/D).
Using the Beavon process to replace the Claus unit
altogether may be desirable in small size plants with
feed gas free of certain impurities.
(i) We understand your question to apply to a Claus unit being
fed with a mixture of l-^S and S02, containing excess S02-
If the excess of S02 is substantial, a slight modification
in the design of the Claus unit may be used to adjust the
ratio so that the Claus unit is more efficient and less
sulfur remains to be taken out when the tail gas is treated.
For economic reasons, this is preferable. However, the
Beavon hydrogenation step can indeed be used to overcome
any reasonable excess of 502 in tne Claus tail gas, and the
only argument against handling the excess SC>2 in this way
is the relatively higher cost of making sulfur in the
Stretford unit compared to the cost of making it in the
Claus plant.
We trust that we have adequately responded to your needs. Should any
clarification be required, we shall of course be pleased to hear from
you.
Very truly yours,
THE RALPH M. PARSONS COMPANY
By
0. C. Roddey
Vice President
OCR:ro gfi
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX K - J. F. PRITCHARD & CO. INFORMATION
97
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February 22» 1972
Mr. n. P. Cole
J. F. Pritcbard asd Coapaay
4623 Koanoke Parkway
Kansas City. Kiaaourt 64112
Subject: Claus Sulfur Units aud Tall flea Treati
!>aar Mr. Cola:
Several of the oothods being considered for abatement of sulfur anlaalen to
the atuoftphere Include Clous sulfur units. Tha Environsttntal P rot act loo
Agency Office of Mr Profiraos has engaged Processes Research, Inc., to atudy
the efficacy of Claua aulfur plant* to pollution abatement (Contract No.
68-n2-0242>.
Wo undoratand that your covpany d*al|as Claua units and baa davalopad, with
T«xaa Gulf Sulfur Company and the Briti0;> Sorth«*aatern Gaa Board, a prooaaa
for Clnuft tail gaa pollution abataaant. Mr. ara rafarring to the Claanalr
Process ddocribad In tbc February 7, 1972, laauee of Cbanlcal CnaioeertnK
and Tint Oil and Gas Journal. Pleaau let us have iaforaation available r«-
gnrding typical Claua aulfur units and tite Claaunlr Procasa, aa follovat
1. ?or typical Claua sulfur units, ouch aa thoaa baaad on natural gaa
(unlta having dally sulfur capacities of 10 tone. 100 tons, and
1000 CODB, acid gaa faad concentratlooa of 15 tele percent, SO aola
percent, and 90 «olo percent «2S' *D(1 Cvo tnd tnre« Claua catalytic
stance are of particular interest):
a. Percentage evltar recoverlee and tail gaa coopoaitions, before
incineration, for varlotu acid gaa feed concentrations and varloua
nuabera of catalytic atagea.
b^. Variatieo of aulfur recovery during the uaual life of the catalyst.
c. Variation of eulfur recovery with acid gaa feed at leea than full
capacity, such aa half of full feed rate.
d^. Approximate investaent, royalty, catalyet coata, and eonsuvption
and generation of fuel, water, power and ateaai for varioua daily
aulfur capacities and various acid gaa feed concentratlooa.
(Please exclude the acid gas recovery units, but include the air
blowers and tail gas incinerators.)
98
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Mr. D. P. Cole
February 22, 1972
Page 2
e_. Operator attendance, maintenance, and catalyst replacement
requirements for varioua dally sulfur capacities. Number of
days of operation to be expected annually.
f_. What acid gas feed pressure Is required to avoid need for
representation to incinerate the tail gas?
2. Por Cleanair units treating Claua tail gas to reduce the sulfurous
content to less than 300 ppm try volume 802 equivalent, before in-
cineration (please include the range of Claua tail gaa feed ratea
aad compositions produced by the Claus unite previously described:
ve understand that Clans units designed by others or using other
catalysts may produce different tall gases affecting the costs of
suitable Cleaaair units):
a. Plow diagram.
b_. Approximate investment, royalty, catalyat ccets. and coneumptlon
of fuel, water, power and steam for varioua dally sulfur capac-
ities and variona Claua tall gaa feed concentrations, aaauxdag
that the feed gas Is at atmospheric pressure.
c. Operator attendance, maintenance, smtf catalyst replacement re-
quirements for various dally sulfur capacities. Number of days
of operation to be expected annually.
d. Percentage sulfur recoveries for various Claua tall gas feed
concentrations. Variation of sulfur recovery during the usual
life of the catalyst, and for various ratios of H?S to SO, in
the Clans tall gaa feed.
e. What Is the form of the recovered sulfur? Is the recovered
sulfurous stream recycled to the Clans unit? What, If any.
impurities occur in the sulfur recovered by the Cleaaair
Process, other than those occurring la the Clans sulfur?
f_. What, if any. air pollution is presented by entralnmeat of
catalyst or solvent in the off gas from the Cleaaair unit? Is
incineration of the Cleanair off gaa advisable?
3. For new sulfur plants bassd on natural gas, combining Clans nnlts
and Cleanair unite to reduce the sulfurous content of the tall gaa
to leas than 300 ppm by volume SO2 equivalent, before incineration
(plants having daily sulfur capacities of 10 tons, 100 tons, and
1000 tons, end acid gas concentrations of 13 mole percent, 30 mole
percent, aad 90 mole percent n2S, are of particular interest):
a. Plow diagram.
99
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Mr. D. P. Cel«
February 22, 1972
Page 3
b_. Percentage sulfur recoveries and off gas compositions, bafora
incineration, for various acid gaa feed concentrations.
c. Variation of aulfur recovery during the usual Ufa of the
catalysts.
d. Variation ef sulfur recovery with acid gas feed at leas than
full capacity, such as half of full fead rate.
£. Approximate Investment, royalty, catalyst costs and consumption
and generation of fuel, water, power and stes* fof various
dally sulfur capacities and various acid ges feed concentrations.
(Please exclude the acid gas recovery units, but include the
air blovcrs, and, if advisable, include the off gaa Incineration.)
f^. Operator attendance, maintenance, and catalyst replacement re-
quirements for various daily sulfur capacities. Muaber of days
of operation to be expected annually.
&. What acid gas feed pressure la required, including, if advisable,
the off gaa incineration?
We will appreciate receiving all of the above infornatlon which you can nake
available to us. Pleaae let us know when we may expect to receive It.
We thank you for your cooperation.
Very truly yours,
PROCESSES RESEARCH, INC.
W. D. Ber.rs
Project Manater
UDB:fJ
cc: C. S. Haselbergar
M. ft. Jester
P. W. Spalte
100
-------
J. F. PRITCHARD £ CO.
ENGINEERS - CONSTRUCTORS
4625 ROANOKE I'ARKWAY
KANSAS CITY, MISSOURI 64112
TWX 910 771-2102 TELEPHONE: isie) 531-9500 CABLE. PRICO
June 5, 1972
Mr. W. D. Beers
Project Manager
Process Research Incorporated
2912 Vernon Place
Cincinnati, Ohio
SUBJECT: CLAUS SULPHUR PLANTS & TAIL GAS TREATMENT
Dear Mr. Beers:
We are pleased to respond to your request for information concerning Claus
Sulphur Plants and Pritchard's CLEANAIR Sulphur Process for treating Claus
tail gas. The information presented should assist in your study for the
Environmental Protection Agency Office of Air Programs.
PRITCHARD EXPERIENCE
Pritchard has a wealth of experience in gas treating and sulphur recovery.
We have built over 50 Amine plants, 16 Sulphur Recovery Plants ranging
in size from 10 LT/D to 1500 LT/D. We currently have contracts for 3
CLEANAIR Sulphur Plants. In addition, we have built or are designing
eight Stretford Sulphur Recovery units. The enclosed Stretford and
CLEANAIR brochures describe these two processes and present the extent
of technical information that we are at liberty to discuss without appropriate
Secrecy Agreements.
CAPITAL COSTS AND UTILITY REQUIREMENTS
Presented in the attached Tables, listed below, are order-of-magnitude
capital costs and utility requirements for the three cases cited in your
inquiry letter. The information is presented for sulphur recovery units
of 10, 100, 500 and 1000 LT/D.
Table I - Description of Cases Studied
Table II - Order-of-Magnitude Capital Costs
Table III - Utility Basis „ .,„—,~^, .Pi,,
Table IV - Order-of-Magnitude Utilities "':j:-'-V •'/:•':M '. .
. i', • e \z B ';nr 2:-
101
A
A Subsidiary of International Systems 8 Controls Corporation
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Mr. W. D. Beers
6-6-72
Page 2
PERFORMANCE OF UNITS
New Claus plants are generally designed for recoveries of 95% plus. It is
not uncommon for Pritchard to guarantee 96% recovery when fed with Amine
off gas having an hLS concentration between 50% and 90%. Nearly all new
units are being designed with three Claus reactors.
When a CLEANAIR Sulphur plant is added to an existing Claus unit or built
concurrently and incorporated in a new Claus unit, the CLEANAIR plant effluent
is normally guaranteed to contain less than 250 to 300 ppm (vol.) of equivalent
sulphur dioxide on an undiluted basis. The sulphur recovered is bright yellow,
99.9% pure, saleable sulphur. There is no entrainment of catalyst of solvent
in the effluent gas from the CLEANAIR unit. It is normally not required, or
recommended that CLEANAIR effluent be incinerated, as this presents a possible
source of NOX formation.
PROCESS QUESTIONS
(1) Variation of Sulphur Recovery
Sulphur recovery in Pritchard Claus plants will normally drop 1
to 2%, say from 96 to 94% over the period of Catalyst life.
Catalyst life will generally vary from 2 to 5 years depending
on how the plant has been operated and, of course, the feedstock.
High concentrations of heavy hydrocarbons (Cs+) will cause
carburization of the catalyst and shorten the life. High C0£
concentrations will also affect life.
The CLEANAIR Sulphur plant provides extreme flexibility in
handling varying and decreasing amounts of sulphur constituents
in the Claus tail gas. These plants can be designed to operate
on tail gases, varying threefold in sulphur constituents. The ^2$
to SOo ratio in the tail gas can vary up to 8:1 without sacrifice
in effluent quality.
(2) Turndown
Claus plants can be designed (and are operating) with turndown capability
of 33% without sacrifice in sulphur recovery.
The CLEANAIR plant will operate from 0% to 100% of design without
sacrifice in effluent quality or increasing operator attention.
i.nz
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Mr. W. D. Beers
6-6-72
Page 3
(3) Pressure Drop
Acid gas feed pressures of 6 to 10 psig are adequate to avoid repressurization
to incinerate the tail gas. If a CLEANAIR unit is added to an existing
Claus unit it is often necessary to add a booster blower to overcome the
small pressure drop in the CLEANAIR unit. This capability is built in the
Claus blower for integrated Claus-CLEANAIR units.
MAINTENANCE AND OPERATIONS
Claus plants generally operate 365 days per year. Their shutdown periods are
generally dictated by local boiler inspection requirements. Some Claus units
have run as long as 5 years without shutdowns. CLEANAIR units will operate
as long, if not longer, than Claus units without shutdown.
The estimated manpower requirements for inside battery limits units are shown
in Table IV.
Catalyst replacement will vary from 2 to 5 years.
We thank you for the opportunity to participate in your study and request a
copy of your final report when completed. We hope this information meets your
needs .
Very truly yours,
J. F. PRITCHARD & COMPANY
D. F. Cole
Contract Engineer
DFCrja
Enclosures
cc: George Thomas - Process Research
103
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TABLE I
DESCRIPTION OF CASES STUDIED
The following Table II presents order-of-magriitude total installed capital
costs for three separate types of sulphur recovery units. A summary of the
estimating basis is described below:
CASE A: CLAUS UNIT
The estimates presented are based on historical data from the more than 15
Claus plants built by Pritchard ranging in capacity from 10 LT/D to 1500
LT/D. In general, if the HLS in the feed gas is in excess of 50%, the
investment cost will generally follow a pattern based on recovery size in
LT/D. These costs are based on 3 Claus reactors, H2S feed % between 50
and 90% and assume a recovery of 95%, although some units were actually
guaranteed at 96% recovery. The costs shown include the following:
- Battery Limits Plant
- Incinerator and Stack
- Sulphur Pit (1 week) and Loading Pumps
- Paid up Royalty
- Initial Charge of Catalyst
CASE B: CLEANAIR SULPHUR PLANT
The estimates are based on actual contracts or firm price estimates previously
prepared. The costs assume the CLEANAIR unit is added to an existing Claus
unit operating at 95% recovery. The CLEANAIR unit produces an effluent gas
containing less than 300 ppm (vol.) of equivalent SQ2 without dilution. The
CLEANAIR costs shown include the following:
- Battery Limits Plant
- Paid up Royalty
- Initial Charge of Catalyst and Chemicals
CASE C: INTEGRATED CLAUS CLEANAIR PLANT
This case represents a new installation with a Claus plant and CLEANAIR plant
built together, in which case Stage III is incorporated in the Claus plant and
overall Claus recovery is no less than 96%. Stages I & II treat the Claus tail
gas producing an effluent with less than 300 ppm (vol.) of equivalent SO? without
dilution. The costs shown include:
- Battery Limits Plant
- Sulphur Pit (1 week) & Loading Pumps
- Paid up Royalties
- Initial Charge of Catalyst & Chemicals
104
June 5, 1972
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TABLE II
TYPE OF UNIT
ORDER OF MAGNITUDE CAPITAL COSTS
GLAUS UNIT
SIZE LT/D
ORDER-OF-MAGNITUDE
INSTALLED COST
CASE A
Claus Unit with
3 Stage Conversion
10
100
500
1,000
$300,000
$1,000,000
$3,000,000
$4,800,000
CASE B
CLEANAIR SULPHUR
Plant on Existing
ClaUS
10 (0.5)^
100 (5) W
500 (25)
1,000 (50)
$600,000
$1,400,000
$2,700j000
$3,400,000
CASE C
Claus-CLEANAIR
Integrated Unit
New Installation
10
100
500
1,000
$800,000
$2,100,000
$5,200,000
$7,700,000
NOTES
(1) Size of unit is actual sulphur in feed gas
(2) Figures in parenthesis represent actual sulphur recovered in the
CLEANAIR unit with a Claus unit operating at 95% recovery.
June 5, 1972
105
-------
TABLE III
UTILITY BASIS
Boiler Feed Water
Steam
Cooling Water
Electricity
Fuel Gas
220° F, 60 psig
50 psig
80° F, 30 psig, 15° F Rise
460 V/3 phase/ 60 h
<3
900 BTU/SCF G> 40 psig
106
-------
TABLE IV SHEET I ftf 'L
CASE A: CLAUS
Recovery LT/D
10
100
500
moo
C^SE B: CLEANAIR
Recovery LT/D
10 (0.5)
Ti<0 (G)
E.-UO (25)
1000 (50)
CASF. C: CLAUS-CLEANAIR
Rccovnrv LT/D
10
100
500
1000
8FW
LB/HR
3000
27,000
130,000
250,000
3000
27000
130,000
,250,000
ORDER OF
STEAM
LB/HR
(2,800)
(26,000)
(126,000)
(240,000)
80
800
4000
8000
(2700)
(25000)
(122,000)
(232,000)
MAGNITUDE UTI
COOLING WATER
GPM
100
900
4550
9100
100
900
4550
9100
(D
LITIES
ELECTRICITY
KW
40
350
1750
3500
50
380
1 900
3800
90
730
3650
7300
(1) Based on Utilities Supplied Per Table III
June r), 1972
107
-------
TABLE TV
ORDER OF MAGNITUDE UTILITIES
(1)
CASE A: CLAUS
CASE__C: C1.AUS-CLEANAIR
!toco v_ery_lT/ D^
1U
100
500
1000
FUEL GAS
SCFM
CHEMICALS
J/IW
Recovery I.T/D
-------
OVAL GUARANTEED
109
-------
... was prouen here!
The pilot testing and development work for the "CLEANAIR" Sulphur Process
was carried on jointly by J. F. Prltchard and Company, and Texas Quit Sulphur Company
operator of the plant at Okotoks, near Calgary, Alberta, Canada (shown here).
This significant new technology can result In cleaning up stack
gas emissions from sulfur plants to less than 250 ppmv equivalent SO'.
Pritchard's new CLEANAIR Sulphur Process offers the next step In sulfur recovery
beyond Claus-type systems. The technology Includes the very successful
Stratford process, plus two new processes developed and pilot tested by Prltchard and
Texas Gulf Sulphur Company.
.
110
-------
...THE MOST ADVANCED STEP
in the prevention of air pollution by sulfur compounds; 99.9% sulfur
recovery, leaving less than 250 ppmv equivalent S02 in the effluent.
99.9% REMOVAL GUARANTEED!
FIGURE
APPROXIMATE PLANT
INVESTMENT COSTS FOR
CLEANAIR
Sulphur Process Plant
The above graph showing CLEANAIR plan! costs vs. Glaus plant ca-
pacity is based upon the Claus plans operating at 95% recovery of the
sulfur In Die feed, the remaining 5% going to the CLEANAIR facilities.
Good news lo gas producers with sour
gas environmental problems! Pritchard
can clean up stack emissions of sulfur
plants ... to less than 250 ppmv
equivalent SO> exceeding the most
stringent regulations.
The process is applicable to new or
existing Clans plants and is licensed on
a world wide basis by Pritchard.
STAGE CONCEPT
The CLEANAIR Sulphur Process consists
of three stages, each of which is a
logical step toward tail gas clean up and
can be installed as required to meet
varying control standards.
Stage I of the Process can be installed
for about 50% of the overall cost, and
removes approximately 50% of the sulfur
from the Claus plant tall gas.
Stage II, involving about 40% of the
total cost, can remove essentially the
remaining 50% of sulfur constituents
from the Claus plant tail gas.
Ill provides polishing facilities,
h reduce sulfur constituents in the
errt to very tow levels.
design is for less than 250 ppmv
equivalent SO in the effluent when all
three CLEANAIR stages are installed.
PROCESS CONSIDERATIONS
The CLEANAIR Sulphur Process recovers
sulfur from Claus plant tall gas as
elemental sulfur, making it possible to
use existing or normally planned sulfur
handling and storage facilities. It is
unnecessary to recycle gas streams back
to the Claus unit allowing the Claus unit
to be operated as it would be without
the CLEANAiR unit.
Pritchard will arrange for client inspection
visits to Okotoks and to the Pritchard
built Stretford unit at the "THUMS"
facility, operated by Lomita Gasoline
Company in Long Beach, California. This
unit represents an advanced
application of the Stretford Process.
CLEAN STACKS are Good
Business and of Significant
Value in Public Relations.
100%
CLAUSI
PROCESS
95%
-90%
-80%
-70%
-60%
-50%
-40%
-30%
-20%
-10%
111
-------
Figure II
CLEANAIR SULPHUR PROCESS SCHEME
Acid Qaa
Slage ill*
(Clau.)
Claw
Tall
Ga»
f
Stage
III*
1
CLAUS
Ellluenl Containing
Less Than
250 ppmv
S at SO.
Sullur to Storage
Sulfur to Storage
'Stage III is Incorporated into new Glaus plant designs while it
operates on tail gas in existing units.
Sullur to Storage
SO
Approx. 50
Converts essentially all
of the SO] to S with some
conversion of H;S to S.
40
Approx. 50
Converts remaining
H,S to S.
III
10
Polishes effluent to less than
250 ppmv equivalent SO,
Reduces COS and CS,
level in tall gas.
Development work has been carried out on a semi-
commercial scale at the 400 LT/D Okotoks plant of
which Texas Gulf Sulphur Company is the operator.
Actual plant streams from an operating commercial
Glaus plant are processed in the pilot plant facilities.
The stream quantities processed are equivalent to
a 4 to 5 LT/D Glaus unit. Pilot facilities have been
in operation since 1968.
The pilot plant program had two main objectives:
• Tail gas clean-up for existing Claus units.
• Design and clean-up of new Claus installations.
Technology exists to meet the stringent require-
ments established by pollution authorities. Sulfur
recovery could be increased by the addition of third
and even fourth stages of Claus conversion—but
there are limits. Conversion efficiency is limited by
chemical equilibrium, particularly as dictated by
temperature and the presence of water. The amount
of additional sulfur recovered decreases while the
recovery cost of the incremental sulfur skyrockets.
Lowering the temperature or removing water favor-
ably affects conversion, but results in solidification
of sulfur. Consequently, 98% recovery is the maxi-
mum for Claus processing—far from acceptable
by the standards being implemented today.
Indeed, some standards are so rigid that they re-
quire removal of organic sulfur compounds, car-
bonyl sulfide (COS) and carbon disulfide (CS2), that
are present in Claus plant tail gas streams in addi-
tion to hydrogen sulfide and sulfur dioxide. Pre-
viously, removal of COS and CSj has received little
emphasis since the quantities involved had minor.
effect on overall sulfur recovery. Consequently, the
state of the art with respect to removal of these
compounds has been less fully developed than the
knowledge involved in the removal of H2S and SOj.
Pritchard has engineered and built Claus plants
since 1953 including units ranging in size from 10
to 1,500 tons of sulfur per day. This experience
plus recent Okotoks development work has defined
112
-------
the troublesome areas in tail gas clean-up and has
established design parameters for. new Claus plants
to minimize these problems.
Pritchard, as a result of the CLEANAIR Sulphur
Process development, can offer to industry the tech-
nology required to meet existing and anticipated
environmental standards. By combining an estab-
lished process with proven sulfur chemistry and
catalyst developments, Pritchard provides process
know-how to advance the state-of-the-art in sulfur
recovery. As a result of development work and en-
gineering/construction expertise, Pritchard will
custom design plants to meet individual client re-
quirements.
SO: Conversion (Stage t)
J. F. Pritchard and Company joined with Texas Gulf
Sulphur Company to continue a development
project initiated by TGS some two years earlier. The
objective of this development work was to convert
SO] in Claus unit tail gas to sulfur. The result of the
joint effort is Stage I of the CLEANAIR Sulphur
Process.
The pilot plant has consistently demonstrated re-
moval of SO] down to 75 ppmv. Commercial design
is for 100 ppmv. Some H2S is converted to sulfur
in Stage I. All of the entrained elemental sulfur is
recovered also.
HzS Conversion (Stage II)
The Stretford Process
The CLEANAIR system employs the Stretford Proc-
ess as Stage II. The Stretford Process, a develop-
ment of the North Western Gas Board of England,
is offered by Pritchard through license. There are
more than 50 unite in commercial operation through-
out the world. Pritchard built and successfully com-
missioned the first Stretford unit in the United States
for THUMS Long Beach Company and the Depart-
ment of Oil Properties in Long Beach, California.
In addition, Pritchard is now engineering and con-
structing additional Stretford units for clients in
North America.
The Stretford Process consists of a gas washing
system wherein the gas is contacted countercur-
rently with an alkaline washing solution. Hydrogen
sulfide is removed from the gas stream and oxidized
to solid sulfur. The sulfur is formed as a finely dis-
persed solid in the circulating solution. The reduced
solution is then oxidized by air blowing which simul-
taneously removes the sulfur by froth flotation. Oxi-
dized solution is returned to the gas washing system
to repeat the cycle.
COS/CSj Removal (Stage III)
An Industry Breakthrough
Some of the sulfur components in a Claus unit acid
gas feed, which contains carbon dioxide and a minute
quantity of light hydrocarbons, are converted to
COS and CS2 in the Claus reaction unit. As much as
25% of the sulfur present in the tail gas may be in
the form of these organic sulfur components. Equiv-
alent SOj concentration varies from 4,000 ppmv for
a Claus unit operating at 96% sulfur recovery to
10,000 ppmv for a unit operating at 90% recovery.
Obviously COS and CS2 removal must be accom-
plished to meet proposed standards that limit total
sulfur emissions to 250 ppmv. The CLEANAIR Sul-
phur Process incorporates such removal as
Stage III.
COS and CS; formation in Claus units has been cor-
related as a function of acid gas composition. The
correlations are based on data from operating
plants. The correlations have been substantiated
through pilot plant work and are used in predicting
COS and CS2 formation in the design of Claus plants.
Stage III of the Process was developed through
18 months of pilot plant operation. COS and CS2
contamination has consistently been lowered from
12,000 ppmv to 150 ppmv. In the pilot unit, investiga-
tions have been performed on process streams from
several points in the Claus process to determine the
most economical means of accomplishing COS and
113
-------
.
Aerial photo of the 1500 tons per day sulfur recovery plant, engineered
and constructed by Pritchard for Pan American Petroleum
liate of AMOCO) at East Crossfield. Alberta, 'Canada.
CSj conversion. The results of these investigations
are incorporated into the design of new Claus units
as well as CLEANAIR units for tail gas treatment
on existing Claus plants.
Reliability
The CLEANAIR Sulphur Process is carefully de-
signed to assure reliability and ease of operation.
It is expected that codes will not allow periods of
variance of emission standards. Testing has been
carried out to determine proper materials of con-
struction. Critical items of equipment are spared to
allow continuous operation.
As an example of the CLEANAIR flexibility, the Stret-
ford solution (Stage II) can be overloaded by H2S as
much as 100% with only minor changes in normal
operating procedures. This feature is especially im-
portant when it becomes necessary to burn off cat-
alyst in a Claus unit. This also allows Stage I to be
taken out of service while Stages II and III continue
to operate. This flexibility permits the plant to meet
continuous on-stream demands for clean-up
systems.
FORM CASP 5M 7112
The CLEANAIR unit can be turned down to any
rate below design without difficulty, and can even
be idled on line. In cases such as oil refineries,
where a number of units produce acid gas, normal
shutdown of individual units causes feed rates to the
Claus unit to vary. Ordinarily, Claus units operate
at lower recovery efficiencies when fed at lower
than design rates. The CLEANAIR unit, while de-
signed for clean-up at full Claus plant rate, also
guarantees total recovery over the full range of
Claus plant operability.
Product Sulfur Quality
Sulfur produced in a CLEANAIR unit is typically
99.5% pure, but Pritchard can guarantee the sulfur
product to be 99.9% pure based on total pit pro-
duction. The sulfur is suitable for any ultimate use.
A typical analysis is:
Sulfur 99.9%
Organic Impurities 0.02% Max.
Ash 0.01% Max.
114
-------
Economics
Figure I shows CLEANAIR investment requirements.
Typical utilities and annual operating costs are set
out in Tables II and III, respectively, for three tail
gas clean-up cases.
Case
A
B
C
Claus Unit
Capacity, LT/D
50
150
500
Cfaus Recovery
Efficiency, %
95
95
In all cases the design basis is 250 ppmv equivalent
SO] in the effluent before incineration and dilution.
Further, the Claus unit is assumed to be existing
and no provisions are included in the Claus unit to
minimize tail gas clean-up requirements. The costs
can vary with the hydrocarbon, carbon dioxide and
hydrogen sulfide content of the acid gas feed to the
Claus unit as well as the static pressure of the tail
gas.
Case A
$925,000
INVESTMENT
CaseB
$1,400,000
CaseC
$2,200,000
SUMMARY
Disclosure of technical details of CLEANAIR re-
quires execution of a secrecy agreement. A ques-
tionnaire is available from J. F. Pritchard & Company
to delineate gas conditions and composition for
individual plant applications. Order-of-magnitude
investment costs and expected operating costs can
be furnished on a non-confidential basis.
Pritchard and TGS maintain the pilot plant at the
Okotoks, Alberta, Canada, plant for client demon-
stration. Arrangements can be made also for client
visits to Stretford plants.
TABLE II
UTILITIES SUMMARY
CoMMona
CM* Cn* C«w
Unit. ABC
50 pafg, salurateo1
CooHngWattr 10'F. 30ptlg.
1S°FrtM
lb/Hr. 400 1200 4000
0PM 475 1400 4550
Electricity 2W/440/2160 «IW.
9 phase, M hem KW 200 500 1900
Fuel On 900 BTU/scf, 40 psig SCFH 500 1500 4500
TABLE III
ANNUAL OPERATING COSTS (365 Days/Yr. BASIS)
Unit
Annual Co*t
Caw* CM*B CM*C
1.40/1000 Ib.
Cooling Water $.02/1000 gal.
Electricity V007/KWH
Fiwl CM (.45/1000 SCF
Chemicale $1.75/IT ol
Sin TO
Operating Ubor v, man/shift
@ S7/MH
Deer. * Finan. 15% ol flrad
capital inv.
3% of F.C.L
TOTAL
$ 1.400 I 4.200 S14.000
5.000 14,700 49.000
12,200 35,600 116,500
1,*00' 3,»00- 17,700'
1.600 4,100 16.000
15,300 15.300 15,300
13*400 210.000 330,000
27,100 42.000 00,000
203.700 332.500 824.500
* In molt cases Incineration will not be necessary.
Coat* shown an for actual process fuel requirements
not Including incineration
A net credit for luel gas can be taken resulting from
savings In Incineration when CLEANAIR la added to
a Claus unit. Actual fuel requirements for Incinera-
tion are reduced by 40%.
Sulfur converters and waste-gas chimney ol a typical
Claus- type recovery plant
115
-------
Pritchard's growth embraces world-wide engineering,
procurement and construction capabilities.
Pritchard has enjoyed rapid growth within the last decade.
In keeping with our fiftieth annniversary In 1970, was the achievement
of a greatly expanded sales and engineering staff and procurement
and financing connections to keep pace with world-wide construction.
Shortly thereafter, a fifty million dollar project was acquired on
a lump sum basis, involving a giant Liquefied Natural Gas facility at
Skikda, Algeria.
The world's largest gas treating plant, a vital unit in the IGAT project,
has gone on stream at Bid Boland, Iran. Many other projects,
In gas treating, petrochemicals, sulfur removal and environmental
processes to clean-up pulp and paper effluent were contracted
for and constructed around the world.
Pritchard has also taken steps to bring this global capability
close to you. Sales and/or engineering offices are located in
Houston; New York; Los Angeles; Calgary; London; KCIn; Paris;
Sydney; Beirut and Tokyo. (See listing of affiliates and
addresses, on this page.)
Top management control and turn-key performance are the
Ingredients of our success story. We welcome any Inquiry, large or
small, regarding our process technology and how It can contribute to
your expansion programs.
THE
Pritchard
COMPANIES
4626 ROANOKE PARKWAY • KANSAS CITY. MO 64112
HOUSTON • NEW YORK A LOS ANGELCS • CALOAftY
LONDON • KtiLN • PARIS J^QL SYDNEY * BEIRUT • TOKYO
Sub»id.»n*s of tnt»rn«lioo«l Svs1«m» tV Conuols CwpOfiilton
HOUSTON. T.-XIIS ffO?'f. .1. r. PnlcharO
>1 Company, tiuiln bW txuruiui1 Plaza,
4615 Soulhwoat fiiTOvnv
NEW YORK. N V iuu?it.j I r.iichard
>\ O-'rrjKin, H-:'i>tn 351G Tinio K I id'
lluilHni'!. It I .', .si Mill! :;!»•>!<
LOS ANGELES. lNrv»nml IViictl).
C.lliluiiiu it,>fi6;i. .). I I'nldl.inf A Citmp.niy.
f'.O »<>« '-»-tr. ."001 Bu'iiiu;sc CVnlm Or.
CALGARY I Albi'ilu. Ciin.iitt. Pnlrjhard
lion, I miitoil. Suili- IliUO Aquilninc
Towiir. S40 Fillh Av.niuo S.W.
LONDON, WIH. SAD l.niilnmt,
I'ul, ti.ml-tili.Kli!-. I imili'H.
I'riu hard Houi*t'., 2b7 TyltonUam Court Rd
COLOGNE, •'. Koin ,«i. W.iSl Ciormany.
KIID Piitilvud G.HI.6 H.. PoMlach 300600
PARIS, ; ' cnlKilo
il tllr.V-K IrnluMiiiiii. 5, (rod I)
I no"u ''1111,1. -14 Avfuuo il*! Cllflton, 9^.
liil"!! M.-i'lp.i
SYDNEY, (Clmlswood).
N S W ?007 Auslioli.i.
Pllli L.iirl l[!u-',l«, (Ausli.iliii) IMY LTD.,
I'O tlcix 31?
BEIRUT, Liibnniin Prlichnirt-Rhoilaii
Mniclli' E;isl Liilnlfit. P.O l)o« 8100
ALGIERS. (KcnlKil AlgiM, L.i Ropubliquo
Ai.ii-iirr.lv. Prllthard-Rhodos llmiteif.
'I lil:, U,MI MtMaliOl
TOKYO. J;i»i,-iiv U.C Worlrf Tratfn
lion. Cf'fl ?003
116
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Clean Up Gas Streams In ONE EASY STEP
process
117
-------
THI "THUMS* PKOJtCT, LONG BIACH. CALIFORNIA
280 wellt from 4 drilling rlgtl A unique worid-engineer-
!ng-|tnt wu employed at the Four "Oil islands" where
the 4 derrick* (shown below) mounted on tracks can
fa* moved and positioned to iltnt-drlt! «• many »
350 welt* Ifom eten iiland.
Latest addition to the famed Long Beach "THUMS" project is this Strettord
facility, engineered and constructed by J. F. Pritchard and Company,
for the operator, Lomita Gasoline Company at Long Beach, California.
It was the first plant built in the United States using the proven Stretford
Process to clean up gas streams in addition to being the first facility anywhere
in the world to apply this process to the purification of natural gas from oil
wells. It incorporates exclusive new technology developed by Pritchard
from extensive experience in engineering and constructing sulfur recovery plants.
The oil from the surrounding Wilmington Field supplies the feed gas. The
name "THUMS" is an acronym for Texaco, Humble, Union, Mobil and Shell,
the oil companies, who with Standard of California, Atlantic-Richfield
and Signal Oil & Gas, jointly cooperated with the City of Long Beach and
Lomita in underwriting the facility cost.
Pritchard has also developed process improvements to extend the process
applicability to a wide range of gases which can be purified economically,
thus improving the efficiency of future plants. Plants are normally designed to
produce a treated gas containing not more than 4 parts per million by
volume (ppmv) of H>S. However, if required, as little as 0.2 ppmv can be achieved
by the Stretfort Process.
118
-------
THE QUEEN'S AWARD TO INDUSTRY
by the "Stretford Process"...
Licensed to Pritchard for
world-wide application
A significant contribution to pollution abatement
measures is the widely proven "Stretford Process"
which removes hydrogen sulfide from sulfur-
bearing gas streams including "sour" natural gas,
refinery gas, industrial plant effluents and coke
oven gas.
Originally developed by the North Western Gas
Board of England, the process is licensed to Pritch-
ard for world-wide application and ties in with
technology developed by Pritchard in over 50 years
of experience with gas processing, sulfur removal,
petrochemical production and Glaus plant tail gas
clean up.
The Stretford Process has been commercially
proven in more than 50 plants around the world
(about half in the British Isles) over a period of
many years.
Pritchard engineers are confident of perform-
ance, and studies or consultation services are
offered for formal presentation to pollution control
authorities even under strict code requirements.
Elemental sulfur removed is normally 99.5% pure.
This photograph shows sulfur cake
being discharged from the vacuum
filter at the THUMS facility operated
by Lomita Gasoline Company at
Long Beach, California.
1968
HISTORY
A
the Systems Approach
is the Sound Approach.
Generally recognized as a breakthrough,
the Stretford Process of gas purification
dates back to the early 1960's. In 1968 the
Stretford Process received the Queen's
Award to Industry for technical innovation.
Based on the use of an aqueous alkaline
solution of salts of one or several anthra-
quinone disulphonic acids (ADA), it con-
stitutes a continuous liquid process for the
removal of hydrogen sulfide from gas
streams.
The Stretford process was originally de-
veloped for the purification of coal gas,
and proved so successful that it is being
applied for the purification of gases as
different as coke-oven gas, reformed pe-
troleum products, natural gas and even the
effluents from the manufacture of yarn,
paper, foil and other industrial products.
Continued research and experience have
yielded many refinements and improve-
ments, making the Stretford Process com-
mercially and economically attractive,
especially in our increasingly anti-pollution,
ecology-conscious world.
The Stretford Process, originally devel-
oped to meet British Statutory restrictions
limiting H2S in coal gas, down to 1.5 ppmv,
has now been refined and improved in so
many ways that it becomes the ultimate
choice and the most economical overall, fn
both capital and operating costs.
Pritchard's Stretford plants recover sulfur
having a purity of better than 99.5%, elimi-
nating the effluent problem and yield a
product in saleable form, in many cases
amortizing part of the investment.
SUMMING UP: Pritchard's expertise in
advanced Stretford application offers the
most flexible and sophisticated method
available for the effective, complete, one-
step removal of H2S. And secondly, it is
the most economical in both capital and
operating costs for most applications.
119
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CLEAN GAS
OUTLET
FOUL GAS
INLET
process description
STRETFORD PROCESS FLOW DIAGRAM
AIR
REACTION
SOLUTION PUMPING
CIRCULATING TANK
PUMP
OXIDIZER SULFUR SULFUR
SLURRY TANK SLURRY
PUMP
A generalized process (low diagram of the Stretford
plant is shown above. The gas stream enters an ab-
sorption column where the HiS is absorbed by gas
contact countercurrently with the Stretford solution.
Soda Ash—When carbon dioxide is present in the gas
stream, a mixture of sodium carbonate and sodium
bicarbonate is formed giving a solution of stable pH
normally In the range of 8.5 to 9.5. This provides the
alkaline solution for initial HiS removal from the gas
stream with the formation of hydrosulphlde.
Sodium Mela Vanadate—When reacted with HS",
vanadium reduces from 5 valent to 4 valent resulting In
the precipitation of sulfur.
Sodium Potassium Tartrate (Rochelle Salt)—Prevents
deposition of vanadium in over-loaded (upset) solutions.
Anthraqulnone Oisulphonic Acid (ADA)—the 2:7 isomer
of ADA oxidizes 4 valent vanadium to 5 valent.
The HtS is absorbed and the clean gas stream is
recovered for other use. Outlet H.S loading depends on
design and can be guaranteed to be as low as 0.2 ppm
in certain applications. It should be pointed out that
more than 25 Stretford plants are operating in Great
Britain and Northern Ireland, where the maximum level
of H.S permitted is 1.5 ppm. Most of these plants have
demonstrated on a continuous basis exit loadings of
less than l ppm.
The Stretford solution, after recirculation through the
H.S absorber, is retained for 10 minutes to allow for
completion of the reaction between HS and vanadium.
This hold up can be in the bottom of the absorber
vessel or in a separate tank. From the hold tank, the
solution passes to the oxidlzer vessel where air is
sparged upward through the solution.
A SIMPLIFIED SUMMARY OF THE REACTIONS
INVOLVED IN THE STRETFORD PLANT
FOLLOWS:
1. Soda Ash (Sodium Carbonate)—Provides the alka-
line solution for initial absorption of HiS and forma-
tion of hydrosulphlde (HS ).
H,S+Na. CO.—>N«HS+NaHCO> (Absorber)
2. Sodium Mela Vanadate—Reacts with HS , Is reduced
from 5 valent to 4 valent and this precipitates sulfur
from the hold tank.
HS + VH-' > S + V**> (Hold tank)
3. Anthraquinone Disulphonic Acid- (ADA)—React* with
the 4 valent vanadium, convert* It back to 5 valent
and I* Itself reduced.
V'<+> + ADA > V*> + reduced ADA
4. Oxygen from air convert* reduced ADA back to the
oxidized state.
Reduced ADA + 0. } ADA + HiO (Oxidlzer)
5. Overall reaction I*—
2H.S + 0. ^2H*> + 2S
A small excess of vanadium ton is helpful in preventing
solution overloading due to variations in gas flow and
H.S content, but usually is uneconomic if upsets occur
rarely. Conversely, too little vanadium allows formation
of thiosulphate and concomitant solution loss through
purging. Pritchard's knowledge of operating plants in
the petro-chemical industry allows an optimum design
on each individual plant. Pritchard is well qualified and
happy to issue an economic analysis'embracing capital
and operating costs on an individual plant basis.
The sulfur formed in the Stretlord process is finely
divided and is floated to the top of the oxidizer by the
air. The sulfur forms a froth containing 6 to 8% sulfur
at the top of the oxidizer. This froth overflows to a
settling tank where the sulfur slurry Is accumulated for
subsequent recovery. Underflow from the oxidizer is
sent to the absorber pump tank for recirculation to the
HiS absorber.
The sulfur is fed to an autoclave where heat is applied
to melt the sulfur. The sulfur-water mixture is separ-
ated, and liquid sulfur of greater than 99.5% purity
and commercially acceptable is obtained. Sulfur purity
depends largely on the amount of impurities such as
tars and light oils present in the original gas stream.
When these are absent the sulfur purity can be as high
as 99.9%.
None of the constituents used In the Stretford process
has proved hazardous in years of operation. No special
handling precautions are necessary.
120
-------
A unique feature of the Stretford plant
at Zurich, Switzerland la the application
of nine washing towers, accommodating
three separate streams. Each stream has
a capacity of 7mm SCF/D. (photo
courtesy N.W.Q.B.)
Photo shows compressor and pump house
with control panel. Stretford plant, Bris-
tol, England,
Stretford Plant, Long Beach, California
A view of the plant taken during start-
up. This plant purifies 65 mm SCF/D
of oil field gas containing 0.15% HtS.
Stratford Plant, Bristol, England. Two
parallel streams, each 8 mm SCF/D coal
gas. Exit gas purity less than 1ppm,
E. Stretford Plant, Belfast, Ireland. Dual ab-
sorption columns, oxldlzers & solution
inventory tanks.
121
-------
Feedstream
Plant A
Natural Gat
al Wellhead
S5
1490
Flow rate— MMSCFD
Inlet sulfur loadihg-ppmv —
Outlet sulfur loading
(guaranteed)-ppmv 2.5
Capital Co«t $800,000
Yearly Operating Coat
Chemicals - $ 1,200
Electricity _ 10,000
Steam ~ None
Operating Manpower _ None
Maintenance (3% of FCI) 24,000
Depreciation (15% of FCI) — 120,000
Total ._ - - $166,000
Overall cost of operation In
$/long ton sulfur.— —— .....
• 'Product quantity too low to warrant recovery for sale.
Stretford Process
Spans the world
Stretford plants outside
• the U. S.
• Licensees and associates
tor the Stretford Process
• Pritchard built
Stretford plants.
(PARTIAL LIST)
Bath
Belfast
Bristol (3)
Cardiff
Ipswich
London (3)
Middlesbrough
Norwich (2)
Carrickfergua Oldham
Colchester Pontypool
Ounstable
Exeter
Gloucester
Guernsey
Reading
Southampton
Tottenham
Whltchurch
Plant B
Refinery
Synthesis Gas
49
14,000
10
$1,100,000
$ 16,000
40,500
500
19,000
33,000
165,000
$ 274,000
$ 30.00
Huddersfietd
London
Manchester
Sheffield
c/
f^frri
Economics
Economics of the Stretford process
have been proven. Inlet gas composition,
operating pressure and outlet gas purity
required determine both capital and
operating costs. Generalized economic
analyses can be misleading. Pritchard is
happy to provide cost estimates for
your problem gas stream.
However, shown here are two actual
cases studied with an economic analysis
for each.
Plant A involves low H>S loading while
Plant B has high H>S loading. Both plants
were designed to operate between 90
and 135 psig pressure on the inlet gas
stream. No credits are assumed
even though incineration and discharge
into a high temperature stack is
unnecessary with the Stretford system.
A high quality, saleable sulfur product
is obtained. Sulfur prices are heavily
dependent on freight and as a
consequence, economics vary with
plant location.
Stretford plants are purifying gas streams
of all kinds, ranging from a few
thousand to more than 50 million cubic
feet per day... from coke ovens, ore
smelting, chemical plants, petroleum
refineries and natural gas sources.
Purification can be carried out at
pressures ranging from atmospheric to
more than 1,000 psig. Thus, each application
is designed to meet specific problems
and local conditions.
CONSTRUCTION MATERIALS
Usually with mild steel throughout, with
inert linings such as cold-cure epoxy
resins for oxidation vessels and slurry
tanks to avoid internal corrosion from
sulfur deposits.
Pipework is of conventional construction
throughout. Pumps are of the centrifugal
type for liquor circulation and of the
screw type for slurry handling.
The vertical washing tower or column
is the most used type of purifying vessel,
with the Stretford solution entering at top
and the gas to be purified at the bottom.
Blowers or compressors, where required,
may be of any suitable type, providing
they deliver air free from oil. No special
technical restrictions on oxidizer design
are required. Caution should be observed
to prevent the accumulation of sulfur
deposits on unprotected metal surfaces
in vessels and pipelines.
• v 'Tr
^4-
. _^—
122
-------
Why Stretford?
Advantages of the Stretford Process:
1. Well proven commercial operation
over many years and a wide
variety of gas streams.
2. Provides complete clean up of HiS to
well below 1-ppmv if required.
3. Extremely flexible operation with
high turndown ratio.
4. Requires little operator attention.
All process streams are handled as
liquids, making for inexpensive
automation.
5. Good process control can be
maintained by simple analytical
testing with little technical
supervision.
6. Short start-up and shutdown period.
7. Mild steel construction primarily.
8. No special handling required of the
aqueous Stretford solution or stored
makeup chemicals.
9. Low chemical consumption.
10. Low maintenance.
11. Recovers contaminants as a saleable,
widely-used material.
12. Plants may be operated over a wide
range of pressures.
Why Pritchard?
In addition to the above listed advantages
inherent in the Stretford Process,
Pritchard offers the following exclusive
Improvements to the basic process:
1. Easy, trouble-free production of
bright molten sulfur.
2. Increased efficiency of the oxidation
step.
3. Optimization of the absorber tower
design ... all adding up to improved
economics!
Ctble or Call Us, About four
ecological P«o/»m»
Our engineer* love to talk technology.
PHONE: (816) 531-9500
Or, il you ere overseas, contact any of our
offices near you, shown on back page of thi«
folder. The meter won't be running)
Some Typical Stretford Plants
1
Plant Location
Amagasaki, Japan
Belfast, N. Ireland
Bergkamen, W. Germany
Carrickfergus, N. Ireland
Colchester, England
Guernsey, Channel Islands
Hamilton, Ontario
Johannesburg, S. Africa
London, England
New Delhi, India
Taiwan
Zambia
Zeebrugge, Belgium
Zurich, Switzerland
Long Beach. California
Toledo, Ohio
Herscher, Illinois
Philadelphia, Penna.
Los Angeles, California
GatFecd H,S Inlet
Type of On MMSCFD Loading
Coke Oven
Refinery/Reformed
Coke Oven
CS2 Retort
Otto Reformer
Reformed Petroleum
Coke Oven
Producer
Water Shift
Chemical Process
Coke Oven
Ammonium Nitrate Plant
Coke Oven
Coke Oven
Natural (Oilfield)
Refinery
Natural
48
45
36
0.1
6
3
28
6
65
0.1
11.8
10
14
21
55
•49
45
0.3%
16-200 ppm
0.6%
60%
30 ppm
30 ppm
0.64%
0.15%
200 ppm
100%
1.25%
1.5%
0.5%
0.5%
0.15%
1.9%
0.06%
(Part of a CLEANAIR plant—
1 ton sulfur per day)
FORM S*> 5M 7112
(Part of a CLEANAIR plant—
40 tons sulfur per day)
All U.S.A. plants to date are of Prftchard design and construction.
The Long Beach plant went on stream May, 1971, followed by two
plants In the Spring of 1972, and two more in early 1873.
123
-------
Pritchard's growth embraces world-wide engineering,
procurement and construction capabilities.
Pritchard has enjoyed rapid growth within the last decade.
In keeping with our fiftieth annniversary In 1970, was the achievement
of a greatly expanded sales and engineering staff and procurement
and financing connections to keep pace with world-wide construction.
Shortly thereafter, a fifty million dollar project was acquired on
a lump sum basis, involving a giant Liquefied Natural Gas facility at
Sklkda, Algeria.
The world's largest gas treating plant, a vital unit in the IGAT project,
has gone on stream at Bid Boland, Iran. Many other projects,
In gas treating, petrochemicals, sulfur removal and environmental
processes to clean-up pulp and paper effluent were contracted
for and constructed around the world.
Pritchard has also taken steps to bring this global capability
close to you. Sales and/or engineering offices are located in
Houston; New York; Los Angeles; Calgary; London; K8ln; Paris;
Sydney; Beirut and Tokyo. (See listing of affiliates and
addresses, on this page.)
Top management control and turn-key performance are the
Ingredients of our success story. We welcome any inquiry, large or
small, regarding our process technology and how it can contribute to
your expansion programs.
THE
Pritchard
COMPANIES
4625 ROANOKE PARKWAY • KANSAS CITY, MO. (4112
HOUSTON • NEW YORK
LONDON » KOLN . PARIS J
LOS ANGELES • CALGARY
SYDNEY . BEIRUT » TOKYO
HOUSTON, Trx.i': iVi'.'Y. .1. F. i'ntcll.lld
iht'j S.IUtlmi-Kt I l.'rw.ly
NEW YORK. N V. iwi'ii.j i i'ii!,.h,tfd
". Cnm|iuny, ||O»HI .'MO Timn «• l.il"'
Dl/lll'ino. II ! Uii:.l Will! ••'.«-.•!
LOS ANGELES, lNi'«(vni n.su.li)
C,iiit..mi.i <.<.>(,t;:i .1. i I'niriKir.i x Ciiiiip.iin,
r'.ll Hn« . 'LI.' ."i,.iPr.. -t.s Cfrlliil Ol.
CALGARY ' Mlnvi.i, I'lin.uin. I'nlihanl
I,mm. ;.']» l-illll AI/,.-IIU,, s W
LONDON, Wllv DAll l.iuilunil.
F'lit.-h.iHj-Hti.Miv, Limiloi),
TriU !i;<".1 IfiHii..-. ',".>! TMtlouhai" Cimrl H,l
COLOGNE. :i h,,in ,KI, w,-sl Gnraunj,
KHD I'liK h.n.l I", in i> II , r'usllwh 30 OB 60
PARIS. ri.Hu.-.r.nmi.i.iiiHi' CI.IIIIL,],.
il'l-'tii,!-.-.. liidii-.ilru'iifs, (COCE.I)
ing, -M. Avruuo dii Cliniou, yi',
Itii'-it M.-illi!.ns,>n
SYDNEY, ((;li.ilsw,-K.i!),
NSW. PtW AuBtinlKi.
I'nlch.iiil-riDoan:. (Ausliuli.i) I'l'V. I.Tp..
i>o no* 3is
r. l"r,Hl>Mi PnU'h.M.) lltiinl.--.
Mi.Mi. IT.isI liiiuli'il. t'O l!"«610fi
ALGIERS. (Kculiul Altj.-'i. In Roinililiq
Ai,f^rii'nno, (Jiil^hard-Rtisnfori Ifmitc-i,
.1 Kill' [!.'diari«c of Intarnational Svatama & Control! Corporation
124
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX L - CHIYODA CHEMICAL ENGINEERING & CONSTRUCTION CO.. LTD..INFORMATION
125
-------
f1 UI v A H A
-------
Client
Nippon Mining Co., Ltd.
Fuji Kosan Co,, Ltd,
Tohoku Oil Co,, Ltd.
- 2 -
Capacity
33,500 Nm3/h
15,8,000 "
14(000 "
Mitsubishi Rayon Co., Ltd, 90,000
Gas to be
Treated
Claua Tail Gaa
Boiler Flue Gas
Claus Tail Gaa
Boiler Flue Gaa
We thank you again for your interest in our Process
and ahall be pleased to hear from you of a specific inquiry.
With beat regards,
Very truly yours,
M. Sato
Executive Managing Director
Kl/hy
Encl.
127
-------
The Chiyoda TI
Flue Gas Desulfurization Process
CHIYODA
CHEMICAL ENGINEERING
& CONSTRUCTION CO.LTO.
128
-------
"Chiyoda THOROUGHBRED" Series of
Environmental Control Technologies
With the remarkable industrial growth, great em-
phasis has been placed on the necessity of pollution
control. We, at Chiyoda, fully recognizing the growing
importance of providing preventive measures against
environmental pollution, have been determined to
challenge this difficult problem based on the total
systems engineering approach. Since the types and
conditions of pollutions are varying in nature, an overall
systems approach is essential to find the best possible
solution.
We are firmly determined to concentrate our tech-
nological efforts on the development of various tech-
nologies for environmental control to meet the need of
the public and industry. It. is for this reason that we
have given a trade name "Chiyoda THOROUGHBRED"
to the processes and equipment for environmental
control with classification numbers coded to each
category. "THOROUGHBRED" stands for the best
race horse of a breed ever created through centuries
of crossbreeding improvement. It is our sincere hope
that the "Chiyoda THOROUGHBRED" series of
environmental technologies will earn the same assessment
and reputation.
Processes and equipment that must be developed
should be such that they satisfy the universal need as
viewed from long range demand forecasts and they
should be developed to solve various problems relating
to environmental preservation under a wide range of
variable conditions.
With the energy innovation coming before us, it is
imperative to place emphasis on the selection of systems
that will provide logical solutions to the problems.
We solicit your continued kind patronage of our
comprehensive services in the field of environmental
control including plant safety control and earthquake
damage prevention.
We avidly look forward to being of service to you.
A. Tamaki
President
129
-------
"Chiyoda THOROUGHBRED 101
Flue Gas Desulfurization Process
1. Flexible to Meet Various Conditions
Various processes of removing sulfur oxides from flue
gases have been developed or are under development
in the world. However, as each process has dis-
advuntages and limitations with requirements for further
improvement, it is of utmost importance to evaluate
and select a process most suitable and flexible to meet
each specific requirement.
"Chiyoda THOROUGHBRED 101" not only demon-
strates high efficiency performance, but also displays
other advantageous features. It only produces gypsum
as a by-product which is completely harmless and non-
toxic, and does not. discharge any stream that will
cause secondary pollution.
"Chiyoda THOROUGHBRED 101" is easy to operate.
and has a highly reliable performance. In addition,
capital, operating and maintenance costs are low. Pro-
cessing cost of the by-product gypsum is only small.
The solution in the absorption-oxidation section is not
slurry, and thus ensures stable operation and is not
detrimental to the operation of the boiler and other
related equipment.
2. Contributions to the Petroleum Industry
"Chiyoda THOROUGHBRED 101" ensures petroleum
refineries an effective use of low-grade fuels such as
asphalt for power generation and also pipestills.
Since "Chiyoda THOROUGHBRED 101" is of simple
construction and has highly reliable operation, it is
suitable for SO2 removal from the tail gas of a sulfur
plant.
There are many cases where boilers and pipestills are
located apart in the premises of petroleum refineries
and petrochemical complexes, and large diameter ducts
are laid to collect flue gases to centralized stacks. In
these cases, "Chiyoda THOROUGHBRED 101" has an
added advantage since the absorption-oxidation section
can be installed separately in one or more places to
pump sulfuric acid to a distant place where it is con-
venient to install a crystallizer to process the by-product
gypsum.
As "Chiyoda THOROUGHBRED 101" can separate the
crystallization section from the absorption-oxidation
section for installation at most any place desired, for
instance, within the premises adjacent to a large thermal
power plant or a large boiler, there poses no special
problem in site selection. The process is a wet de-
sulfurization method with a high sulfur removal rate,
which eliminates the installation of a tall chimney.
130
-------
3. Application to the Energy Industry
Currently, it is u common practice in Japan that a
thermal power station is jointly built adjacent to a
large petroleum refinery. For example, in the Mizu-
shima and Sendai petrochemical complexes, thermal
power stations were jointly constructed to rationalize
utilization of energy.
Since a large amount of fuels is consumed by these
power stations, tremendous savings are ensured, if low
grade fuels such as asphalt can be used.
"Chiyoda THOROUGHBRED 101" ensures thermal
power stations the use of low grade high sulfur fuels
to convert them into electric power without air pollu-
tion problem, resulting in improved national environ-
ment ... national interests.
A large quantity of the by-product gypsum can be
utilized for housing construction materials and many
other purposes as it is harmless to man and his sur-
roundings. Furthermore, as this is a wet type flue gas
desulfurization process, no paniculate from stack is
emitted even where coal is used with heavy fuel oils.
and thus, no duct collector is required.
131
-------
This IOOONm]/h (650 scf.'min) pilot plan! operated continuously for o\cr J!00 days desulfuriring flue gas.
132
-------
Process Description
As shown in the process flow scheme, "Chiyoda
THOROUGHBRED 101" is comprised of three process
steps.
Reactions take place in each step of the process sequ-
ence as follows:
Absorption SO2 + H:O > H2S03
Oxidation H2S03 + JO2 » H,SO,
Crystallization ... H2SO, + CaCO3 + H2O >
CaSO4-2H:O (Solid) + CO. (Gas)
1. Absorption
After being removed of dust and pre-cooled in the
prescrubber, flue gas is led into absorber where SO2
and SO3 contained in the flue gas are absorbed and
removed by dilute sulfuric acid at 50~70°C (120~
I60°F).
Absorption can be carried out in a column. The ab-
sorber can be of any type with simple construction to
meet the purpose.
In H.jSOj of 2—10 wt % concentration, SO2 can only
be soluble to a range of one-third of the solubility to
water, but the dilute sulfuric acid recycled from the
succeeding oxidation section dissolves oxidation catalyst
and O. nearly to the saturation point. Thus, as oxida-
tion reaction can take place in the absorption section
also, recycle rate of three times the water is not
required. In the absorption section, SO2 content in the
exhaust gas cari be held to below 100 ppm, depending
upon the size of the absorber, or flow rate and con-
centration of dilute sulfuric acid.
In the pilot plant test with a six meter (eighteen foot)
high packed column, combustion gas of vacuum residue
containing SO? of 3,000 ppm was absorbed by 3 wt %
sulfuric acid, and it was successful in holding the SO,
content in the exhaust gas to below 50 ppm.
The treated gas passes to the atmosphere at about the
same temperature with dilute sulfuric acid.
The dust collected in the prescrubber can be removed
from the process, if it affects the gypsum quality.
2. Oxidation
Sulfurous acid in the dilute sulfuric acid is completely
oxidized into sulfuric acid. And a part of sulfuric acid
(HoSO4 corresponding to SO2 and SO3 removed from
the flue gas) is passed into the crystallizer to process
gypsum and the remainder is circulated into the ab-
sorber.
In this section is used a special catalyst to accelerate
oxidation. The special catalyst used has been specifically
developed by Chiyoda after continuing research and
development efforts, and has been evaluated most suit-
able for the purpose from the standpoint of catalyst
activity, poison resistibility and cost.
Type and size of the oxidizer vary with the oxidation
agent, absorption velocity, reaction velocity, etc. It is
recommended to use a bubbling column of simple design
which can utilize air as oxidation agent.
Air consumption is about five times the theoretical
requirement.
3. Crystallization
Sulfuric acid sent from the oxidizer is neutralized with
calcium compounds to continuously crystallize and
separate gypsum.
This process allows choice of any of a variety of
calcium compounds, such as natural limestone, quick
lime or calcium oxide, slaked lime, calcium hydroxide
and carbide residue.
Gypsum can be crystallized in varying sizes in the
crystallizer of special design. Crystals thus formed are
continuously separated by centrifuge and water washed
to produce the product gypsum.
The mother liquor and wash water is recycled to the
absorber, thus, there is no effluent water drained out
the whole system.
133
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ABSORPTION
OXIDATION
VENT
t
REHEATER
ABSORBER
FUEL
MAKE-UP WATER
PRESCRUBBER
S02 CONTAINING
GASES
£3
BLOWER
OXIDIZER
SULFURIC ACID TANK
PUMP
PUMP
BLOWER
PUMP
Features of "Chiyoda THOROUGHBRED 101
O Simple Process Flow and Ease of Operation
With simple process flow and plant structure, the process
promises a wide range of operation flexibility.
C Continuously Stable Operation
Unlike conventional wet type flue gas desulfurization
systems, as no slurry is used in the absorption-oxidation
section, there presents no problem of clogging. In ad-
dition, by virtue of its process flexibility, it ensures
reliable continuous operation under a wide range of
fluctuations in load.
C High-efficiency Desulfurization
Approximately 97% of desulfurization can be attained.
In other words, SO, in the stack gas to be emitted can
be held to lOOppm or lower.
O Lower Construction, Operation and
Desulfurization Costs
Because of its simple process, it minimizes the number
of unit operations. Since there is no requirement for
special chemicals and utilities, low running cost is as-
sured, resulting in lower desulfurization costs.
O S02 Removal for Dirty Flue Gases
SO2 can be removed economically even from low grade
fuels such as combustion gases from vacuum residue,
because of stable catalyst performance.
134
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CRYSTALLIZATION
HzSO»+CaCOj+H20-'CaS04 -2H20-f C02
WATER
CENTRIFUGE
CRYSTALLIZER
LIME STONE
\
GYPSUM
PUMP
PUMP
• Dust Removal
No electrostatic precipitator is required since the
soot and other particulates in the flue gas are removed
in the prescrubber and absorption steps.
• No Waste Stream
Since there is no bleed of the solution, there is no
concern of secondary pollution problem.
• By-Product Gypsum
Gypsum is a highly stable chemical compound of sulfur.
and is harmless when stocked. There can be found
versatile applications in place of natural gypsum. In
Japan, since there is a lack of natural resource of
gypsum, the by-product can be used as Portland cement
retarder, gypsum boards and so on.
In addition, dilute sulfuric acid can be used as a pickling
solution in steel mills, and can be sent to waste water
treatment facilities to neutralize alkaline substances in
chemical and petroleum industries.
• Flexible Combination of Process Steps
Since the absorption-oxidation section can be separately
installed from the crystallization section, dilute sulfuric
acid processed can be pumped through pipeline to a
centralized crystallization section located in an adjacent
gypsum board plant or cement plant.
135
-------
Investment and Utility Summary (Boiler Fine Gas Cases)
"Chiyoda THOROUGHBRED 101"
Flue Gas Desulfurization Process
ITEM
Design Conditions
i
By-prodiicl
Plant Cost (A)
Fixed Cost (B)
Direct Cost (C)
Net Operating Cost (D)
Overhead (E)
Operation Cost (F)
By-product Credit
Cost of Desulfurization
Required Area
DESCRIPTION
Flue Gas
Power Generating Capacity
SOj Content in Flue Gas
Flue Gas Temperature
Desulfurization Rale
Service Factor of Boiler
Fuel Oil Consumption in Boiler
Sulfur Content in Fuel Oil
Gypsum (CaSO.-2H,0)
18% of (A)
Limestone Powder $5.50/T (0.25C/lb)
Electricity 0.7C/KWH
Industrial Water 2C/T (SC/lOOOgal)
Re-heat Fuel Oil S20/K1 (3.18$/barrel)
Catalyst
Labor $ 12, 000/Year/capi ta
Maintenance 2% of (A)
Sub-Total
(B) + (C)
12% of (C)
(D) + (E)
$5.50/T(0.25C/lb)
Without By-product Credit
With By-product Credit
Include 7 days Storage Area
UNIT QUANTITY
NmJ/hr (scf/nin.) 750,000 (441,400)
MW ! 250 '
p.p.m
£ (T)
2,400,000 (1,
800
1,500 1,500
140 (284) , 140
% \ More than 90
%
Kl/year (barrel/year)
%
ton/hr (bb/hr)
$/year
$/year
>>
>/
t
'/
*
f
*
$/year
'/
b
$/K) ($/bbl)
S/MWH
$/ra ($/bbi)
S/MWH
m1 (1000ft1)
90
482,000 (3,032,000)
2.7
7.8 (17,200)
4,970,000
894,600
202,400
263,200
8,000
241,000
6,000
96,000
99,400
916,000
1,810,600
109,900
1,920,500
343,200
3.98 (0.63)
0.96
3.27 (0.52)
0.79
3,600 (38.7)
More than 90
90
1,540,000 (9,
2.7
25.1
413,000)
(284)
687,000)
(55,350)
11,850,000
2, 133,000
642,400
812,000
22,400
770,000
19,000
144,000
237,000
2.646,800
4,779,800
317,600
5,097,400
1, 104,400
3.31
0.80
2.59
0.62
11,500
(0.53)
(0.41)
(123.7)
Notes : The plant cost (A) is based on the Japanese cost.
Unit cost in U. S. A. is used in column (C).
(US $1.00= ¥308)
136
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX M - INSTITUT FRANCAIS DU PETROLE INFORMATION
137
-------
February 24. 1*72
Mr. Robert Outriau
Instltut Francois du Petrole
90 Park Avenue
New York, New York 10016
Subject: Claua tail Gas Treatment
Dear Mr. Dutriau:
Several of tbe methods being considered for abatement of sulfur ami as ion
to the atmosphere include Claua sulfur uuits. The Environmental Protection
Agency Office of Air Programs has engaged Processes Research, Inc., to
gather information regarding the efficacy of Claus sulfur plants in pollu-
tion abatement (Contract Ho. 68-02-0242).
Proa the May 1971 issue of Uydrocarbon Processing we understand that your
company has developed a process for removing sulfur from Claus tall gases.
Please let ua have additional information available regarding the Inatitut
Francais du Petrole Tail Gas Sulfur Recovery Process, as follows (tail gas
treatment units having daily sulfur capacities of 1 ton, 10 tons.and 100
tons, for Claua tail gas feed concentrations of 0.3 «ole percent, 1.0 mole
percent, and 4.0 »ole percent of H2S + S02 are of particular interest):
1. ConfIra approxiaate investment, royalty, catalyst costs, solvent costs,
and consumption of water, power and atean for LIT units having various
daily sulfur capacities and various Claus tall gas feed concentrations
*f h2S + SO2-
2. Operator attendance and aaintenance requirements.
2. Conflrn percentage sulfur recoveries for various Claus tail gas con-
centrations of H2S + SOj.
4. What is the pressure drop of the gaa through the IPP unit?
5. Is the quality of the sulfur recovered by the IFP process equal to
that of Clausssulfur?
6. What, if any. air pollution is presented by entrainaent of catalyst
and solvent overhead froa the packed tower? Is Incineration advisable?
7. A principal cause of poor sulfur recovery in Claua plants is deviation
froa the optiaua feed ratio of air to H2S, resulting froa inadequate
138
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Mr. Kobert Dutriau
February 24, 1972
2
instrumentation or careleea operation. This alao resulCfl la daviatioae
from tUe etoicfeioMtric balance of U ,3 and 30 2 in the tail §*». There-
fore tne tail gnats froa Clan* anitft having tb* gr«at*«t nead for
pollution abat«H*iit ar« llk«ly to cotitalo oabalancad and arratlc
quantities of Hy5 awl &°2' x* lfc f««*ibla to uc« SIMM of tha acid gait
fron upatraaei of tita Claua unit to nutintaio tba ratio of U2S to S02
required by the IP? pr*e«aaT
6. Tha COS and C$2 typical of Claua tail gaa is umlar stood not rauoved by
tha IFF proceaa. Do you bav« otb«r naaa* of r«»onritig tbaa«?
9. Tha IF1» procaa* ia uadoratooa to ba «ff«ctiva ia placa of tba aacond and
third Claoa atagaa. 1» tharo baai* for tbe IFF procaaa raplaciae the
Claua wait altogatbar?
We will appreciate rac«iviog all Che above infomatioa which you can make
Available to u«. Plaaaa lat ua Iwov trtien we nay expect to receive it.
We chant you for your cooperation.
Very truly yours,
PROCESSES HZSBARQi, INC.
a. D. Beere
Project Manager
WUli.fJ
ec: U. 3.
d. &. Jester
P. V. Spaite
139
-------
r
Mr. W. D. Beers
Project Manager
Processes Research, Inc.
2912 Vernon Place
Cincinnati, Ohio 45219
~l
March 17, 1972
CR 1 P08 00
Institut
Francais
du
Parole
North
American
Office
Dear Mr. Beers:
In reply to your letter dated February 24th 1972, I.F.P. is
pleased to provide you with non confidential information on the I.F.P.
Glaus tail gas clean up process. We understand that this information
will be used for your study on pollution abatement from Glaus plants
for E. P. A. office of Air Programs.
contains:
I am sending you attached a document on our process which
- a process description and flow diagram
- reaction mechanism
- operating parameters
- typical economics for a plant tied with 30 and 140 T/D
Glaus plants.
- list of industrial references
Besides our demonstration operation with Delta Engineering in Canada
during the summer of 1971, I.F.P. now has 6 months of successful op-
erating experience in the first Japanese unit. 3 more units will
start in Japan in April 1972 and one in Canada in July 1972.
In addition I have attached typical economics for our I.F.P.
plants tied with a 100, 300 and 1500 T/D Glaus plant, at different
levels of l^S -r 502 contens in tne tail gas.
I will answer the questions as they are listed in your letter:
Q 1 - See attached document. Paid up royalty figures are of the order
of 10-20% of erected cost.
Q-2 - The process is very simple to operate and does not require any
additional labor, above operators.attending the Claus plant. Main-
tenance can be estimated at 2% of erected cost per year.
90 Park Avenue
New York, N.Y. 10016
Telephone (212)986.3391
Telex IFPNY / 620060
140
-------
Q 3 - See attached document
Q 4 - Pressure drop is low and tail gas pressure is generally well above
I.F.P. requirements.
Q 5 - Sulfur produced by I.F.P. process is pure and can be blended with
sulfur produced by Claus plant. A typical analysis of I.F.P. sulfur
is:
ashes 100 ppm
carbon 100 ppm
S 99.5 minimum (wt%)
Q 6 - The treated gas from I.F.P. plant is meant to be incinerated before
sending it to the stack. The purpose of this incineration is to burn
the remaining sulfur compounds (H2S, COS, CS2> into S02. Solvent and
catalyst show a very low volatilaty at operating temperature. Never-
theless small quantities are carried over with the treated gas and completely
burn in the incinerator without creating any pollution problem.
Q 7 - The question of H2S/S02 control is covered in the attached document. The
basic I.F.P. design includes a bypass of small amount of acid gas in order
to control to some extent the ratio. This is considered as a safety
device in case of the close loop control on the Claus plant is out of
service.
Q 8 - COS and CS2 are inert in our process as stated in the attached document.
Nevertheless means exist to get rid of most of COS and CS2 in the Claus
plant. This is achieved by the use of specific catalyst at higher temp-
erature in the 1st stage which destroy COS and CS2 by hydrolysis.
Q 9 - The I.F.P. process can replace the second and/or third catalytic stage.
It does not replace the first stage, for the reason shown above (COS & CS2).
I hope this information will be useful for your preliminary evaluation
of I.F.P. process.
Do not hesitate if you have any question to contact me in New York.
I.F.P. is interested to get a copy of your final study. Kindly let me know
whether this is possible.
Looking forward to hearing from you, I remain,
Yours very truly,
R. Dutriau
Sales Engineer
North American Office
RD:cs
encls.
141
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THE IFP PROCESS FOR CLEANING UP CLAUS TAIL CAS
The IFP process for cleaning up
Claus plant tail gas offers natural
gas processors the chance to
boost overall sulfur recoveries to
99% levels. The IFP process is al-
ready being used in one Canadian
and one Japanese plant. Actual
performance meets design crite-
ria. Four other plants utilizing the
process are under construction.
Process description and
reaction mechanism
The basic reaction of the IFP process is
the same as that in the Claus unit itself:
2H2S
3S + 2H20
The reaction is carried out in a catalyst-
containing solvent. The first step of the
reaction mechanism is that the H2S
and S02 dissolve in the solvent, the
extent to which the gases dissolve
naturally being a function of their par-
ticular pressures. Then the catalyst
combines chemically with the SO2, H2S
and sulfur to yield an active complex.
This complex in turn reacts with addi-
tional feed H,S and S02 to produce
elemental sulfur according to the reac-
tion noted, constantly regenerating the
active complex itself.
During the initial phase of the reaction,
product sulfur dissolves in the solvent
until the saturation point for the given
temperature is reached. Thereafter sul-
fur is continuously separated from the
reaction mixture, and the reaction is
pushed to the right. Lower tempera-
tures also favor sulfur production, but
they must not be low enough to permit
condensation of water, or solidification
of the sulfur which would cause plug-
ging. Optimum temperature range is
230-320°F.
Advantages off the
IFP solvent/catalyst system
a) high catalyst activity
b) good chemical and thermal stability
of both solvent and catalyst
c) minimum volatilization losses of sol-
vent due to low vapor pressure
d) maximum gas/liquid contact, with
no foam formation, because of good
physical properties of solvent
e) ease of product separation due to
low solubility of sulfur in solvent,
and large difference in density
f) maximum product purity due to low
solubility of solvent in sulfur
g) ready commercial availability and
low cost of both solvent and catalyst
142
-------
FLOW tCHIMI OF IPP PROdtt
tail gas from
Clous plant
treated gas to
incinerator
• steam condtntaia
liquid
sulfur
The IFP process is exceptionally simple
and requires only a few pieces of
equipment. Glaus tail gas at about
260"F is injected into the lower part
of a packed column. The tower is
designed for low pressure drop. One
or more packed beds with redistribu-
tion are employed, depending on
capacity. Product sulfur accumulates
in a boot at the bottom of the tower
and is continuously decanted under
interface control.
The catalyst-containing solvent is cir-
culated continuously from bottom to
top of the tower to maximize liquid/
gas contact by counter-current flow.
Liquid temperature is maintained at
260-280°F. the heat of reaction being
removed by vaporization of conden-
sate injected into the solvent pump-
around loop just prior to entering the
top of the tower. Circulation is regu-
lated to give optimum wetted packing
surface in the tower.
Solvent degradation has not been found
to occur, but some is lost in the over-
head by evaporation even though vapor
pressure is |ow at reactor temperatures.
(These minute quantities of solvent are
completely burned in the incinerator
and cause no pollution problems.) No
solvent is lost through entrainment.
Losses are made up by replacement
from a storage tank heated by a steam
coil. The capacity of the storage tank
may be as large as the total column
and pump-around loop capacity.
Catalyst is also made up from a stor-
age tank equipped with a mixer which
holds a day's charge. Metering pumps
are used to hold catalyst concentra-
tion constant and to compensate for
losses in solvent. The heat exchanger
shown in the circulation loop is used
for start-up to raise the solvent to reac-
tion temperature.
It is noteworthy that no buildup of water
occurs. Since the solvent itself is not
corrosive, construction is thus entirely
of carbon steel, and plant investment
is low.
143
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PROCESS VARIABLES
total MiHwr concentrcrtlon
In Clous gas
Conversions (S02 + H2S —» S) to be
expected in the IFF process will depend
on the total H2S + S02 concentration
in the Claus tail gas:
Typical
H2S + S02. Vol % conversion, %*
0.4 - 0.8
>0.8
80
90
•In addition, the IFF process recovers 100% of
free,sulfur — both vapor and entrained droplets.
HaS/SOa ratio
From an operating viewpoint, only the
ratio of H2S to S02 affects conversion
rates. The ratio should be held between
2.0 and 2.4 if conversion is to be maxi-
mum. This should present no difficulty
in modern gas processing practice:
even though feeds to the Claus unit
may fluctuate widely in both flow rate
and composition, in-line gas chroma-
tographic or UV speclrophotometric
monitors can be used to regulate the
H2S/S02 ratio in the Claus tail gas ± 5%.
Controlling the ratio not only maxi-
mizes sulfur recovery in the IFF unit,
but it also keeps sulfur recovery at the
highest level in the Claus plant itself.
COS and CSi content
The only other process variable that
can affect sulfur recovery adversely is
the concentration of COS and CS2 in
the feed to the IFP unit. Even though
significant amounts of these com-
pounds are formed in the Claus burner,
the first Claus catalytic reactor can
bring levels of COS and CS2 well under
1000-1500 ppm. The level remains
essentially unchanged in the second
and third stages, and is unchanged in
the IFP unit, as the IFP process does
not touch COS and CS2.
The first Claus reactor should be run
hotter than usual to keep COS and CS2
at a minimum. Bauxite can also be
replaced with a more sophisticated
catalyst. The slightly lower conversion
encountered when running the first
reactor hotter will be more than offset
by the higher sulfur recovery in the
IFP unit.
Summary
Holding the H2S/S02 ratio in the range
2.0-2.4, and running the Claus plant
to keep COS and CS2 down, can pro-
vide overall sulfur conversions of more
than 99.0% for the combined Claus-
IFP system. This is equivalent to stack
S02 emissions of about 1500 ppm
after incineration.
144
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TYPICAL ECONOMICS OF IFP PROCIft
Two-stage sulfur unit, T/day
Recovery in IFP process, %
Overall recovery, % (2-stage Claus plus IFP)
HjS + SO, in tail gas, % Vol (wet basis)
Total tail gas throughput, Ib-moles/hr (wet basis)
IFP unit battery limits investment, US$ (engineering excluded)
Initial load of solvent and catalyst, US$
Chemicals consumption, US $/hr (solvent plus catalyst)
Power, KW
30
85
99
1.5
400
140,000
5100
1.00
30
140
85
99
1.5
1800
400,000
24,000
3.40
60
IFP CLAUS TAIL CAS CLEANUP PLANTS OPERATING AND UNPER CONSTRUCTION
Start-up Throughput, Sulfur
Plant owner Location Purpose date MMSCFD (design) recovery (design)
Delta Engineering
Corporation
Nippon Petroleum
Refining Company
Idemitsu Oil Company
Lone Pine,
Alberta
Negishi,
Japan
Japan
Demonstration
Cleaning tail gas
from 3-stage
Claus plant
ditto
July '71*
Sept. '71«
April '72
0.8
26
22
80-85
85
85
Kyokutoh Oil Company Japan
ditto
April '72
16
90
Showa Oil Company
Japan
ditto
April '72
4.2
85
Confidential
Canada
ditto
July '72
22
'Both the Lone Pine ano the Negishi plants are operating smoothly since start-up at design or
better levels. See the article in OILWEEK 22. No. 32, 19-24 (September 27, 1971) lor full infor-
mation on the Lone Pine plant.
For more information on the IFP process fnr cleaning up Claus plant tail gas,
contact IFP's North American office at 90 Park Ave., New York, New York 10016.
Telephone (212) 986-3391.
Primed in U.S.A.
IFP153L712CI72
65
145
-------
! 01=. '±
I.F.I'. SULFUR RECOVERY PROCESS
PRELIMINARY EVALUATION DATA
Performances of I.F.P. plant - 85% of H?S -r S02is converted into S
- 100% of free sulfur is recovered
Sulfur unit, T/day
•
Recovery Ln I.F.P. process, %
HITS 4. «;O'i<>
H2S -r S02 in tail gas, % Vol
(wet basis)
l.F.P. unit battery limits invest-
ment, US$ (engineering excluded)
F.iiLtlal load of solvent & Catalyst
US$
Chemicals consumption, US$/hr
(solvent plua catalyst)
Power, KW
.100
85
0.6
340,000
17,500
1.6
30
100
85
1
320,000
12,500
1.6
30
' 100
85
4
280,000
10,000
1.7
30
146
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I.F.P. SULFUR RECOVERY PROCESS
PRELIMINARY EVALUATION DATA
Performances of I.F.P. plant - 85% of HoS -r S02is converted into S
- 100% of free sulfur is recovered
Sulfur i-.nlt, T/day 300 300
Recovery in I.F.P. process, 7. 85 85
Jt_
II2S •» S02 in tail gas, % Vol 0.6
(wet basis)
I.F.P. unit battery limits Invest- 700,000 670,0.00
nxMit , US$ (engineering excluded)
f.;iLt.l..-il load of solvent & Catalyst 40,000 37,000
• us$ ' '
Chemicals consumption, US$/hr 4.3 4.2
(solvent plus catalyst)
Pov.-er, KW 80 80
147
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I. P.P. SULFUR RECOVERY PROCESS
PRELIMINARY EVALUATION DATA
Performances of I.P.P. plant - 85% of I^S * SC^is converted into S
- 100% of free sulfur is recovered
Sulfur iMi.it, T/day 1500 1500
Recovery in I.F.P. process, % 85 85
H2S -r S02 in tail gas, % Vol 0.6 1
(wet basis)
I.P.P. unit battery limits invest- 3,300,000 3.000,000
menu, US$ (engineering excluded)
r.uUlal load of solvent & Catalyst 200,000 180,000
Chemicals consumption, US$/hr 21.2 20,3
(ijulvent plus catalyst)
Power, KW 390 390
148
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FILL OUT AND RETURN TO IFP FOR BUDGET QUOTATION
1. COMPANY
2. PLANT LOCATION.
3. CLAUS PLANT CAPACITY_
6. ENGINEERED BY
_LT/D SULFUR
4. YEAR BUILT
_5. YEAR STARTED UP
7. ACID GAS THROUGHPUT
9. ACID GAS ANALYSIS (VOL. %) H,S_
10. TYPE OF CATALYST
11. RECOVERY: DESIGN
MMSCFDl 8. NUMBER OF STAGES
I CO, | H,Q | C,.C,_
ACTUAL
12. PROCESS CONTROL (SPECIFY GC. UV, OTHER).
13. VARIATION OF H.S/SO, RATIO
CLOSED LOOP CONTROL (YES OR N0)_
TO.
14. TAIL GAS THROUGHPUT.
MMSCFDl (5)
CAN BE COOLED . Of| is. MAXIMUM ALLOWABLE PRESSURE OROP RFTWFFN Cl AUS UNIT AND INCINFRATOR PSI
17. TAIL GAS ANALYSIS FROM 1st REACTOR
Ib-mol/hr vol %
H,S
SO,
s
S.
s,
s,
cos
cs,
N.
w,n
CO,
0,
H:
rn
c,,c,
Trvrai
FROM 2nd REACTOR
Ib-mol/hr vol %
FROM 3ni REACTOR
Ib-mol/hr vol %
18. DUTY FOR IFP PROCESS (SPECIFY ONE):
CONVERSION % (FROM H,S + SO, IN TAIL GAS)
DECREASE IN STACK SO, FROM PPM TO PPM
INCREASE IN OVERALL RECOVERY FROM % T0_
DECREASE IN STACK SO, FROM LT/D TO
LT/D
19. YOUR NAME.
20. TITLE
21. COMPANY.
22. ADDRESS.
23. CITY
STATE
.ZIP.
24. TELEPHONE (AREA CODE.
EXTENSION.
RETURN THIS COMPLETED QUESTIONNAIRE TO IFP, 90 PARK AVE., NEW YORK, N.Y. 10016 • TEL: (212) 986-3391
Printed In U.S.A. IFP154L712C172
149
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX N - WELLMAN-POWER GAS INFORMATION
150
-------
TRIP TO JAPAN, DECEMBER 2-12, 1971
DETAILED REPORT
BY
Sheldon Meyers, Control Systems Division
John DeKany, Control Systems Division
Gary Rochelle, Control Systems Division
February 1, 1972
151
-------
and manganese processes.
WELLMAM-POWER GAS LICENSEES
We visited two operating Wellman-Lord units in Japan and discussed the
process with operating personnel and design engineers. The processes are
summarized in the tables below. Additional descriptive material on the units
and the process in general is in'Appendices 11.0. The units have been in
operation since August 1971. Performance is generally satisfactory. Problems
are summarized in the following sections.
Location
Operating Wellman-Lord Units
User Engineers
Application
Kawasaki, Japan
Chiba, Japan
Paulsboro, N. J.
Capacity Data
Toa Nenryo Kogyo
Japan Synthetic
Rubber
Olin Matheson
Sumitomo Chem. Eng.
Mitsubishi Heavy
Machinery Mfg.
Wellman-Power Gas
Claus plant
Oil-fired boiler
Acid plant
Kawasaki
Chiba
Paulsboro
Hypothetical 100 MW
Gas rate
SCFM
43,000
128,000
45,000
177,000
S0~ rate
C/7hr.
3300
2650
2500
5000
S02 concentration (ppm)
In Out
6500
2000
5000
2700
50
200
200
200
Purge - Degradation of the absorbent is similar to that observed at Paulsboro.
At both Japanese plants the required makeup rate is about 0.45 moles NaOH/mole
S02 removed. At JSR oxidation and disproportionation contribute equally to
sulfate formation. At Toa Nenryo disproportionation produces twice as much
sulfate as oxidation. Overall degradation at both units is 3 to 5% of the
sulfur removed. Process improvements to eliminate disproportionation and reduce
oxidation should reduce makeup to" 0.10 moles NaOH/mole S02.
Mother liquor purged from the evaporator is used in the prescrubber, then
treated with sulfuric acid and stripped with air to remove SO- and reduce COD.
The solution sent to sewer is essentially sodium sulfate. Only 10 to 20% of the
dissolved solids in the untreated mother liquor are sulfate or thiosulfate, the
rest being sulfite and bisulfite. Even though degradation is only 3 to 5% of the
sulfur removed, 15 to 30% of the sulfur is purged as sodium sulfate. MKK is
piloting an alternate scheme of reducing COD-by disproportionation of the waste
solution at elevated temperature.
152
-------
Oxidation - Both plants use scrubbers with two stages of SCL absorption and a
prescrubber. Each stage consists of two sieve trays and a recirculation system.
Toa Nenryo also uses a quench spray tower followed by a gas cooler before the
prescrubber. The stack gas at both units contains about 5% 0_. JSR has 200 ppra
NO into the scrubber and 160 ppm out. At both units sulfate formation from
oxidation has been about 1 kg/100 Nm^O-.
Both licensees operated small pilot plants (600 SCFM). Mitsubishi observed
oxidation of 0.8 - 1.3 kg Na2SO/f/100 NnrO™. In a packed column Sumitomo observed
oxidation of 3.0 kg without inhibitor, 1.3 kg with. Both licensees found that
the rate of oxidation was directly proportional to oxygen concentration.
The oxidation inhibitor developed by Sumitomo was tested by Welltnan-Power
Gas at Paulsboro. It reduced oxidation 50 to 80%. The inhibitor has been used
continuously at Toa Nenryo, so there is no firm evidence of its effectiveness
in that application. Information received after the trip indicated that the
inhibitor is EDTA (ethylenediarainetetracetic acid).
Disproportionation - There are two evaporator vessels at each plant, designed
to permit double effect of steam. However, at half-load conditions only one
evaporator is being used, operating near atmospheric pressure. The evaporators
are designed for a residence time of 3'hours with respect to feed liquor. The
amount of disproportionation should increase rapidly with temperature and
proportionately with residence time. Both Japanese users are installing vacuum
equipment to permit operation of the evaporators at lower temperature, thereby
eliminating disproportionation. There have been.no serious maintenance problems
with blowers presently used to transport the SO™ product.
Ash Removal - The JSR plant was not initially equipped to remove oil ash from
the evaporator-absorber cycle. Ash entrained from the prescrubber accumulated
and eventually caused minor plugging in the closed cycle. A semi-continuous
vertical centrifuge has been installed to remove particulates from the scrubber
effluent. It appears to have alleviated the problem.
Acid - The acid plant at JSR uses 100% excess air but is still significantly
smaller than a plant to produce acid from S. Gas flow is about half that
required for a conventional plant. Maximum gas temperature is 600°C.
Operations - JSR uses two operators. Toa Nenryo is on closed loop control by
the refinery computer.
Glaus Plant Alternatives - Toa Nenryo also considered use of the Beavon and
IFF processes. Beavon is more expensive and IFF has technical problems.
Commercial Arrangements - The JSR plant was built by funds from MKK and the
Japan Development Bank at a cost of 800 million yen ($2.4 million). MITI
arranged and guaranteed the low-intece,st loan. JSR will buy the plant after
satisfactory operation for a year.
153
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SUMITOMO CHEMICAL ENGINEERING COMPANY, LTD. 11.5
THE WELLMAN-LORD SOo RECOVERY PROCESS
' NOVEMBER'; 1971
SUMITOMO CHEMICAL ENGINEERING CO,', LTD,
ISA
-------
I. Development and Improvement in Japan
II. Commercial Application:—Toa Nenryo Plant
This represents a brief outline of the development and
Improvement for the WeHman-Lord S02 Recovery process
made by our company and it's commercial application to
toa Nenryo Plant.
155
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t. Development and Improvement in Japan
The environmental problems we have here in Japan are probably similar
to those of the America. In recent years, the public opinion against
pollution-air, waters, dusts, etc. has been increasingly widespread,
centering on petro-chemical combinat and heavy industries crov/ded areas,
such as areas of Kawasaki, Chiba, Sakai and so on. The emphasis given
to industrial growth in the past thinking has been shifted to human
health, safety and well-being for environmental protection. The enforce-
ment by laws has been gradually prepared for pollution control;
the comprehensive pollution control laws were passed in the Diet
last December, transferring broad powers to local governments to regulate
pollutants emissions from worlds or factories. The laws:»ks enacted on
July 1st this year, giving one* year or one year and half grace period,
depending on local conditions. With this respect to the air pollution
control, the permissible emission level of S02 from stacks has become
severe year after year and therefore industries have realized the necessity
of the S02 recovery process to direct their efforts towards it in order
to meet local requirements. As one of the approaches to the SOg abatement
process, a dry system was at first taken up. as a pilot plant, jointly
by the Government and power companies, chiefly in consideration of exit
gas diffusion. And two processes were selected; one is the activated
carbon process by Tokyo Power Co. and another DAP -Mn process by Chubu
Power Co. and another activated carbon process was used by Kansai Power
Co. later.
But these prospects are all said to be not so promising from past ex-
periences. Some observe that a number of hitches still remain before
the plant can be put to commercial use.
These capacities now are:
Tokyo Power Co.
Chubu Power Co.
Kansai Pov/er Co.
420,000 MM /H (on stream early next year)
326,500 " ( " )
175,000 " ( completed in September this year
and at present test run continues)
156
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SUMITOMO CHEMICAL ENGINEERING COMPANY, LTD.
We, Sumitomo Chemical Engineering Co.\ richly expeirenced in the sulfuric
add plant, taking notice of this potential trend towards air pollution
control, introduced the SC^ recovery process from the Wellman-Power Gas
Corp. (then Wellman-Lord) jointly with Mitsubishi Kakoki Company two
years ago for the following reasons:
1. The Wellman-Lord process is a wet regenerative system requiring
less plant area, less capital cost, compaired to the dry system.
2.. The end product from the process is pure gaseous or liquid S02,
which can be used as raw material for the sulfuric acid or elemental
sulfur.
3. The Wellman-Lord process is able to recover at least 90% of S02
from stack gases, in excess of 97% of any $03 and add mist,
«
and about 902 of fly ash.
4. It 1s widely adaptable for use to power plants, chemical industries,
oil refineries and others. *
The Wellman-Power Gas, from the very beginning of the pilot plant instal-
lation to the Olin's commercial plant through the Baltimore demonstration
plant, has proceeded with extensive works to obtain the process reliabili-
ty, both technically and economically. On the other hand, Sumitomo began
activities by installing a pilot plant of 1,000 NM3/H_at Niihama just
after Introduction of the Wellman-Lord process. The objectives of the
pilot plant were:
1. To further investigate and corroborate the Wellmna-Lordls laboratory
and pilot plant data, especially in the points of S0£ removal,
reduction of chemical make up requirements by purge treatment and
antloxidant.-
2. To refine the process design', thereby further improving the process.
3. To obtain the mechanical reliability of the equipment and machinery.
157
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SUMITOMO CHEMICAL EN6INEERIN6 COMPANY, LTD.
The Niihama pilot plant was operated for the duration of about a year
and half, first using the potassium system and then the sodium system.
And also the plant treated gases from the sulfuric acid tail gases to
oil fired boiler using the high concentrated sulfur of 5%. Thus, the
extensive test programs were conducted and the pertinent data the plant
could give were all collected, The results on basic process chemistry
proved to be encouraging and satisfactory. The research and development
tests thus carried out by us led to the .award of the contract by Toa
Nenryo Company for the first Well man-Lord S02 recovery plant last July.
-II. Commercial Application"!!. Toa Nenryo Plant
Toa Nenryo Company, one of the leading oil company 1n Japan and incorporat-
ed with Esso and Mobil of the U.S.A. with each 25« shareholder, installed
the sulfur recovery plant (Claus unit) as part of the indirect desulfuriza-
tlon plant at Kawasaki, Kanagawa Prefecture. The Kawasaki area is under
the severest regulation for pollution control-because of heavy industries
covering oil refineries and Iron steel densely congested and the stack '.
height is limited as low as 50 meters or so because the Haneda air port is
located in the close neighborhood of the Kawasaki area.
In such a circumstance, Toa Nenryo made the extensive, study of the $02
recovery process to treat tail gases from the sulfur recovery plant and
finally selected the Wellman-Lord process as the most suitable and advanced
technology after evaluation of the process effectiveness. They appreciated
the Sumitomo efforts to conduct tests by the Niihama pilot plant and finally
gave us an award to proceed with designing, engineering and construction of
the plant as a general contractor last July, based on the Well man-Lord basic
design. The process is a sodium based absorption which will recover the
S02 for re-use 1n the sulfur'recovery plant. The plant v/as completed early
July this year as expected but the plant start-up was delayed more than a
month because Toa Nenryo decided on consideration that the Japanese market
surrounding the oil products was so badly depressed.
158
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SUMITOMO CHEMICAL ENGINEERING COMPANY, LTD.
But the plant now 1s operating successfully absorbing $03 In excess of
the original design specifications and this is the first commercial
Installation of the Wellman-Lord's $02 recovery process in Japan and
further constitutes a milestone to the air pollution control.
The outlines of the Toa Nenryo plant are as follows:
Basic design conditions
Gas volume: 67,200 NM3/H
S02 concentration: 7,600 PPM
Temperature: 538°C
Pressure: 20 mm H£0
End product of S02: Max. 200 PPM
The process itself is principally the Well man-Lord process except the
pretreatment of gases. (The process flow 1s given on the attached sheet
for reference.)
It 1s, first,necessary to cool down the gases of hfgh temperature.
The gases containing rich S02 and other components are led into the
waste heat boiler where steam is generated to be available for use
and then Introduced into the spray tower by the blower to be cooled
down with water spray. The cooled-down gases are sent to the pre-
scrubber at the absorber bottom at an appropriate temperature by way
of the Indirect gas cooler. Following the absorber section to the
S02 cooler through the chemical section, the main stream is as covered
by the Wellman-Lord process. Here, we present you some characteristics
with the Toa Nenryo plant:
1. S02 emission at tfie absorber top.
70~150 PPM (Inlet S02 6.000PPM)
2. The absorber is of sieve tray type.
3. End product of S02 is returned to the sulfur recovery plant.
4.*Antioxidant developed by Sumitomo Chemical Co. is used to
inhibit the sulfate formation, thereby reducing chemical
requirement.
159
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5. Materials
Rubber lining or FRP used where temperature is relatively
low. Stainless steal used where temperature is relatively
high or corrosion may occur.
The plant started up mid-August after a month postponement as aforesaid
and up to date it shutdowned twice, the first due to the failure af the
gas duct from the absorber to the central stack and the second the sewer
system. We experienced some mdnor mechanical problems with it but we
have cleared them up through a joint effort with Wellman-Power Gas and
the client.
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX 0 - BIBLIOGRAPHY
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX 0 - BIBLIOGRAPHY
1. October 1950 Industrial and Engineering Chemistry Vol. 42 No. 10
pages 1938-1950 "Sulfur From Sour Gases" by Frederick G. Sawyer, Rodney N.
Hader, L. Kermit Herndon and Eugene Morningstar.
2. November 1950 Industrial and Engineering Chemistry Vol. 42 No. 11
pages 2258-2268 "Recovery of Sulfur Compounds from Atmospheric Contaminants"
by Morris Katz and R. J. Cole.
3. November 1950 Industrial and Engineering Chemistry Vol. 42 No. 11
pages 2277-2287 "Recovery of Sulfur From Synthesis Gas" by A. E. Sands and
L. D. Schmidt.
4. April 1953 Chemical Engineering Progress Vol. 49 No. 4 pages 203-215
"Sulfur from Hydrogen Sulfide" by B. W. Gamson and R. H. Elkins.
5. April 1953 The Petroleum Engineer pages C-19 to C-24 "Sulfur Recovery
Practices In Oil Industry" by R. A. Graff.
6. April 1, 1963 Chemical Engineering Vol. 60 No. 4 pages 38 and 40 "Plant
Recovers Sulfur From Lean Acid Gas."
7. March 1964 Hydrocarbon Processing & Petroleum Refiner Vol. 43 No. 3
pages 104-108 "New Look At Sulfur Plants, Part 1: Design" by A. R. Valdes.
8. April 1964 Hydrocarbon Processing & Petroleum Refiner Vol. 43 No. 4
pages 122-124 "New Look At Sulfur Plants, Part 2: Operations" by A. R. Valdes.
9. September 1965 Chemical Engineering Progress Vol. 61 No. 9 pages 70-73
"Package Plants For Sulfur Recovery" by Howard Grekel, L. V. Kunkel and
R. L. McGalliard.
10. April 15, 1968 Evaluation of Fluid Bed Contactor and Glaus Sulfur Recovery
for Application to Alkalized Alumina Process Final Report prepared for
National Center for Air Pollution Control U. S. Public Health Service by
A. M. Kinney, Inc.
11. May 1968 Engineering and Mining Journal Vol. 169 No. 5 pages 63-72 "Sulphur,
Part One: The Economics of New Recovery Systems."
12. June 1968 Engineering and Mining Journal Vol. 169 No. 6 pages 91-100
"Sulphur, Part Two: Pollution Control and By-Product Sulphur Too."
13. July 1968 Engineering and Mining Journal Vol. 169 No. 7 pages 69-76
"Sulphur, Part Three: Route to Sulphur Via Volcanics and Gypsum."
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INDUSTRIAL PLANNING AND RESEARCH
14. August 1968 Engineering and Mining Journal Vol. 169 No. 8 pages 59-66
"Sulphur, Part Four: A Hidden Asset In Smelter Gases."
15. September 1968 Hydrocarbon Processing Vol. 47 No. 9 pages 248-252 "Today's
Sulfur Recovery Processes" by B. Gene Goar.
16. October 1968 Engineering and Mining Journal Vol. 169 No. 10 pages 85-92
"Sulphur, Part Five: Harvesting Sulphur From Sour Gas and Oil."
17. October 1968 Hydrocarbon Processing Vol. 47 No. 10 pages CR9-CR28 "HPI
Construction Boxscore, Hydrocarbon Processing Plants, United States."
18. October 28, 1968 The Oil and Gas Journal Vol. 66 No. 43 pages 88-101 "Why
Recover Sulfur From H2S?" by Howard Grekel, J. W. Palm and J. W. Kilmer.
19. November 1968 Chemical Engineering Progress Vol. 64 No. 11 pages 47-53
"The Sulfur Outlook" by M. C. Manderson.
20. November 1968 Chemical Engineering Progress Vol. 64 No. 11 pages 75-81
"New Source For Sulfur" by B. G. Mandelik and C. U. Pierson.
21. February 1969 Hydrocarbon Processing Vol. 48 No. 2 pages CR8-CR22 "HPI
Construction Boxscore, Hydrocarbon Processing Plants, United States."
22. September 1969 Hydrocarbon Processing Vol. 48 No. 9 pages 179-183 "Gas
Processing In The USSR" by Joseph C. Benedyk.
23. October 1969 Hydrocarbon Processing Vol. 48 No. 10 pages CR13-CR25 "HPI
Construction Boxscore, Hydrocarbon Processing Plants, United States."
24. November 1969 Hydrocarbon Processing Vol. 48 No. 11 page 236 "Sulfur
Recovery, Direct Oxidation Process" by Pan American Petroleum Corp.(Subsidiary
of Standard Oil Company, Indiana).
25. December 1969 Hydrocarbon Processing Vol. 48 No. 12 pages 133 and 134 "Ideas
for Gas Plant Automation" by B. A. Eckerson.
26. February 1970 Hydrocarbon Processing Vol. 49 No. 2 pages CR3-CR16 "HPI
Construction Boxscore, Hydrocarbon Processing Plants, United States."
27. May 11, 1970 The Oil and Gas Journal Vol. 68 No. 19 pages 63-67 "Here's
What's Being Done To Combat Sulfur-Oxide Air Pollution" by Charles B. Barry.
28. August 1970 Engineering and Mining Journal Vol. 171 No. 8 page 136 "A
Process That Would Permit Sulfur Oxides To Be Converted To Elemental Sulfur
For $5 A Ton At The Smelter Instead Of The Present $47 A Ton."
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
29. October 1970 Hydrocarbon Processing Vol. 49 No. 10 page 15 "Process Recovers
99.9% Of Sulfur In Tail Gas."
30. October 1970 Hydrocarbon Processing Vol. 49 No. 10 pages CR5-CR18 "World-
Wide HPI Construction Boxscore, United States."
31. October 5, 1970 Chemical Engineering Vol. 77 No. 21 page 43 "Sulfur Is
Effectively Removed From The Tail Gas of Sulfur-Recovery Plants Themselves."
32. October 5, 1970 Chemical Engineering Vol. 77 No. 21 page 47 "New Pollutant
Removal Processes Announced."
33. December 14, 1970 The Oil and Gas Journal Vol. 68 No. 50 pages 102-112
"Evaluation of Sulfur-Plant Efficiency-A New Stoichiometric Method" by
L. F. Sudduth, S. K. Farmer and H. Grekel.
34. January 5, 1971 U. S. Patent 3.552.927 "Sulfur Recovery Apparatus" by
George M. Franklin, Lorenz V. Kunkel and Willard A. Lewis.
35. February 1971 Chem Tech pages 114-116 "Desulfurize Coal?" by Henry C. Messman.
36. February 1971 Hydrocarbon Processing Vol. 50 No. 2 Section 2 pages 5-13
"World-Wide HPI Construction Boxscore, United States."
37. February 10, 1971 Chemical Week Vol. 109 No. 6 pages 25-36 "Dark Cloud On
Sulfur's Horizon" by John M. Winton.
38. February 26, 1971 Preprint Japan Petroleum Institute "Prevention of Air
Pollution by Refinery Sulfur Plants" by David K. Beavon.
39. April 1971 Journal of the Air Pollution Control Association Vol. 21 No. 4
pages 185-194 "Control of Sulfur Oxide Emissions From Primary Copper, Lead
and Zinc Smelters - A Critical Review" by Konrad T. Semrau.
40. April 1971 Hydrocarbon Processing Vol. 50 No. 4 (NG/SNG Handbook)
page 105 "Giammarco Vetrocoke (H2S)" by The Power Gas Corp. Ltd.
page 112 "Modified Glaus" by BAMAG Verfahrenstecknik GmbH.
page 113 "Molecular Sieves" by Linde Division, Union Carbide Corp.
page 119 "Stretford" by The Ralph M. Parsons Company.
41. May 1971 Hydrocarbon Processing Vol. 50 No. 5 pages 89-91 "Treat Claus Tail
Gas" by Yves Barthel, Yaoudi Bistri, Andre Deschamps, Phillippe Renault,
Jean Claude Simadoux and Robert Dutriau.
42. May 1971 Chemical Engineering Progress Vol. 67 No. 5 pages 69-72 "Reducing
S02 Emmission From Stationary Sources" by T. H. Chilton.
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
A3. June 14, 1971 Chemical Engineering Vol. 78 No. 13 pages 58-62 "Sulfur-
Recovery Processes Compete For Leading Role" by Judith Yulish.
44. June 14, 1971 Chemical Engineering Vol. 78 No. 13 page 151 Advertisement
"Improved Sulfur Recovery Process Reduces Air Pollution" by The Ralph M.
Parsons Company.
45. June 14, 1971 Chemical and Engineering News Vol. 49 No. 24 pages 31 and
32 "Citric Acid Used In S02 Recovery."
46. July 1971 Environmental Science & Technology Vol. 5 No, 7 pages 626-630
"Removal of Sulfur Dioxide From Stack Gases By A Modified Claus Process" by
Robert T. Struck, Metro D. Kulik, and Everett Gorin.
47. July 1971 Engineering and Mining Journal Vol. 172 No. 7 pages 61-71 "S02
Laws Force U.S. Copper Smelters Into Industrial Russian Roulette" by
Lane White.
48. July 5, 1971 The Oil and Gas Journal Vol. 69 No. 27 page 106 "Dallas Firm
Offers New Sulfur Process."
49. July 12, 1971 The Oil and Gas Journal pages 84-124 "1971 Survey of Gas-
Processing Plants."
50. September 6, 1971 The Oil and Gas Journal pages 118-131 "Worldwide Survey
Of Petrochemical Facilities, United States" by Ailleen Cantrell.
51. September 20, 1971 Chemical Engineering Vol. 78 No. 21 page 83 "Sulfur
Removal Projects Keep A-Coming."
52. October 1971 Hydrocarbon Processing Vol. 50 No. 10 Section 2 pages 7-15
"World-Wide HPI Construction Boxscore, United States."
53. October 1971 Engineering and Mining Journal Vol. 172 No. 10 page 32 "Pilot
Plant to Produce Elemental Sulfur Comes On Stream At Asarco's El Paso Smelter."
54. October 11, 1971 The Oil and Gas Journal Vol. 69 No. 41 pages 68 and 69
"Stretford Removal Process For H2S Is Licensed."
55. November 1971 Hydrocarbon Processing Vol. 50 No. 11 page 9 "A New Catalyst
Will Eliminate Sulfur In Glaus-Unit Tail Gas.,"
56. November 1971 Hydrocarbon Processing Vol. 50 No. 11 page 208 "Sulfur Recovery
(Split Flow-Sulfur Recycle Process)" by Amoco Production Co.
57. November 29, 1971 Chemical Engineering Vol. 78 No. 27 pages 17 and 18
"Molecular Sieves Can Effectively Control Emissions at Sulfuric Or Nitric
Acid Plants."
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58. November 29, 1971 Chemical Engineering Vol. 78 No. 27 pages 18 and 19
"A Continuous Copper-Smelting Process That Is Economical And Doesn't Pollute
The Air."
59. November 29, 1971 Chemical Engineering Vol. 78 No. 27 pages 43-45 "S02
Absorbed From Tail Gas With Sodium Sulfite" by John C. Davis.
60. December 1971 Environmental Science & Technology Vol. 5 No. 12 page 1165
"S02 Removal Process Tested By Copper Producers."
61. December 13, 1971 Chemical Engineering Vol. 78 No. 28 pages 71-73 "Add-On
Process Slashes Claus Tailgas Pollution" by David K. Beavon.
62. December 13, 1971 The Oil and Gas Journal Vol. 69 No. 25 page 39
"Desulfurization Projects Mushroom In Japan."
63. December 20, 1971 Chemical and Engineering News Vol. 49 No. 51 page 38
"S02 Removal."
64. January 1972 Coal Age Vol. 77 No. 1 page 6 "New Contract Supports
Gasification."
65. January 10, 1972 The Oil and Gas Journal Vol. 70 No. 2 pages 58 and 59
"Sulfur-Recovery Unit Is On Stream."
66. January/February 1972 Pollution Engineering Vol. 4 No. 1 pages 34 and 35
"Abating Sulfur Plant Tail Gases" by David K. Beavon.
67. February 1972 Chemical Engineering Progress Vol. 68 No. 2 pages 70-76
"The Status Of SOY Emmission Limitations" by R. L. Duprey.
X
68. February 1972 Hydrocarbon Processing Vol. 51 No. 2 Section 1 pages 17 and 18
"Another (world's first) For IFP Sulfur Recovery."
69. February 1972 Hydrocarbon Processing Vol. 51 No. 2 Section 2 pages 3-10
"World-Wide HPI Construction Boxscore, United States."
70, February 1972 Hydrocarbon Processing Vol. 51 No. 2 Section 2 pages 24 and 25
"The Chiyoda Thoroughbred 101 Flue Gas Desulfurization Process."
71. February 7, 1972 The Oil and Gas Journal Vol. 70 No. 5 page 40 "Gulf
Refinery Boosting Stack Cleanup."
72. February 7, 1972 The Oil and Gas Journal Vol. 70 No. 5 pages 65 and 66
"Tail-Gas Desulfurization Operations Successful."
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73. February 7, 1972 The Oil and Gas Journal Vol. 70 No. 5 pages 66 and 67
"New Beavon Process Takes Sulfur-Bearing Compounds From Tail Gas."
74. February 7, 1972 Chemical Engineering Vol. 79 No. 3 page 23 "First User
Of J. F. Pritchard & Co.'s Process To Take Sulfur Out Of Tail-Gas."
75. February 14, 1972 Chemical and Engineering News Vol. 50 No. 7 page 13
"Testing Sulfur Oxide Removal."
76. March 1972 Hydrocarbon Processing Vol. 51 No. 3/pages 105-108 "Watch
These Trends In Sulfur Plant Design" by J. W. Palm.
77. March 1972 Power Vol. 116 No. 3 page 30 "Removal Of S02 From Flue Gases."
78. March 6, 1972 The Oil and Gas Journal Vol. 69 No. 10 page 42 "The Chiyoda
Thoroughbred 101 Flue Gas Desulfurization Process."
79. March 6, 1972 Chemical and Engineering News Vol. 50 No. 10 page 16 "Sulfur
Dioxide Recovery Process."
80. April 1972 Hydrocarbon Processing Vol. 51 No. 4 pages 102-106 "Reduce
Glaus Sulfur Emission" by Charles B. Barry.
81. April 3, 1972 Chemical and Engineering News Vol. 50 No. 14 page 16
"Removing H2S From Effluents."
82. April 3, 1972 Chemical Engineering Vol. 79 No. 7 page 39 "A Quick, Simple
Way to Remove Hydrogen Sulfide From Gases Or Liquids."
83. April 12, 1972 Chemical Week Vol. 110 No. 15 pages 41 and 42 "Wringing
Sulfur From Stack Gas."
84. April 17, 1972 Chemical Engineering Vol. 79 No. 8 pages 78 and 79 "Solvent/
Catalyst Mixture Desulfurizes Glaus Tailgas" by M. Hirai, R. Odello and
H. Shimamura.
85. May 15, 1972 Chemical Engineering Vol. 79 No. 11 pages 66 through 68
"Desulfurization - Part 1 ... Add-on Processes Stem I^S" by John C. Davis
(Note correction August 7, 1972 Chemical Engineering Vol. 79 No. 17 page 5).
86. June 1972 Hydrocarbdn Processing Vol. 51 No: 6 page 15 "Claims Sulfur
Removal at 99.9% Efficiency."
87. June 1972 Hydrocarbon Processing Vol. 51 No. 6 Section 2 pages 3-7
"World-Wide HPI Construction Boxscore, United States."
88. June 12, 1972 Chemical Engineering Vol. 79 No. 13 pages 52 through 56
"Desulfurization - Part 2 ... S02 Removal Still Prototype" by John C. Davis.
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BIBLIOGRAPHIC DATA '• ReP°" No- 2-
SHEET EPA-R2-73-188
4. Tide and Subciclc
Characterization of Claus Plant Emissions
7. Author(s1
W.D. Beers
9. Performing Organization Name and Address
Processes Research, Inc.
2912 Vernon Place
Cincinnati, Ohio 45219
12. Sponsoring Organization Name and Address
EPA, Office of Research and Monitoring
NERC/RTP, Control Systems Laboratory
Research Triangle Park, North Carolina 27711
3. Recipient's Accession No.
5* Report Date
April 1973
6.
8- Performing Organization Kept.
No.
10. Project/Task/Work Unit No.
Task Order 2
11. Contract/Grant No.
68-02-0242
13. Type of Report & Period
Covered
Final
14.
IS. Supplementary Notes
i6. Abstracts rj,^ repOrt discusses Claus sulfur plant emissions an
literature, supplemented with data from companies operating o
plants. It discusses process variations, investment, and opera
for 169 Claus plants in 31 states , with daily sulfur capacities to
tons , most based on natural gas or petroleum refining. Total c
plants is 60 percent more than the U.S. total. Tail gases from
usually burned, converting the H2S to sulfur oxides. Annual em
plants are estimated to be 875,000 short tons of SO2 equivalent
stages could eliminate about 70 percent of these emissions. Th
process could eliminate about 99 percent of the emissions , dou
operating costs. The IFF process could eliminate about 90 pen
investment and operating costs for the IFP addition are about h
17. Key Words and Document Analysis. 17o. Descriptors UiaUS plant aJ
Air Pollution Hydrogen Sulfide the Chiyoda a
"•Operating Costs Catalysis flue gas desu
Desulfurization are also pres
Design is included.
d control, based on
r designing Claus
tjng costs. 'It lists data
taling over 15 ,800 long
apacity of 66 Canadian
Claus plants are
issions from U.S.
. Additional catalytic
e Beavon or Cleanair
bling investment and
:ent of the emissions;
alf of those for the
[one. Information on
ind the Wellman- Power
Lfurization processes
ented. A bibliography
*Investments
Economics
Natural Gas
Petroleum Refining
Sulfur Oxides
17b. Idemifiers/Open-Ended Terms
Air Pollution Control Cleanair Process
Stationary Sources IFP Process
*Claus Plant Chiyoda Process
Tail Gases Wellman- Power Process
Beavon Process
17c. COSAT1 Field/Group 13B
18. Availability Statement 19.. Security Class (This 21. No. of Pages
Unlimited . Reft$i.AssiFiEn 167
JOTSecuriiy Class (This 22. Price
Pa*e
UNCLASSIFIED
FORM NTIS-33 (REV. 3-721
USCOMM-DC 14BS2-P72
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