EPA-450/3-75-081
August 1974
CHARACTERIZATION
OF SULFUR RECOVERY
IN OIL AND NATURAL GAS
PRODUCTION
U.S. ENVIRONMENTAL PROTECTION AGENCY
Offiro of Air and Waste Manure mm!
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA-450/3-75-081
CHARACTERIZATION
OF SULFUR RECOVERY
IN OIL AND NATURAL GAS
PRODUCTION
by
Keshava S. Murthy
Battelle
Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Contract No. 68-02-0611
Task 6
EPA Project Officer: William Herring
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
August 1974
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the
Air Pollution Technical Information Center, Environmental Protection
Agency, Research Triangle Park, North Carolina 27711; or, for a fee,
from the National Technical Information Service, 5285 Port Royal Road,
Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by
Battelle Columbus Laboratories, Columbus, Ohio 43201, in fulfillment
of Contract No. 68-02-0611, Task 6. The contents of this report are
reproduced herein as received from Battelle Columbus Laboratories.
The opinions, findings, and conclusions expressed are those of the
author and not necessarily those of the Environmental Protection Agency.
Mention of company or product names is not to be considered as an endorsement
by the Environmental Protection Agency.
Publication No. EPA-450/3-75-081
il
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NOTICE
The attached document is a DRAFT CONTRACTOR'S REPORT. It
includes technical information and recommendations submitted by the
Contractor to the United States Environmental Protection Agency ("EPA")
regarding the subject industry. It is being distributed for review and
comment only. The report is not an official EPA publication and it has
not been reviewed by the Agency.
The report, including the recommendations, will be undergoing
extensive review by EPA, Federal and State agencies, public interest
organizations, and other interested groups and persons during the coming
weeks. The report and in particular the contractor's recommended standards
of performance are subject to change in any and all respects.
The regulations to be published by EPA under Section 111 of the
Clean Air Act of 1970 will be based to a large extent on the report and the
comments received on it. However, EPA will also consider additional
pertinent technical and economic information which is developed in the
course of review of this report by the public and within EPA. Upon completion
of the review process, and prior to final promulgation of regulations, an
EPA report will be issued setting forth EPA's conclusions concerning the
subject industry and standards of performance for new stationary sources
applicable to such industry. Judgments necessary to promulgation of
regulations under Section 111 of the Act, of course, remain the responsi-
bility of EPA. Subject to these limitations, EPA ia making this draft
contractor's report available in order to encourage the widest possible
participation of interested persons in the decision making process at the
earliest possible time.
The report shall have standing in any EPA proceeding or court
proceeding only to the extent that it represents the views of the Contractor
who studied the subject industry and prepared the information and recommendation.
It cannot be cited, referenced, or represented in any respect in any such
proceedings as a statement of EPA's views regarding the subject industry.
ill
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ABSTRACT
The U. S. oil and natural gas production and processing systems
are described. The sources of sulfur emissions in these systems as well as
the current methods of control of such emissions are traced. Fourteen major
and four minor processes for sweetening (removing H^S) sour gas, two processes
(Glaus and Stretford) for production of sulfur and six processes for tail
gas cleanup are described. Some factors that may help choose a process for
a particular application are also indicated. The location of 84 Glaus
sulfur production plants used in natural gas facilities, their design
capacity, and production data are tabulated. The contribution of SCL
emissions from the natural gas processing industry to the national S0_
emission is compared and described. Control options available for different
levels of hypothetical allowable sulfur emissions from the natural gas industry
are described. This report was prepared for the Office of Air Quality
Planning and Standards of the U. S. Environmental Protection Agency,
Contract No. 68-02-0611, and submitted on July 29, 1974.
IV
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TABLE OF CONTENTS
LIST OF TABLES viii
LIST OF FIGURES i ix
ACKNOWLEDGEMENTS x
CONCLUSIONS xi
RECOMMENDATIONS .; . ' xiii
INTRODUCTION 1
Objective 2
Methodology 3
I. OIL AND NATURAL GAS PRODUCTION AND PROCESSING SYSTEMS 5
Types of Processing Facilities 6
Size Range of Gas Processing Facilities 7
Detailed Description of Small, Intermediate and
Large Size Facilities 9
Description of Small and Intermediate Processing
Facilities 9
Description of Large Natural Gas Processing
Facilities 13
Sources of Sulfur Emissions. . . • 15
II. COMPOSITION OF NATURAL GAS AND REFINERY FUEL GASES ....... 18
Composition of Refinery Fuel Gas 18
Comparison of Refinery and Natural Gases 23
III. MAJOR DESULFURIZATION PROCESSES IN OIL AND GAS PROCESSING. . . 24
Gas Sweetening Processes 24
Amine Processes 24
Carbonate Processes. ....... 27
Liquid Sweetening Processes . 29
Environmental Effects of Liquid Sweetening 29
IV. DESCRIPTION OF LESSER KNOWN SULFUR (H2S) REMOVAL PROCESSES . . 30
Minor Desulfurization (H2S Removal Processes) 31
Purisol Process 34
Iron Sponge (Oxide) Process 34
Fluor-Solvent Process i • 34
Giammarco-Vetrocoke Sulfur Process 34
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TABLE OF CONTENTS (Continued)
Level of Sulfur Compounds in Treated Natural Gas
Attainable by Various Processes. 35
V. COMPARATIVE DESCRIPTION OF SULFUR REMOVAL AND PRODUCTION
PROCESSES IN NATURAL GAS AND REFINERY GASES . . . 38
Factors in the Selection of H~S Removal Processes. ... 39
Solubility of Organic Components of the Fuel
Gas in Absorption Solvent ..... 39
Presence of Sulfur Species Other Than H-S in
Untreated Gas 40
Required Degree of Removal of Sulfur Compounds. . . 40
Other Factors in Process Selection 41
Methods of Sulfur Production in Natural and
Refinery Gas Applications 41
Direct Vapor Phase Oxidation Principle 41
Glaus Sulfur Plant Capacity VS Production Rate. . . 43
Sulfur Recovery by Liquid-Phase Absorption-
Oxidation. Principle 45
Tailgas Conditioning Processes 51
VI. ASSESSMENT OF SULFUR RECOVERY IN NATURAL GAS PROCESSING ... 53
Listing of Sour Gas Processes in Texas 58
VII. OVERALL ASSESSMENT AND RECOMMENDED CONTROL OPTIONS 59
Effect of Claus Plant Efficiency on S0_ Emissions. ... 59
Control Options and Performance Standards. ........ 61
(A) Reinjection of Acid Gas to Well Formations. . . 62
(B) Use of Iron Oxide Process ; 66
(C) Use of the Molecular Sieve Process ,67
(D) Package Claus Plant ; 67
(E) Tail Gas Clean Up With Claus Plant 67
VIII. OPERATIONAL DATA FOR SELECTED PROCESS 69
Data for Claus Plants 71
IX. REFERENCES 72
VI
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TABLE OF CONTENTS (Continued)
APPENDIX A
DETAILED DESCRIPTION OF MAJOR H S REMOVAL PROCESS IN OIL AND
GAS PROCESSING . . . A-l
APPENDIX B
DETAILED DESCRIPTION OF MINOR (LESSER KNOWN) H2S REMOVAL PROCESSES. B-l
APPENDIX C
DESCRIPTION OF SULFUR PRODUCTION PROCESSES. C-l
APPENDIX D
DESCRIPTION OF TAIL GAS CLEANUP PROCESSES D-l
APPENDIX E
DETAILS OF PLANT AND FIELD VISITS AND SAMPLE OF QUESTIONNAIRE
SENT OUT FOR SOLICITING INFORMATION E-l
APPENDIX F
LIST OF INDUSTRY AND OTHER PERSONNEL CONTACTED BY TELEPHONE AND
VISITS. F-l
APPENDIX G
CONVERSION FACTORS G-l
APPENDIX H
HANDLING OF WASTE GAS WITH HIGH H S CONTENT H-l
APPENDIX I
LIST OF GLAUS PLANTS IN NATURAL GAS PROCESSING. 1-1
APPENDIX J
TECHNICAL REPORT DATA SHEET j_l
vii
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LIST OF TABLES
TABLE 1. CLASSIFICATION OF U.S. GAS PROCESSING FACILITIES
BY STATE AND SIZE (JANUARY, 1973) 8
TABLE 2. COMPOSITION OF VARIOUS NATURAL GASES 19
TABLE 3. COMPOSITION OF NATURAL GASES (1972-73 Data) 20
TABLE 4. SULFUR COMPOUNDS IN UNTREATED NATURAL GAS 21
TABLE 5. ANALYSES OF CATALYTIC CRACKER GAS 22
TABLE 6. SUMMARY OF MAJOR GAS AND LIQUID SWEETENING
PROCESSES 25
TABLE 7. COMPARISON OF CIRCULATION RATES AND REBOILER STEAM
RATES FOR VARIOUS TREATING PROCESSES 28
TABLE 8. LISTING OF LESSER KNOWN GAS DESULFURIZATION
PROCESSES 32
TABLE 9. APPROXIMATE LEVEL OF SULFUR COMPOUNDS IN TREATED
NATURAL GAS WITH VARIOUS PROCESSES 36
TABLE 10. RECOMMENDED MAXIMUM CONCENTRATION OF SULFUR COM- . . .
POUNDS IN NATURAL GAS SUPPLIED TO GAS TRANSMISSION .
SYSTEMS FROM NEW PROCESS PLANTS(a) 37
TABLE 11. SUMMARY OF CLAUS PLANT FIELD TESTS 46
TABLE 12. TYPICAL COMPOSITION OF STRETFORD PURGE SOLUTION. ... 49
TABLE 13. CLAUS PLANT TAIL-GAS TREATMENT PROCESSES 52
TABLE 14. NATURAL GAS AND LIQUID PROCESSING PLANTS REPORTING
SULFUR RECOVERY 54
TABLE 15. SALIENT DATA ON SULFUR RECOVERY IN NATURAL GAS
PROCESSING 56
TABLE 16. COMPARISON OF S02 EMISSIONS FROM ALL SOURCES 57
TABLE 17. ANALYSIS OF REPORTED DATA (1973) ON NATURAL GAS
PROCESSING PLANTS REPORTING SULFUR PRODUCTION. ... 60
TABLE 18. CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION
• 63
LEVEL "C",
TABLE 190 CONTROL OPTION-AT HYPOTHETICAL ALLOWABLE EMISSION
LEVEL "B" 64
viii
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LIST OF TABLES (Continued)
TABLE 20. CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION
LEVEL "C" 65
TABLE 21. OPERATIONAL DATA FOR TAIL GAS CLEANING PROCESSES. ... 70
LIST OF FIGURES
FIGURE 1. SCHEMATIC OF A SMALL (OR INTERMEDIATE) GAS
PROCESSING FACILITY 10
FIGURE 2. TYPICAL LARGE NATURAL GAS PROCESSING FACILITY ... 14
FIGURE 3. DETAILED SCHEMATIC OF TYPICAL SULFUR RECOVERY
(CLAUS) PLANT , 16
FIGURE 4. TREATMENT OF STRETFORD PROCESS PURGE SOLUTION. ... 50
IX
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ACKNOWLEDGMENTS
This report has benefitted from discussions with various oil
and gas industry personnel. Mr. Charles B. Sedman, Task Officer, U. S.
EPA, has provided many useful suggestions for the study. The critical review
of this report by Dr. Joseph M. Genco, Mr. G. R. Smithson, Jr., and
Dr. James E. Flinn of Battelle Columbus Laboratories is very much appre-
ciated.
Permission to reproduce process descriptions presented in
Appendixes A through D was kindly and quickly granted by Mr. Frank L.
Evans, Editor, Hydrocarbon Processing, Gulf Publishing Company, Houston,
Texas, to whom sincere thanks are due.
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CONCLUSIONS
1. The U.S. oil and natural gas industry operated 795 gas processing
plants of various capacities with a total processed gas volume of
(a)
1.6 billion scumd (56 billion scfd) as of January, 1973 .
2. About two percent of the processed gas volume was handled in small
plants with production less than 0.3 million scumd (10 MM scfd).
However, the small plants numbered 206 (or 26 number percent).
3. About 83 percent of the total processed gas volume was handled in
plants larger than 1.13 scumd (40 MM scfd) in production volume.
(D*
4. Reported gas volume associated with sulfur production data
indicate that only about two percent of all natural gas processed
was sour (i.e., contaminated with H.S and other sulfur bearing
compounds like COS, CS-, and RSH). However, if plants that do
process sour gas but do not report sulfur production due to flaring
of the acid gas are included, estimated sour gas volume may be
about five percent of total gas production.
5. The most widely used processes for removal of H.S and other sulfur
compounds from sour natural gas are the MEA, Sulfinol, DGA,
Selexol and Benfield. Most widely used process for production of
sulfur from acid gases is the Glaus process*
6. During 1973, there were 84 Glaus plants (detailed in Table 11) in
natural gas processing with design capacities ranging from 1 to
1250 MT/D of sulfur output. The total design capacity was 6249
MT/D while the reported actual production was 2443 MT/D as detailed
in Table 15. The number of plants with different capacities were
as follows: 2 plants with up to 2 MT/D; 14 plants with 2 to 10
MT/D; 34 plants with 41 to 600 MT/D; and one plant with 1250 MT/D.
Estimated range of efficiencies of the plants is 90 to 97 percent.
(a) Conversion factors are provided in Appendix G,
* References are listed on Page 71.
(b) See footnote on Page 1 for explanation.
XI
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7. If the maximum allowable emission limit (MAL) of sulfur per
sulfur recovery unit (SRU) is limited at 1.0 MT/D, the 84 plants
would emit 61,320 MT/Y of sulfur dioxide. This quantity of SCL
represents 0.18 percent of the national SO- emissions based on
1972 data. To achieve the 1.0 MT/D sulfur emission limit, at
least 34 Glaus units or SRUs will be required to have conversion
efficiencies in the range of 97.56 to 99.7 percent as described
in Table 19.
8. If the MAL is raised to 2.0 MT/D of sulfur, the total SO emis-
sion will be 122,640 MT/Y which represents about 0.36 percent of the
national S02 emission of 33 million MT/Y for 1972. Thus, required
efficiency of SRUs will be in the range of 95 to 99.6 percent
for at least 34 units as detailed in Table 20.
9. Achieving the required SRU efficiencies to meet the MAL of
2.0 MT/D of sulfur is believed to require a significantly lower
expenditure of electrical energy (which, therefore, is related to
the national goal of energy resource conservation where possible)
than the achievement of MAL of one MT/D of sulfur. Capital and
other operating costs of achieving the former may also be signifi-
cantly lower. The tradeoffs in environmental burdens to be
considered as a consequence of decreased SO- emissions from SRU
are as follows:
(a) Increased SO- emission at power generating plants from
increased electrical energy requirements
(b) Increased fine particle emissions at power plants that
escape the most advanced particulate collectors like
high efficiency electrostatic precipitators
(c) Any increase in water pollution and solid waste burden
caused by SRU tail gas units
10. Tail gas cleaning systems are available to increase sulfur recovery of
Glaus plants to 99.7 percent or higher. Some experimental data are
reported which support the view that new Glaus plants can be designed
and operated to obtain 99.3 percent efficiency.
xn
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RECOMMENDATIONS
On the basis of this study, it is recommended that:
1. Consideration should be given to estimating any energy savings
that may be realized by adopting a hypothetical allowable sulfur
emission of 2.0 MT/D or 3.0 MT/D (see Tables 19 and 20) as compared
to 1.0 MT/D or any other allowable sulfur emission level.
2. Due consideration should be given to setting emission levels that
would help to continue the existence and growth of energy supply
from the small gas processing plants.
3. Specific control equipment or control option should not be specified
so that the optimum combination of options suitable for each processing
facility can be chosen for each control category and allowable
emission limit.
4. The cost of various options for the different control categories be
studied to help in understanding the control cost-benefit relationship.
5. Evaluation should be made of the possibility of realizing improved
Glaus plant efficiency of 98 percent and higher by exploring this
aspect in depth and by considering the possibility of providing the
needed lead time for the industry to evaluate this very desirable
alternative.
xill
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CHARACTERIZATION OF SULFUR RECOVERY
IN OIL AND NATURAL GAS PRODUCTION
(Contract No. 68-02-0611, Task 6)
Keshava S . Murthy
INTRODUCTION
Production of petroleum (crude oil) is almost always associated
with production of substantial quantities of natural gas. Production
wells are classified as gas wells when the ratio of gas to oil produced is
high. When the oil-to-gas ratio is high, however, the production facility
is considered an oil well. An arbitrary definition of a gas well is that
(a\
it can product up to 31.8 kltr (200 bbl)v ' of oil per 28,000 cu m
(10 cu ft) of gas. A higher oil-to-gas ratio in the production well could
place it in the oil well category. These classifications are aribitrary
and are merely a convenience.
The natural gas processing plant with the lowest gas production
reported'1) for 1973 had an output of 8400 cu m/day (0.3 x 10 cu ft per
day) in Texas (Ranchland Plant, Midland County); the highest plant through-
put was 52.7 x 10 cu m/day (1971 x 10° cu ft/day) also in Texas.
(b)
About five percent of the U. S. natural gas production is sour.
Consequently, treating to remove the acid gas'**) constituents is required.
(a) Metric System is used in this report and conversion factors are provided
in Appendix G.
(b) Sour gas in industry jargon implies gas contaminated with sulfur in
excess of pipeline specifications mainly in the form of hydrogen sulfide
(H2S) and carbon dioxide (C02), both of which are also called the "acid
gas" constituents of natural gas. Many gas streams, however, particu-
larly those in a refinery and manufactured gases may contain mer-
captalns (RSH), carbon disulfide (CS£) and/or carbonyl sulfide (COS).
The latter three are often products of refinery processing and usually
only appear in small concentrations in natural gas streams.
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The treatment process is usually designed for the product natural gas to
conform to the general pipeline specification o.f one quarter grain or one
grain of HgS per 100 standard cubic feet of gas. The "quarter grain gas"
is equivalent to 4 parts per million by volume (ppmv) of E^S.*
Pipeline gas specifications are known to range from 6 to 23 mg/s
cu m (0.25 to 1.0 grain/100 scf). Pipeline companies' specifications for
other sulfur compounds in natural gas are not common. However, the total
sulfur content of the gas is specified usually at 120 to 480 mg/s cu in (5
to 20 grains per 100 scf).
Processes used for sweetening the sour gas are generally either
amine treatment processes or modifications thereof. These are discussed in
this report. Other processes used are the hot carbonate process, the
fluor solvent process, etc. Depending upon the ratio of C0£ and H2S in the
feed gas, the acid gas from these processes may be rich in E^S. The methods
of removal of the E^S and CO, from the natural gas and subsequent handling
or disposal of the HoS in an environmentally sound manner form the subject
of this report.
Objective
The overall objective of this study (Task 6 under Contract No.
68-02-0611) is to assist the Office of Air Quality Planning and Standards,
Environmental Protection Agency in developing standards of performance for
sulfur removal and recovery associated with the production of oil and
natural gas. The study is concerned with the identification of: (1) sources
of sulfur emissions, (2) current methods of sulfur recovery, (3) potential
improved methods of sulfur recovery, and (4) efficiencies of sulfur recovery,
for gas processing facilities of small, intermediate, and large sizes.
From this information, recommendations for performance standards for the
three facility sizes are to be developed. Specific subtasks to be completed
to achieve the overall objective are as follows.
* For a gas of 0.65 specific gravity the 4 ppm of H^S is equivalent to
approximately 7 parts per million by weight (ppmwj. In the metric system
a quarter grain gas contains approximately 6 mg of H2S per standard
cu m of gas.
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(1) Describe the oil and gas processing and production
systems using typical example facilities. Provide
quantity and composition of sulfur -constituents in the
systems described.
(2) Describe lesser known or novel sulfur removal processes
used in oil and gas fields with reasons for their choice.
Provide quantity and composition of sulfur constituents
in the systems or processes described.
(3) Provide comparative description of natural gas and re-
finery gas compositions and define similarities and
differences in processing methods.
(4) Compare methods of sulfur production from acid gases and
tail gas conditioning processes.
(5) Provide statistical summary of sulfur recovery plants
used in production and processing of oil and natural gas.
(6) Relate sulfur emissions from natural gas processing
systems to overall national sulfur emissions.
(7) Provide operational details of selected oil and gas
sweetening processes.
(8) Provide an overall assessment of the problems with suitable
conclusions and recommendations.
Methodology
Understanding the industry as thoroughly as possible can be
considered a prerequisite to the characterization of the problems and
methods of sulfur recovery in oil and gas processing areas. Therefore
considerable effort was expended in the direction of familiarization
with the processing techniques by (a) field visits to processing units,
(b) discussions with process engineers and plant superintendent of
several production companies, (c) study of latest publications on
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the gas processing techniques, (d) contact with academicia, and (e) contact
with manufacturers of equipment for sulfur removal and recovery. To obtain
insight into the Control philosophy of the state control agencies, discus-
sions were held with the state agencies in Texas, Louisiana, and Oklahoma
via telephone and visits as appropriate.
The visits and discussions described above and listed in Appendix
E were useful. The data and surveys reported in the Oil and Gas Journal
were a good starting point for approaching the industry base and classifying
the industry into size groups. The Oil and Gas Journal Survey data for the
states of Louisiana and Texas were verified for completeness and accuracy
by direct contact with gas process engineers of several energy companies.
The steps used in conducting this study to achieve the goals of
identifying control options can be summarized as follows:
(1) Survey open literature
(2) Visit processing facilities, meet industry personnel,
\
and identify additional sources of useful and critical
data
(3) Visit and/or discuss with state air-pollution control
agencies their experience in the control of sulfurous
emissions and related problems from oil and natural gas
processing
(A) Analyze the problem in light of the above discussions,
plant visits, and open literature survey
(5) Apply the results of analyses to preparation of draft
final report
(6) Obtain review of the draft document from EPA
(7) Prepare final report.
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I. OIL AND NATURAL-GAS PRODUCTION AND PROCESSING SYSTEMS
Petroleum is a complex mixture of low- and high-volatile organic
compounds. Most of the less-volatile compounds (pentane and higher carbon
compounds) can be considered to comprise the oil portion while the more-
volatile compounds such as methane, ethane, and some propane are predomi-
nantly in the natural-gas portion of petroleum. Butanes which have boiling
points ranging from -11.7 to -0.56 C (11 to 31 F) occur in both the gas and
oil fractions in substantial amounts.
Because the oil and gas occur together in the reservoir, field
facilities for oil and gas processing usually handle both oil and gas.
Usually the field processing of the oil is limited to its physical separa-
tion from the gas; the separated oil is not generally subject to further
processing in the field but is delivered to refineries for processing into
various products. Therefore, this report is concerned primarily with the
processing of natural gas only.
Depending on the well output, producing and natural-gas processing
facilities can be classified into small, intermediate, and large sizes. An
arbitrary size classification is presented below:
Gas Production
Size Range Million scf/day Million cu m/day
Small 0.5 to 9 Up to 0.3
Intermediate 9.1 to 40 0.3 to 1.13
Large 40.1 to 1971* 1.13 to 51.0
Natural gas dissolved in the crude oil underground acts as a buoy-
ant medium for conveying the oil to the surface in the "Dissolved-Gas-Drive"
method of production. Usually the oil production ranges from six to several
hundred kiloliters per MMscum (10 to several hundred barrels per million
cubic foot) of gas produced.
* Largest reported facility.
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Most oil and gas wells produce at the highest rates during the
initial period of production. Since the production rate usually decreases
with the age of the well, a large processing facility would normally have
then become intermediate-sized, then small-sized, and finally shut down.
However, there are numerous small gas and oil wells that are operated on
a part-time basis by ranch hands.
Types of Processing Facilities
The facility type is a function of production capacity and the
constituents present in the oil and gas. For example, if the gas volume is
in the intermediate range and the gas has significant amounts of propanes
and butanes (NGL components), the facility would be more complex than a
simple gas-treating facility. Similarly, if the gas is sweet (free of H2S
as >90 percent of all gas wells are) and does not contain recoverable amounts
of heavier hydrocarbons, the facility will be very simple in that the gas
after water removal is sold directly to pipeline companies.
An example of a complex facility is the Bryans Mill Gas Processing
Plant at Bryans Mill, Texas, operated by Shell Oil Company. This plant
produces about 1.42 million a cu m/day (50 MM scf/day) of gas associated
with about 1590 kltr (100,000 bbl) of oil per day. The Glaus unit pro-
duces 203 MT/day of sulfur (200 LT/day). The gas from this plant is recom-
2
pressed to about 253 Kg/cm (3600 psi) of pressure and reinjected to maintain
sufficient reservoir pressure. One of the purposes of the facility is to
produce sulfur which has a ready market in this area. This facility is not
typical in that almost all of the gas produced is recompressed and reinjected
into the reservoir. The facility operates as a secondary oil-recovery opera-
tion and uses refrigerated absorption to produce 188 kiloliters (47,000 gal-
lons) of liquid propane and 235 kl (62,000 gallons) of combined gasoline/LP
gas per day.
Other facilities produce gas for sales, LPG (propane and butanes),
natural-gas liquids, and crude oil.
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Size Range of Gas Processing Facilities
The Oil and Gas Journal Annual Survey for 1973 indicated that
during 1972, a total of 795 gas processing facilities in the U.S. produced
1.606 billion cu m (56.7 billion cubic feet) per day of natural gas, and
295610 kltr (78.1 million gallons) per day of natural gas liquids. The
sulfur production per day was ~ 2480 MT/D (2445 long tons/day).
The 795 gas-processing facilities were fed by about 120,000 indi-
vidual gas/oil wells, each facility processing on the average the output
from about 10 wells.. The size of the 795 facilities ranged'from 8400 cu m
(0.3 million eft) to 52.7 million cu m (1971 million eft) per day. Table 1
provides detailed size classification of the processing plants by state for
the 24 states in which gas-processing facilities are reported to exist. Al-
though the survey reports that industry response to the questionnarie by the
Oil and Gas Journal was substantially 100%, it is quite possible that some
small gas processors who flare or emit H?S as-is from their amine treatment
units may not have responded. By and large, the data in Table 1 provide a
relatively complete picture of the industry. A summary of the data is tabu-
lated below.
Size Range Number of Plants Total Production
MMscfd
0.5 to 9.0
9.1 to 40
40.1 to 1800
.Total
The data show significantly that although the plants in the small
size range amount to 26. number percent of the facilities, only 1.9 of the
total U.S. gas plant capacity is in this size range. It is also significant
that as of January, 1973, 82.7 percent of gas production and processing was
done in the large size range plants.
Number
206
319
270
795
Percent
26%
40%
34%
100
MMscfd
1046.6
8798.4
46942
56787
Percent
1.9
15.4
82.7
100
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TABLE 1. CLASSIFICATION OF U.S. GAS PROCESSING FACILITIES BT STATE AND SIZE (JANUARY, 1973)
0.5 to 9.0 MMscfd
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
New Mexico
North Dakota
Oklahoma
Pennsylvania
S. Dakota
Texas
Utah
W. Virginia
Wyoming
1*«%*«.1
Tocal
Number
of Gas
Plants
1
2
1
3
49
12
10
1
29
2
132
5
10
4
2
36
3
86
2
1
369
4
4
27
795
Gas Production
Per Day
MMscmnd**
0.034
0.92
0.057
2.41
24.92
10.11
22.09
14.73
136.47
22.37
553.57
3.12
2.61
0.85
0.34
88.78
2.80
95.52
0.093
0.71
590.56
3.43
7.56
24.16
1608.21
MMscfd
1.2
32.5
2.0
85
880
357
780
520
4,819
790
19,547
110
92
30
12
3,135
99
3,373
3.3
25
20,853
121
267
853
56,787
Number
of
Plants
1
1
1
1
21
6
5
20
1
7
3
2
4
1
23
2
93
1
13
206
MMscumd
0.034
0.14
0.057.
0.76
4.02
1.02
0.79
2.29
0.028
1.076
0.283
0.34
0.51
0.24
5.66
0.093
11.33
0.17
1.47
29.64
9.1 to 40 MMscfd
Total Number
Production of
MMscfd Plants
1.2
4.9
2.0
2.7
142
36
28
81
1.0
38
10
12
18
8.5
200
3.3
400
6
52
1,046.6
_ '
1
2
23
5
9*
9
37
3
3
1
10
1
35
1
167
2
2
8
319
MMscumd
0.78
2.33
11.55
1.87
3.68
5.41
18.21
1.78
1.53
0.57
3.40
0.44
30.02
0.71
160.74
1.02
0.99
4.22
249.17
40.1 to 800 MMscfd
Total Number
Production of
MMscfd Plants
27.6
82.3
408
66
130
191
640
63
54
20
120
15.5
1,060
25
5,676
36
35
149
8,798.4
5
1
1
1
15
2
75
1
22
1
28
109
1
2
6
270
MMscumd
9.35
7.22
18.41
14.73
'130.27
22.37
533.15
1.30
84.88
2.12
59.84
418.48
2.24
6.57
18.46
1329.4
Total
Production
MMscfd
330
255
650
520
4,600
790
18,826
46
2,997
75
2,113
14,777
79
232
652
46,942
'* 137. H2S.
** MMscumd - million standard cubtc meters per day.
-------
Derailed Description of Small, Intermediate
and Large Size Facilities
Distinctions between small and large facilities are not very
useful because the unit processes used in a particular facility do not
depend on the plant size but on the gas composition. Accordingly, if the
gas is sour (523 milligrams per s cu m) and rich (or wet i.e. containing
>1.34 liters of liquids per s cu m of gas), even the smallest facility will
be forced to use a gas sweetening process and a liquid recovery unit. On
the other hand if large quantities of sweet gases are produced, as 90% of
the gas wells do, even large plants processing more than one billion cubic
feet daily do not use sweetening units.
However, one important difference between small and large plants
processing sour gas is in the area of sulfur recovery from acid gases.
Usually, if the volume of acid gas generated is insufficient to produce
enough sulfur (~2 MT per day) , small plants flare the acid gas instead of
recovering the sulfur. The large plants usually practice sulfur recovery
because of the large volume of acid gas they generate and the consequent
sulfur value contained in the acid gas.
Description of Small and Intermediate Processing Facilities
A schematic block diagram of typical gas-processing facilities in
this size range is presented in Figure 1. The facility represented here can
handle both sweet and sour gas. A very small facility would only employ
processes (1), (3), (A), (6), and (8) identified in the figure. The
description of the process steps and associated environmental burdens follow.
Stage Separation (1).* Gas from the wells enters the stage sepa-
rators where the oil is separated from the gas and the pressure of the gas
is reduced from about 150 atm to pipeline requirements, usually about 70 atm.
* Number refers to block number in Figure 1.
-------
Sweet and dry gas direct to sales
Sales gas
1
1
Gas from wells Stage _
under high pressure *" separators
u.
O
•*-
'o
TJ
0)
"5
UJ
1
1
1
fl
+ 1
ol
Til
•-I
v5i
|
I
L
••»>
Amine .
treatment
unit
1
Amine
regeneral
unit
4
or
/
1
^ Dehy^ajion6 ^as ^
1 unit ^^metering^
\ ^
— Hydrocarbon
*" Unit
(If no S recovery)
(h^S + COg) | r»rnu<»ru Tail gOS
unit
Crude oil
1 »
2
Central
unit (station)
Deemulsifying
unit
(heat or
electricity)
9
,- . ., LACT
Crude oil d f h
battery
)
(drocarbons
To flare
8
Tail gas
incinerator
Oil pipe line
Water phase to formation
LEGEND
O ATMOSPHERIC EMISSIONS
A LIQUID
FIGURE I. SCHEMATIC OF A SMALL (OR INTERMEDIATE) GAS PROCESSING FACILITY
-------
11
The oil is then flashed in several stages to insure maximum oil recovery.and
the flash vapors are recompressed to pipeline pressure. ^-
Products from this process step are, (1) sour or sweet gas and
(2) crude oil. If the gas is sweet and dry (free of water), it is sold to
/ rt \
pipe line companies via the sales metering station (8). If the gas is sour,
it is routed to step (3) which is described later. Similarly, the crude
petroleum oil is sent to step (2) or step (9) as shown in H-gure 1. This
process produces .no environmental burdens.
Central Treating Unit (2)_. When the crude oil from step (1) is an
emulsified mixture of oil and water it is pumped to a central treating
facility. De-emulsifying treatment followed here is described in step (5).
Amine Treatment (3). Amine treatment removes the undesirable H^S
(and CO ) from the sour gas produced in step (1) stage separators. The more
common amine treatment processes currently in use are: the luonoethanol amine
(MEA) process, the Shell sulfinol process, the Diethanol amine (DBA) process,
and the Econamine process. Details of these processes are discussed elsewhere
in this report. These processes are usually carried out at high pressures.
The process produces "quarter-grain" to one-grain gas which is equivalent to
about 4 to 16 ppm H_S by volume.
There are no environmental burdens from this process step.
Amine Regenerator (4). The spent amine solution in step (3) is
continuously regenerated in an amine regenerator. Usually the process in-
volves warming of the solution plus stripping to desorb the H^S and CCL.
The process produces H S and CO which are the major components of
the "acid gas". Generally the acid gas is fed to a sulfur recovery plant.
The major environmental burden from the regenerator is H S. If
the acid gas is not processed to recover sulfur, it is flared, which results
in emission of sulfur dioxide to the atmosphere.
De-emulsifying Process (5). Treatment of the oil-water emulsion
is necessary whenever the stage separation process step (1) generates an
emulsified crude oil-water mixture. The most common methods of emulsion
-------
12
treating use chemicals or heat, or both. The kind of treating method is de-
termined by the characteristics of the emulsion. The treatment is normally
done with a "heater", or "heater-treater". The heat is supplied by means
of a burner which uses either gas or fuel oil; and if chemicals are used,
they are injected in small quantities by pumps like those used for corrosion
treating. A great variety of chemicals are used for this purpose, but
no one material has proved effective for all emulsions.
After being heated and/or chemically treated, the emulsion is
allowed to enter a tank where the water can separate from the oil. The
separated liquids are then drawn off-the oil going to the stock tanks,
and the water going to the disposal system. Recently the use of electrical
currents to break emulsions is gaining acceptance.
Major environmental burden is salt water separated in the process.
The water is returned to well formations; when this is not feasible, water
treatment is employed so that the discharged water is accepted without
endangering the safety of the waterways.
Dehydration (6). Sweet gas from the amine treatment units is con-
taminated with water vapor. Removal of this water vapor is usually done by
using triethylene glycol (TEG), an alcohol which can absorb only the water
very effectively.
Product from this process is dry natural gas ready for sale. There
are no environmental burdens from this process.
Sulfur Recovery (7). Acid gas from the amine regenerator step (A)
is often rich in H.S and by suitable processing, is converted to pure ele-
mental sulfur* in this process. The most common sulfur-recovery process em-
ployed is the modified Claus Process which has a recovery efficiency limit
of 90-97 percent.
Product from this process is pure sulfur.
The major environmental burden of this process is a tail gas from
the plant which contains about 3 to 4 percent H..S in the feed.
Tail-Gas Incineration (8). Unconverted H S, sulfur vapors, and
other sulfur compounds from the Claus sulfur plant are burned to sulfur
Sulfur purity exceeds 99.5 percent.
-------
13
dioxide (SCL) In this unit. Fuel for combustion is provided by plant
»as or by flash vapors and vapor from sour water strippers (if there are any).
This step is the major contributor to environmental burden. The
emission of S0« to ambient air is the major problem of Claus plants. This
is discussed in detail in other sections of this report.
LACT* Crude Tank Battery (9). This system provides for the
unattended transfer of the oil (or gas) from the lease to the pipelines.
The oil storage tanks in this system are under a positive pressure. When
no vapor recovery system is installed, a small amount of hydrocarbon vapor
contaminated with H?S (if the oil is sour) is lost to ambient air.
Environmental burden from this unit consists of loss of H~S
and Hydrocarbons as vapors from oil tanks. The emissions are not signifi-
cant however. Most of the new tanks are equipped with vapor recovery
units, thus reducing the emissions to near zero.
Description of Large Natural Gas Processing Facilities
The essential differences between large processing installations
and the smaller facilities are as follows.
(1) The large facilities can often justify a sulfur-recovery
plant with recovery efficiencies of up to 97 percent.
This implies that three recovery stages will be used in
the Claus plant.
(2) Large units are more likely to have hydrocarbon recovery
plants that produce liquid propane, liquid butanes, and
gasoline-blending cuts.
A schematic of a typical large facility is presented in Figure 2.
This plant produces crude oil with a Reid Vapor Pressure (RVP) of 8 psi
(about 0.5 atm) , sales gas, propane, butanes, natural gasoline, and elemental
sulfur.
Figure 3 provides a detailed flow scheme of just the sulfur-
recovery plant shown in Figure 2.
*.Lease Automatic Custory Transfer.
-------
! i
i i
iRECOMPRESSOR
i !
. } CONDENSATE
H
STABILIZATIOiM
j JPLANT
8° RVP
CONDENSATEJO—5
STORAGE
GLYCOL
DE H YD R ATI ON
UNIT
V
O4
o
O
j | __ BUTANE. _____ ^
{_=____G^S01:jNE ____
LIQUID Ss LOADING
BLOCK S6
STORAGE
FIGURE 2o TYPICAL LARGE NATURAL GAS PROCESSING FACILITY
-------
15
Both Figures 2 and 3 are self-explanatory. However, the sources
of US and SO emissions need discussion.
'*>
Sources of Sulfur Emissions
The sources are: (1) the tail gas from the Glaus plant final
sulfur separator, (2) the salt-water flash tank, and (3) the salt-water
stripper.
Tail Gas from Glaus Plant. The quantity of H S present in the
tail gas depends on the following factors: (1) the H S in Glaus plant feed,
(2) the conversion efficiency of the plant which is a function of the number
of stages of sulfur reactors, (3) degree of precision in the control of the
temperature in the Glaus plant burners, and (4) the instrumentation employed
in controlling the plant-operating conditions.
(2)
Rankine, et al predict that theoretical thermodynamic recoveries
from a four-stage Glaus plant, processing a feed containing 67 percent hydrogen
sulfide, to be as follows:
2 catalytic stage recovery 97.9 percent
3 catalytic stage recovery 99.1 percent
A catalytic stage recovery 99.4 percent.
However, actual yields of sulfur in existing plants has been about
90 to 97 percent. This leaves about 3 to 10 percent of the feed H S in the
tail gas.
S aIt-Water Flash .Tank. A considerable quantity of salt water (also
called sour water if dissolved H S is present) is produced from oil-water
separators. One plant reports a salt-water production of one percent by
volume of the oil production (one liter/100 liters of oil) and on the basis
of gas production, 4.63 kiloliters of salt water/million cu m of gas pro-
duced. These statistics are not typical because salt-water production ranges
from 1 to as much as 99 percent of total well output. Reported H S content of
sour waters also varies, a typical value being 0.5 gram/liter of sour water.
Dispos.il of the sour water requires that the H_S in it be stripped.
This is accomplished in flas|) tanks and strippers. Because the sour-water
-------
Acid
gas
from
j
0^
N
—
X1
Air blower
3Z2(
^
regent-"'
erator
Sulfur
1
•
/
Waste heat \>»/
furnace ^X'v
plant
N,
\
j~-
\
\
*•»
,
Water
.!
— v,
/
/
,**
'
No. 1
r
\
\ |
^
eheat burner
No. 1
i
/
\
' No. 2, No.3.X
"1
• -$
\ burner + ) ^^
J No. 1 sulfur
' reactor
-
Steam
Sulfur
\
y,
i
\
f —
\
•»>_
i
Water
i
— ^
— ;
}
s
'
")
)
reactors t
1 j ,
! s
.1
!^_
r* ^
il
\
Steam
t Sulfur Sulfur
I
Liquid to
OEA line
(
Sulfur'
H2S
1^^
Heater
/ '
H2S-r-SOz
\
suirur
separator
S
+ HC
n
! |
-J
—a
i
•• Incinerator^/ \..
* . 17 \
A
1 Fuel Gos
^;
'
H 2S + HC
.
'^ N\
\
1
^3 n
3 -2 •ACtsr
0) w
f\i O
Salt water stripper
«H "T ~"
FIGURE 3. DETAILED SCHEMATIC OF SULFUR RECOVERY (GLAUS) PLANT
-------
17
stripper gas contains some amounts of hydrocarbons (HC), the gases are often
fed to the Glaus tail-gas incinerator. It is not known if this practice is
followed by all processing plants..
It is possible to compress the gas from the stripper or operate
the sour-water stripper at about 0.5 atmospheres (-7.5 psig) so that the gases
can b.e fed to the Glaus plant. However, if the hydrocarbon content of the
gas is high, removal of heavy hydrocarbons will be necessary to insure that
the purity and color of the Glaus plant sulfur is maintained.
Emission Sources of Other Sulfur Compounds. The natural gas
industry is predominantly concerned with ELS as an undesirable constituent
in natural gas. However, other organic sulfur compounds that can be present
in both raw and processed natural gas are: mercaptans (RSH), carbonyl sulfide
(COS) and carbon disulfide (CS«). Some of the sweetening processes are
more effective in removal of these other sulfur compounds. There is also
(3)
evidence that undesirable side reactions in a Glaus plant tend to form
COS and CS~. It is estimated that as much as 2 percent of the sulfur in the
feed might be converted to organic sulfur compounds, and that this might
(A)
account for 40 percent of the S0» in the incinerated gases .
In summary, although COS and CS9 can be formed in a Glaus plant,
*
their exact source (point location) is difficult to identify. However,
these compounds end up in the tail gas. Also the raw gas can contain
significant amounts of COS, and RSH as shown in Table 7. The CS? content
of natural sour gases is very low. By a judicious selection of the sweet-
ening process, up to 90 percent of these compounds can be taken out of the
natural gas. However the acid gas will concentrate the organic sulfur
compounds and when fed to the Claus plant, these compounds constitute
emissions in the tail gas. Recently, catalysts (example Cobalt-Molybdynum)
to hydrolyze COS and CS to H,?S and C02 have been identified . It j;!;-
appears possible that improved catalysts can reduce unconverted CS0 and COS if.*
m
concentrations in the tail gas and hence the SO,, emission in the incineration P
vi
of gases. |P''
K
H
-------
18
II. COMPOSITION OF NATURAL..GAS...AND. REFINERY _FIJKL-CASES
The U.S. Bureau of Mines reports that as of December 31, 1972,
there were 1.2.1,153 producing wells for gas and condensates in the United
States. These wells were distributed over 30 states. Generally, the
composition of gas from these wells varies from well to well. However
for processing purposes they must be grouped. Thus, sour and sweet is
one type of grouping, and, rich (or wet) and dry gas is another type of
grouping. Both groupings are necessary and significant. Sour gas contains
considerably more than 2.29 grams/100 s cu m (1 grain of H£S per 100 scf)
and must be sweetened by amine or other processing methods described in
Appendix A. Rich gas is gas containing more than 1.34 litres of liquid
components (propane and higher-boiling compounds) per s cu m of gas (10
gallons/1000 s cu ft). Dry gas usually contains less than 0.5 gallons of
propane plus compounds per 1000 eft and hence, recovery of natural-gas
liquids (NGL) from dry gas is usually not economically warranted. Natural
gas exists at high pressures (20 atm and above) which helps in amine treat-
ment. Also, because most natural gases are free of very heavy hydrocarbons,
aromatics, and olefins, the treatment of acid gas to produce bright yellow
sulfur in a Glaus unit is much easier. Composition of various samples of
natural gases are presented in Tables 2 and 3. Detailed analyses of sulfur
compounds in natural gas are presented in Table 4.
Composition of Refinery Fuel Gas
Refinery fuel gases originate in the refinery from many cracking
and catalytic processes. Examples of gas producing processing are:
thermal cracking, catalytic cracking, sour water stripping, topping,
hydrotreating, etc. Gases from these processes usually are contaminated
with H.S. Typical analyses of refinery fuel gases are not available because
most refineries do not record the analyses of the fuel gases except for
their H-S content when H^S removal is employed. Thus, data on the
concentrations of mercaptans and COS in refinery gases are difficult to
obtain although industry experts claim that the concentration of these
gases in refinery fuels is generally higher than in most natural gas
streams.
-------
19
TABLE 2. COMPOSITION OK VARIOUS NATURAL
,;A^<«>
....
Composition, mole %, of gas from
Component
Methane
Ethane
^r.opahe.
Butanes'
Pentanes and
heavier
•Carbon
dioxide
Hydrogen
sulfide
Nitrogen
Helium
- 'Total
To'tal sulfur, „
grains/100 ft
Classification
wet
dry
sweet
sour
Gross heating
value,-
Btu/ft
Specific
gravity
Rio
Arriba
County,
N.M.
96.91
1.33
0.19
0.05
0.02
0.82
0.68
100.00
0
X
X
1,010
0.574
Terrell
County ,
Texas
45.64
0.21
53.93
0.01
0.21
100 . 00
6.3
X
X
466
•1.0777
Stanton
County,
Kansas
67.56
6.23
3.18
1.42
0.40
0.07
21.14
100.00
0
X
X
938
0.733
San Juan
County,
N.M.
77.28
11.18
5.83
2.34
1.18
0.80
1.39
100.00
0
• X
X
1,258
0.741
Olds
Field,
Alberta,
Canada
52.34
0.41
0.14
0.16
0.41
8.22
35.79
2.53
100.00
22,525
X
X
807
0.882
Cliffside
Field,
Amarillo,
Texas
65.8
3.8
1.7
0.8
0.5
25.6
1.8
100.00
X
X
825
0.711
-------
20
TABLE 3. COMPOSITION OF NATURAL GASES* (1972-73 Data) - Mole %
Carbon dioxide
Nitrogen
Hydrogensulfide
Methane
Ethane
Propane
Isobutane
N-butane
Iso-pentane
Gas Gas
Sample Sample
No . 1 No . 2
43.40 1.27
0.50 0.94
0.01 0.37
56.00 91.16
0.09 4.05
0 1.20
0 0.13
0 . 0.36
0 0.10
Gas
Sample
No. 5
4.4
. 8.7
10.6
59.93
7.7
4.1
1.3
2.1
0.6
Gas
Sample
No. 6
1.6
1.6
0.6
83.5
8.0
3.3
0.3
0.8
0.1
N-pentane
and heavier 0 0.42 0.6 0.2
Total 100.00 100.00 100.00 100.00
Btu/cft 570 1060
Total sulfur gr/100 cu ft. 10 200 NA
Specific gravity 0.975 0.622
* These data were reported by AMOCO, Shell and Exxon in response to BCL
requests. However, it should be noted that there are wells in the U.S,
and Canada that contain greater than 50 percent H S by volume.
-------
TABLE 4. SULFUR COMPOUNDS IN UNTREATED NATURAL GAS
Sulfurous
Components
Hydrogen suifide (H_S)
ppmv of H_S
Mercaptans (RSH) •
Sulfides (COS etc)
Residual suifide (S)
Total sulfur
C02 (mole %)
Gas Sample 1
grams*/
100 s cu m
153
1044
21
7
4
185
1.5
Gas Sample 2
grams/
100 s cu m
76
519
14
5
2
97
0.71
Gas Sample 3
grams/
100 s cu m
2
14
0.12
0.04
0.01
2.17
2.42
Gas Sample 4
grams/
100 s cu m
24,905
170,026**
627**
188
105
25,825
NA
Gas Sample 5
grams/
100 s cu m
29,213
199,437**
735**
220
121
30,289
NA
Gas Sample 6
grams/
100 s cu m
21,369
146,000**
973**
893
146
23,381
NA
* Multiply given values by 0.43665 to obtain grains/100 scf.
** Such high concentrations are not common in natural gas streams. These concentrations of sulfur compound
definitely are much higher than those of refinery fuel gas. As pointed out elsewhere, about 2 percent of
U.S. natural gas is sour and less than 2 to 3 percent of the sour gases contain high sulfur compound
levels presented in this table.
(Source: Mr. Neal, Petroleum Analytical Laboratory Service, Odessa, Texas)
-------
22
TABLE 5. ANALYSES OF CATALYTIC CRACKER GAS*
Mole %
Carbon dioxide
Hydrogen sulfide
Carbonyl sulfide
Hydrogen
Methane
Ethane and heavier
Water
Temperature C (F)
Pressure, atmospheres (PSIG)
1.24
6.38
•
44.86
32.17
14.35
1.00
60 (140)
5.5 (80)
* Not a typical analyses. See text, page 18.
(Source: Official Communication dated January 4, 1972
from David C. Parnell, Chief Process Engineer, Ford,
Bacon and Davis Texas Inc., to Richard K. Burr, U.S.
EPA, RTF, NC 27711)
-------
23
Comparison of Refinery and Natural Gases
The most imporCant differences related to the design of sulfur
recovery units from the two gases are
(1) Presence of heavy hydrocarbons including aromatics
in the refinery gases which tends to form a somewhat
black sulfur instead of the more readily marketable
yellow sulfur in the sulfur recovery step.
(2) The refinery gases are usually at atmospheric pressure
and higher than ambient temperature. Natural gas is
at higher pressure (>25 atm. depending on the stages
of separation) and a lower temperature. These factors
contribute to the ease of processing natural gas during
the ELS removal step. The absence of heavy hydrocarbons
in natural gas helps in recovering pure yellow sulfur.
(3) Other differences are that refinery gases contain cracked
products (gum-forming olefins) and are more likely to
contain sulfur compounds like carbbnyl sulfide, mereap-
tans, etc., as discussed on page 18.
To generalize on these differences and summarize how they affect
the design of sweetening and sulfur-recovery units is not practical because
there are far too many variables involved in the design. However, it cannot
be too strongly emphasized that design of treatment units for refinery gases
requires more careful tailoring to individual gas compositions. This is not
to imply that design of natural-gas treatment units is highly standardized.
-------
24
Til. MAJOR DESULFURIZATION PROCESSES IN'OIL AND GAS PROCESSING
The natural gas Industry has to sweeten (remove H»S from) both
the gas and sometimes the liquified gases such as propanes, butanes, etc.
Available sweetening p.rocesses employ physical, chemical and a combination
of separation techniques. Thus, a confusing array of gas and liquid
sweetening processes is in use. These are discussed below under two
headings: (1) gas sweetening processes and (2) liquid sweetening processes.
Gas Sweetening Processes*
These can be grouped under five types: (1) the Amine Processes,
(2) the New Amine Processes, (3) Carbonate Processes, (4) Physical Absorption
Methods, and (5) Solid-Bed Sweetening Processes. Most of these processes
remove both the H S and C0? from the natural gas to produce an "acid gas"
rich in H?S and C0_. Further processing of this acid gas is necessary to
produce sulfur. This is discussed under sulfur production processes.
Also, processes that combine H_S removal and direct sulfur pro-
duction are used selectively. Examples of such processes are the Stretford
process used in the U.S. and the Giammarco-Vetricoke Process (GV) in use
primarily in Europe.
A summary of the essential features of all these processes Is
presented in Table 6. A brief discussion of each process type follows.
Detailed discussion and flow diagrams are presented in Appendices A, B and C.
Amine Processes (Including New Amine Processes)
Although at least five different types of amine processes have been
developed, only three (MEA, DEA, and sulfinol) have gained wide usage in the
industry. Of these processes, the MEA and DEA (used chiefly in refineries),
are two of the oldest gas-sweetening processes which are still used in over
300 installations.
* There is considerable overlap in processes used for gas and liquid sweetening.
-------
TABU 6 . SUMUIV OF MAJOI GAI
ffroee.lt Conditions
Process Name
(Process Applicability)
Te»p.,
Process Mechanism C
Prassuri,
atm
Solution
Concentration,
percent Regeneration
Product
Torm
Amtna Processes
Konoethanolamlne (HEA)
Dlethanolamlne (DEA)
Now Amtng Processes
Dlglycolani.no (DGA) or
Flour Econamlne (sour
Sat
Shell sulflnol (gas and
liquid sweetening)
Liquid chemical absorp-
tion (acid-base
reaction)
Liquid chemical absorp-
tion In an aqueoul
oolutlon
Improved liquid chemi-
cal absorption with
alkanolamlne
Liquid chemical absorp-
tion plus physical
solution of HjS In
sulfolane
30-55 1-70 15-20% In water In a steam strip: H.8 gas
per column
30-55 1-70 15-20% In water By steam stripping J^S gas
30-55
30-50
1-70
1-80
Up to 60S In
water
Yes
Highly variable Yes
gas
gas
SNPA-OEA
Soctote Rationale das
Petroles d'Aqultnlno
(sour gan)
Shell ADIP (Gae and
liquid sweetening,
mostly In refineries)
Same as DEA process but 30-55
the DEA concentration
Is high' In this Im-
proved version
Regenerative abtiorption 25-40
In aqueous so).vont
amlne (dllsopropanol
amlne)
1-70 20-30% In water Yes R,S gas
1-80 25 to 30% In Pressure reduc- H..S gas
water tlon plus
stripping
Carbonate Processes
Benfleld (Benson and
field Invention)
Benfleld Corporation,
Pittsburgh Pa.
(Natural and synthesis
gas)
Catacarb (sour gas)
Physical Absorption
Activated (promoted)
hot K process
Catalyzed hot K;jCO3
Proccea with corrosion
Inhibitor
Selexol (Allied ChaalcQls) Pftyotcal absorption of
(gaa and liquid
sweetening)
Rectlsol
Lurgl Mineralolcechnlk
GMbH
(syngas)
002 a»d HjS In di-
methyl ether of
polyethylene elycol
(DMPBO)
25-200
55-130
7-300
10-70
20-80
20 to 35%
Not known
5 to 10% In
water
By steam
stripping
Steam plus gas
stripping
Yes, by stage
flashing and
reheat
gas
gas
gas
Removes CO , H 3, NH , HCN and other impurities from crude gases from coal gasification, etc.
I Solid Bad Sweetening Processes
Molecular sieve (sodlun Physical absorption 10-40 5-100
aluminum silicate)
. Union Carbide Corporation,
Llnde Division
(914) 345-3196
(Gas end liquid otrecm
with rater, BjS, 002)
8imulfsneo bUU US° °f "8a"1C "Ui in tha a
Varies
Heat
HjS gas
Stretford-ADA vondate
(sour gas)
Sulfreen (SNPA/Lurgt)
The Ralph M. Person
(Gas containing SOj)
acceptable la the U.S.
Yes Pure sulfur
Diooolutlon in (tquoous 58 0-100 Varies v»s
solution of sodium .
carbonate, sodium . .,
vondate, end tinthra-
qulnona dlsuli'onlc
•eld (ADA)
Although this procesa converts H^S to sulfur. It is essentially an extension of the Claus reaction.
=»——~—« =»— r
-------
26
ttuobar of Units
In Operation
la the U.8.
Selectivity
for HjB In
Hj8 + COj
Rich reed
Advantages
(Also see text)
Disadvantage!
Utilities
Raqulrenentf
AMD LIQUID SVBIIHIia IMCSS8IS
>300 units mostly In
refineries
>300 unite mostly to
refineries
56 x 10 8 Cu, m In
operation In
natural gaa
58 (NG). widely ac-
cepted In natural
gas, refiner? gas,
coke oven gaa
operation!.
18 In Canada
None In the U.S.
12 In other countries
30
Widely accepted for
refinery gases In
Europe.
Many In Europe
20 In natural gaa
>200 In MBa plants,
etc.
66 unlta total
Honaelectlve
Good for
Excellent up to 50%
COj can be re-
tained In gaa
None
Good aelectlvlty
achievable
Possible
Possible
Rapid reaction with aold gat
(H2S. C02, ate.)
0.2 mole acid gas/mole of
MEA
-Removes 901 of all ner-
captans with no addi-
tional burdens.
-High solution loading
-Excellent ease of
operation
-Skid mounted units for
small gas operations
available
Lower utility requirements
Well danonstratad process for
refining gases
No corrosion problems
Applicable to liquid hydro-
carbons, synthetic gas,
etc.
Flexible operating conditions
The higher the pressure the
better
Lover solubility of HC
Low cost of materials
Mora difficult to regen-
erate. Higher utility
costs
Currently DGA Is in short
supply
Absorbs heavy aromatlca
from the gaa
Depends on feed and/or
COzi IfeB concantratlon
•MEA Is better for low
pressure (100 pal)
Must have at least 201
total acid gas and
must be 002
Very low. Lower than
MEA and DBA. See
Table next page
low
Low steasi consumption
Low steam consumption
construction
Moderate selectivity
for BjS la possible
Can handle both high and
low CC? and HjS gases.
Lower capital and operating
costs are claimed by
developers
Can treat high pressure
gases only
0*0 ata)
Not used In natural gaa Industry but Is mentioned here to emphaslce that it la a major process.
Very low compared to
MBA
Hot XJCO3 processes
12 In (a*
30 In UB
Excellent for H20
and HJS
Easy to operate and vary
useful for LOG purification
Off gaa from regenerator
is too lean In H»8 for
a Claus plant. Hence
concentrator it needed.
Hence this proceea ts eat likely to be uaed in the U.S.
53 unlta total
Completely selective
to HjS
No tall gaa hence no HjS
emissions
Therefore It l» discussed to detail under "Tallgas Cleaning Processes",
-------
27
Detailed process descriptions are available in literature and
Appendix A. Essentially, the principle used is the chemical reaction of j
r .'',,
H S and CO with amine. In recent years the Sulfindl and other improved !• V
t . ;;
processes are tending to replace the not-so-selective MEA and DBA processes. I '-i'
A comparison of some operating data for the MEA, DEA, DGA, and Sulfinol pro- \'
cesses are presented in Table 7. [
Carbonate Processes
Most of the carbonate processes were designed to remove CO- (rather
than H S) from the gas. The principle used is that C0? (and to a lesser ex-
tent H S) has a high affinity for potassium carbonate (K2CO,) and hence,
K C0_ can be used to remove C00 and H?S from a mixture of gases according to
the following reactions.
K.CO. + C00 + H00 £=£. 2KHCO- and
L J 2 2 j
K2C03 + H2S £=5; KHS + KHCO^
Since the salt formation in both reactions is high, high temperatures are fe'.
• • '• • '
employed to keep the salt in solution. Thus, the process is called hot
• ' ' '
carbonate process.
'• '
The hot carbonate process has been successfully utilized for bulk
removal of CO and incidental removal of small concentrations of H9S. The
2. 2.
process will not work if only H?S but no CO is present. The process has
the advantage that both carbon disulfide (CS_) and carbonyl sulfide (COS)
can be removed without significant solution degradation. Carbonyl sulfide,
for example, will hydrolyze as follows.
COS
The C0« and H S are removed as per reactions described earlier.
-------
28
TABLE 7. COMPARISON OF CIRCULATION RATES AND REBOILER
STEAM RATES FOR VARIOUS TREATING PROCESSES^10'
ITEM
Contactor Pressure, psla
Feed Gas Temp., °F
Feed Gas Flow (Dry), MMSCFD
Feed Gas Composition, Mol 7.
H,S
CO,
N2
Cl
C2
C3
'4
C5+
TOTAL
COS, Grs/100 SCF
RSH, Grs/100 SCF
H2S/CO2 Ratio
Sweet Gas H2S Content, Grs/100 SCF
Sweet Gas C02 Content, Hoi 1
Sweet Cas Total Sulfur, Grs/100 SCF
Solution Circulation Rate, gpm @ 110'F
SuHinol (Composition Varies)?
MEA (15 wt. 1 ME A)
DEA (25 wt. I DEA)
DGA (65 wt. 7. DCA)
Section Net Pickup, SCF Acid-Gas/Gal
Sulfinol Sol'n.
MEA Sol'n.
DEA Sol'n.
DGA Sol'n.
raboller Steam Rate. 0/HR
Sulfinol Sol'n. '
MEA Sol'n.
DEA Sol'n.
DGA Sol'n.
Reboller Steam Rate, (?/Cal. Sol'n.
SulUnol Sol'n. .
MEA Sol'n.
OEA Sol'n.
DCA Sol'n.
Cas "A"
1,000
no
100
0.65
8.73
2.37
87.90
0.35
100.00
3.0
2.1
0.0744
<. 0.25
<. 1.0
<1.0 '
1,483
2,170
1,272
1,277
4.39
3.00
5.12
5.10
69,740
143, 200
87,770
91,950
0.78
1.10
1.15
1.20
Gas "B"
1,000
110
100
20.1
2.0
1.4
71.5
2.0
1.7
1.1
0.2
100.00
7.3
1.5
10.05
<0.25
*1.0
<1.0
1,748
5,115
2,997
3,010
8.78
3.00
5.12
5.10
111,440
337.590
206,790
216,720
1.06
1.10
1.15
1.20
Gas "C"
1,000
no
100
20.10
2.00
1.40
63.01
8.43
3.71
0.82
0.53*
100.00
7.3
1.5
10.05
<0.25
<1.0
<1.0
1,790
5,115
2,997
3,010
8.57
3.00
5.12
5.10
125,960
337,590
206,790
216,720
1.17
1.10
1.15
1.20
Gas "D"
1,000
110
100
51.5
3.5
8.6
25.8
5.8
3.2
1.6
1.00.00
8.4
3.1
14.71
<0.25
<1.0
Cl.O
2,366
12.-730
7,460
7,490
16.14
3.00
5.12
5.10
156, 000
840,180
514,740
539, 280
1.10
1.10
1.15
1.20
Gas "Z"
1,000
110
100
0.10
18.00
0.70
80.94
0.17
0.05
0.04
100.00
0.0056
<0.?5
2.0**
<1.0
2,167
4,190
2,455
2.465
5.24
3.00
5.12
5.10
99,600
276.540
169,400
177,480
0.77
1.10
1.15
1.20
* Includes 0.02 Mol. 7. arranatics.
** 2.0 mol. 7. COj for Sulfinol; < 1.0 tnol. 7. for all other processes.
(Courtsey: Campbell Petroleum Series and Dr. R. N. Maddox)
-------
29
Li cm Id-Swee tening Pro ce s ses
Liquid sweetening is also widely practiced in the natural-gas
processing industry.
Many of the gas-sweetening processes discussed previously also
serve to sweeten liquid hydrocarbons. Examples of such processes are:
(1) Molecular Sieve Process
(2) MEA Process (plus caustic wash)
(3) Adip Process.
The Molecular Sieve process is particularly suited to the simul-
taneous drying and removal of H S and CO- and is widely used. Maddox
describes other processes used in the sweetening of gasoline fractions
(hence, not used in natural-gas processing). These are the Merox Process,
Caustic Wash, Copper Sweetening, etc.
Environmental Effects of Liquid Sweetening
Atmospheric emissions and other environmental burdens are not sig-
nificant because, although the volume of plant liquids treated is significant,
the total amount of sulfur removed is small.
-------
30
IV. DESCRIPTION OF LESSER KNOWN SULFUR(H9S) REMOVAL PROCESSES
Many factors need to be considered when selecting a process for f-
a given sweetening application. These include: .
(1) The types of impurities to be removed from the gas {
stream. f
• ' \ -I--.
(2) The relative concentration level of these impurities i
and the degree of removal desired. v
(5) The feasibility and desirability of sulfur recovery. f/
(6) Relative economics of the suitable processes. . :•;.'
Acid gas constituents present in most natural gas streams are rf-
f •
hydrogen sulfide and carbon dioxide. Many gas streams, however, particularly |.
those in a refinery or for manufactured gases, may contain mercaptans, '/-
$
carbon disulfide and/or carbonyl sulfide. Any of these constituents f.
present in the gas stream will lead to irreversible reactions, degrada- £:>'
tion of sweetening solution or non-removal of the acid gas constituent f
£
which may cause many processes to be ineffective or economically unattractive. !
The level of acid gas concentration in the sour gas is an [,.
!'••'•
important consideration for selecting the proper sweetening process. Some $
processes are applicable for removal of large quantities of acid gas; }•'
however, many of these processes, will not sweeten to pipeline specifications. |
Other processes have the capacity for removing acid gas constituents to the i"
parts per million range - although some are applicable only to low concen- !,
trations of acid gas constituents in the sour gas to be treated. £
u
The selectivity of a sweetening agent is an indication of the j
degree of removal that can be obtained for one acid gas constituent as '
opposed to another. There are sweetening processes which display rather
marked selectivity for one acid gas constituent. In other cases there ]
is no selectivity demonstrated and all acid gas constituents will be removed. ;
There are processes for which operating conditions can have a marked effect ,.
-------
31
on ihe .selectivity exhibited. Some sweetening agents absorb relatively
large amounts of hydrocarbons while others are much more selective for
the acid gas constituents.
Only rarely will natural gas streams be sweetened at low pressures.
Moreover, there are processes which are unsuitable for removing acid gases
under low pressure conditions. Other processes are adversely affected by
temperatures much above ambient. Some processes lose their economic
advantage when large volumes of gas are to be treated.
The major processes described earlier have gained acceptance
because among other reasons they are very flexible in their application.
However there are numerous not-so-widely used processes examples of which
are: (1) the Purisol Process licensed by Lurgi, (2) the Iron Oxide (sponge)
Process, (3) Many of the carbonate processes including the Giammarco-
Vetrocoke Process, and (4) the Fluor solvent process licensed by the Fluor
Engineers and Constructors. All these processes, used more in Europe than
in the U.S., show high selectivity for either H S or C0~. For example,
the iron oxide process is completely selective to H~S; thus a gas from
which only H_S needs to be removed, other conditions favoring, could be
treated by iron sponge process. Basically therefore, the lower cost and
selectivity determine the justification for the minor processes. It is
emphasized that to generalize on which process to employ for a general range
of input and output of H7S concentration In natural gas Is almost imoossible.
Every gas stream will have to be analyzed with reference to as many processes
as necessary to derive the factors required to make a proper process
selection. This is a major process selection project for each gas well
or combination of wells in a field.
Minor Desulfurization QUS Removal) Processes
A brief description of the four lesser known processes is provided
below and detailed flow sheets are presented in Appendix B.. The four
processes are listed in Table 8 with possible reasons for the choice of each
process in a given processing situation.
-------
TABLE 8. LISTING OF LESSER KNOWN GAS DESULFURIZATION PROCESSES
Process Name
and Licensor/Seller
Approximate Reasons for the Choice of Process
Number of Units Installed
PURISOL
Lurgi Mineral
GMBH
IRON SPONGE (OXIDE)
Sold by many in-
cluding National
Tank Company, Tulsa,
Oklahoma
(918) 663-9100
FLUOR SOLVENT
Fluor Engineers and
Constructors
- Good selectivity for H_S or C02 can be achieved
- Low temperature (ambient) operation
- Low circulation rate for a given situation
- C02 removal by pressure let down
- Excellent solvent stability
- Nontoxlc fumeless operation
- Removes efficiently trace amounts of H^S in gas
- Batch process has low investment and operating
costs. Infinite turndown capability
- H2S removal independent of gas pressure
- Easily installed (wood chips coated with iron
oxide is packed in any available cylindrical
column).
- The used iron oxide is thrown away as solid waste
or burned
- Very low capital costs ($20,000) for a system with 10
grains/100 scf H2S at 2 million scfd of gas.
- Low solvent loss due to low vapor pressure of poly-
propylene carbonate
- High capacity solvent, which absorbs acid by gas by.-
physical solution, permits solvent regeneration
simply by pressure let down of rich solvent,
usually without the application of heat.
- Solvent breakdown rate is virtually zero
- Carbon steel is used in construction
- The process is favored when the combined partial
pressure of C0£ + H2S is>5 atm; and when the
heavy hydrocarbons are low.
2 Units in Natural gas
outside the U.S.
None in U.S. in natural
gas
2 units in hydrogen
manufacture in the U.S.
More than 200 batch units
in operation. However,
the construction is so
simple and costs so low
that builders cannot
justify maintaining
record of installations
7 plants in natural gas
1 plants in ammonia pro-
duction
2 plants in hydrogen pro-
duction
-------
TABLE 8. (Continued)
Process Name
and Licensor/Seller
Approximate Reasons for the Choice of Process
Number of Units Installed
GIAMMARCO-VETROCOKE
(Power-Gas Ltd.)
Treating costs about half the costs of most other
processes (hot carbonate, MEA).
Low capital costs
Low corrosion of G-V plants
No solution degradation
Process not applicable if H~S content is above 1-5
volume present
Treated gas has low H?S content of 1 ppm (0.06
gr/100 scf)
Process can operate at pressures as low as atmos-
pheric and temperatures up to 150 C.
One plant in natural gas
in the U.S. (West Texas)
Used mostly in Europe.
Use of the process in the
: U.S. is not likely to
increase because of the
arsenic used in ab-
sorption solution.
-------
34
Purisol Process
Detailed flow sheet, process description and operating conditions
are presented in Appendix B. The process is applicable to the removal of
acid gases (H2$ + C02) from Syngas (synthetic gas) and natural gas
streams using physical absorption in N-Methyl-Pyrrolidone (NMP).
Iron Sponge (Oxide) Process
Detailed flow sheet, process description and operating conditions
are presented in Appendix B. This process is well suited for removal of
H?S when it is the only undesirable component of natural gas. The process
does not generate atmospheric pollutants because the sulfur formed in the
iron oxide bed can be disposed of in a landfill, providing that a suitable
landfill site away from water ways (both surface and underground) is
available.
Fluor-Solvent Process
Detailed flow sheet, application and process description are
presented in Appendix B.. The process is excellent for the removal of high
concentration of acidic gases (when the combined partial pressure of
C0_ + H-S is about 5 atmospheres or higher). The processing arrangement
can be modified to suit the degree of purification required for both
H-S and CCL. Solvent regeneration is inexpensive and solvent carrying
capacity is high because of the sufficient free refrigeration obtained by
expansion of the acidic constituents. The process does not require special
or exotic materials of construction.
Glammarco-Vetrocoke Sulfur Process
Detailed flow diagram, application, process description and
operating conditions are presented in Appendix B. The process produces
-------
35
sulfur as a precipitate directly by continuous scrubbing of H S with an
alkali arsenates and arsenites solution.
The main drawback of the process for gaining acceptance in the U.S.
is the use of arsenlte compounds in the scrubbing solution. In addition, if .:
• ' ' »,'*J
both CO. and H-S are present, two separate treating units are required. The J ;i
process is used widely in Europe and other countries.
Level of Sulfur Compounds in Treated
Natural Gas Attainable by Various Processes
The level of sulfur compounds attainable by the 18 processes de-
scribed earlier is summarized in Table 9. Obviously, there are data gaps.
It should be noted that the extent of removal of H_S and other compounds de-
pends on the partial pressure of these compounds and the careful design of
' if
the process to attain that level. ' • a'
In general, the gas industry can confidently state the specific
level of H S attainable in the product natural gas. However, since the gas
industry was not particularly required to concern itself about the concen-
tration of other sulfur compounds in product natural gas, insufficient exact
data on the levels of COS, CS-, and RSH exist. Recommended levels of sulfur
compounds as maximum permissible concentrations in natural gas sold as in-
dustrial and residential fuel are presented in Table 10.
Based on the fact published by the AGA* that about 8 percent of the
gas is sold to industry and commerce, a 64-ppm total sulfur level (4.0 gr/100
scf) would have resulted in a sulfur emission of 12 MT/D by natural gas com-
bustion during 1973. This quantity of emission (0.009 million MT/Y as SO ) | 1
*• 1' A
is very insignificant in comparison with national SO emission data presented
in Table 16. The insignificance of this quantity will be more pronounced
due to the area source nature of the emissions.
* GAS FACTS - 1971 data, American Gas Association, Arlington, Virginia.
-------
36
TABLE 9. APPROXIMATE LEVEL OF SULFUR COMPOUNDS IN TREATED
NATURAL GAS WITH VARIOUS PROCESSES
Process
Name
Level of Sulfur Compounds
In Treated Natural Gas (ppm) ^a'
H2S COS CS2 RSH Sulfur^
Source of
Information
Major absorption
mode used in
removal
MEA (aqueous)
Physical Chemical Chemical Physical
<4 <2 <2
Industry
Expert
DEA (aqueous)
DGA
Sulfinol
SNPA-DEA
ADIP
Benfield
Catacarb
Selexol
Rectisol
Mol-sieve
GV-Sulfur
Stretford
Sulfreen
Purisol
Ironoxide
Flour Solvent
(,'/- Sulfur
<4 <5 <5 60% 10-16 w
<4 (d) (d) (d) (d)
<4 <2.0 <1 >90%^C' <10 "
Removal
<4 <2.0 <1 50%(C) <10(b)
<4 <1 <0.5 60JP <10 "
<4
0.8 1.0 Union Carbide
Bulletin F-86
<2
<0
<0.4
<0.1
<0.4
<0.4
(a) Blank spaces signify data not available.
.(''.') Depends on inlet roercaptan (RSH) levels.
(<-) Indicates percent RSH removed.
;-.-.) Mo definite levels can be specified. Mr. Dingman (see Appendix F) is of the
.•-yi.'i.'xion ?,hat the feed gas conditions ,'-?i.d composition should be kno^vn to arrive
at: "U:V'-:1;-; of these compounds that can be attained.
-------
37
TABLE 10'. RECOMMENDED MAXIMUM CONCENTRATION OF SULFUR COMPOUNDS
IN NATURAL GAS SUPPLIED TO GAS TRANSMISSION SYSTEMS
FROM NEW PROCESS PLANTS(a)
Maximum
Concentration,
Name of Compound ppm
Hydrogen eulfide (H2S) 16
Carbpnyl sulfide (COS) (b)
Carbon disulfide (CS2> (b)
Mercaptans (RSH) (b)
Total sulfur (S) 64
(a) These concentration limits apply to new
gas processing plants only.
(b) The allowable concentration of COS, CS-,
mercaptans, and other sulfur compounds shall
be such that the total sulfur content of the
treated gas (which determines the ambient SO.
emissions) shall not exceed 64 ppm (4 grains/
100 scf).
(c) The intent of this limitation on total sulfur
is to limit sulfur emissions to atmosphere when
the natural gas is burned as fuel. Therefore,
when the same gas processing facility produces
sour and sweet gases both feeding to a common
transmission system, the recommended total
sulfur limitation may need adjustment. Such
adjustment shall Include the permitting of a
higher total sulfur concentration in treated
sour gas such that its admixture with the
sweet gas at the pipeline inlet will not
result in a total sulfur greater than 64 ppm
in the gas mixture. Also, in those rare cases
when the concentration of mercaptans in sour
gas exceeds 400 ppm, the allowable total
isulfur limit shall be adjusted to account for
the fact that the best control technology
limits mercaptan removal to 90 percent of
inlet mercaptan level.
-------
38
V. COMPARATIVE DESCRIPTION OF SULFUR REMOVAL AND PRODUCTION
PROCESSES IN NATURAL GAS AND REFINERY GASES
The choice of processes used in desulfurization of natural and
refinery gases is based on the following parameters.
(1) Gas composition
(2) Gas volume
(3) Required degree of removal of undesirable constituents
in the gases
As discussed earlier, there are 14 major processes and at least
four minor processes in use for the removal of H»S in the natural gas
processing industry. Generally, the product from these 18 processes is an
acid gas (a mixture of H_S 4- CO,,) which is further processed in a sulfur
plant to pure sulfur which is sold when a ready market is available. The
tail gas from the sulfur plant may need to be further treated by use of
one of the many tail gas treatment processes which have been recently
developed. Examples of tail gas treatment processes are: (1) the IFP,
(2) the Wellman-Lord S02 removal process, (3) the Clean air process,
(4) the Beavon process, and (5) the SCOT process, etc.
A recent Battelle study^ indicates that processes for removal
of H S from refinery fuel-gases are: (1) the Shell Adip, (2) Girdler's
Girbotol*, (3) DBA, (A) Fluor Econamine, and (5) the Shell phosphate process.
Not included among these five fuel-gas treatment process is the Stretford
process which is a direct oxidation process for removing H2S to obtain sulfur
as the product directly.
The four processes (Adip, MEA, DBA, and Econamine) which have com-
mon applicability to both the natural gas and the refinery gas desulfuriza-
tion needs have been described earlier in Table 8 and Appendices A and B.
An industry expert is of the opinion that the Shell phosphate process is not
* Same as MEA Process.
-------
39
in the current list of processes readily offered for licensing. However,
this process will be s-old if specific demand exists which happens in certain
unusual situations. The older units using this process are still working
well.
It appears therefore that the process for I^S removal used
in the natural gas industry and in the refinery fuel gas treatment are
not significantly different. However while the process choices available
for natural gas industry are from more than 20 processes, the refinery
gases have a limited choice, the reasons for which are explored In
this chapter.
Factors in the Selection of I^S Removal Processes
The parameters in the choice of processes listed earlier can be
covered under three factors which govern the selection of processes for
hydrogen sulfide removal from refinery fuels.
Solubility of Organic Components of the
Fuel Gas In Absorption'Solvent
Natural gas has a much lower concentration of heavy hydrocarbons
(less than 1 percent of heptanes and heavier) than refinery fuel gases.
As an example, a catalytic-cracker gas contains more than 10 percent of
heavy hydrocarbons which tend to be soluble or otherwise be held in the
absorption solvent used in the H S removal process. The Shell Sulfinol
process is a typical example in which the solvent (sulfolane, di-isopropanol
amine, and water) tends to absorb heavy hydrocarbons from the feed gas,
especially the aromatics.
By contrast, the solvent in the Shell ADIP process (di-isopropanol
amine) and the DEA process (diethanolaraine) have a very low solubility for
almost all hydrocarbons because among other reasons, the solvents are used
as aqueous solutions (Ca 75 percent water by weight). This Is one of the
reasons for the very wide use of ADIP and DEA In cleaning of refinery fuel
-------
40
gases. Very few solvents have low solubility for heavy Hydrocarbons while
at the same time maintaining good desulfurization ability. The MEA, DBA,
and ADIP processes appear to be about the only processes that are being
widely used in refinery fuel gas cleaning for this reason.
Presence of Sulfur Species Other Than
H,S in Untreated Gas
__£ ; . .
In general, the concentration of non-H S sulfur species is higher
in refinery-fuel-gas streams than in natural-gas streams because the re-
finery cracking reactions generate these sulfur compounds*. Consequently,
refinery-fuel-gas streams tend to severely degenerate certain solvents used
in H S removal. Such degeneration is generally not a serious problem in
natural-gas streams. The Sulfinol process, quite widely used in natural-
gas treating, is substantially immune to solvent degeneration^ ; the cost
of solvent, however, is high. The MEA solvent is subject to heavy degenera-
tion by carbonyl sulfide (COS), etc., and hence, is seldom used in refinery-
gas cleaning where the concentration of COS, etc., in the gases is quite
high; DBA and ADIP are not subject to degradation by COS and are therefore
favored for refinery-fuel-gas cleaning. This is one additional factor con-
sidered in process selection.
Required Degree of Removal of Sulfur Compounds
Pipeline companies have set the H~S level in natural gas by the
quarter-grain or one-grain concept (0.25 grains or 1.0 grain H2S per 100
scf equivalent to 6 or 23 mg/s cu m). However, no such strict limits for
H S content exist for refinery fuel gases because they are burned as plant
•
fuel on site and do not need to be piped to customers. Further, the total
sulfur level in natural gas is usually also limited by sales agreements for
natural gas to about 10 to 20 grains/100 scf. By contrast, the total sulfur
level in refinery gaseous fuels can be as high as 100 grains/100 scf and
the H S level can also range from 1 to 50 grains/100 scf. These facts tend
* Carbonyl sulfide (COS), carbon disulflde (CS ), etc.
-------
41
to favor the selection of desulfurizatlon processes that have low overall
cost and lower sulfur removal efficiency for refinery-fuel treating. The
Shell ADIP process has the ability to be designed for both low- and high-
H S removal. However, the need for more effective removal of sulfur com-
pounds like COS, CS , etc., is greater in natural-gas treatment. Thus, the
sulfinol for example has a greater applicability to natural-gas treatment.
Other Factors in Process Selection
The extent of carbon dioxide present in natural-gas streams is
also a factor in the selection of the gas-treating process. Some natural-
gas streams contain very high (50 percent or more) roncentrations of CO
and low concentrations of H S which favor the use of a modified (promoted)
carbonate process. Similarly, if the refinery fuels contain high CO. levels,
the selected cleaning process will have to deal with removal of the high C02
levels. Outside the U.S., the GV-carbonate removal process is widely used
for this situation.
The above factors do not cover all of the aspects involved in
the selection of a process. Process selection is an expert area and
detailed process engineering, design, and economic analyses must precede
the selection of a process.
Methods of Sulfur Production in Natural
arid Refinery Gas Applications
Two different principles of sulfur production from H_S are in
current use: (1) direct vapor phase oxidation-reduction and (2) liquid
phase absorption-oxidation.
Direct Vapor Phase Oxidation Principle
The well known Glaus process employs this principle of oxidation-
reduction as follows:
H2S + 3/2 02 —^> H20 + S02 (oxidation)
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42
2H0S 4- SO -__^2H.O + 3S (Reduction)
/ z /
If the acid gas (or feed to Claus plant) contains hydrocarbon
compounds, the following undesirable reactions also take place
CH. + S00 ^»COS 4- H00 + H0
42 22
CO + S 5*—-COS
2CO
Carbonyl sulfide (COS) and carbon dlsulfide (CS.) are the undesirable
constituents contributing to tail gas sulfur.
It also is quite likely that in the presence of hydrocarbons,
the following reaction will occur
3CH4 + 3/2 02 - > 4H2 + CO + 2C + 2H20.
This reaction can use up the air supply as well as blind the catalyst with
carbon soot.
The Claus plant has found wide acceptance in both the refinery and
natural gas industries. The choice of the Claus plant is simply a function
of the availability of enough acid gas feed to the unit. Eighty- four Claus
units (Appendix I) are installed in natural-gas processing with a total
(9)
capacity of 6250 MT/D . The number of Claus units in refinery-gas sulfur
^
recovery is about 200, with a total production capacity of 8000
Detail e.d description of a Claus plant with three catalytic stapes
o f co nv e r. y i. on : ;: p r e. •-, eo t e d in A p i : \ • IK! i x C .
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43
Glaus Sulfur Plant Capacity VS Production Rate
(9)
According to the data presented in Appendix I (List of Glaus
Plants in Natural Gas Processing), as of April, 1973, there were 84
sulfur production units in natural gas processing with a total design
capacity of 6,250 MTD. However eight of these plants with a total
capacity of 660 MTD were stand-by units. Further, available production
data for 1972 indicate that in most cases, the actual production was
about 50 percent of design capacity. This may be due to the reduced gas
output coupled with initial optimistic overdesign of the Claus units.
The sulfur production data (2443 MT/D) reported in a later Section
(Table 14) is in reasonable agreement with estimated data from Appendix I*
assuming average production to be about 50 percent of plant design capacity.
There are 31 Claus plants with design capacity greater than
or equal to 50 MT/D. If 50 MT/D is arbitrarily chosen as the cut point
at which tail gas cleaning requirement would be deemed necessary then
a total of 35 tail gas units could be expected in natural gas processing
industry. The rationale for chosing a 50 MT/D plant as the cut off point
is that 94% Claus plant efficiency, the tail gas unit will have at least
3 MTD of sulfur production. This will be discussed in greater detail
in a later Section.
Sulfur Recovery Efficiency of Claus Plants. A considerable
amount of study on the present and potential efficiencies of Claus plants
has been conducted by the companies connected with sulfur production and
recovery in the Province of Alberta, Canada. It is only natural that such
study has been initiated in the Alberta area which is the world's leading
sulfur production center.
(2)
Rankine et al contend that theoretical calculations and field
scale experiments together clearly demonstrate the potential of the Claus
*(6250-660)/2 * 2795 MT/D = (Total Glaus plant capacity - Capacity of standby
units) x (Plant utilization factor of 0.5). This "reasonable" agreement
implies that almost all of: the Claus plants in natural gas processing are
listed in Appendix I.
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44
process to achieve efficiencies well in excess pf the present of 90-97
percent. In their opinion more research should be directed to the
exploitation of the Glaus plant's potential for increased efficiency.
On the contrary, so far, most of the research effort has been directed
towards development of new process intended to augment Glaus plant
efficiencies.
(2)
The study model has led to the definition of several criteria
for optimum Glaus plant performance; namely
(1) Each sulfur condenser should operate at about
260°F which provides a margin of about 20°F
above the freezing point of sulfur.
(2) Mist elimination equipment should be utilized
in interstage sulfur condensers as well as in
the final condenser.
(3) Methods of reheat which introduce sulfur com-
pounds into the main gas stream should be
avoided. This is in adherence to the principle
that optimization implies all sulfur compounds
are introduced as far upstream in the plant as
possible.
(4) The operation of each converter should be
adjusted so that the actual and dew point
temperatures converge at the converter outlet.
They conclude that these criteria have not been generally adhered
to in the design and operation of existing Glaus plants. Finally, the
thermodynamic recoveries from a four stage Glaus plant processing a feed
containing 67 percent hydrogen sulfide were predicted as follows.
2 Catalytic Stage Recovery 97.9 percent
3 Catalytic Stage Recovery 99.1 percent
4 Catalytic Stage Recovery 99.A percent
The optimum yields for the lean-feed case (H.S content of 10 to
50%) were predicted to be not significantly different. These efficiencies
are based on the following practical factors.
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45
(1) Furnace conversion cannot be predicted thermo-
dynamically. In this example a value of 60
percent: was chosen. This is lower than that
which is generally observed.
(2) The gas off the first sulfur condenser was
assumed to be 330°F.
(3) In consideration of certain side reactions,
which must proceed in the first converter,
an outlet temperature of 625°F was chosen.
This temperature is well above the sulfur dew
point.
The above predictions were tested in June, 1972 by the Western
Research and Development Ltd. Calgary, Alberta on a Claus plant of 1600 MT/D
capacity. Pertinent results of the field test are summarized in Table 11.
The agreement between actual and theoretical conversion and
recovery tends to support the view that Claus plants can be operated at
high enough conversion efficiencies to obviate the need for tail gas
cleaning in most cases.
However, conversations with the Ralph M. Parsons Company, Los
Angeles, California indicate that guaranteed efficiency of sulfur recovery
cannot be made in excess of 97% (for new Claus plants). For old plants
with efficiencies in the range of 90-97%, increasing the efficiency by any
method will cost from 80 to 100 percent of the cost of a new Claus plant
of equal capacity.
These discussions show the problems and potential solutions to
improve H~S conversion to sulfur in Claus plants. The other method of
improving Claus plant efficiency is to use a tail gas unit. The variety
of tail gas units available is described in a later section of this report.
Sulfur Recovery by Liquid-Phase Absorption-Oxidation Principle
Three processes using this principle are described in detail in
-------
TABLE 11. SUMMARY OF CLAUS PLANT FIELD TESTS
(2)
Operating Temperatures C
Conversion* Recovery*
Stage
Thermal Stage
Catalytic Stage //I
Catalytic Stage #2
Catalytic Stage #3
Catalytic Stage #4
Total
Feed
98.31
0.48
0.43
0.78
-
100.0
Actual
66.6
91.3
97.5
98.9
99.3
99.3
Theoretical Actual
-
90.9
97.3
98.8 98.6
99.3 99.1
99.3 99.1
Theoretical
-
89.1
95.9
98.6
99.1
99.1
Condenser
Outlet
190.6
176.7
165.6
137.8
123.9
-
Converter
Outlet
-
310
215.6
190.6
171.1
-
Maximum
Dew Point in
Converter
-
248.9
207.2
179.4
148.9
-
* Cumulative plant performance index in which all parameters are expressed as percentage of total plant feed.
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47
Appendix C. These are the G-V sulfur process, the Stretford ADA vandate
process, and the Takahax process. Although all these processes are in
commercial operation as described in Appendix C, only the Stretford process
appears to be important in the U.S. and will be discussed below.
The Stretford Process. The reactions upon which this process is
based are essentially insensitive to pressure. Operating temperature through-
out the unit are in the range of ambient to 49 C. A summary of the reactions
is given below.
(1) Absorption of H2S
H2S + Na2C°3 ~* NaHS + NaHC03 '
(2) Precipitation of sulfur
2NaVO + NaHS + NaHC03 -> S
(3) Regeneration of sodium vanadate
Na2V2°5 + ADA (°xidtzed) "* 2NaV03 + ADA (reduced) .
(4) Regeneration of ADA
ADA (reduced) + ^p (air) - ADA (oxidized) .
(5) Overall reaction
H2S + 2°2 ~* S + H2° '
COS and CS2 are not recovered by the Stretford process and this
reduces the overall sulfur recovery. Otherwise the Stretford solution is
quantitative for the removal of H-S. Some adverse side reactions occur
due to peaks in loading (increased liquor temperature) and trace oxidizing
gases contained in the fuel gas (notably oxygen, SO-, and HCN) and result
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48
in the buildup of sodium thiosulfate and related compounds in the circulating
liquor which must be purged from the system. A typical analysis for the
purge stream is shown in Table 12*. The rate of thiosulfate formation depends
on the partial pressure of oxygen in the inlet gas stream, and the pH and
temperature of the liquor. Formation of thiosulfate is quite low below
about 38 C.
Disposal of Stretford Purge Solution. Currently, the Stretford
purge stream normally is disposed of by discarding it to an industrial
sewer. A process alternative that is being developed by Nittetu Chemical
Engineering, Ltd. (NICE) involves treatment to reclaim the sodium value as
(12)
Na~CO. (see Figure 4). As shown in the diagram, waste liquid removed
from the desulfurization plant is first fed to the evaporator operated at
60 C and a vacuum of 100 mm. Hg (abs), where the salts are preconcentrated
to about 50 weight percent. The evaporator heat source is quenched-
combustion-gas obtained directly from the quenching tank at a temperature of
about 90 C.
The concentrated waste liquid is then sprayed into the incinerator.
Combustion of an auxiliary gas maintains the incinerator at 850 C in a
reducing atmosphere. The reducing conditions are maintained by limiting
the oxygen feed at 70-80 percent of the theoretical amount required for
combustion. At the designated residence time, most of the sodium salts
decompose to Na«CO- and NaHCO»; they are then blown into the quenching tank
along with the hot combustion gas.
The quenching tank carries out two tasks: quenching of the hot
combustion gas that is blown from the incinerator, and the capture of sodium
salt contained in the gas, mainly Na^CO.,. Quench and makeup water for the
reconstituted Na^CO, solution is fed through the gas-blowing duct between
the incinerator and the quenching tank. The Na^CO- solution is continuously
removed from the tank and used as absorbent in the H-S absorber.
* Private communication from Charles Sedman, EPA, Durham,.N.C. to Joseph
Genco, BCL, Columbus (December, 1973).
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49
TABLE 12. TYPICAL COMPOSITION OF
STRETFORD PURGE SOLUTION
Composition Wt. Percent
Na2C03 0.47
Na-ADS(b) 0.07
Na-Meta Vanadate 0.03
Na-Citrate 0.03
Na2S2°3 °'6°
NaSCN 0.60
HJD 98.20
(a) Purge solution approximately 1.5 to 15
gal/100 moles of feed gas to the absorber,
(b) Na-anthraquinone disulfonate.
-------
DESULFURIZATION SECTION
INCINERATION AND SODIUM RECOVERY SECTION
Concentrated
waste liquid
Fuel gas
Exhaust gas
(for fuel)
COG
Combustion
gas (contains
Gas
cooler 50 C
kJ
Incinerator
Quench Tank
Coke oven
gas (to be
treated)
Compressed
Condensate
Waste liquid
(to be
incinerated)
Na2C03
Receiver
Recovered liquid (contains NaHS)
in
o
FIGURE 4. TREATMENT OF STRETFORD PROCESS PURGE SOLUTION
(12)
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51
The combustion gas, with sodium salts removed, is drawn out of
the tank at approximately 90 C. This gas contains about 8 volume percent
(dry basis) of H_S as well as such gases as H2, CO, and CH, and has a
temperature of about 75 C when discharged from the shell side of the
evaporator. It is cooled to about 50 C by a surface condenser and cooler
before being supplied to the H.S absorber.
The absorber is designed to return the absorbed H S that results
from incineration under the reducing condition to the oxidizer at the
desulfurization plant. There it is recovered from the filters as elemental
sulfur. The Na.CO- solution, recovered from the quenching tank, and the
absorbent from the desulfurization plant are both recycled. Indication
is that the NICE Process has been tried only at the pilot-plant level.
Tailgas Conditioning Processes
The six tail gas treatment processes in commercial use are listed
in Table 13. Detailed process description and flow diagrams are presented
in Appendix D.
Since tail gas processes are used to clean up the Glaus plant
effluent, the criteria of selection of any tail gas process are the same
for both natural gas and refinery fuel gas applications. As is the case
with any process selection problem, detailed design and economic evaluation
of several alternate processes for a given gas stream will be necessary to
arrive at the process giving optimum benefits.
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TABLE 13. GLAUS PLANT TAIL-GAS TREATMENT PROCESSES
Process
Beavon
Cleanair
IFP-1
SCOT
Sulfreen
Wellman-Lord
Developer/Licensee
Commercial Units in Operation
or Under Construction
Union Oil, Ralph M. Parsons
J. F. Pritchard, Texas Gulf Sulfur
Institut Francais du Petrole
Shell Development
Lurgi, SNPA*, Ralph M. Parsons
Davy Powergas
7 in operation and 6 under construction
1 in operation and 3 under construction
12 in operation and 5 under construction
2 in operation and 25 under construction
3 in operation and 4 under construction
2 in operation and 6 under construction
tn
K>
* Societe Nationale des Petrole d'Aquitaine.
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53
VI. ASSESSMENT OF SULFUR RECOVERY IN NATURAL GAS PROCESSING
Natural gas and liquid processing plants reporting sulfur
recovery for 1972 are listed in Table 14 '. Accordingly 24 states
in the U.S. processed natural gas; however, sulfur recovery from sour
gas was done in only seven of these states, namely, Arkansas, Florida,
Mississippi, New Mexico, North Dakota, Texas, and Wyoming. The total
sulfur recovery amounted to 2443 MT/D (metric tons/day also equal
to kkg/day) and the associated gas throughput volume x/as 33
MMscumd (1162 Million scfd). Thus the average t^S concentration in
the gas processed for sulfur recovery is computed -o be about 5.5 volume
percent or 35 grains per scf. A salient summary by state is also
i
presented in Table 15.
The following points of significance are noted from Tables 14
and 15.
(1) Total sour gas (33 MMscumd) is only about two
percent of the total daily gas production rate of
1608 MMscumd (56787 MMscfd).
(2) Nearly 100% of the gas produced in 17 states in-
cluding Louisiana, California, Kansas, Oklahoma
is sweet.
(3) The total sulfur produced by the gas processing
industry is about one million tons per year. If
the Claus> plants used in this production is
assumed to be 95 percent efficient, the emissions
from the industry would be 50,000 tons of sulfur
per year in 1972. Comparison of this emission with
the total SO, emissions for the nation as a whole
(7)
represented by the Council on Environmental Quality
(CEQ) is made in Table 16. Accordingly S0_ emission
from natural gas processing is 0.30% of the total
national S00 emissions during 1972-1973.
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TABLE 14. NATURAL GAS AND LIQUID PROCESSING PLANTS
REPORTING SULFUR RECOVERY (1973)
(1,6)
State
Arkansas
Florida
Mississippi
New Mexico
North Dakota
Texas
Company and Plant
Arkansas Louisiana Gas Company
Hamilton Plant, Various Fields, Columbia
Exxon and other companies
Jay Field Facilities, Santa Rosa and Escambia Counties
Shell Oil Company - Goldwater Plant and Field, Clarke County
Thomasville Plant and Field, Rankin County, Jackson
Amoco, Empire Abo Plant and Field, Eddy County
Cities Services Oil Company, Bluitt Plant, Chaveroo, Roosevelt
County
Signal Oil and Gas Company, Tioga Plant, Williams County
Amoco, Edgewood Plant and Field, Van Zandt County
Midlands Farm Plant, Andrews County
North Cowden Plant, Ector County
Slaughter Plant & Field, Mockley County
South Fullerton Plant, Andrews County
West Yantis Plant. Wood County
City Services Oil Company, Lehman Plant, Cochran County
City Services' Oil Company, Myrtle Springs Plant, Van Zandt County
Robstown Plant, Nueces County
Simon X Perry's Subdivision of Fred Tract
Seminole Sulfur Plant, Seminole County
Welch Plant, Dawson County
Exxon Company, Jourdonton Plant, Atascosa County
Gulf Energy and Development Corporation, Powell Plant, Navarro
County
Odessa Natural Corporation, Foster Plant, Ector County
Sour-Gas
Production
(MMscumd)
0.9
3.7
0.17
0.40
0.68
0.85
2.12
0.86
1.00
2.6
0.82
0.51
0.37
0.76
0.59
0.79
0.05
0.62
0.30
0.54
Sulfur
Production
(MTD)
5.3
650
1.4
220
22
8
116
332
6
26
34
3
34
2
216
216
23
2
13.2
6
12.8
en
-------
TABLE ]&.. (Continued)
State
Company and Plant
Sour-Gas
Production
(MMscumd)
Sulfur
Production
(MTD)
Texas
Wyoming
TOTAL
Shell Oil Company, Bryan's Mill Plant, Cass County
Shell Oil Company, Person Plant, Karnes County
Warren Petroleum Company, Como Plant, Hopkins County
Warren Petroleum Company, Fashing Plant, Atascosa County
Warren Petroleum Company, Sand Hills Plant, Crane County
Warren Petroleum Company, Waddel Plant, Crane County
Amoco Production Company, Beaver Creek Plant, Fremont County
Amoco Production Company, Elk Basin Plant, Park County
Husky Oil Company, Ralston Plant, Park County
1.56
1.41
0.34
1.40
4.1
3.4
1.47
0.31
0.15
33.0
190
20
34.6
27.4
33.4
89.2
39
32
29
2,443.3
I/I
en
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56
TABLE 13. SALIENT DATA ON SULFUR RECOVERY
IN NATURAL GAS PROCESSING
State
Arkansas
Florida
Mississippi
New Mexico
N. Dakota
Texas
Wyoming
Total Sulfur
Production
(MT/D)
5.3
650
221.4
30
116
1,320.6
100
Associated (Sour)
Gas Throughput
(MMScfd)
31.9
130
20
54.3
74.8
783.0
68.2
Total 2,443.3 1,162.2
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57
TABLE 16.
COMPARISON OF S02 EMISSIONS FROM ALL SOURCES
S02 From Natural Gas As
Weight Percent of S0_ From
MT/Y Other Sources
Natural gas industry
CEQ Data ^ '
All industrial processes
Stationary sources using
fuel combustion
Transportation
Solid Waste Disposal
Miscellaneous
Total (except SO- from
natural gas
o.io(a)
5,1
26.3
1.0
0.1
0.1
32.6
-
2.35%
0.46%
12.0%
120.0%
120.0%
0.30%
(a) Based on an average sulfur recovery of 95 percent in existing Glaus
plants and on a total sulfur production from natural gas industry
of about one million tons per year (MT/Y). Texas and Louisiana
state laws require Glaus plants to achieve and maintain a minimum
of 94 to 97 percent sulfur recovery depending on the size of
the plant.
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58
Listing of Sour Gas Processes in Texas
Attempts were made to obtain accurate data on the extent of
unrecovered H~S emission from oil and gas processing plants in Texas.
Such information was theoretically available in the files of the Railroad
Commission of Texas*. Accordingly, this agency was contacted and
information on H?S emissions and sulfur production for 77 plants (GP-1
forms) in Texas was obtained. However, upon carefully checking the forms,
it was found that the information available did not differentiate between
the acid gas and H_S even though very often the acid gas contained 90 percent
C02. As a result, the data available in GP-1 forms were suspect. For
other states, no such data are available.
In summary, a statewide - plant wise emission inventory for H.S
requires a major effort. However, the objectives of this report do not
suffer due to the lack of such data because it has already been shown that
(1) small operators comprise only about 2 percent of the total gas processing
capacity, (2) the sour gas production is less than 5 percent of the total
gas produced in the U.S., and (3) a sufficiently accurate data on Glaus
plants producing sulfur for every state is available from which an estimate
of sulfur emissions can be made.
* See listing for Mr. James C. Bouldin in Appendix F. All plants processing
gas report to the Railroad Commission of Texas on Form GP-1 entitled
"Monthly Report for Gas Processing Plants".
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59
VII. OVERALL ASSESSMENTAND RECOMMENDED CONTROL OPTIONS
The US natural gas processing industry operates about 800
processing installations of three different size ranges described in
Table 17. The combined processing capacity of these installations was
1.6 billion/scumd as of January, 1973. Of this gas volume, 33 million
cumd was sour gas. Thus, sour gas represents about two percent of the
total gas volume. It is quite possible that many small gas plants
processing less than 0.3 million cumd of sour gas with low H-S (100 ppm)
concentration are not represented in this sour gas volume of 33 cumd.
But such unreported volume is not expected to be more than about a few
million/scumd) as a reasonable guess.
As reported in Section II, the H2S concentration in the sour
gas ranges from 100 to 106,000 ppm (0.25 to 270/gm/scum) although
isolated fields have produced natural gas with up to 600,000 ppm of H2S.
However H?S levels in processed sour gas which led to the production
(1)
of sulfur in 29 reported plants averaged 74 gm/scum. Of these 29
plants, four were small sized, 16 were in the intermediate size
rnage and 9 in the large size range of processing facilities. This
fact and other useful analytical conclusions are summarized in
Table 17.
Also presented in Table 17 is the effect of HLS recovery efficiencies
obtainable with Glaus plant and other processes on sulfur emission levels
for the three size ranges.
Effect of Claus Plant Efficiency on SO Emissions
The following conclusions can be drawn from the data in Appendix I
and Table 17.
(1) Small gas plants contribute 1.6 percent of the total
SO- emission from all the gas plants at the three sulfur
recovery levels of 95%, 97% and 99.5 percent.
(2) In absolute quantities, the reduction in S0_ emission from
small plants realized by increasing the sulfur
recovery efficiency from 95 percent to 99.5% will be
85,000 MT/Y and is not significant in comparison with
about 33 million MT/Y of S02 emission for the nation
as a whole.
-------
TABLE 17. ANALYSIS OF REPORTED DATA^ (1973) ON NATURAL GAS
PROCESSING PLANTS REPORTING SULFUR PRODUCTION
Classification of Natural Gas
Effect
(1) SO
i.
(2) S02
(3) S02
L*
Item
Size range MMscumd
No. of plants^1) (1972)
Volume of sour gas
Processed MMscumd
Sulfur produced MT/D (1972)
7o
Average t^S in raw gas
ppm
gm/scum
grains/lOOscf
of sulfur recovery efficiency
emission at 95%^' recovery MT/D
106MT/Y
7,
emission at 977
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61
(3) Intermediate and larj^e plants produce about the same
quantity of sulfur and benefits of increasing the
sulfur recovery from these sizes are about the same.
(4) If the current average Glaus plant efficiency is assumed
to be 95%, the natural gas industry at current sulfur
production levels contributes about 0.1 million MT/Y of
SO to the national SO emission of about 33 MT/Y.
Thus, about 0.3% of the national S0_ emissions are due
to the Glaus plants in natural gas.
(5) If the efficiency of all Glaus plants is raised to 97%,
the SO emissions would be reduced from 0.1 to 0.055
million MT/Y, i.e., to 0.17 percent o!: the total national
SO emissions. However, if the actual Glaus plant sulfur
production reaches the full production capacity indicated
in Appendix I, for the 84 plants, the SO emission at
97% Glaus plant efficiency will be 386 MT/D* which is
about 0.43% of the national SO emission level of 33
million MT/Y.
(6) If each of the 84 Glaus plants were allowed to emit 2
tons of sulfur per day, the total emission of SO. would
be 0.123 million MT/Y. This represents 0.37 percent of
the total annual national S0? emission.
Control Options and Performance Standards
The various control options available to reduce the emission of
H S and/or SO. in the natural gas industry depend on the degree of emission
reduction specified for each facility size. The required degree of emission
reduction is derived from the allowable sulfur emission that would not sig-
nificantly contribute to the national SO- emissions. These factors
* 386 MT/D = (2) x (6249) (100-97)/97 since one ton of sulfur (S) produces
two tons of sulfur dioxide (SO.).
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62
determine the needed performance standards Cor sulfur recovery units in
natural-gas processing.
The control options possible for three hypothetical levels of
allowable emissions are shown in Tables 18 through 20. In all of the hypo-
thetical, allowable levels* A, B, and C, seven control categories result.
The various control options suggested are:
(1) Reinjection of acid gas
(2) Iron oxide process
(3) Molecular sieve process
(4) Packaged Glaus plant
(5) 2- and 3- and 4-stage Glaus plant
(6) Tail-gas units with Glaus plant.
Each of these options is briefly discussed below.
(A) Reinjection of Acid Gas or Separated Sour-
Gas to Well Formations
Reinjection is possible and economically feasible when it assists
a production field in secondary gas/oil production and when the wells in the
field are unitized. The decision to reinject is up to the gas processors.
(13)
There is one facility practicing reinjection in Alberta . Some of the
problems of handling H.S under high pressure are listed in Appendix H. A
brief summary of the reinjection problems is listed below.
The most serious problems to be encountered in reinjection of the
separated sour gas or of the treating plant regenerator off gases are:
(1) Dehydration of gas prior to handling in injection
service.
(2) Hazards associated with handling high-pressure toxic
material like H S and CO .
(3) Costs associated with the designing and installation
of a safe, noncorrosive system, in unitizing the mineral
rights of the receiving subsurface formation, and pro-
tecting the producing wells bottomhole equipment which
would be exposed to the high concentration of acid gases
in the producing reservoir after reinjection.
* Defined in Tables 18, 19. and 20.
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TABLE 18. CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION LEVEL "A"
Gas Plant Size Sulfur Allowable
Control as Sweet Gas Production Sulfur
Category Production Rate Rate Emission
Number MMscumd hMscfd MT/D MT/D
1 Any Any £1.0 1.0
2 ^0.3 <10.5 >1 to 410 1.0
3 ^0.3 O-0.5 >10 -
4 >0.3 but >10.5 but >10 but 1.0
$1.13 £40 440
5 >0.3 but >10.5 but >40
^1.13 ^40
6 >1.13 >40 40 to 500 1.0
7 >1.13 >40 >500
Required
Sulfur
Recovery
Efficiency
0
0% at 1 MT/D
90% at 10 MT/D
94%
90% at 10 MT/D
97.5% at 40 MT/D*
97.5%*
97.56% @ 41 MT/D*
99.00% 97.5 percent would require
tail gas cleaning systems. The cost of such systems range from 80 to 100 percent of the cost of the Claus plant.
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TABLE 19. CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION LEVEL "B"
Gas Plant Size
Control as Sweet Gas
Category Production Rate
Number MMscumd MMscfd
Sulfur Allowable
Production Sulfur
Rate, Emission,
MT/D MT/D
Required
Sulfur
Recovery
Efficiency,
percent
Control Options
3
4
Any
£0.3
£0.3
>1.13
Any
<10.5
<10.5
>0.3 but >10.5 but
£1.13 £40
>40
£2.0
>2 to £10
>10
>0.3 but >10.5 but >10, £40
£1.13 £40
>40
40- to 500
2.0
2.0
2.0
2.0
0
0% at 2 MT/D
80% at 10 MT/D
£80%
80% at 10 MT/D
95% at 40 MT/D
95% at 40 MT/D
98% at 100 MT/D
99% at 200 MT/D
99.6% at 500 MT/D
Tall stack dispersion when
ground level concentration
of H2S/S02 is high
(1) Reinjection of acid gas
(2) Iron oxide process
(3) Molecular sieve process
(4) Packaged Claus plant
Packaged Claus plant
Packaged Claus plant
2-stage Claus plant
3-stage Claus plant
2-stage Claus plant
Claus plant + tail gas
Claus plant + tail gas cleanup
Claus plant + tail gas cleanup
>40
>500
£99.6%
Claus plant + tail gas cleanup
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TABLE 20. CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION LEVEL
Control
Category
Number
1
Gas Plant Size
as Sweet Gas
Production Rate
MMscumd MMscfd
Any Any
Sulfur
Production
Rate,
MT/D
£2.0
Allowable
Sulfur
Emission,
MT/D
2.0
Required
Sulfur
Recovery
Efficiency,
percent
0
Control Options
Tall stack dispersion when
3
4
<0.3
<10.5
, £10
<0.3
<10.5
X).3 but >10.5 but >10, £20
£1.13 £40
X).3 but >10.5 but
£1.13 £40
>20
2.0 0% at 2 MT/D
80% at 10 MT/D
90%
1.0 90% at 10 MT/D
95% at 20 MT/D
95%
ground level concentration
of H2S/S02 is high
(1) Reinjection of acid gas
(2) Iron oxide process
(3) Molecular sieve process
(4) Package Glaus plant
2-stage Glaus plant
2-stage Glaus plant
3-stage Glaus plant
6 >1.13 >40 20-500 2
3
4
5
7 >1.13 >40 >500
95% at 20 MT/D
97% at 100 MT/D
98% at 200 MT/D
99% at 500 MT/D
2:99%
2-stage Glaus plant
4-stage Glaus plant
Glaus plant + tail gas cleanup*
Glaus plant + tail gas cleanup*
Glaus plant + tail gas cleanup
* The 98% to 99% efficiency may be attainable with the LFP-1 tail-gas cleanup process which appears to
have a much lower overall energy and capital requirement.
on
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66
(4) The cost of installing adequately rated equipment in
high-pressure service. This cost depends on the geometry
of the system as well as the injection pressures required
and the volumes of gases to be handled. These costs may
be so high that an operator, simply because of economics
(cost versus benefit), cannot afford to make the neces-
sary investment in dehydration equipment, compressors,
high-pressure lines and fittings, well conversion cost,
etc., and may elect to prematurely abandon his production
which is responsible for the generation of the sour gas.
(5) Proper consideration must be given the effect of treat-
ing plant regenerator off gas injected on the resultant
concentration of sour gas components in the receiving
formation and its effect on the wellbore equipment in
close proximity to the injection well.
(6) Underground reinjection of sour or acid gases as well as
any other extraneous fluid will, in most cases, require
complete unitization of all the mineral interests in-
volved in the project to protect correlative rights of
all the interests involved. Depending upon the com-
plexity of ownership, this unitization effort could take
years to conclude. This time delay and effort could add
to the cost of the project and may also, in itself,
make the project uneconomical.
(B) Use of Iron Oxide Process
This process removes H.S from the natural-gas stream to almost
zero level. Thus, in a small facility, a portion of the gas can be sweet-
ened and mixed with the remaining sour gas so that the total H_S in the
natural-gas mixture does not exceed pipeline or other specifications. The
small operator may be able to reduce his H S emission to less than one MT/D
by using the iron oxide process because the process produces solid waste
but no H S emissions. Burning the spent sponge would, of course, result
in emitting SO equivalent to the amount of H S removed from the gas.
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67
(C) Use of the Molecular Sieve Process
This is an alternative to the iron sponge process insofar as it
can be quite selective in removing H9S (and other sulfur compounds) but not
CO and the comments made above apply to this process also. However, re-
generation of the sieve, unless the non-commercial Raines arrangement is
utilized i
posed of.
(D) Packaged Glaus Plant
utilized results in the release of the adsorbed H S which must then be dis-
When a maximum of only about 90 percent VJ' conversion to sulfur
is required, a pack?~cd two-stage Glaus plant may provide a suitable option
at low cost. The cost of the packaged Glaus plant in relation to cost of
the facility and other available options, if any, needs to be evaluated.
(E) Tail-Gas Cleanup with Glaus Plant
There are at least six commercially used tail-gas cleaning pro-
cesses with many more under various stages of development. The six pro-
cesses, details of which are presented in Appendix C, are
(1) Beavon Process
(2) Cleanair Process
(3) IFP Process
(A) SCOT (Shell Glaus Offgas Treating) Process
(5) Sulfreen Process
(6) Wellman-Lord (W-L) S02 Recovery.
There are advantages and disadvantages associated with the employ-
ment of any of these processes for a particular application. All of the
processes require electrical energy; the amount of energy used usually in-
creases in proportion to the desired degree of sulfur removal for the tail
gas. It could be useful to compare the increased emission of S02 at the
coal-fired power plant resulting from the increased use of electric power
at the natural-gas plant necessitated by the tail-gas units. Both are point
sources and both require energy for SO emission control. Some aspects of
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68
the operational data of these tail-gas cleaning processes are discussed in
Section VIII.
One other control option not related to the emission of sulfur
from acid gas is the use of vapor recovery units on oil storage tanks em-
ployed in LACT systems described earlier. The Texas Air Control Board in-
forms that all new storage tank installations do include vapor recovery
units which compress the small amount of vapor leaking from the tanks and
inject the compressed vapor to sales or plant inlet gas lines. The injec-
tion of a small amount of H?S by this method into sales gas lines would
be permissible only if the resultant mixture does not exceed the allowable
H S level of the gas. This practice appears to ,be a sound and reasonable
approach to the prevention of small-volume H_S emission at remotely located
IACT units.
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69
VIII. OPERATIONAL DATA FOR SELECTED PROCESSES
The study of the natural-gas processing systems described in the
preceding Sections of this report indicates that control options which may
be used in reducing the SO emissions from the industry as a whole are as
follows:
(1) Reinjection of the sour-gas and acid gas to well
formation
(2) Iron oxide process for R-S removal
(3) Molecular sieve process for H.S removal from sour
gas
(A) Packaged Glaus plant
(5) 2- and 3-stage Glaus plant
(6) A-stage Glaus plant
(7) Glaus plant with tail-gas unit
(8) Tail-gas cleaning units (TGU's)
(a) Beavon
(b) Cleanair
(c) IFP-1 and IFF-2
(d) SCOT
(e) Sulfreen
(f) W-L SO recovery
For the six TGU's listed, detailed operational and process description data
are presented in Appendix D. However, a convenient overall summary of the
data is also presented in Table 21. It can be seen that the IFP-1 process
which can increase the Glaus plant sulfur recovery to about 98.5%, has the
lowest utility consumption and perhaps the lowest total capital requirement.
The waste stream from this process consists of intermittent (once every
two years) waste waters generated in catalyst washing. The process off-gas
leaving the top of the ammonia scrubber containing traces of NH-, entrained
polyalkylene glycol solution, and occasionally fine white particulate fume
is another minor waste stream. A study is currently in progress to determine
the least expensive method to eliminate the particulate fume . Both these
waste streams can be considered to constitute a minor environmental problem.
-------
TABU 21. OPERATIOHAL DATA FOR TAIL GAS CLBAHIN5 PROCESSES
Proceas Bams
Beavoo
Cleanalr
nrp-i
(TCT-1300)
Operating Feature*
Redaction of tall gaa constituents to
HjS followed by sulfur recovery
with S tret ford unit
Recovers 99.9 percent of sulfur
from Clan* plant tail gaa
Designed for low coat and sulfur
recovery efficiency of about
98.5 percent
Product
From
Process
99 percent pure
Sulfur as molten
or cake. Par-
ticle size 0.3
to 23 microns
99.3 to 99.9 pure
sulfur
Bright yellow
sulfur 99.9
percent pure
Sulfur in
Exit Gaa
<100 ppa
Total S
<10 ppa
HjS
<200 ppm
by volume
~2000 ppm
of S02
Investment
For a 100 MT/D Clans
unit, $700,000 to
$1 million
$500,000 for a 10
MT/D Claus plant
$3,000,000 for a
1000 MT/D Claus
plant
$2 million for a
1400 MT/D Claus
plant with 96.5
Costs aa of April. 1973*
Utilities
Steam - 1,453 Kg/hr
Cooling water - I/sec
Electricity - 25 kwh/hr
Fuel gaa - 224 scmh
For a ton of sulfur
produced in Claus
plant per day
Steam - 22 Kg
Electricity - 4 fcwh
Cooling water - 34 1/hr
Steam: for start up
only
Electricity - 35 kwh/hr
Operating
Maintenance 2
percent of
capital
1/2 men/shift
$30/day
$347/day for
catalyst and
Secondary Waste Streams**'
Stretford purge solution
(see text, page 53) am?
sour water condensate
Purge waste water stresir
Intermittent water con-
taminated with alkali
metal salts and organic
CFP-2 High sulfur recovery (99 percent Bright yellow ~5OO ppm
(TCT-150) plus) at a cost higher than sulfur 99.9 of SO.
DT-t
BOOT Increases sulfur recovery of Pure and bright <300 ppm
Claoa plant from 95 percent to yellow sulfur of SOj
99.8 percent by reduction and
alfcanolamlne absorption. Can
handle varying feed rat* and
composition
percent efficiency
and 99 percent
overall sulfur re-
covery
$450,000 for 200
MT/D Clans plant
$800,000 for 250
MT/D Claus plant at
93 percent
efficiency
70 to 100 percent of
the cost of Claus
plant
Cooling water - for shut
down only
Fuel gas - 0
$70/dsy
For a 250 MT/D Claus
plant at 94 percent
efficiency
Boiler water - 2500 Kg/hr
LP steam - 2,910 Kg/hr
Fuel gas - 100 Kg/hr
Reducing gas - 26 Kg/hr
Electricity - 350 Kw
solvent
Catalyst plus
solvent, $5/
day
Maintenance 2
percent of
capital
acid
Hj - 507 fume pins waste
water stream as In TCT-
1500
Substantially none
A very small amount of de-
grade solvent is
generated
Sulfreen
Mailman-Lord
SO. recovery
Essentially aa extension of the
Claua process after CS2 in t;all
gas is reduced to HjS. Sulfur
yield to about 99 percent
Treats only SO? (hence tail gaa in-
cineration 1* a moat)
Liquid sulfur,
99.9 percent
pure, bright
yellow
Concentrated
SO.
~1000 ppm
of S02
<100 ppm
Of SO.
For a 1000 MT/D Claus
plant, $2 million
For a 200 MT/D Ciena
unit, $1.6 million
Electricity - 650 kwh
Boiler water - 40 1/nln
Fuel gaa - 9900 scund
Cooling water - 500**
Kg/hr
Electricity 220 Kw
HaOH - 1 MT/D
Ho liquid waste*
Catalyst life - 4 years
Solid waste is generated
as used alumina, catalyst
Purge stream containing
•etal aaJlt are eent
currently to industrial
sewer*
* To update these ctsta to April, 1974, multiply April, 1973 costs by aa approximate CE plant cost index ratio of 1.1.
••For •aantlu.tlv* data see Referamea
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71
Data for Glaus Plants
The most significant waste stream from a Claus the tail
gas which contains sulfur equivalent to 3 to 5 percent of the feed sulfur
concentration. This aspect has been discussed in detail in earlier Sections
of this report.
The second significant waste stream is the spent catalyst (usually
bauxite) generated from the Claus catalytic reactors. The amount of spent
catalyst is a function of the number of catalytic conversion stages employed,
which, in turn, is a function of the required sulfur recovery efficiency.
Thus, to maintain an efficiency greater than 97 percent, the catalyst may
have to be replaced every 12 to 18 months. Current!••-, most plants replace
the catalyst between the third and fourth years and efficiencies obtained
range from 94 to 97 percent. One plant reports that about 20 MT of spent
catalyst is usually generated once in 3 to 4 years from a 200 MT/D Claus
plant. The spent catalyst is not regenerated and hence constitutes a
solid waste burden. The quantity of solid wastes generated is relatively
insignificant and toxic or leachable substances are not expected to be
present. For these reasons, it should be possible to dispose of the
spent catalyst in a landfill. However, it should be pointed out that
no analyses of the spent catalyst are available to make a definite
determination of its toxicity.
K:
I :'
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72
IX.REFERENCES
(1) Cantrell, Ailleen, "1973 Survey of Gas Processing Plants", Oil
and Gas Journal (July 9, 1973).
(2) Rankine, Robin. P., Kerry, R. K., et al "Potential Efficiencies
of the Conventional Claus Sulfur Recovery Process", a paper
presented to the Alberta Sulfur Gas Research Workshop, Edmonton,
Alberta, Canada, November 1, 1973, by Western Research and
Development Ltd., Calgary, Alberta, Canada.
(3) Chalmers, W. W., et al "Improvements to the Claus Process—Past,
Present and Future" Paper No. 71-AP-8. Presented at the 1971
Annual Meeting of APCA, Pacific NW International Section, Calgary,
Alberta, Canada (Nov 21-23, 1971).
(4) Horner, W. N., "Operating Parameters at Ram River Plant Outlined",
Gas Processing, Canada, (March-April, 1973), Page 14.
(5) Reprint from the 1972 "Bureau of Mines Mineral Year Book" - Natural
Gas Section, U.S. Department of Interior, Washington, D.C.
(6) Telephone Conversation with Mr. John Flynn, Chief Gas Processing
Engineer, Shell Oil Company, Houston, Texas (Phone 713/220-5440)
and with Mr. Carl T. Hester, Exxon Production Company, U.S.A.,
Houston, Texas (Phone 713/221-3563).
(7) "Environmental Quality" - The Fourth Annual Report of the Council
on Environmental Quality, September, 1973. Page 266, Published
by U.S.. Government Printing Office, Washington, D.C. 20402.
(8) Encyclopedia of Chemical Technology,.Edition 2, 10, Pages 390-420.
(1965) Kirk and Othmer Interscience Publishers, Division of John
Wiley, New York, N.Y.
(9) Beers, W. D. , "Characterization of Claus Plant Emissions", EPA
Report No. EPA-RD-73-188 (NTIS PB 220-376) from Process Research
Inc., Cincinnati, Ohio. (April, 1973).
(10) Maddox, R. N., Gas and Liquid Sweetening, 2nd Edition, John M.
Campbell Company, Norman, Oklahoma (1974).
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73
(1.1) Genco, J. M. , and Tarn, S. S., "Final Report on Characterization
of Sulfur From Refinery Fuel Gas" Report to EPA, Durham, N.C.,
under Contract No. 68-02-0611 (June 28, 1974).
(12) Mitachi, K., Chemical Engineering, 80 (21), 78-79 (October 15,
1973).
(13) Baraniuk, E.M., "Sour Gas Compression at the West White Court
Plant" Journal of Canadian Petroleum Technology, January-March,
1968.
-------
Contactor
APPENDIX A
DETAILED DESCRIPTION OF MAJOR H2S REMOVAL
PROCESS IN OIL AND GAS PROCESSING
Stripper
Treated gas.
Reproduced from
best available copy.
Acid gas
Feed gas
Start
eed gas
Steam
Rich solution
Fluor Econamine
Application! For the removal of acidic impurities, H»S
and CO*, from. gas streams. The treating agent used
is an aqueous solution of the primary alkanolamine,
HO-CaH4-O-C2H4-NH2, tradenamed Diglycolamine
(DGA).
Products Natural, synthesis or refinery gas streams may
be treated to H2S levels of less than 0.25 grains/100 scf
and to COj levels less than normally attained with con-
ventional MEA or DEA treating.
Description: The process scheme is identical to any other
alkanolamine treating plant. In fact, several existing MEA
treating plants have been switched to Fluor Econamine
with no equipment changes.
Feed gas is purified in a contactor vessel where acidic
impurities are absorbed by the Fluor Econamine solution.
Treated gas flows to dehydration or other subsequent
processing. Rich solution is heated by interchange with
hot lean solution, then flows to the stripper vessel for
solution regeneration. Stripped acid gases and water vapor
pass overhead to the condenser. Condensed water is
rcfluxcd to the stripper while H2S and COa go to flare
or to sulfur recovery. Stripping heat is furnished by a
steam-heated rcboiler. Lean solution circulates from the
stripper, through the exchangers, and is pumped through
solution coolers to the top of the contactor.
The solution is typically 65 percent by weight DGA
or higher. Use of this high concentration permits reducing
circulation rate by, typically, 25-40 percent compared to
MEA treating. This results in substantial savings in both
capital and operating costs. At the same time, experience
has demonstrated that corrosion is comparable to or less
than normally experienced with conventional amines.
Degradation of the treating solution is prevented by the
use of a simple and inexpensive high temperature re-
claiming technique, which purifies a slipstream of the
treating solution. No caustic or other chemical addition
is involved in this operation. Solution makeup require-
ments are generally below those of conventional amine
processes. This reclaiming method permits the use of the
Econamine Process for gas streams containing COS or
CSa since the decomposition products formed by the reac-
tion between these sulfur impurities and the DGA are also
thermally regenerated during the normal reclaiming
operation.
Commercial Installations: Econamine is in use in 19
plants with an aggregate capacity of well over 1 billion
standard cubic feet per day.
Reference: Oil and Gas Journal, May 2, 1966, pp. 83-86.
Licensor: Fluor Engineers and Contructors, Inc.
April 1973
HYDROCARBON PnocEsstno
-------
Treated
gas
A-2
Start
Flash gas
*-Acld gas
Reclaimer i
Heat
exchanger
Sulfincl
Application: Process removes acidic gas constituents such
as HZS, COj, COS, mercaptans, etc., from natural, re-
finery and synthesis gases, and LNG feedstocks.
Description: The process is based on the use of an or-
ganic solvent, Sulfolane (tetrahydrothiophene dioxide)
mixed with an alkanolamine, and water. Simultaneous
physical and chemical absorption under feed gas con-
ditions is provided by this Sulfinol solvent, and regenera-
tion is accomplished by release of the acidic constituents
at slightly above atmospheric pressure and at elevated
temperature.
Feed gas is contacted with regenerated Sulfinol solvent
in the absorber. Feed enters near the tower base and sol-
vent hear the top. Treated gas from the tower leaves the
unit for further processing or use. In high operating pres-
sure units the contact solvent may be flashed in a flash
tower, where most of the absorbed hydrocarbons are
separated for return to the absorber or for use as plant
fuel. In other units the contacted solvent goes direct to the
regenerator, where acidic gases are stripped, using a re-
boiler. The regenerated solvent is cooled and recirculatcd
to the absorber. Acidic gases are cooled, condcnsate is
separated and returned to the regenerator as reflux, and
acidic gas is made available for processing.
Operating conditions: The process has been used for
natural gas applications in which the H:S content has
varied from 0 to 53 mole c/o and the CO, content has
varied from 1.1 to 28 mole %. Satisfactory removal of
mercaptans and carbonyl sulfidc is obtained for all nat-
urally occurring mixtures of acid gases that have been
found. Natural gas'pipe line specifications that arc readily
attained arc:
H2S below 0.25 grain/100 scf
CO2 below 0.3 mole %
Mercaptan content .below 0.2 grain/100 scf
Total sulfur. below 1 grain/100 scf
With minor modifications to the normal plant design,
the gas can be treated to LNG feedstock requirements of
less than 50 ppm COa. ••
Specifications which allow 2 to 3% COS can be ob-
tained where the CO3/H2S ratio is high.
Absorption pressures are determined by the gas feed
pressure and vary from slightly above atmospheric, to
1,000 psi or more. The regenerator normally operates at
near atmospheric pressure such that low-pressure steam
(60 psig) is suitable for rcboilcr heat.
The absorber temperature varies with the operating
pressure, while the solvent circulation varies with the feed
gas rate and acid gas content. Circulation rates are rel-
atively low, compared with conventional amine processes.
Low corrosion rates are experienced.
Economics: Typical requirements for utilities, per pound
of acid gas removed, are:
Electricity, kWh <0.01
LP steam (60 psig), Ib. 0.8-1.6
Cooling water (or equivalent), gal 5.4*9.8
Commercial installations: Over 100 units are in opera-
tion or under construction; about 70 percent of these are
for natural gas treating.
Reference: Hydrocarbon Processing, Vol. 44, No. 4, pp.
137-140 (1965).
Licensing Inquiries: Shell Development Co., Houston,
(USA), and Shell Internationale Research Mij, B.V.,
The Hague (rest of world).
Apr! 1973 HYDROCARBON PROCESSING
-------
Contoctor Flash Tank Solution Storage
.
Regenerator Reflux Drum
Sweet gas
"X
Start
Sour
gas
^
Acid gase
( )
<2H
SNPA-DEA
Application: For sweetening raw gas streams containing
a total of about 10% or more of acid gases (H2S plus
CO2) at operating pressures of about SCO psig or higher.
Product: Natural gas streams may be treated to meet
the conventional pipe line specification of }4 grain H2S
per 100 scf maximum simultaneously with CO2 of 2
volume % or less. The acid gases removed from the raw
. gas are produced at an adequate pressure and the proper
temperature to serve as direct feed for a Glaus-type sulfur
recovery unit. No intermediate processing steps are re-
quired between the SNPA-DEA unit and the sulfur re-
covery unit, regardless of composition and nature of the
hydrocarbons contained in the raw natural gas stream.
Description: An aqueous solution of diethanolamine
(DEA) is used in concentrations determined to be eco-
nomical from past commercial scale experience.
An SNPA-DEA unit is similar to a conventional DEA
unit in many respects. The notable differences are: use of
higher DEA concentrations, optimization of .operating
conditions to achieve higher than conventional loading of
the rich DEA in terms of scf per gallon of solution, and
specific conditioning of a slipstream of lean solution to
maintain a low level of solids, corrosive products, and
hydrocarbons. Incorporation of these features results in
stable operation through a wide thruput range, with low
foaming tendencies and, hence, high reliability and on-
stream time.
Sour raw gas enters the contactor where it is scrubbed
with lean DEA solution. The H;S (and COa) are removed
in the rich DEA leaving the contactor. Rich DEA flows
to a flash tank from where dissolved gases, after being
further purified, are released to fuel. From the flash tank,
rich DEA is preheated and charged to the regenerator. In
the regenerator the acid gases are stripped from the DEA
solution, then cooled and routed to a sulfur recovery plant.
Heat input to the regenerator is from low pressure steam
via reboilers. Lean DEA from the regenerator is first ex-
changed and then cooled before returning to the con-
tactor. Solution storage and conditioning are provided on
the lean DEA stream.
Operating conditions: Commercial units are in opera-
tion at from 600 to 1,100 psig treating raw gas streams
containing from 11 to 35% acid gases. The ratio of
HaS:CO8 ranges from 34 to 0.65 in these units.
Investment: Process factors affecting investment cost
include: operating pressure, acid gas content, HjS/COs
ratio and treated gas purity. The onplot investment for a
battery limits units processing 220 MMscfd of natural gas
at 900 psig to produce a treated gas meeting pipe line
specifications will be $S-$8.5 million on a Gulf Coast
basis. The total acid gas removed in this unit is 68
MMscfd with an H,S/CO, ratio of 4/1.
Commercial installations: The SNPA-DEA process is
currently in use to sweeten about 3 billion scfd of raw gas,
with an added 2 MMMscfd under construction.
References: Wendt, C. J., Jr., and Dailey, L. W., "Gas
Treating: The SNPA Process," Hydrocarbon Process-
ing, Vol. 46, No. 10, 155-157 (1967).
Licensor: The Ralph M. Parsons Co. and affiliates.
-------
A-4
Absorber
Woshing Tower
Reqenerotor
Gas
Start-
Rawgos
Acid gos
Applications: For the substantial removal (to a few
ppm) of H*S and the partial removal of incidental COS,
CO» and mercaptans.
Charge! Natural, refinery or synthesis gas or LPG having
any concentration of acid gases.
Description: The process is based on an absorption-re-
generation cycle using a circulating aqueous solution of an
alkanolamine which reacts with acidic gases. H2S-contain-
ing feed is contacted counter-currently with Adip solution
in an absorption or extraction column. Regenerated solu-
tion is introduced into the head of the absorption column
at a normal or slightly higher temperature and leaves at
the bottom of the column. Rich solution exchanges heat
with regenerated solution and is fed to the regenerator.
Acid gases are stripped in the regenerator, which is
equipped with a steam reboiler. Cooled regenerated solu-
tion is recycled to the absorber. Acid gases removed from
solution in die regenerator are cooled, thus condensing the
water.
The low steam consumption normally associated with
the process is further reduced when H2S is removed from
gases under pressure, because higher absorption tempera-
tures are possible. Because of the relatively low steam con-
sumption, savings are possible in both capital and operat-
ing costs. Initial investment is also minimized, since car-
bon steel is used with the non-corrosive Adip solution.
HSS in the product can be reduced to meet stringent
specifications (less than 10 ppm), thus making after-
treatment unnecessary.
Operating conditions: Wide flexibility is possible in set-
ting operating conditions. The absorber pressure is set by
the pressure of the feed stream and ranges from slightly
above atmospheric pressure to several hundred psi. The
regenerator normally operates at slightly above atmo-
spheric pressure, such that low-pressure (above 60 psjjg)
steam is suitable for reboiler heat. ' <
The solvent circulation rates depend on the total gas
feed rate and the concentration of acidic gases in the feed.
Economics: Basis: Fetrl—925 metric t/d, 15.6% (voL)
H,S and 0.3% (vol.) CO2.
Product: 100ppm vol. H2S and 0.1% vol. COa
Plant cost: US $1 million
Solvent circulation: 200 m'/h
Utilities: L.P. steam (4.5 atm.)—450 t/sd
Electricity (incl. air cooling): 3,000 kWh/sd
Make-up water (steam condensate): 9 t/sd
Chemicals: Adip (100%, incl. mechanical losses)—70
kg/sd
Operating costs: Labor—J4 operator per shift
Maintenance: 2% of capital.
Commercial installations: More than 130 units are in
operation or under construction.
Reference: "Developments in Sulfinol and Adip Pro-
cesses Increase Uses," Oil and Gas International, Vol. 10,
No. 9, September 1970, pp. 109-111.
Licensing inquiries: Shell Development Co., Houston,
(USA), and Shell Internationale Research Mij B.V.,
The Hague (rest of world).
-" t973
HYDROCARBON PROCESSING
-------
Purified
gas out
A-5
JL
Acid gas,
Start
Raw gas in
Lean
solution
Rich
solution
Steam
Benfield
Applications: Removal of CO2, H2S and COS from sour
natural gas and raw gases produced during manufacture
of substitute natural gas by partial oxidation of coal or
oil or by naphtha reforming. Selective removal of H3S
from CO2 plus H2S mixtures provides H2S-enriched
stream suitable for recovery of elemental sulfur.
Feed: Sour natural gas containing CO2 or COS and H2S
mixtures or synthetic gas containing COa (and some-
times HjS) produced by partial oxidation or reforming
processes.
Product: Purified gas with H2S reduced to pipe line
purity specifications and with CO2 removal to a few ppm.
Description: Raw gas is contacted with potassium car-
bonate solution containing Benfield additives at elevated
pressures (100 to 2000 psig) in an absorber column
(packed or trayed) and acidic components (CO, and
H2S) are absorbed. The rich solution is let down to about
atmospheric pressure and stripped in a regenerator tower
to drive off absorbed acid gases and the regenerated lean
solution then recycled to the absorber. Process conditions
and flowsheet vary to meet various feed gas composition
and desired product gas specifications.
Operating conditions:
Absorption Pressures—Usually 100 to 2,000 psig. No
upper limit for absorber pressure.
Feed Gas Composition—Economics favored by high
partial pressure of CO2 and HZS. In usual applications,
CO2 or CO2 and H2S concentrations range from 5 to
50%. Feed gas may be saturated with H2O and may
contain substantial content of higher hydrocarbons.
Feed Gas Temperatures—Not critical—usually ambient
to 400°F. Heat in feed gas can be used to supply all or
part of process heat requirements.
Regeneration Pressure—Atmospheric.
Economics: Typical capital investment (large plant) per
Mscfd of COa + H8S removed: $75. Typical operating
utility requirements per Mscfd of CO2 + H2S removed:
Regeneration Heat 70,000-130,000 Btu
1-2 kwh
50,000-100,000 Btu
Solution make-up for mechanical
losses only—no degradation
Power (pumping)
Total Cooling Duty
Chemical Cost
Commercial installations: More than 250 operating
units including 18 units for natural gas sweetening and
over 150 units serving substitute natural gas units (COt
scrubbing of reformed and partial oxidation gases).
Reference: Benson, H. £., "Hot Carbonate Plants: How
Pressure Affects Costs," Petroleum Refiner, Vol. 40, No.
4, p. 107-108.
Licensor: The Benfield Corp., Pittsburgh, Pa.
April 1973
HYDROCARBON PROCESSING
-------
•'.»*
Absorber
A-6
HiaL
Pressure
Flash
Intermediate Low
Pressure Pressure
Flash . Flash
Stripper
Recycle
Start
Vent
Air Or
inert gas
Selexol
Application: For gas purification and removal of HjS,
CO», COS, mercaptans, etc., from gas streams by physical
absorption. The solvent, dimethyl ether of polyethylene
glycol, trade named Selexol, has strong preference for
sulfur-based compounds, while retaining the capability to
absorb bulk quantities of all impurities economically. It
is also capable of simultaneously dehydrating to pipe line
specifications.
Charge: Sour natural gas; raw product gas from the gasi-
fication of coal, oil, and light hydrocarbons; synthesis
gases from steam reforming or partial oxidation: refinery
gases.
Product gases: To less than 1 ppm total sulfur; CO,
can be retained or removed as required: water to less than
7 Ib./MMscf gas.
Off gases: Provide Glaus plant feed stream highly en-
riched in sulfur compounds; pollution-free vent gases.
Description: A Selexol plant consists of an absorber to-
gether with means for desorbing by flashing and/or strip-
ping. Recycle is sometimes included to enhance natural
selectivity for sulfur compounds. Temperatures can many
times be controlled without external heating or cooling,
by using hydraulic turbines and heat interchange. Over-
all liiMt effects are minimized by very low heats of absorp-
tion and a specific heat of only 0.5. No solvent reclaimer
is nct-dod since there is no degradation. This, along with
low vapor pressure means very low solvent losses. Solvent
is non-corrosive and inherently non-foaming.
Operating conditions: Absorption of impurities is essen-
tially proportional to their partial pressures. Feed condi-
tions can be varied over a broad range in existing
equipment. At the other end of the process, the solvent
is regenerated by physical desorption, rather than chem-
ical decomposition. Over 8 years of commercial experience
shows long term maintenance-free service.
Economics (expressed as % of MEA costs) : For a
plant treating 100 MMscfd, operating at 1,000 psiir, re-
ducing CO2 from 30 to 2 mole % rain., and meetine
H2S spec, of 0.25 gi/100 scf. *
% of MEA
Grass roots plant 70
Direct annual operating
Steam JQ
Electricity 20
Cooling & process water 25
TOTAL ~4o~~
Indirect annual operating 75
TOTAL annual operating 50
Commercial installations: Now operating or under con-
struction in natural gas treatment, synthesis gas purifica-
tion, coal gasification purification, COS removal,
Reference: Oil and Cos Journal, March 20, 1967, pp.
Licensor: Allied Chemical Corp.
April 1973
HYDROCARBON PROCESSING
-------
A-7
Desulfurizotion
Regeneration
(H2S-rCOS).
Regeneration
(C02)
Removol
CH3OH
\l\ conversion |"
CH3OH
C02
To meth/
woter
separation
Rectisol
Application: The process uses methanol as solvent in
three typical applications: (1) Removal of CO2, H2S,
NH3, HCN, gumformers, higher hydrocarbons and other
impurities from crude gas produced by coal gasification
for syngas or SNG manufacture; (2) Removal of H,S,
COS and CO» from reformed gas, in particular from
.gas produced by partial oxidation of hydrocarbons, to
yield synthesis gas, and (3) Integration of gas purifi-
cation with low temperature plants (liquefaction and
fractionation) for removal of moderate contents of acidic
components.
Description (Case 2: two-stage syngas purification):
Crude gas, saturated with water vapor, is indirectly cooled
by cold purified gas and evaporating ammonia. Icing is
prevented by the injection of methanol. The gas then
enters the first absorber where sulphur compounds are
removed completely by washing with methanol already
charged with CO,. After CO shift conversion and further
cooling, the gas is fed into the second absorber for the
removal of CO2 down to the level required. Before leav-
ing the plant, the purified gas is heat exchanged with
the shifted gas.
Fat solvent from the first absorber, after flashing and
heating, is regenerated completely in the H2S regenerator
by rebelling. After cooling, lean solvent is supplied to
tlic second absorber top together with stripped solvent
from the CO3 regenerator. In addition, semi-stripped
solvent is charged to the second absorber bottom section
for bulk removal of CO2. Fat solvent leaving tlic second
absorber is regenerated in the CO: regenerator !>y flashing
and stripping with impure nitrogen available .from the
oxygen unit. Solvent for dcsulfuri/ation is withdrawn from
HjS off-gas
57.3
40.1
the COg regenerator and pumped to the first absorber top.
Co-absorbed H2 and CO is released in the first flash
stages at relatively high pressure and either returned to
crude gas or used as fuel.
Refrigeration necessary for crude gas and solvent cool-
ing can be supplied by NHj absorption refrigeration unit
operating on waste heat.
Water introduced into solvent by crude gas is removed
by treating a small bleed stream in a methanol/water
distillation column.
Operating conditions: Feed: Flow—108 MMscfd (100
MMscfd H, and CO). Pressure—685 psig.
Desulfurlxatlom Feed Treated gas
CO,, Vol. % 5.3 - - *
HtS-f COS, Vol. % .. 0.7
HhVol.% 44.6
CO, Vol. % 48.4
N,+Ar,Vol. % 1.0
COj removal: Feed
CO,,Vol.% 36.1
HtS + COS,Vol. % .. —
H,,Vol. % 62.8
CO, Vol. % OJ
N, + Ar,VoJ. % 0.6
Utilities:
Power, shaft (without power recovery) 2,500 kW
Steam, 70 psig, tat'd 5.2 t/hr.
Waito heat (for refrigeration unit) 50 • 10*Btu/hr.
Cooling water, 75'F, 18* AT 2,060 m'/hr.
Mcthnnol 80 kg/hr.
Commercial installations: 23 operating units plus 7 in
construction, total capacity more than 2 billion scfd.
Reference: / & EC, Vol. 62 (1970), No. 7, 37/43.
Licensor: Lurgi Mincraloltechnik GmbH.
1.6
5.3
<0.1 ppm
45.0
48.7
1.0
Treated gat
0.1 (1 ppm possible)
98.2
0.8
0.9
-------
200 mmscfd
Start—-1
A-8
LJ
Absorbing
Low temperature
hydrocarbon
recovery
Pipe line
Dehydration
Desorbing
Sweetening
Start.
200 mmscfd
6% C02
10-100 grH2S
7 Ib r^O/mmscfd
T
H20
100 mmscfc
6% CO
<0.25gr
bone dry
100 mmscfd
<0.25gr H2S
7lbH20/mmscfd
200 mmscfd
3% CO
<0.25 gr H2S
3 lbH2C/mmscfd
Adsorbing Cooling
Molecular sieve
Desorbing
Amine Glvcol
Scrubber Scrubber
Application: Processes to dehydrate and to remove car-
bon dioxide and sulfur compounds from natural gas.
Charge: Impure gas streams containing water, carbon di-
oxide and sulfur compounds.
Products: Gas meeting pipe line specifications or suitable
for feeding to cryogenic processing plants and LNG plants.
Description: The processes involve two or more fixed bed
adsorbers and other regeneration facilities. At least one
bed is on adsorption at all times while the other bed(s)
are being regenerated.
The natural gas passes through the service bed where
the impure material(s) are removed to product specifi-
cations. Dry, treated regeneration gas is heated to 400-
600° F in a cooling adsorber and/or a heater, then fed
counter current to normal flow through the adsorber bed
being regenerated. Impure gas from the bed being dc-
sorbed is cooled, liquid water is separated, and the stream
fed to the product line, used for fuel, or goes on for
further treating.
A typical flow arrangement for carbon dioxide removal
is similar to that shown for sweetening except that no
further treating and drying is usually needed.
Selection of the appropriate type molecular sieve de-
pends on impurities to be removed. Type 4A is most com-
monly used for dehydration and Type 4A-LNG for car-
bon dioxide. Several types are used for desulfurization
depending on the kinds of sulfur compounds and their
concentrations to be removed. Sieve life ranges from two
to five years for desulfurization and carbon dioxide re-
moval, and from three to seven years for dehydration.
Molecular sieves used for drying cryogenic plant feed
can be used also for drying out the plant during shut-
down and before starti-os.
Economics: Unit size is dependent on the concentration
of impurities in the feed and other factors. Generally,
molecular sieves are used for sweetening when carbon
dioxide can be left in the product. Their use for dehy-
dration depends on the required dew point and normally
occurs when the dew point must be — 40° F or below.
Carbon dioxide removal with molecular sieves is most at-
tractive when the product must have a very low CO2
content and the feed has 1.5% (mol) COa or less.
Commercial applications: More than 12 units arc used
for sweetening over two billion scfd natural gas. All cryo-
genic gas processing plants in the USA except two use
molecular sieve dehydration. Twenty-nine LNG pre-
purificrs arc in operation and others are in the design or
construction stage.
Contributor: Union Carbide Corp., Linde Div.
1!YIWOCARBON PROCESSING
Apn! '073
-------
A-9
Purified gos
Absorber
Start '"Pure
X
Lean solution
Rich solution
Giammarco Vetrocoke—sulfur
Application: For the continuous removal of hydrogen
sulfide from natural gas or synthesis gases.
Description: The Giammarco Vetrocoke (HjS) process
for the removal of HSS continuously scrubs sour gas with
an alkali arscnatcs and orsenitcs solution. Sodium carbon-
ate, being relatively inexpensive, is the alkali usually ap-
plied for the removal of large quantities of sulfur. The
successive reactions occurring are:
+ 3 H,S - Na,AsS, + 3 H,O
Na,AsO,
Na*AiO> + '/,€>,=
(1)
(2)
(3)
(4)
Sour gas enters the base of the absorber column at
pressures up to and above 75 ats. g., depending on well-
head gas conditions. A countciflow stream of Vetrocoke
solution scrubs the I I2S to a level of 0.5 ppm or less. The
sweetened gas leaving the absorber is cooled to rcducC'thc
load on the downstream duhydration plant. The con-
dcnsntc removed takes with it most of the carryover. The
absorption reaction, Equation 1, gives rise to sodium
thioarscniic which has a low vapor pressure of HjS and
allows a high purity gas to \>c obtained by straight counter-
current absorption.
The thioarsenitc formed is slowly converted to mono-
thioarscnatc and arscnitc by a "digestion reaction," Equa-
tion 2, which occurs in absorber and in the subsequent
oxidizing column. The monothioarsenite formed has an
even lower vapor pressure of H2S.
Mono-thioarsenate, being more soluble, helps keep the
sulfur in solution.
The solution leaving the base of the absorber passes to
an air-blown oxidizing column working at atmospheric
pressure and around 40°C. This vessel is open to atmo-
sphere at the top. Under the oxidizing conditions, the
mono-thioarsenate decomposes to arscnite and elemental
sulfur. Elemental sulfur is removed overhead by froth
flotation, vacuum filtered and washed. The oxidizing re-
action also re-establishes the original Vetrocoke solution
balance by oxidizing some arsenite to arscnate.
Operating conditions: The dual function of the oxidiz-
ing tower limits the variation possible in the air flow to
the oxidizer because flotation process would be impaired
and a constant flow of solution to the absorber is possible
only at constant air rates. It is not practical to control
arsenate formation solely by the depth of solution aeration.
A small amount of catalyst is added to promote and con-
trol arscnate formation. This also reduces oxidizer size.
Commercial installations: Approximately 30.
Economics: Battery limits capital cost of a 100
MMscfd plant (in the United Kingdom) is approximately
$600,000. This plant removes II-.-S from inlet concentra-
tion of GOO ppm to outlet of J/a ppm. Utility costs arc
approximately 0.193 ccnts/MM Btu of treated gas,
Reference: Mntldox, R. N. and Burns, M. D., "Liquid
Absorption-Oxidation Processes," Oil and Gas Journal,
Vol. 66, No. 23, p. 90-91,%(19G8).
Contributor: Power-Gas Ltd.
Aoril 1973
IlYDROCAKIlON PHOCKSSINO
-------
A-10
Purified gas
Start
Reactors
Claus unit
tail gas
i
i
' i
i
t
1 i
i
', — C
A/V—I
Liquid sulfur
Sulfrean
Application: Desulfurization of residue gas.
Charge: Glaus unit tail gas.
Products: Liquid sulfur.
Description: The process is essentially an extension of
the Claus process, except that H2S and SO2 are made to
react at temperatures below the sulfur dew point of the
reaction gas mixture:
2H-S + SO, > 3S + 2H,0 + 35Kcal
Since equilibrium conversion Becomes more complete
as temperature is lowered, substantially higher sulfur
recovery is possible than in a normal Claus plant. The
reaction takes place in the presence of a catalyst, either
alumina or special activated carbon.
Sulfur formed is adsorbed on the catalyst which
eventually becomes saturated, requiring periodic regen-
eration by desorption of sulfur with hot gas.
The process reduces entrained sulfur to a minimum,
as the catalyst nets as a very effective adsorbent for
liquid sulfur. COS and CS, nre not affected.
Unit operation is exceedingly simple and differs only
sli"htlv from that of a Clans unit. Since only solid ad-
sorbents are used and no liquids except sulfur condense,
the process is free of liquid waste disposal problems.
Sulfur produced is bright yellow and of 99.9rc purity.
A unit may consist of throe reactors, two in adsorption
and one in desorption service. The mimbc.r of reactors is
determined strictly by economic considerations. Desorp-
tion of sulfur is effected by means of hot gas in a closed
cycle Desorption sjas, confining liquid sulfur is com-
bined with Uaus pi minced sulfur. Since produced sulfur
is of the same quality no product contamination exists.
An alternate of the Sulfncn process involving two-
Stage treatment can provide over-all recoveries exceeding
99%. A two-stage Sulueen unit consists of two catalytic
beds in series. In the first bed H:S and SO8 form sulfur
according to the Claus reaction; however, the ratio of
HiS/SO- is adjusted in such a manner that essentially
all of the SO2 is consumed and the effluent gas contains
only H2S. After addition of air to the first stage effluent,
H2S is oxidized directly to sulfur in the second stage.
With a 95% conversion in the Claus plant and COS
and CS. content reducing the yield by 0.5%, an over-all
yield around 99$> (or higher with the alternate) can
be obtained, with either catalyst.
Operating conditions: As all processes based on the
Claus reaction, a control with an optimizer of the
H-S/SOj ratio is required in the reaction gas mixture
at' or near the stoichiometric proportion of 2:1 for op-
timum results. Pressure drop through the unit is in the
order of 1.4-2 psi. Catalyst life expected: at least 4 years.
Investment/operating costs: Use of alumina catalyst
permits carbon steel construction and gives a lower cost
for the unit. Battery limits capital cost of a unit for a
1,000 Itpd sulfur plant will be around $2 million.
Utilities consumption will be as follows:
Electricity—C50 Kwh
Boiler feed water—10 L.S. gpm
Fuel cas—0.55 MMsrfd .
Commercial installations: 2 onstream: One in France
(1.000-t/d sulfur plant) and one in Canada (4,000-t/d
sulfur ptonO. 3 in construction.
Reference* Guvot. G. and Martin. J. F., "The Sulfrcen
Process," Canadian NO PA, June II. 1971.
Licensor: SNPA/I.urpi; The R- M. Parsons Co.. engi-
neering.
HVOROCARHON PROCESSING
April 1973
-------
APPENDIX B
DETAILED DESCRIPTION OP MINOR (LESSER KNOWN]
H2S REMOVAL PROCESSES
Absorber
Stripper
Solvent Dryer
Treated gas
Start
es
(\\ » Steam
\L* *
Purlsol
Application: Removal of acid gases from syngas and
natural gas streams using physical absorption in N-Methyl-
Pyrrolidone (NMP)..Three typical applications for high
pressure gases:
(1) Removal of high contents to low residual level,
(2) Bulk removal of acedic components down to mod-
erate product purity using a simplified flash regenerator
system,
(3) Selective removal of H2S.
Process description: (Case 1, above) cooled raw gas
saturated with water vapor enters the CO2 absorber
where it is dehydrated with rich NMP and then washed
with regenerated NMP. Entrained NMP is removed from
treated gas by water wash.
Rich solvent is first regenerated by two-stage flashing
to atmospheric pressure. Co-absorbed H2 and CO are
degassed at relatively high pressure and recomprcsscd
into raw gas. Residual CO2 is removed from NMP by air
or waste nitrogen stripping. COi and stripped gas are
diu-lt.trgcd via water wash.
.The solvent drier is fed with NMP/water mixtures
fiorh dehydration and water wash sections and separates
water and NMP by distillation with surplus water dis-
charged from the top with the off-gas and dried NMP
from tlic bottom. This column also removes NMP from
off-gav from (he second flash stage.
Operating conditions!
Feed conditions:
Flow
Pressure
Temperature
100 MMscfd
1,070 psig
110°F
Analyses:
Feed Treated gas
H,, % vol. 64.53 96.44
CO,, % vol 33.15 0.10
CO, % vol 1.50 2.24
C,, % vol 0.44 0.59
N, + Ar,9feVol 0.38 0.63
Utilities:
El. power, at the shaft • '... 2,100 kW
(without power recovery)
Steam, 45 psig, sat'd 1.7 t/hr.
Cooling water, 75° F 300 m'/hr.
Condensate 1.3 t/hr.
NMP cxcl. leakage 3 kg/hr.
Commercial Installations: 4 plants with a total thruput
of 420 MMscfd are in operation; 2 for high pressure
hydrogen manufacture, 2 lor natural gas treating.
Reference: Ilochgcsand, G., "Rcctisol and Purisol,"
Industrial and Engineering Chemistry, Vol. 62 (1970),
No. 7, p. 37/43.
Licensor: Lurgi Mincraloltechnik GmbH.
April 1973
HvoRocARnoN PROCESSING
-------
B-2
SOUR GAS
IN
WATER
REGENERATION
AIR
REGENERATION
STREAM
SWEET
*>
GAS OUT
FIGURE B-2. TYPICAL IRON OXIDE PROCESS FLOW SHEET
(Courtesy: Campbell Petroleum Series and Dr. R. N. Maddox)
IRON OXIDE (SPONGE) PROCESS
Application;
Removal of H2S from gases using the solid bed reaction of H_S with iron
oxide (Fe~0_). The reaction is regenerative.
3, + gH90
D, + 6S
^ J L £ J
Process Description:
A typical flow scheme using two towers is shown above. The use of more than
two towers is possible. In a 2-tower process, one of the towers wouJd be on
stream removing H?S from the sour gas while the second tower would either be in
a regenerative cycle or having the iron sponge bed replaced. Both continuous
and periodic regeneration are used. A bed is discarded when the H»S content of
sweet gas is unacceptable. The system is most suitable for low H S concen-
trations and/or low gas rates and will operate satisfactorily at low pres-
sures. For certain applications, capital costs about 1/4 of MES system
costs.
-------
B-3
Operating Conditions:
Feed Conditions:
Flow. No minimum flow
Pressure. Any pressure
Temperature. About 80° F
Commercial Installations;
More than 200 units are in use in the U.S.
Reference; . ••
Maddox, R. N. , Gas and Liquid Sweetening, John M. Campbell Co., Norman,
Oklahoma 73069 (1974).
•.••
Manufacturers:
(1) National Tank Company, Tulsa, Oklahoma
(2) Fish Engineering and Construction, Inc.
The process is nonproprietory.
-------
Absorber
B-4
Flash Drums
Treated gos
Start
Feed gas ,
Recycle gos
Lean solvent
Rich
solvent
H
To
•Expansion^ Pump
turbine dnve
Acid gas
I
I ^J
/—"\X5Tb pump drive
Hydraulic turbine
Fluor Solvent
Application: For the removal of high concentrations of
acidic impurities, CO2, and H2S, from natural or synthetic
gas streams.
Product: Plant designs are tailored to meet the purity
levels of COa and H2S needed in each specific situation.
Description: The Fluor Solvent Process employs an an-
hydrous organic compound, propylene carbonate, to re-
move COj and H2S from natural gas streams. The use of
this high capacity solvent, which absorbs acid gas by physi-
cal solution, permits solvent regeneration simply by pres-
sure letdown of the rich solvent, usually without the ap-
plication of heat.
In general, this process is best suited for cases where the
combined CO2 plus H2S partial pressure in the feed gas
is high, about 75 psi or higher. In addition, the use of this
process is favored by low heavy hydrocarbon content.
The processing arrangement selected for any particular
installation will depend upon a number of factors. These
include the degree of purification required for both COj
and H8S, concentration of both CO, and JIjS in the feed
gas, operating pressure, etc. Since solvent carrying capac-
ity is increased at reduced temperatures, solvent tempera-
tures below ambient are usually used to cut circulation
rate to a minimum. Often, the expansion of the acidic
constituents through the plant furnishes sufficient free re-
frigeration to make this possible. At other times it has been
found advantageous to install auxiliary refrigeration facili-
ties to permit lower circulation rates with attendant reduc-
tion in equipment sizes. Split-stream schemes can be ap-
plied to certain situations and other techniques may be
applied to assure the production of sales gas containing
0.25 grain H2S/100 scf. At other times simple atmospheric
flashing or vacuum flashing will be the preferred method
of solvent regeneration. Hydraulic turbines in the rich
solvent, and gas expansion turbines on flash gas streams
separated at intermediate pressures, are common items in
Fluor Solvent plants. Both these devices conserve energy
and reduce requirement for outside refrigeration.
Extended operation of this process over a 12-year pe-
riod has demonstrated conclusively that solvent reclaimers
are unnecessary. The solvent breakdown rate is virtually
nil. Several plants have demonstrated total solvent losses
of 1 pound per million standard cubic feet of feed gas,
other plants have demonstrated even lower losses.
Sidestrcam .distillation or other special equipment for
water elimination is not required. By proper process de-
sign, water content of the solvent is kept at 1 percent or
below. Carbon steel is a suitable material of construction
for all equipment and piping in this process.
Commercial installations: The process is now in use
in a total of 10 plnnts, 7 on natural gas, 1 in ammonia
production and 2 in hydrogen production.
Reference: Buckingham, P. A. "Fluor Solvent Process
Plants: How They Arc Working," Hydrocarbon Process-
ing, Vol. 43, No. 4, 113-116, (1964).
Licensor: Fluor Engineers and Constructors, Inc.
PROCESSING April 1973
-------
B-5
Purified gas
Absorber
Start lmpure gas »
K<
/N
T
I ^-X
L
* ,t
Steam
-r
kSulfur
Air
Rich solution
Heater
Giarnmarco Vetrocoke—sulfur
Application: For the continuous removal of hydrogen
sulfide from natural gas or synthesis gases.
Description: The Giammarco Vetrocoke (H*S) process
for the removal of H2S continuously scrubs sour gas with
an alkali arsenatcs and arsenitcs solution. Sodium carbon-
ate, being relatively inexpensive, is the alkali usually ap-
plied for the removal of large quantities of sulfur. The
successive reactions occurring are:
3 //,$ =
, + 3 H,0
(1)
f 3 Na.AsO. = 3 Na,AsO,S + Na.AiO, (2)
Na,AsO*S = HaiAiO, + S (3)
>. (4)
'Sour gas enters the base of the absorber column at
pressures up to and above 75 ats. g., depending on well-
head gas conditions. A counter/low stream of Vetrocoke
solution scrubs the II2S to a level of 0.5 ppm or less. The
sweetened gas leaving tlic absorber is cooled to reduce the
Jrod on the downstream dcln drat ion plant. The con-
dr'iisatc-removed takes with it most of the carryover. The
absorption reaction, Equation 1, gives rise to sodium
Ihioaiscnitc which has a low vapor pressure of H2S and
allows a high purity gas to be obtained by straight counter-
current absorption.
The lliioarscnite former! is slowly converted to mono-
tliionrscn.ilc and arson itc by a "t-li^rstion reaction." Equa-
tion 2, which occurs in absorbrr and in the subsequent
oxidizing column. The monothioarsenite formed has an
even lower vapor pressure of H2S.
Mono-thioarsenate, being more soluble, helps keep the
sulfur in solution.
The solution leaving the base of the absorber passes to
an air-blown oxidizing column working at atmospheric
pressure and around 40°C. This vessel is open to atmo-
sphere at the top. Under the oxidizing conditions, the
mono-thioarsenate decomposes to arsenite and elemental
sulfur. Elemental sulfur is removed overhead by froth
flotation, vacuum filtered and washed. The oxidizing re-
action also re-establishes the original Vetrocoke solution
balance by oxidizing some arsenite to arsenate.
Operating conditions: The dual function of the oxidiz-
ing tower limits the variation possible in the air flow to
the oxidizer because flotation process would be impaired
and a constant flow of solution to the absorber is possible
only at constant air rates. It is not practical to control
arsenate formation solely by the depth of solution aeration.
A small amount of catalyst is added to promote and con-
trol arsenate formation. This also reduces oxidizer size.
Commercial installations: Approximately 30.
Economics: Battery limits capital cost of a 100
MNfscfd plant (in the United Kingdom) is approximately
$600,000. This plant removes II:S from inlet concentra-
tion of 600 ppm to outlet of /a ppm. Utility costs arc
approximately 0.193 ccms/MM IJtu of treated gas.
Reference: Madclox, R. N. and Burns, M. D., "Liquid
Absorption-Oxidation Processes," Oil and Gas Journal,
Vol. 66, No. 23, p. 90-91, (I'JGS).
Contributor: Power-Gas Ltd.
April 1973
IFVUftOCAUIlON PHOCKS.SINfi
-------
L-l
APPENDIX C
DESCRIPTION OF SULFUR PRODUCTION PROCESSES
Acid qas
(may contain 4
1 " ' **' Reutl
r
.Air ^
Jbf
Boiler feed
. water
ion
. i
r
| i Cond.
1
•M
Reheat
— CD
I '
(1st Stage A
converterj
t -
1
i
i
fiCond.
1
[ .
Reheat
i
| 2nd Stage]
^ converterj
1
1
;
JCond
'
k
Reheat
(
J
1
'
T(
;3rd Stage ]
converterj
|
1
Cond.
•
\
1
\
) incinerator/stack
To Beavon sulfur
removal unit
Steam
• \
Liqt
Sulfur
transfer
pumpQ
Sulfur pit II
CD-
jid sulfi
Claus
Application: Conversion of hydrogen sulfide to high
purity sulfur.
Feedstock: Hydrogen sulfide gas streams from gas pro-
cessing and refinery operations.
Product: High purity elemental sulfur.
Description: The hydrogen sulfide containing acid gas
stream, which may originate in a conventional amine unit
or similar process, is fed to a reaction furnace where it
is 'burned with sufficient air to satisfy the stoichiometry of
the Glaus reaction. The hot reaction gases are cooled in
the steam generating section of the reaction furnace and
then further cooled in the first condenser where sulfur
produced in the reaction furnace is removed. After re-
heating, the gases enter the first catalytic converter where
additional sulfur is formed, which is condensed in the
second condenser. In the process shown three catalytic
conversion stages are used. However, in some cases it
may be economical to add a fourth stage, Depending on
the hydrogen sulfide concentration in the acid gas fed to
the unit, the number of catalytic stages and the quality of
the catalyst used, conversion cITiricncics of up to 98 per-
cent can be attained.
With proper modifications the process is suitable for
ihe treatment of acid gases containing hydrogen sulfide
over a wide mngr of concenirniions. In addition, the
process c.\n be designed so that ilie presence of impurities,
such as hydrocarbons and ammonia, in the acid gas
stream has no harmful effect on plant performance and
sulfur product quality. There are many units in operation
which process refinery gas streams containing appreciable
amounts of ammonia. This feature is of particular impor-
tance in view of pollution control requirements which
necessitate essentially complete removal of hydrogen sul-
fide from all gaseous and liquid refinery streams and
conversion to elemental sulfur before disposal as waste.
Under the conditions prevailing in the reaction furnace,
formation of some carbonyl sulfide (COS) and carbon
disulfide (CS2) is inevitable if the acid gas contains
COa and hydrocarbons. Although the amounts of COS
and CSa formed are relatively small, especially if the
hydrocarbon content of the acid gas is low, they are signifi-
cant as potential air pollutants. A special catalyst may be
Elaced in one or several of the catalytic converters to
irgely hydrolyze COS and CS2 to H2S and CO2, and
thus to prevent these compounds from escaping to the
atmosphere. The modified process emphasizes maximum
conversion efficiency and the highest degree of reliability
at low capital investment and operating costs. The high
conversion efficiency minimizes expenditures for tail gas
desulfurization.
Operating conditions: The process has been applied
to acid gas streams containing from 15 to 100 percent
H8S in capacities from 5 to 1,500 long tons per day. The
smallest units are skidmounted.
Contributor: Ralph M. Parsons Co.
PROCESSING
Apn! 1973
-------
Contactor
02
Skim Tank
Sweet go
Sour
aas
17** •*
s
1
rS
1
-*"i
.
Air
-— •
-—- --^
1
— -—
,
i
^- —
1
=»_
OTMB
•*«^
X^>
"S
Alternate
sulfur
recovery
methods
Filtration
Filtration and
autoclave
Centrifugotion
Centrifugotion
and heating
-*
-*
— M
1
-»J
Sulfur cake
Molten sulfur
Sulfur cake
Molten sulfur
Oxidize r
Surge Tank
Stretford
Application: For the sweetening of natural and industrial
gases by the complete removal of hydrogen sulfide and the
partial removal of organic sulfur compounds.
Product: An H2S content of 1 ppmv can be attained in
the treated gas at operating pressures through the range of
atmospheric to pipe line pressure. Sulfur of 99% purity can
be produced molten or as a cake. Particle sizes range from
0.5 to 25 microns. It has found use in agricultural insecti-
cides, plus all normal commercial outlets for elemental
sulfur.
Description: The gas is washed with an aqueous solution
containing sodium carbonate, sodium vanadatc, anthra-
quinonc disulfonic acid. The solution reaches an equilib-
rium with respect to the CO2 in the gas and only rela-
tively small amounts of CO2 are removed by the process.
Thus, the process represents an economic route for sweet-
ening a sour CO5 containing gas with much less shink-
age than that associated with aminc based processes.
The sour gas is countcrcurrently washed with regener-
ated liquor. The hydrogen sulfide dissolves in the alkaline
solution and is removed to any desired level. The hydro-
sulfidc formed reacts with the 5-valcnt state vanadium and
is oxidixcd to elemental sulfur. The liquor is regenerated
by air blowing, and the reduced vanadium is restored to
the 5-valcnt state through a mechanism-involving oxTgcn
transfer via the ADA. ''The sulfur is removed by froth
flotation and the scum produced can be processed several
ways depending on the desired end product, total sulfur
production, and utilities cost. For large sulfur production
rates, one or more stages of centrifuging followed by heat-
ing are often economic. For lower sulfur capacities, simple
filtration of the sulfur scum may be used.
Operating conditions: The reactions upon which this
process is based are essentially insensitive to pressure.
Thus, complete removal of H2S is attained equally at a
few inches of pressure as well as at the 1,000-psig level.
Operating temperatures throughout the unit are in the
range of ambient to 120° F and result in an operating
environment remarkabiy free of corrosion tendencies.
Investment: Process factors affecting investment cost in-
clude: operating pressure, HSS content of feed gas, and
disposition of sulfur product. The onplot investment for a
battery limits unit processing 15 MMscfd of natural gas
at 30 psig, and reducing its HSS content from 200 grains
per 100 scf to ;4 grain per 100 scf will be $600,000-$7QO,-
000 on a West Coast basis. CO, content of this raw
natural gas is 6 vol. % and remains in treated gas product.
Produced sulfur is discharged as a damp cake for disposal
at no value.
Commercial Installations: 55 Stretford units are cur-
rently in operation, with capacities ranging from 100
Mscfd to 90 MMscfd.
Reference: Ellwood, P., "Mcta-Vanadatcs Scrub Manu-
factured Gas." Chemical Engineering, Vol. 71, No. 15,
July 20, p. 128-130, (1964).
Licensor. International Consultancy Sen-ices, British Gas
Corp.
HvimOCARIJON PROCESSING
April 1973
-------
D-l
APPENDIX D
DESCRIPTION OF TAIL GAS CLEANUP PROCESSES
Reactor
Stretford
Absorber Oxidizer
Filter
Sulfur
Melter
Start.
Sulfur plant
toil gas
Hydrogenated
cooled tail gas
to h^S recovery
Liquor .Sulfur
return
Beavon
Appllcationi Purification of sulfur plant tail gas to meet
air pollution standards.
Feed: Tail gas from Glaus sulfur recovery unit.
Description: In the first portion of the process, all sulfur
compounds in the Glaus tail gas (SO2, Sx, COS, CSa)
are converted to H2S. The tail gas is heated to reaction
temperature by mixing with the hot combustion products
of fuel gas and air. This combustion may be carried out
with a deficiency of air if the tail gas docs not contain
sufficient H2 and CO to reduce all of the SO, and S, to
HjS. The heated gas mixture is then passed through a
catalyst bed in which all sulfur compounds are converted
to H2S by hydrpgenation and hydrolysis. The hydrogen-
ated gas stream is cooled by direct contact with a slightly
alkaline buffer solution before entering the HSS removal
portion of the process.
The Stretford Processes then used to remove H2S from
the hydrogenated tail gas. This process involves absorp-
tion of the HL.S in an oxidizing alkaline solution. The
oxidizing agents in the solution convert the H2S to ele-
mental sulfur, then are regenerated by air oxidation,
which floats the sulfur off as a slurry. This sulfur slurry
is then filtered, washed and melted to recover the Strct-
foi'd solution and produce a high-purity sulfur product.
Operating conditions: The pressure drop for the
treated gas is 2 to 3 psi; all pressures are near atmos-
pheric. Operating temperatures are 550 to 750° F for
the hydrogenation reactor and 70 to 120° F for the Stret-
ford section. Equipment is essentially all carbon steel. The
treated gas stream contains less than 100 ppm of'total
sulfur compounds and less than 10 ppm of H2S. Spent
oxidizer air is odorless, since it contains only air and
water vapor.
Economics: Based on a plant treating the tail gas from
a 100 It/d sulfur plant. Investment: $700,000 to $1 mil-
lion. Net utilities and chemical cost: $100 per day.
References: Beavon, D. K. and Vaell, R. P., "The
Beavon Sulfur Removal Process for Purifying Glaus
Plant Tail Gas," 37th Mid-year Meeting, API Division
of Refining, New York, May 9, 1972.
Commercial installations: Eight Bcnvon Sulfur Re-
moval plants arc currently being designed and built in
six locations in the United States and Japan.
licensor: Union Oil Co. of California.
PROCESSING April 1973
-------
D-2
tail gas
% sulfur recovery
from tail gas
Function
% of investment
H2S
S02
COS
CS2
. Stage IE
(optional)
i
Removes COS
and C$2
10
H2S
S02
w
1
Stage I 1 _ Staae H
•
50
Recovers elemental S
and converts all S02
S some HgS to sulfur
50
(Stretford)
1
j^s s
50
Converts H2S to S
40
Gas discharge
200 ppmv
S as S02
Cleanair
Application: Recovers 99.9% of the sulfur from Glaus
plant tail gas, leaving no more than 200 ppmv SOa
equivalent in the effluent.
Produ:t: Sulfur produced is typically 99.5% pure elemen-
tal sulfur, but can be guaranteed to be 99.9% pure,
based on total pit production. The sulfur is suitable for
any ultimate use.
Description: The process is used to convert sulfur con-
stituents in Clans plant tail gas to molten elemental
sulfur. It is installed upstream of the incinerator in a
conventional Claus plant, and may preclude the need
for incineration. The process consists of three stages
installed stcpwisc to achieve decreasing amounts of sulfur
emitted to the atmosphere. Levels of not more than 200
ppmv SO2 equivalent in the effluent can be guaranteed.
The system may be installed on old Claus plants or on
new Claus plants, but is somewhat more expensive on
old Claus systems.
From a space standpoint, the process .requires about
the same amount of plot plan as a dual-train Claus plant.
From an operating standpoint, the plant requires about 6
hours per 24 houis of operation. Other requirements per
daily ton of sulfur produced in the Claus plant arc: 8
pounds of strani per hour, 4 Kwh per hour, 9 gpm of
water for cooling, and 10-25 cents per day for chemicals.
Stage one of the process removes the sulfur dioxide,
stage two removes the hydrogen sulfide, and stage three
removes the COS and the CSS.
Economics: With a. given amount of gas flow, which
would result from a Claus plant being fed a constant
amount of feed, the process plant cost is somewhat sensi-
tive to the amount of sulfur being handled. Therefore, a
unit for a Claus plant operating at a low efficiency is more
expensive than one operating at a high efficiency. Taking,
as an arbitrary number, a Claus plant operating at 95%
efficiency, CLEANAIR process facilities can be provided
for a 10-ton per day Claus plant for about $500,000. For
a 1,000-ton-per-day Claus plant, this would be about $3
million.
Commercial installations: The first commercial in-
stallation was made at the Gulf Oil Corp. refinery at
Philadelphia.This plant is guaranteed to provide a cleanup
as low as 300 ppmv of sulfur dioxide equivalent. Several
other CLEANAIR plants arc in various stages of engi-
neering and construction.
Reference: Proceedings of the 51st Annual Convention,
Natural Gas Processors Association, April 10-12, 1972,
New Orleans, La.
Licensor: J. F. Pritchard and Co.
1973
HYDHOCARMON PKOCP.S.MNG
-------
To stock Fue'
D-3
Ammonia scrubber
->K«» S" ~S
NH3
make-up
I /O^NH3recycle
H^S-containing gas
Catalytic
reactor
Solvent
Thermal
catalytic
incinerator
Fuel
gas
Ammoniacal
brine Sulfite
evaporator
and S02
regenerator
so
S05
4 Sulfato
reducer
Application: 1. Removal of H2S and SO2 from Glaus
unit tail gas to an SOa level of 1,500-2,000 ppm (IFP-1)
or 500 ppm or below (IFP-2). 2. Stack gas clean-up to
take SQa down to or below 500 ppm. (IFP-2).
Feed:. Tail gas from 1, 2 or 3-reactor Glaus plants or
stack gas, as appropriate.
Product: Bright yellow sulfur, 99.9% pure, with 150 ppm
max. ash and 150 ppm max. organic impurities.
Description. IFP-1 (not illustrated): Glaus tail gas is in-
jected into a packed tower and contacted contercurrent
with solvent containing catalyst. Sulfur is formed, collected
and removed from bottom of the tower. Operating tem-
peratures in the tower range from 250 to 280 ° F. No
booster blower on Glaus tail gas is required due to low
pressure drop design of tower. IFP-2 (illustrated): Glaus
tail gas after incineration is scrubbed with aqueous
ammonia. Clean overhead is incinerated and vented up the
stack. Brine containing sulfites, bisulfitrs and small
amounts of sulfatcs from the scrubber is evaporated; sul-
fairs :iro reduced, and mixed SO2/NH3 overheads arc in-
j'Xfc'd into the bottom of tlic contactor. An IItS slipstream
.is also fed to tlic bottom of the contactor along with the
SQj stream. Solvent containing catalyst is circulated
.coiinlercurrcnt to the gas flow. Operating temperature in
tlic contactor ranges from 250 to 280° F. Sulfur is
formed, collected and removed from the bottom of the
tower. Ammonia is removed overhead and returned to the
scrubber.
Operating conditions: The solvent temperature to the
packed tower ranges from 250 to 280°F. The most im-
portant variable in the process is the ratio of HjS/SO3
in the feed to the packed tower. This ratio is held within
a given range by appropriate analyzer-controller equip-
ment.
Economics: An IFP-1 unit for an over-all recovery of
99% for use with a 1,400-T/d Glaus plant that recovers
96.5% sulfur requires a battery limits investment of $2
million. Operating costs are: utilities—$30/d; catalyst
and solvent—$347/d. Investment for a 200-T/d IFP-1
plant is of the order of $450,000. An IFP-2 plant added
on to a 250-T/d Glaus @ 95% recovery requires a bat-
tery limits investment of $800,000. Operating costs are:
utilities—$70/d; catalyst and solvent—$5/d.
Commercial Installations: IFP-1: Seven operating, five
under construction for Glaus plants with capacities from
5 to 2,400 T/d, totalling 4,000 T/d. IFP-2: One plant
operating and one under construction.
Reference: Bonnifay, P. et al, "Partial and Total Sulfur
Recovery," Chemical Engineering Progress, Vol. 68,
No. 8, pp. 51-52, August 1972.
Lkensor: Institnt Francois du Pctrolc.
HYLWOCARHON PROCESSING
April 1973
-------
D-4
Reactor
Cooling Tower
Reducing gas
To Clous Unit
incinerator
Start
Claus Unit
off-gas
n
n
W^
I
1
?'
Condensote to
n
^
^ Lean amine
Fat amine to
sour woter stripper | regenerator
Shell Glaus off-gas treating (SCOT)
Application: To increase the sulfur recovery efficiency of
Claus units from the usual level of about 95% to more
than 99.8%.
Description: The process essentially consists of a reduc-
tion section and an alkanolamine absorption section.
In the reduction section all sulfur compounds and free
sulfur present in non-incinerated Claus off-gas are com-
pletely converted into H2S over a cobalt/molybdenum
catalyst at 300° C in the presence of H2 or a mixture of
HJ and CO. Reducing gas can be supplied from an out-
side source, or a suitable reducing gas can be generated
by substoichiometric combustion in the direct heater. This
heater is required in any case for heating process gas to
the reactor inlet temperature. Reactor effluent is cooled
subsequently in a heat exchanger and a cooling tower.
Water vapor in the process gas is condensed, and con-
dcnsate is sent to a sour water stripper.
Cooled gas, normally containing up to 3% vol. HjS and
up to 20% vol. CO., is countercurrently washed with an
alkanolamine solution in an absorption column specially
designed to absorb almost all II:S but relatively little CO:.
Thc~ treated gas from the absorption column, which con-
tains only traces of H;S, is burned in a standard Claus
incinerator.
Tlic concentrated II;S is recovered from the rich absor-
bent solution in a conventional stripper and is recycled to
the Claus unit.
Operating conditions: Tin: process has a high flexibility
to cope with variations in Ci.ius plant operation; changes
in the Claus off-gas composition have only a small effect
on over-all sulfur recovery efficiency. Feed gas rates from
20 to 100 % of design can be handled easily. No secondary
waste streams are produced.
Units are designed for minimum pressure drop so that
they can be added easily to existing Claus units.
Economics: Basis: Unit for a Claus unit 250 t/sd sulfur
intake and a Claus unit sulfur recovery of 94%.
Utilities: . . .
Boiler feed water 5,500 Ib/h
LP steam (50 psig) 6,400 Ib/h
Electricity 350 kW
Fuel gas (LHV 19,800 Btu/lb) 230 Ib/h
Reducing gas (expressed in equivalent pure II:)... 53 Ib/h
Operating data:
Labor f 1/6 operator/shift
Maintenance 2% on capital
Capital investment varies between 70 and 100% of the
capital for the preceding Claus unit.
Commercial Installations: Several units ranging in size
from 10 to 2,100 t/sd equivalent Claus plant capacity arc
in various stages of planning, design and construction.
Reference: Petroleum and Petrochemical International,
Vol. 12, No. 9, September 1972, pp. 54-53.
Licensing inquiries: Shell Development Co., Houston
(USA), Nihoii Shell Gijutsu K.K., Tokyo (Japan and
Far East), Shell Internationale Research Mij. D.V., The
Hague (rest of world).
April 1973
PROCESSING
-------
D-5
Purified gas
Start
Clous unit
tail gas
i
i
i
l
i
,
i
i
Reactors
A/V—J
Liquid sulfur
Suifresn
Application: Desulfurization of residue gas.
Charge: Clans unit tail gas.
Products: Liquid sulfur.
Description: The process is essentially an extension of
the Glaus process, except that H-S and SO, are made to
react at temperatures below the sulfur dew point of the
reaction gas mixture:
2 H;S + SO2 >• 3 S + 2 H2O + 35 Kcal
Since equilibrium conversion Becomes more complete
as temperature is lowered, substantially higher sulfur
recovery is possible than in a normal Glaus plant. The
reaction takes place in the presence of a catalyst, either
alumina or special activated carbon.
Sulfur formed is adsorbed on the catalyst which
eventually becomes saturated, requiring periodic regen-
eration by dcsorption of sulfur with hot gas.
The process reduces entrained sulfur to a minimum,
as' the catalyst nets as a very effective adsorbent for
liquid sulfur. COS and CS, arc not affected.
'•.; Unit operation is exceedingly simple and differs only
slightly from that of a Clans unit. Since only solid ad-
sorbents arc used and no liquids except sulfur condense,
the process is free of liquid waste disposal problems.
Sulfur produced is bright yellow and of P?.9fo purity.
A unit may consist of three reactors, two in adsorption
and one in dcsorption service. The number of reactors is
determined strictly by economic considerations. Dcsorn-
tion of sulfur is effected by means of hot »ns in a closed
cvcle. Dcsorption eras, containing liquid sulfur is com-
b'incd with Clans produced sulfur. Since produced sulfur
is of the- same quality no product contamination exists.
An alternate of the Sulfrtcn process involving two-
Stage treatment can provide over-all recoveries exceeding
99%. A two-sta<*e Sulfreen unit consists of two catalytic
beds in series. In the first bed H:S and SO, form sulfur
according to the Glaus reaction; however, the ratio of
H"S/SO2 is adjusted in sur.h a manner that essentially
all of the SO- is consumed and the effluent gas contains
only H2S. After addition of air to the first stage effluent,
H*S b oxidized directly to sulfur in the second stage.
With a 95% conversion in the Glaus plant and COS
and CS, content reducing the yield by 0.5fo, an over-all
yield around 99% (or higher with the alternate) can
be obtained, with either catalyst.
Operating conditions: As all processes based on the
Clans reaction, a control with an optimizer of the
H-.S/SO. ratio is required in the reaction gas mixture
at"or near the stoichiomctric proportion of 2:1 for op-
timum results. Pressure drop through the unit is in the
order of 1.4-2 psi. Catalyst life expected: at least 4 years.
Investment/operating costs: Use of alumina catalyst
penults carbon steel construction and gives a lower cost
for the unit. Battery limits capital cost of a unit for a
1,000 Hpd sulfur plant will be around $2 million.
Utilities consumption will be as follows:
Electricity—G30 Kwh
Boiler feed water—10 U.S. m
Fuel itas—0.35 MMscfd _ . „
Commercial Installations: 2 onstrcam: One in Fnnrc
(1,000-t/cl sulfur plant) and otu- m Canada (-l.UUU-t/d
sulfur plant). 3 in construction.
Reference: Cuyot. G. and Marlm, J. F, "The biilfrrcn
Process," Can.uli'an NGPA, June 11. 1971.
Licensor: SXPA/Lurgi; The R. M. Parsons Co.. engi-
neering.
11YWUOC.VRUON PkOCK ? S1 NO
April 1973
-------
Incinerator
Waste
Heat
Boiler
Claus Plant
tail gas i ,
tort «
D-6
Quench b» Cos
Cooling Section
SO? Dissolving
Absorber Evdporotor Tonk
Clean
air
'/^
t
1 A-^
u
1
Product S02
recycled to
Claus Plant
W-LS02 recovery
Application: Desulfurization of waste gas stream.
Feed: Tail gas from Claus units.
Products: Concentrated SO2 gas suitable for recycle to
Claus units or for further processing, e.g., to sulfuric acid.
Description: Tail gas from Claus sulfur units is first
incinerated to convert all of the sulfur compounds origi-
nally present (H2S, COS, CS,, etc.) to SO,. The hot gases
are cooled in a waste heat boiler, then quenched and
fed to the SO- absorber.
The absorber is fed a lean solution of sodium sulfite
which absorbs the SO; by reacting with it to form sodium
bisulfite. The clean gases pass to the stack, while the
rich bisulfite solution is fed to an evaporator/crystallizer
regeneration system. SO2 and water vapor pass overhead
from the evaporator to a condenser. A knockout drum
separates condensed water for return to the absorbent
dissolving tank and the product stream of concentrated,
saturated SO; is piped back to the Claus plant feed or to
other processing.
A stream of slurry is withdrawn from the evaporator
and the sulfite crystals are redissolvcd to produce the
lean solution for recycle to the absorber. The evaporator
can be designed to use very low pressure exhaust steam
•(iO-lJ psig} as a heat supply.
A typkul SO-: recovery system for Claus units producing
about 400 hpd of sulfur is designed to treat -1-2,000 scfm
of tail gas with initial SO2 content in the range of 10,000
to 13,000 ppmv (1-1.3%, vol.). Effluents levels less than
100 ppmv SO2 in the stack gas have been consistently
achieved in commercial installations.
Yields: Sulfur oxide emissions in effluent stack gas can
be reduced by as much as 99%. The product stream for
recycle is 90-95% SO2.
Economics: Investment for adding a SO2 recovery system
onto a typical existing 200-ltpd Glaus unit is about $1.6
million (absorber and following).
Typical requirements:
Steam—High-pressure, produced 19,000 Ib./hr.
Low-pressure consumed 14,000 Ib./hr.
Net for export 5,000 Ib./hr.
Connected H.P. 300
Cooling water 1,000 Ib./hr.
Caustic make-up (100% NaOH basis) 1 tpd
Commercial installations: Five in operation; eight under
construction or being engineered. Two of these treat Clans
plant tail gns: one from three 150-ltpd units at Standard
Oil of California's El Scgundo, Calif., refinery, and an-
other used for two 200-ltpd units at the Toa Nenryo
Kogyo K.K. refinery in Kawasaki, Japan.
Licensor: Wellman-Power Gas, Inc.
April '973
HYDROCARBON PROCESSJNO
-------
E-l
APPENDIX E
DETAILS OF PLANT AND FIELD VISITS AND SAMPLE
OF QUESTIONNAIRE SENT OUT FOR SOLICITING INFORMATION
Visits were made to the companies and the State Air Pollution
Control Agency listed in Table E-l. The persons visited and a brief
description of the nature of the visit are also presented in the table.
In addition to these visits, numerous (telephone) conversations
were held with many industry experts in various areas. These experts
are listed in Appendix F. Everyone of these experts were very helpful
in providing without hesitation the information sought. Such informa-
. tion was quite useful in making this report accurate and current.
Details of the Questionnaire Sent Out
Copies of the questionnaire presented on pages E-3 and E-4 were
mailed to the following: (1) Exxon Company USA (Production Depart-
ment) Houston, Texas and (2) The Texas Mid Continent Oil Gas Association;
the former provided helpful oral answers while the latter organiza-
tion provided an excellent compilation of written answers to every
question. This computation has been the source of much useful informa-
tion base for this BCL report.
-------
TABLE E-l. DETAILS OF PLANTS AND FIELD VISITS
Name of Plant/
Field Visited and
Date of Visit
Persons Visited With
and Nature of Visit
Name of Person(s)
Visiting from BCL/EPA
Shell Oil Company
Bryans Mill Processing Plant
Bryans Mill, Texas
March 9, 1974
Texas Air Control Board
Austin, Texas
March 10, 1974
Exxon Company USA
Production Department
New Orleans, La.
April 28, 1974
Exxon's Jay Field Gas
Processing Facilities
Pensacola, Florida
April 29, 1974
Mr. Kenneth H. Rhoads
Chief, Gas Plant Engineering
Mr. John Flynn
Process Engineer
Discussed methods of H2S recovery, etc., and
visited Glaus plant, and gas processing plant
Mr. Charles R. Barden
Executive Director
Mr. Steve Spaw
Director, Permits & Inventory Division
Mr. Samuel Crowther
Engineer
Discussion of the extent of the S02 emissions
and control problems related to oil and gas
processing
Mr. Charles Hagemeier
Senior Technical Advisor
Mr. Carl T. Hester
Environmental Coordinator
Discussion of Exxon's Jay Field facilities
and reinjection as a means of control etc.
Mr. John Barry Chambers
Senior Engineer
Plant visit and discussions
Keshava S. Murthy, BCL
Keshava S. Murthy, BCL
S3
Charles B. Sedman, EPA
Keshava S. Murthy, BCL
Charles B. Sedman, EPA
Keshava S. Murthy, BCL
-------
E-3
Information Requested by Battelle for the Preparation of
a Document to Assist USEPA in Setting Performance
Standards for Oil and Gas Producing and
Processing Facilities
NOTE; The purpose of this information gathering is to get the opinion
of the industry experts. The answers need not be typed or
formal. These answers will not be held against anyone as legal.
They will be kept as strictly confidential or destroyed if you
so desire. Therefore, feel free to provide factual and critical
opinions and support your opinion on solid data wherever possible.
Question 1:
Question 2:
Question 3:
Question 4:
There are thousands of small gas producers/processors.
The sour gas produced by small operations is usually
treated in a conventional amine process. The spent
amine solution is regenerated and the ?. ^generator off-
gases are flared. Some suggest that instead of the
current practice of flaring, the off-gases (mainly
H_S and CO.) can be relnjected to the well formations.
a. Do you agree that this is possible?
b. If yes, can you provide details of operations
that are currently reinjecting?
c. If reinjection is not feasible, provide reasons
why it is not feasible.
d. Define problems (corrosion, etc.) If reinjection
Is followed.
e. In summary, please provide sufficient factual
Information that would assist in forming definitive
conclusions about the feasibility or otherwise
of reinjection as a method of avoiding SO.
pollution from flares in small plants.
If reinjection discussed above is felt to be impractical
as a method of disposal of flares, what other methods
in your opinion are available as alternatives to flaring?
Define briefly the economic and technical merits of the
method suggested by you.
What, in your opinion, should be the cut off point at
which emission regulations for gas treating plants should
be applicable (or not applicable). Justify you opinion
with technical and economic data.
The pipeline standard for H-S is I/A grain/100 scf. Are
you aware of any similar limitations on the concentrations
of mercaptans (RSH), carbonyl sulfide (COS), and carbon
disulfide (CS-) by pipeline companies? If so, what are the
standards and what is the basis for these established
standards?
-------
E-4
Question 5: Please provide the composition of your well head gas if
available for H^S, CO., COS, RSH, total sulfur, and
hydrocarbons. (The well need not be identified by name
or location If you wish to preserve secrecy.)
Question 6: List all problems (present and potential) that small and
large gas processors will face if SO. emission regulations
on processing plants are enacted at levels you consider
to be uneconomic.
Question 7: Please provide a material balance flowsheet of the
desulfurizatlon plant for large natural gas plants you
currently use. The flowsheet can be for any of the
following: sulfinol, DEA, SNPA-DEA, MEA, Stretford
ADA/Vandate, Giammarco-Vetricoke, DGA or Econamine or
hot carbonate.
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F-l
APPENDIX F
LIST OF INDUSTRY AND OTHER PERSONNEL
CONTACTED BY TELEPHONE AND VISITS
Mr. Elmer Berlie
Vice President
Western Research and Development Company
932, 700-6th Avenue
Southwest, Calgary, Alberta, Canada
(403) 263-1253
Mr. James C. Bouldin
Director
Rail Road Commission of Texas
Oil and Gas Division
Earnest 0. Thompson Building
Teuth and Colorado Streets
Austin, Texas 78701
Miss Ailleen Cantrell
Director of Editorial Surveys
The Oil and Gas Journal
Petroleum Publishing Company
211 South Chayanne Street
Tulsa, Oklahoma 74101
(918) 584-4411
Mr. L. E. Cardwell
Helium Analysis Group
U. S. Bureau of Mines
Amarillo, Texas
(806) 376-2658
Mr. Samuel Crowther, P.E.*
Engineer
Permits & Inventory Division
Texas Air Control Board
8520 Shoal Creek Blvd.
Austin, Texas 78758
Mr. Jack C. Dingman
Jefferson Chemicals Company
Box 53300
Houston, Texas 77052
(713) 529-4471
Mr. Vincent R. Gurzo
Sales Engineer
Linde Molecular Sieve Products
Union Carbide Corporation
1300 Lakeside Avenue
Cleveland, Ohio 44114
(216) 621-4200
* Contact established by pen-onal visit:.
-------
F-2
Mr. Charles E. Hagemeier*
Senior Technical Advisor
Exxon Company, U.S.A.
Post Office Box 60626
New Orleans, Louisiana 70160
(504) 527-3440
Mr. J. Douglas Harlan
Head, Natural Gas Liquids
Cities Service Oil Company
P. 0. Box 300
Tulsa, Oklahoma 74102
(918) 586-2211
Mr. Carl T. Hester*
Environmental Coordinator
Exxon Company USA
P.O. Box 2180
Houston, Texas 77001
(713) 221-3563
Mr. E. G. Hill
Director of Research and Development
National Tank Company
Division of Combustion Engineering
P.. 0. Drawer 1710
Tulsa, Oklahoma 74101
(918) 663-9100
Mr. Richard Jackson
Chief of Gas Engineering
Cities Service Oil Company
Oklahoma City, Oklahoma
(405) 236-0601
Mr. Earl Jairus
Manager of Sfclfur Programs
The Ralph M. Parson Company
617 West 7th Street
Los Angeles, California 90017
(213) 629-2484
Mr. Gordon Koelling
Natural Gas Division
U.S. Bureau of Mines
Arlington, Virginia
(703) 557-0239
* Contact established by personal visit.
-------
F-3
Mr. Larkin Kyle
Chief Engineer of Mechanical Design
Gas Engineering Office
Cities Service Gas Company
Oklahoma City, Oklahoma
Dr. R. N. Maddox
Head, School of Chemical Engineering
Oklahoma State University
Stillwater, Oklahoma
(405) 372-6211, Ext. 7565
Donald H. McCrea
Manager, Process Development
Benfield Corporation
615 Washington Road
Pittsburg, Pa. 15228
(412) 344-8550
Mr. Jack McWilliams
Division Environmental Coordinator
Ampco Production Company
Houston Division
500 Jefferson Building
P. 0. Box 3092
Houston, Texas 77001
(713) 227-4371
Mr. Kenneth H. Rhoads (John Flynn)
Chief, Gas Plant Engineering
Exploration and Production
Shell Oil Company
Two Shell Plaza
P. 0. Box 2099
Houston, Texas 77001
(713) 220-5446
* Contact established by personal visit.
-------
G-l
APPENDIX G
CONVERSION FACTORS
To convert from Metric to English units, use reciprocal of given factors.
To Convert (English)
=1 .-tual cubic ft/tnin (acfm)
atmospheres (atm)
barrels of oil (bbl)
barrels of oil (bbl)
cubic feet (eft)
cubic feet, (eft)
cubic meters (cum)
°F
ft
ft/sec
gal/Mcf
8Pm
grains (gr)
grains (gr)
gr/scf
grains/100 scf
in.
in. H20
Ib -moles
Ib -moles /hr
Ib-moles/min
long ton (LT - 2240 Ib)
pounds (Ib)
pounds /sq. in. (PS I)
pounds/sq.. in. (PSI)
ton (2000 Ib) /month
tons
To (Metric)
cu.m/hr
kilogram/Cm2
kiloliters (kltr)
U.S. gallons
cubic meters (cum)
litres (1)
cubic feet (eft)
°C
meter (m)
m/sec
I/cum
1/min
1/min/m2
milligrams (rag)
pounds (Ib)
gm/m3
mg/s cu m
cm
mm Hg
gm-moles
gm-moles/min
gm-moles/sec
metric ton (MT)
grains (gr)
atmospheres (atm.)
kilogram/Cm2 (kg/cm )
metric ton/day (MT/D)
kilograms (kg)
Multiply by
1.70
1.033
0.159
42
0.02832
28.32
35.31
subtract 32 then multiply 0.5556
0.305
0.305
0.^34
3.79
40.8
64.8
0.00014
2.29
22.9
2,
1
454
7.
7
1,
54
,87
.56
.56
.0084
7000
0.068
0.0703
0.02926
907.2
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APPENDIX H
HANDLING OF WASTE GAS WITH
HIGH H2S CONTENT
(Courtesy of Mr. Jack McWilliams,
Mid-Continent Oil § Gas Association, Dallas, Texas)
The corrosivity of waste gases containing hydrogen sulfide can
vary considerably due to the gas composition, temperature, pressure, moisture
or water content, velocities, etc. The selection of the proper metallurgy,
need for protective coatings or use of inhibitors or neutralizers can best
be made when the above conditions can be accurately defined.
Some general guidelines for handling these waste gases are listed
below.
(1) You will not have corrosion if moisture is not present.
However, it is not safe to assume that because dehydra-
tion facilities are installed that 'he gas will be kept
dry at the operating conditions. Uehydrators are
notorious for having malfunctions resulting in some
moisture or water to get into the line. It quite
often takes a considerable amount of time before this
moisture is reabsorbed into dry gas.
(2) Hydrogen sulfide can form a liquid at moderate
temperatures and pressures. At approximately 1000
psi and ambient temperature, some mixtures of H?S and
natural gas will contain liquid rich in H^S.
(3) In field operations even when very high concentrations
of H_S are present, corrosion rates are relatively low.
The reason for this is not known; however, it is
partly due to (1) the poisonous and corrosive nature
of H S results in a high degree of awareness and
effort on the part of all personnel to assure that
corrosion mitigation and monitoring programs are
rigidly followed; (2) sulfur or iron sulfide may form
a very tough protective scale on the steel which
minimizes corrosion.
(4) It is important that velocities be kept as low as
possible since high velocities (particularly when any
liquids or abrasive materials such as sand or scale
particles are present) tend to remove any protective
film or scale buildup and cause corrosion reactions
to proceed at a high rate.
-------
H-2
(5) The formation of iron sulfide can cause plugging
of the formation you are injecting into as well as
causing corrosion. It should also be noted that
iron sulfide upon exposure to air rapidly oxidizes to
iron oxide.
(6) Hydrogen sulfide or other corrosion can cause hydrogen
blistering or embrittlement (stress cracking) to take
place depending on temperatures and pressures. To
prevent this, metals below Rockwell "C" hardness of
22 are used in this type service. In wells handling
streams containing H S, C-75 or softer tubing or casing
are usually used. It must be remembered that prior to
the last few years, API Grades J, K, and N pipe had
only a minimum yield but no maximum value. Therefore
manufacturers could substitute API Grade N or P grade
pipe for J or K grade if the company so desired. This
could be disastrous if the higher strength steel is used
in the well containing high H.S and a catalyst such as
mentioned in Item 7 is used. Instant failures in tubing
couplings, sucker rods have occurred under these condi-
tions.
(7) Any low pH material such as dissolved CCL, hydrochloric
and other acids, or arsenic compounds (rarely used
acidizing inhibitors) can act as a catalyst for stress
corrosion and can cause rapid failure of highly stressed,
high-strength steel. For example, acidizing a well
equipped with N-80 or P-105 tubing (Re above 22) that
has been exposed to high H S concentrations can result in
immediate tubular goods failures probably in the highly
stressed couplings.
(8) For steel tubing and line pipe it is generally necessary
to use corrosion inhibitors, plastic coatings, or cement
linings as applicable to prevent corrosion. Most plastic
coatings are not effective :in very hJgh H-,8 and r.0?
environments or high temperatures and should be only used
-------
H-3
after extensive testing or investigation based on
similar operating conditions. Cement linings are
effective except that if the pH is below 5 to 5.5
the cement will be dissolved by the acids formed.
Oil or scale tends to form a protective coating on
the cement and increase its acid tolerance to some
degree.
(9) Copper and many copper alloys tend to corrode at
extremely high rates in the presence of H-S.
(10) High strength stainless steel tends to embrittle
in high H_S concentrations. Certain heat treated
stainless steels with a low hardness are satisfactory.
Monel and Inconel (although expensive) is an excellent
material in a severely corrosive H^S service.
(11) When designing any system, the conditions should be
compared with similar systems in operation. Also
any potentially corrosive system installed should
have corrosion monitors at key points. These monitors
such as corrosion coupons, electronic devices, etc.
allow the corrosivity of the system to be measured.
This will allow any changes to be made in corrosion
mitigation programs prior to extensive damage occurring.
(12) Attached is a reference that will be helpful in designing
a system.
(13) All welds in piping used in high hydrogen sulfide system
should be normalized (heat treated) or stress relieved
prior to use to prevent sulfide stress cracking and
galvanic corrosion between the weld metal and the steel.
In mildly corrosive environments .the use of pre-heat
and post-heat welding techniques are generally effec-
tive. This spreads out the heat affected zone and mini-
mizes galvanic action. This is discussed in the attached
material.
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1-1
APPENDIX I
LIST OH GLAUS PLANTS IN NATURAL GAS PROCESSING
APPENDIX I. LIST OF GLAUS PLANTS IN NATURAL GAS PROCESSING
State/Company/City, County
Year
Sulfur
Production
Started
Sulfur Sulfur
Production Design
in 1973 Capacity
(MT/D) (MT/D)
ALABAMA
Humble Oil & Refining Co.
Flomaton, Escambia
Stauffer Chemical Co.
LeMoyne
Expansion
ARKANSAS
Arkla Chemical Corp.
Magnolia, Columbia
Expansion
Olin Corporation
McKamie, Lafayette
CALIFORNIA
Lomita Gasoline Company
Long Beach, Los Angeles
FLORIDA
Amerada Hess Corporation
Jay, Santa Rosa
Humble Oil & Refining Company
Jay, Santa Rosa
Expansion
Louisiana Land & Exploration Co.
Jay, Santa Rosa
Louisiana Land & Exploration Co.
Escambia County
MISSISSIPPI
Elcor Chemical Corporation
Canton, Madison
Shell Oil Company (3-Stage Plant 97%)
Jackson*
Shell Oil Company (2-Stage Plant
Being Upgraded)
Goodwater, Clarke
1972
Before 1962
Before 1972
Before 1962
1962
1944
1971
1972
1971
1972
1972
1972
1965
1972
1971
5.3
650**
500
1.4
136
127
+123
19
+11
100
Not reported
120
14
+360
82
88
12 Standby
1250
35
(-) Blank spaces signify data not available
-------
1-2
APPENDIX I. (Continued)
State/Company/City, County
NEW MEXICO
Amoco Production Company
Artesia, Eddy
Cities Service Oil Company
Milnesand, Roosevelt
Climax Chemical Company
Oil Center, Lea
Marathon Oil Company
Indian Basin, Eddy
Northern Gas Products Co.
Hobbs, Lea
Warren Petroleum Corporation
Tatum, Lea
Year
Sulfur
Production
Started
1960
1967
1962
1967
1969
1961
Sulfur
Production
in 1973
(MT/D)
24.3
8.0
Sulfur
Design
Capacity
(MT/D)
26
20
18
36
13
4
NORTH DAKOTA
Texaco, Inc.
Lignite, Burke
OKLAHOMA
Pioneer Natural Gas Co.
Madill, Marshall
J. L. Parker Company
Madill, Marshall
TEXAS
Amarillo Oil Company
Waha, Pecos
Marathon Oil Company
Raan, Pecos
Mobil Oil Corp.
Coyanosa, Pecos
Texas American Sulfur Co.
Sand Hills, Crane
Phillips Petroleum Company
Crane County
Expansion
Warren Petroleum Corp.
Waddell, Crane
Expansion
1961
1967
Before 1961
1971
1967
1967
1966
Before 1961
1962
Before 1961
1968
20
89.0
15 Standby
2
13
29
15
100
+65
50
4-45
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1-3
APPENDIX I. (Continued)
State /Company /City, County
Warren Petroleum Corp.
San Hills , Crane
Northwest Production Corp.
Big Lake , Reagan
Expansion
Sid Richardson Carbon & Gasoline Co.
Kermit, Winkle r
Wanda Petroleum Company
Kermit, Winkler
Amarillo Oil Col.
Goldsmith, Ector
Amoco Production Co.
North Cowden, Ector
Odessa Natural Gasoline Co.
Odessa, Ector
J. L. Parker Company
Penwell, Ector
Phillips Petroleum Co.
Goldsmith, Ector
.Elcor Chemical Corp.
Midland, Midland
Amoco Production Co.
Midland Farms, Andrews
Amoco Production Co.
South Fuller ton, Andrews
J. L. Parker Co.
Andrews, Andrews
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
Year
Sulfur
Production
Started
1964
Before 1962
1962
Before 1961
1967
1967
1952
1961
Before 1962
Before 1961
1958
1956
1968
Before 1961
1951
1970
Before 1961
Before 1972
1962
1951
Sulfur Sulfur
Production Design
. in 1973 Capacity
(MT/D) (MT/D)
34 50
3
+5
5
18
5
26 26
12.8 13
30
75
1 Standby
6 11
3 6
15
34 48
2 4
23 28
2 4
9
30
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1-4
APPENDIX I. (Continued)
State/Company/City, County
Year
Sulfur
Production
Started
Sulfur
Production
in 1973
(MT/D)
Sulfur
Design
Capacity
(MT/D)
Texas Sulfur Products Inc.
Dumus, Moore
Trans-Jeff Chemical Corp.
Tilden, McMullen
Expansion
Atlantic Richfield Co.
Fashing, Atascoaa
Elcor Chemical Corp.
Fashing, Atascosa
Humble Oil & Refining Co.
Jourdanton, Atascosa
Warren Petroleum Corp.
Fashing, Atascosa
Shell Oil Co. (2-Stage Plants
Feed to a Common 3rd Stage)
Person, Karnes
Expansion
Coastal States Gas Producing Co.
Kenedy, Karnes
Olin Corp.
Beaumont, Jefferson
Amoco Production Co.
Edgewood, Van Zandt
Cities Service Oil Co.
Myrtle Springs, Van Zandt
Amoco Production Co.
West Yantis, Wood
Getty Oil Co.
Cayuga, Anderson
Getty Oil Co.
Winnsboro, Franklin
Shell Oil Company (3-Stage, 97%)
Bryan's Mill, Cass
Texaco, Inc.
Dunbar, Rains
Warren Petroleum Corp.
Sulphur Springs, Hopkins
1966
Before 1962
1962
Before 1961
1960
1967
Before 1962
1962
1965
1968
1959
1964
1968
1963
Before 1972
1969
1962
1966
1965
13.2
27.4
332
216
34
190
40
13
20
+80
10
55
22
45
12
+23
50 Standby
576
270
80
130
224
200
70
89
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1-5
APPENDIX I. (Continued)
State/Company/City, County
Year
Sulfur
Production
Started
Sulfur
Production
in 1973
(MT/D)
Sulfur
Design
Capacity
(MT/D)
UTAH
Union Oil Co. of California
Lisbon, San Juan
1967
10
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
Texas Gulf Sulfur Co.
Worland, Washakie
Jefferson Lake Sulfur Co.
1 ! . • Manderson, Big Horn
Atlantic Richfield Co.
Sinclair, Carbon
Signal Oil & Gas Co.
,. Nieber Dome
Texas-Seaboard Inc.
Silvertip
TOTAL
1965
1963
1968
1949
1961
1964
1966
1958
1950
Before 1959
Before 1962
Before 1962
1957
84 Plants
39 70
12
5
32 110
14
29 32
+15
22 Standby
400 Standby
113 Standby
26
50
50 Standby
(Incomplete) 6249
* Field deliverability limited production of sulfur
** These fields are unitized and the total sulfur production in 1972 was 650 MTD
Blank spaces indicate data not available
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