Report Number 9075-015
Contract Number 68-02-1358
January 1975
EVALUATION OF TECHNIQUES
TO REMOVE AND RECOVER SULFUR
PRESENT IN FUEL GASES PRODUCED IN HEAVY
FOSSIL FUEL CONVERSION PLANTS
for
Industrial Studies Branch
Office of Air Programs
U. S. Environmental Protection Agency
BOOZ- ALLEN APPLIED RESEARCH
a division ofBooz • dllen & Hamilton Inc.
4733 BETHESDA AVENUE
BETHESDA, MARYLAND 2OOI4
656-22OO
AREA CODE 301
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NOTICE
The attached document is a CONTRACTOR'S REPORT. It includes
technical information and recommendations submitted by the Con-
tractor 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 exten-
sive review by EPA, Federal and state agencies, public interest or-
ganizations, and Qther 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 con-
clusions 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 responsibility of EPA. Subject to these limi-
tations, EPA is making this draft contractor's report available in
order to encourage the widest possible participation of interested per-
sons in the decisionmaking process at the earliest possible time.
The report shall have standing in any EPA proceeding or court pro-
ceeding only to the extent that it represents the views of the Contractor
who studied the subject industry and prepared the information and rec-
ommendations. It cannot be cited, referenced, or represented in any
respect in any such proceedings as a statement of EPA's views regard-
ing the subject industry.
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T A B L E OF CO NT E N T S
Page
Number
I. INTRODUCTION 1-1
1. Purpose of the Study 1-1
2. Summary of Results 1-3
3. Approach and Basis of Analysis 1-6
4. Data Base Limitations 1-8
5. Organization of the Report I-10
II. STREAM CHARACTERIZATION II-l
1. Estimations of Stream Compositions II-4
2. Comparison of Process Gas Streams 11-23
3. The Problem of Removing Sulfur in
Clean Fuel Processes 11-26
4. Toxicity of Sulfur Species in Clean-Fuel
Processes 11-30
III. IDENTIFICATION AND APPLICABILITY OF
SULFUR REMOVAL AND RECOVERY PROCESSES III-l
1. Identification of Sulfur Removal and
Recovery Techniques III-l
2. Applicability of Sulfur Control Processes
to Gas Streams From Clean Fuel Conversion
Processes 111-51
11
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Page
Number
IV. COST AND EFFECTIVENESS OF SULFUR REMOVAL
• AND RECOVERY IN HIGH-BTU CLEAN FUEL
PROCESSES IV-1
1. The Bases for the Analysis of Sulfur
Control Processes IV-1
2. Cost and Effectiveness of Sulfur Control
Systems Applied to a Typical High-Btu
Gas Stream Derived From High-Sulfur Feed IV-4
3. Summary of Cost and Performance Results:
Sulfur Removal and Recovery From High-
Btu Gas Derived From High-Sulfur Feed IV-9
4. Cost and Effectiveness of Sulfur Control
Schemes Applied to a Typical High-Btu
Gas Stream Generated From a Low-Sulfur
Coal Feed IV-19
5. Summary of Cost and Performance Results:
Sulfur Removal and Recovery From High-
Btu Gas Derived From Low-Sulfur Feed IV-21
APPENDIX A
V. SULFUR REMOVAL AND RECOVERY IN LOW-
BTU CLEAN FUEL PROCESSES • V-l
1. The Problem of Desulfurizing Low-Btu
Fuel Gas V-3
2. Cost and Effectiveness of Sulfur Control
Schemes Applied to a Typical Low-Btu
Gas Stream V-5
3. Analysis of Results: Low-Btu Gas Streams V-ll
APPENDIX B
111
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Page
Number
VI. SULFUR REMOVAL AND RECOVERY FOR
PYROLYSIS GASES VI-1
• 1. Bases of Analysis for the Pyrolysis Gas
Stream and Applicability of Control Techniques VI-2
2. Analysis of Results: Pyrolysis Gas Streams VI-4
3. Expected Emissions and Costs to Treat
Pyrolysis Gas Streams. VI-7
APPENDIX C
VII. SULFUR PROJECTIONS VII-1
1. Proposed Scenarios for Development of a
Clean Fuels Industry VII-1
2. Projections of the Number of Clean Fuels
Plants to be Constructed by 1990 VII-3
3. Projected Sulfur Emissions VII-8
BIBLIOGRAPHY
IV
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LIST OF TABLES
Page
Number
II-l Gas Composition to Purification Section II-7/8
II-2 Calculation of Methane Content, Hypothetical
High-Btu Gas Process Stream 11-11
II-3 Calculation of Sulfur Content, Hypothetical
High-Btu Gas Process Stream 11-12
II-4 Gas Composition and Flow Rates for a 63 Billion
kcal/day Pipeline Gas Facility 11-13
II-5 Gas Composition of Quenched Low-Btu Gas 11-19
II-6 Hypothetical Gas Composition and Flow Rates for
130 Billion Btu/day (32. 75 x 109 kcal/day) Low-
Btu Gas ' 11-19
II-7 Composition of Typical Pyrolysis Gases ' 11-21
II-8 Hypothetical Pyrolysis Off-Gas 11-22
II-9 Comparison of Gases to Be Desulfurized 11-25
11-10 Physiological Response to Hydrogen Sulfide 11-32
11-11 Effects of Various Concentrations of Carbon
Bisulfide on Man 11-36
III-l Summary Data on Amine Solvent Processes III-7/8
III-2 Summary Data on Amine Solution Processes 111-11/12
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Page
Number
III-3 Summary Data on Alkaline Salt Solution Processes 111-15/16
III-4 Summary Data on Organic Solvent Solution Processes 111-19/20
III-5 Summary Data on SOo Absorption Processes 111-23/24
III-6 Summary Data on Adsorption Processes 111-29/30
III-7 Summary Data on Catalytic Conversion Processes 111-33/34
III-8 Summary of Data on Dry Oxidation Processes 111-37/38
III-9 Summary Data on Liquid Processes Involving
Oxidation to Sulfur 111-41/42
HI-10 Summary Data on Processes Involving Oxidation
to Sulfur Oxides 111-49/50
IV-1 Summary of Results, Sulfur Removal and Recovery
From a High-Btu Gas Derived From High-Sulfur
Coal IV-10
IV-2 Estimated Potential Emissions from High-Btu
Gas Derived From High Sulfur Coal, Maximum
Abatement Case IV-18
IV-3 Summary of Results Sulfur Removal and Recovery
From High-Btu Gas Derived From Low-Sulfur Coal IV-22
V-l Expected Emissions From Low-Btu Gas Production
and Consumption Compared to Direct Combusion
of Coal V-12
V-2 Expected Emissions From Low-Btu Gas Production
and Consumption Compared to Direct Combustion
of Coal V-14
VI
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Page
Number
VI-1 Summary of Results, Expected Emissions From
Pyrolysis Gas Treatment, 50, 000 bbl/day Oil
From Coal Pryolysis Facility VI-4
VII-1 U. S. Coal-to SNG Capacity VII-4
VII-2 Projected Number of Facilities Producing
High-Btu Gas VII-4
VII-3 Projected Rate of Commercialization of Low-Btu
Utility Gas Conversion Plants VII-6
VII-4 Projected Number of Pyrolysis Plants VII-7
VII-5 Sulfur Emissions on a Per Plant Basis VII-9
Vn-6 National Projection of Sulfur Emissions VII-13/14
VII-7 Total National Sulfur Emissions, Tons/Day VII-15
VII-8 Comparison of Sulfur Emissions From Clean
Fuels Plants and Electric Generating Stations
Producing Equivalent Heat Energy Output VII-16
VII
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L. 1ST OF FIGURES
Page
Number
III-l Typical Schematic and Reactions for Amine
Processes III-5
III-2 Typical Schematic and Reactions for Ammonia
Solution Processes III-9
III-3 Typical Schematic and Reactions for Alkaline
Salt Solution Processes 111-14
III-4 Typical Schematic for Organic Solven Solution
Processes 111-17
III-5 Typical Schematic and Reaction for SOg Absorption
Processes 111-21
in -6 Typical Schematic and Reactions for Adsorption
Processes 111-28
III-7 Typical Schematic and Reactions for Catalytic
Conversion Processes 111-31
III-8 Typical Schematic and Reactions for Dry
Oxidation Processes 111-35
III -9 Typical Schematic and Reactions for Liquid
Process Oxidation to Sulfur Schemes 111-40
111-10 Typical Schematic and Reaction for Processes
Involving Oxidation to Sulfur Oxides 111-47
IV-1 Summary of Results: Incremental Capital Investment
for Sulfur Removal and Recovery From a High-Btu
Gas Derived From High-Sulfur Coal IV- 12
Vlll
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Page
Number
IV-2 Summary of Results: Incremental Gas Price
Increase Caused by Sulfur Removal and Recovery;
High-Btu Gas From High-Sulfur Coal IV-13
IV-3 Summary of Results: Incremental Capital Invest-
ments for Sulfur Removal and Recovery From a
High-Btu Gas Derived From a Low-Sulfur Coal IV-23
IV-4 Summary of Results: Incremental Gas Price
Increase Caused by Sulfur Removal and Recovery
From High-Btu Gas Derived From Low-Sulfur Coal IV-24
IX
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I. INTRODUCTION
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I. INTRODUCTION
As demands for energy increase and the cost of traditional
fuels to satisfy these needs.escalates, the use of the abundant re-
serves of domestic coal and oil shale becomes more attractive. These
heavy fossil fuels, however, contain substantial amounts of sulfur that
must be removed to minimize environmental pollution. This report
describes approaches for controlling sulfur emissions through gasi-
fication and purification of heavy fossil fuels prior to combustion.
1. PURPOSE OF THE STUDY
The technical and economic feasibility of installing pollution
control systems to those clean fuel conversion facilities likely to be
constructed in the next ten years was developed in a previous study
for the EPA. * In that project:
The types and amounts of pollutants generated in clean
fuel processes were estimated
The availability of control processes to minimize
harmful emissions from these processes was assessed
The economic costs to control these emissions were
estimated.
Using this information developed earlier on clean fuel conversion
technology as a foundation, the present report considers in detail the
alternative sulfur removal and recovery techniques currently available
which can be applied to clean fuels processes. Specifically, the levels
of sulfur abatement attainable with current technology and the asso-
ciated costs to attain these levels are developed.
Booz, Allen & Hamilton Inc., Final Report No. 9075-015 to the
U. S. Environmental Protection Agency, Emissions From
Processes Producing Clean Fuels, March 1974.
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The research program to accomplish these objectives involved
four major steps:
The compositions of representative gas streams produced
in typical hypothetical clean fuel facilities were first esti-
mated. Taking into account expected variations in raw
feedstock, five gas streams were selected and their com-
position assumed. They included:
A high-Btu (pipeline) gas from high-sulfur coal
A high-Btu (pipeline) gas from low-sulfur coal
A low-Btu (utility) gas from high-sulfur coal
A low-Btu (utility) gas from low-sulfur coal
An intermediate-Btu pyrolysis gas from coal or oil
shale feeds.
The sulfur removal and recovery processes presently
available were then identified and categorized. Those
considered most promising for application in the treat-
ment of the representative gas streams were discussed.
. A total of'9 potentially applicable sulfur removal and re-
covery systems were applied to the typical gas streams.
Modifications of these systems were considered as well,
bringing the total number of processing schemes addressed
in detail to 37. Flowsheets, material balances and costs
were developed for these various alternatives on the dif-
ferent gas streams.
Finally, from the per plant emissions developed and from
estimates of the number of plants that may be constructed
over the next decade, national sulfur emissions resulting
from production of these gases were projected, assuming
maximum control levels as indicated in this report.
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2. SUMMARY OF RESULTS
The sulfur emissions resulting from the manufacture of clean
fossil fuels will come from two major areas of the plant: the process-
ing system itself and the utility systems that supply the steam and
electrical energy required. Additional potential points of sulfur dis-
charges may include:
Discharges from pretreatment of agglomerating coals
Sulfur contained in char, ash, tar, or oil that may be
generated.
The purpose of this study is to address the emissions from the off-
gases in the processing system only. Estimates for the total emis-
sions expected from these other sources are discussed in a previous
report prepared for the EPA. * The results obtained of the analyses
presented in the following six chapters of this report are summarized
below. It should be emphasized that the data base available for
these analyses influences the accuracy of the results reported.
This point is discussed more fully later in this introductory chapter.
(1) Emissions From Desulfurization of High-Btu Gas
The emissions from processing coal to manufacture high-
Btu gas are intermeshed with the gas purification system em-
ployed to treat the raw gasifier-effluent and upgrade it to pipe-
line quality. The expected emissions of sulfur from these
facilities are a function of the sulfur content of the coal, with
a minimum emissions level dictated by the maximum expected
purity of the discharged CC^-rich gas.
The emissions to the atmosphere from a commercial size
facility subject to maximum sulfur abatement are estimated
to be 250 ppm sulfur^ in the total CO2 removed from the
process gas or the organic sulfur content of the untreated
stream, whichever is greater.
Booz, Allen & Hamilton Report, op. cit.
The general term "sulfur" as employed in this report refers
to undefined, monatomic, gaseous sulfur species.
1-3
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With high-sulfur coals, a small but significant portion of the
sulfur may be present in the gas stream as carbonyl sulfide or
other forms of organic sulfur. Assuming this COS reports to
the CC^-rich gas, the estimated recovery of sulfur from the
facility represents approximately 98 percent of the sulfur con-
tained in the raw gasifier product. The emissions appear either
in the vented CO^ stream or the Glaus plant tail gas. In high-
Btu gas streams from low-sulfur feeds, however, the occur-
rence of carbonyl sulfide is less than 250 ppm and therefore is
not a controlling factor in projecting minimum emissions.
O 2z
The expected total emissions from a 250 million ft /day
gasification facility (7. 08 x 106m3/day) will be about 3. 5 tonst/
day, calculated as elemental sulfur, for coal feedstocks contain-
ing up to about 1 percent sulfur. With higher sulfur content
coals (feedstocks containing about 4. 5 percent sulfur), the emis-
sions will increase to about 10 tonst/day, calculated as elemen-
tal sulfur.
The expected sulfur emissions in the production of clean,
pipeline gas from coal are approximately one order of magni-
tude lower than the alternative of burning the coal directly in
conformance to present Federal EPA New Source Performance
Standards, either for the direct generation of heat or production
of electricity.
The capital investment cost of the acid-gas removal and
recovery at maximum abatement is approximately $80 million,
or about 20 percent of the total cost of the entire gasification
facility ($400 to $450 million). However, not all of this cost is
* Throughout this report, gas volumes (e.g., ft"3, m*3) are assumed
to be measured at standard conditions of 60°F (15°C), 30 inches
(762 mm) Hg, the natural gas industry standard.
t These quantities were calculated in short tons throughout this re-
port. Due to the level of accuracy of these estimates, expressing
these values in both short and metric tonnages would be irrelevant.
t Costs quoted in this report are based on mid-1973 estimates. With
the recent unpredictable rise in plant (and coal) costs, this earlier
costing basis is warranted.
1-4
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correctly charged to sulfur abatement; for both high- and low-
sulfur coals, the capital requirement for removal of carbon
dioxide alone from the process gas stream is approximately
$50 million, and the resulting increase in the gas price is ap-
proximately $0.20/million Btu ($0. 80/106 kcal). Hence, about
two-thirds of this cost is charged to the removal of the total
acid gas from the process gas stream and only one-third can
be charged to the removal of sulfur alone.
The cost of sulfur recovery is approximately proportional
to the quantity of sulfur in the process gas. At maximum abate-
ment (97-98 percent recovery), the additional cost for sulfur
recovery (in addition to carbon dioxide removal) is about $7 mil-
lion for each percent of sulfur in the coal. In addition to the
cost for carbon dioxide removal, the effect upon the gas price
for maximum sulfur recovery (maximum abatement) over that
for no recovery is $0. 02-$0. 03/106Btu/percent sulfur in the
coal ($0. 08-$0. 12/106 kcal/percent sulfur in the coal). The
incremental costs of sulfur recovery at about 90 percent abate-
ment are approximately one-third the costs at maximum abate-
ment.
(2) Emissions From Desulfurization of Low-Btu Gas
as Developed in Chapter V
The sulfur emissions from manufacturing, purifying and
combusting low-Btu (utility) gas will be equivalent to the quan-
tity of sulfur in forms other than hydrogen sulfide present in
the raw gas (e.g., COS). Maximum abatement below 250 ppm
for the sulfur removal during treatment, however, is not ex-
pected. Because extreme levels of sulfur removal are not re-
quired for low-Btu gas, more efficient recovery of the sulfur
removed is expected. The sulfur remaining in the treated gas
is combusted with the fuel and, assuming no further treatment,
is emitted to the atmosphere. The total level of sulfur emitted,
however, is still a factor of three to five lower than the alter-
native of direct combustion of the coal in conformance with
present Federal EPA New Source Performance Standards.
When using high-sulfur coals, daily emissions of 14 tons*
(elemental sulfur) are projected, including emissions from
Short tons, reference footnote p. 1-4.
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combustion of the fuel gas for a low-Btu gas plant producing
130 x 10^ Btu/day. The cost of treatment (sulfur removal and
recovery) will be $0.10-$0.15/million Btu ($0.40-$0. 60/106kcal).
For low-sulfur feed, emissions of 9 tons*/day are expected. To
attain this level of control will cost about $0. 04/106 Btu ($0.16/
10^ kcal) of gas produced. These costs include the costs of sul-
fur removal and recovery processes only. They do not include
any preconditioning costs or efficiency losses that may be nec-
essary when applying low-temperature purification schemes to
low-Btu gas.
(3) Emissions From Desulfurization of Pyrolysis Gas
as Developed in Chapter VI
The analysis performed on pyrolysis gases generated from
coal or oil shale feeds indicates that for a 50, 000 bbl/day plant,
including the expected emissions from combustion of the treated
inter mediate-Btu off-gas, 15 tons*/day calculated as elemental
sulfur will be emitted. On the basis of the energy in the product
gas, this amount is equivalent to 0. 13 Ib SC>2/106 Btu (0. 23 kg
SO2/10" kcal) or a factor of 10 lower than the emissions permit-
ted for direct combustion of solid fuels.
The expected cost of this sulfur removal and recovery from
the treated gas is $0.10-$0. 20/10 Btu (0. 35-$0. 85/10 kcal).
3. APPROACH AND BASIS OF ANALYSIS
In this report calculations were made on commercially available
sulfur removal and recovery processes as applied to typical gas
streams from clean fuels processes to control sulfur emissions. The
effectiveness of each control scheme is estimated and the expected
costs to incorporate these controls in commercial size facilities are
projected.
The flowsheets developed to show the treatment system applied
represent control processes as discrete elements. Process flows
Short tons, reference footnote p. 1-4.
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depicting the primary inputs to, and outputs from, each element are
characterized. This representation does not reflect the detail found
in engineering process flow diagrams. However, this approach was
adopted because it facilitates comprehension, and permits the cate-
gorizing of sulfur control schemes on a uniform basis which enables
parallel assessments of the cost and effectiveness of each to be made.
For each gas stream, the processing steps required to effect
maximum practical sulfur recovery were applied first. In successive
control schemes, selected processing steps were modified or deleted,
resulting in increased emissions. The highest emissions case ana-
lyzed involved maximum removal of sulfur from the gas stream treated
with no sulfur recovery techniques applied (minimum abatement). The
resulting sulfur emissions illustrate the degrees of control possible
using current commercialized procedures. They by developing the
cost of each treatment scheme on a uniform basis, the cost effective-
ness of alternative control schemes could be assessed and the sensi-
tivity of the various levels of desulfurization related to both the capital
investment required and the incremental cost of gas.
Information used in the analysis of these various control schemes
was developed through a review of the open literature and refined
through interviews with process licensors, developers and users.
These organizations included:
Five developers of amine-based acid-gas removal systems
Licensors of six solvent-based acid-gas systems
Licensors of five processes for sulfur recovery or
Glaus plant tail-gas cleanup
Four engineering companies active in the field
Two users of systems similar to those presented.
A preliminary version of the results presented in this report as
Chapter IV (the analysis of desulfurization schemes as applied to
high-Btu gas derived for high-sulfur coal) was sent to representatives
of these firms prior to scheduling of the interviews. The contribution
of these organizations to the process evaluations and the bases for
1-7
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analysis presented in this report has been significant. However,
because this study presents conservative estimates of the sulfur
recovery levels attainable, some of the more optimistic inputs
obtained from those interviews are not fully reflected in this report.
4. DATA BASE LIMITATIONS
Though the data presented are the best (if conservative) estimates
that are currently available for these control systems, their accuracy
cannot yet be substantiated by commercial experience. In applying the
results of this study, therefore, the major assumptions made and the
limitations of the approach used must be appreciated. Specifically,
it should be emphasized that:
The control processes assessed have not yet been applied
to large-scale clean fuel processes (since none yet exist)
and though data from licensors and pilot studies indicate
the potential feasibility for each system selected, some
of these processing schemes may eventually prove not
to be viable choices.
The representing of control processes as discrete elements
in the flowsheets overly simplifies actual process flow
requirements. This approach was selected for ease of
presentation and to facilitate the comparison of alternative
control schemes. A detailed process flow diagram may
show that the actual interfaces between controls would
require additional processing and/or costs.
The concentrations of many forms of organic sulfur (e. g.,
COS, 082) in the clean fuel process gases are not well
defined. The projections developed in this report were
based upon assumed thermodynamic equilibrium conditions.
The accuracy of this assumption may not be borne out
by actual plant experience; however, since operating data
currently do not exist, this assumption is taken to be
valid.
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The fate of the organic sulfur species in many of the sulfur
treatment schemes analyzed in this report has not been
adequately defined. Industry claims as to the effectiveness
of the recovery of these species for apparently similar
control systems vary widely. Conservative estimates as to
the fate of these species were, therefore, employed in the
analyses presented here.
Many of the more environmentally preferred treatment
systems that can be used to treat these sulfur-bearing
streams are relatively complicated. With the expected
variation in the feedstock sulfur concentrations, possible
efficient operation of these systems may be compromised.'
In specific applications, therefore, the more optimistic
results presented in this report may not be achieved.
The costing factors for the control schemes analyzed
were developed based on information from the open
literature and discussions with knowledgeable industry
representatives. Since not all of these cost estimates
were developed from uniform data, some extrapolation
of the data was required and some estimates had to be
made specifically for this report. Therefore, although
the cost data are presented to three significant figures
to facilitate calculations, this degree of accuracy is not
meant to be implied.
The control schemes in which no sulfur recovery tech-
niques were applied serve as a least cost reference base
for each of the streams treated. In some cases, this
means directly venting a gas containing nearly 5 percent
sulfur (as E^S) to the atmosphere. It should not be
inferred that this level of emissions would ever be
permitted.
The consensus of the industry representatives interviewed was that,
until the technology to treat these sulfur streams has been demonstrated
the sulfur recovery figures presented in this report represent only
reasonable estimates of the emissions to be expected for differing
degrees of treatment, and the cost data developed represent only
approximate estimates of the effect of recovery upon additional pro-
cessing costs.
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5. ORGANIZATION OF THE REPORT
This report is composed of seven chapters. This introductory
chapter defines the purpose of the study and the approach used and
summarizes the results obtained. Chapter II presents data on the
compositions of typical gases from clean fuel processes, specifies
the compositions and flowrates for the five hypothetical gas streams
treated, and compares these five gases with those which are being
commercially treated today. In Chapter III the sulfur control pro-
cesses discussed in the open literature are identified and categorized.
Those of specific interest are then discussed in detail and basic
assumptions on sulfur removal and recovery are developed. In the
next three chapters. (Chapter IV - VI), sulfur removal and recovery
from the high-Btu, low-Btu, and pyrolysis gas streams is considered
by calculating the effects of various combinations of potentially viable
sulfur control processes identified in Chapter III. The report con-
cludes with a projection of national sulfur emissions (Chapter VII)
based on the expected emissions from the gas streams analyzed, and
estimates of the number of facilities to be constructed over the next
decade.
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II. STREAM CHARACTERIZATION
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H. STREAM CHARACTERIZATION
The selection of viable sulfur treatment schemes for high-Btu,
low-Btu and pyrolysis gas streams requires an estimate of the
composition of the feed gas to be treated. The concentrations of
hydrogen sulfide, carbon dioxide, and the ratio of these two compo-
nents, and the presence of mercaptans, carbonyl sulfide, carbon di-
sulfide, heavy hydrocarbons, and aromatics influence the method of
treatment proposed to remove and recover sulfur.
The purpose of this chapter is to:
Characterize typical sulfur-laden gas streams that may
be generated in future clean fuel manufacturing pro-
cesses
Compare and contrast these streams with gases where
sulfur removal and recovery processes are currently
applied .
Explain the problem of removing sulfur from these gases
Discuss the relative toxicity of the sulfur species ex-
pected to be emitted from these gas streams.
The typical gas streams characterized cover the range of variables
affecting the removal and recovery of sulfur from synthetic gas pro-
duced from fossil fuel. The location of the sulfur removaland re-
covery processes within the overall processing schemes are identi-
fied and the characteristics of the sulfur species within these streams
are estimated. Finally, the physical and chemical parameters of
these gas streams are discussed and compared to the parameters of
gas streams from operations where sulfur removal and recovery are
currently commercially practiced.
In this study, five process streams were selected for in-depth
evaluation:
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Production of high-Btu gas from high-sulfur coal
Production of high-Btu gas from low-sulfur coal
Production of low-Btu gas from high-sulfur coal
Production of low-Btu gas from low-sulfur coal
Production of an intermediate-Btu pyrolysis gas.
The composition of a typical gas was selected for each of these
five process streams. The five gas streams characterized for this
report encompass the range of sulfur-laden gases that may be expected
in future clean fuel processes. However, these streams differ from
those commercially treated today. A wide range of variables affect
the applicability and effectiveness of sulfur removal and recovery
processes, among them:
The pressure of the system
. The sulfur content of the gas
Impurities in the stream
The reason for requiring desulfurization, i. e.,
Process constraints
Emissions control.
To each of these gas streams, specific treatment schemes have been
selected to control sulfur emissions. Several of the more important
factors that both govern the choice of a specific sulfur removal and
recovery processing scheme, and define the location of the sulfur
processing scheme within the overall process, are discussed below:
The intended use of the desulfurized gas stream is of
prime importance in the selection of the sulfur processing
scheme. If the product gas is to be used as a synthesis
gas to manufacture alcohol or ammonia, or as a sub-
stitute natural gas, it must be completely desulfurized as
a process requirement. The removal of all the sulfur
from a gas stream requires different sulfur processing
techniques than if only partial removal were required.
The physical and chemical characteristics of the gas
stream are important parameters. These character-
istics are functions of the conditions under which the gas
stream was produced. They include the pressure of the gas,
the cleanliness of the gas (e. g., quantities of tars, oils,
possible minor constituents), the reaction temperatures
II-2
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and their effect on COS and 082 formation, and the quantity
of carbon dioxide that is present and generally removed
simultaneously with the sulfur.
Other treatment required during the processing of the gas
stream may also influence the choice of sulfur processing
schemes. For example, a fixed ratio of hydrogen to car-
bon monoxide is usually required in the manufacture of
synthesis gas. In establishing this ratio over a water-gas
shift reaction catalyst, the ratio of carbonyl sulfide to
hydrogen sulfide will also be fixed. Similarly, many gases
will be washed for ammonia, phenol, cyanide, or oil re-
moval. With these constituents removed, the sulfur pro-
cessing scheme becomes simplified.
The ratio of sulfur to carbon dioxide in the process gas
stream is an important parameter because this factor
determines the choice between selective or bulk acid-
gas removal processes, the fraction of sulfur in the
treated acid-gas stream, and the applicability for treat-
ment by a Claus sulfur recovery process.
Of equal importance are the characteristics of the candidate
sulfur processing schemes. For example:
Will they remove mercaptans and carbon sulfides
as well as hydrogen sulfide?
Must they operate with a pressurized feed gas
stream to be economical? .
What is the effect of contaminants or species that
may break through from upstream processing?
What are the temperature requirements of the acid-
gas removal system?
These factors must be matched to the characteristics of the gas
stream to be processed; they were considered in defining the process
gas streams to be studied and in applying processing techniques to
remove sulfur from them.
II-3
-------
1. ESTIMATIONS OF STREAM COMPOSITIONS
This section is devoted to characterizing the five gas streams
selected for analysis in this study. The particular sulfur removal
problems existing for each typical stream are identified and high-
lighted. The location of the sulfur treatment stages within each con-
version process is also discussed.
(1) Specification of a Hypothetical Process Stream Generated
During the Manufacture of High-Btu Gas
Although several different types of gasifiers are available
or being developed for the manufacture of high-Btu gas, the ex-
pected processing steps for treating the raw gasifier product
and upgrading that effluent to high-Btu gas are similar in those
cases employing oxygen-blown gasifiers. Other types of gasi-
fiers will be discussed later. In each oxygen-blown gasification
system, the raw gasifier effluent is cooled and washed for the
recovery of coal dust or ash fines that may appear overhead in
the gasifier. The gas composition is then adjusted in a water-
gas shift reactor, * probably by a split-flow technique, so that
the ratio of hydrogen to carbon monoxide in the gas is correct
for the methanation reaction that will take place later in the
processing scheme. The gasifier effluent is then water-washed
for removal of ammonia, cyanides, phenols, chlorides, and
other undesirable species that may be present. In many cases,
the gas is then oil-washed for recovery of heavier hydrocarbons
that may also be present. This point in the process is the logi-
cal location for the sulfur removal stage. The gas has been
cleaned of solid and oily materials that could cause foaming and
degradation problems in some of the sulfur removal systems.
Similarly, ammonia and cyanide have been removed; these con-
stituents could cause problems in the sulfur removal stages.
Also, the final carbon dioxide loading on the system has been
set following the water-gas shift reaction.
Although the processing sequence discussed above is the
approach generally considered for acid-gas treatment, several
other schemes have appeared in the published literature. For
The principal reaction is: CO + H0O +* CO0 +
&
-------
example, in earlier descriptions of the Hygas process, the
shift conversion stage was delayed until later in the flowsheet.
The first stage of selective sulfur removal was located down-
stream of quenching, water scrubbing, and straw oil washing.
This scheme reduced the sulfur concentration in contact with
the shift reaction catalyst and permitted the use of less expen-
sive catalyst materials. Then, after the CC>2 loading had been
fixed in the shift reactor, the final sulfur and CC>2 removal was
accomplished in a second stage of acid-gas treatment. This
operating scheme is similar to that practiced by Shell in apply-
ing their Sulfinol process to the washed effluent from a heavy-
oil partial-oxidation unit before shift reaction. In a similar
manner, some proposed schemes have depicted selective acid-
gas treatment split around the methanation section. In this case,
the sulfur is completely removed in the first-stage treatment
and guard beds, but a portion of the carbon dioxide is not re-
moved until after methanation. The carbon dioxide therefore
acts as a diluent in the methanation section and moderates the
reaction. Some solvents, when used in that system, also serve
to dehydrate the product gas.
Although minor variations may occur in the placement of
the acid-gas removal system as discussed above, the effect
from an engineering and emission standpoint is similar. In
every case, the process gas stream has been purified of con-
taminants that might affect the operation of the acid-gas
stream (although provision must be included in the acid-gas
system for carryover of these impurities in the event of up-
stream malfunction). The composition of the gas is relatively
fixed, except in the unusual case of the delayed water-gas
shift reaction. Table II-1 presents the compositions as taken
from the open literature for a variety of gasification schemes.
The gas compositions in Table II-l were reported as the feed
to the acid-gas removal system; the gas quantities were ad-
justed for a 63 billion kcal/day (250 x 109 Btu/day) gasification
facility (the expected scale of commercial facilities).
The data underlying the composition in Table II-l were
not taken with a single coal feed, and gasifier performance
may vary greatly from coal to coal. Nevertheless, these data
indicate that those gasification systems that tend to make
methane directly will produce relatively large quantities of
methane in the gas and low quantities of carbon monoxide,
II-5
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II-6
-------
Table n-1
Gas Composition to Purification Section
Oxygen-Blown, Hqn-Btu Gas Protases, 250 x 109 Btu/day (63 x 109 teal/day) Facilities:
Lurgi Bi-Gas Hygas
Hypothetical Gas:*
CO
H2
CH.
C2H6
H20
CO,
H2S
. Synthane
Atgas
Ib-moles/hr gm-moles/sec Ib-moles/hr gm-moles/sec Ib-moles/hr gm-moles/sec Ib-moles/hr gm-moles/sec Ib-moles/hr gm-moles/sec
12,203 1,537.6 13,871 1,747.8 11,304 1,424.3 7,234 • 911.5 13,459 1,695.8
45,506 5,733.8 43,118 5,432.9 36,106 4,549.4 23,104 2.911.1 40,242 5,070.5
11,159 1,406.0 12,947 1,631.3 15,260 1,922.8 16,608 2,092.6 13,597 1,713.2
939 118.3 . - . . - 562 70.8 516 65.0
302 38.1 577 72.7 60 7.6 590 74.3 549 69.2
130 16.4 9,248 1,165.2 165 20.8 1,476 -186.0 34,336 4,326.3
33,751 4.25Z6 34,448 4,340.0 29,294 3,691.0 23,916 3,013.4 34,473 4,343.6
354 44.6 1,387 174.8 1,348 169.8 369 46.5 -
Ib-moles/hr gm-moles/sec
By inspection C02
H2
C2Hg
N2
H2/CO = 3.2:1 co
From Table 11-2 CH4
H20 saturated at 140°F (60°C),
i ncn „.;., ni a i/n/nm2\ u n
30,000
40,000
800
200
12,500
12,705
icn
3,780.0
5,040.0
100.8
25.2
1,575.0
1,600.8
in •)
From Table 11-3
H2S 1,480; 350 186.5; 44.1
COS
27; 6
3.4;0.8
Basis: 1,050 psia (73.8 kg/cm2)
140°F(60°C)
Heating value about 950 Btu/ft3 (8,500 kcal/m3)
II-7/8
-------
hydrogen, and carbon dioxide. Similarly, the less efficient
gasification systems — those requiring more oxygen during
gasification—make a greater quantity of carbon dioxide. The
quantity of sulfur in each of the gasifier streams is not directly
related to the gasifier but is a direct function of the composi-
tion of the coal feed. The sulfur species present in the raw
gas, however, will be a function of the gasifier type and operat-
ing conditions.
The hypothetical process gas stream for this analysis
was derived from Table II-1 by inspection and calculation
rather than by averaging the quantities for each component
from the gasifiers. The flow rates for the primary compo-
nents in the gas stream were expressed in rounded numbers. *
Therefore, the feed gas is strictly a hypothetical one and
should not be related to any specific gasifier design. The
molar flow rate of carbon dioxide was taken to be 30, 000
Ib-moles/hr and that of hydrogen 40, 000 Ib-moles/hr. The
ethane flow rate was set at 800 Ib-moles/hr, slightly favoring
the higher hydrocarbon level of the Lurgi gasifier. The nitro-
gen flow rate was taken at only 200 Ib-moles/hr, assuming
that higher purity oxygen would be used in the gasification
process.
The carbon monoxide content of the gasifier stream was
calculated in the following manner. The normal ratio of hydro-
gen to carbon monoxide in the feed to the methanation system
is 3.2:1. This factor is slightly higher than the theoretical
ratio of 3:1 needed to minimize the potential of carbon deposi-
tion in the methanator. Therefore, the molar flow rate of
carbon monoxide in this gas stream must be 40, 000/3. 2 or
12, 500 Ib-moles/hr.
The flow rate of methane in this hypothetical stream was
obtained on the basis of methane equivalents, as illustrated by
the calculation shown in Table II-2. For this calculation, the
These values were estimated in English units and are reported
as such here to emphasize the computational basis of the esti-
mate. However, in Table II-1, as in tables throughout the re-
port, data and results are reported in both English and metric
units.
II-9
-------
total quantity of product methane must be 27, 230 Ib-moles/hr
(3431 gm-moles/sec) to produce (63 x 109 kcal/hr). The pri-
mary chemical reaction that occurs in methanation is the com
bination of hydrogen and carbon monoxide:
CO + 3H ^ CH + H_O
From this reaction, the equivalent methane production from
hydrogen and carbon monoxide is the sum of those constituents
divided by 4. The second major reaction in the methanation
section is the conversion of ethane to methane.
C2H6 + H2 ^ 2CH4
Because H2 is equivalent to 0. 25 CH^, one C2Hg is equivalent
to 1.75 CH4.
According to the calculation in Table II-2, the equivalent
methane content of the hydrogen, carbon monoxide, and ethane
for the hypothetical gas is 14, 525 Ib-moles/hr, indicating that
12,705 Ib-moles/hr of methane must be present in the gas for
the proper heat flow rate.
The water content of the product gas was calculated by
assuming that it exists at 1050 psia pressure (73.8 kg/cm^)
and had been washed at 140°F (60°C). The gas would be sat-
urated with water at these conditions and contain 160 Ib-moles/hr.
The sulfur content of the gas was also obtained by calcu-
lation as illustrated in Table II-3. For this calculation, the
overall efficiency of the gasification plant was assumed to be
60 percent. Therefore, a 63 billion kcal/day output requires
a gasification plant input of 105 billion kcal/day (416. 7 x 10 9 Btu/
day). For the case of the high-sulfur coal, it was assumed that
the feedstock was a bituminous coal containing 6900 kcal/kg
(12,420 Btu/lb), with 4. 5 percent sulfur. The coal feed to the
gasifier is assumed to be 80 percent of the total feedstock; the
remainder is used for steam and power generation. Therefore,
11-10
-------
Table II-2
Calculation of Methane Content
Hypothetical High-Btu Gas Process Stream-1
CH^ equivalents required:
250x109Btu/day
— 5 o = 27,230 Ib-moles/hr (3,431 gm-moles/sec)
24 hr/day x 1,012 Btu/ftJ x 378 ftj/lb-moles
CH. equivalents present:
Ib-moles/hr
H2 40,000x0.25 = 10,000
CO 12,500x0.25 = 3,125
C2H6 800x1.75 = 1,400
14,525 14,525 Ib-moles/hr (1,830.2 gm-moles/sec)
CH4 that must be present in gas for
250 x 109 Btu/day (63 x 109 kcal/day)
production 12,705 Ib-moles/hr (1,600.8 gm-moles/sec)
the daily coal feed rate to the process gas stream was
26. 8 million pounds (12 x 10^ kg) and the sulfur feed rate
was 1. 2 million Ib/day (0. 5 x 10° kg/day). It was next as-
sumed that 96 percent of the sulfur in the feedstock was
gasified, the remaining sulfur appearing in the ash, yielding
1.16 million Ib/day (0. 53 x 106 kg/day) of sulfur in the raw
gasifier product. This is equal to a flow of 48, 309 Ib/hr
(21, 918 kg/hr); at a molecular weight of 32. 066, the total
molar flow rate is 1507 moles/hr.
The disposition of the sulfur species in the gas was
calculated on a thermodynamic basis only. It was first as-
sumed that thermodynamic equilibrium would be attained
between EL,, H2S, CO, and COS at the operating conditions
within the gasifier. It was next assumed that two-thirds of
________ O
The heating value of methane is assumed at 1,012 Btu/ft
(9,000 kcal/m3); the molar volume is 378 ft3/lb-moles
(0.02 m3/gm-moles) @ 60°F and 30 inches Hg absolute
pressure (16°C, 762 mm Hg).
11-11
-------
Table II-3
Calculation of Sulfur Content
Hypothetical High-Btu Gas Process Stream
Assumed:
Process efficiency of 60%
Coal to process - 80% of total coal
Coal to boiler house = 20% of total coal
Sulfur in process ash = 4% of sulfur in gasifier feed
Sulfur species breakdown in gas: 1.8% COS, remainder H2S
For High-Sulfur Coal:
4.5% Sin coal with dry heating value =12,420 Btu/lb (6,700 kcal/kg)
Total molar flow rate of sulfur in product gas:
.s^gg, «.ss*isg. •
: —: = 1,507 Ib-moles/hr
(12,420 Btu/lb coal) (0.6 Q 8") (24 hr/day) (32.066 Ib S/lb-moles S) (189.9 gm-moles/sec)
Btu in coal
COS = 27 Ib-moles/hr
(3.4 gm-moles/sec)
H2S = 1,480 Ib-moles/hr
(186.5 gm-moles/sec)
For Low-Sulfur Coal:
0.9% S in coal with dry heating value 10,500 Btu/lb (5,833.3 kcal/kg)
By similar calculations, total sulfur in gas = 356 Ib-moles/hr (44.8 gm-moles/sec)
COS = 6 Ib-moles/hr (0.7 gm-moles/sec)
H2S = 350 Ib-moles/hr (44.1 gm-moles/sec)
the gasifier product would pass through the water-gas shift
reactor where equilibrium would be reestablished. The
shifted gas and the bypassed gas were found to contain, on the
average, 1. 8 percent of the sulfur in the form of COS, and the
remainder as H^S; only small concentrations of the total sulfur
can thermodynamically exist as CSg, mercaptans, or other
organic sulfides. For the purposes of this analysis, only HgS
and COS were considered. On the basis of these thermodynamic
calculations, the COS content of the hypothetical gas stream
was shown to be 3. 4 gm-moles /sec, and the E^S content was
186.5 gm-moles/sec.
11-12
-------
For the case of the low-sulfur coal, it was assumed that
a Western coal would be used containing 5833. 3 kcal/kg
(10, 500 Btu/lb) and 0. 9 percent sulfur. On the basis of calcu-
lations similar to those described above, the expected molar
flow rate in the product gas is found to be 44. 1 gm-moles/sec
of H2S and 0. 7 gm-moles/sec of COS. The flows of the other
constituents remain unchanged. The gas from a Western coal,
however, should contain more CH4 and less CO, E^, and CO2
because of the higher relative reactivity of the typical Western
coal.
The expected composition of the gas streams for processes
manufacturing high-Btu gas from both high-sulfur and low-sulfur
coal, calculated as described above, is given in Table II-4.
Table II-4
Gas Composition and Flow Rates
For a 63 Billion kcal/day Pipeline Gas Facility
High-Sulfur Coal Feedt
CO
H2
CH4
C2H6
N2
H20
co2
H2S
COS
Total
Ib-moles/hr
12,500
40,000
12,705
800
200
160
30,000
1,480
27
97,872
gm-moles/sec
1,575.0
5,040.0
1,600.8
100.8
25.2
20.2
3,780.0
186.5
3.4
12,331.9
Vol %
12.8
40.8
13.0
0.8
0.2
0.2
30.7
1.5
(276 ppm)
100.0
Low-Sulfur Coal Feed1^
Ib-moles/hr
12,500
40,000
12,705
800
200
160
30,000
350
6
96,721
gm-moles/sec
1,575.0
5,040.0
1,600.8
100.8
25.2
20.2
3,780.0
44.1
0.7
12,186.8
Vol%
12.9
41.4
13.1
0.8
0.2
0.2
31.0
0.4
(82 ppm)
100.0
t698 short tons/hr ^827 short tons/day
(633 m tons/hr) (750 m tons/day)
11-13
-------
Though hypothetical, these streams are representative of what
might be generated from any of the gasifier types now under
development. The significant variations in gas composition,
obtainable from variations in the coal feeds, could place the out-
put of any of these gasifiers quite close to the hypothetical mix
if the proper coal were selected. This hypothetical gas stream
has been developed for the purpose of illustrating the various
techniques of sulfur treatment. Particular installation, however,
may differ appreciably from this example.
This high-Btu gas stream is typical of the type generated
from oxygen-blown gasifiers currently being developed or
already commercially available (see Table II-1). However,
several gasification systems have been proposed, or are under
development, that generate a gas differing significantly from
those specified for analysis in this study. Some of these pro-
cesses may eventually be commercialized, and it is, therefore,
appropriate to give an indication of how these gases differ from
those shown in Table II-1.
1. CO2-Acceptor (Consolidated Coal Company)
This process gas is low in sulfur and CO2 which
are removed to a lime desulfurization system and a Claus
sulfur recovery system. * The primary CC>2 off-gas from
the CC>2-Acceptor process gas comes from recalcining
the carbonated lime with air and char. The gas may con-
tain low concentrations of SO,,, depending upon the operat-
ing conditions of the regenerator.
2. Batelle-Union Carbide, Toscoal, Exxon,
COGAS (FMC)
These processes recirculate hot inert solids or ash
to the gasifier to supply the endothermic heat of the gasi-
fication reactions. The heat content of the solids is re-
generated by combustion of the residual gasifier char with
Refer to Emissions From Processes Producing Clean Fuels,
Booz, Allen & Hamilton Inc. Report No. 9075-015 to the
Environmental Protection Agency, March 1974.
11-14
-------
air; the resulting stack gas is desulfurized. The residual
char, used for combustion, may contain about half of the
sulfur concentration of the initial coal. Therefore, for a
4.5 percent sulfur coal feedstock, the char for combus-
tion may contain over 2 percent sulfur — requiring stack
cleanup of the resulting flue gas.
The process gas streams in these systems will con-
tain about 75 percent of the sulfur entering the gasifier,
and the CO2 will also be reduced. Therefore, the process
gas desulfurization will be similar to that reported in later
chapters but with reduced volumes.
3. Hydrane (Bureau of Mines)
This process requires separate steam-oxygen gasi-
fication of the residual hydrogasification char. The pro-
cess gas from this coal hydrogasification may contain
75 percent of the initial sulfur with very little CO2J con-
sequently, the sulfur removal and recovery from this
stream is simplified. The gas from the steam-oxygen
gasification of the char is converted to nearly pure hydro-
gen before introduction to the hydrogasifier. In purifying
this gas, nearly all of the CC>2 from the process will be
removed, together with about 25 percent of the initial
sulfur (probably over 99. 8 percent as HgS). The CC^-rich
gas is therefore found in a different location in the process.
The purification of this gas is complicated by the lower sul-
fur concentration but simplified by the near-elimination of
COS.
4. Hygas, Electro-Thermal (IGT)
In this process, the heat of the endothermic steam-
carbon reaction is supplied by electricity in the fluidized
carbon bed. The electricity is generated by combustion of
residual char. In this system, therefore, part of the pro-
cess sulfur and CO2 are discharged in combustion gases
and a stack-gas cleanup is expected.
11-15
-------
5. Hygas. Steam-Iron (IGT)
In the steam-iron process for generating hydrogen
for the hydrogasifier, residual char is steam-air gasified
in a fluidized-bed reactor. Some of the sulfur in the re-
sidual char should leave the steam-iron section with the
hydrogen, to be recovered eventually from the primary
gas stream. Most of the CC>2 and about 100 ppm to
200 ppm of reduced sulfur species report to the steam-
iron off-gas (not the process gas stream). The sulfur
concentration in the acid-gas is sufficient for a Glaus Plant
feed.
(2) Specification of a Hypothetical Process Stream Generated
During the Manufacture of Low-Btu Gas
It is assumed for purposes of this discussion that a low-
Btu gas would be manufactured from coal primarily for the pur-
pose of providing a clean fuel for direct combustion. * In this
case, the sulfur removal problem is simplified because the last
traces of sulfur need not be removed; the gas need only be de-
sulfurized to a level consistent with environmental needs. In
fact, the primary purpose of low-Btu gasification in the near
term will be environmental--to permit easier removal of the sul-
fur in the fuel compared to alternative techniques of fuel desul-
furization or post-combustion stack-gas cleanup. Another sim-
plification in low-Btu gas processes is that the carbon dioxide
in the gas stream need not be removed except as desired to up-
grade the heating value of the gas for industrial consumers.
One potential application of low-Btu gas is the generation
of electricity in a combined-cycle system. In this case, a de-
particulated and desulfurized gas is first combusted and ex-
panded through gas turbines. The heat in the gas turbine exhaust
.* Although some low-Btu gas may, in the future, be produced from
coal for the purpose of manufacturing hydrogen, ammonia, alco-
hol, or oils through the synthesis gas route, those applications
are not considered because the sulfur removal and recovery prob-
lem relates more closely to the high-Btu gas processes.
11-16
-------
is used to generate steam which is used in a conventional steam-
power cycle. The combination of gas turbines and steam tur-
bines promises greater efficiency in power generation, parti-
cularly when higher temperature gas turbines are developed. In
the application of low-Btu gas to combined-cycle power genera-
tion, the carbon dioxide and water vapor in the gasifier effluent
should not be removed as they represent mass at temperature
and pressure and therefore can generate work.
The location of the sulfur removal step in low-Btu gas
manufacture is straightforward in that it need be the only step
between gasification and combustion. The sulfur removal and
recovery techniques applied to treat the gas stream, however,
require that the low-Btu gas first be conditioned. This condi-
tioning includes the following steps:
Cooling to the temperature of operation of the desul-
furization unit
With cooling, water containing ammonia, cyanide,
and phenols is condensed from the gas stream
Many acid-gas removal systems are adversely
affected by higher hydrocarbons in the gas stream;
these must be removed by condensation, and, per-
haps, oil-washing
With cooling, condensation, and oil-washing, par-
ticulates are also removed from the gasification
stream.
Cooling represents a system efficiency loss because heat that
can be recovered from the low-Btu gas during the cooling and
condensation is available at too low a temperature to be gener-
ally useful. Additionally, when combined-cycle power genera-
tion becomes available, the loss of condensed water vapors will
be undesirable because this water is equivalent to mass that can
be converted to work in helping to drive the gas turbine. These
efficiency losses are the primary reason that high-temperature
desulfurization techniques are being developed at Battelle-
Northwest, IGT, U. S. Bureau of Mines, and other laboratories.
With high-temperature desulfurization, efficiency can be in-
creased as will be discussed in the analysis section on low-Btu
gas treatment in Chapter V.
11-17
-------
The specification of the hypothetical low-Btu gas is rela-
tively straightforward. Table II-5 presents the compositions
expected from various low-Btu gasifiers that are now commer-
cialized or under development. These compositions are quite
similar, varying primarily with the pressure of operation, and
in the methane content and the quantity of tars and oils that
would be present in the raw gasifier overhead. For this analy-
sis, the hypothetical composition of only the primary compo-
nents is specified. This gas has a heating value of about
1450 kcal/m3 (163 Btu/ft^). Note that the heat of combustion
of the sulfur is not included in the heating value of the product
gas. It is assumed that the low-Btu gas would exist at about
21. 1 kg/cm (300 psia) because pressure gasifiers will have
greater long-term applicability with the advent of combined-
cycle power generation.
The flow rate of the hypothetical gas system was selected
as equivalent to 32, 750 x 106 kcal/day (130 billion Btu/day) gross
heating value. As indicated in a previous study for the EPA* this
quantity of energy, in addition to by-product steam generated in
the process, can fuel a nominal 1000 MW combined-cycle power
system.
The gas composition was scaled to this flow rate. The
complete gas composition, quenched at 52°C (125°F), is speci-
fied in Table II-6. For this specification, the number of moles
of the primary species was rounded off to the nearest 10 and
other components were added. Water was included at its vapor
pressure, and sulfur compounds were added by a calculation
similar to that presented in Section (1) above. In carrying out
that calculation, the overall coal-to-gas efficiency was assumed
to be 80 percent and the sulfur gasification efficiency was assumed
to be 99 percent. The same bases were used to define the low-
Btu gas case (as derived from both high-sulfur and low-sulfur
feeds) as were used in the high-Btu gas discussions except that
the fraction of the total sulfur reporting as COS was taken to be
4 percent (as representative of the expected output of the gasi-
fier based on thermodynamic considerations).
* Booz, Allen & Hamilton Inc. Report 9075-015, op cit.
11-18
-------
I
I—*
CD
Table II-5
Gas Composition of Quenched
Low-Btu Gas (Vol %)
Gas Composition of Quenched Low-Btu Gas (Vol %):
Lurgi Winkler Well man U-Gas
CO,
Table II-6
CO
CH,
Total
14
16
25
5
_!°
100
10
22
12
1
_55
100
5
25
15
3
_52
100
Averaged Low-Btu Gas Composition (Vol %):
CO 20
co2
H2
CH,
10
15
5
Mo 3U
Total 100
10
20
14
5
51
100
Hypothetical Gas Composition and Flow Rates .
for 130 Billion Btu/ day (32. 75 x 109 kcal/day)
Low-Btu Gas
(Heating Value About 150 Btu/ft3,
1335 kcal/m2)
High-Sulfur Coal*
Ib-moles/hr
CO 17,540
H2 13,150
CH4 4,380
N2 43,840
H20 570
C02 8,770
H2S 723
COS 30
Total 89,003
*273 short tons/hr
(247 m tons/hr)
gm-moles/sec Vol %
2,210.0 19.7
1,656.9 14.8
551.9 4.9
5,523.8 49.2
71.8 0.6
1,105.0 10.0
91.1 0.8
3.8 (334 ppm)
11,214.3 100.0
*322 short tons/hr
(292 m tons/hr)
Low-Sulfur Coal*
Ib-moles/hr gm-moles/sec Vol %
17,540 2,210.0 19.8
13,150 1,656.9 14.9
4,380 551.9 4.9
43,840 5,523.8 49.6
570 71.8 0.6
8,770 1,105.0 10.0
172 21.7 0.2
, 7 0.9 (79 ppm)
88,429 11,142.0 100.0
* Basis: 125°F (52°C)
300 psia (21.1 kg/cm2)
-------
(3) Specification of a Hypothetical Process Stream Generated
Daring the Manufacture of an Intermediate-Bta Pyrolysis
Gas
A variety of clean fuel processes use a pyrolysis step in
their operation. Among these processes are the COED, Toscoal,
and Garrett processes for coal treatment and several schemes
for the retorting of oil shale. As indicated in Table II-7, the
composition of pyrolysis off-gases varies widely. For example,
the carbon dioxide concentration in the gas varies from 9 percent
to 50 percent, depending upon the process selected. The sulfur
content of the gas also varies; it is a function of the initial sulfur
content of the coal or shale that is being treated. This wide
range of gas characteristics makes the specification of a
"typical" gas stream difficult. The gas-composition presented
in Table II-8 was selected as a "typical", pyrolysis gas, although
it is realized that several other compositions could have been
proposed with equal validity. In actual practice, for each of the
gas streams encountered in any of the clean fuel processes, a
separate detailed study will be made for evaluation of sulfur re-
moval and recovery processes during the engineering evalua-
tion phase of the commercial plant.
The gas stream of Table II-8 was specified from the
average pyrolysis gas composition listed in Table II-7. The
gas was assumed to exist at 1.27 kg/cm and 38 C after quench-
ing and washing to remove the higher molecular weight com-
pounds. The gas is also saturated with water at this condition,
so the vapor pressure of water was included as a component in
this gas stream.
The disposition of sulfur into the species listed in
Table II-8 represents one possible composition that may be
reasonably expected. Typical pyrolysis processes operate at
relatively low temperatures of about 300°C to 550°C (600°F to
1000°F), so thermodynamic equilibrium cannot be expected with-
out catalysts present. A significant fraction of the sulfur in the
coal will be pyrolized in the form of mercaptans or organic sul-
fides; these organic-sulfur compounds are assumed to be re-
covered with the oil fraction from the pyrolysis unit. The dis-
position between H2S and COS was assumed to correspond to the
equilibrium concentration at 550°C (1000°F).
The treatment of this pyrolysis gas depends largely upon its
final use in the process. In many systems, this off-gas may be
11-20
-------
Table II-7
Composition of
Typical Pyrolysis Gases
Composition of Typical Pyrolysis Gases (Vol %):
COED (02)
Illinois Western
CO 18.4 20.0
H2 38.5 43.2
CH4 12.3 16.3
C2Hg + 14.0 5.4
C02 13.0 14.9
N2 - -
H2S 3.8 0.17
Total 100.0 100.0
Composition of Average Hypothetical
COED (Cogas)
Illinois
7.4
26.2
34
8.3
9.3
4.0
10.8 '
100.0
Pyrolysis
Western
17.2
16.6
34.9
7.6
20.1
1.2
2.4
100.0
Gas (Vol %):*
CO
H2
CH4
C2H6
CO,
Garrett Toscoal
21 17
33 1
19 18
15 13
9 50
3 1.5
100 100
18
35
15
8
22
Tosco BuMines
Shale Shale
3.4 3
1.5 6
8.3 6
50
31.8 23
62
5 0.1
100.0 100.0
H2S
Total 100
Gas is assumed saturated at 18 psia (1.27 kg/cm2) and 100°F (38°C).
11-21
-------
Table II-8
Hypothetical Pyrolysis Off-Gas*
Ib-moles/hr
gm-moles/sec
Vol %
CO
CH4
C2H6 +
H20
co2
H2S
COS
RSH, etc.
Total
10,080
19,570
8,300
4,745
2,965
12,450
1,170
20
low
1,270.1
2,465.8
1,045.8
597.9
373.6
1,568.7
147.4
2.5
-
17
33
14
8
5
21
2
(340 ppm)
59,300
7,471.8
100
* Basis: COED-type process producing 50, 000 bbl/day (8 x 10 liters/
day) syncrude.
Off-gas exists at 18 psia (1.27 kg/cm2) and 100°F (38°C).
Heating value between 450 - 500 Btu/ft3.
Water saturated.
11-22
-------
upgraded to hydrogen for use as hydrogenation gas in down-
stream refining facilities. In these cases, the CO will be largely
shifted to hydrogen and the CC>2 will be scrubbed out. Sulfur
compounds need not be removed but probably will leave the sys-
tem with the CC>2. In other systems, the pyrolysis gas will be
mixed with other gases from the process and the total stream
will become a synthesis gas, perhaps for methane manufacture.
In this case, the total gas stream must be more thoroughly desul-
furized according to the techniques discussed for high-Btu gas
production.
In most applications, the gas will be consumed as fuel for
the facility. In these cases, the gas need only be desulfurized
sufficiently to assure adequately clean combustion. This is the
case that is considered in this report.
If the gas is to be used for its fuel value, the only step
necessary before combustion is desulfurization. However, the
available desulfurization techniques will require that the gas be
cooled. In Table II-8 the gas stream has been assumed to be
water-washed at 38 C, removing ammonia, phenols, and other
water soluble materials. Significant quantities of Cj-C^ hydro-
carbons are present as vapors in the gas stream; their effect
upon the operation of the acid gas removal unit is not discussed
in this study.
Although the only sulfur species listed in Table II-8 are
H2S and COS, enough organic-sulfur compounds will be present
to add distinct odors to the gas. These materials may not be
removed in every acid-gas removal system; however, for direct
combustion of the gas, complete sulfur removal is not required.
The distinguishing features of this gas are the greater
concentrations of the higher hydrocarbons, the high heating value
of the gas, and the low pressure at which it exists (1. 27 kg/cm ).
This low operating pressure significantly limits the number of
acid-gas treatment processes that can be economically applied
(see Chapter III and Chapter VI).
2. COMPARISON OF PROCESS GAS STREAMS
Table II-9 summarizes the compositions of the five primary gas
streams that are considered in this analysis. Also included are com-
ponent concentrations of gas streams for representative applications
11-23
-------
where sulfur removal and recovery have been commercialized. The
characteristics of the acid-gas (CO2 +H2S) that are present in these
12 gas streams are examined in the following discussion.
(1) Ac id-Gas Components
The primary parameters considered in evaluating acid
gases from various sources are:
The total quantity of acid gas
The ratio of sulfur to carbon dioxide in the acid gas
The presence of sulfur species other than H2S.
Since the cost of sulfur removal is proportional to the quantity
of acid gas treated, the total quantity of acid gas to be processed
is of major importance. Among primary gas streams presently
processed (Table II-9) that might offer problems in this area,
"Natural Gas A" has a high concentration of carbon dioxide.
The ratio of sulfur to carbon dioxide is important since it
determines if the total acid-gas stream, after recovery, can be
fed directly to a Claus plant. Note that both the catalytic
cracker off-gas and HDS residual gas contain very high sulfur
concentration in the total acid gas; 80 percent to 100 percent
would be excellent feed for Claus type operations. Also, coke
oven gas and "Natural Gas B" have relatively high-sulfur con-
centrations in the total acid gas: 25 percent and 65 percent re-
spectively. Only "Natural Gas A" and the synthesis gas from
partial oxidation offer any problems in this regard. The partial
oxidation gas has a very low S/CO ratio if it is treated after
shifting to a hydrogen-rich stream.
It is seen that only three of the gases now processed con-
tain carbonyl sulfide,-* two contain carbon disulfide and only one
gas contains mercaptans and other sulfur. The concentrations
of these other sulfur compounds can have a definite effect upon
the sulfur treatment scheme utilized.
Note that the COS/H^S ratio for the partial oxidation gas is
similar to thermodynamic expectations.
11-24
-------
Table II-9
Comparison of Gases to Be Desulfurized
,, Hypothetical Process Gas Streams Expected Representative Gases That Have Been Processed Commercially
in Clean Fuel Processes (Vol %) for Sulfur Removal and Recovery (Dry Basis) (Vol %)
Synthesis Gas Cracked Gas
Pipeline Gas Low-Btu Gas Pyrolysis Coke Oven From From Catalytic
Manufacture Manufacture Gas . Gas Partial Oxidation Cracker
CO
H2
CH4
C2H6
N2
CO 2
H2S
COS
cs2
RSH
OtherS
H20
Total
High-
Sulfur
Coal
12.8
40.8
13.0
as
0.2
sa?
1.5
(276 ppm)
0.2
100.0
Low- High- Low- Quenched Shifted
Sulfur Sulfur Sulfur
Coal Coal Coal
12.9 19.7 19.8 17 6.0 49.0 2.1
41.4 14.8 14.9 33 47.0 44.5 62.0
13.1 4.9 4.9 14 32.0 0.5 0.3 65.0
0.8 - 8 5.0 - - 22.0
0.2 49.2 49.6 - 8.0 0.6 0.4 -
31.0 10.0 iaO 21 1.5 4.9 34.8 2.5
0.4 0.8 0.2 2 0.5 0.5 0.4 10.5
(82 ppm) (134 ppm) (79 ppm) (340 ppm) (100 ppm) (220 ppm) (5 ppm) ?
(50 ppm) - - -
7
_
0.2 0.6 ae 5
100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
HOS
Residual Natural Natural
Gas Gas A GasB
- • -
62.5
13.0 62.0 72.0
9.0 14.9 15.4
5.0 0.5
18.0 4.2
15.5 0.1 7.9
(125 ppm)
(10 ppm)
(260 ppm)
(290 ppm)
100.0 100.0 100.0
-------
(2) Major Gas Components
Prior to the treatment of off-gas from heavy-oil partial-
oxidation units, there was almost no basis for comparing gas
streams from clean-fuel processes to currently treated gases as
feeds to acid-gas removal schemes on the basis of their bulk gas
compositions. Except for coke oven gas, which exists at low
pressures and is generally treated by amines, only the off-gas
from HDS treatment contained even hydrogen. There is also
little experience in this country with carbon monoxide. Signifi-
cant background information is available on methane, ethane,
and high hydrocarbons, but none of the gases currently treated,
except partial oxidation synthesis gas., even resembles the
streams to be treated in clean-fuel processes.
The synthesis gas from partial oxidation has a composi-
tion that is most similar to those considered in this report.
Based upon the extreme temperature of operation of the heavy-
oil partial-oxidation units, this gas should be nearly identical
to a Koppers-Totzek off-gas. It may not contain the quantities
of methane and carbon dioxide expected in the new clean fuels
processes, but experience is available on those species. Data
is also available on the acid-gas removal techniques that have
been applied to these gases. These data can be scaled up and
used in the analysis of clean fuels processes with reasonable
accuracy. For those acid-gas removal processes that have not
been previously utilized on partial-oxidation gas, or in lower
pressure gasification facilities overseas, sufficient differences
exist in the processes (e. g., total pressure, partial pressure
of various species, total sulfur content, carbon dioxide concen-
tration) that the validity of extrapolation is less certain.
3. THE PROBLEM OF REMOVING SULFUR IN CLEAN FUEL
PROCESSES
This section discusses the major problems encountered, and
relative levels of desulfurization attainable, when total or partial re-
moval of sulfur is required in the off-gases characterized in this
chapter. This process of gasifying and desulfurizing fossil fuels
prior to combustion is then contrasted to the historical alternative of
direct combustion of the solid fuel followed by stack gas desulfuriza-
tion.
H-26
-------
A general observation concerning desulfurization in clean fuel
processes is that the effectiveness of sulfur removal and sulfur re-
covery are inversely proportional. If high sulfur removal,from the
process gas stream is not required, sulfur recovery techniques can
be very effective. However, when extreme sulfur removal is re-
quired, correspondingly high levels of sulfur recovery cannot be ex-
pected. This effect is caused by the nature of the acid-gas processes
that generally remove both HgS and CC>2 from the process gas stream
simultaneously. The H^S usually can be removed preferentially over
the CC>2 in many removal processes. If high-sulfur removals are
not required, the majority of the CC>2 and a small portion of the H^S
may be left in the gas stream while recovering a stream that is rela-
tively concentrated in H^S. This concentrated H^S stream can be fed
to a conventional Claus plant for sulfur recovery. If, however, nearly
all the sulfur must be removed to a single sulfur-containing off-gas
stream, simultaneous removal of much of the CO2 is also implied.
The resulting H2S-CC>2 stream is too weak for effective Claus plant
operation and the study of other options, discussed in detail in this
report, indicates that a portion of the reduced sulfur species must be
discharged with the final CC^-rich gas.
(1) Sulfur Removal From High-Btu Gas Streams
The distinguishing feature of sulfur removal in the produc-
tion of high-Btu gas is that essentially all the sulfur present must
be removed from the process gas stream to protect sensitive
downstream methanation catalysts. Also, the amount of carbon
dioxide in the final gas stream must be minimized to avoid dilu-
of the final product. Because most processes that remove H^S
are also active for the removal of carbon dioxide (see Chapter
III), these two constituents are removed simultaneously. How-
ever, the ratio of H S to CO2 is low for the two gas streams
presented here. This low ratio causes design problems in the
sulfur removal system (discussed in detail in Chapter IV).
The carbonyl sulfide content of the process gas is only
276 ppm in the case of the high-sulfur coal. Yet, as discussed
later in this report, the carbonyl sulfide is the source of the
majority of the sulfur emissions when treating high-sulfur coal
to manufacture high-Btu gas. Data available from the Lurgi
facility designed for the El Paso Natural Gas Company indicate
that the COS concentration may be significantly higher than the
11-27
-------
equilibrium.value; a thermodynamic basis was nevertheless used
to estimate the COS concentration in this analysis. Until further
data become available, the thermodynamic equilibrium assump-
tion is the only defensible one. However, it must be qualified by
noting that the potential emissions from these systems may be
greater or lesser, depending upon the generation and fate of this
trace constituent, carbonyl sulfide.
Similarly, emissions due to the presence of carbon disul-
fide (CSo) have not been considered in this analysis because ther-
modynamics indicate that CSo concentrations will be extremely
low. Under some gasifier operating conditions, however, the
kinetics of CSg formation may override thermodynamics. Con-
ceivably, when these systems have been studied further, the
occurrence of CS2 may be found to have a significant effect upon
the emissions from the facility. Assumptions similar to that for
CS^ were used when considering thiophenes, mercaptans, and
organic sulfides. In the gases from some low-temperature gasi-
fiers, these organic sulfur-bearing compounds may be trouble-
some; but, at present, there is no reliable basis for estimating
their concentration. It is assumed here that if these components
do exist, their concentrations will be low.
In the case of low-sulfur coal the expected emissions can
be reduced to the minimum level projected in this report. Be-
cause the COS content of the process gas will be less than this
minimum emission level the characterization of sulfur species is
not the overriding factor in estimating emissions. Nevertheless,
if reaction kinetics overwhelm the thermodynamic potential for
COS formation, the emissions due to this species may become
significant, even if the sulfur content of the coal is not high.
(2) Sulfur Removal From Low-Btu and Pyrolysis Gas Streams
The problems inherent in removing sulfur from low-Btu
or intermediate-Btu pyrolysis gas streams are similar for all
gases used for direct combustion as utility fuel. The purpose
of desulfurizing these gases is to reduce the emissions that will
otherwise be present from the combustion of the raw feed. As
an example, in the hypothetical low-Btu gas streams, assuming
80 percent gasification efficiency, the EPA New Source Perfor-
mance Standards for the direct combustion of coal would permit
11-28
-------
the emission of 16 gm-moles/sec (127 Ib-moles/hr) of sulfur.
If the gas can be purified to 250 ppm of sulfur, only 2. 8 gm-
moles/sec (22 Ib-moles/hr) of sulfur would be burned and
emitted as SO2» about one-sixth of the emissions permissible
from direct combustion of the coal. Actually, significantly
lower emissions can be achieved with some acid-gas removal
processes, although penalties are involved. These penalties
include greater removal of carbon dioxide with the hydrogen
sulfide which further decreases the efficiency of the combined-
cycle powerplant, significantly increases the cost of sulfur re-
moval, and reduces the efficiency of the Glaus plant for sulfur
recovery.
The problem of addressing carbonyl sulfide in these gases
is not as great as it was with the high-Btu gas stream. In this
case, even with the COS remaining, very low levels of sulfur
emissions can be realized during final combustion.
(3) Comparison of Desulfurization Before and After
Combustion
The problem of removal of sulfur in clean fuel processes
is substantially different from the removal of sulfur in stack
gases. The purpose of the removal is the same in both instances:
to minimize the occurrence of SCu (and SOo) in the final com-
bustion products emitted to the atmosphere. However, the dif-
ferences between the two methods are significant.
First the sulfur concentration in the clean fuels is much
higher than in stack gases. Typically, after combustion, stack
gas will occupy about 1000 m3/10 kcal (11 x 104 ft3/10° Btu).
The volume of the gasified fuel, however, may be a factor of
10 lower. Therefore, if both of these gases each contain equal
quantities of sulfur, the total sulfur concentration in the fuel gas
would be approximately 10 times greater than the concentration
in the stack gas. This higher concentration of sulfur greatly
simplifies the removal process.
A second important difference between fuel gas desulfuri-
zation and stack gas desulfurization is the state of the sulfur.
In the stack gas, the sulfur is fully oxidized to SO2 (and some
SOo). In the fuel gas, however, the sulfur exists in reduced
11-29
-------
forms such as H^S, COS, mercaptans, organic sulfides, or
thiophenes. The characteristics of these compounds are signi-
ficantly different from SC>2 (and from each other) in odor, toxic-
ity, and reactivity. These differences will be discussed in
greater detail in the next section. The higher reactivity of most
of these reduced sulfur compounds simplifies and improves the
overall sulfur removal system.
A third major difference between the two areas of sulfur
removal is the difficulty of sampling and measurement of the
sulfur content in the gas. The sampling techniques for reduced
sulfur compounds are notoriously difficult. Samples should be
drawn continuously through nonreactive lines until the sampling
system is equilibrated* before meaningful answers can be obtained.
Yet, the sulfur concentration of the raw feedstock to these proc-
esses will probably vary, hour-by-hour, as coal from different
seams or mines is fed to the process. Also, much of the equip-
ment in the process will be mild steel that has a strong affinity
for absorbing reduced sulfur species, particularly at elevated
temperatures and pressures. Obtaining a reasonable sulfur
balance around a coal-fed gasifier, from experimental samples,
is extremely difficult.
In stack gas desulfurization however, these reduced species
are not present. The sulfur contained in post-combustion stack
gases is essentially all SO2. Though accurate sampling tech--
niques are still required, sulfur dioxide is less reactive than the
reduced sulfur compounds and commercially designed measure-
ment equipment which has been available for many years is ade-
quate to determine process conditions.
4. TOXICITY OF SULFUR SPECIES IN CLEAN-FUEL PROCESSES
This section identifies the sulfur forms which may be present in
the off-gases of the streams analyzed and considers their chemical
and physical properties as well as their toxicity and other physiologi-
cal impacts on man.
* Sulfur has reached its correct steady state concentration in the
sampling system.
11-30
-------
(1) Hydrogen Sulfide
Hydrogen sulfide is a colorless, reactive gas. In low con-
centrations this gas has an offensive odor described as that of
rotten eggs. Hydrogen sulfide is heavier than air, having a
specific gravity of 1.19 (air = 1). The gas is soluble in water,
alcohol, petroleum solvents, and crude petroleum. Hydrogen
sulfide is considered a highly toxic gas with a maximum allow-
able concentration of 10 ppm* in a working environment.
Although the characteristic odor of the gas is detectable
in concentrations as low as 0. 025 ppm, it is distinct at 0. 3 ppm,
offensive and moderately intense at 3 ppm to 5 ppm, and strong
but not intolerable at 20 ppm to 30 ppm; the odor of higher con-
centrations does not become more intense. Above 200 ppm, the
disagreeable odor appears less intense. These perceptions are
based upon initial inhalations, and, with continuous inhalation,
the olfactory sense fatigues rapidly. The characteristic odor of
hydrogen sulfide is not considered to be adequate protection for
sensing this gas because of olfactory fatigue.
Hydrogen sulfide is considered a toxic gas that is extremely
poisonous, even in small quantities. The maximum allowable
concentration of hydrogen sulfide for an eight-hour period is
10 ppm by volume (15 mg/m of air) as recommended by the
American Standards Association. Table 11-10 presents the
physiological response to various concentrations of hydrogen
sulfide.
The greater danger from inhaling hydrogen sulfide is sys-
temic. Concentrations of over 600 ppm by volume may result
in death due to the action of free hydrogen sulfide in the blood-
stream. Mortality occurs when the gas is absorbed faster than
it can be oxidized to pharmacologically inert compounds such as
thiosulfate or sulfate. Such oxidation occurs rapidly in man and,
even following inhalation exposure to concentration up to
700 ppm, hydrogen sulfide does not appear in the exhaled breath.
Relatively massive doses are required to overcome this protec-
tive activity of the body. If a victim who has been overcome by
The TLV (threshold limit value).
11-31
-------
hydrogen sulfide is removed to pure air and his respiration is
set in motion by any means before heart action has ceased,
rapid recovery may be expected with no aftereffects.
Table 11-10
Physiological Response to Hydrogen Sulfide
Response
Maximum allowable concentration for prolonged
exposure (TLV )
Slight symptoms after several hours (irritant to
eyes and lungs)
Maximum concentration for 1 hour without
serious consequences
Dangerous after exposure of 0.5 hr (causes
dizziness and headaches)
Can be fatal after exposure of 0.5 hr
Concentration
(ppm)
10
20-150
170-300
400-600
600
Hydrogen sulfide may be expected in the off-gases from
hydrogasification of coal because of the action of hydrogen upon
the sulfur in the coal. Thermodynamic analysis indicates that
the majority of the sulfur in the process gas stream should
occur as hydrogen sulfide.
Because hydrogen sulfide is reactive and readily soluble
in many materials, several processes have been commercial-
ized for its removal from gas streams, as discussed in this
report. The reactivity of hydrogen sulfide also permits its re-
covery as elemental sulfur by several processes (see Chapter III).
The removal and recovery of hydrogen sulfide is not expected to
be a major problem in most coal gasification systems.
11-32
-------
(2) Carbonyl Sulfide
Carbonyl sulfide (COS) is a colorless gas that is odorless,
when pure; however, carbpnyl sulfide is rarely found in the pure
state. Usually it is partially reacted to hydrogen sulfide, and
the odor of this material will give warning that sulfur compounds
are present. However, the pure compound is odorless and gives
no warning of its presence.
The toxicity of carbonyl sulfide is not well defined. Though
only a mild irritant to the lungs, it acts on the central nervous
system. Death comes from respiratory paralysis. Experience
involving exposure of human beings has not been recorded. It is
probable that the effects of COS can be assigned to the action of
hydrogen sulfide resulting from partial decomposition in the
lungs. Since the most harm to man appears to be when the COS
hydrolyzes to HgS, the TLV for COS may eventually be set some-
what higher than for hydrogen sulfide.
Carbonyl sulfide, like hydrogen sulfide, is soluble in water
and many organic solvents. This solubility, however, is signifi-
cantly less than hydrogen sulfide^ causing some of the problems
of carbonyl sulfide recovery discussed in other sections of this
report.
The chemistry of carbonyl sulfide is similar in many ways
to that of hydrogen sulfide--with the carbonyl ion replacing two
hydrogen ions. For example, it can react with metals, forming
metal sulfides and carbon monoxide. Carbonyl sulfide is less
reactive than hydrogen sulfide; this may be ascribed to the
ability of hydrogen sulfide to lose hydrogen ions sequentially;
however, carbonyl sulfide must release the carbonyl ion in a
single reaction. Also, carbonyl sulfide behaves somewhat like
a thiocompound of carbon dioxide, with one sulfur ion replacing
an oxygen ion. This effect may also explain the greater sta-
bility of the carbonyl sulfide species.
The primary chemical reactions of carbonyl sulfide that
are used in this report are the hydrogenation reaction:
H2 + COS ** H2S + CO
11-33
-------
and the hydrolysis reaction:
H2O + COS & H2S + CO2
These two reactions are interrelated by the water-gas shift re-
action:
H2O + CO -*± H2 + CO2
because the hydrolysis reaction may be considered as the sum
of the hydrogenation reaction plus the water-gas shift reaction.
Note that the sulfur species in the hydrogenation reaction be-
have precisely the same as one of the oxygen atoms in the re-
verse of the water-gas shift reaction. This indicates the cor-
respondence of the oxygen and sulfur in these reactions and the
possible thionature of the sulfur. One of the major considera-
tions in this study has been to evaluate conditions that promote
either the hydrolysis or hydrogenation reactions of carbonyl
sulfide to hydrogen sulfide because the hydrogen sulfide species
can be readily removed from process gas streams by applying
existing commercialized technology.
The existence of carbonyl sulfide in the process gas
streams from the clean fuel processes has been confirmed by
several investigators; however, there is no hard data to estimate
the concentration of carbonyl sulfide that may be present. The
sampling and measurement techniques for reduced sulfur species,
as discussed earlier, are extremely difficult to perform; good
quantitative data on the occurrence of carbonyl sulfide have not
yet been obtained. At present, one can only estimate the con-
centration of carbonyl sulfide on a thermodynamic basis,
assuming equilibrium is obtained between sulfur, hydrogen,
carbon, and oxygen at the operating temperature and pressure
of the gasifier, according to the hydrogenation reaction. On this
basis, approximately 4 percent of the sulfur in the raw product
gas will exist as carbonyl sulfide and most of the remainder will
be hydrogen sulfide. This value for the concentration of COS
is one of many that could have been selected. The concentration
of carbonyl sulfide can be greater or less than predicted by
11-34
-------
thermodynamic considerations, depending upon the direction from
which equilibrium is approached and the kinetics of the hydro-
genation reaction. The pres.ently available data are contradictory:
some data indicate that COS may be present in greater than equi-
librium concentrations, and other data suggest that its concen-
tration will be less than expected thermodynamically. At present,
thermodynamics must be used as the basis for estimating the COS
concentration in the process gas streams of clean-fuel processes.
Some processes for clean-fuel processing will employ a
water-gas shift reactor in order to modify the molar ratio of
hydrogen and carbon monoxide in the gas. Certain catalysts for
this duty are resistant to sulfur poisoning and may also promote
the hydrogenation of carbonyl sulfide. If these catalysts are used
in a process, the carbonyl sulfide concentration in the process
gas stream may be reduced, as will be discussed in Chapter III.
(3) Carbon Disulfide
Under normal conditions, carbon disulfide (082) is a color-
less liquid that has a slightly ethereal odor that does not offer
adequate warning in the lower concentration ranges. Table 11-11
lists six representative levels of effect upon man, with corre-
sponding ranges of concentrations of inhaled carbon disulfide.
The concentrations of carbon disulfide required for various
effects are much greater than found with hydrogen sulfide (cf.
Table 11-10). Nevertheless the maximum allowable concentra-
tion for prolonged exposure has been determined as identical to
hydrogen sulfide at 20 ppm (1962), (60 mg/m3 of air). *' The toxic
effect is chiefly on the central nervous system when, in high con-
centration, it acts as an anesthetic with respiratory failure caus-
ing death.
In 1962, the threshold limitation value for H2S was 20 ppm. It
has since been reduced to 10 ppm.
11-35
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Table II-11
Effects of Various Concentrations
Of Carbon Disulfide on Man
Effects
Slight or no effect
Slight symptoms after several hours
Symptoms after 0.5 hr
Serious symptoms after 0.5 hr
Dangerous to life after 0.5 hr
Fatal in 0.5 hr
Concentration
(ppm)
160-230
320-390
420-510
1150
3210-3850
4800
Carbon disulfide is dimolecular in sulfur and is the sulfur
analog of carbon dioxide. It can undergo single hydrolysis to
carbonyl sulfide and hydrogen sulfide:
HoO +
COS +
H2S
Similarly, it can undergo double hydrolysis to hydrogen sulfide:
2H2O + CS2
CO2 + 2H2S
The hydrolysis reactions above were used as the basis for esti-
mating the concentration of CS2 in the process gas streams on
a theoretical, thermodynamic basis. These calculations indi-
cate that the concentration of carbonyl sulfide in the process
gas streams should be very low; only small quantities of
the total sulfur in the gas should exist as carbon disulfide.
This fact, combined with the known high solubility of CS2 in
organic liquids, indicates that very little carbon disulfide should
reach the acid-gas removal section of most of these facilities.
Consequently, this species was not given great attention in this
study.
11-36
-------
It should be rioted, however, that €82 may be formed in
much greater than thermodynamic quantities in some processes,
and its possible presence should not be ignored in any detailed
engineering evaluation.
(4) Other Organic-Sulfur Compounds
Potential for formation of many species of organic sulfur
compounds exists in clean-fuel processes. This series of com-
pounds includes mercaptans, thiophenes, organic sulfides, and
other sulfur-containing organic compounds. Thermo dynamic ally,
these compounds should not be expected in most of these pro-
cesses. The high concentrations of reducing compounds and the
elevated temperatures existing in most clean fuels processes
should cause the destruction of these compounds, primarily to
hydrogen sulfide. However, in those processes that produce
significant quantities of tars and heavy oils, the operating con-
ditions are correct for significant concentrations of organic-
sulfur compounds in the process off-gas.
In general, organic-sulfur compounds are high molecular
weight species with low vapor pressures and high solubility in
hydrocarbon liquids. Characteristically, the vapors from these
compounds are foul-smelling, causing the odors characteristic
of skunk, natural gas odorant, and decaying organic matter.
This odor problemjwill be the most pronounced effect should
any of these compounds be discharged to the atmosphere. High
concentrations of mercaptans can produce severe headaches,
nausea, and unconsciousness with cyanosis. Thiophenes are a
clear and colorless liquid whose toxicity is unknown. Experi-
ments with animals indicate that thiophenes are moderately
toxic for higher exposure levels.
Discharges of organic-sulfur compounds in significant
quantities are not expected in these processes. In those sys-
tems where they are formed, they will generally be removed
from the process with the by-product tars and oil. If the pro-
cess gas is to undergo a water-gas shift reaction over sulfur-
tolerant catalysts, the organic-sulfur compounds will be hydro-
desulfurized in this step. Last traces of these compounds will
be removed in either the initial steps of acid gas treating or in
the sulfur guard beds. For these reasons, in addition to the low
11-37
-------
thermodynamic potential for their occurrence in most gasifica-
tion schemes, these compounds were not evaluated extensively in
this program. However, in any detailed study of a specific sys-
tem, the occurrence and disposition of these materials should
be addressed.
The toxicity of reduced sulfur species may be compared to that
of SOg, the compound upon which most environmental considerations
are based. The TLV for HgS is 10 ppm; and for CSg, 20 ppm. Al-
though TLV s have not yet been established for COS and other organic-
sulfur compounds, they are expected to be set higher than for H^S.
The TLV for SC^, however, is 50 ppm, inferring lower toxicity for
the reduced sulfur species.
11-38
-------
III. IDENTIFICATION AND APPLICABILITY
OF SULFUR REMOVAL AND RECOVERY PROCESSES
-------
III. IDENTIFICATION AND APPLICABILITY
OF SULFUR REMOVAL AND RECOVERY PROCESSES
To desulfurize gas streams — whether they be from natural gas
fields, petroleum refineries, or manufactured gas .plants (e. g. , SNG,
synthesis gas) — many processes have evolved and are being used,
and many more are now becoming commercially available. Though
development of desulfurization techniques began before the turn of
the century, numerous problems remain to be solved in the puri-
fication of synthetic fuel gases for use either as a clean fuel in
electrical utility plants, or for commercial, industrial, and resi-
dential applications.
The sulfur compounds existing in these gas streams can cause
corrosion problems and catalyst poisoning during processing. These
compounds, if released to the environment, are polluting, but can be
treated to recover a salable by-product. For these reasons, and
especially because ofthe recent increased environmental concern
over the occurrence of these compounds in the atmosphere, there
has been continued development to find widely applicable, efficient,
yet economical methods of purifying these gas streams.
Many of these treatment methods have been developed to satisfy
specific plant needs. This chapter presents a discussion of the appli-
cability of each to the typical gas streams defined in Chapter II.
First to make that discussion more meaningful, the sulfur treatment
methods available are first identified and their characteristics are
reviewed. Then those processes specifically applicable to the repre-
sentative gas streams are discussed in more detail.
1. IDENTIFICATION OF SULFUR REMOVAL AND RECOVERY
TECHNIQUES
Treatment methods developed to remove and recover sulfur from
fuel gases range from simple one-step water washing operations to
complex multistep regenerative-recycle systems. The primary opera-
tion of all sulfur treatment processes, however, can be defined as one
of the following:
III-l
-------
Absorption of gas stream imparities into a liquid. In
absorption-type processes, the gas stream is usually
passed through a liquid in a tower. The gaseous impuri-
ties are either physically or chemically dissolved in the
liquid absorbent. The absorbent may be later stripped of
these impurities, regenerated, and recycled.
Adsorption of impurities onto the surface of a solid. In
adsorption processes, the gas stream is passed through
a fixed bed of granulated solid material. The adsorbate
is removed from the gas and held in the solid adsorbent.
Chemical conversion of impurities into more easily
treatable or more desirable forms. By passing the gas
stream through fixed beds of various catalysts (similar
to adsorptive techniques), the impurities can be con-
verted to less objectionable compounds or forms which
can be subsequently removed more easily than in their
original form.
Due to the myriad of processes mentioned in the published lit-
erature, a more refined classification of the identified processes is
desirable. Therefore, the basic treatment techniques have been
divided into the following process groups:
Basic Treatment Technique Process Group
Absorption Amine solvents
Ammonia solutions
Alkaline salt solutions
Organic solvents
Absorption of SO2
Adsorption
Chemical (catalytic) By reduction to IL^S
conversion By oxidation to sulfur
Dry processes
Liquid processes
By oxidation to oxides of sulfur
Many treatment techniques are a hybrid design or a combination
of several basic processes, and can therefore be placed in more than
one of the listed groups. To prevent duplicate entries in the discussion
III-2
-------
which follows, each process has been discussed under the group it
most closely resembles. In the following sections a brief introduction
to each group of control processes is given. The licensed processes
in each group are identified and characterized in summary tables in
which the following data are given:
Process Name and Developer. Each process is identified
by its marketing trade name and its original developer or
principal licensor. Where numerous firms are offering
the same process, the generic name is used along with
the name of one or more of the more significant suppliers.
Range.of Treatment. The range of pressures and tem-
peratures that each process can accept (or was designed
to treat) is defined. For processes composed of numer-
ous unit processes, the conditions described are for in-
troduction to the first of these unit processes. Though
some of these ranges may at first seem to restrict their.
use in treating many of the previously characterized gas
streams, they may be modified by use of heat exchangers
and pumping schemes, or the treatment process itself
might be redesigned to permit its application to the
specific stream being studied.
Components Removed. The principal species of sulfurous
compounds removed from acid gas streams by each of the
treatment processes are defined.
Hydrogen Sulfide Selectivity. Acid gas removal processes
remove CO2 as well as t^S. The degree to which they can
selectively remove HgS is an important consideration in
Determining if a concentrated H^S effluent can be
generated for feed to a Glaus sulfur recovery plant
Their ability to achieve desired levels of desulfur-
ization in low I^S yet high CO^ stream concentra-
tions
Defining the economics of the process
Assessing its applicability to treatment of the pro-
posed gas streams.
Ill-3
-------
Limitations. Some of the more prominent characteristics
which restrict the use of each treatment process are
briefly noted. Operating difficultues and utility require-
ments which may conspicuously affect their applicability
are also mentioned.
Status of Commercialization. The historical usage, state
of development, and commercial availability of each pro-
cess is indicated
Abstract. Salient comments, including brief process de-
scriptions and process accomplishments, are presented.
(1) Absorption Processes
Chemical and physical absorption processes are widely
accepted as important gas desulfurization techniques. Five
groups of absorption processes are described synoptically in
this section.
1. A mine Solvent Processes
Table III-l presents data on eleven amine processes
in format described above. Figure III-l gives a typical
process flow diagram.
Amine processes have been widely used in natural
gas, refinery, and synthesis gas sweetening in large part
due to their reliable operation. The primary impurities
removed from these streams are HpS and COo. In gas
streams containing other impurities (e. g., organic sulfur
compounds or other organic compounds), the amine solu-
tion may become nonregeneratively poisoned.
In this group of processes the sour gas feed con-
tacts a basic amine solution in a scrubbing tower where
acid gases are absorbed. The E^S and CCX^-rich amine
solution is regenerated by stripping, and it is then re-
cycled back to the absorber.
HI-4
-------
TYPICAL SCHEMATIC:
cw
RICH AMINE SOLUTION
SWEETENED GAS
SOUR GAS STREAM '• »
ABSORBER
ACID GAS
CONDENSER AMINE
SOLUTION
STRIPPING
LOW AMINE COLUMN
SOLUTION
TYPICAL REACTION:
RNH +H2S
(The reaction is reversible
with application of heat. )
FIGURE III-l
Typical Schematic and Reactions for Amine Processes
elude:
Problems encounted in this category of process in-
Corrosion of metal surfaces in the stripper
and heat exchangers by the acid gas. This
may be minimized by employing corrosion-
resistant metals and by using low steam
temperatures
Foaming which requires addition of inhibitors
Loss of solvent by vaporization or degrada-
tion which increases replacement cost and
may poison downstream catalysts
Cyanides, and in some cases organic sulfur,
for nonregenerable compounds.
Ill-5
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III-6
-------
Table III-l
Summary Data on Amine
Solvent Processes
GROUP
Amines (Chemical Absorption
PROCESS - DEVELOPER OR LICENSOR
Monoethanolamine (MKA) - Girdler
IJiethanolamine (DKA) - Girdler
SNPA-DEA'- Societe National des Petrols
d'Aquitaine - Ralph M. Parsons Co.
Triethanolamine (TKA) - Girdler
Methyldiethanolamine (MI)KA) - Girdler
Glycol-Amine (DKG-diethylene glycol and
MEA or TKG-triethylene glycol and MKA)
I>i-isopropanolamine (I)IPA) - e. g. , A.\
Widely eoiniiier<-i;iljx,.(|
Active in II. S. and
Canada: used for manu- •
I'actured or refinery gas
sweetening
Commercialized; developed
for natural gas sweetening'
Karliest alkanolaminc process
to be commercialized: not now
in wide commercial use
In declining commercial use
Commercialized
Active
Commercial i?.ed
Active in hydrogen gen-
erator plants, natural
gas streams and ammo-
nia plants; has gained
wide acceptance
ABSTRACT
Keonomical (low solvent cost): highly reactive; due to low
molecular weight has highest capacity for I! S as compared
to other amine processes: very stable: easify reclaimed
from contaminated solutions (usually stripped and regen-
erated by steam); MKA is the major amine sorbeht; ex-
cellent process for, Cjnal cleanup (can attain better than
0. 25 grains/ 100 ft" of IIS for pipeline gas from as high
as several percent II.S): can effectively treat H S:CO.
ratios or between 1:70 -* 20:1
Kesists degradation in presence of COS and C'S9; high acid-
gas partial pressure enhances this sorbent system; has lower
vapor pressure than MKA process"
A modification of the DEA process; can reduce high pres-
sure, high acid gas concentrations (9% to 25%) to pipeline
specifications; solution can be regenerated with steam with
sulfur compounds fed directly to a Claus unit; compared to
MICA, this process has a lower solution circulation rate,
lower utility consumption, and lower vapor pressure (less..
solution losses): C'OS is partially removed without degrad-
ing absorbent; removed. acid gas contains few hydrocarbons
to reduce purity of elemental sulfur, if produced
Par'iallv selnctive towards II S removal
Partially selective towards HgS removal
Simultaneously dehydrates and purifies high. pressure
natural gas; 'requires less steam consumption than
Ml-: A or OKA processes
Acid gases are stripped off and the solvent regenerated by
steam; noncorrosive; low steam consumption; can meet
pipeline specifications; recovers r^S with good selectivity
High operating, concentrations and low heat requirements
permit lower investment and utility costs than for other .
amine processes; low absorption of heavy hydrocarbons
yields a good sulfur plant feed; can purify 2 to 8% H.S
streams to p;peline quality
Combines characteristic? of a solvent and amine
process: see organic solvent process section
m-7/8
-------
For high acid gas concentration streams (e.g. , greater
than. 30 percent) the heat requirements to strip the ab-
sorbed material tend to make these processes relatively
uneconomical. Amine processes are usually the economi-
cally preferred acid gas removal system for low pressure
applications; other systems may become more economi-
cally favorable at higher pressures.
2.
Ammonia Solution Processes
Data on four ammonia solution processes are pre-
sented in Table III-2. Figure III-2 illustrates a typical
flow for these processes.
TYPICAL SCHEMATIC:
PURIFIED GAS
SOUR GAS •
ACID GAS
SOLUTION
TYPICAL REACTION:
2NH
NH
(NH4)2S
FIGURE III-2
Typical Schematic and Reactions for Ammonia Solution Processes
III-9
-------
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Ill-10
-------
Table III-2
Summary Data on Amine
Solution Processes
GROUP
. Ammonia Solutions
PROCESS - DEVELOPER OR LICENSOR
Chemo-Trenn
Collins
Marlno-Rufite Industrial
Ammonia Scrubbing - Showa Denko"
RANGE OF TREATMENT
Stream Pressure
(psi) (Pa)
Low
Low
Low
Low
Stream Temperature
<°F) (°K)
70
70
70
70
COMPONENTS REMOVED
H2S
Yes
Yes
Organic
Sulfur
Compounds
C02
Yes
Yes
H2S SELECTIVITY
No
No
LIMITATIONS
Ammonia washing does
not appear to have the
capability for excellent
acid gas removal, com-
pared to the alternative
processes listed in this
section.
• STATUS OF
COMMERCIALIZATION
Commercially used in
England and Europe
Under development in
Mexico; ammonia sulfate
market is poor; most
applied to small plants
Under development in
Japan; same comments
as for Marino process
ABSTRACT
Also removes HCN; removes acid gases with ammonia
contained in acid gases; CO_ and H.S stream remains
after ammonia is stripped off
Also removes HCN; primarily a process to separate .
ammonia, from acid gas
Treats SO- in Claus tail gas; produces ammonium sulfate
• as fertilizer
Treats SO^ in Claus tai! gas; produces ammonium sulfate
as fertilizer
III-11/12
-------
Aqueous ammonia solutions have been widely used
to sweeten coal gas. These streams remove not only Hr>S,
but organic sulfur compounds and nitrogen (as ammonia)
as well. H2S and NH3 were historically removed to pro-
duce sulfur and nitrates which are valuable by-products.
In addition these gases are highly corrosive if not removed
from the process stream.
In these continuous processes, similar to amine
treatment, the sour gas passes through the absorber solu-
tion where H2S and CC^ are removed. The absorbent can
be stripped by heat in a regenerator and recirculated to
the absorber.
Ammonia washing does not appear to have the capa-
bility for excellent acid gas removal, compared to the
alternative processes listed in this section.
3. Alkaline Salt Solution Processes
Eleven absorption processes employing alkaline salt
solutions are summarized in Table III-3. Figure III-3
presents a typical schematic for these processes.
A number of processes have been developed in which
alkaline salt solutions (a base), such as sodium or potas-
sium carbonate, have been used to absorb acid gases.
These solutions are easily dissociated to permit regenera-
tion of the solution. Though not highly selective, H2 S is
absorbed into the solution at a faster rate than CO2 ; thus,
a de facto partial selectivity can be achieved. The level
of acid gas removal, however, may be satisfactory for
many requirements, although the process gas stream
may still require treatment for residual sulfur.
The alkaline salt solution absorbs sulfur compounds
from the sour gas. If the feed is at high pressure, the
absorber solution can be stripped and regenerated by
flashing. A reflux drum returns additional condensed
absorbent to the regenerator.
Ill-13
-------
TYPICAL SCHEMATIC:
REFLUX DRUM
SWEETENED GAS
ACID GAS
SOUR GAS ; »•
ABSORBER
««
LOADED
SOLUTION
RECYCLED
ABSORBENT
TO SULFUR
RECOVERY
CONDENSED ABSORBENT
REGENERATOR
TYPICAL REACTION :
KHS
FIGURE III-3
Typical Schematic and Reactions for Alkaline Salt Solution Processes
4. Organic Solvent Solution Processes
Table III-4 summarizes data on seven organic sol-
vent solution processes and the general schematic for
these processes is given in Figure III-4.
As the acid-gas fraction of a gas increases, the
cost of applying heat regenerated solvent processes in-
creases. A group of organic-solvent based processes
has been developed which physically dissolves the acid
gases and can be regenerated by flashing. Therefore no
additional heat need be supplied.
Organic solvent processes are therefore most appli-
cable for high pressure applications. These processes ab-
sorb substantial amounts of organic sulfur compounds
IH-14
-------
Table III-3
Summary Data on Alkaline Salt
Solution Processes
GROUP
Alkaline Salt Solutio
PROCESS - DEVELOPER OR LICENSOR
Caustic Wash
Seaboard - Koppers Co.
Vacuum Carbonate - Koppers Co.
Hot Potassium Carbonate (Hot Pot) - U. S. Bureau of Mines
Catacarb - Eickmeyer
Tripotassium Phosphate - Shell
Benfield - Benfield Corp. . •
Alkacid - I. o. Farbentndustrle
Sodium Phenolate - Koppers Co.
Dolomite Acceptor
Molten Carbonatp (Hattcllo).
RANGE OF TREATMENT
Stream Pressure
(psi) (Pa)
No'
Con' rolling
Low
2-20
100 or
higher
C'an be
200 to
pipeline
pressu re
but usually
300-500
400
(1-1000)
100 ••
3000
1-150
1.200
Stream Temperature
(<*•> (°K)
230-
284
120-260
90-
130
T -»
anib
400 ' .
COMPONENTS REMOVED
H2S
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes.
Sulfur
Compounds
Yes
Yes (CS
and COS)
COS and
CS2;
mercaptans
hard to
remove
COB and
CS2
No
No
COS
C°2
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Yes
Yes
Yes
H S SELECTIVITY
NO
Partially
Partial
Can be made
selective
Can be made •
partially
selective
Partially
Can be made
partially
selective
No '
Yes
- No
Partially
LIMITATIONS
Typically
nonregonprable •
Disposal of foul air is re-
quired; HCN forms non-
regenerable salts; H2S
contaminates air used
during regeneration
CO. is not completely
stripped and gradually
decreases absorption ca-
pacity; napthalene, if
present, will solidify and
- plug equipment
• Solution has limited carry-
ing capacity; only removes
H2S in presence of CO2;
corrosion problems; for
complete H2S removal a
final purification step .is
necessary; has little mer-
captan removal .ability;
cannot be followed by a'
Claus unit if'CX>2 content •
is too high unless operated
selectively
Unable to achieve low levels
of H S removal without com-
plicating the process with
split stream or two-cycle
units: can be applied to high
pressure .gas streams with
high acid gas partial pres-
sure; corrosion is a prob-
lem: recovery of sulfur is
usually not possible if
operated nonselectivly.
Similar to Benfield process.
Requires more energy in
form of stripping stream
than in other scrubbing
processes (i.e.. MEA)
Low efficiency of H2S
removal (90%); high
steam consumption;
corrosion problems
STATUS OF
Commonlv l-5f*d Kor
Final Purification
Inactive; was commercialized
for coke oven gas but now
obsolete
Inactive; was mostly used for
coke oven gas sweetening
Active
Active; can sweeten
natural gas; widely used
to purify ammonia
synthesis gas
Not currently important;
largely replaced by amine
processes for treating re-
fining and natural gas
• streams
Used overseas
Obsolete
Under
development
ABSTRACT
Kmplovp caustic .(NaOID-solution for removal of !!„£,
ff'c. Commonlv and for trace removal af'cr bulk
purification hy o'her techniques
Simple and economical; removes HCN too; one of earliest
commercialized processes; based on absorption of H S
by a dilute sodium carbonate solution and regenerated by
air; the M_S and CO are not recovered during stripping:
has been superseded by newly developed processes
Outgrowth of Seaboard process; no longer important; re-
moves HCN too but HCN does not degrade process: uses
vacuum distillation instead of air to regenerate absorbant;
H_S is recovered; uses potassium or sodium carbonate
(Na2 003) solutions
Active ingredient is Potassium Carbonate (K2CO3>; low
investment; primarily a bulk removal process but can be '-
followed by an amine process; lower absorption losses
and improved economics when compared to amine systems;
high temperature absorption eliminates heating requirement
for stripping (usually by steam or pressure swing stripping);
can treat medium and high content H2S streams; not degraded
by COS and CS2 (these are hydrolized to H2S and CO2>
Agents include. a hot KZ CO3 + amines + V2 °5 catalysts;
primarily a CO_ removal process; an improvement in the
Hot Pot process (more active solution, less easily con-
taminated; increased capacity; less corrosion; cheaper);
no heat exchange equipment is required as is for amine
processes
Uses tri-potassium phosphate (K$ PO4); not degraded by COS
and other trace impurities; K2 PC*4 is -nonvolatile and therefore
is adaptable to high-temperature applications; solution is
usually regenerated by heat; process is similar to Hot Pot
process.
Modification of Hot Pot process; uses K2 CO2 + DEA
'additive; primarily CO2 removal process; can be
designed to selectively remove H2S from CO2 and
feed to a sulfur recovery process; can meet pipeline'
sulfur specs
Three variations: all use conventional heat-regenerative cycles
Solution "M" - uses sodium alanine when onlyH^S and/or CO2
is present . ' •
"dik" - a glycerine salt; selectively removes H^S only;
may be reactivated
"S" - sodium phenolate; when appreciable amounts
of HCN, ammonia. CS,. mercaptans, dust
P '
Employs sodium phenolate'iri a heat regeneration cycle; high
H S capacity; can treat Claus tail gases
Uses calcined dolomite or limestone in fluidized
absorption process; acceptor is regenerated with
steam and CO2
US dissolves in a molten solution of Na CO, or -
K CO ; regenerated chemically
111-15/16
-------
TYPICAL SCHEMATIC:
SWEETENED GAS
SOUR GAS
ABSORBER
ACID GAS
ATMOSPHERIC
FLASH
VESSEL
RECYCLE
FIGURE m-4
Typical Schematic for Organic Solvent Solution Processes
(high solution capacities), including COS, CS2» and mer-
captans, and they operate best with high concentrations
(high partial pressure) of acid gas in the gas stream to be
treated. The gas stream is purified in an absorber con-
taining an organic solvent solution. The acid gases are
selectively dissolved in the solvent. The loaded solvent
is regenerated in a flash vessel and the acid gases are de-
sorbed and removed. Solvent loss may become a problem
in these processes, particularly for some of the more ex-
pensive solvents. Some heavy hydrocarbons are absorbed
and cannot be selectively recovered; this may hinder sub-
sequent sulfur recovery efforts. In addition, the acid gas
removal by use of organic solvents may not be complete
and the gas often requires additional purification.
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111-18
-------
Table III-4
Summary Data on Organic
Solvent Solution Processes
GROUP
Organic (physical)
Solvents
*
Other
PROCESS - DEVELOPER OR LICENSOR
Rectisol - Lurgi Gesellschaft fur Warmetechnik
& German Linde
Selexol - Allied Chemical Corp.
Fluor Solvent - r^S Removal - Fluor Corp.
Purisol - Lurgi
M-Pyrol-GAF
Estasolvan - UHDE
Sulfinol - Shell
Water Wash
RANGE OF TREATMENT
Stream Pressure
(psi) (Pa)
£300
>300
850-1.000
1000
Not Pressure
Sensitive •
500
Stream Temperature
-40 to
-70F
sub-
ambient
T , or lower
am
^"amb
110
T .
amb
COMPONENTS REMOVED
H2S
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Organic
Sulfur
Compounds
Yes
Yes
Yes
-
-
Yes;
mercaptans
too
No
co2
Yes, but
at a
slower
rate than
2
Yes
Yes
Yes
Yes
Yes
Yes
H2S SELECTIVITY
Yes, in some
flowsheets;
can be operated
selectively since
sAuble than CO2
Yes, if desired;
can be operated
selectively since
H S is more
soluble than CO2
•Can be operated
selectively since
H2S is much more
soluble than CO2
Yes, if desired
_
Not now selective;
however capability
for selectivity
exists
Partially
LIMITATIONS
Complex flow scheme
for selective case;
high vaporization loss
of solvent; requires •
very low temperatures
to minimize solvent
vaporization losses;
absorbs heavy hydro-
carbons + oils
selectively; C^, Cg
losses high
Not designed for low.
pressures or low acid
gas concentrations
(10 grains/100 ft3);
absorbs heavy hydro-
carbons; solvent is
expensive
The solvent retains
heavy hydrocarbons
. which must be removed
by charcoal adsorption
before feeding to a
sulfur recovery unit
Heavy hydrocarbons
are absorbed
Solvent is expensive; some
hydrocarbons are soluble
in the sweetening agent and
if followed by a Claus unit,
must be filtered out first
II S not very soluable in
HgO except at high ?T2S
partial pressures; has
excessive power require-
ment for pumping because
of high liquid-circulation
rate; corrosion can occur *
STATUS OF
COMMERCIALIZATION
Commercialized mainly
for synthesis gas
cleanup
Commercialized
Commercialized to
purify natural gas
Commercialized
Inactive; not commer-
cialized in U.S.
Active in hydrogen gen-
erator plants, natural
gas streams and ammo-
nia plants; has gained
wide acceptance
Historical process
' ABSTRACT
Physical absorption in cold methanol as the solvent;
operates at relatively low temperatures (***-40F)
low heat requirements and generally low energy
consumption; all undesirable impurities are
removed in one process: high solvent loading at
high partial pressures; gas is dehydrated and de-
oiled too; If S selectivity permits concentrating -
IIS for feea to a Claus unit; solvent is inexpensive
compared to others; doesn't foam; no corrosion
problem; low vaporization losses; methanol is
regenerated; absorbs IICN too.
A glycol ether; also dehydrates; aimed at bulk
removal of CO and IIS from up to 5% of-acid
streams; regenerated oy release of pressure and
heating or air stripping; HgS pipeline specs can be
met; no corrosion problem; low vapor pressure
keeps solvent losses low; can be fed to a Claus plant.
Uses -a propylene carbonate; no regenerative
heat required as gas is desorbed by flashing
to lower pressures: can purify to pipeline
quality: absorbs water vapor arid hydrocarbons too;
solvents are non-corrosive and high capacity; low
solvent vapor pressures result in low vaporization
pressure, high II S content streams; can be followed
by Claus process.
Active ingredients are'NMP or M-Pyrol; aimed at:
bulk removal of acid gas but pipeline specs are
attainable for H^S; can selectively remove H^S
even from low H2S:CO2 streams and feed to a
Claus unit; regenerated by pressure reduction;
can treat high pressure, highly sour gases at
• ambient temperatures; doesn't foam; no corrosion:
low vaporization losses; no regenerative heat re-
quired; can concentrate H2S for feed to a sulfur .
plant.
Regenerated by outside gas stripping thereby
saving steam but decreases II S concentration
to a sulfur plant.
Combines characteristics of a solvent and amine pro-
cess; most applicable when H S;CO is > 1; economics
improve for high II S content (even >50%); dehydrates
somewhat; uses conventional absorption- regeneration
cycle; active ingredients are aqueous solutions of
sulfolane (tetrahydrothiophene dioxide) plus amine (i.e..
DIP A); improvement over MEA process due to lower
solution circulation rates and lower steam requirements;
can .purify high II S concentration streams to pipeline
quality; no foaming tendencies; low corrosion rate
Active ingrediant is II_O; readily available and at
low cost; particularly applicable to treating large
volumes of gas; primarily a bulk CO removal
.process; low heat load required; for additional
purification one must use a second process (e.g., '
amines); the process would be most effective
with high pressure and high US concentration gas;
regeneration of the water is by pressure reduction
and flashing so stripping steam is not required
111-19/20
-------
5. Processes Based on Absorption of SO
^
Table III-5 presents data on a large number of SC>2
absorption processes, typified by the flowsheet and reac-
tions shown in Figure III-5.
TYPICAL SCHEMATIC:
TREATED GAS
TO STACK
WATER
I
SO2 CONTAINING.
GAS
SCRUBBER
SOLUTION
MAKEUP
*
PUMP
TANK
DEWATERING
TO WASTE
SLIPSTREAM
TYPICAL REACTION:
CaSO
FIGURE III-5
Typical Schematic and Reaction for SO
Absorption Processes
Although SO2 is not present in most clean fuel pro-
cess streams, it may occasionally occur (i. e. , following
incineration of Glaus effluent or in the plant boiler stacks).
A large number of procedures has been investigated to
remove this pollutant from stack gases. Typically, lime
or limestone slurries can be used in a wet scrubber to
absorb SO2. A slip stream containing reaction products,
such as fly ash, is passed through a dewatering operation.
The dewatered waste can be sent to a disposal pond or land-
fill site.
The difficulties in recovering sulfur or sulfur dioxide
from stack gases evolved from combustion operations (i.e.,
steam and power plant boilers or incinerated tail gas
streams) are due to the following:
III-21
-------
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HI-22
-------
Table III-5
Summary Data on SO2
Absorption Processes
GROUP
Absorption of £0?
PROCESS - DEVELOPER OR LICENSOR
•
Wet Limestone - Several Developers (Combustion
Engineering)
Dry Limestone - TVA
Carbide-Lime - Combustion Kngineoring
New Lime - Mitsubishi .Heavy Industries
Cominco Sulfur Dioxide Recovery - Consolidated Mining
and Smelting Co.
Double -Alkali - GM; FMC; Envirotech; A. D. Little/
Combustion Equipment Assoc. ;
Chemico
Wellman-Lord SO_ Recovery - Davey Powergas Inc.
Catalytic Oxidation (Cat -Ox) - Monsanto Co.
Citric Acid - U.S. Bureau of Mines (also known as
Citrate Process)
Magnesia Slurry Scrubbing - Chemico (also called
Mag-Ox Slurry Scrubbing or Chemico Process)
Chiyoda Thoroughbred 101 Flue Gas Uesulfurization -
Chiyoda Chemical Engineering & Construction Co.
Dimethylaniline Absorption - American Smelting &
Refining Co.
Grillo - A. G. Puer Zink-Industrie
Wet Caustic Scrubbing or Sodium Ion Scrubbing With
Electrolytic Regeneration - Stone & Webster/ Ionics
Flue Gas Desulfurization (also known as Copper Oxide
Process) - Shell
DAP-Mu - Mitsubishi Heavy Industries
RANGE 0
Stream Pressure
(psi) (Pa)
amb
P .
amh
KTHKATMKNT
Stream Temperature
(OF) (°K)
95 35
110-
130
120- 50-
160 70
750
COMPONENTS REMOVED
Organic
H2S Sulfur C02
Compounds
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
N4
NA
NA
NA
NA
H S SELECTIVITY
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
LIMITATIONS
Solids disposal,
scaling
Sludge disposal
Higher absorber tempera-
tures increase ammonia
loss; ammonia loss and
effectiveness dependent on
pll of the solution .
Sludge disposal proti-
lems, high maintenance
and operating costs, low
temperature corrosion;
requires plume reheat
High energy demand; qua-
lities of purged solids must
be disposed of; relatively
weak solutions have to be
handled both to. and from
the recovery plants; great
quantities of waste are
generated
High capital costs; dilute
H SO. user must be close
by
High energy requirements;
requires stack plume re-
heat
Relatively dilute solution
between boiler and re-
covery means high trans-
portation costs
STATUS OF
COMMERCIALIZATION
Demonstrated in U. S- ;
commercially available
Under development
Demonstrated
Demonstrated in
England
Commercialized for
smelters; under develop-
ment for coal combustion
stack gases
- Under study; a
throwaway. scheme is
commercially
available
Commercialized in Japan
for oil-fired utility and
in Western U.S.. for
Claus off- gas
. Prototype built; commer-
cially available
Not yet commercially
demonstrated
Demonstrated in U. S. ;
commercially available
Commercialized
Will be demonstrated
Pilot plant work
Under development
ABSTRACT
Wet scrubbing, throwaway process to treat S0>2 stack
gas; removes particulates too; most fully characterized
of fuel gas desulfurization systems
Kstensive testing by TVA
SO is absorbed in a lime slurry in a wet scrubber
Wet scrubbing, throwaway process to treat SO2 .
stack gas
Similar to Exorption process but uses sulfuric acid to
strip sulfur as ammonium sulfate
Wet scrubbing throwaway process to treat SO 2 stack gas;
thus sodium based absorbant which is regenerated
followed by a lime/limestone reaction
A wet sodium or potassium sulfite solution (K^SO..) scrubs
SO» from incinerated Claus tail gas or stack gases; the.
SO is recovered and can be recycled back to the
Claus unit; uses thermal regeneration; a throwaway
system where pulverized limestone is calcinated and
.-reactivated with SO at high temperature in the fur-
nace and precipitated or collected prior to entering
the stacks; regenerable
Converts SO- in stack gases to sulfuric acid by SO2~* SO-
and then SO3 + H2O regenerable
Regenerative chemical removal of SO- from stack gases;
reacts H_S with SO0
£. £>•
Uses a wet slurry of MgO to absorb SO2; regenerates
spent Sorbant; regenerative chemical removal of SOg
from stack gases; produces »2 SO^ or concentrated SOg
Removes SOj from incinerated Claus tail gas or
stack gases in dilate H SO and containing Fe2 (SO^;
produces gypsum (Ca SO -2 HO)
Concentrates SO in stack gas streams
Absorbant is NaOH; electrolytic conversion to produce
H2 SO4 or sulfur and recycle NaOH
A cyclic dry SO removal process using copper on
ammonia and regenerating with heat; can be used to
recover SO- from incinerated Claus off-gas and re-
cycle SO back to Claus
111-23/24
-------
Table III-5 (Continued)
GROUP
PROCESS - DEVELOPER OR LICENSOR
Potassium Formate - Consolidated Coal Co.
Molten Carbonate - North American Rockwell
B&W-Esso Flue Gas Desulfurization - Esso Rese'arch
and Babcock & Wilcox Co.
Kiyoura - Tokyo Institute of Technology
Key West - Engineering Science Inc.
Modified Howderf - IC1 - J. Howden & Co.
SNPA -Sulfuric Acid - SNPA and Haider Topsoe
Ammonia
Fluosolids
Nahcolite Dry - Precipitair Pollution Control Co.
Basic Aluminum Sulfate-- Imperial Chemical Industries
Cyclic Lime - Metropolitan Borough of Fulham,
England
Battersea
. Fulham-Simon- Carver Ammonia-
Simon-Carver. Ltd
Exorption - American Smelting and Refining Co.
ASRCO - American Smelting and Refining Co.
Sulphidine - Gesellschaft fur Chemische Industries and
Metallgesellschaft, A. G.
RANGE OF TREATMENT
Stream Pressure stream Temperature
(psi) (Pa) (°F) (°K)
800
•
240
113,
45°C
COMPONENTS REMOVED
Organic
Compounds
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
H2S SELECTIVITY
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
LIMITATIONS
Requires high absorbing
temperatures
Requires high
• temperature
Most economical for
smaller boilers
Sulfates formed must be
removed
Ammonia concentration and
pH levels must be controlled
closely to reduce ammonia
loss by vaporization
Developed to remove high
concentration of SO from
smelter operations
Requires high concentration
of SO- in flue gases
(>3.5%)
STATUS OF
COMMERCIAI IZATION
Under development
Under development
Under development
Will be demonstrated
in U. S.
Under development
Commercialized
Under development
Developmental
Being developed
Was commercialized;
none presently operating
Commercially used on
power plant stack gases
Never commercialized
Never commercialized
Has been commercially
applied
ABSTRACT
Regenerative chemical removal of SO from stack gases;
reacts MjS with SO2
SO« is absorbed in a molten salt which is regenerated
to produce US
High temperature SO9 removal, maybe applied to treat
stack gases; absorbant is regenerated .'. eliminating . .
disposal problems of wet spent material
High temperature SO removal; may be applied to treat
stack gases: absorbant is regenerated .'. eliminating
disposal problems of wet spent material
Wet scrubbing, throwav/ay process to treat SO% stack gas
a variation of the Wet Limestone process
Wet scrubbing, throwaway process to treat SO2 stack gas;
requires smallest investment of. type of process to control
'^2
Claus tail gas is incinerated transforming all sulfur com-
ponents to SO-; a converter containing a vanadium oxide
catalyst oxidizes SO to SO- which is concentrated as
H2S04 3
Throwaway process using natural sodium
bicarbonate to remove SO~ as a. dry inert waste product
(Na2S04) • .
SO.J is absorbed in an aluminum hydroxide-sulfate
solution and absorbant is regenerated by heating
SO is absorbed in aqueous solution of calcium sulfate
and lime or chalk; improved economics over Fulham
or zinc oxide processes
Employs an aqueous alkaline solution to remove SO.
Regenerates sulfur as ammonium sulfate and elemental
sulfur
SO is absorbed in aqueous solutions of ammonia and
regenerated by heat
Improvement of Sulphidine process 7 lower steam con- .
sumption; less reagent loss, less labor required
Uses aromatic amines; stripped by heating
111-25/26
-------
The relative small amounts of sulfur contained
in the extremely large volumes of stack gas
The large investment required is not reduced
appreciably by credits for the small amounts
of liquid SO2» H2SO4, or elemental sulfur
recovered
The considerable expense required to first
clean the gas dust and other contaminants and
to cool the high temperature, low pressure
stack gas prior to treatment
The need to dispose of large amounts of con-
taminated material if a nonregenerative pro-
cess is selected.
(2) Adsorption Processes
Four adsorption processes are described in Table III-6
and typical schematic and reaction for these processes are
shown in Figure III-6 below. Adsorption processes in gas
purification are of primary importance in removing water vapor
and organic solvents from gas streams. They also have been
shown to be effective in adsorbing mercaptans and H^S.
The gas passes through a fixed bed of adsorbent material
where the removed material collects on the surface. When the
bed is fully loaded, it can be reclaimed, regenerated, or dis-
carded. If regenerated, heat and stripping vapor are frequently
used. Adsorption is usually considered for selective H^S re-
moval in presence of CO2 from small natural or industrial gas
streams containing low concentrations of acid gas and mercap-
tans. These batch-type operations usually generate a high
purity gas.
(3) Chemical Conversion Processes
Chemical conversion processes are the third general group
of operations that can be applied to purify gas streams generated
in clean fuel processes. Processes of this type usually employ
III-2 7
-------
TYPICAL SCHEMATIC:
SOUR GAS
WATER
SWEETENED GAS
TYPICAL REACTION:
AIR-BLOWN
REGENERATOR
AIR
SULFUR +SULFUR
COMPOUNDS
A typical reaction using iron oxide adsorbent is:
Fe2°3 + 3H2S -> F62S3 + 3H2°
Regeneration proceeds as,
2Fe2S3 + 3°2
FIGURE III-6
Typical Schematic and Reactions for Adsorption Processes
fixed-bed catalytic reactors to chemically convert the gas-
phase impurities present. Four chemical conversion modes
are considered in this section.
1. Catalytic Conversion of Organic Compounds to H S
£i
In Table III-7 a number of catalytic conversion pro-
cesses are described synoptically and the general flow and
reactions for these processes are characterized in Fig-
ure III-7.
111-28
-------
Table III-6
Summary Data on Adsorption
Processes
CLASS: ADSORPTION OF ACID GAS
GROUP
PROCESS - DEVELOPER OR LICENSOR
Activated Carbon - Hitachi
Haines - Krell & Assoc
SO2 Recovery - Westvaco Corp
Reinluft - Reinluft Gmb H
Wet Char - Sulfacid - Lurgi
Molecular Sieves -e.g.. Union Carbide
<
Zinc Oxide
RANGE OF TREATMENT
Stream Pressure
(psi) (Pa)
Not pressure
sensitive
(usually 450
considered
optimum)
Not pressure
sensitive
Stream Temperature
(°F) <°K)
90
400-600
400-600F
COMPONENTS REMOVED
H2S
Yes
Yes
Yes
Yes
Organic
Sulfur
Compounds
CS2
Mercaptans
C02
No
Yes
H2S SELECTIVITY
Yes
Yes, if desired
LIMITATIONS
Very small amounts of
heavy hydrocarbons foul
zeolites
Batch operations re-
quiring at least two beds
for uninterrupted pro-
cessing
Batch operation
STATUS OF
COMMERCIALIZATION
Commercialized on
limited scale *
Pilot plants
Commercialized for
small streams
«
Commercialized
ABSTRACT
Used for organic solvent recovery or odor and trace
impurity removal by using a fixed bed of granular
activated carbon as adsorbent; also recovers BTX;
regeneration is accomplished by steam stripping;
can be used to adsorb SO2 from stack gases
Uses molecular sieves to adsorb H2S; regenerated
with hot SO2 or air to recover elemental sulfur from
condensing sulfur vapor; 1/3 of the sulfur is burned
to produce the SO?; dehydrates too
Though not really acid gas treating process, these
adsorb SO2 from stack gases
Uses highly porous crystalline aluminum silicate
minerals in a fixed bed; a batch process regener-
ated by heating; dehydrates too; can meet pipeline
requirements; H2S selectivity can be designed by
selecting smaller pored sieves; can remove trace
amounts; selectively adsorbs polar compounds
(e.g., H2S, mercaptans, H2O, CO2> so may be
considered if dehydration is also desired;
adsorbent stripped by hot natural gas; H2S may be
burned to sulfur during regeneration; most attrac-
tive for treating small to "medium streams with
small H2S concentrations
Used for trace impurity removal to protect sen-
sitive catalysts.
111-29/30
-------
TYPICAL SCHEMATIC:
UNTREATED
GAS
TYPICAL REACTION:
CS + 2H 2 C + 2H S
£t & £i
COS + H 2 CO + HS
RCH0 SH + H_ ? RCHQ + H0S
^ ^ • O u
C4H10 + H2S
FIGURE III-7
Typical Schematic and Reactions for Catalytic Conversion Processes
Organic sulfur compounds present in gas streams
from clean fuel processes may include carbonyl sulfide,
carbon disulfide, mercaptans and thiophenes. These
sulfur compounds are not as chemically reactive as
hydrogen sulfide and, therefore, are not completely
removed in conventional processes. Catalytic conversion
processes treat these compounds not by removing them
but by converting them into forms more amenable to fur-
ther treatment. The gas is passed, at high temperatures,
through a fixed bed of catalyst in a reactive vessel (con-
verter) where organic sulfur compounds are catalytically
converted to H2S by hydrogenation. The H2S can then be
water-cooled and removed by an iron oxide type process.
111-31
-------
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111-32
-------
Table III-7
Summary Data on Catalytic
Conversion Processes
GROUP
Catalytic Con-
version, Or-
ganic Compo-
nent to H2S
PROCESS - DEVELOPER OR LICENSOR
Carpenter-Evans - England
Peoples Gas Co - Peoples Gas Co.
Holmes-Maxted - W. C. Holmes & Co., England
British Gas Council
Iron Oxide Catalysts
Chromia - Alumina Catalysts
Copper-Chromium - Vanadium Oxide Catalysts
Cobalt- Molybdenum -
RANGE OF TREATMENT
Stream Pressure
(psi) (Pa)
Pamb
10
Pamb
P u to
amb
450
2-380
350
Pamb to
450
Stream Temperature
<°F) <°K>
790-840
800
570-645
482
250
650-950
600-800
600
650-950
COMPONENTS REMOVED
H2S
No
No
No
No
No
No
No
No
Organic
Sulfur
Compounds
Yes
Yes
Yes
Yes
COS
Yes
Yes
(COS &
CS2)
Yes
Yes
CO2
H2S SELECTIVITY
Yes
-------
Though this technique can be applied to remove
organic compounds, it cannot remove any E^S that may be
present. In fact, some of these catalysts become deacti-
vated in the presence of H2S.
2. Chemical Conversion by Oxidation to Sulfur: Dry
Processes
Processes for chemical conversion by oxidation to
sulfur are described in Table III-8 and Figure III-8 pre-
sents a typical flow scheme and the basic dry reaction.
TYPICAL SCHEMATIC:
AIR
STEAM
SOUR GAS
TAIL GAS
PREHEATER
TYPICAL REACTION:
SULFUR
2H2S
2H20
FIGURE III-8
Typical Schematic and Reactions for Dry Oxidation Processes
III-3 5
-------
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111-36
-------
Table III-8
Summary of Data on Dry
Oxidation Processes
CROUP
By Oxidation to
Sulfur - Dry
Processes
PROCESS - DEVELOPER OR LICENSOR
Iron Oxide (Dry Box)
Activated Carbon - I, G. Farbenindustrie
Claus - Amoco Production Co.
I. G. Farbenindustrie - I. G. Farbenindustrie.
The Great Lakes Carbon Co.l
Jefferson Lake 1
RANGE OF TREATMENT
Stream Pressure
(psi) (Pa)
Any
pressure
0-15
Stream Temperature
(°F) <°K)
60-85
<140
Up to 180
(usually 400-500)
COMPONENTS REMOVED
Organic
H2S Sulfur C02
Compounds
Yes Mercaptans No
. (only) but only par-
tially for COS
and CS2
Yes Some No
Yes Converts COS No
and CS2 to
sulfur with
difficulty .
H2S SELECTIVITY
Yes
Yes - depending on
proper carbon
Yes
LIMITATIONS
Prone to hydrate formation;
produces poor quality sulfur;
ineffective for organic sulfur
removal;sulfur recovery is
usually not considered but
can be made regenerable in
some applications; operation
deteriorates above 120°F or
pH above 8.0
Usually nonregenerable
but can be made regenerable
in some applications; carbon
is deactivated by tar and
polymers 'present
Economics demand at least
15%I1 S concentrations;
hydrocarbons present in
H2S stream are detrimental
in recovering elemental
sulfur (should be <2%);
H2S:SO2 ratio must be
closely controlled; corro-
sion is a concern
STATUS OF
COMMERCIALIZATION
One of oldest known
sweetening processes;
widely used in Europe
Used commercially
Highly commercialized
ABSTRACT
Requires minimum attention; most suited for small to
medium gas volumes with low H,S and CO2 content;
bulk process with periodic bed cnangeover required;
organics are regenerated as organics; iron (ferric
oxide) is the active agent; used for trace cleanup
(complete removal) of H2S usually after another pro-
cess (usually liquid absorption); formed ferric sulfide
is oxidized in air to elemental sulfur and ferric oxide
Catalytic action of activated carbon oxidizes H2S and
a solvent (aqueous ammonium sulfide) extracts it as
elemental sulfur; -used for trace cleanup of H2S,
usually after another process; doesn't remove HCN
Originally a once-through process; now found with
many variations; vapor phase oxidation of at least
2 to 10% and usually at least 15% H,S stream to
. high purity sulfur in presence of activated alumina
or bauxite catalyst; exothermic; for H9S>20% can
use air as oxident; for H_S as low as 5/o use oxygen
or oxygen-enriched air; tail gas contains nitrogen,
CO IT , SO, hydrocarbons, O^, water vapor, COS,
CS2., 11^, SO2, sulfur vapor (S^and Sg) and en-
trained sulfur mist; all can be further treated; sulfur
recovery can be increased by treating tail gases
with catalytic conversion or adsorption; corrosion
can be a problem
A split stream modified Claus - see Claus process;
utilizes waste heat boilers to recover exothermic
heat; used when HgS is <20%, to sustain combustion
process, and to burn C or COS instead of these
contaminating elemental sulfur
Refinement of the Claus process for increased
recovery of relatively diluted H2S stream and to
improve control; uses interstage cooling and
sophisticated recycling
111-37/38
-------
As exemplified by the Glaus reaction, the sour gas
stream is burned with air (and in the presence of a catalyst
to increase its reaction rate) in a reaction chamber. When
cooled, water and elemental sulfur are condensed and re-
covered. This type of process has been used extensively
for recovery of sulfur from concentrated (15 percent H2 S)
acid gas streams removed from oil fields, refineries, and
coke ovens. The reaction, however, is equilibrium-limited
and complete sulfur recovery cannot be achieved in a gas
phase reaction. The Glaus process is the principal sulfur
recovery technique in commercial practice. Significant
effort has been expended in developing .variations of this
system, as discussed later in this chapter.
3. Chemical Conversion by Oxidation to Sulfur: Liquid
Processes
A large number of processes for oxidation to sulfur
in a liquid reaction are described in Table III-9, and
Figure III-9 presents a typical schematic and reactions
for these processes.
The processes included in this category are liquid
regenerative processes that yield elemental sulfur. They
are based on the same chemical reactions as the dry pro-
cesses, but here the oxidants are dissolved or held in
aqueous suspensions in a liquid medium. These processes
can treat sulfur selectively in the presence of CC>2 (up to
1000 gr H2S/100 ft3) and remove it to very low levels.
They require large reactors to regenerate the solution
and the low sulfur-solution capacity absorbent requires
high circulation rates. Ctther. problems inherent in
these liquid processes include inefficient dissipation
of the exothermal heat of reaction.
Liquid-phase oxidation processes produce elemental
sulfur by two general routes:
Liquid-phase Glaus reaction of H2S and SO2
to give higher conversion .rates than possible
for the gas-phase Glaus reaction
Staged oxidation processes, using catalysts
for oxygen carriers.
111-39
-------
TYPICAL SCHEMATIC:
SWEETENED GAS •«!
AIR
SOUR GAS •
ABSORBER
ELEMENTAL
SULFUR
AIR
REGENERATOR
(AIR OXIDATION)
KAUNE^jN
LUTION I J
ALKALINE
SOLUTION
TYPICAL REACTION: (Giammarco-Vetrocoke)
Absorption: Na.As S O0 + H0S -» Na^As S O + H0O
4 £ 0 J 6 4^O £i
Regeneration: Na.As S ._O+ 1/2O
+ S
FIGURE III-9
Typical Schematic and Reactions for Liquid Process
Oxidation to Sulfur Schemes
The H^S in the sour gas is oxidized to elemental
sulfur by oxidants or catalysts .that are dissolved or sus-
pended in liquid solutions. The fouled solution may be
pumped to a regenerator where it is regenerated by a
stream of air, or the oxidation may occur in the sorption
vessel. The air also serves to collect the sulfur as a
froth, which can be extracted for further processing.
Ill-40
-------
Table III-9
Summary Data on Liquid Processes
Involving Oxidation to Sulfur
GROUP
By Oxidation to
Sulfur - LIQUID
PROCESSES
PROCESS - DEVELOPER OR LICENSOR
Perox - Germany
*Ferrox — Koppers Co.
'Burkheiser - Germany
*Gluud - Germany
'Manchester - Manchester Corp, England
Thylox - Koppers Go.
Giammarco - Vetrocoke H2S - Powergas Corp.
or Vetrocoke of Italy
Stretford ADA - North Western Gas Board, Parsons
RANGE OF TREATMENT
Stream Pressure
(psi)' (Pa)
- Pamb • '
Pamb
Pamb
Pamb
to 1000
Pamb
to 1000
(insensitive
to pressure)
Stream Temperature .
(°F) <°K)
100
80-100
73-100
100-300
90-130
COMPONENTS REMOVED
H2S
Yes
Yes
Yes
Yes
Yes
(Com-
pletely)
Total
removal
possible
Yes
Yes
Organic
Sulfur
Compounds
-
All par-
tially
removed
No
co2
No
Yes
No
No
Yes
Little
If de-
sired
No
H2S SELECTIVITY
Yes
No
Yes
Yes
No
If desired
Yes
LIMITATIONS
Low solution capacity
requires high circulation
rates; solution con-
taminated by side re-
action products
. Solution is very cor-
rosive; complete re-
moval of H2S not ob-
tained as readily as in
dry box process; side
. reactions can yield non-
regenerable salts which
lead to high-chemical
replacement costs; re-
covered sulfur is of
poor quality; no longer
economically competi-
tive with other processes
Sulfur recovered is of
poor quality . ' •
Corrosive solution; high
operating cost; com-
plex process
Usually limited to streams
with small concentrations
of H2S (<1.5% H2S 1,000
grains H2S/100 ft3) or
sulfur outputs of <25 tpd:
product contaminated with
arsenic
The low capacity of the
solutions require very high
liquid circulation rates;
thiosulfate-forming side
reactions plug up equipment
with sludge deposits re-
quiring frequent cleaning
STATUS OF
COMMERCIALIZATION
Inactive; was commercial-
ized in Germany for purify-
ing coal gas
Being supplanted; some
still in operation in U. S.
for treating natural gas
and refinery gas
Being supplanted; some
still in operation in U. S.
for treating natural gas
and refinery gas
Being supplanted; some
still in operation in. U. S.
for treating natural and
refinery gas; also used
in Europe
No longer economically
competitive; used in
England to treat coal gas
Has been widely commer-
cialized and still used
here and overseas; being
supplanted and now con-
sidered obsolete
Active; also used in
Europe for coke oven
gas and synthesis gas
treating and in U.S. for
high pressure natural
gas streams
Active here and overseas
ABSTRACT . '
Absorbent is ammonia -hydroquinone (an organic
catalyst); elemental sulfur recovered as a froth during
regeneration with air; removes NH3 and HCN too.
An Improvement on the Seaboard process; can achieve
complete H2S removal; uses Na2CO3+Fe(OH)3;
elemental sulfur recovered as a froth during regene-
ration by aeration; takes up less space than dry box
plants '
Removes HCN too; uses Na2CO3+Fe(OH)3; elemental
sulfur recovered as a froth during regeneration by
aeration
Very similar to Ferrox process but dilute solution of
ammonium replaces the sodium carbonate; elemental
sulfur recovered as a froth during regeneration by
aeration; requires less air than Ferrox process; a
HCN -free gas is washed with a solution of poly-
thionates and iron sulfate to remove HgS
Uses Na2CO3Fe(OH)3; elemental sulfur recovered as
a froth during regeneration by aeration; a modifica-
tion of the Ferrox process using multi-stage washing
instead of a single contact
Active agents are Na^O^ + thioarsenate (slightly alka-
line solution); elemental sulfur is regenerated as a
froth by air blowing; sulfur is of high purity
Uses an aqueous arsenic solution (Na2CO3*As2O3+
AsO2); elemental sulfur is recovered; can purify to
<1 ppm H2S even at Pamb and elevated temperatures;
air regenerated; absorbs very little methane;
low heat consumption and free of corrosion
problems; continuous process
Absorbents are alkaline solutions of Na2CO3+ADA;
can treat gases from 10-700 grains H S/lOOFt3;
regenerated by air bolwing; can even Be used
for small amounts of H S and large amounts of
CO2 present; it is a further development of the
Manchester process. with increased capacity: pro-
duces high quality sulfur; reliable process for com-
plete H^S removal
111-41/42
-------
Table III-9 (Continued)
GROUP
PROCESS - UKVF.I.OPER OR LICENSOR
Stretford ADA/Vanadate
Takahax - Tokyo C.us Co.
Townsend
Freeport - Freeport Sulfur Co.
Lacy-Keller-Lacy Research ^ Development Inc.
• Sulfonly - Shell
IFP - Institut du Petrole
Sulfreen - S. N.P.A. and Lurgi •
Nalco - Nalco-Iloxve Baker
Beavon Sulfur Removal - Ralph M. Parsons and
("nion Oil of Cnlil'ornia
Clean Air Sulfur - .1. !•'. I'ritchard and Co. and
Texas Gulf Sulfur Co.
RANGE OF TREATMENT
Stream Pressure
(psi) (Pa)
I'p to.
3000
0.5
1'
amb
ami)
- ''a,,,.,
Stream Pressure.
(°F) <°K>
100-150
COMPONENTS REMOVED
H2S
Y.'s
Yes
Yl-s
*i <•>
230-320
260-300
90-
130
Vi'S
YPS
Yes
Organic
sulfur
C'om pounds
Merc-aptans
No
No
co2
N'o
No
No
N'o
No
No
H SELECTIVITY
Yes
Yes
Yes
Yes
Yes
Yes
Yes
LIMITATIONS
If HCN is present, it will
form thiocysnate which
will reduce H2S removal;
some HCN is released to
air from regenerators
Mechanical problems of
handling sulfur slurry; •
quality of sulfur products
is poor; corrosion is a
problem
Cannot remove unoxidi-
zable compounds; be-
comes uneconomical for
recovery of over one tpd
sulfur
COS and CS^ aren't
reacted: some solvent
makeup is rrquired
Does not convert COS '
or CS2
Costs as much as a
Claus unit
STATUS OF
COMMERCIALIZATION
Pilot plant, in Canada
I-ndor development
Under development
Pilot plants in U. -S. ;
commercialized in
Japan and Canada
Pilot plant stage
Commercialized
Commercialized
ABSTRACT
Same as for Stretford ADA process except addition
of (NaVOg) a vanadium salt increases reaction rates
and permits operation at lower pH therefore reducing
thiocyanate formation
Similar to Stretford process; uses a sodium carbo-
nate •*- nephthoquinone solution to convert HnS to
elemental sulfur; solution is regenerated by air
Composed of SO2*di or triethylene glycol; essen- i
tially a low temperature Claus in a liquid; forms
sulfur slurry and water; dehydrates gas too; the
SO2 is formed by burning some of the sulfur pro-
duced in air; used as a direct conversion to sulfur
process in natural gases containing about. 3% H2S
Absorbents are SO2 + amine catalyst in hot molten
sulfur; H2SKSO2 react to form molten sulfur and
water vapor; the SO2 is obtained by burning sulfur
in air; also uped to extend Claus reaction in Claus
tail gas; epsr-ntially a low temperature Claus
process in a liquid medium
Chemically converts small amounts of H2S and mer-
captans directly to elemental sulfur in low concen-
tration streams (up to 35 grains H2S/100 ft3); re-
generation is without addition of heat
Active agents are SO2 *- catalyst in Sulfolane sol-
vent; essentially a low temperature Claus process
in liquid; recovers elemental sulfur; similar to
Townsend process
Essentially a low temperature Claus process in a
liquid; the continuous Claus reaction uses a catalvst
in a, liquid to form sulfur from H2S+SO2, and to
treat incinerated Claus tail gas; no foaming prob-
lems; economical; highly stable and active solution
Essentially a low temperature Claus process in
liquid; uses SO2^ activated carbon to produce
elemental sulfur; repeats the Claus reaction between
H2S»-SO2 in the Claus tail gas and absorbs the sulfur
formed; it is desorbed by stripping by hot inert gas
Essentially a low temperature Claus process in
liquid; uses a proprietary agent
Catal.ytirally ( eobalt-molybdate) hydrogenates tail gas
from Claus units to H9S and passes to a Stretford unit
whirh is considered as part of the Beavon process
3 sta^e process:
I -converts Claus tail gas SO^ and
some -11,8 to sulfur " Regenerated
2-converts rest of II^S to sulfur in a by ajr
Stretford unit blowing
•S-redures COS and CS9 levels between
( 'Uuts and stace 1
In. all four processes H^S reacts with an alkaline compound followed by reaction of hydrosulfide with iron oxide; iron sulfide
III-43/44
-------
Table III-9 (Continued)
GROUP
Liquid Processes
(Continued)
'
PROCESS - DEVELOPER OR LICENSOR
C. A. S. - Kopprrs
Fischer
Staatsmijncn-Ollo - Netherlands/
Autopurification - England (
Permanganate :ind Dichomaic
Direct Oxidation - Pan American Petroleum Corp.
Sulphoxidc - Alberta Sulfur Research. Ltd.
Cataban - Rhodia Inc.
Union Carbide - IJnion Carbide Corp.
SCOT - Shell
RANGE OK TREATMENT
Stream Pressure
(psi) (Pa)
P ,
a mli
Stream Temperature
(°F> (°K)
90-130
COMPONENTS REMOVED
H2S
Yes
Yes
Yes
(Com-
plete
Yes
Yes
Yes
Yes
Organic
CS2. COS,
RSH
y)
COS and
CS2
Yes
c:o2
No
H2S SELECTIVITY
LIMITATIONS
High electrical con-
sumption
N1 on regenerative;
chemicals are
expensive
Heavy hydrocarbons
contained in refining
gases adversely affect
process
STATUS OF
COMMERCIALIZATION
No satisfactory commercial
application yet
Commercialized
Commercialized for dry air
production
Used in natural gas sweet-
ening
1 .aboratory scale
I'ilot plant stage-
Under development
ABSTRACT
C.A.S. = cyanogen, ammonia, sulfur; ammonia and
elemental sulfur remove HCN forming ammonium
. thioseyonate; H^S and NH3 are removed by ammonium
polythionate, suffite and thiosulfate; the solution is
regenerated producing elemental sulfur
Uses alkaline aqueous iron; cyanide complexes to
convert I^S to elemental sulfur of good quality
Uses suspended solution of iron-cyanide compounds
in an alkaline solution to produce relatively pure
sulfur; the solution can be regenerated by air
A buffered aqueous solution of potassium permangate
and sodium or potassium dichromate and for trace
removal of H2S; also removes organic compounds
such as amines
Can handle low concentration HgS streams (i.e.,
2-1 8%) and high concentrations of light weight
hydrocarbons; this is a catalytic conversion process
using air and producing elemental sulfur
Uses an organic sulphoxide as catalyst to react H2^
and SOg to yield elemental sulfur; converts COS and
<-'S2 to both CO2 'ind sulfur
Uses an iron salt liquid solution to oxidize H2S to
elemental sulfur; may be applied to Claus tail gases
Catalytically absorbs I^S; can reduce sulfur from
Claus tail gases
A catalytic hvdrocenation process (at 600 F" ' ) to
react C(TP. CS0. SO.,, and ll^S from tail gases or
Clans off gases': the "cleaned feed can proceed to an
a mine (Adip) absorption unit and the off gas to a
Clan? unit
111-45/46
-------
4. Chemical Conversion by Oxidation to Oxides of Sulfur
Four processes for chemical conversion by oxidation
of the sulfur bearing compounds to oxides of sulfur are
described in Table 111-10. The general schematic for these
processes is given in Figure 111-10.
TYPICAL SCHEMATIC:
AIR
TREATED GAS
SOUR GAS
TYPICAL REACTION:
2Fe000 + 3HJ3 + 3COS -»• 2FeS-2FeS0 + 3H_O + 3CC-
2 o 2i &&
FeS-FeS
FIGURE III-10
Typical Schematic and Reaction for Processes
Involving Oxidation to Sulfur Oxides
111-47
-------
This page intentionally left blank.
HI-4 8
-------
Table III-10
Summary Data on Processes Involving
Oxidation to Sulfur Oxides
GROUP
By Oxidation to
Oxides of Sulfur
PROCESS - DEVELOPER OH LICENSOR
Appleby-Frodingham or Hot Ferric Oxide
Katasulf
North Tliames Gas Board
Soda -Iron
RANGE OF TRKATMENT
Stream
(psi
'ressure
(Pa)
Stream
<°K)
600-700
430-570
390-500
Temperature
<°K>
COMPONENTS REMOVED
Organic
H2S Sulfur CO2
Compounds
Yes Yes (COS)
Yes 50% Yes
Yes
Yes Yes
H2S SELECTIVITY
LIMITATIONS
Sulfur recovered as sulfuric
acid requiring expensive
storage and inventory prob-
lems
The catalyst is fouled by
carbon deposits
STATUS OF
COMMERCIALIZATION
Has been
commercialized
Commercialized
In commercial use
In commercial use
" ABSTRACT
A dry process using hot ferric oxide (FeO); fluidized bed:
regenerated with air to SO which is used to manufacture
sulfuric acid; low labor costs and excellent heat economy
Catalytically oxidizes H S to SO which is converted to
ammonium sulfate and elemental sulfur; removes ammonia
and HCN too; catalysts are activated carbon or bauxite
Outgrowth of the Carpenter-Evans process; uses nickel
subsulfide to oxidize organic sulfur compounds; the sulfur
oxides evolved are removed by water washing »
Oxidizes organic sulfur compounds to oxides of sulfur.
primarily SO_, over a hydrated iron oxide and sodium
carbonate catalyst at elevated temperatures
111-49/50
-------
In these processes, H2S and organic sulfur com-
pounds are catalytically converted to oxides of sulfur.
An aqueous solvent removes the oxides which can be
converted to elemental sulfur or sulfuric acid. To react,
organic sulfur compounds require elevated temperatures.
The H2S and organic sulfur compounds present in
the gas stream are oxidized to SO2 over a catalyst, at
elevated pressure and temperature. The oxygen required
for oxidation is supplied by the addition of air. Though not
included here, direct incineration of sulfur compounds can
also be considered in this category.
2. APPLICABILITY OF SULFUR CONTROL PROCESSES TO GAS
STREAMS FROM CLEAN FUEL CONVERSION PROCESSES
In this section, the specific control techniques selected to
remove and recover the sulfur from the representative gas streams de-
veloped in Chapter II are discussed in more detail.
(1) Applicability of Sulfur Removal Processes
In most applications of sulfur removal in clean-fuel pro-
cesses, the sulfur is removed simultaneously with carbon
dioxide from the gas stream treated. This combination of sulfur
and carbon dioxide removal is known as acid-gas treatment.
The primary form of sulfur in acid gas is hydrogen sulfide.
The acid-gas removal processes that have been developed to
date are directed primarily to the removal of sulfur in this
form.
Data from Chapter II indicate that another form of sulfur,
carbonyl sulfide (COS), will exist in the primary gas stream in
small but potentially significant quantities. For example, of
the total gas stream in the production of high-Btu gas from high-
sulfur coal, the concentration of COS maybe about 275 ppm, or
about 1. 8 percent of the total sulfur. Although these quantities
of COS are small, they result in the major contribution of poten-
tial sulfur emissions from these proposed facilities.
Ill-51
-------
Trace quantities of other sulfur compounds will also be
formed during coal gasification. Among these compounds are
carbon disulfide, mercaptans, thiophenes and other organic
sulfides. In general, these materials will be hydrogenated to
H2S in a water-gas shift reactor, or they will be removed from
the system with the by-product oils (discussed in Chapter II).
Historically, acid-gas removal systems have been operated
primarily for the simultaneous bulk removal* of hydrogen sulfide
and carbon dioxide. When the bulk removal concept is applied to
streams encountered in clean-fuel processes, the resulting acid-
gas is too dilute in sulfur to be an acceptable feed for a conven-
tional Claus sulfur recovery plant. Modified Glaus facilities
have been designed to operate at inlet sulfur concentrations ap-
proaching those encountered in typical streams. However, these
systems have not yet been widely used commercially. For the
purpose, of this report, therefore, a Stretford system has been
applied which recovers sulfur in its elemental form following
bulk removal processes. The Stretford facility is a relatively
expensive option and can be justified only if a conventional
Claus plant proves unacceptable.
Some of the acid-gas removal systems now available
commercially have a greater affinity for sulfur than for carbon
dioxide (see Section 1 of this chapter); therefore, these sys-
tems can be operated with a partial selectivity for sulfur. If a
selective acid-gas removal system is employed, two acid-gas
streams are evolved. One of these streams is concentrated in
sulfur and is an acceptable feed for a Claus plant; overall pro-
cess economies are thereby realized. The second acid-gas
stream contains the majority of the carbon dioxide present in
the initial feedstock, but, because separation cannot be perfect,
it will contain small quantities of sulfur. Depending upon the
selectivity of the process, this CO2~rich stream may be vented
directly if the sulfur concentration is low, or it may be treated
further for additional sulfur recovery, perhaps with a Stretford
system.
The term bulk removal, as used in this report, refers to non-
selective removal of acid gases, with no connotation as to
depth of treatment.
IH-52
-------
The types of sulfur removal processes selected to repre-
sent the two approaches to acid-gas removal (bulk and selective)
considered in this report are: .
Amine treatment systems for bulk removal
Alkaline salt (e. g., hot carbonate) systems for bulk
and partially selective removal
Organic-sol vent based systems for selective re-
moval in varying degrees of selectivity.
These three systems are all classified as absorptive-type pro-
cesses in Section 1 of this chapter. They differ from each
other primarily in the removal agent employed and as further
discussed below.
Several process licensors are active in these three areas,
and each has developed processes with different acid-gas re-
moval agents or additives. Additionally, each licensor can
offer processing schemes with different degrees of severity
(more thorough removal) or greater degrees of selectivity. A
complete analysis of each licensor's process in several degrees
of severity was well beyond the scope of this study. Further-
more, considering the uncertainties in the primary data avail-
able on these processes, a detailed investigation would not be
warranted at this time.
In the discussion which follows, the nature of processes
in each of the three basic categories noted above is reviewed
briefly.
1. Amine Treatment Systems
A variety of amine systems have historically been
used for acid-gas removal. In the treatment of clean
fuel streams, monoethanolamine (MEA) does not appear
suitable because it is irreversibly degraded by carbonyl
sulfide. One may, however, expect potential application
of diethanolamine (DEA), tertiary amines (MDEA or TEA),
diglycol amine (DGA), or di-isopropanyl amine (DIPA).
The Sulfinol process uses a combination of amines and
111-53
-------
solvents (discussed later), and at low pressures (one or
two atmospheres), this system behaves much as a selec-
tive amine process. Amines have consistently been the
most common type of acid-gas treatment system employed
in oil refineries and in natural gas fields. Based on this
experience, bulk removal at elevated pressure should be
possible with an I^S concentration of less than 10 ppm in
the process gas and a carbon dioxide concentration of less
than 1 percent. .
The disposition of carbonyl sulfide in these systems
is uncertain. Process licensors generally agree that
most of the carbonyl sulfide is absorbed. However, the
data on regeneration are varied, depending upon the specific
amine and operating conditions. In some cases, essentially
all of the COS is regenerated intact; in others, it is nearly
all hydrolyzed to hydrogen sulfide; and in still others,
about half of the initial carbonyl sulfide is hydrolyzed to
H2S, and the remainder reports to the effluent as COS.
In analyzing the performance of the generic amine process
selected for consideration in this study, the most conser-
vative case is assumed; namely, that all of the COS is re-
generated intact. In the analysis section, however, the
improved performance possible by amine sulfur removal
processes, if the COS is hydrolyzed, is discussed.
Tertiary amines and DIPA have the capability for
partial selective removal of H2 S. For the analysis
given in this report, however, only the bulk removal
system was employed. The high steam costs associ-
ated with amine-based systems probably will eliminate
them from consideration for high-pressure systems
(although higher amines might be competitive in some
situations).
A diglycol amine process has operated satisfactorily
in bulk treatment at the pilot plant facility of the Hygas
process, and the Sulfinol process has been installed in
similar operations to treat the process gas streams from
heavy oil partial oxidation and Koppers-Totzek low-Btu
generators. It was assumed, therefore, that amine-
based systems can be operable on the gas streams se-
lected in Chapter II.
111-54
-------
2. Hot Carbonate Processes
The distinguishing advantage of hot-carbonate sys-
tems for acid-gas removal is that they can hydrolyze
carbonyl sulfide to H2 S according to the claims of the
process developers. Conversion of carbonyl sulfide
to H2 S may prove valuable in treating gas streams
from clean-fuel processes in the future. In this
report, it has been assumed that the COS is converted
quantitatively to H2 S. The potential consequences
should this assumption prove invalid are considered
later in this section.
In. addition to simultaneous bulk removal of both sul-
fur and carbon dioxide from the process gas stream, the
hot-carbonate system may be designed for partial selec-
tivity in the removal of sulfur in the presence of carbon
dioxide. This mode of operation can generate an H^S-
rich effluent that is a satisfactory feed for operation of a
Claus plant to recover elemental sulfur.
Like most,acid-gas removal systems, the hot-carbonate
process can be operated with different column heights, liquor
recirculation rates, regenerator pressures, and steam
duties to effect varying degrees of acid-gas removal. For
this study, two degrees of severity have been assumed: a
"light" bulk treatment that will reduce the hydrogen sulfide
in the process gas to 20 ppm and the carbon dioxide con-
centration to 1 percent, and a "deep" bulk treatment where
the hydrogen sulfide concentration is reduced to 1 ppm and
the carbon dioxide concentration to 0. 2 percent. Two de-
grees of intensity for the selective removal of sulfur using
the hot-carbonate system have also been assessed (see
Chapter IV). In one of these cases, it was assumed that
a first-stage section, using light severity, could remove
90 percent of the sulfur in the feed gas, yielding an H2S-
gas with an H2S/CO2 ratio of 1:3. In the case of deeper
severity treatment, the hydrogen sulfide could probably
be removed to a concentration of 15 ppm in the process
gas stream; in this case, the H^S/CC^ ratio in the B^S-
rich gas is 1:3. 7. In both cases, after the selective re-
moval of hydrogen sulfide, a bulk removal system would
be used to recover the remainder of the carbon dioxide
and sulfur if the process gas required further catalytic
treatment after sulfur removal.
111-55
-------
The removal criteria for hot-carbonate systems
used in this analysis were taken from the literature, with
the exception of the sulfur concentration in the process
gas stream after deep selective removal. In that case,
the process licensors indicate that H^S as low as 20 ppm
in the CC>2-rich gas can be attained. However, until this
severe treatment has been operated in a large, related
application to provide satisfactory proof of the process,
this quantity was arbitrarily increased to 50 ppm as repre-
sentative of the expected process performance on a con-
tinuing basis.
- ' - . >
The applicability of the hot-carbonate sulfur removal
systems may be subject to question for two major reasons.
First, as currently designed, these processes may not be
applicable to selective sulfur recovery from low-pressure
gas streams. The acid gases must be dissolved in the
carbonate before they react with the active agents, and the
degree of solubility of the acid gases is strongly influenced
by the operating pressure. Second, the hot carbonate sys-
tem may be affected by degradation to formic acid:
HO + CO -> HCOOH
£
With a high partial pressure of carbon monoxide, the
catalysts that are present may promote the formation of
formic acid. Furthermore, the conditions which tend to
promote COS hydrolysis (high temperature and long con-
tact time) may also enhance formate generation.
Hot-carbonate treatment has been applied to a variety
of acid-gas removal systems, including one coal gasification
facility in Westfield, Scotland. Although the partial pres-
sure of carbon monoxide in this facility is somewhat lower
than expected in newer technology plants, and complete CO2
removal is not desired, this installation indicates that hot-
carbonate processing maybe applicable in clean fuels op-
erations. Hot carbonate processing is also being installed
in the Synthane pilot plant, and, from operation of this fa-
cility, direct information on the applicability of the hot-
carbonate process in a bulk removal system should soon
be available.
Ill-56
-------
3. Organic-Solvent-Based Acid-Gas Removal Systems
Many solvents dissolve acid gases (such as H2S,
COS, and CC>2) in preference to fuel gas species, such as
methane, carbon monoxide, and hydrogen. This relative
solubility has been commercially utilized for the removal
of acid-gas species. The advantages of solvent-based
processes are most apparent at high operating pressure
because the solubility of gases follows Henry's law. *
Several different solvent-based processes such as Fluor
solvent, M-Pyrol, Purisol, Rectisol, and Selexol, have
been commercialized and are offered by various process
licensors (see Section 1 of this chapter). Although sig-
nificant differences may exist among the various solvent
processes, they are treated as a single process in this
study. Significant savings may be realized by solvent
selection or specific flowsheet design, but in this study,
the high cost options were selected for consideration.
Similarly, the assumed product loss was taken for the
most conservative solvent system.
One of the primary advantages of the solvent-based
processes is the difference in solubility between hydrogen
sulfide and carbon dioxide. This relative difference in
solubility may be utilized to remove hydrogen sulfide from
the process gas stream with a high degree of selectivity
over carbon dioxide. An H2S-rich gas stream (over 30 per-
cent H2 S) can be generated and, after bulk removal, the
H2 S (not Included COS) concentration in the CO2 -rich gas
can be as low as 10 ppm. Furthermore, the H2 S concen-
tration in the process gas is only 0.1 ppm, and the carbon
dioxide concentration is about 0. 5 percent. These were
the bases used in the analysis of the systems employing
deep severity of solvent-based processing in this report.
One area of conflicting data in solvent-based pro-
cesses concerns the disposition of carbonyl sulfide. These
The quantity of gas dissolved in a given quantity of solvent is
directly proportional to its partial pressure over the solution.
Ill-5 7
-------
differences may be partially ascribed to the characteristics
of the various solvents and the degree of complexity utilized
in the treatment scheme. For the purposes of this study,
the conservative assumption is taken that the carbonyl sul-
fide will divide evenly between the B^S-rich stream and the
CC>2-rich stream. The analysis of the data presented in
Chapters IV through VI indicates that improvement in
emissions is possible if the expectations of the more op-
timistic process licensors can be proved in commercial
operation.
The solvent-based processes can also be operated
with lighter degrees of severity. In Chapters IV and V,
an example based on the Rectisol facility designed for the
El Paso coal gasification plant in New Mexico is presented
to illustrate the results which can be expected from light
severity processing.
A wider range of operating experience is available
with solvent-based processes than with other systems for
operation on streams similar to those expected in clean-
fuel processes. For example, the Rectisol process has
been operated on Lurgi plants producing intermediate-Btu
gas at several locations, and on gas streams from partial
oxidation of heavy oils. Also, the Selexol process will be
installed at the pilot plant facility for the Bi-Gas process,
and, from this operation, direct data on the applicability
of this system in the selective mode should be obtained.
(2) Applicability of Sulfur Recovery Processes
After the sulfur is removed from the primary gas stream
in clean fuel processes, it must be recovered so that it does not
pollute the environment. The sulfur could be recovered in forms
of concentrated sulfur dioxide, sulfuric acid, or as elemental
material. Although each of these forms of sulfur is saleable,
the most marketable form, from the standpoint of storage and
transportation, is elemental sulfur. In the discussion which
follows, therefore, the sulfur is assumed to be recovered in
the elemental form.
Ill-58
-------
1. Glaus Processing
The traditional process for recovery of elemental
sulfur from streams containing H^S is the Glaus process.
In this process, the overall chemical reaction is the con-
trolled partial combustion of H2 S with air to produce ele-
mental sulfur and water:
H2S+1/2 02^ H20+ 1/2 S2
Generally, in the operation of the Glaus process with feed
sulfur concentrations in the range of 15 percent to 50 per-
cent, one-third of the original H^S feedstream is fully
oxidized to sulfur dioxide in a burner section of the plant.
This sulfur dioxide is then mixed with the remainder of the
initial gas feed and reacted over a bauxite or alumina
catalyst to form elemental sulfur:
2H0S + SO0 2 2H_O + 3/2 S0
£i £l . £ &
The H2S-SC>2 reaction is reversible, and complete conver-
sion of the sulfur forms to the elemental species is not
possible. Lower temperature of operation tends to favor
higher conversion to elemental sulfur, but, if the tempera-
ture is too low, the sulfur will condense within the catalyst
bed.
Greater sulfur recovery can be expected with more
reaction stages. Consequently, Glaus plants are generally
run in two or three stages with interstage condensation of
elemental sulfur to the liquid form. No matter how many
stages are used, however, the final gas must still theo-
retically contain H2S, SC>2» and sulfur vapor in addition to
COS, CS2» and sulfur mist that may escape the system.
Carbonyl sulfide is not oxidized to the elemental
sulfur form at the normal temperatures of operation of a
Glaus plant. However, the first stage of the plant can be
operated at higher temperatures to minimize the amount
of this species in the off-gas. Generally about 50% of
the COS in the Glaus feed can be recovered by this oper-
ating technique.
111-59
-------
The efficiency of sulfur recovery in a Glaus plant is
a strong function of the sulfur concentration in the incoming
feed gas. If, for example, the incoming feed gas is nearly
pure ~H-2^' as might be encountered in a petroleum refinery
or some gas fields, Glaus plant efficiencies of 95 percent
can be obtained with multiple stages of operation. With
more dilute sulfur feedstocks, the efficiency decreases,
as dictated by theoretical considerations. The efficiency
is also decreased if solvent-based processes are used for
acid-gas removal. The solvent systems discharge a higher
concentration of hydrocarbons into the acid gas, and these
hydrocarbons tend to form carbonyl sulfide or carbon di-
sulfide in the burner section of the facility. In the analysis
presented in this report, the theoretical Glaus plant effi-
ciency was discounted by 1. 5 percent to account for poten-
tial operating problems.expected with varying sulfur con-
tent of the feed gas and to allow for end-of-run degradation
of the catalyst.
A 93 percent conversion of sulfur in a three-stage
Glaus plant was assumed for sulfur concentrations of
greater than 10 percent in the acid gas. Following sol-
vent-based processes, this efficiency was reduced to
90 percent. However, the expected performance of the
facility, if fully instrumented and carefully operated,
might approach the theoretical conversion limit with
new catalyst.
2. Glaus Tail-Gas Treatment
With 90 to 93 percent sulfur recovery in a Glaus
plant, the assumed basis selected above for this study,
the off-gas will still contain significant concentrations
of sulfur that can be further treated and recovered. A.
group of Glaus tail-gas treatment processes have been
developed for this purpose. Three general approaches
to tail-gas treatment are employed commercially. In
the first group of processes, the off-gas is incinerated,
and all sulfur types are converted to sulfur dioxide.
Then, typical stack-cleaning processes are applied.
The Wellman-Lord system, with a sulfite-bisulfite
exchange, is representative of this group of processes.
The regenerated sulfur dioxide is returned to the Glaus
plant for further reduction to elemental sulfur.
In the second group of Glaus tail-gas treatment
processes, reducing gases (H2» CO, etc.) are used to
III-60
-------
reduce the various forms of sulfur in the tail gas to
over a cobalt-molybdenum hydrodesulfurization catalyst. *
The H2S is either recovered through a selective acid-gas
system (as in the SCOT process) or selectively recovered
by a Stretford facility (as in the Beavon or Clean-Air pro-
cesses).
In the third group of processes, the basic Claus
reaction (H2S-SO2) is operated at lower temperatures.
In at least two versions, the catalytic converter is op-
erated in a condensing mode to minimize the back reaction.
In other versions, the reaction is carried out in a liquid
medium with the same effect.
The various schemes for treating Claus tail gas are
included as a single process step in the analysis given in
this report. All processes were assumed to treat the gas
to 250 ppm total sulfur of unspecified sulfur types.** Also,
all processes were assumed to have capital and operating
costs similar to those for the basic Claus plant; based on
data in the literature, these costs were assumed to be in-
dependent of the efficiency of the Claus unit (within the
ranges considered). These simplifying assumptions, while
not necessarily consistent with standard engineering design
practice, are satisfactory for this study considering the
accuracy of the data base available.
3. The Stretford Process
The Stretford process is specific to removal of
H2 S from gas streams; most other forms of sulfur
: In one option for one of these systems, the entire Claus system
is operated in a H^S-rich mode to minimize the occurrence of
other species in the tail gas. The excess H^S is then recovered
and recycled.
=* As discussed earlier, incineration of all sulfur types to SC>2
may be practiced in some processes.
Ill-61
-------
and carbon dioxide are not attacked in this system.
However, hydrogen cyanide (HCN) can be removed
with the H2 S in this process, although the HCN
causes irreversible degradation of the recirculating
solution. Because of relatively high initial and
operating costs, the Stretford system is generally
not applied for sulfur recovery unless:
High specificity for ^S is required
Low sulfur concentrations (less than 5 percent)
are encountered where Claus plants would be
expensive and inefficient.
The Stretford process was applied only on dilute acid-gas
streams in the processes analyzed in this report.
The controlled partial oxidation of ^S to elemental
sulfur and water is accomplished in the Stretford process
by incorporating sodium vanadates and substituted anthra-
quinones into a recirculating carbonate solution. The
oxidation potential of these additives is sufficient to con-
vert H2S to elemental sulfur but not strong enough to
oxidize it to sulfur dioxide. The oxygen carrier is re-
generated by airblowing the solution, and elemental sul-
fur froth is centrifuged or filtered for recovery of the by-
product. The operation is characterized by low sulfur-
loading capacity of the recirculating liquor and high
horsepower requirements. Nevertheless, where appli-
cable, it is an excellent process for recovering elemental
sulfur from H2S.
Some data indicate that the Stretford process can
remove ^S species to 10 ppm; in some applications, the
H2S concentration has been driven below the limits of de-
tection by odor (significantly less than 1 ppm). However,
other sulfur species, particularly COS, are not attacked
in this system. Therefore, based upon commercial ex-
perience with Claus plant tail gas treatment, Stretford
process licensors quote 250 ppm total sulfur in the effluent
gas with several qualifications:
III-6 2
-------
The H2S concentration in the treated gas does
not exceed 10 ppm
The total sulfur concentration in the treated
gas could exceed 250 ppm (if the COS con-
centration in the feed exceeded that amount).
These guidelines were adopted in this report, and the sulfur
concentration in the treated gas from the Stretford process
was assumed to be 250 ppm (nonatomic species) or 10 ppm
H2S plus the quantity of other sulfur species in the feed gas
(e.g., COS)— whichever is greater.
. In applying the Stretford process to certain treatment
systems, it is assumed, as a basis of analysis, that this
process removes sulfur to 250 ppm remaining in the gas
stream treated; however, this assumption can lead to an
inconsistency. For example, following a deep hot-carbonate
treatment, the acid gas should contain no sulfur species
other than H2 S. Under this circumstance, a Stretford
system could treat this gas to 10 ppm total sulfur, instead
of 250 ppm as assumed. However, to provide a uniform
assessment of the alternative treatment schemes analyzed
and considering that Stretford licensors will not quote puri-
ties greater than 250 ppm in the treated gas without detailed
process analysis, this more conservative removal level was
assumed for this report. The Synthane pilot plant will employ
a Stretford process following hot-carbonate scrubbing; there-
fore, actual data on the operation of this combined system
will be available soon.
Ill-6 3
-------
IV. COST AND EFFECTIVENESS OF SULFUR
REMOVAL AND RECOVERY IN HIGH-BTU
CLEAN FUEL PROCESSES
-------
IV. COST AND EFFECTIVENESS OF SULFUR
REMOVAL AND RECOVERY IN
HIGH-BTU CLEAN FUEL PROCESSES
This chapter presents a detailed discussion of the effectiveness
with which alternative processes remove and recover sulfur from the
two "typical" high-Btu gas streams specified in Chapter II. The costs
of installing and operating these control processes are also estimated.
The two hypothetical streams analyzed are 'representative of process
streams obtained from gasifying high-sulfur and low-sulfur coals.
The gas streams are assumed to exist at 73. 8 kg/cm and 60°C
(1050 psia and 140°F). The flow rate assumed is typical of a pro-
jected commercial gasification facility, 63 x 10 kcal/day (250 x 10
Btu/day) of product gas.
Following a discussion of the basis used to develop emissions
levels and expected costs to treat these gases, the sulfur treatment
schemes selected for study are analyzed in detail. The flowsheets,
material balances and cost estimates developed appear in the
appendix to this chapter.
1. THE BASES FOR THE ANALYSIS OF SULFUR CONTROL
PROCESSES
The bases for the analysis given in this chapter, as well as
for the subsequent analysis of processes for treating low-Btu and
pyrolysis gas streams (Chapter V and VI) are summarized in this
section.
(1) Estimation of Emissions
The following guidelines were used as the basis for esti-
mating emissions in these analyses:
To define the species of the sulfur emitted, about
1. 8 percent of the sulfur contained in the gas
stream treated was assumed to exist as carbonyl
sulfide in high-Btu plants, 4 percent in low-Btu
facilities; the remainder was taken to be hydrogen
IV-1
-------
sulfide. A thermodynamic basis was used to define
the amounts of sulfur present by species
The quantification of effluent streams is based on a
commercial clean fuels facility producing
250 x 109 Btu/day (63 x 109 kcal/day) for high-Btu
gas plants, 130 x 106 Btu/day (32, 750 x 103 kcal/day)
for low-Btu gas facilities, and 50, 000 bbl/day of
syncrude for pyrolysis plants.
During the analyses presented in Chapters IV through VI for
high-Btu, low-Btu and pyrolysis gas treatment, respectively,
numerous additional guidelines are assumed for the specific
circumstances described. These guidelines are clearly stated
as such so that the results developed in this report can be
correctly applied to specific applications of clean fuel technology
as it reaches commercialization. In addition to these guidelines,
the basic assumptions used in developing the approach to this
study, as discussed in Chapter I, should also be considered.
(2) Estimation of Costs
The costs presented throughout this report were developed in
late 1973, (based on discussions with process licensors, published
data, and engineering size-scaling factors) and were projected to
mid-1974 dollars. The costs of chemical plant construction, however,
have escalated rapidly (as much as 30 percent to 50 percent in 1974
alone). Consequently, the costs presented here more nearly reflect
a mid-1973 basis and are already obsolete. Nevertheless they are
relatively consistent and provide a baseline for extrapolation.
1. Cost of Steam
The unit costs of steam, power, and other process
inputs are listed in the estimating bases for each of the
processing schemes. For these analyses it was assumed
that all steam and power are raised onsite in a boilerhouse
requiring heat input equivalent to a 300-megawatt power-
plant.
Process steam for these facilities was valued at
$1/1000 Ib ($2. 20/kg). This is approximately $1/106 Btu
($4/10^ kcal). This price is based upon raising steam
from coal that is estimated to cost between
$0. 30-$0.40/106 Btu (about $1.40/106 kcal). Several
IV-2
-------
process licensors suggest that steam s.hould be nearly free
because of the ample opportunity to raise steam from waste
heat in the process. One system that has been engineered
(the Lurgi facility for El Paso) requires 4. 5 x 10° Ib/hr
(2 x 106 kg/hr) of steam. Of this total, 3. 5 x 106 Ib/hr
(1.6 x 10" kg/hr) is raised by waste heat recovery, and
1 x 106 Ib/hr (0.5 x 106 kg/hr) is raised in a boiler. As
these systems become more thoroughly engineered, an
even greater fraction of the total steam requirement is
expected to be raised through waste heat recovery. The
costs of incremental steam generated by heat recovery will
be relatively high and, as long as any steam is generated
by fired boilers, this marginal steam will be valued at
$l/106'Btu ($4/106 kcal). If lower-valued steam from
waste heat recovery is assigned to acid-gas removal, the
relative costs of sulfur control may change significantly,
particularly favoring the amine-based processes with
higher steam consumption. Sufficient data are presented
in the appendices to this and the following two chapters to
permit recalculation of control costs with steam valued at
.any price.
2. Cost of Product Gas
The value of the product pipeline gas from the
overall coal gasification facility was assumed to be
$2/106 Btu ($8/106 kcal). This gas price was based
upon projections of the overall capital requirements for
construction of these facilities, and assumes that the
feedstock would be mined underground at a cost of
$0. 30-$0. 40/106 Btu (about $1. 40/106 kcal). The finan-
cial factors employed, which are listed in the appendices
to the analysis chapters, are conservative and reflect
the present cost of capital with utility financing. The
price of pipeline gas might vary between
$1. 50-$2. 50/106 Btu ($6-$10/106 kcal), depending upon
the specific assumptions made.
Data from process developers indicate that the
product gas losses in the acid-gas removal system should
not be charged at the full sales value of the product,
because further processing would be required beyond
IV-3
-------
the removal point in the flowsheet and because the cost
of marginal processing capacity in the downstream units
should be low.
In this report, however, the product gas lost is
valued at its average price, rather than as a lower value
based on its contribution to increased marginal output.
The downstream processing equipment is considered to
be ah essential part of the facility. If the value of this
lost product gas is not taken to be its average sale price,
sufficient data are presented in the appendices to recal-
culate the costs of the various processing schemes for
any other assumed gas price. The level of lost product
is greatest when applying solvent-based acid gas removal
systems to treat the gas stream. This fact detracts from
the cost effectiveness of the solvent process.
Under these guidelines, specific desulfurization
techniques identified in Chapter III are applied to the
representative gas streams characterized in Chapter II.
The next three sections contain this analysis for the
high-Btu gas case.
2. COST AND EFFECTIVENESS OF SULFUR CONTROL SYSTEMS
APPLIED TO A TYPICAL HIGH-BTU GAS STREAM DERIVED
FROM HIGH-SULFUR FEED
A series of eight sulfur removal and recovery systems for
treatment of the typical high-Btu gas stream derived from the
high-sulfur coal feed were selected for calculational analysis in
this report. (See Figure A-l through Figure A-8 and Table A-1A
through Table A-8A in the appendix to this chapter). Considering
flowsheet modifications in each of these systems, a total of 20
control schemes has been evaluated for sulfur removal and recovery.
Material balances and estimated costs are presented in the
appendix for each operating scheme. As discussed in Chapter I,
the process parameters were taken from the open literature and
modified as a result of extensive conversations with process licensors.
The effectiveness of each sulfur removal and recovery unit process
is indicated by the data presented in the appendix.
IV-4
-------
(1) Analysis of Hot Carbonate Acid-Gas Removal Control
Processes (Systems 1 Through 4)
There is no general industry agreement on the fate of the
carbonyl sulfide that may be present when a hot-carbonate
process is applied. In this analysis, the COS is assumed to be
hydrolyzed. This presumes the simultaneous removal of CC>2.
In addition, the conditions required for hydrolysis may also
promote the formation of formic acid (CH^C^). If formic acid
formation is severe, it will be assumed that some system can
be developed for its destruction, but at some additional cost.
The successful operation of the Synthane pilot plant, which
incorporates a similar acid-gas scheme, should determine
the applicability of carbonate processes for these systems,
establish the degree of COS hydrolysis, and indicate the
potential degradation of the recirculating solution by formic
acid production.
The cost data for the hot-carbonate systems were pro-
vided by a process licensor; the costing for the solvent-based
systems was developed from published costs determined by an
engineering construction firm. Because of different cost data
sources, these results may not be strictly comparable.
1. Control Systems 1 and 2
In Systems 1 and 2, different degrees of severity of
removal by hot-carbonate processes were compared.
From the results given in the appendix, it appears that the
deeper severity can recover more of the sulfur with little
cost differential, considering the added cost of the sulfur
guards that must be included if light severity is employed.
As employed in these systems, the Stretford process for
sulfur recovery should permit excellent recovery of
sulfur because the only sulfur species present should be
H2S. However, as discussed in Chapter II, the process
developers quote 250 ppm total sulfur (species undefined)
in the effluent gas. The question of the level of COS
hydrolysis and the thermodynamic potential for the forma-
tion of COS in the transfer system between the acid-gas
removal process and the sulfur recovery unit must be
resolved to accurately project Stretford emissions.
IV-5
-------
In this report, the estimates of the Stretford licensors
are used; therefore, a total discharge from these facili-
ties of about 3 tons'"-3. 5"Vday equivalent sulfur has
been projected. If the only sulfur compound discharged
from the hot-carbonate process is I^S and if the Stretford
process operates as expected on H2S, the total sulfur
emissions from the facility could be reduced by at least
one order of magnitude below the values quoted here.
2. Control Systems 3 and 4
Systems 3 and 4 employ selective hot-carbonate
processes in two degrees of severity. The deep selective
hot-carbonate treatment used in System 4 is no longer
considered viable and will probably not be commercialized.
Though System 4 does result in the lowest emissions level
of all the schemes considered, significant portions of
these emissions are odorous hydrogen sulfide.
When compared to Systems 1 and 2, System 3 indi-
cates the cost saving that might be achieved by employ-
ing a Glaus facility. In System 3, a portion of the
acid-gas has been concentrated in sulfur so that it
becomes an acceptable feed for the Glaus plant. The
remainder of the acid-gas is desulfurized with a Stretford
unit. The overall cost savings, in this case, are signifi-
cant, but the emissions remain essentially constant. The
effluent from the Glaus tail-gas treatment and the discharge
from the Stretford unit are both assumed to contain 250 ppm
total sulfur (species undefined). The potential for improved
emissions, in this case, is reduced. As discussed in the
preceding paragraphs, the effluent from the Stretford
portion of the facility may be reduced significantly, but
the Glaus plant discharge, after purification, is not
expected to be reduced much below 250 ppm with present
processing techniques. In fact, because of the high CO
concentration in the Glaus feed gas, the overall sulfur
emissions may be greater for these facilities, as will be
discussed later.
Short tons, reference footnote p. 1-4.
IV-6
-------
(2) Analysis of Solvent-Based Processes (Systems 5 and 6)
The allocation of carbonyl sulfide between the Glaus feed
gas and the CC«2-rich gas of the selective, solvent-based,
acid-gas removal systems is not generally agreed upon. Data
from two process licensors of one solvent based system suggest
85 percent and 99. 5 percent recovery of the carbonyl sulfide to
the H2S-rich gas. * One of these licensors claims recovery of
all the COS except 10 ppm in the CO2-rich gas. The designs
of two engineering companies that license a second system are
based on 0. 5 percent and 67 percent loss of COS to the CO2 stream.
A third and fourth solvent-based system, with apparently similar
solvent characteristics, are not offered as processes for selec-
tive recovery. A fifth system is only now being evaluated for
selective recovery of sulfur.
In part, the differences claimed for solvent-based systems
may be due to different characteristics of the various solvents;
however, the disposition of carbonyl sulfide in solvent-based
acid-gas removal systems is not clearly defined. Each of these
solvent-based acid-gas systems may be designed for varying
degrees of severity of treatment. In fact, differences in the
designed degree of severity of treatment may be a major reason
for the disparity in the claims of the different licensors. One
system uses a series of nine absorption towers, regeneration
stills, and systems for solvent and/or water recovery with
multiple feedback loops and recycling streams. However, such a
high severity, complicated treatment might be inoperable on a
coal-based system, given the hour-by-hour variation of feedstock
characteristics, and acid-gas composition since they may not be
able to track the process adequately (particularly if short-
residence time gasifiers are employed.)
For purposes of this report, it was assumed that approx-
imately 50 percent of the carbonyl sulfide will be discharged
with the CO2~rich gas from a selective, solvent-based, acid-gas
removal system and 50 percent of the COS will report to the
Glaus feed gas. This disposition of carbonyl sulfide will result
in a CO2~rich gas containing approximately 500 ppm total
sulfur, if the initial coal fed to the gasifier contains 4. 5 percent
sulfur and the process is reasonably efficient. If, however, the
expectations of the more optimistic process licensors are
The design of the WESCO facility, employing selective
solvent-based acid-gas treatment, indicates 11 percent
loss of the COS to the CO2-rich gas (see p. IV-17).
IV-7
-------
achieved, the sulfur losses to the CO2~rich gas will be reduced
by about 1. 5 orders of magnitude and the total emissions from
the process will be reduced by a factor of about 5.
(3) Analysis of Nonselective Amine-Based Acid-Gas Removal
(System 7T"
A number of amines have been developed for acid-gas
removal and several have been commercialized. A nonselec-
tive scheme was selected in System 7 in which amines are
used for simultaneous removal of sulfur and CO2 from the
acid gas. Although some hydrolysis of COS may occur with
certain amines, it has been conservatively assumed that all
of the COS in the shifted, washed gas will report to the vented
CO2 gas at a concentration of about 1000 ppm.
There is industry-wide agreement that a reasonable
degree of selectivity could be achieved with certain amines.
On this basis, a system similar to System 3 can be designed,
using amines for the primary acid-gas removal system. At
present, the disposition of carbonyl sulfide in such a system
has not been estimated. The relatively high costs of these
systems* indicate that they may not be an economical choice
in systems employing high-pressure gasifiers. Therefore,
amines were not investigated in great detail for this application.
(4) Analysis of Selective Sulfur Removal With the Stretford
System (System 8)
The process flow diagram illustrated for System 8 in
the appendix to this chapter incorporates a Stretford process
operating at high pressure to preferentially remove the hydro-
gen sulfide from the process gas. The remaining acid-gas
constituents are then removed with any bulk-removal system.
Although this system was suggested for the airblown Lurgi
gasifier in the El Paso Natural Gas Company's application to
the FPC, it may not be applicable here. The high partial-
pressure of carbon dioxide in this system may cause opera-
tional difficulties, problems in pH control, and excessive
* The cost of amine processing is not significantly affected by
pressure; however, the costs of competing carbonate and solvent-
based systems are significantly reduced as the pressure increases.
IV -8
-------
degradation of the recirculating solution. These factors suggest
that System 8 may not be an economical choice for this appli-
cation.
If this system were operated as presented, all the COS
in the feed would be discharged to the CC>2 stream because the
Stretford process is not active for COS recovery. The result-
ing sulfur loss would be about 1000 ppm in the CO2 stream.
However, if a hot-carbonate system were used for the final
bulk recovery and this carbonate system did hydrolyze the
COS, a secondary Stretford process could be used for cleanup
of the "hot pot" effluent. This may result in extremely low
emissions for this process. This system, however, offers a
marginal cost advantage over System 2 which also employs
hot-potassium carbonate and Stretford processes.
3. SUMMARY OF COST AND PERFORMANCE RESULTS: SULFUR
REMOVAL AND RECOVERY FROM HIGH-BTU GAS DERIVED
FROM HIGH-SULFUR FEED
Table IV-1 summarizes the data collected for the various
high-Btu gas processing schemes presented in Systems 1 through 8.
The quantities of emissions from each scheme, the total capital
requirements for the sulfur removal and recovery system, and the
effect of sulfur removal and recovery upon the product price are
reported in this table.
In Figure IV-1, the total incremental* capital investment is
plotted as a function of sulfur emissions. Figure IV-2 presents a
comparative assessment of the emissions levels for the processes
considered as a function of the gas price increment caused by
improved abatement. Systems applied to treat process gases in the
manufacture of high-Btu (pipeline quality) gas are required to remove
essentially all the sulfur from these streams to protect downstream
methanation catalysts. The costs and emissions reported in .
Table IV-1 indicate possible sulfur abatement levels for this maxi-
mum sulfur removal case.
* The incremental capital investment, as used in this report,
is limited to the cost of the sulfur removal and recovery
facilities only.
IV-9
-------
Table IV-1
Summary of Results
Sulfur Removal and Recovery From a High-Btu Gas Derived From High-Sulfur Coal
2 50x1 09 Btu/day (63x1 09 kcal/day) Facility
Emissions, short tons'/day Sulfur Incremental Gas Price
System
Scheme
1
la
2
2a
3
3a
3b
3c
4
4a
5
5a
Claus
Description Off-Gas
Bulk hot carbonate (light) with
Stretford
OmitStretford
Bulk hot carbonate (deep) with
Stretford
OmitStretford -
Selective hot carbonate (light) with
Claus, Claus tail gas, and Stretford 0.8
Omit tail gas treatment 36.5
OmitStretford 0.8
Omit both Stretford and tail gas 36.5
Selective hot carbonate (deep) with
Claus, Claus tail gas treatment 1.0
Omit Claus tail gas treatment 40.5
Selective solvent (light), bulk
solvent (deep) with Claus, Claus
tail gas treatment, and Stretford 1 .2
Omit Claus tail gas treatment 51.2
C02-Rich
Off-Gas
3.0
579.4
3.0
579.9
2.6
2.6
57.2
57.2
0.5
0.5
8.4
8.4
Sulfur
Guard
0.5
0.5
0.02
0.02
0.5
0.5
0.5
0.5
0.02
0.02
_
-
Incremental Capital .
Total Investment, $ million' 'C/10faBtu
3.5
579.9
3.0
579.9
3.9
39.6
58.5
94.2
1.5
41.0
9.6
59.6
77.1
45.3
79.9
47.9
66.3
59.7
61.8
55.2
69.6
62.6
78.3
70.7
32.4
22.0
31.2
20.9
26.1
24.4
24.7
23.0
Z4.4
22.6
25.2
23.4
C/106kcal
128.57
87.30
123.81
82.94
103.57
96.83
98.02
91.27
96.83
89.68
100.00
92.86
* short tons x 0.9072 = m tons
short tons x 0.8929 = LT
*When comparing the data reported here, the limitations discussed on pages I-7, 8 and IV-2, 5 should be recognized.
-------
Table IV-1 (Continued)
Emissions, short tons*/day Sulfur
System
Scheme
5b
5c
5d
6
6a
7
7a
8
Description
Omit Stretford
Omit both tail gas treatment
and Stretford
Omit all sulfur recovery
Selective solvent (deep) with
Claus, Glaus tail gas treatment
Omit tail gas treatment
Bulk amine with Stretford
Omit Stretford
Pressure Stretford with bulk
removal
Claus C02-Rich Su|fur
Off-Gas Off-Gas Guard
1.2 68.7
51.2 68.7
579.9
0.7 5.3
57.4 5.3
10.7 0.2
579.9 0.2
10.3 0.5
Total
69.9
11S.9
579.9
6.0
62.7
10.7
579.9
10.8
Incremental Capital
Investment, $ million
73.5
66.0
58.5
77.3
70.7
89.8
58.3
82.6
Incremental Gas Price
(f/106 Btu
23.7
21.9
21.5
30.3
28.7
51.3
41.1
34.8
C/106 kcal
94.05
86.90
85.32
120.24
113.89
203.57
163.10
138.10
* short tons x 0.9072 = m tons
short tons x 0.8929 = LT
*When comparing the data reported here, the limitations discussed on pages 1-7,8 and IV-2, 5 should be recognized.
-------
FEED-
700
—»
500
300
200
100
•I 70
I 50
t
o
30
20
oc
D
^ 10
3'.7
5
o
o
o o
o
DO NOT
EXTRAPOLATE
500
300
200
100
70
50
30
20
10
7
5
3
to
•5.
vt
C
O
CO
O
co
CO
CO
40
50 60 70 80 90
INCREMENTAL CAPITAL INVESTMENT, $106
FIGURE IV-1
Summary of Results
Incremental Capital Investment for Sulfur Removal
and Recovery From a. High-Btu Gas Derived From High-Sulfur Coal
250x109 Btu/day (63x109 kcal/day) Facility
IV-12
-------
FEED
O
o°
DO NOT
EXTRAPOLATE
o-
500
300
200
100
70
50
30
20
10
7
5
3
2
CO
c
O
CO
g
CO
CO
LU
DC
CO
20
25 30 35 40
INCREMENTAL GAS PRICE 0/106 Btu
45
50
FIGURE IV-2
Summary of Results
Incremental Gas Price Increase Caused by Sulfur Removal
and Recovery; High-Btu Gas From High-Sulfur Coal
250x109 Btu/day (63x109 kcal/day) Facility
IV-13
-------
The data presented in Figures IV-1 and IV-2 form bands, rather
than precise lines. The upper bound of these bands is based upon
input data which are considered to be particularly reliable because
they were developed from information published by engineering
companies. These data indicate that the cost of maximum abatement
will be on the order of $80 million total capital investment and will
add about $0. 30/106 Btu ($1. 20/106 kcal) to the gas price. *
On both figures, the data from Table IV-1 form three groups
of points:
One group of points represents no recovery of sulfur
from the acid-gas stream. The full 580 tons*/day
of sulfur present in the gas is discharged to the atmo-
sphere. Though unrealistic, this situation represents
the base case to which other emissions reductions are
compared. The estimated capital requirement for this
case is about $50 million and the incremental cost
of sulfur removal from the gas stream, with no sulfur
recovery, is about $0.20/106 Btu ($0.80/106 kcal)
A second group of data points represents 80 percent
to 90 percent recovery of the sulfur in the process
gas. This group of points represents minimal treat-
ment of the process stream for sulfur recovery and
requires an incremental capital investment of an
additional $10 million over the base case described
above. The value of the sulfur recovered partially
offsets some of the costs, so the incremental effect
on the gas price is only about $0. 03/10^ Btu
($0. 12/10^ kcal) additional cost over the base case
described above.
A third group of data points represents maximum abate-
ment with about 3 tons-10 tons*/day total emissions
from the large facility defined for this analysis. These
data can be further subdivided into three groups:
Three data points, representing emissions of
about 3 tons-4 tons''Vday total sulfur, are approx-
imately equivalent to 250 ppm total sulfur
(monatomic) in the various discharged streams;
Short tons, reference footnote p. 1-4.
IV-14
-------
A fourth (dotted) point (representing the application
of a deep hot potassium carbonate processing scheme)
is not considered commercially viable and is not
considered here
One data point, at about 6 tons''Vday total emis-
sions, represents a case where half of the carbonyl
sulfide in the process gas is lost to the atmosphere
Three data points, at about 10 tons-11 tons*/day
total emissions, represent instances where the
emissions are equivalent to the total carbonyl
sulfide content of the process gas.
Within the accuracy .of the data base available for this report, the
level of emissions expected from the schemes representing maximum
abatement is equal to about 2 percent of the sulfur in the coal feed-
stock. The estimated incremental capital investment for 98 percent
sulfur recovery is about an additional $30 million over no sulfur
recovery and an additional $20 million over 80 percent to 90 percent
recovery. The incremental gas price for 98 percent sulfur recovery
is about $0. 10^ Btu ($0.40/10" kcal) over no sulfur recovery and
about an additional $0. 07/106 Btu ($0. 28/106 kcal) over 80 percent
to 90 percent recovery.
(1) Comparison to Total Plant and Gas Cost
The total capital requirement for a facility to manufac-
ture 250 x 106ft3/day (7. 08 x 106m3/day) of gas from high-sulfur
coal can be estimated to be about $450 million.* The costs of
maximum sulfur removal and recovery, therefore, represent
about 20 percent of this total capital requirement.
The overall cost of gas from this facility has been esti-
mated at about $2/10$ Btu ($8/106 kcal). Excluding the cost
of coal at $0. 40/106 Btu ($1. 60/106 kcal) and assuming a
67 percent overall plant efficiency, the processing cost in
this facility is about $1. 40/1Q6 Btu ($5. 55/106 kcal). There-
fore, the cost of sulfur removal and recovery at maximum
abatement is approximately 20 percent of the total processing
cost in this facility.
Short tons, reference footnote p. 1-4.
IV-15
-------
(2) Expected Emissions at Maximum Control Levels
At the maximum sulfur abatement level for the hypothetical
high-Btu gas derived from high-sulfur coal, a commercial size
facility is expected to emit about 1.0 tons*/day (see Table IV-1) of
sulfur to the atmosphere. These emissions, calculated as elemental
sulfur, will be equivalent to the organic sulfur content of the process
gas stream and correspond to 98 percent recovery of the sulfur in
the high-sulfur coal. Based upon heating value of the product, the
emissions from this portion of the facility are about 0. 80 pounds
of sulfur per million Btu* (144 kg/109 kcal). Based upon coal input,
the sulfur emissions are about 0. 06 pound of sulfur per million
Btu*(108 kg/109 kcal).
(3) Comparison to Alternative, Acceptable Approaches
for Producing the Same Quantity of Energy
The product of the high-Btu coal gasification facility will
be burned, probably residentially, to produce clean heat energy.
If the coal were burned directly to produce the same quantity
of energy, 250 x 109 Btu/day (63 x 109 kcal/day), the total
emissions would be 75 short tons/day (68m tons/day) of sulfur,
calculated as elemental sulfur, in compliance with Federal
EPA New Source Performance Standards. If coal were burned
under boilers to produce electricity with the same heat content
(63 x 10 kcal/day, about 3 gigawatts) at 37. 5 percent efficiency,
the total sulfur emissions, calculated as elemental sulfur, would
be 200 short tons or 180 metric tons daily. These calculations
indicate that the sulfur emissions from the processing of high-
sulfur coal to produce high-Btu gas, even when estimated on a
conservative basis, are approximately 7.5 to 20 times lower
than they would be if an equivalent amount of energy were
produced by alternative means that are now considered to be
environmentally acceptable.
Short tons, reference footnote p. 1-4.
(10 tons S/day) x (2000^-) * (250 x 109 Btu/day).
Calculated on the basis of a gasification facility achieving
a 70 percent thermal efficiency.
IV-16
-------
(4) Potential Changes in Estimated Emissions
The data presented in this chapter are based upon conser-
vative engineering estimates of the future performance of the
various processing schemes. The potential exists for both higher
and lower emissions from these facilities. Higher emissions may
result if the organic sulfur content of the process gas stream is
higher than the thermodynamic equilibrium assumed here or if
Glaus plant tail-gas processes cannot operate satisfactorily on
a stream with high carbon dioxide concentration, as discussed
earlier. Similarly, lower emissions may result if the expectations
of several process licensors can be realized.* Table IV-2 outlines
the possible variation in the emissions for the various systems.
The results presented in the table are discussed below:
Glaus Plant Off-Gas: Some of the systems that
employ Glaus plants may suffer from increased
emissions if the tail-gas cleanup processes cannot
operate satisfactorily on CC^-rich feedstock. Gen-
erally, the final off-gas from a Glaus plant after tail
gas treatment is expected to contain 250 ppm total
sulfur (species undefined). These estimates are
based upon experience with operating plants and are
used as the estimating basis in this report. Thermo-
dynamically, however, the presence of high concentra-
tions of carbon dioxide in the process gas feed to the
Glaus plant may have an effect upon the emissions
from the overall facility. Table IV-2 indicates that
uncertainty in the Glaus plant emissions has the po-
tential of doubling the quantity of sulfur discharged
from this source. In those processing schemes that
employ Glaus plants, the total emissions might in-
crease about 1 tont /day, or, about 10 percent of the
total emissions estimated.
As footnoted on p. IV-7, the WESO plant design indicates
that future clean fuel facilities may have significantly
reduced emissions, compared to those projected in this
report. This report, however, considers a broad spectrum
of coals and gasifier types; conservative projections were,
therefore, felt to be appropriate.
Short tons, reference footnote p. 1-4.
IV-17
-------
Table IV-2
00
Estimated Potential Emissions From High-Btu Gas
Derived From High Sulfur Coal, Maximum Abatement Case
250xl09 Btu/day (63xl09 kcal/day) Facility
Preliminary Estimate
System Claus
Schemes Off-Gas
1
2
3 0.8
4 1.0
5 1.2
6 0.7
7 -
8 -
C02-Rich
Off-Gas
3.0
3.0
2.6
0.5
8.4
5.3
10.5
10.3
Sulfur
Guards
Emissions, short
0.05
0.02
0.5
0.02
-
-
0.2
0.5
Variation*
Claus
Total Off-Gas
tonst/day sulfur
3.5
3.0
3.9 +0.8
1.5 +1.1
9.6 +2.0
6.0 +0.6
10.7 -
10.8
C02-Rich
Off-Gas
-2.9
-2.9
-2.5
-0.3
- ..
-5.2
-10.4
-7.5*
* Potential for increase (+) or decrease (-) in the preliminary estimates of sulfur emitted in the Claus off-gas
or vented with the CC^-rich off-gas.
t Short tons x 0.9072 = m tons
Short tons x 0.8929 = LT
$ With additional processing.
-------
CO2-Rich Gas: As stated earlier in this chapter,
several process licensors expect lower losses of
carbonyl sulfide to the CC>2 gas than were assumed
in this report. Should these expectations be eventually
realized in practice, the overall reductions in emis-
sions from these facilities could be significant.
Table IV-2 indicates that some processing schemes
could have total emissions of less than 1 ton*/day
of sulfur and others may be reduced by at least
one order of magnitude.
4. COST AND EFFECTIVENESS OF SULFUR CONTROL SCHEMES
APPLIED TO A TYPICAL HIGH-BTU GAS STREAM GENERATED
FROM A LOW-SULFUR COAL FEED
The problem of sulfur removal and recovery in the production of
high-Btu gas from low-sulfur coal is closely related to the problem
discussed in detail earlier on the same process using high-sulfur coal.
In general, the same constraints apply. Rather than reiterate these
points, the detailed discussion on the production of the high-Btu gas from
high-sulfur coal is referenced throughout.
The production of high-Btu gas from low-sulfur coal was not
analyzed at the same level of detail as the more difficult problem
involving high-sulfur coal. During the evaluation of the high-sulfur
case, the limitations of the various sulfur removal and recovery
processes became evident. It was necessary, however, to analyze
three additional processing systems (nine levels of treatment) to
develop a comparison of the high- and low-sulfur coal cases, and
these systems are discussed in this section.
The hypothetical feed gas to the sulfur removal and recovery
system was specified in Chapter II. Its composition, presented in
Table II-6, assumes a molar flow rate for a plant producing 250 x
Btu/day (63 x 1Q9 kcal/day).
* Short tons, reference footnote p. 1-4.
IV-19
-------
In comparing the typical process gases for high- and low-sulfur
coals, the only difference is the sulfur content of the gas. Since the
lower sulfur coal would probably be a Western subbituminous coal
compared with an Eastern bituminous coal, for the high-sulfur case,
the gas from the Western coal should contain higher relative quantities
of methane and a lower concentration of carbon dioxide. However,
because the gases defined in this report represent only hypothetical
situations, the same base composition was used for both the highland
low-sulfur cases. This potential difference in the gas composition is
not considered significant within the context of this study.
The hypothetical low-sulfur process gas stream defines a
gas existing after gasification, water gas shift to the proper hydro-
gen/carbon monoxide ratio, quenching and washing to remove
water-soluble species (such as ammonia and phenols) and perhaps
straw-oil washing to remove most of the higher hydrocarbons
from the system. At this point in the process, the gas would
exist at 1050 psia (73. 7 kg/cm2) and 140° F (60° C).
The low sulfur concentration of this hypothetical gas may cause
some problems in sulfur removal and recovery. The CC>2/ sulfur ratio
in this case is 84:1 compared with 20:1 in the high-sulfur case. This
reduced sulfur concentration decreases the effectiveness of selective
acid-gas removal processes. Greater difficulties are encountered in
separation of the sulfur-rich and CC>2-rich fractions in the acid gas.
Specifically, the t^S-rich fraction should contain greater than 10 per-
cent sulfur to be an acceptable feed to a conventional Glaus plant.
However, the recovery of a high fraction of the sulfur to the Glaus feed
is difficult. Consequently, schemes such as System 4 and System 6 in
the high-sulfur case may not be applicable here because the sulfur con-
centration that must be left in the CC>2 -rich gas may be too high for
direct venting.
Three process systems have been evaluated in detail (see Figures
A-9 through A-ll and Tables A-9A through A-11A in the appendix to
this chapter). Considering flowsheet modifications in each of these pro-
cesses, a total of nine schemes are evaluated in the appendix. Material
balances and estimated costs are presented for each operating scheme.
The process parameters, as discussed earlier in this chapter, were
taken from the open literature and later modified as a result of exten-
sive conversations with various process licensors. The effectiveness
of the sulfur removal and recovery process selected for each control
scheme is presented in the appendix and discussed further in the fol-
lowing section.
IV-20
-------
5. SUMMARY OF COST AND PERFORMANCE RESULTS: SULFUR
REMOVAL AND RECOVERY FROM HIGH-BTU GAS DERIVED
FROM LOW-SULFUR FEED
Table IV-3 summarizes the sulfur emissions by source for the
nine processing schemes considered for low-sulfur coal. Also included
are the total capital investment requirements for each of the process
schemes and the effect of sulfur recovery upon gas price. Figure IV-3
and Figure IV-4 present this data (for low-sulfur coals) graphically to
facilitate a comparative analysis. Also included on these two figures
are the bands previously described for the high-sulfur coals.
As in the high-sulfur fuel case,, essentially total sulfur removal
is required to prevent poisoning of sensitive downstream catalysts.
Levels of controlling and recovering this removed sulfur can vary
widely, however.
From an examination of Figures IV-3 and IV-4, it appears that
the sulfur emissions from systems employing maximum practical
abatement on the hypothetical gas stream in a 250 x 10^ Btu/day (63 x
10^ kcal/day) facility will result in the discharge of about 2. 5-3. 5 tons*/
day of sulfur (.species undefined), calculated as elemental sulfur. The
total capital requirement for sulfur removal and recovery facilities
at maximum abatement is estimated to be about $60 million, and the
estimated effect upon gas price is expected to be between $0. 20 and
$0. 25/million Btu (about $0. 90/106 kcal).
The data given in Figures IV-3 and IV-4 can be grouped into
three levels of abatement:
Total emissions of 137 short tons/day (124 m ton/day)
total sulfur would be expected if the sulfur species were
removed from the process gas stream and discharged
directly to the atmosphere. As discussed earlier, this
situation is not a realistic mode of operation but presents
a base reference case for comparison of the costs of other
levels of abatement. For this hypothetical case with low-
sulfur coal, sulfur removal is expected to require about
$50 million total capital investment and add about $0. 20/
million Btu ($0. 80/106 kcal) to the gas price.
Short tons, reference footnote p. 1-4.
IV-21
-------
Table IV-3
to
CO
System
Scheme Description
9 Deep hot carbonate bulk
removal with Stretford
9a Omit Stretford
10 Selective solvent (light),
bulk solvent (deep) with
Claus, Claus tail gas
treatment, and Stretford
10a Omit Claus tail gas clean-up
lOb Om it Stretford
lOc Omit Claus tail gas, clean-up
and Stretford
10d 0 m it all sulfur recovery
11 Bulk amine system with
Stretford
11a Omit Stretford
Summary of Results
emoval and Recovery From High-Btu Gas
Derived From Low -Sulfur Coal
109 Btu/day (63x10 9 kcal/day) Facility
Emissions, short tons'/day Sulfur Incremental Gas Price
Claus
Off-Gas
—
0.3
12.2
0.3
12.2
-
. -
C°2-Rich Sulfur
Off-Gas Guard
3.1 0.03
137.0
2.0 0.003
2.0 0.003
15.3 0.003
15.3 0.003
137.0 0.003
3.0 0.3
136.8 0.3
Incremental Capital „
Total lnvestment,$ million1 C/106 Btu
3.1 54.8 23.0
137.0 46.2 20.2
2.3 58!l 21.4
14.2 55.6 20.8
15.6 56.8 20.9
27.5 53.7 20.2
137.0 52.2 20.0
3.3 64.9 42.5
137.3 56.4 39.7
C/106kcal
91.3
80.2
84.9
82.5
82.9
80.2
79.4
168.7
157.5
* short tons x 0.9072 = m tons
short tons x 0.8929 = LT
When comparing the data reported here, the limitations discussed on pages I-7, 8 and IV-2, 5 should be recognized.
-------
CO
•o
"c
I
r
o
V)
CO
z
o
m
DC
D
CO
700
500
300
200
100
70
50
30
20
10
7
5
3
2
BAND OF DATA FROM FIG. IV-1
HIGH-SULFUR COAL
O
I
500
300
200
100
70
50
30
20
10
7
5
3
2
s-
1
I
E
co"
z
o
HI
cc
40
50 60 70 80
INCREMENTAL CAPITAL INVESTMENT, $106
90
FIGURE IV-3
Summary of Results
Incremental Capital Investment for Sulfur Removal
and Recovery From a High-Btu Gas Derived From a Low-Sulfur Coal
250x109 Btu/day (63x109 kcal/day) Facility
IV-2 3
-------
I
3
r
o
V)
w
700
500
300
200
100
70
50
30
20
10
7
5
3
2
—- FEED QD
15
BAND OF DATA FROM FIG. IV-2
HIGH-SULFUR COAL
(9
o
o —
o
1
20 25 30 35
INCREMENTAL GAS PRICE, /106 Btu
40
500
300
200
100
70
50
30
20
10
7
5
3
2
45
O
CO
g
V)
V)
cc.
ID
FIGURE IV-4
Summary of Results
Incremental Gas Price Increase Caused by Sulfur Removal
and Recovery From High-Btu Gas Derived From Low-Sulfur Coal
250xl09 Btu/day (63x1 Q9 kcal/day) Facility
IV-2 4
-------
A group of data points at 80 percent to 90 percent sulfur
recovery represents cases of intermediate abatement. The
capital requirement for this abatement level is about
$4 million or $5 million more than for the first case (no
recovery). The increased cost of gas is about $0. Ol/
million Btu ($0. 04/10 kcal) because of the market value
of the sulfur recovered.
A group of points at maximum abatement corresponds
to emissions of about 2. 5-3. 5 tons* of sulfur/day. The
total capital requirement for this abatement is about
$60 million. The differential capital requirement for max-
imum abatement as compared to maximum emissions is
about $10 million and the increased capital for maximum
abatement (about 97. 5 percent) over 90 percent abatement
is about $5 million. The total increase in gas price for
maximum abatement is about $0. 22-$0. 23/million Btu
(about $0. 89/106 kcal) compared with about $0. 20 ($0. 79/
106 kcal) for no abatement and $0. 2.1 ($0. 83/106 kcal)
for minimal abatement.
Based on the results in Table IV-3 and Figures IV-3 and IV-4,
the controlling factor that determines the maximum abatement in the
processing of low-sulfur coal is the quoted purity of the CO2~rich
gas, estimated as 250 ppm monatomic sulfur (species undefined)
discharged from the system. In the hypothetical gas stream, this
concentration amounts to 3. 1 tons*/day discharged, calculated as
elemental sulfur. On this basis, the discharge from the hypothetical
facility is about 2. 5 percent of the incoming sulfur, compared with
about 2 percent of the sulfur fed to the high-sulfur case that was
controlled by COS formation.
The criterion used to estimate sulfur discharge (250 ppm total
sulfur in the CO2~vent gas) indicates that there will be different
emissions from different high-Btu gas manufacturing facilities employing.
low-sulfur coal. These will depend on the efficiency of the gasification
process employed and the reactivity of the coal species used as feed.
Short tons, reference footnote p. 1-4.
IV-2 5
-------
If the product gas were made by a synthesis gas route, with essentially
no methane manufactured in the gasifier itself, the total carbon dioxide
content of the processing gas stream would be significantly higher, thus
increasing the total sulfur emissions. For the stream compositions
in a Koppers-Totzek synthesis gas generator, the calculated emissions
from a low-sulfur coalby this route are 4.7 tonp*/dayt . At the
other extreme, using the efficiency claimed for the Synthane process,
the quantity of CC>2 discharged is reduced and the expected sulfur
emissions are about 2. 5 tons*/day. Similar changes in emissions can
be expected from processing coals of different reactivities.
(1) Comparison With Emissions When Processing High-Sulfur
Coal
The total sulfur concentration in the feedstock for the
low-sulfur coal is a factor of 5 less than the concentration in
the high-sulfur coal -- 0. 9 percent compared with 4. 5 percent.
The ratios of the sulfur concentrations in the process gas are
4. 18:1 (0. 37 percent compared with 1. 54 percent). The reduced
ratio in the process gas is due primarily to the heat content
assumed for the different coals. The ratios of the concentrations
in the acid-gas, assuming simultaneous sulfur and CC>2 recovery,
are 4. 08:1 (1.17 percent against 4. 78 percent).
The expected reduction in emissions is a factor of about
3 (10 tons*/day against 3. 5 tons*/day). The reason that the
relative emissions from the high- and low-sulfur cases are not
the same is that different criteria control the emissions in the
different cases. In the high-sulfur case, the emissions were
determined by the quantity of organic sulfur species that was
present in the gas stream and lost to the process. However,
in the case of the low-sulfur coal, the controlling parameter
is the concentration of sulfur species expected in the CO2~vent
gas. In the low-sulfur case the quantity of carbonyl sulfide
manufactured in the process is expected to be less than the
quantity of equivalent sulfur present at 250 ppm total sulfur in
the CO2-rich gas.
Short tons, reference footnote p. 1-4.
Booz, Allen & Hamilton, Inc., Final Report No. 9075-015 to
the U. S. Environmental Protection Agency, Emissions From
Processes Producing Clean Fuels. March 1974.
IV-2 6
-------
If a coal had been considered with intermediate sulfur
concentrations, the expected emissions might again have been
controlled by the carbonyl sulfide content of the gas. In this
case, the emissions may be intermediate between the quantities
estimated for the high- and low-sulfur cases.
The costs of sulfur removal and recovery for the low-
sulfur case are lower than found with the high-sulfur case, but
not proportional to the sulfur content of the feedstock nor the
emissions levels. The total capital requirement at maximum
abatement is a factor of 2. 6 for the low-sulfur case when
compared with the high-sulfur case. The effect upon the gas
price is a reduction of about 25 percent from the high-sulfur
case to the low-sulfur case.
(2) Potential Changes in Emissions
As discussed more thoroughly in the earlier sections on
high-sulfur coal, the projections of emissions quoted in this
report are based upon conservative, engineering evaluation of
the available data. In this analysis, it was found that the
potential exists for both increased and decreased emissions from
the various processing schemes. Increased emissions might
be expected in the final effluent from Glaus plants; decreased
emissions might be expected in the primary CC^-rich gas
discharged to the atmosphere.
Based upon theoretical considerations only, the potential
discharges from a Glaus plant, operating with high carbon diox-
ide concentrations in the feed gas, might double. In System 10,
(see the appendix to this chapter) "employing a Glaus plant, the
discharges might increase by 0. 3 ton*/day or about 10 percent
of the total expected emissions from the facility.
Some process licensors claim excellent recovery of all
sulfur compounds from the CO2~vent gas. Similarly, the
combination of hot carbonate and Stretford processing may result
in a CC^-vent gas of low-sulfur concentration. These schemes
Short tons, reference footnote p. 1-4.
IV-2 7
-------
might have potential for a total sulfur concentration in the CC>2-
rich gas of 10 ppm. If this low concentration can be proved on
a day-in, day-out basis for large-scale facilities (as is planned
for the Synthane and Bi-Gas pilot plants), the expected emissions
from these facilities might be reduced by about 1. 5 orders of
magnitude; however, until these systems are proved, these
optimistic projections could not be used as the basis for the
analysis presented in this report.
The basic conclusion which can be drawn from the discussion
presented in this chapter is that the level of sulfur emissions
resulting from the manufacture of high-Btu gas from feedstock
of any sulfur content, are expected to be equivalent either to:
250 ppm sulfur (unspecified monatomic species)
in the total CO2 vented from the process gas
Organic sulfur content of the process gas,
whichever is greater.
IV-2 8
-------
APPENDIX A
-------
APPENDIX A(l)
STREAM No.
DESCRIPTION
TEMP, °F (°C)
Ib-moles/hr*
CO
H2
CH,
C2H6
N2
H20
C02
H2S
COS
s
TOTAL "S"
TOTAL
1
SOUR CAS
140 (60)
12,500
40,000
12,705
800
200
160
30,000
1,480
27
—
1,507
97,872
2
TREATED
GAS
100 (38)
12,440
39,900
12,645
799
199
40
660
unk
unit
' —
1.4
(20 ppm)
66,684
3
ACID GAS
100 (38)
60
100 ^
60
1
1
1,500
29,340
unk
unit
--
1505.6
32,568
4
OFF-GAS
100 (38)
60
100
60
1
1
1,500
29,340
unk
unk
unk
8
(250 ppm)
31,070
5
BYPRODUCT
SULFUR
1,497.6
1,497.6
(576 tons/dor)
*lb-motes/hr x 0.126 = gm-moles/sec.
Figure A-l
LIGHT HOT POTASSIUM CARBONATE AND STRETFORD PROCESS
-------
APPENDIX A(2)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH-Btu GAS
FROM HIGH SULFUR COAL
System No. 1:
System No. 1A:
Hot potassium carbonate system of light severity for bulk
acid-gas removal, followed by Stretford process for sulfur
recovery (Fig. A-l)
Similar to System 1, but omit Stretford process.
Acid Gas Removal
Hot potassium carbonate system ("Hot Pot") of light severity to reduce H^S
concentration in product gas to 20 ppm. Final COj concentration is 1%. Carbonyl
sulfide is hydrolyzed and regenerated as ^S in the Hot Pot system. From
Fig. A-l, total acid gas removed (H2S + (X^) is 3886.5 gm-moles/sec
(30845.6 Ib-moles/hr) or 7935 x 103 m3/day (280.2 x 106 ft/day).
Estimating Bases;
Component
Investment Cost
Steam Duty
Cooling Duty
Net Power Req'd
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
$100/103 ft3/day
23.2 X 10 Btu/lb-mole
acid gas removed
24.5 X 103 Btu/lb-mole
acid gas removed
1.07 X (0.4) HP/lb-mole
acid gas removed
0.022
-------
APPENDIX A(3)
Estimating Bases;
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day
(For capacity> 100 LT/D
Power Factor = 0.9, for
< 100 LT/D Power
Factor =0.7). . .
1473 Ib/LT
1353 kW/LT!
1026 gal/LT
$4/LT
$1/1000 Ib
Basis*
30C/1000 gal
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Guards
Activated carbon beds and zinc oxide beds are installed in series to purify
the product gas to <0.1 ppm sulfur content. From Fig. A-l, the feed gas to
the sulfur guard system will contain 20 ppm sulfur.
Estimating Bases;
Component
Investment
Steam
Power
Estimated Value
$1.0 X10 /5 ppm H S in Feed
(For Capacity >5ppm Power
Factor = 0.8, for < 5ppm
Power Factor = 0.6)
815 Ib/hr/ppm H S removed
5 hp/ppm H S removed
Chemicals Cost $61,800/year/ppm H S removed
Basis*
Cooling Water
70 gpm/ppm H S removed
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid--1974 basis.
-------
APPENDIX A(4)
Table A-lA
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 1
Incremental Investment
Component
Hot Pot Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard . .
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs .
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss *_
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies •
Local Taxes and Insurance .
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
Btu
$10
28.0
22.3
3.0
53.3
8.0
61.3
3.8
10.3
1.7
$77.1
$1000
332.2
919.5
187.8
863.7
5641.8
1164.2
715.0
52.4
682.8
249.1
3431.9
51.1
676.1
1374.3
99.
919,
1655.1
19016.2
-1690.1
17326.1
26596.4
82,125
32.4
-------
APPENDIX A(5)
Table A-IB
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 1A
(OMIT STRETFORD)
Incremental Investment
Component
Hot Pot Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
Btu
$10
28.0
3.0
31.0
4.7
35.7
2.5
6.0
1.1
$45.3
$1000
249.2
535.5
117.7
541.4
5641.8
1164.2
715.0
52.4
682.8
1374.3
74.8
535.5
963.9
12648.5
12648.5
18097.2
82,125
22.0
-------
APPENDIX A(6)
SOUR ^
BULK HOT
CARBONATE -
DEEP
1
REGENERATION
©
0
SULFUR GUARD
STRETFORD
PROCESS
1 '
REGENERATION
1©
BY-PRODUCT
SULFUR
_ CLEAN
OFF-
GAS
"©
STREAM No.
DESCRIPTION
TEMP, °F (°C)
Ib-moles/hr*
CO
H2
CH,
C2H6
N2
H20
C02
H2$.
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
140 (60)
12,500
40,000
12,705
800
200
160
30,000
1,480
27
• —
1,507
97,872
2
TREATED
GAS
100 (38)
12, 470
39,900
12,675
799
199
40
130
link
link
"
0.07
(1 Ppm)
66,213
3
ACID GAS
100 (38)
30
100
30
1
1
1,500
29,870
unk
link
—
1,507
33,039
4
OFF-GAS
100 (38)
30
100
30
1
1
1,500
29,870
iink
link
unk '
8
(250 ppm)
31,540
5
BY-PRODUCT
SULFUR
1,499
1,499
(577 tons/do/)
"Ib-moles/hr x 0.126 * gm-moles/sec.
Figure A-2
DEEP HOT POTASSIUM CARBONATE AND STRETFORD PROCESS
-------
APPENDIX A(7)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM HIGH SULFUR COAL
System No. 2:
System No. 2A:
Hot potassium carbonate system of deep severity for bulk
acid gas removal, followed by Stretford process for sulfur
recovery (Fig. A-2)
Similar to System 2, but omit Stretford process.
Acid Gas Removal
Hot potassium carbonate system ("Hot Pot") of deep severity to reduce H2S
concentration in product gas to 1 ppm. Final CO^ concentration is 0.2%-
Carbonyl sulfide is hydrolyzed and regenerated as H^S in the Hot Pot system.
From Fig. A-2 total acid gas removed (H2S + C02) is 3953.5 gin-moles/sec
(31377 Ib-moles/hr) or 8071 x 103 m3/ day (280.5 x 10& ft3/day).
Estimating Bases:
Component
Investment Cost
Steam Duty
Cooling Duty
Net Power Req'd
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
115 ft3/day
23.2 X 10 Btu/lb-mole
acid gas removed
24.5 X 10 Btu/lb-mole
acid gas removed
1.07 X (0.4) hp/lb-mole
acid gas removed
0.022 C/lb-mole
acid gas removed
$1/106 Btu
$0.03/1000 gal
1.5CAW
$2/106 Btu
Basis*
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Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
Stretford process to recover sulfur from the sour acid gas stream that was
the Hot Pot effluent. The Stretford system is capable of reducing the sulfur
concentration of this stream to 250 ppm, while recovering elemental sulfur.
From Fig. A-2 the quantity of sulfur recovered is 523 m tons/day (577 short
tons/day, 515 LT/day).
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(8)
Estimating Bases;
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day
(For capacity>100 LT/day
Power Factor = 0.9, for
<100 LT/day Power
Factor =0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 Ib
1.5$./kW
30C/1000 gal
Basis*
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Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Guards
Activated carbon beds and zinc oxide beds are installed in series to
purify the product gas to <0-1 ppm sulfur content. From Fig. A-2 the
feed gas to the sulfur guard system will contain 1 ppm sulfur.
Estimating Bases;
Component
Investment
Steam
Power
Estimated Value
$1.0 X10 /5 ppm H S in Feed
(For capacity> 5ppm Power
Factor = 0.8, for < 5ppm
Power Factor =0.6)
815 Ib/hr/ppm H S removed
5 hp/ppm H S removed
Chemicals Cost $61,800/year/ppm H S removed
Basis*
Cooling Water
70 gpm/ppm H S removed
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
Table A-2A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 2
APPENDIX A(9)
Incremental Investment
Component
Hot Pot Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
32.8
22.3
0.4
55.5
8.3
63.8
3.6
10.8
1.7
$79.9
$1000
332.2
957.0
193.4
889.5
5738.8
1184.2
727.3
53.3
443.1
249.1
3431.9
51.1
676.1
68.7
99.7
957.0
1722.6
17775.0
-1691.8
16083.2
25688.9
82,125
31.3
-------
Table A-2B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 2A
(OMIT STRETFORD)
APPENDIX A(10)
Incremental Investment
Component
Hot Pot Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental .Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
32.8
0.4
33.2
5.0
38.2
2.3
6.4
1.0
$47.9
$1000
249.2
573.0
123.3
567.3
5738.3
1184.2
727.3
53.3
443.1
68.7
74.8
573.0
1031.4
11406.9
11406.9
17165.1
82,125
20.9
-------
APPENDIX A(11)
BY-PRODUCT
SULFUR
STREAM No.
DESCRIPTION
TEMP, °F (°C)
Ib-moles/hr*
CO
H2
CH4
C?H6
N2
H20
C02
H2S
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
140 (60)
12,500
40,000
12,705
800
200
160
30,000
1,480
27
—
1.507
97,872
2
PARTIALLY
TREATED
100 (381
12,490
39,970
12,695
799
199
40
26,000
unk
unk
—
150'
92,343
3
TREATED
GAS
.00 (38)
12,435
39,800
12,640
798
198
40
640
unk
unk
—
1.4
(20 ppm)
66,552
4 .
H2S-RICH
ACID GAS
100 (38)
10
30
10
1
1
400
4,000
unk
unk
unk
1,357*
(23K) ,
5,809
5
CLAUS
TAIL GAS
2,716
1,690
4,017
unk
unk
unk
95*
8,518
6
OFF-GAS
120 (49)
2,716
1,690
4,017
unk
unk
unk
2
(250 ppm)
8,425
7
LEAN
ACID GAS
100 (38)
55
170
55
1
1
1,200
25,360
unk
unk
—
148.6
26,991
8
OFF-GAS
100 (38)
55
170
55
1
1
1,200
25,360
unk
unk .
—
7
(250 ppm)
26,849
9
CLAUS
SULFUR
1,355
1,355 (521.4
tons/day)
10
STRETFORD
SULFUR
141.6
141.6
54.5 Ions/day)
" Ib-moles/hr x 0.126 = gm-moles/sec.
t 90% Sulfur removal in light hot carbonate select!'
193% Claus efficiency.
Figure A-3
LIGHT HOT POTASSIUM CARBONATE WITH CLAUS AND STRETFORD PROCESS
-------
APPENDIX A(12)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM HIGH SULFUR COAL
System No. 3:
System No. 3A:
System No. 3B:
System No. 3C:
Hot potassium carbonate system of deep severity for
selective H S removal from process gas stream, followed
by hot potassium carbonate system of light severity for
bulk acid gas removal. The H S-rich acid gas from the
selective system is processed by a Claus plant, followed
by Claus tail gas treatment. The lean acid gas from the
bulk removal is treated by a Stretford process for sulfur
recovery (Fig. A-3)
Similar to System 3, but omit Claus tail gas treatment.
Similar to System 3, but omit Stretford process.
Similar to System,3, but omit both Stretford process and
Claus tail gas treatment.
Acid Gas Removal
Selective: Hot potassium carbonate system ("Hot Pot") of deep severity will
remove 90% of H2S in the process gas in addition to 13% of C02, producing a
H S--rich acid gas of 23% H2S concentration suitable for feed to a Claus plant.
From Fig. A-3 the total acid gas removed in the primary treatment is
675 gm-moles/sec (5357 Ib-moles/hr) or 1379 x 103 m3/day (48.7 x 10^ ft3/day).
Bulk: A bulk removal of the remainder of the acid gas (to 20 ppm H2S and
1% C02) is achieved with a secondary hot pot treatment of light severity.
Carbonyl sulfide is hydrolyzed and regenerated as H2S in this hot pot system.
From Fig. A-3 the acid gas removed is 3214.1 gm-moles/sec (25508.6 lb-moles/
hr) or 6567.4 x 103 m3/day (231.9 x 106 'ft3/day).
Estimating Bases:
Component
Investment Cost
Selective
Investment Cost
Bulk
Steam Duty
Cooling Duty
Net Power Req'd
Estimated Value
$150/103 ft3/day
$100/103 ft3/day
23.2 X 10 Btu/lb-mole
acid gas removed
24.5 X 10 Btu/lb-mole
acid gas removed
1.07 X (0.4) hp/lb-mole
acid gas removed
Basis*
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Costs Calculated on a mid-1974 basis.
-------
APPENDIX A(13)
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
0.022 C/lb-mole
acid gas removed
$1/106 Btu
$0.03/1000 gal
1.5100 LT/Day
escalated by 25% From
Mid-1971 to Mid-1974.
Basis
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-25
Operating Costs $1.50/LT
(Including utilities,
catalysts, chemicals etc.)
Derived from process
engineering for tail gas,
July 1973 and some other
articles
Claus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Claus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content
Component
Investment Cost
Operating Cost
Estimated Value
Equal to Claus plant
cost
Equal to Claus plant
cost
Basis
From article "Add On Process
Slashes Claus Tail Gas
Pollution," Dec. 13, 1971
Stretford Process: Recovery of elemental sulfur from streams with relatively
low H2S concentration (From Fig. A-3, 0.55% in this case). Stretford process
is capable of reducing the sulfur concentration in this stream to 250 ppm. From
Fig. A-3, the quantity of sulfur recovered is 49.4 m tons/day (54.5 short tons/
day, 48.7 LT/day).
-------
APPENDIX A(14)
Estimating Bases;
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100J,T/Day - (For
capacity> 100 LT/day Power
Factor = 0.9, for< 100 LT/day.
Power Factor = 0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 Ib
1.5 5ppm Power
Factor =0.8 for< 5ppm
Power Factor = 0.6)
815 Ib/hr/ppm H S Removed
5 HP/ppm H S Removed
$61,800/year/ppm H S Removed
$1/1000 Ib
1.5
-------
Table A-3A
SUMMARY: . INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 3
APPENDIX A(15)
Incremental Investment
Component
Hot Pot Acid-Gas Removal Light (Selective + Bulk)
Glaus Sulfur Recovery
Glaus Tail Gas Cleanup
Stretford Sulfur Recovery .
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Glaus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
30.5
5.6
5.6
3.2
3.0
47.9
7.2
55.1
3.1
9.3
1.4
$68.9
$1000
332.2
826.5
173.8
799.5
5645.7
1165.0
715.4
52.5
925.6
24.4
340.6
5.7
67.0
229.4
229.4
1374.3
99.7
826.5
1487.7
15320.9
-1696.7
13624.2
21906.1
82,125
26.7
-------
Table A-3B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 3A
(Omit Claus Tail Gas Cleanup)
APPENDIX A(16)
Incremental Investment
Component
$10
Hot Pot Acid-Gas Removal Light (Selective + Bulk)
Claus Sulfur Recovery
Claus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
30.5
5.6
3.2
3.0
42.3
6.3
48.6
4.9
8.2
1.3
$63.0
$1000
290.6
729.0
152.9
703.5
5645.7
1165.0
715.4
52.5
925.6
24.4
340.6
5.7
67.0
229.4
1374.3
87.2
729.0
1312.2
14550.0
-1592.0
12958.0
20531.1
82,125
25.0
-------
APPENDIX A(17)
.Table A-3C
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 3B
(Omit Stretford Sulfur Recovery)
Incremental Investment
Component $1O
Hot Pot Acid-Gas Removal Light (Selective + Bulk) 30.5
Claus Sulfur Recovery • 5.6
Claus Tail Gas Cleanup . 5.6
Stretford Sulfur Recovery
Sulfur Guard . 3.0
Subtotal Incremental Plant Investment 44.7
Project Contingency 6.7
Total Incremental Plant Investment 51.4
Start-up Costs 2.9
Interest During Construction 8.7
Working Capital ]L. 3
Total Incremental Capital Requirement $64.3
Incremental Annual Operating Costs
Component • $1000
Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs) 290.6
Maintenance Labor 771.0
Supervisory 159.2
Administrative and General Overhead 732.5
Other Direct Costs
Hot Pot Steam 5645.7
Hot Pot Power 1165.0
Hot Pot Cooling Water ' 715.4
Hot Pot Chemicals 52.5
Hot Pot Product Loss 925.6
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals 229.4
Claus Tail Gas Utilities and Chemicals 229.4
Sulfur Guard Utilities and Chemicals 1374.3
Operating Supplies 87.2
Maintenance Supplies 771.0
Local Taxes and Insurance 1387.8
Incremental Gross Operating 14536.6
By-Product Sulfur Credit —1536.8
Incremental Net Operating Cost 12999.8
Incremental Annual Revenue Required 20728.7
Annual Gas Production, 10 Btu 82,125
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu 25.2
-------
APPENDIX A(18)
Table A-3D
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 3C
(Omit Glaus Tail Gas Cleanup and
Stretford Sulfur Recovery)
Incremental Investment
Component $10 •
Hot Pot Acid-Gas Removal Light (Selective + Bulk) 30.5
Claus Sulfur Recovery 5.6
Claus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard 3. 0
Subtotal Incremental Plant Investment 39.1
Project Contingency 5.9
Total Incremental Plant Investment 45.0
Start-up Costs 2.8
Interest During Construction 7.6
Working Capital 1.2
Total Incremental Capital Requirement $56.6
Incremental Annual Operating Costs
Component $1000
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs) 249.2
Maintenance Labor 675.0
Supervisory 138.6
Administrative and General Overhead 637.7
Other Direct Costs
Hot Pot Steam 5645.7
Hot Pot Power 1165.0
Hot Pot Cooling Water . 715.4
Hot Pot Chemicals 52.5
Hot Pot Product Loss 925.6
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals 229.4
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals 1374.3
Operating Supplies 74.8
Maintenance Supplies 675.0
Local Taxes and Insurance 1215.0
Incremental Gross Operating Cost 13773.2
By-Product Sulfur Credit —1432.2
Incremental Net Operating Cost 12341.0
Incremental Annual Revenue Required 19145.4
Annual Gas Production, 10 Btu 82,125
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu. . . 23.3
-------
APPENDIX A(19)
STREAM No.
DESCRIPTION
TEMP. °F (°C)
Ib-moles/hr*
CO
H2
CH4
C2H6
N2
H20
C02
H2S
COS
s
TOTAL "5"
TOTAL
• 1
SOUR GAS
140 (60)
12,500
40,000
12,705
800
200 .
160
30,000
1,480
27
-
1,507
97,872
2
PARTIALLY
TREATED
100 (38)
12,494
39,982
12,699
799
199
40
24,500
unk
unk
—
1.3'
90,714
3
TREATED
GAS
100 (38)
12,469
39,902
12,674
798
198
40
140
unk
unk
—
0.06
(1 ppm)
66,221
4
H2S-RICH
GAS
100 (38)
6
18
6
1
1
450
5,500
unk
unk
—
1,505.7
(MX)
7,488
5
CLAUS TAIL
GAS
2,936
1,960
5,514
unk
unk
unk
105.4 *
10,515
6
OFF-GAS
120 (49)
2,936
1,960
5,514
unk
unk
unk
2.6
(250 ppm)
10,413
7
C02 -RICH
GAS
100 (38)
25
80
25
1
1
1,200
24,360
unk
unk
—
1.28 »
(50 ppm)
25,693
8
BY-PRODUCT
SULFUR
1,503.1
1,503.1(578.4
tons/day)
* Ib-moles/hr x 0.126 - gm-moles/sec.
t Basis: 50 ppm in®.
* 93% Glaus efficienty.
Figure A-4
DEEP HOT CARBONATE AND CLAUS PROCESS
-------
APPENDIX A(20)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM HIGH SULFUR COAL
System No. 4:
System No. 4A:
Hot potassium carbonate system of deep severity for
selective H S removal from process gas stream,
followed by hot potassium carbonate system for bulk
acid gas removal. The H S-rich acid gas from the
selective system is processed by a Claus plant, followed
by Claus tail gas treatment. The lean acid gas from
the bulk removal is vented (Fig. A-4)
Similar to System 4, but omit Claus tail gas treatment.
Acid Gas Removal
Selective: Hot potassium carbonate system ("Hot Pot") of-deep severity
will remove H2S in the process gas to the extent that the gas vented from
bulk removal contains 50 ppm total sulfur. Minimal C02 is also removed,
producing a H2S-rich acid gas of 20% H2S concentration suitable for feed to
a Claus plant. From Fig. A-4, the total acid gas removed in the primary
treatment is 882.8 gm-moles/sec (7006 Ib-moles/hr) or 1.8 x 106 m3/day
(63.6 x 106 ft3/day).
Bulk: A bulk removal of the remainder of the acid gas (to 1 ppm H2S and
0.2% CO2) is achieved with a secondary hot pot treatment of deep severity.
Carbonyl sulfide is hydrolyzed and regenerated as H2S in this system. From
Fig. A-4, the acid gas removed is 310.1 gm-moles/sec (24361.2 Ib-moles/hr)
or 6267 x 103 m3/day (221.3 x 105 ft3/day).
Estimating Bases:
Component
Investment Cost
Selective
Investment Cost
Bulk
Steam Duty
Cooling Duty
Net Power Req'd
Estimated Value
200 ft3/day
100 ft3/day
23.2 X 10 Btu/lb-mole
acid gas removed
24.5 X 103 Btu/lb-mole
acid gas removed
1.07 X (0.4) HP/lb-mole
acid gas removed
Basis*
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(21)
Chemicals Cost
Steam Cost .
Cooling Water Cost
Power Cost
Product Gas Loss
0.022 C/lb-mole
acid gas removed
$1/106 Btu
$0.03/1000 gal
$2/10 Btu
Communication With
Process Licensor
'Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
Claus Plant: Recovery of elemental sulfur from streams with relatively high
H2S concentration (Fig. A-4, 20% H2S in this case). With modification, COS
is also converted to sulfur. Estimated Claus plant efficiency is 93%. From
Fig. A-4, sulfur recovered is 516 LT/day, including sulfur values recovered in
tail gas treatment.
Estimating Bases;
Component
Investment Cost
Estimated Value
1.14 X 10 /100 LT/D (Max
capacity 350 LT/day (Max
each train)
2 trains, 0.8 Power Factor
for capacity> 100 LT/Day
escalated by 25% From
Mid-1971 to Mid-1974.
Basis
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-25
Operating Costs $1.50/LT
(Including utilities,
Catalysts, chemicals, etc.)
Derived from "Process
Engineering for Tail Gas,"
July 1973 and some other
articles
Claus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Claus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content
Component
Investment Cost
Operating Cost
Estimated Value
Equal to the Claus
Plant Cost
Equal to the Claus
Plant Cost
Basis
From article "Add On Process
Slashes Claus Tail Gas
Pollution," Dec. 13, 1971
Sulfur Guards
Activated carbon beds and zinc oxide beds are installed in series to purify
the product gas to<0.1 ppm sulfur content. From Fig. A-4, the feed gas to
the sulfur guard system will contain 1 ppm sulfur.
-------
APPENDIX A(22)
Estimating Bases:
Component
Investment Cost
Steam
Power
Chemicals Cost
Cooling Water
Steam Cost
Power Cost
Cooling Water
Estimated Value
$1.0 X 106/5ppm H S Feed
(for capacity>5ppm Power
Factor = 0.8 for<5ppm
Power Factor = 0.6)
815 Ib/hr/ppm H S Removed
5HP/ppm H S Removed:
$61,800/year/ppm H S Remove
70 gpm/ppm H S Removed
$1/1000 Ib
l.SC/kW
3C/1000 gal
Basis*
Estimated for This Report
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
for This
for This
for This
for This
for This
for This
for This
Report
Report
Report
Report
Report
Report
Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs.calculated on a mid-1974 basis.
-------
Table A-4A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 4
APPENDIX A(23)
Incremental Investment
Component
Hot Pot Acid-Gas Removal Deep (Selective + Bulk)
Claus Sulfur Recovery
Claus Tail Gas Cleanup
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
.Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
38.2
6.1
6.1
0.4
50.8
7.6
58.4
2.7
9.9
1.4
$72.4
$1000
332.2
876.0
181.2
833.6
5737.2
1183.9
727.1
53.3
458.8
254.5
254.5
68.7
99.7
876.0
1576.8
13513.5
-1696.4
11817.1
20518.3
82,125
25.0
-------
Table A-4B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 4A
(Omit Glaus Tail Gas Cleanup)
APPENDIX A(24)
Incremental Investment
Component
Hot Pot Acid-Gas Removal Deep (Selective + Bulk)
Glaus Sulfur Recovery
Claus Tail Gas Cleanup
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
38.2
6.1
0.4
44.7
6.7
51.4
2.5
8.7
1.2
$63.8
$1000
290.6
771.0
159.2
732.5
5737.2
1183.9
727.1
. 53.3
458.8
, 254.5
68.7
87.2
771.0
1387.8
12682.8
-1585.5
11097.3
18764.3
82,125
22.8
-------
APPENDIX A(25)
BY-PRODUCT
SULFUR
STREAM No.
DESCRIPTION
TEMP, °F (°C)
Ib-moles/hr"
CO
H2
CH4
C?H6
N2
HjO.
C02
H2S
COS
S
TOTAL "S"
TOTAL
1
SOUR GAS
140 (60)
12,500
40,000
12,705
800
200
160
30,000
1,480
27
—
. 1,507
97,872
2
PARTIALLY
TREATED
12,498
39,998
12,701
798
199
30
21,177
157
21.6'
—
178.6
87,580
3
TREATED
GAS
12,488
39,878
12,676
598
198
30
320
unit
unk
—
0.1 ppm
66,188
4
HjS-RICH
ACID GAS
2
2
4
2
1
30
8,823
1,323
5.4'
—
1,328.4
(13%)
10,192
5
CLAUS
TAIL GAS
2,553
1,365
8,833
unk
unk
unk
133'
12,884
6
OFF-GAS
2,553
1,365
8,833
unk
unk
unk
3.2
(250 ppm)
12,754
7
LEAN
ACID GAS
10
120
25
200
1
40
20,857
157
21.6
—
178.6
21,432
8
C02-RICH
OFF-GAS
10
120
25
200
1
40
20,857
0.2 (10 ppm)
21.6
—
21.8
(1,024 ppm)
21,275
9
CLAUS
SULFUR
1,325.?
1,325.2
510 tons/dor)
10
STRETFORD
SULFUR
156.8
156.8
60.3 lons/dar)
" Ib-moles/hr x 0.126 = gnvmoles/se
t 20 % of COS to ®.
I 90% Glaus efficiency.
Figure A-5
ORGANIC SOLVENT WITH CLAUS AND STRETFORD PROCESS
-------
APPENDIX A(26)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF. HIGH BTU GAS
FROM HIGH SULFUR COAL
System.No. 5:
System No. 5A:
System No. 5C:
System No. 5D:
A selective, solvent-based system of light severity
will preferentially remove H S from the process gas
stream, followed by a solvent system of deep severity
for satisfactory bulk acid gas removal. The H S-rich
acid gas from the selective system is processed by a
Claus plant, followed by Glaus tail gas treatment. The
lean acid gas from the bulk removal is treated by a
Stretford process for sulfur recovery (Fig. A-5)
Similar to System 5, but omit Claus tail gas treatment.
System No. 5B: Similar to System 5, but omit Stretford process.
Similar to System 5, but omit both Stretford process and
Claus tail gas treatment.
Similar to System 5, but omit all sulfur recovery.
Acid Gas Removal
Selective: A solvent-based system of light severity will recover 89.4% of the
H2S and 20% of the COS, together with 41.7% of the CO2, producing an H2S-rich
acid gas of 13% sulfur concentration suitable for feed to a Claus plant. From
Fig. A-5, the total acid gas removed in primary treatment stage is 1278.4 gm-moles/
sec (10146 Ib-moles/hr) or 2.61 x 106 m3/day (92.2 x 106 ft3/day).
Bulk: A bulk removal of the remainder of the acid gas (to 0.1 ppm H2S and
0.5% CO2) is achieved with a secondary solvent treatment of deep severity. The
remainder of the COS is also removed. Light severity was not used in this case
because it leaves too much CO2 in the product gas, requiring significant changes
in the downstream processing. Some solvent-based systems also recover oils to a
separate stream; therefore, a credit is applied in this case for the costs of a
benzene recovery process required with other systems. From Fig. A-5, the acid gas
removed in this stage is 2650.5 om-moles/sec (21035.6 Ib-moles/hr) or
5.41 x 106 m /day (191.1 x 106 ft3/day).
Estimating Bases;
Component
Estimated Value
Investment Cost 120/10 ft /day
Light Solvent Selective
Investment Cost
Deep Solvent Bulk
Steam Required
Cooling Duty
Power Req'd
150/10 ftVday
5.35 Ib/lb-mole
acid gas removed
0.6 gpm/lb-mole
acid gas removed
1.3 HP/lb-mole
acid gas removed
Basis*
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(27)
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
0.081 C/lb-mole
acid gas removed
$1/1000 Ibs
$0.03/1000 gal
1.5 100 LT/day
escalated by 25% From
Mid-1971 to Mid-1974.
Basis
Mid-1971 Cost Basis, F.P.C-
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-25
Operating Costs $1.50/LT
(Including utilities,
catalysts, chemicals, etc.)
Derived from Process
Engineering for Tail Gas,
July 1973 and some other
articles
Claus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Claus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content
Component
Investment Cost
Operating Cost
Estimated Value
Equal to the Claus
Plant Cost
Equal to the Claus
Plant Cost
Basis
From article "Add On Process
Slashes Claus Tail Gas
Pollution," Chemical
Engineering, Dec. 13, 1971
Stretford Process: Recovery of elemental sulfur from streams with relatively
low H2S concentration (From Fig. A-5, 0.83% in this case). The Stretford
process does not remove CO2 from its feed gas. It will produce an effluent of
250 ppm sulfur concentration or contain all the feed COS plus 10 ppm H2S, which-
ever is greater. From Fig. A-5, the sulfur recovered in this Stretford plant
is 53.8 LT/day.
-------
APPENDIX A(28)
Estimating Bases;
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X loVlOO LT/day (for
capacity>100 LT/day Power
Factor = 0.9, for<100 LT/D
Power Factor = 0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 Ib
1.5<:/kW
30C/1000 gal
Basis*
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Guards
Activated carbon beds and zinc oxide beds are installed in series to purify
the product gas to <0.1 ppm sulfur content. From Fig. A-5, the feed gas to
the sulfur guard should contain as little as 0.1 ppm of sulfur. A concen-
tration of 1 ppm is used, however, to provide a conservative basis for analysis.
Estimating Bases;
Component
Investment Cost
Steam
Power
Chemicals Cost
Cooling Water
Steam Cost
Power Cost
Cooling Water
Estimated Value
Basis*
Estimated for This Report
$1.0 X 10 /5ppm H S Feed
(for capacity> 5ppm Power Factor
= 0.8 for<5ppm Power Factor = 0.6)
Estimated for This Report
Estimated for This Report
815 Ib/hr/ppm H S Removed
5 HP/ppm H S Removed-
$61,800/year/ppm H S Removed Estimated for This Report
70 gpm/ppm H S Removed
$1/1000 Ib
1.5C/kW
3C/1000 gal
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(29)
Table A-5A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 5
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Glaus Sulfur Recovery
Glaus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Glaus Utilities and Chemicals
Glaus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
39.7
-4.0
6.5
6.5
3.3
0.1
52.1
7.8
59.9
2.5
10.1
.1.4
$73.9
$1000
332.2
898.5
184.6
849.2
1188.9
3230.8
240.0
179.9
2573.3
-502.8
26.0
358.3
5.7
70.7
223.4
223.4
6.9
99.
898.
.7
.5
1617.3
12704.5
-1666.2
11038.3
19919.2
82,125
24.3
-------
Table A-5B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 5A
(Omit Claus Tail Gas Cleanup)
APPENDIX A(30)
Incremental Investment
Component
$10
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Claus Sulfur Recovery
Claus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
•>
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
39.7
^4.0
6.5
3.3
0.1
45.6
6.8
52.4
2.4
8.8
1.2
$64.8
$1000
290.6
786.0
161.5
742.9
1188.9
3230.8
240.0
179.9
2573.3
-502.8
26.0
358.3
5.7
70.7
223.4
6.9
87.2
786.0
1414.8
11870.1
-1520.7
10349.4
18136.2
82,125
22.1
-------
Table.A-5C
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 5B
(Omit Stretford Sulfur Recovery)
APPENDIX A(31)
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Claus Sulfur Recovery
Claus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
,Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
-------
APPENDIX A(32)
Table A-5D
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 5C
(Omit Claus Tail Gas Cleanup + Stretford Sulfur Recovery)
Incremental Investment
Component $10
Light Solvent Process For Acid-Gas Removal 39.7
Credit For Benzene Recovery -4.0
Claus Sulfur Recovery 6.5
Claus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard 0.1
Subtotal Incremental Plant Investment 42.3
Project Contingency . 6.3
Total Incremental Plant Investment 48.6
Start-up Costs 2.2
Interest During Construction 8.2
Working Capital 1.1
Total Incremental Capital Requirement $60.1
Incremental Annual Operating Costs
Component $1000
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs) 249.2
Maintenance Labor 729.0
Supervisory 146.7
Administrative and General Overhead 675.0
Other Direct Costs
Light Solvent Steam 1188.9
Light Solvent Power 3230.8
Light Solvent Cooling Water 240.0
Light Solvent Chemicals 179.9
Light Solvent Product Loss 2573.3
Credit For Benzene Recovery —502.8
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals 223.4
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals 6.9
Operating Supplies 74.8
Maintenance Supplies 729.0
Local Taxes and Insurance 1312.2
Incremental Gross Operating Cost 11056.3
By-Product Sulfur Credit —1344.2
Incremental Net Operating Cost 9712.1
Incremental Annual Revenue Required 16933.9
Annual Gas Production, 10 Btu 82,125
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu . 20.6
-------
Table A-5E
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 5D
(Omit Claus Plant, Claus Tail Gas Cleanup
+ Stretford Sulfur Recovery)
APPENDIX A(33)
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Claus Sulfur Recovery
Claus Tail Gas Cleanup
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (5 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
39.7
--4.0
0.1
35.8
5.4
41.2
2.0
7.0
1.1
$51.3
$1000
207.7
618.0
123.9
569.8
1188.9
3230.8
240.0
179.9
2573.3
-502.8
6.9
62.3
618.0
1112.4
10229.1
10229.1
16396.6
82,125
20.0
-------
APPENDIX A(34)
BY-PRODUCT
SULFUR
STREAM No.
DESCRIPTION
TEMP. °F (°C)
-Ib-moles/hr*
CO
H2
. CH,
C2H6
N2
H20
C02
H2S
COS
s
TOTAL ••$"
TOTAL
1
SOUR GAS
140 (60)
12,500
40,000
12,705
800
200
160
30,000
1,480
27
-
1,507
97,872
2
PARTIALLY
TREATED
12,498
39,998
12,701
795
199
30
26,530
0.3'
13.5'
—
13.8
92,765
3
TREATED
GAS
12,486
39,838
12,671
195
198
20
320
--
—
--
0.006
(0.1 ppm)
65,728
4
H2S-RICH
ACID GAS
2
2
4
5
1
20
3,470
1,479.7
13.5*
1,493.2
(30%)
4,997
5
CLAUS TAIL
GAS
2,893
1,085
3,499
148s
l.jS
unk
149.3
7,626
6
OFF-GAS
2,893
1,085
3,499
unk
unk
unk
2
(250 ppm)
7,479
7
C02-RICH
OFF-GAS
12
160
30
600
1
30
26,210
0.3 (10 ppm)
13.5
—
13.8
(510 ppm)
27,057
8
BY-PRODUCT
SULFUR
1,491.2
1,491.2(573.8
lons/dojr)
* Ib-moles/hr x 0.126 * gnvmoles/sec.
t 10ppmH2Sin®.
(50% of COS to®.
§ 90% Claus efficiency.
Figure A-6
ORGANIC SOLVENT AND CLAUS PROCESS
-------
APPENDIX A(35)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM HIGH SULFUR COAL
System No. 6:
System No. 6A:
A selective, solvent-based system of deep severity
will preferentially remove H S from the process gas
stream, followed by a solvent system of deep severity
for bulk acid gas removal. The H S-rich acid gas
from the selective system is processed by a Glaus plant,
followed by Glaus tail gas treatment. The lean acid
gas from the bulk removal is vented. (Fig. A-6)
Similar to System 6, but omit Claus tail gas treatment.
Acid Gas Removal
A solvent-based system of deep severity will recover the H^S so
Selective:
that the final concentration in the vented gas is 10 ppm, together with minimal
C02, to produce an H2S-rich acid gas of 30% sulfur concentration suitable for
feed to a Claus plant. Fifty percent of the COS in the feed is recovered with
this H2S-rich acid gas. From Fig. A-6, the total acid gas removed in primary
treatment stage is 625.3 gm-moles/sec (4963 Ib-moles/hr) or 1.277 x 106 m3/day
(45.1 x 106 ft3/day).
Bulk: A bulk removal of the remainder of the acid gas (to 0.1 ppm H2S and
0.5% CO2) is achieved with a secondary solvent system of deep severity. The
remainder of the COS is also removed. The solvent-based system also recovers
oils to a separate stream; therefore, a credit is applied in this case for the
costs of a benzene recovery process required with other systems. From Fig. A-6,
the acid gas removed in this stage is 3304 gm-moles/sec (26224 Ib-moles/hr) or
6746 x 103 m3/day (238.2 x 106 ft3/day).
Estimating Bases;
Component
Investment Cost
Deep Solvent Selective
Investment Cost
Deep Solvent Bulk
Steam Required
Cooling Duty
Power Req'd
Estimated Value
150 ft3/day
150 ft3/day
5.35 Ib/lb-mole
acid gas removed
0.6 gpm/lb-mole
acid gas removed
1.3 HP/lb-mole
acid gas removed
Basis*
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(36)
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
0.081 C/lb-mole
acid gas removed
$1/1000 Ib
$0.03/1000 gal
$2/10 Btu
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
Glaus Plant: Recovery of elemental sulfur from streams with relatively high
concentration (Fig. A-6, 30% in this case). With modification, COS is also con-
verted to elemental sulfur. The efficiency of the Glaus plant is depreciated to
90% following a solvent-based acid gas removal system. From Fig. A-6, the sulfur
recovery is 512.2 LT/day, including sulfur values recovered in tail gas treatment.
Estimating Bases:
Component
Investment Cost
Operating Costs
(Including Utilities,
Catalysts and chemicals etc.)
Estimated Value
1.1 X 106/100 LT/day (Max
capacity 350 LT/day for
each train)
2 trains, 0.8 Power Factor
for capacity> 100 LT/Day
escalated by 25% From
Mid-1971 to Mid-1974.
$1.50/LT
Basis
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-2!
Derived from "Process
Engineering for Tail Gas,"
July 1973 and some other
articles
Claus Plant Tail Gas .Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Claus
plant. ' These processes generally treat the tail gas to 250 ppm
total sulfur content
Component
Investment Cost
Operating Cost
Estimated Value
Equal to the Claus
Plant Cost
Equal to the Claus
Plant Cost
Basis
From article "Add On Process
Slashes Claus Tail Gas
Pollution," Chemical
Engineering, Dec. 13, 1971
Sulfur Guards
Activated carbon beds and zinc oxide beds are installed in series to purify the
product gas to <0.1 ppm sulfur content. From Fig. A-6, the feed gas to the
sulfur guard system will contain 0.1 ppm sulfur.
-------
APPENDIX A(37)
Estimating Bases;
Component
Investment Cost
Steam
Power
Chemicals Cost
Cooling Water
Steam Cost
Power Cost
Cooling Water
Estimated Value
$1.0 X 10 /5ppm H S Feed
(for capacity> 5ppm Power
Factor = 0.8 for<5ppm
Power Factor = 0.6)
815 Ib/hr/ppm H S Removed
5 HP/ppm H S Removed
$61,800/year/ppm H S Removed
70 gpm/ppm H S Removed
$1/1000 Ib
l.SC/kW
3C/1000 gal
Basis*
Estimated for This Report
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
for This
for This
for This
for This
for This
for This
for This
Report
Report
Report
Report
Report
Report
Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
Table A-6A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 6
APPENDIX A(38)
Incremental Investment
Component
Deep Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Claus Sulfur Recovery
Glaus Tail Gas Cleanup
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs • .
Deep Solvent Steam
Deep Solvent Power
Deep Solvent Cooling Water ,
Deep Solvent Chemicals
Deep Solvent Product Loss
Credit For Benzene Recovery
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
Btu
$10
42.5
-4.0
5.6
5.6
0.1
49.8
7.5
57.3
3.4
9.7
1.5
$71.9
$1000
332.2
859.5
178.8
822.3
1315.8
3575.3
265.5
199.2
6895.3
-502.8
252.4
252.4
6.9
99.7
859.5
1547.1
16959.1
-1682.6
15276.5
23919.8
82,125
29.1
-------
Table A-6B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 6A
(Omit Claus Tail Gas Cleanup)
APPENDIX A(39)
Incremental Investment
Component
Deep Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Claus Sulfur Recovery
Claus Tail Gas Cleanup
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs)
. Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Deep Solvent Steam
Deep Solvent Power
Deep Solvent Cooling Water
Deep Solvent Chemicals
Deep Solvent Product Loss
Credit For Benzene Recovery
Claus utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
42.5
-4.0
5.6
0.1
44.2
6.6
50.8
3.2
8.6
1.4
$64.0
$1000
290.6
762.0
157.9
726.3
1315.8
3575.3
265.5
199.2
6895.3
-502.8
252.4
6.9
87.2
762.0
1371.6
16165.2
-1517.8
14647.4
22342.3
82,125
27.2
-------
APPENDIX A(40)
BY-PRODUCT
SULFUR
STREAM No.
DESCRIPTION
TEMP, °F (°C)
Ib-moles/hr*
CO
H2
CH4
' C;H5
N2
H20
C02
H2S
COS
S
TOTAL "S"
, TOTAL
1
SOUR GAS
140 (60)
12,500
40,000
12,705
800
200
160
30,000
1,480
27
-
1,507
97,872
2
TREATED
CAS
140 (60)
12,475
39,880
12,680
79?
199
30
670
0.7
—
—
0.7
(lOppm).
66,734
3
ACID GAS
160(71)
25
120
25
1
1
4,200
29,330
1,479.3
27
—
1,506.3
35,208
4
OFF-GAS
100 (38)
25
120
25
1
1
. 1,500
29,330
0.3 (10 ppm)
27
--
27.3
(880 ppm)
31,029
5
BY-PRODUCT
SULFUR
1,479
1,479
(569 tons/dor)
= gm-moles/sec.
Figure A-7
AMINE AND STRETFORD PROCESS
-------
APPENDIX A(41)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM HIGH SULFUR COAL
System No. 7:
System No. 7A:
An amine-based system is used for bulk removal of
gas, followed by a Stretford process for selective
recovery of sulfur from the
(Fig. A-7)
H S in the acid gas
Similar to System 7, but omit Stretford process.
Acid Gas Removal
An example of amine-based bulk acid gas removal is included here because amines
are widely used for this service. In this case, a Diglycol Amine (DGA) was em-
ployed because it is resistant to COS degradation. According to process licensors,
the COS is regenerated, without hydrolysis, into the acid gas. The bulk treatment
with DGA reduces the sulfur content of the process gas to 10 ppm and removes CO2 to
1% concentration. From Fig. A-7, the total acid gas removed by the DGA is
3885.4 gm-moles/sec (30836.3 Ib-moles/hr) or 7932.4 x 103 m3/day (280.1 x 106 ft3/day)
Estimating Bases:
Component
Investment Cost
Steam
Cooling Duty
Net Power Req'd
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
$130/103 ft3/day
60 Ibs/lb-mole
acid gas removed
120 gpm/lb-mole
acid gas removed
1.24 hp/lb-mole
acid gas removed
1.30C/lb-mole
acid gas removed
$1/1000 Ib
$0.03/1000 gal
Basis*
$2/10 Btu
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
The Stretford process is used here for recovery of elemental sulfur from streams
with relatively low H2S concentration (From Fig. A-7, 4.2% in this case). The
Stretford process does not remove COS from its feed gas. It will produce an
effluent with 250 ppm total sulfur concentration or containing all the feed COS
plus 10 ppm H2S, whichever is greater. From Fig. A-7, the sulfur recovered in
the Stretford plant is 508 LT/day.
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(42)
Estimating Bases:
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day
(For capacity>100 LT/D
Power Factor = 0.9, for
<100 LT/D Power
Factor = 0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 LB
Basis*
30C/1000 gal
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Guards
Activated, carbon beds and zinc oxide beds are installed in series to purify the
product gas to <0.1 ppm sulfur content. From Fig. A-7, the feed gas to the sulfx
guard system will contain 10 ppm sulfur.
Estimating Bases:
Component
Investment
Steam
Power
Estimated Value
$1.0 X 106/5ppm H2S in Feed
(For Capacity> 5ppm Power
Factor = 0.8, for < 5ppm
Power Factor =0.6)
815 Ib/hr/ppm H S removed
5 hp/ppm H S removed
Chemicals Cost $61,800/year/ppm H S removed
Basis*
Cooling Water
70 gpm/ppm H S removed
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA. .
Costs calculated on a mid-1974 basis.
-------
Table A-7A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 7
APPENDIX A(43)
Incremental Investment
Component
Amine Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Amine Steam
Amine Power
Amine Cooling Water
Amine Chemicals
Amine Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10. Btu
$10
36.4
22.0
1.7
60.1
9.0
69.1
6.6
11.7
2.4
$89.8
$1000
332.2
1036.5
205.3
944.4
14586.8
3372.0
875.2
3171.7
443.1
246.0
3388.1
51.1
667.5
687.0
99.7
1036.5
1865.7
33008.8
-1668.8
31340.0
42145.5
82,125
51.3
-------
APPENDIX A(44)
Table A-7B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 7A
(Omit Stretford)
Incremental Investment
Component $10
Amine Acid-Gas Removal System 36.4
Stretford Sulfur Recovery
Sulfur Guard 1. 7
Subtotal Incremental Plant Investment 38.1
Project Contingency 5.7
Total Incremental Plant Investment • 43.8
Start-up Costs 5.3
Interest During Construction 7.4
Working Capital 1.8
Total Incremental Capital Requirement $58.3
Incremental Annual Operating Costs
Component $1000
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs) 249.2
Maintenance Labor 657.0
Supervisory 135.9
Administrative and General Overhead 625.3
Other Direct Costs
Amine Steam 14586.8
Amine Power 3372.0
Amine Cooling Water 875.2
Amine Chemicals ' 3171.7
. Amine Product Loss 443.1
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs 687.0
Operating Supplies 74.8
Maintenance Supplies 657.0
Local Taxes and Insurance 1182.6
Incremental Gross Operating Cost 26717.6
By-Product Sulfur Credit —
Incremental Net Operating Cost 26717.6
Incremental Annual Revenue Required 33737.5
Annual Gas Production, 10 Btu . 82,125
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu 41.1
-------
APPENDIX A(45)
CLEAN
GAS
STREAM No.
DESCRIPTION
TEMP, °F (°C)
Ib-moles/hr*
CO
H2
CH4
C2H4
N2
H20
C02
H2S
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
140 (60)
12,500
40,000
12,705
800
200
160
30,000
1,480
27
--
1,507
97,872
2
PARTIALLY
TREATED
120 (49)
12,440
39,900
12,645
799
199
40
29,700
1 (10 Ppm)
27
—
28
95,751
3
TREATED
GAS
120 (49)
12,380
39,800
12,585
798
198
40
665
unk
k
unk
1.3
(20 ppm)
66,467
4
OFF-GAS
100 (38)
60
100
"60
1
2,783
1,599
300
—
—
--
4,903
5
OFF-GAS
100 (38)
60
1 00
60
1
1
1,500
29,035
unk
unk
unk
26.7
(867 ppm)
30,784
6
BY-PRODUCT
SULFUR
1,479
1,479
(569 tons/dox)
" Ib-moles/hr x 0.126 * gm-moies/hr.
Figure A-8
STRETFORD AND HOT CARBONATE PROCESS
-------
APPENDIX.A(46)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM HIGH SULFUR COAL
System No. 8:
The Stretford process, operating under pressure, will
selectively remove H S from the process gas and
recover the sulfur in the elemental form. The carbon
dioxide, together with sulfur not recovered by the
Stretford Process, is then removed from the process gas
by a bulk hot potassium carbonate system of light severity.
The process gas is then further purified with sulfur
guards (Fig. A-8)
Sulfur Removal and Recovery
The Stretford process is used in this case for direct sulfur removal and
recovery. The ^S in the feed gas is reduced to a concentration of 10 ppm,
but the carbonyl sulfide is not attacked. From Fig. A-8, the sulfur recovered
in this stage is 508.1 LT/day.
Estimating Bases;
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day
(For capacity> 100 LT/D
Power Factor = 0.9, for
< 100 LT/D Power
Factor =0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 Ib
Basis*
30C/1000 gal
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
Acid Gas Removal \
The hot potassium carbonate system ("Hot Pot") of light severity will
reduce the sulfur in the process gas to 20 ppm, hydrolyzing the carbonyl
sulfide to H S. The carbon dioxide concentration is reduced to 1%. In
this case, the off gas is vented with less than 1000 ppm total sulfur,
although a separate, low pressure Stretford facility could be applied
here to reduce that concentration to 250 ppm. .
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(47)
Estimating Bases;
Component
Investment Cost
Steam Duty
Cooling Duty
Net Power Req'd
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
$100/103 ft3/day
23.2 X 10 Btu/lb-mole
acid gas removed
24.5 X 103 Btu/lb-mole
acid gas removed
1.07 X (0.4) hp/lb-mole
acid gas removed
0.022 5ppm Power
Factor = 0.8, for < 5ppm
Power Factor =0.6)
815 Ib/hr/ppm H S removed
5 hp/ppm H S removed
Chemicals Cost $61,800/year/ppm H S removed
Basis*
Cooling Water
70 gpm/ppm H S removed
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
Table A-8A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 8
APPENDIX A(48)
Incremental Investment
Component
Hot Pot Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct.Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
. Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
Btu
$10
26.4
27.6
3.0
57.0
8.6
65.6
4.1
11.1
1.8
$82.6
$1000
332.2
984.0
197.4
908.2
5641.0
1164.0
714.9
52.4
1363.9
307.5
4235.1
63.9
834.4
687.2
99.
984.
.7
.0
1771.2
20341.0
-1668.8
18672.2
28603.3
82,125
34.8
-------
APPENDIX A(49)
©
STREAM Mo.
DESCRIPTION
Ib-moles/hr*
CO
H?
CHj
C2H5
N2
H20
C02'
H2S
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
12,500
40,000
12,705
800
200
160
30,000
350
6
—
356
96,721
. 2
TREATED
GAS
12,470
39,900
12,675
799
199
40
130
0.07
(1 ppm)
—
—
0.07
66,213
3
ACID GAS
30
.100
30
1
1
1,500
29,870 '
unk
unk
356
31,888
4
OFF- GAS
30
100
30
1
1
1,500
29,870
unk
unk
8
(250 ppm)
31,540
5
BY-PRODUCT
SULFUR
348
348033.9
tons/day)
348
* Ib-moles/hr x 0.126 = gm-moles/sec
Figure A-9
DEEP HOT CARBONATE AND STRETFORD PROCESS
-------
APPENDIX A(50)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM LOW SULFUR COAL
System No. 9:
System No. 9A:
Hot potassium carbonate system of deep severity for bulk
acid gas removal, followed by Stretford Process for sulfur
recovery (Fig. A-9)
Similar to System 9, but omit Stretford process.
Acid Gas Removal
Hot potassium carbonate system ("Hot Pot") of deep severity to reduce H2S
concentration in product gas to 1 ppm. Final CO2 concentration is 0.2%.
Carbonyl sulfide is hydrolyzed and regenerated as H2S in the Hot Pot system.
From Fig. A-9, total acid gas removed (H2S + C02) is 30226.0 Ib-moles/hr
(3808.5 gm-moles/sec) or 274.6 x 106 ft3/day (7.8 x lO6 m3/day).
Estimating Bases:
Component
Investment Cost
Steam Duty
Cooling Duty
Net Power Req'd
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
115 ft3/day
23.2 X 103 Btu/lb-mole
acid gas removed
24.5 X 103 Btu/lb-mole
acid gas removed
1.07 X (0.4) hp/lb-mole
acid gas removed
0.022 C/lb-mole
acid gas removed
$1/106 Btu
$0.03/1000 gal
Basis*
$2/10 Btu
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
Stretford process to recover sulfur from the sour acid gas stream that was
the Hot Pot effluent. The Stretford system is capable of reducing the sulfur
concentration of this stream to 250 ppm, while recovering elemental sulfur.
From Fig. A-9, the quantity of sulfur recovered is 133.9 short tons/day
(119.6 LT/day, 121.5 m tons/day).
Costs calculated on a mid-1974 basis.
-------
APPENDIX A(51)
Estimating Bases:
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day
(For capacity > 100 LT/D
Power Factor = 0.9, for
< 100 LT/day Power
Factor = 0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 Ib
Basis*
30C/1000 gal
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Guards
Activated carbon beds and zinc oxide beds are installed in series to purity
the product gas to <0.1 ppm sulfur content. From Fig. A-9, the feed gas to
the sulfur guard system will contain 1 ppm sulfur.
Estimating Bases;
Component
Investment
Steam
Power
Estimated Value
$1.0 X106/5 ppm H S in Feed
(For capacity> 5ppm Power
Factor = 0.8, for < 5ppm
Power Factor =0.6)
815 Ib/hr/ppm H S removed
5 hp/ppm H2S removed
Chemicals Cost $61,800/year/ppm H S removed
Basis*
Cooling Water
70 gpm/ppm H S removed
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
Table A-9A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 9
APPENDIX A(52)
Incremental Investment
Component
Hot Pot Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
. Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit £'
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
31.6
6.0
0.4
38.0
5.7
43.7
2.5
7.4
1.2
$54.8
$1000
332.2
655.5
148.2
681.5
5528.3
1140.8
697.6
51.4
443.
58.
798.
11.4
157.2
68.7
99.7
655.5
1179.9
.1
,3
.3
12707.6
-392.9
12314.7
18903.5
82,125
23.0
-------
Table A-9B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 9A
(OMIT STRETFORD)
APPENDIX A(53)
Incremental Investment
Component
Hot Pot Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard .
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct. Costs
Hot Pot Steam
Hot Pot Power
Hot Pot Cooling Water
Hot Pot Chemicals
Hot Pot Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
-------
APPENDIX A(54)
BY-PRODUCT
SULFUR
STREAM No.
DESCRIPTION
Ib-moles/hr'
CO
H2
CH4
CjHi
N2
H20
C02
H2S
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
12,500
40,000
12,705
800
200
160
30,000
350
6
—
356
96,721
2
PARTIALLY
TREATED
12,498
39,998
12,701
798
199
30
27,930
35
4.8'
—
39.8
94,194
3
TREATED
GAS
12,488
39,878
12,676
598
198
30
320
unk
unk
—
0.1 ppm
66,188
4
H7S-RICH
ACID GAS
2
2
4
2
1
30
2,070
315
1.2'
—
316.2
(13%)
2,427
5
- CLAUS
TAIL GAS
657
357
2,081
unk
unk
31. 6<
3,127
6
OFF-GAS
657
357
2,081
unk
unk
unk
0.8
(250 ppm)
3,095
7
LEAN
ACID GAS
10
120
25
200
1
40
27,610
35
4.8
—
39.8
28,046
8
OFF-GAS
10
120
25
200
1
40
27,610
0.3
(10 ppm)
4.8
—
5.1
28,011
9
CLAUS
SULFUR
315.4(121.4
tons/day)
315.4
10
STRETFORD
SULFUR
34.7(13.3
tons/day)
34.7
'.Ib-moles/hr x 0.126 = gm-moles/sec.
120% of COS lo®.
t 90% Glaus efficiency.
Figure A-10
SELECTIVE SOLVENT, STRETFORD AND CLAUS PROCESS
-------
APPENDIX A(55)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM LOW SULFUR COAL
System No. 10:
System No. 10A:
System No. 10B:
System No. IOC:
System No. 10D:
A selective, solvent-based system of light severity
will preferentially remove H S from the process gas
stream, followed by a solvent system of deep severity
for satisfactory bulk acid gas removal. The H S-rich
acid gas from the selective system is processed by a
Claus plant, followed by Claus tail gas treatment. The
lean acid gas from the bulk removal is treated by a
Stretford Process for sulfur recovery (Fig. A-10) .
Similar to System 10, but omit Claus tail gas treatment.
Similar to System 10, but omit Stretford process.
Similar to System 10, but omit both Stretford process and
Claus tail gas treatment.
Similar to System 10, but omit all sulfur recovery.
Acid Gas Removal
Selective: A solvent-based system of light severity will recover 89.4% of the
H2S and 20% of the COS, together with 6.9% of the C02, producing an H2S-rich
acid gas of 13% sulfur concentration suitable for feed to a Claus plant. From
Fig. A-10, the total acid gas removed in primary treatment stage is 2386 lb-moles/
hr (301 gm-moles/sec) or 21.7 x 106 ft3/day (614.5 x 103 m3/day).
Bulk: A bulk removal of the remainder of the acid gas (to 0.1 ppm H2S and
0.5% C02) is achieved with a secondary solvent treatment'of deep severity. The
remainder of the COS is also removed. Light severity was not used in this case
because it leaves too much CO2 in the product gas, requiring significant changes
in the downstream processing. Some solvent-based systems also recover oils to a
separate stream; therefore, a credit is applied in this case for the costs of a
benzene recovery process required with other systems. From Fig. A-10, the acid
gas removed in this stage is 27650 Ib-moles/hr (3484 gm-moles/sec) or
251.8 x 106 ft3/day (7131 x 103 m3/day).
Estimating Bases;
Component
Investment Cost
Light Solvent Selective
Investment Cost
Deep Solvent Bulk
Steam Required
Cooling Duty
Power Req'd
Estimated Value
120/103 ft3/day
150/103 ft3/day
5.35 Ib/lb-mole
acid gas removed
0.6 gpm/lb-mole
acid gas removed
1.3 HP/lb-mole
acid gas removed
Basis*
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Costs calculated on a mid-1974 basis.
-------
Chemical Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
0.081
-------
APPENDIX A(57)
Estimating Bases:
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day (For
capacity>100 LT/day Power
Factor = 0.9, for<100 LT/D
Power Factor =0.7)
1473 lb/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 Ib
1.55ppm Power Factor
= 0.8 for<5ppm Power Factor = 0.6)
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
3C/1000 gal Estimated for This Report
815 Ib/hr/ppm H S Removed
5 HP/ppm H S Removed
$61,800/year/ppm H S Removed
70 gpm/ppm H S Removed
$1/1000 Ib
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force.report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
Table A-10A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 10
APPENDIX A(58)
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Glaus Sulfur Recovery
Claus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
40.4
-4.0
1.2
0.1
41.3
6.2
47.5
1.5
8.0
1.1
$58.1
$1000
332.2
712.5
156.7
720.0
1140.0
3099.5
230.2
172.6
2640.2
-502.8
5.5
80.4
1.1
15.8
53.3
53.3
6.9
99.
712.
.7
.5
1282.5
11012.9
-394.9
10618.0
17586.2
82,125
21.4
-------
Table A-10B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 10A
(Omit Glaus Tail Gas Cleanup)
APPENDIX A(59)
Incremental Investment
Component
$10
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Glaus Sulfur Recovery
Glaus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities arid Chemicals
Glaus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
40.4
^4.0
1.8
1.2
0.1
39.5
5.9
45.4
1.5
7.7
1.0
$55.6
$1000
290.6
681.0
145.7
670.4
1140.0
3099.5
230.2
172.6
2640.2
-502.8
5.5
80.4
1.1.
15.8
53.3
6.9
87.2
681.0
1225.8
10724.4
-321.3
10403.1
17083.8
82,125
20.8
-------
Table A-IOC
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 10B
(Omit Stretford Sulfur Recovery)
APPENDIX A(60)
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Glaus Sulfur Recovery
Claus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (7 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
. . Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
40.4
—4.0
1.8
1.8
0.1
40.0
6.0
46.0
2.1
7.7
1.0
$56.8
$1000
290.6
690.0
147.1
676.6
1140.0
3099.5
230.2
172.6
2640.2
-502.8
53.3
53.3
6.9
87.2
690.0
1242.0
10716.7
-356.1
10360.6
17185.0
82,125
20.9
-------
APPENDIX A(61)
Table A-lOD
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. IOC
(Omit Glaus Tail Gas Cleanup + Stretford Sulfur Recovery)
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Claus Sulfur Recovery
Glaus Tail Gas Cleanup
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
«/10 Btu
$10
40.4
-4.0
1.8
0.1
38.3
5.7
44.0
1.4
7.4
0.4
$53.7
$1000
249.2
660.0
136.4
627.3
1140.0
3099.5
230.2
172.6
2640.2
-502.8
53.1
6.9
74.8
660/.0
1188.0
10435.4
-321.3
10114.1
16565.2
82,125
20.2
-------
Table A-10E
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 10D
(Omit Claus Plant, Glaus Tail Gas Cleanup
+ Stretford Sulfur Recovery)
APPENDIX A(62)
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Credit For Benzene Recovery
Claus Sulfur Recovery
Claus Tail Gas Cleanup
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment.
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (5 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Chemicals
Light Solvent Product Loss
Credit For Benzene Recovery
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Sulfur Guard Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
40.4
-4.0
0.1
36.5
5.5
42.0
2.0
7.1
1.1
$52.2
$1000
207.7
630.0
125.7
578.0
1140.0
.5
.2
3099.
230.
172.6
2640.2
-502.8
6.9
62.3
630.0
1134.0
10154.3
10154.3
16429.6
82,125
20.0
-------
APPENDIX A(63)
0
STREAM No.
DESCRIPTION
Ib-moles/hr*
CO
H2
CHj
C2H6
N2
H20
C02
H2S
COS
S
TOTAL "S"
TOTAL
1
SOUR GAS
12,500
40,000
12.705
800
200
100
30,000
350
6
—
356
96,721
2
TREATED
GAS
12,475
39,880
12,680
799
199
30
670
0.7
(lOppro)
—
—
0.7
66,733
3
ACID GAS
25
120
25
1
1
4,200
29,330
349.3
6
-
355.3
34,057
a
OFF-GAS
25
120
25
1
1
1,500
29,330
0.3
(lOppm)
6
—
6.3
31,357
5
BY-PRODUCT
SULFUR
349
349(134.3
tons/doy)
349
" Ib-moles/hr x 0.126 = gm-moles/sec.
Figure A-ll
AMINE AND STRETFORD PROCESS
-------
APPENDIX A(64)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF HIGH BTU GAS
FROM LOW SULFUR COAL
System No. 11:
System No. 11A:
An amine-based system is used for bulk removal of
gas, followed by a Stretford process for selective
recovery of sulfur from the
(Fig. A-ll)
Similar to System 11, but omit Stretford process.
H S in the acid gas
Acid Gas Removal
An example of amine-based bulk acid gas removal is included here because amines
are widely used for this service. In this case, a Diglycol Amine (DGA) was
employed because it is resistant to COS degradation. According to process
licensors, the COS is regenerated, without hydrolysis, into the acid gas. The
bulk treatment with DGA reduces the sulfur content of the process gas to 10 ppm
From Fig. A-ll, the total acid gas removed
by the DGA is 19685.3 Ib-moles/hr (374 gin-moles/sec) or 269.7 x 106 ft3/day
and removes CO2 to 1% concentration.
by the DGA is 19685.
(7638 x 103 n>3/day) .
Estimating Bases:
Component
Investment Cost
Steam
Cooling Duty
Net Power Req'd
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
$130/103 ft3/day
60 Ibs/lb-mole
acid gas removed
120 gpm/lb-mole
acid gas removed
1.24 hp/lb-mole
acid gas removed
1.30
-------
APPENDIX A(65)
Estimating Bases:
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day
(For capacity>100 LT/day
Power Factor = 0.9, for
100 LT/day Power
< Factor = 0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 LB
1.5 5ppm Power
Factor = 0.8, for < 5ppm
Power Factor =0.6)
815 Ib/hr/ppm H S removed
5 hp/ppm H S removed
Chemicals Cost $61,800/year/ppm H S removed
Basis*
Cooling Water
70 gpm/ppm H S removed
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA
Costs calculated on a mid-1974 basis.
-------
Table A-11A
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 11
APPENDIX A(66)
Incremental Investment
Component
Amine Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Amine Steam
Amine Power
Amine Cooling Water
Amine Chemicals
Amine Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
35.1
6.0
1.7
42.8
6.4
49.2
5.5
8.3
1.9
$64.9
$1000
332.2
738.0
160.5
738.4
14042.3
3246.2
842.5
3054.
443.
58.
798.
11.4
157.2
687.0
99.7
738.0
1328.4
27476.2
-393.9
27082.3
34894.9
82,125
42.5
-------
Table A-11B
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 11A
(Omit Stretford)
APPENDIX A(67)
Incremental Investment
Component
Amine Acid-Gas Removal System
Stretford Sulfur Recovery
Sulfur Guard .
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (6 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Amine Steam
Amine Power
Amine Cooling Water
Amine Chemicals
Amine Product Loss
Stretford Steam
Stretford Power
Stretford Process Water
Stretford Chemicals
Sulfur Guard Costs
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu
$10
35.1
1.7
36.8
5.5
42.3
5.2
7.1
1.8
$56.4
$1000
249.2
634.5
132.6
609.8
14042.3
3246.2
842.5
3054.7
443.1
687.0
74.8
634.5
1142.1
25793.3
25793.3
32585.6
82,125
39.7
-------
V. SULFUR REMOVAL AND RECOVERY IN LOW-BTU
CLEAN FUEL PROCESSES
-------
V. SULFUR REMOVAL AND RECOVERY IN LOW-BTU
CLEAN FUEL PROCESSES
The manufacture of low-Btu gas from coal is expected to be a
major segment of the clean fuels industry in the future. For the pur-
poses of this report, low-Btu gas is assumed to be generated by an
airblown gasifier that manufactures a product with a caloric value of
about 150 Btu/ft3 (1335 kcal/m3). The low heating value is caused by
the dilution of the gas with nitrogen that was present in the air fed to
the gasifier. The gas contains sufficient energy to be fired under
boilers for the onsite generation of heat and/or electricity.
The first of these low-Btu gas facilities will be constructed to
demonstrate the utility of this technique to generate energy from high-
sulfur coal in an environmentally acceptable manner. The low-Btu
gas is desulfurized prior to combustion, as compared to the alterna-
tive of post-combustion treating of the stack gas. The first installa-
tions generating low-Btu gas will not be energy-conservative; the over-
all efficiency of generation of electricity by firing low-Btu gas under
boilers will be about 30 percent, coal-to-electricity, compared to
about 35 percent achievable by burning the coal directly with stack gas
desulfurization. In the future, however, low-Btu gas may be teamed
with combined-cycle systems for generation of electricity. When high-
temperature gas turbines have been developed for combined-cycle use,
the overall efficiency of gasification and combined-cycle power genera-
tion may exceed 40 percent. Therefore, the manufacture and desulfur-
ization of low-Btu gas may become a significant factor in the clean
fuels industry.
The removal and recovery of sulfur in low-Btu processing is
based upon applications of the processes now being developed for high-
Btu gas purification. The application of these processes to high-Btu
gas was discussed in detail in Chapter IV and will not be repeated.
The discussion presented on low-Btu gases is necessarily more
qualitative than the discussion on high-Btu gas because of the following:
The development of low-Btu gasification processes has pro-
ceeded more slowly than that for high-Btu gasification
V-l.
-------
Less work has been completed on the application of sulfur
removal processes to low-Btu gas
The low-Btu gases themselves have not been adequately
specified.
Despite these limitations, the data presented here represent the best
available information on the applicability and effectiveness of applying
control techniques, to this type of gas stream.
Presently, one facility has been installed for the manufacture of
low-Btu gas from coal. An airblown Lurgi gasification system has
been constructed at STEAG in Liinen, West Germany. This installa-
tion has faced several problems in a protracted startup, but it is ex-
pected to be functional soon. Although plans have been announced for
eventual inclusion of sulfur removal and recovery at this facility, the
low-Btu gas from this system will not be desulfurized when it first be-
comes operational.
A low-Btu gasification system has been designed for the utility
system of the El Paso project in New Mexico. * This design includes
desulfurization by one of the schemes discussed in this chapter.
Although high-Btu gasification is not a commercial reality, the
operating experience with oxygen-blown gasifiers is significant. The
Lurgi installation at Sasol, South Africa is similar to a high-Btu gas-
ification facility except that the final step involves Fischer-Tropsch
synthesis of oils, rather than methanation to pipeline gas. The Lurgi
gasifier at Westfield, Scotland has been operated with a slipstream
that was processed into high Btu-gas, but the detailed data on the
sulfur removal and recovery from this installation are not yet avail-
able. In addition to these operations, high-Btu gasification has been
designed for at least three large installations using the Lurgi gasifier.
A.dvanced technology is also being developed for high-Btu gas manu-
facture; two pilot plants for high-Btu gasification are now operational,
and two more are expected to be onstream in the next year. In con-
trast, the application of advanced technology to low-Btu gasification
has not been heavily pursued. When increased emphasis is placed
on low-Btu gas, the development of these processes should proceed
rapidly, using the experience gained in the advanced technology, high-
Btu gasification.
Booz, Allen & Hamilton Inc. Report No. 9075-015 to the
Environmental Protection Agency, Emissions from Processes
Producing Clean Fuels, March 1974.
V-2
-------
The impetus for the development of low-Btu gasification is sig-
nificantly less than that for high-Btu gasification. The development
of high-Btu gasification appears to be required for the continuing
viability of the gas utility companies. Although desirable from the
"emission and long-term efficiency standpoints, low-Btu gasification
is not equally vital to the electric utility industry.
1. THE PROBLEM OF DESULFURIZING LOW-BTU FUEL GAS
The problem of sulfur removal and recovery in the purification
of low-Btu utility gas can be directly compared to the sulfur emitted
when that gas is burned for fuel. As stated previously, the first low-
Btu gasification installation will permit the use of high sulfur coal
in an environmentally sound manner. When viewed as an integrated
three-stage process (gasification, purification and combustion), this
concept offers potential for the overall combustion of high-sulfur
coal in conformance with current standards existing for the direct
combustion of this coal. The coal is first treated with air and steam
to manufacture a low-Btu gas. This gas is then treated to remove a
significant portion of the sulfur, and combustion is completed by
burning the treated gas with air. The resulting emissions will be
less than the present standards for combustion of coal. It is noted
that for this purpose the complete removal of the sulfur is not required.
The gas must be clean enough so that the process is competitive with
stack gas desulfurization and can meet emission standards.
As discussed in Chapter II, the concentration of sulfur species
in low-Btu gas is greater than in stack gas, and the sulfur species
present are more reactive. Therefore, it is possible to desulfurize
fuel gas so that the resultant overall emissions, even with the ex-
pected loss of some sulfur in the recovery section, are much less than
the alternative of stack gas cleanup. The purpose of this chapter is to
indicate the practical degree of sulfur removal and recovery that can
be achieved today by low-Btu gasification, and to estimate the costs
associated with those removal processes.
The problem of sulfur removal in low-Btu gasification is sim-
pler than the comparable problem in high-Btu gasification. In the pro-
duction of high-Btu gas, essentially all of the sulfur must be removed
from the process gas stream to protect sensitive downstream catalysts.
Low-Btu gas, on the other hand, need not be completely desulfurized;
some sulfur may be left in the gas and still produce low emissions.
As described in the previous chapter, high removal of sulfur is
V-3
-------
counterproductive to high recovery of sulfur. In the case of low-Btu
gas, where high removal is not required, high recovery of the sulfur
removed may be expected. In addition, since the treatment of low-
Btu gas does not require the discharge of carbon dioxide, a potential,
loss of sulfur to this stream is not expected. Similarly, sulfur guards
are not required in low-Btu gas production, and the potential emissions
from this source are also avoided.
Although low-Btu gasification appears to be a promising approach
for meeting emission standards while still using high-sulfur coal, the
greatest benefit from this technique will be realized when combined-
cycle systems for power generation become economically attractive.
For this system, the water vapor and carbon dioxide in the process gas
stream should not be removed because they represent mass at tempera-
ture and pressure that can generate additional power in the gas turbine.
Ideally, the sulfur removal techniques employed in purification of low-
Btu gas streams should leave both the water vapor and carbon dioxide
in the gas stream for eventual utilization. Unfortunately, present tech-
niques for sulfur removal require that the gas stream be cooled and the
water vapor condensed. By using selective sulfur removal techniques,
most of the carbon dioxide can be left in the process gas stream. Not
only does selective desulfurization leave carbon dioxide in the gas
stream, but the cost of carbon dioxide removal is avoided. From an
economics standpoint, therefore, selective desulfurization is desirable
since it permits the utilization of the expansion energy of the carbon
dioxide in the product gas. With the advent of high-temperature desul-
furization (now being developed by Battelle-Northwest, IGT, U. S.
Bureau of Mines, and others), it may be possible to leave water vapor
in the system in future processes. Controversy exists over the merits
of high-temperature desulfurization, however. At present, develop-
ment and engineering evaluation of low-Btu gasification processes, in-
cluding heat recovery is needed to prove the potential value of high-
temperature desulfurization. For the typical 130 billion Btu/day
(32. 75 x 10^ kcal/day) low-Btu gasification facility (approximately
equivalent to a 1000 megawatt powerplant in a combined-cycle power
operation), the compression energy alone of the water vapor in the gas
is equivalent to about 20, 000 kilowatts. The recovery of this energy,
through high-temperature desulfurization, would increase the efficiency
and the economy of low-Btu gasification for electrical power genera-
tion.
V-4
-------
2. COST AND EFFECTIVENESS OF SULFUR CONTROL SCHEMES
APPLIED TO A TYPICAL LOW-BTU GAS STREAM
The hypothetical feed gas Composition for a typical low-Btu gasi-
fication facility was developed in Chapter II and presented in
Table n-6 for both high-sulfur and low-sulfur coal feeds. The flow
rates indicated are based upon a production of 130 x 109 Btu/day
(32. 75 x 10^ kcal/day). As indicated in a previous report prepared
for the EPA*, this gas production, including by-product steam,
is sufficient to fuel a nominal 1000 magawatt powerplant in future
combined-cycle streams.''' The gas compositions for the typi-
cal low-Btu gas streams consider both a high-sulfur and low-sulfur
coal as feedstock for the gasification system. As explained previously,
a different gas is expected for different sulfur-content coals, but the
composition developed in Chapter II depicts gas composition which
can be expected to evolve from gasification of a typical coal feed.
The energy produced is only about 50 percent of the product
energy of the high-Btu case.* According to the flow rates presented
in the previous chapter, the coal input to the process is approximately
40 percent of the coal required for the manufacture of high-Btu gas.
These relative rates must be considered when evaluating the sulfur
emissions discussed in the various low-Btu control schemes.
The sulfur content of the gas from the high-sulfur coal is
753 Ib-moles/hr (94.9 gm-moles/sec), approximately 50 percent of
the sulfur content in the high-Btu case. The gas contains 50 percent
of the sulfur from only 40 percent of the feedstock because of the
comparatively higher conversion efficiency in the low-Btu gas case.
The low-Btu gas facility requires no boilerhouse or separate CO2 off-
gases.§ The only other discharge streams containing sulfur are the
tar and oil streams that are by-products from some specific low-Btu
processes. Some sulfur is also bound into the ash leaving the gasifier.
Booz, Allen & Hamilton Inc. Report No. 9075-015 to the
Environmental Protection Agency, Emissions from Processes
Producing Clean Fuels, March 1974.
Note that if the fuel gas is fired under boilers, rather than in
combined-cycle operation, significantly more gas production
is required to generate 1000 MW of electricity.
/130xl09 Btu/day _ ,A
q
\250xlO Btu/day /
The energy requirements of the gasification facility are supplied
by the power generation section.
V-5
-------
After gasification, the process gas stream is assumed to exist
at 300 psia (21.1 kg/cm ). As discussed in Chapter II, the only pro-
cessing required between gasification and combustion is departicula-
tion and desulfurization. Because desulfurization requires cooling of
the gas to the operating temperature of the desulfurization system, the
process gas is assumed to exist at 125°F (52°C). Water has been
condensed and soluble oils, phenols, ammonia, and others, are as-
sumed to have been removed. In the schemes considered for high-
temperature desulfurization, the operating temperature is assumed
to be 1500°F (800°C), and the water vapor content will correspond to
the expected output of most gasifiers.
The disposition of sulfur among the various species is important
in estimating the overall effectiveness of desulfurizing low-Btu gas.
In this report, the ratio of carbonyl sulfide to hydrogen sulfide was
assumed to be fixed at the operating temperature and gas composition
of the typical gas if ier (defined by thermodynamic considerations).
According to the analysis of the Lurgi operation in El Paso, however,
the COS concentration in the output from the airblown gasifier may be
greater than that indicated by thermodynamic considerations alone.
In this analysis, about 4 percent of the total sulfur is assumed to
exist as carbonyl sulfide, a form not readily recoverable from the
process gas stream.
Many other sulfur species, such as carbon disulfide, organic
sulfides, mercaptans, and thiophenes may be present in effluents from
gasifiers that tend to produce quantities of tars and oils. For the pur-
pose of this analysis, it is assumed that these organic sulfur com-
pounds are recovered with the oils from the process or lost to the
process gas, causing an insignificant increase in the sulfur emissions
to the stack.
Three sulfur removal and recovery techniques were applied to
the low-Btu gas treated in this analysis (see Appendix to this chapter).
V-6
-------
(1) Systems 1 and 4, Selective Solvent System
Systems 1 and 4 are based upon similar selective solvent
systems for preferential extraction .of sulfur from the process
gas stream; they treat gas derived from a high-sulfur coal feed
and a low-sulfur coal feed, respectively. The relative sulfur
and carbon dioxide removal efficiencies are based on 1971 data
quoted by a process licensor. Those costs have been scaled to
the required production rate and converted to a mid-1973 basis
but do not reflect the unexpectedly rapid escalation of all costs
during that period to the present. For this system, the hydrogen
sulfide concentration in the process gas was reduced to 20 ppm,
and 50 percent of the carbonyl sulfide reported to the Glaus plant
feed. This design represents excellent sulfur recovery but the
costs are relatively high, particularly when compared to the
costs of sulfur removal for similar systems described for the
high-Btu gas cases. Part of the increased costs is ascribed to
the greater volume of process gas being treated in the absorption
columns, when compared to the high-Btu gas case.
In these solvent-based systems, nearly all of the water
and about 35 percent of the carbon dioxide are removed from the
process gas stream during treatment. These removals would
tend to upgrade the gas if it were to be combusted directly but
would detract from the gas if it were used as feed in a combined-
cycle system.
The available data were applied to System 4 using low-
sulfur coal. In this case, the fractions of sulfur and carbon
dioxide removal were maintained constant relative to System 1
which assumes a high-sulfur coal feed; therefore, the concen-
tration of sulfur in the acid-gas is low, slightly greater than
5 percent. For this operation, it was assumed that a modified
Glaus plant with condensing stages would be applicable. If the
analysis presented a higher ratio of sulfur to carbon dioxide in
the acid-gas, a more efficient Glaus plant operation would be
expected.
(2) Systems 2 and 5, Stretford Process
Systems 2 and 5 (for high- and low-sulfur coals, respec-
tively) are based on applying a Stretford process directly to the
process gas stream. In this case, the Stretford process is
V-7
-------
applicable because the partial pressure of carbon dioxide in the
gas stream is relatively low, about 25 psig (2. 8 kg/cm ). For
these analyses, the Stretford process was assumed to remove
the hydrogen sulfide but leave the carbonyl sulfide and other
forms of sulfur in the process gas. Direct application of the
projections of the Stretford process licensors suggests that the
final process gas may contain as little as 250 ppm total sulfur.
However, the Stretford system should remove the hydrogen sul-
fide, leaving the COS. In System 2, with high-sulfur coal, the
total sulfur concentration in the process gas is, in fact, greater
than 250 ppm. In contrast, System 5 with low-sulfur feedstock,
after removal of the hydrogen sulfide by the Stretford process,
results in a process gas shown to contain less than 250 ppm.
Although System 5 indicates excellent sulfur removal and re-
covery, the sulfur content of this process gas was increased to
250 ppm in the analysis section of this chapter to be in confor-
mance with the quotations of process licensors.
(3) Systems 3 and 6, High-Temperature Desulfurization
Systems 3 and 6 present the possible application of a high-
temperature sulfur removal process to a low-Btu stream. The
data were taken for the Battelle-Northwest process using molten
carbonates to extract the sulfur from the fuel gas. Published
data indicate 95-percent removal of the sulfur under these con-
ditions; this removal may be improved with further development
for pressure operation.
Systems 2 and 5 (assuming high- and low-sulfur feeds, respec-
tively) offer essentially complete recovery of the sulfur that is removed
from the low-Btu gas. The other systems, however, employ Glaus
processes for sulfur recovery from the acid-gas. In these cases, the
off-gas from the Glaus plant, after tail-gas treatment, is assumed to
contain 250 ppm total sulfur. As discussed in Chapter IV, the effi-
ciency of the Glaus plant may suffer following solvent-based systems.
The operation of the systems for cleanup of the Glaus tail-gas might be
adversely affected by the high carbon dioxide concentrations in the Glaus
feed. In particular, System 5, with about 95 percent CC>2 concentration
in the feed and low sulfur recoveries in the Glaus plant, may not per-
form according to expectations. Nevertheless, the performance of the
tail-gas processes was estimated to meet the expectations of most pro-
cess licensors (that the final off-gas contain 250 ppm total sulfur).
V-8
-------
The processing schemes described were applied to the hypotheti-
cal low-Btu gas streams in the control systems presented in the Appen-
dix to this chapter. These systems were selected because they were
selective for sulfur removal, leaving the majority of the carbon dioxide
(and in one case, water vapor) in the process gas stream. As previ-
ously mentioned, the preferred techniques for purification of low-Btu
gas streams will attempt to minimize the removal of these species,
because removal of water and carbon dioxide causes inefficiencies
in the overall process and adds to the cost of purification. Therefore,
many of the purification processes that were applicable for high-Btu
gas, where simultaneous removal of carbon dioxide is required, are
not applicable here. Nevertheless, these sulfur removal and recovery
techniques should be considered to determine if improved emissions
would result and to indicate the cost and/or performance penalties that
would accompany the improved emissions.
Qualitative conclusions on the effects of applying these sulfur
control techniques are summarized below:
Systems similar to System 1, System 2, and System 7 of
the high-Btu gas schemes will nonselectively remove a
large portion of the sulfur and carbon dioxide from the
process gas stream. In the case of high-sulfur coal, the
concentration of sulfur in the resulting acid-gas is about
8 percent. This sulfur concentration is too dilute to eco-
nomically utilize a Glaus process yet too high for econom-
ically selecting a Stretford process. If a modified Glaus
plant were used, perhaps with condensing stages and ex-
tensive tail-gas purification, the total sulfur discharge to
the atmosphere from the process would be about 1.5 tons*
daily. About 60 percent of this sulfur would be discharged
from the Glaus plant; the remainder would be in the com-
bustion gases vented to the stack. This discharge is a fac-
tor of 5 to 10 below the level of discharges anticipated for
the selective processes listed above. The penalties, how-
ever, are increased cost of equipment and operation for
carbon dioxide removal and a 10 percent loss in the com-
pression energy of the low-Btu gas. Compared to Sys-
tem 3, where water is not removed from the system, the
loss in compression energy is about 20 percent.
Short tons, reference footnote p. 1-4.
V-9
-------
If the output of the bulk, nonselective removal system,
described above, is passed through a Stretford unit for
sulfur recovery, the emissions will be defined by the type
of acid-gas removal process employed. If hot-carbonate
processing is employed, with assumed hydrolysis of the
carbonyl sulfide, the expected emissions will be identical
to the Glaus plant discussed above (because the assumed
output of the Stretford system is 250 ppm). However, if
bulk amine or solvent systems are used, the carbonyl sul-
fide is not hydrolized and will pass directly through the
Stretford system. In that case, the expected emissions
will be on the order of 12 tons* daily; similar to Scheme 2
above.
If low-Btu gas produced from low-sulfur coal is treated
nonselectively, the acid-gas will be too weak for Glaus
plant treatment, and the expected emissions from the over-
all process, including a Stretford facility, will be on the
order of 1. 5 tons* daily or about half the emissions from
the low-sulfur coal estimated in the case studies above.
The efficiency losses are similar to those discussed ear-
lier.
If either selective amine or selective carbonate process-
ing is used on the low-Btu gas, the carbonyl sulfide may
not be removed from the process gas. .These systems
were not included in the schemes studied because cost data
for low-Btu gas treatment have not yet been developed.
The expected emissions are similar to Scheme 2 and
Scheme 5 where all the carbonyl sulfide reports to the com-
bustion gas. In this example, the majority of the water is
lost from the process gas, but the carbon dioxide is not re-
moved and the process efficiency is similar to the other
selective processes.
In summary, of the sulfur removal and recovery tech-
niques that might be applied to low-Btu gas but not anal-
yzed in the cases studied, most techniques of treatment
will result in expected emissions that are similar to those
quoted in the schemes presented. In some specific
Short tons, reference footnote p. 1-4.
V-10
-------
processes, th'e expected emissions may be lower by a fac-
tor of 2 to 8, depending upon the sulfur content of the coal
feedstock. Processing schemes that will produce the re-
duced emissions, however, remove water vapor and car-
bon dioxide from the process gas stream and therefore
decrease the overall efficiency of the coal-to-electricity
process.
3. ANALYSIS OF RESULTS: LOW-BTU GAS STREAMS
Table V-l presents the total daily sulfur emissions (by source)
for a 130 billion Btu/day (32, 750 x 10 kcal/day) low-Btu gasification
facility. As discussed in a previous study*, this size was
selected to be equivalent to a future 1000 megawatt powerplant using
a combined-cycle operation. Table V-l presents the emissions from
both high-sulfur and low-sulfur coals, assuming treatment by three
alternative processing schemes. Also included in Table V-l are the
incremental capital requirements for the sulfur removal and recovery
equipment and the effect of this processing upon the gas costs, assum-
ing utility financing according to the factors derived by the Synthetic
Gas-Coal Task Force for the FPC. The cost data presented are
approximations based upon data for low-Btu gasification systems but
were derived from different sources, possibly with different estimat-
ing techniques, and have been extrapolated in some instances to meet
the guidelines set for this study.
For the high-sulfur coals, Scheme 1 and Scheme 2 (representing
current technology) indicate daily sulfur emissions of 6. 9 tonst and
11.9 tonst, calculated as elemental sulfur. These expected emis-
sions are of the same order of magnitude and within the constraints
and assumptions of the program, and are not considered to be signifi-
cantly different. A conservative engineering basis would dictate that the
higher of these two calculations should be used to project the expected
emissions. On this basis, the total emissions are approximately
equivalent to the quantity of organic sulfur present in the low-Btu
gas manufactured from high-sulfur coal.
System 3 is based upon high-temperature desulfurization of the
fuel gas. The data indicate that high-temperature desulfurization may
* Booz, Allen & Hamilton Inc. Report No. 9075-015 to the
Environmental Protection Agency, Emissions from Processes
Producing Clean Fuels, March 1974~!
t Short tons, reference footnote p. 1-4.
V-ll
-------
Table V-l
Expected Emissions From Low-Btu Gas Production and
Consumption, Compared to Direct Combustion of Coal
System No.
(High-Sulfur Coal)
1
2
3
(Low-Sulfur Coal)
4
5
6
Description
Light, selective
solvent
Stretford
High-temperature
desulfurization
Light, selective
solvent
Stretford
High-temperature
desulfurization
Incremental Incremental
Emissions -Short Tons'/Day Sulfur Capital .Gas Cost
Process Combustion Total investment ($10B) C/106 Btu C/106 kcal
0.5 6.4 6.9 25.6 15.0 59.5
11.9 11.9 15.1 10.4 41.3
0.8 14.0 14.8 25.2 13.7 54.4
0.3 2.0 2.3 . 19.2 12.7 50.4
3.0 3.0 5.4 4.1 16.3
0.2 3.3 3.5 8.0 4.9 19.4
Notes: 1 ton/day emissions = 0.015 Ib $/106 Btu; 0.028 kg/106 kcal
* short tons x 0.9072 = m tons
x 0.8929 = LT
When comparing the data reported here, the limitations discussed on pages 1-7, 8 and IV-2, 5 should be recognized.
not provide the same degree of purity in the fuel gas as conventional
approaches. If high-temperature desulfurization can permit the im-
proved efficiency of combined-cycle power generation, as expected
from some literature sources, the increase in emissions, on a Btu
basis, may be more than offset by the improved efficiency in generat-
ing the end product (electrical power).
When conventional sulfur removal techniques are applied to a
fuel gas manufactured from low-sulfur coal, the calculated emissions
are reduced significantly (to 2. 3-3.0 tons*/day). The example of
3. 0 tons*/day is based upon loss of all carbonyl sulfide in the process
gas to the combustion stack (as SO2). with nearly complete removal of
the hydrogen sulfide in the fuel gas. However, the design basis for
the Stretford process suggests that the treated gas should contain
250 ppm total sulfur. Calculations indicate emissions of only 2. 3 to
Short tons, reference footnote p. 1-4.
V-12
-------
3 tons-/day for low-sulfur coal, but quotations from process licensors
suggest that the treated fuel gas would contain 250 ppm total sulfur
that would report to the stack, after combustion, as sulfur dioxide.
Assuming 250 ppm total sulfur in the fuel gas amounts to 9 tons*/
day of sulfur emissions--the basis used to project the emissions in
Chapter VII—the calculated value for low-sulfur coals was included to
indicate the sulfur emissions that might be realized in future practice.
The costs of sulfur removal and recovery, as developed, indicate that
the cost of treatment may be about $0. 04/million Btu ($0.16/10 kcal)
for the low-sulfur schemes, and $0.10-$0.15/million Btu ($0. 40-
$0. 60/106 kcal) for the high-sulfur schemes.
The eventual primary application for low-Btu gas will probably
be in the generation of electric power by the combined-cycle route.
In this application, carbon dioxide (and water vapor) should not be re-
removed from the process gas during treatment because they increase
mass at pressure and temperature which can be expanded through gas
turbines. The sulfur removal schemes selected for Table VII-1 are
selective in recovering sulfur while leaving carbon dioxide in the process
gas stream. If nonselective processes were employed in this opera-
tion, which also remove the CO2, some techniques might be available
to permit better sulfur removal and recovery, although at some
expense to the overall process. The analysis in the previous section
indicates that the removal might be improved by a factor of 8 in the
case of the high-sulfur coal. Additional studies will be necessary to
more accurately evaluate the cost effectiveness of sulfur removal and
recovery for this emerging industry.
(1) Comparison to Alternative Uses of the Coal
Table V-2 presents the expected emissions from low-
Btu gasification and the expected emissions from the alternative
utilization of the coal by direct combustion (in conformance to
present Federal EPA New Source Performance Standards). The
first column presents the sulfur emitted as a function of the heat
content of the fuel that is consumed. Even in the case of high-
sulfur coal, the sulfur losses per million Btu of product gas are
about a factor of 3 lower than the alternative of direct combustion
Short tons, reference footnote p. 1-4.
V-13
-------
of the coal. Therefore, the primary short-term goal of low-Btu
gasification, that is, to consume high-sulfur coal in a manner
that is consistent with Federal standards for coal combustion
is expected to be met. With low-sulfur coal, the expected emis-
sions at 250 ppm sulfur content in the treated gas are a factor of
5 lower than direct combustion of the coal.
Table V-2
Expected Emissions From Low-Btu Gas Production
And Consumption, Compared to Direct Combustion of Coal
Low-Btu Gas
High-Sulfur Coal (4.5%)
Low-Sulfur Coal (0.9%)
Direct combustion of coal in
conformance with EPA Standards
Sulfur
lb/106Btu kg/106 kcal
0.18-0.22 0.32-0.40
(0.05) §-0.12* (0.09)§-0.22t
0.6 1.1
Ibt Sulfur/MW-hr
Fuel Combusted Under Boilers* Combined-Cycle**
1.7-2.1 1-1.25.
(0.4)§-1.1t (0.25) §-0.61*
5.5
* at 37.5% efficiency
t Ib x 0.4536 = kg
* Expected emissions including 250 ppm sulfur compounds in 150 Btu/ft3 (1335 kcal/m3) gas
§ Calculated emissions based on direct interpretation of the data presented in this report.
** At 42 percent overall efficiency, including utilization of waste heat.
The 'second two columns of Table V-2 present the sulfur
emissions in terms of the units of final energy generated. These
data are presented to indicate the potential improvement in total
overall emissions when low-Btu gasification and combined-cycle
power generation have been developed.
(2) Overview of Low-Btu Process Desulfurization
The study of sulfur removal and recovery from processes
that manufacture low-Btu gas from coal is subject to the same
guidelines that restricted the evaluation of high-sulfur coal. In
addition, the development of low-Btu gasification, using modern
technology, lags behind the development of high-Btu gasification.
V-14
-------
As noted in Chapter IV, the sulfur species causing the most
difficulty is carbonyl sulfide. Sulfur forms such as carbon disul-
fide and organic species may also be difficult to convert to the
elemental form, but these sulfur types are not expected in signi-
ficant concentrations in most low-Btu gases. The total sulfur
emissions from the manufacture and combustion of low-Btu gas
can be expected to be equivalent to the sulfur content of the raw
gas of species other than I^S, or equivalent to 250 ppm total
monatomic sulfur in the low-Btu gas, whichever is greater.
V-15
-------
APPENDIX B
-------
APPENDIX B(l)
SOUR ^ .
GAS *
SELECTIVE
SOLVENT-
LIGHT
1
1
REGENERATION
CLAUS
1
BY-PRC
SULFU
,®
PLANT
^ - TREATED
P GAS
* I
J
CLAUSTAIL-
GAS TREAT.
*
® •
JDUCT
R
STREAM No.
DESCRIPTION
TEMP, °F (°C)
pficcc PSia
PRESS' (kg/cm2)
Ib-moles/hr*
CO
H?
CH4
NH3
N2
H20
C02
H2S
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
125(521
300 (21.1)
17,540
13.150
4,380
-
43,840
570
8,770
723
30
-
753
89,003
2
TREATED
GAS
100 138)
290 120.41
17,538
13,148
4,370
—
43,835
—
5,700
1.7
(20 ppm)
15»
—
16.7
84,608
3
H2S-RICH
ACID GAS
100 138)
20 (1.4)
2
2
10
5
-
3,070
721.3
IS'
-
736.3
3,825
4
CLAUS TAIL
GAS
325(163)
17 (1.2)
1,473
743
3,097
unk
unk
unk
73.6'
5,387
5
OFF-GAS
120(49)
15 (1.1)
1,473
743
3,097
unk
unk .
unk
1.3
(250 ppm)
5,314
6
BY-PRODUCT
SULFUR
3001149)
15 (1.1)
735
735
283 tons/day]
735
• Ib-moles/hr x 0.126 = gm-moles/sec.
t 50% of COS to®.
i 90% Claus sfficiencv.
Figure B-l
SELECTIVE SOLVENT AND CLAUS PROCESS
-------
APPENDIX B(2)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF LOW-BTU GAS
FROM HIGH SULFUR COAL
System No. 1:
A selective, solvent-based system of light severity
will preferentially remove H S from the process gas
stream for satisfactory acid-gas removal. The H S-rich
acid gas from the selective system is processed By a
Glaus plant, followed by Claus tail gas treatment.
(Fig. B-l)
Acid Gas Removal
Selective: A solvent-based system of light severity will recover 99.8% of the
H2S and 50% of the COS, together with 35.0% of the C02, producing an H2S-rich
acid gas of 19.2% sulfur concentration suitable for feed to a Claus plant. From
Fig. B-l, the total acid gas removed is 3806 Ib-moles/hr (480 gm-moles/sec) or
34.6 x 106 ft3/day (980 x 103 m3/day).
Estimating Bases:
Component
Investment Cost
Light Solvent Selective
Steam Required
Cooling Duty
Power Req'd
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
$350/103 ft3/day
28.9 Ib/lb-mole
acid gas removed
2.93 gpm/lb-mole
acid gas removed
2.1 kW/lb-mole
acid gas removed
$1/1000 Ibs
$0.03/1000 gal
Basis* .
$2/10 Btu
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
Claus Plant: Recovery of elemental sulfur from streams with relatively high
H2S concentration (Fig. B-l), 19% in this case). With modification, COS is
also converted to elemental sulfur. The efficiency of the Claus plant is de-
preciated to 90% following a solvent-based acid gas removal system. From
Fig. B-l, the sulfur recovery is 252.5 LT/day, including sulfur values re-
covered in tail gas treatment.
Costs calculated on a mid-1974 basis.
-------
APPENDIX B(3)
Estimating Bases:
Component
Investment Cost
Estimated Value
$1.14 X 106/100 LT/day
(Max capacity 350 LT/day
for each train)
0.8 Power Factor
for capacity>100 LT/day
escalated by 25% From
Mid-1971 to Mid-1974.
Basis
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-25
Operating Costs $1.50/LT
(Including utilities,
catalysts, chemicals, etc.)
Derived from Process
Engineering for Tail Gas,
July 1973 and some other
articles
Claus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Claus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content '
Component
Investment Cost
Operating Cost
Estimated Value
Equal to Claus plant
cost
Equal to Claus plant
cost
Basis
From article "Add On Process
Slashes Claus Tail Gas
Pollution," Chemical
Engineering, Dec. 13, 1971
:counting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
-------
APPENDIX B(4)
Table B-l - LOW BTU GAS-HIGH SULFUR COAL
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 1
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Glaus Sulfur Recovery
Glaus Tail Gas Cleanup
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
$10
12.1
3.0
3.0
18.1
2.7
20.8
0.8
3.5
0.5
$25.6
Incremental Annual Operating Costs
Component
Labor
Direct Operating Labor (5 men/shift @ $5.0/hr, 8304 hrs)
Maintenance Labor
Supervisory
Administrative and General Overhead
Other Direct Costs
Light Solvent Steam
Light Solvent Power
Light Solvent Cooling Water
Light Solvent Product Loss
Claus Utilities and Chemicals
Claus Tail Gas Utilities and Chemicals
Operating Supplies
Maintenance Supplies
Local Taxes and Insurance
Incremental Gross Operating Cost
By-Product Sulfur Credit
Incremental Net Operating Cost
Incremental Annual Revenue Required
Annual Gas Production, 10 Btu
Incremental Gas Cost Due to Sulfur Removal,
Btu
$1000
207.6
312.0
77.9
358.5
867.
945.
158.3
68.1
124.4
124.4
62.3
312.0
561.6
4179.6
-629.5
3350.1
6426.9
42772.2
15.0
-------
APPENDIX B(5)
©
©
STREAM No.
DESCRIPTION
TEMP, °F (°C)
PRESS' |k&
Ib-moles/hr*
CO
H;
CH..
NH,
Nj
H;0
CO;, .
HjS
COS
S
TOTAL "5"
TOTAL
1
SOUR GAS
125 (521
300 (21.1)
17,540
13,150
4,380
-
43,840
570
8,770
723
30
--
753
89,003
2
TREATED
GAS
125(52)
290 (20.4)
17,536
13,145
4,375
-
43,830
570
8,720
0.9
(10 ppm)
30
-
30.9
88,206
3
OFF-
GAS
100 (38)
20 (1.4)
4
5
5
-
10
—
50
74
4
ar.pRODUCT
SULFUR
300 (149)
15 (1.1)
722.1
722.1
278 tons/day
722
' Ib-moles/hr x 0.126 = gm-moles/sec.
Figure B-2
STRETFORD PROCESS, HIGH-SULFUR FEED
-------
APPENDIX B(6)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF LOW-BTU GAS
FROM HIGH-SULFUR COAL
System No. 2: A Stretford Process for selective recovery of
sulfur from the H S in the sour gas (Fig. B-2)
Sulfur Recovery
The Stretford process is used here for recovery of elemental sulfur from sour
gas with relatively low H2S concentration (From Fig. B-2, 0.8% in this case).
The Stretford process does not remove COS from its feed gas. It will produce
an effluent with 250 ppm total sulfur concentration or containing all the .feed
COS plus 10 ppm H2S, whichever is greater. From Fig. B-2, the sulfur recovered
in the Stretford plant is 248 LT/day.
Estimating Bases; . .
Component Estimated Value Basis*
Investment Cost $5.1 X 10 /100 LT/day ' Communication With
(For capacity>100 LT/day Process Licensor
Power Factor = 0.9, for
<100 LT/day Power
Factor = 0.7)
Steam 1473 Ib/LT Communication With
Process Licensor
Power 1353 kW/LT Communication With
Process Licensor
Process Water 1026 gal/LT Communication With
Process Licensor
Chemicals Cost $4/LT . Communication With
Process Licensor
Steam Cost $1/1000 LB Estimated for This Report
_Power Cost 1.5£/kW Estimated for This Report
Process Water 30C/1000 gal Estimated for This Report
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
APPENDIX B(7)
Table B-2 - LOW BTU GAS-HIGH SULFUR COAL
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 2
(Stretford)
Incremental Investment
Component $10
Stretford Sulfur Recovery 10.5
Subtotal Incremental Plant Investment 10.5
Project Contingency 1. 6
Total Incremental Plant Investment 12.1
Start-up Costs 0.7
Interest During Construction 2.0
Working Capital 0. 3
Total Incremental Capital Requirement $15.1
Incremental Annual Operating Costs
Component $1000
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs) 207.6
Maintenance Labor 181.5
Supervisory 58.4
Administrative and General Overhead 268.5
Other Direct Costs.
Stretford Steam 120.0
Stretford Power 1653.4
Stretford Process Water 25.1
Stretford Chemicals 325.9
Stretford Losses 47.6
Operating Supplies 62.3
Maintenance Supplies .. 181.5
Local Taxes and Insurance 326.7
Incremental Gross Operating Cost 3458.5
By-Product Sulfur Credit —814.7
Incremental Net Operating Cost 2643.8
Incremental Annual Revenue Required 4458.7
Annual Gas Production, 10 Btu 42772.2
Incremental Gas Cost Due to Sulfur Removal,
-------
APPENDIX B(8)
©
©
OFF-
GAS
CLAUS TAIL-
GAS TREAT.
1
©
©
BY-PRODUCT
SULFUR
STREAM No.
DESCRIPTION
TEMP, °F (°C)
PRESS'(k&
Ib-moles/hr*
CO
Hj
CH4
NH3
N?
H20
CO;
H2S
COS
S
TOTAL "5"
TOTAL
1
SOUR GAS
1,500 18151
300 (21.1)
17,540
13,150
4,380
10
43,840
10,931
8,770
723
30
--
753
99,374
2
TREATED
GAS
1,500 (815)
290 (20.4)
17,540
13,150
4,380
10
43,840
11,613
9,515
35
1.5
—
36.5
100,090
3
HjS-RICH
ACID GAS
unk
20 (1.4)
6,449
716.5
—
—
716.5'
7,165
4
CLAUS TAIL
GAS
325 (163)
17 (1.2)
1,348
717
6,449
unk
unk
unit
71.7'
8,586
5
OFF-GAS
125 (52
15 (1.1)
1,348
717
6,449
unk
unk
unk
2.1
(250 ppm)
8,516
6
BY-PRODUCT
SULFUR
300 (149)
15 (1.1)
714.4
714.4
275 tons/dox)
714
* Ib-moles/hr x 0.126 = gm-moles/sec.
t 95% efficiency 'in high-temperature desulfurization assumed.
i 90% Glaus efficiency.
Figure B-3
HIGH-TEMPERATURE DESULFURIZATION, HIGH-SULFUR FEED
-------
APPENDIX B(9)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF LOW-BTU GAS
FROM HIGH-SULFUR COAL
System No. 3:
Novel high temperature desulfurization for selective
recovery of sulfur in fuel gas, followed by Claus
treatment.
Sulfur Removal
Several processes are under development to treat fuel gas at elevated
temperature for sulfur removal. A sulfur removal efficiency of 95%
was estimated for the Battelle-Northwest process according to data
in the OCR Annual Report. Tlio sulfur concentration is o.o^scted to be
about 10% in the regenerated off-gas.
Estimating Bases:
Component
Investment Cost
Estimated Value
4.6 X 106/100 LT
per day scale-up
factor =0.8
Operating Cost / $6000 Annually per
(including utilities, LT/day
catalysts, chemicals, etc.)
Basis
Published data on costs of
high temperature desulfuri-
zation
Published data on costs of
high temperature desulfuri-
zation
Sulfur Recovery
Claus Plant: Recovery of elemental sulfur from streams with relatively high
H2S concentration (Fig. B-3, 10% in this case). With modification, COS is
also converted to elemental sulfur. From. Fig. B-3, the sulfur recovery is
245.4 LT/day, including sulfur values recovered in tail gas treatment.
Estimating Bases:
Component
Investment Cost
Estimated Value
$1.44 X 106/100 LT/day
(Max capacity 350 LT/day
for each train)
0.8 Power Factor
for capacity> 100 LT/day
escalated by 25% From
Mid-1971 to Mid-1974.
Operating Costs $1.50/LT
(Including utilities,
catalysts,, chemicals, etc.)
Basis
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-25
Derived from Process
Engineering for Tail Gas,
July 1973 and some other
articles
-------
APPENDIX B(10)
Glaus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Glaus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content
Component Estimated Value Basis
Investment Cost Equal to Glaus plant . From article "Add On Process
cost Slashes Glaus Tail Gas
Pollution," Chemical
Engineering, Dec. 13, 1971
Operating Cost Equal to Glaus plant
cost
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
-------
TABLE B-3
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 3
APPENDIX B(ll)
Incremental Investment
Component
High Temperature Process For Acid-Gas Removal
Claus Sulfur Recovery
Glaus Tail Gas Cleanup
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
$10
9.5
4.2
4.2
17.9
2.7
20.6
0.7
3.5
0.4
$25.2
Component
Incremental Annual Operating Costs
$1000
Labor
Direct Operating Labor (5 men/shift @ $5.0/hr, 8304 hrs) 207.6
Maintenance Labor 309.0
Supervisory 77.5
Administrative and General Overhead 356.5
Other Direct Costs
Claus Utilities and Chemicals 120.9
Claus Tail Gas Utilities and Chemicals 120.9
Acid Gas Process Utilities and Chemicals 1500.0
Operating Supplies 62.3
Maintenance Supplies 309.0
Local Taxes and Insurance 556.2
Incremental Gross Operating Cost 3619.9
By-Product Sulfur Credit —806.1
Incremental Net Operating Cost 2813.8
Incremental Annual Revenue Required 5840.7
Annual Gas Production, 10 Btu 42772.2
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu 13.7
-------
APPENDIX B(12)
SOUR ^ _
GAS *
SELE
SOLV
LIGH
CTIVE
r
.
REGENERATION
,® .
CLAUS PLANT
BY. PR
SULFU
^ TREATED
®
iUr-K
GAS
CLAUS TAIL- ]
GAS TREAT.
\
®
3DUCT
R
STREAM No.
DESCRIPTION
TEMP, °F (°C)
PRESS^cm*>
' 'b-moles/hr*
CO
Hj
CH4
NH3
N2
HjO
C03
H,S
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
125 152)
300 (21.1)
17,540
13,150
4,380
—
43,840
570
8,770
173
7
--
180
88,430
2
TREATED
GAS
100 138)
290 (20.41
17,538
13,148
4,370
43,835
- "
5,700
1.7
(20 ppm)
3.5 1
--
5.2
84,596
3
H3S-RICH
ACID GAS
100 (38)
20 (1.4)
2
2
10
5
—
3,070
171.3
3.5 t
-
174.8
3,254
4
CLAUS TAIL
GAS .
250 1121)
17 (1.2)
417
193
3,086
Unk
unk
unlc '
28*
3,724
5
OFF-GAS
120 (49)
15 (1.11
417
193
3,086
0.9
,_ (250 ppm)
3,697
6
BY-PRODUCT
SULFUR
200 (93)
15(1.1)
173.9
173.9
66.9 tons/day
174.8
* Ib-moles/hr x 0.126 = gm-moles/sec.
t 50% of COS to®.
* 84% Glaus efficiency for low sulfur stream.
Figure B-4
SELECTIVE SOLVENT AND CLAUS PROCESS
-------
APPENDIX B(13)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF LOW-BTU GAS
FROM LOW SULFUR COAL
System No. 4:
A selective, solvent-based system of light severity
will preferentially remove H S from the process gas
stream for satisfactory acid-gas removal. The H S-rich
acid gas from the selective system is processed by a
Claus plant, followed by Glaus tail gas treatment.
(Fig. B-4)
Acid Gas Removal
Selective: A solvent-based system of light severity will recover 99.0% of the
H2S and 50% of the COS, together with 35% of the CO2, producing an H2S-rich
acid gas of 5.4% sulfur concentration suitable for feed to a modified Claus
plant. From Fig. B-4, the total acid gas removed -is 3245 Ib-moles/hr
(408.9 gm-moles/sec) or 29.6 x 106 ft /day (838 x 10 m /day).
Estimating Bases:
Component
Investment Cost
Light Solvent Selective
Steam Required
Cooling Duty
Power Req'd
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
$350/103 ft3/day
28.9 Ib/lb-mole
acid gas removed
2.93 gpm/lb-mole
acid gas removed
2.1 kW/lb-mole
acid gas removed
$1/1000 Ibs
$0.03/1000 gal
Basis*
$2/10 Btu
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
Modified Claus Plant: Recovery of elemental sulfur from streams with
relatively moderate H_S concentration (Fig. B-4, 5.4% in this case).
With modification, COS is also converted to elemental sulfur. The effi-
ciency of the Claus plant is depreciated to 84% following a solvent-
based acid gas removal system and because of the low inlet sulfur con-
centration. From Fig. B-4, the sulfur recovery is 59.7 LT/day, including
sulfur values recovered in tail gas treatment.
Costs calculated on a mid-1974 basis.
-------
APPENDIX B(14)
Estimating Bases:
Component
Investment Cost
Estimated Value
$1.74 X 106/100 LT/day
(Max capacity 350 LT/day
for each train)
0.6 Power Factor
for capacity<100 LT/day
escalated by 25% From
Mid-1971 to Mid-1974.
Operating Costs $1.50/LT
(Including utilities,
catalysts, chemicals, etc.)
Basis
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task. Force
Report, April 1973, Page AI-25
Derived from Process
Engineering for Tail Gas,
July 1973 and some other
articles
Claus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Claus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content
Component
Investment Cost
Operating Cost
Estimated Value
Equal to Claus plant
cost
Equal to Claus plant
cost
Basis
From article "Add On Process
Slashes Claus Tail Gas
Pollution," Chemical
Engineering, Dec. 13, 1971
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
.the EPA. '
-------
Table B-4 — LOW BTU GAS-LOW SULFUR COAL
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 4
APPENDIX B(15)
Incremental Investment
Component
Light Solvent Process For Acid-Gas Removal
Claus Sulfur Recovery
Glaus Tail Gas Cleanup .
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
$10
10.3
1.6
1.6
13.5
2.0
25.5
0.7
2.6
0.4
19.2
Component
Incremental Annual Operating Costs
$1000
Labor
Direct Operating Labor (5 men/shift @ $5.0/hr, 8304 hrs) 207.6
Maintenance Labor 232.5
Supervisory 66.0
Administrative and General Overhead 303.7
Other Direct Costs
Light Solvent Steam 739.3
. Light Solvent Power 805.8
Light Solvent Cooling Water 134.9
Light Solvent Product Loss 68.1
Claus Utilities and Chemicals 29.4
Claus Tail Gas Utilities and Chemicals 29.4
Operating Supplies 62.3
Maintenance Supplies 232.5
Local Taxes and Insurance 418.5
Incremental Gross Operating Cost 3330.0
By-Product Sulfur Credit —196.1
Incremental Net Operating Cost 3133.9
Incremental Annual Revenue Required 5442.0
Annual Gas Production, 10 Btu 42772.2
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu . 12.7
-------
APPENDIX B(16)
©
©
STREAM No.
DESCRIPTION
TEMP, °F (°CI
"RESS'<«
Ib-moles/hr*
CO
Hj
CH,
NH3
Nj
H;0
COj
H2S
COS
s
TOTAL "S"
TOTAL
1
SOUR GAS
125(52)
300 121.1)
17,540
13,150
4,380
-
43,840
570
8.770
173
7
—
180
88,430
2
TREATED
GAS
125 (52)
290 (20.4)
17,536
13,145
4,375
-
43,830
570
8,720
0.9
(10 ppm)
7
—
7.9
88,184
3
OFF-
GAS
100 (38)
20 (1.4)
4
5
• 5
10
—
50
-
—
-
—
74
4
BY-PRODUCT
SULFUR
300 (1491
15 (1.1)
172.1
172.1
66.2 tons/day
172
' Ib-moles/hr x 0,126 = gm-moles/sec.
Figure B-5
STRATFORD PROCESS - LOW SULFUR FEED
-------
APPENDIX B(17)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF LOW-BTU GAS
FROM LOW-SULFUR COAL
System No. 5:
A Stretford Process for selective recovery of
sulfur from the H S in the sour gas (Fig. B-5)
Sulfur Recovery
The Stretford process is used here for recovery of elemental sulfur from sour gas
with relatively low H2S concentration (From Fig. B-5, 0.2% in this case). The
Stretford process does not remove COS from its feed gas. It will produce an
effluent containing all the feed COS plus 10 ppm H2S. From Fig. B-5, the sulfur
recovered in the Stretford plant is 59.1 LT/day.
Estimating Bases;
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Estimated Value
$5.1 X 106/100 LT/day
(For capacity> 100 LT/day
Power Factor = 0.9, for
<100 LT/day Power
Factor = 0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 LB
1.5«/kW
30C/1000 gal
Basis*
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
Accounting Method
.The accounting method and financial factors used in this analysis were
taken from the FPC Task Force Report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
Costs calculated on a mid-1974 basis.
-------
Table B-5 — LOW BTU GAS-LOW SULFUR COAL
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 5
(Stretford)
APPENDIX B(18)
Incremental Investment
Component
Stretford Sulfur Recovery
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
$10
3.7
3.7
0.6
4.3
0.3
0.7
0.1
$ 5.4
Component
Incremental Annual Operating Costs
$1000
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs) 207.6
Maintenance Labor 64.5
Supervisory 40.8
Administrative and General Overhead 187.7
Other Direct Costs
Stretford Steam 28.6
Stretford Power 394.0
Stretford Process Water . 6.0
Stretford Chemicals 77.7
Stretford Losses 47.6
Operating Supplies 62.3
Maintenance Supplies 64.5
Local Taxes and Insurance 116.1
Incremental Gross Operating Cost 1297.4
By-Product Sulfur Credit —194.1
Incremental Net Operating Cost 1103.3
Incremental Annual Revenue Required 1752.2
Annual Gas Production, 10 Btu 42772.2
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu 4.1
-------
APPENDIX B(19)
©
©
TREATED
GAS
STREAM No.
DESCRIPTION
TEMP, °F (°C)
^ss.(k&
Ib-moles/hr"
CO
H:,
CHj
NH3
N?
H20
C02
H2S
COS
S
TOTAL "S"
TOTAL
1
SOUR GAS
125 (52)
300 (21.1)
17,540
13.150
4,380
10
43.840
10,931
8,770
173
7
-
180
98,801
2
TREATED
GAS
1,500 1815)
290 (20.4)
17,540
13,150
4,380
10
43,840
11,016
8,948
8.4
'--
8.7
98,973
3
HjS-RICH
ACID GAS
unk
2011.4)
1,542
171.3
unk
-
171.3'
1,713
4
CLAUS TAIL
GAS
325 (163)
17 (1.2)
322
171
1,542
unlc
unk
unk .
17.1'
2,052 .
5
OFF-GAS
125 (52)
15 (1.1)
322
171
1,542
unk
unk
unk
0.5'
(250 ppm)
2,035
6
BY-PRODUCT
SULFUR
300 (1491
15(1.1)
170.8
170.8
65.7 tons 'doy
170.8
* Ib-moles/hr x 0.126 = gm-moles/sec.
t 95% efficiency in high-temperature desulfurization assumed.
i 90% Glaus efficiency.
Figure B-6
HIGH-TEMPERATURE DESULFURIZATION, LOW-SULFUR FEED
-------
APPENDIX B(20)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PRODUCTION OF LOW-BTU GAS
FROM LOW-SULFUR COAL
System No. 6:
Novel high temperature desulfurization for selective
recovery of sulfur in fuel gas, followed by Claus
treatment.
Sulfur Removal
Several processes are under development to treat fuel gas at elevated
temperature for sulfur removal. A sulfur removal efficiency of 95%
was estimated for the Battelle-Northwest process according to data
in the OCR Annual Report. The sulfur concentration is expected to be
about 10% in the regenerated off-gas.
Estimating Bases:
Component
Investment Cost
Estimated Value
4.6 X 106/100 LT
per day scale-up
factor =0.8
Operating Cost $6000 Annually per
(including utilities, LT/day
catalysts, chemicals, etc.)
Basis
Published data on costs of
high temperature desulfuri-
zation
Published data on costs of
high temperature desulfuri-
zation
Sulfur Recovery
Claus Plant: Recovery of elemental sulfur from streams with relatively high
H2S concentration (Fig. B-6, 10% in this case). With modification, COS is
also converted to elemental sulfur. The efficiency of the Claus plant is de-
preciated to 90% following a solvent-based acid gas removal system. From
Fig. B-6, the sulfur recovery is 58.7 LT/day, including sulfur values recovered
in tail gas treatment.
Estimating Bases;
Component
Investment Cost
Estimated Value
$1.44 X 106/100 LT/day
(Max capacity 350 LT/day
for each train)
0.6 Power Factor
for capacity<100 LT/day
escalated by 25% From
Mid-1971 to Mid-1974.
Operating Costs $1.50/LT
(Including utilities,
catalysts, chemicals, etc.)
Basis
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-;
Derived from Process
Engineering for Tail Gas,
July 1973 and some other
articles
-------
APPENDIX B(21)
Glaus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Glaus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content
Component Estimated Value Basis
Investment Cost Equal to the Glaus From article "Add On Process
Plant Cost Slashes Claus Tail Gas
Pollution," Chemical
Engineering, Dec. 13, 1971
Operating Cost Equal to the Claus
Plant Cost
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force Report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA.
-------
APPENDIX B(22)
Table B-6
SUMMARY: INCREMENTAL INVESTMENT AND
x OPERATING COSTS SYSTEM NO. 6
Incremental Investment
Component
High Temperature Process For Acid-Gas Removal
Glaus Sulfur Recovery
Claus Tail Gas Cleanup
Subtotal Incremental Plant Investment
Project Contingency
Total Incremental Plant Investment
Start-up Costs
Interest During Construction
Working Capital
Total Incremental Capital Requirement
$10
3.0
1.3
1.3
5.6
0.8
6.4
0.3
1.1
0.2
$ 8.0
Component
Incremental Annual Operating Costs
$1000
Labor
Direct Operating Labor (5 men/shift @ $5.0/hr, 8304 hrs) 207.6
Maintenance Labor 96.0
Supervisory 45.5
Administrative and General Overhead 209.5
Other Direct Costs
Claus Utilities and Chemicals 28.9
Claus Tail Gas Utilities and Chemicals 28.9
Acid Gas Process Utilities and Chemicals 360.0
Operating Supplies 62.3
Maintenance Supplies 96.0
Local Taxes and Insurance 172.8
Incremental Gross Operating Cost 1307.5
By-Product Sulfur Credit —192.8
Incremental Net Operating Cost 1114.7
Incremental Annual Revenue Required 2077.1
Annual Gas Production, 10 Btu 42772.2
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu 4.9
-------
VI. SULFUR REMOVAL AND RECOVERY
FOR PYROLYSIS GASES
-------
VI. SULFUR REMOVAL AND RECOVERY
FOR PYROLYSIS GASES
The third type of gas considered in this study is a reducing gas
of the kind that would be manufactured in a typical pyrolysis opera-
tion. Pyrolysis is the process for chemical decomposition brought
about by the action of heat, considered to occur in a closed system
without the addition of either oxidizing or reducing gases. Examples
of pyrolysis are sometimes called carbonization, destructive distil-
lation, thermal cracking, or retorting.
A "hypothetical" pyrolysis gas was presented in Chapter II.
As indicated, an extreme range of compositions has been reported
in the literature for these gases. The hypothetical gas stream pre-
sented in this report (Table II-8) is representative of a typical case
to indicate the types of treatment that might be used and the degree
of sulfur removal that is obtainable. For a specific gas stream de-
rived from a specific feed, a separate analysis should be performed.
The basis for the typical pyrolysis gas was a COED-type pyrol-
ysis process producing 50, 000 barrels per day of a syncrude. The
gas from this process exists at low pressure, assumed at 18 psia
(1. 27 kg/cm2), and a temperature of 100°F (38°C) after water-washing
to remove the higher molecular weight oils.
The production rate of the facility manufacturing this gas is rela-
tively large compared to that of other processes described in this re-
port. The coal feed rate to the facility is approximately triple the
amount of feed to the high-Btu gas plant, and 7. 5 times the coal feed
rate to the low-Btu gas facility. Due to the relatively high heating
value of this gas, approximately 450 to 500 Btu/ft3 (4000-4500 kcal/
m ), the heat content of this process gas stream is approximately
240 billion Btu/day (60 x 109 kcal/day) -- approximately the same flow
as in the high-Btu gas facility. These relative size relationships
should be considered when evaluating the respective emissions from
these facilities.
Table II-7 indicates that the sulfur content of typical pyrolysis
gases varies from 0. 1 percent to more than 10 percent, depending
VI-1
-------
upon the system employed. The sulfur content of the typical pyrolysis
gas was assumed at 2 percent by volume. The effect of varying this
sulfur concentration is presented in the analysis section of this chap-
ter.
The disposition of sulfur among the various species has been
estimated on a thermodynamic basis only. The quantity of carbonyl
.sulfide presented in the fuel gas is based on an equilibrium concen-
tration at a typical pyrolysis temperature, 1000°F (about 550°C).
This carbonyl sulfide concentration may vary from equilibrium con-
centrations in pyrolysis gases where relatively low temperatures
are present and reaction rates relatively slow. Although higher
quantities of organic-sulfur compounds are expected in processes
that form large amounts of tars and oils, such as pyrolysis proces-
ses, the existence of these organic-sulfide compounds, estimated
on a thermodynamic basis, is assumed to be minimal. This basis
was adopted because the majority of these materials will be washed
into the product tars and oils for eventual recovery in the refinery
section of the facility and will not appear in the pyrolysis off-gas.
Should these compounds occur, however, they are expected to exist
in small quantities and report either to the elemental sulfur stream
or to the combustion stack as sulfur dioxide.
1. BASES OF ANALYSIS FOR THE PYROLYSIS GAS STREAM
AND APPLICABILITY OF CONTROL TECHNIQUES
With respect to sulfur removal, the distinguishing feature of
the hypothetical pyrolysis gas is the low pressure at which it is
available. Generally, solvent-based and hot-carbonate systems
would not be applied to treat streams having low operating pressures
because insufficient pressure differential is available between the
absorber and regenerator resulting in uneconomical operation. For
conventional processing, therefore, the choice is limited to amines
for, acid-gas removal, followed by a Glaus plant for sulfur recovery.
A nonconventional system may also be applicable to direct recovery
of the sulfur by a Stretford system. These two options were applied
to the pyrolysis gas in the schemes studied in this chapter.
The two schemes presented are based upon those discussed in
the more extensive study on high-Btu gas purification. The same
concepts of sulfur removal and recovery apply. In the pyrolysis gas
case, however, it has been assumed that the treated gas would be
VI-2
-------
consumed onsite for power generation. Therefore, complete removal
of sulfur from the gas is not required. The gas must be purified enough
to be competitive environmentally with the direct combustion of coal,
according to present Federal EPA New Source Performance Standards.
Any improvement of emissions over those expected from coal combustion
is an environmental benefit for using this energy source.
The combustion of the pyrolysis off-gas might be deferred until
later in the overall process. Most of the systems that produce a
pyrolysis off-gas are directed at producing a hydrocarbon liquid
(syncrude) from coal as the primary product. This hydrocarbon
liquid will require hydrotreating for upgrading, and the pyrolysis
off-gas, perhaps after shifting with steam to minimize the carbon
monoxide concentration, would contain significant hydrogen for this
purpose. The principles involved in treating the gas after hydro-
treatment would be similar to those discussed.
Bulk treatment by amines will simultaneously remove the sulfur
and carbon dioxide concentrations of the treated gas to very low levels.
For the hypothetical pyrolysis off-gas, the total sulfur concentration
in the combined acid-gas would be about 8. 7 percent. This concen-
tration is relatively weak for operation of a conventional Claus fa-
cility; however, a modified Claus plant could be designed to process
this acid-gas stream. The expected concentration of the sulfur in
the Claus tail-gas, after purification, is 250 ppm. This emission
point is the major source of the sulfur emitted from the amine pro-
cessing scheme. The majority of the carbonyl sulfide in the raw
pyrolysis gas is removed to the acid-gas and then recovered as ele-
mental sulfur in the Claus plant.
A more economical treatment scheme at this sulfur concentra-
tion might employ a selective amine process of a type that .is now
commercialized (e. g., TEA, MDEA, DIPA). In this case, the
majority of the sulfur would be removed from the pyrolysis gas,
along with only a portion of the carbon dioxide. The resulting acid-
gas would have a high sulfur concentration and would be a more
satisfactory feed for a Claus plant. The total quantity of carbon
dioxide in this stream would be reduced; therefore, the level of
emissions from this source, at a concentration of 250 ppm, would
also be reduced. In a selective amine process the carbonyl sulfide
would probably remain with the majority of the carbon dioxide and
be consumed during combustion.
VI-3
-------
An alternative approach to the desulfurization of the pyrolysis
off-gas is the direct use of a Stretford process. The Stretford sys-
tem is specific for recovery of hydrogen sulfide as elemental sulfur;
other sulfur species will pass through the Stretford scrubber to com-
bustion.
2.
ANALYSIS OF RESULTS: PYROLYSIS GAS STREAMS
The cost and performance data for the sulfur removal and re-
covery systems applied to the hypothetical pyrolysis off-gas are pre-
sented in the Appendix to this chapter. Table VI-1 summarizes the
results of this analysis. In addition to the two systems analyzed, an
alternative treatment by a selective amine has been considered. In
this case* it has been estimated that the cost would be intermediate
between the two values quoted in Table VI-1,. but the total emission
would be in the range of the higher quantity of 8 tons* daily.
Table VI-1
Summary of Results
Expected Emissions From Pyrolysis Gas Treatment
50,000 bbl/day Oil From Coal Pryolysis Facility
System
No.
1
2
Description
Direct Stretford
Treatment
Bulk Amine
Process, followed
by Claus Plant
Incremental
Emissions (Tons*/Day) Capital
Off-Gas Investment'
r*
Processing Combustion Total $10
7.9 7.9 22.4
1.6 0.2 1.8 43.1
Incremental
Gas Cost
$/10BBtu C/106kcal
8.4 33
21.2 84
comparing the data reported here, the limitations discussed on pages 1-7, 8 and IV-2, 5 should be recognized.
* Short tons, reference footnote p. 1-4.
VI-4
-------
The emissions from a pyrolysis operation will be directly re-
lated to the characteristics of the feedstock and the operating condi-
tions of the pyrolysis unit^ Referring to the gas compositions listed
for the coal pyrolysis processes in Table II-7, * it can be seen that
the sulfur concentration of the raw gas varies from approximately
0. 2 percent to 4 percent by volume. At the higher values of this range,
the expected emissions may be about 15 tonst daily, calculated as
elemental sulfur. This potential emission is equivalent to the carbonyl
sulfide content of the gas. In the example presented, the emissions
are equal to approximately 1. 7 percent of the sulfur in the raw gas,
and less than 0. 7 percent of the sulfur in the coal. On an energy
basis, the calculations for this emission amount to 0.15 Ibs (0. 07 kg)
of sulfur per 10 Btu heating value in the gas, or approximately
25 percent of the emissions that would be generated in an alternative
system using coal directly to generate the utility requirements of the
overall process.
The emissions were calculated for a raw gas with an H2/CO
ratio of approximately 2:1. Thermodynamically, this ratio should
control the concentration of carbonyl sulfide present in the process
gas, thereby controlling the potential emissions from combustion of
the gas following sulfur recovery. With lower H^/CO ratios, the quan-
tity of carbonyl sulfide would be expected to increase. For example,
the low ratio of H2/CO in the Toscoal process would tend to promote
the formation of carbonyl sulfide; the expected emissions quoted here
may not be applicable for that system.
The potential emissions from the combustion of desulfurized
pyrolysis off-gas made from high-sulfur coal are dependent upon the
concentration of sulfur species other than hydrogen sulfide in the raw
gas. Considering the composition of the coke oven gas listed in
Table II-9 as a type of pyrolysis gas (because of its temperature
and operation), it would appear that the expected ratio of COS to H?S
is about 1 part in 200, based on thermodynamic calculations. How-
ever, the actual COS concentration is four times this level. Similarly,
the carbon disulfide concentration, at 1 percent of the total sulfur in
the coke oven gas, is over two orders of magnitude higher than would
be expected on the basis of thermodynamic calculations. These
* Excluding the Cogas version of the COED process which was
developed for simultaneous oil and high-Btu gas production.
t Short tons, reference footnote p. 1-4.
VI-5
-------
comparisons indicate the degree to which actual pyrolysis gas compo-
sitions can deviate from that theoretically expected.
If the pyrolysis process is based on low-sulfur coal, the ex-
pected emissions should be significantly reduced. Based on the data
presented in a previous study prepared for the EPA, "" the expected
efficiency of oil production from pyrolysis processes is expected to
be significantly greater for low-sulfur Western coal. It is, there-
fore, expected that the majority of future installations of pyrolysis
processes will be based on this feedstock. Using the ratio of the
sulfur content in the raw gas as a basis, the emissions from py-
rolysis processes based on low-sulfur Western coal might be a fac-
tor of 20 less than the emissions based on high-sulfur coal. However,
information from those licensors of processes that promise to be the
most economical in this application indicates a minimum sulfur con-
centration in the treated gas of 250 ppm (monatomic species). This
sulfur concentration corresponds to a total sulfur emission, after
combustion, of about 5 tonst/day (calculated as elemental sulfur)
from a 50, 000 barrel per day facility. This expected emission
amounts to 0. 05 pounds of sulfur per million Btu in the treated off-
gas (90 kg/103 kcal), a factor of 12 less than the emissions from
the direct combustion of coal, assuming conformance to existing
solid fossil fuel standards.
The expected emissions discussed in this report for pyrolysis
processes are based only on the treatment of the pyrolysis off-gas.
Sulfur compounds will also exist in the syncrude product from the pro-
cess and the char by-product. The upgrading of these materials has
not been addressed.
Booz, Allen & Hamilton Inc. , Final Report No. 9075-015 to
the U. S. Environmental Protection Agency, Emissions From
Processes Producing Clean Fuels, March 1974.
Short tons, reference footnote p. 1-4.
VI-6
-------
3. EXPECTED EMISSIONS AND COSTS TO TREAT PYROLYSIS
GAS STREAMS
The emissions expected from the processing of pyrolysis off-
gas, and its combustion after treatment, are expected to be equivalent
to the concentration of the sulfur species (other than hydrogen sulfide)
in the raw gas, or 250 ppm monatomic sulfur in the treated gas,
whichever is greater. In accordance with present standards for solid
fossil fuels, these expected emissions are significantly lower than the
process alternative of direct combustion of this fuel, to meet the
utility requirements of the overall process. As seen in Table VII-1,
the expected cost for sulfur removal and recovery in these systems
is on thex>rder of $0.10-$0. 20/106 Btu in the treated gas ($0.35-
$0.85/10 kcal). The incremental capital investment is on the order
of $20 to $45 million for a 50, 000 bbl/day facility.
VI-7
-------
APPENDIX C
-------
APPENDIX C(l)
STREAM No.
DESCRIPTION
.TEMP, °F (°C)
PRESS'. psia
(kn/rm2|
Ib-moles/hr*
CO
H?
CH4
C?H4
*2
H20
C02
H3S
COS
s
TOTAL "S"
TOTAL
1
PYROLYSIS
GAS
.100(381
18(1.3)
10,080
19,570
8,300
4,745
-
2,965
12,450
1,170
20
.
1,190
59,300
2
TREATED
GAS
100 (38)
15(1.1)
10,076
19,566
1,295
4,735
-
2,730
12,390
0.6
(10 Ppm)
20
-
21
57,813
3
OFF-
GAS
100 (38)
15(1.1)
4
4
5
10
unk
235
60
—
- .
—
318-
4
BY-PRODUCT
SULFUR
300 1149)
15(1.1)
1,169.4
1,169
!4SO tons/day)
1,169
* Ib-moles/hr x 0.126 = gm-moles/sec.
Figuire C-l
STRETFORD PROCESS
-------
APPENDIX C(2)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PURIFICATION OF PYROLYSIS GAS
System No. 1:
A Stretford Process for selective recovery of sulfur
from the H S in the pyrolysis gas (Fig. C-l)
Sulfur Recovery
The Stretford process is used here for recovery of elemental sulfur from
pyrolysis gas with relatively low H2S concentration (From Fig. C-l, 2% in
this case). The Stretford process does not remove COS from its feed gas.
It will produce an effluent with 250 ppm total sulfur concentration or
containing all the feed COS plus 10 ppm H2S, whichever is greater. From
Fig. C-l, the sulfur recovered in the Stretford plant is 401 LT/day.
Estimating Bases;
Component
Investment Cost
Steam
Power
Process Water
Chemicals Cost
Steam Cost
Power Cost
Process Water
Accounting Method
Estimated Values
$5.1 x 106/100 LT/day
(For capacity > 100 LT/
day Power Factor = 0.9,
for < 100 LT/day Power
Factor = 0.7)
1473 Ib/LT
1353 kW/LT
1026 gal/LT
$4/LT
$1/1000 Ib
30C/1000 gal
Basis*
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Process Licensor
Communication With
Processor Licensor
Communication With
Process Licensor
Estimated for This Report
Estimated for This Report
Estimated for This Report
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA
Costs calculated on a mid-1974 basis.
-------
APPENDIX C(3)
Table C-l
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 1
Incremental Investment
Component $10
Stretford Sulfur Recovery 15.5
Subtotal Incremental Plant Investment 15.5
Project Contingency 2.3
Total Incremental Plant Investment • 17.8
Start-up Costs 1.1
Interest During Construction 3.0
Working Capital 0.5
Total Incremental Capital Requirement $22.4
Incremental Annual Operating Costs
Component $1000
Labor
Direct Operating Labor (8 men/shift @ $5.0/hr, 8304 hrs) 207.6
Maintenance Labor 267.0
Supervisory 71.2
Administrative and General Overhead 327.5
Other Direct Costs
Stretford Steam 194.4
Stretford Power 2678.8
Stretford Process Water 40.6
Stretford Chemicals 528.0
Stretford Losses 151.5
Operating Supplies 62.3
Maintenance Supplies 267.0
Local Taxes and Insurance 480.6
Incremental Gross Operating Cost 5276.5
By-Product Sulfur Credit —1319.9
Incremental Net Operating Cost 3456.6
Incremental Annual Revenue Required 6636.0
Annual Gas Production, 10 Btu 79037.1
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu 8.4
-------
APPENDIX C(4)
PYROLYSIS ^ _
GAS *
AMINE
PROCESS
1
REGENERATION
,©
CLAUS. PLANT
!
\
BY.PRC
SULFU
©
, V^ ^ TREATED
. GAS
©
UH--
I1 GAS
CLAUS TAIL- I
GAS TREAT.
1 '
®
JDUCT
R
STREAM No.
DESCRIPTION
TEMP. °F(°C)
PRESS ,,7 2
(kg/cm*)
Ib-moles/sec'
CO
H?
Cttj
C2H5
N2
H20
CO 2
H2S
COS
s
TOTAL "S"
TOTAL
1
PYROLYSIS
GAS
100 (38!
18(1.3'
10,080
'19,570
8,300
4,745
' —
2,965
12,450
1,170
20
-
1,190
59,300
2
TREATED
GAS
100 (38)
15(1.11
10,065
19,560
8,280
4,740
—
2,965
280
. 0.5
UOppm)
—
-
0.5
45,890
3
H2S-RICH
ACID GAS
100138)
18(1.3)
15
10
20
5
—
670
12,170
1,169.5
20
—
1,189.5
14,080
4
CLAUS TAIL
GAS
300 1149)
16(1.11
2,425
1,810
12,215
unk
unk
unk
1191
16,569
5
OFF-GAS
120
1511.11
2,425
1,810
12,215
unk
unk
unk
4.1
(250 ppm)
16,454
6
BY-PRODUCT
SULFUR
300 1149)
15(1.1)
1,185.4
1,185
(456 Ions/day)
1,185
Ib-moles/hr x 0.126 = gm-motes/sec.
90% Claus efficiency at low-sulfur feed.
Figure C-2
AMINE AND CLAUS PROCESS
-------
APPENDIX C(5)
COSTS OF SULFUR REMOVAL AND RECOVERY
DURING PURIFICATION OF PYROLYSIS GAS
System No. 2:
An amine-based system is used for bulk removal of gas,
followed by a Claus process for recovery of sulfur
from the H2S in the acid gas (Fig. C-2)
Acid Gas Removal
An example of amine-based bulk acid gas removal is included here because
amines are widely used for this service. In this case, a Diglycol Amine
(DGA) was employed because it is resistant to COS degradation. According
to process licensors, the COS is regenerated, without hydrolysis, into the
acid gas. The bulk treatment with DGA reduces the sulfur content of the
process gas to 10 ppm and removes CO2 to 1% concentration. From Fig. C-2,
the total acid gas removed by the DGA is 13359.5 Ib-moles/hr (1683.3 gm-moles/
sec) or 121.4 x 106 ft /day (3438 x 103 m3/day).
Estimating Bases;
Component
Investment Cost
Steam
Cooling Duty
Net Power Req'd
Chemicals Cost
Steam Cost
Cooling Water Cost
Power Cost
Product Gas Loss
Estimated Value
$130/103 ft3/day
60 Ibs/lb-mole
acid gas removed
120 gal/lb-mole .
acid gas removed
1.24 hp/lb-mole
(2.73 metric hp/kg-mole)
acid gas removed
1.30<:/lb-mole
acid gas removed
$1/1000 Ib
$0.03/1000 gal
1.5C/kW
$2/106 Btu
Basis*
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Estimated for This Report
Sulfur Recovery
Modified Claus Plant: Recovery of elemental sulfur from streams with
intermediate H2S concentration (Fig. C-2, 8.5% in this case). With modi-
fication, COS is also converted to elemental sulfur. The efficiency of the
Claus plant is depreciated to 90% because of the low J^S concentration.
From Fig. C-2, the sulfur recovery is 407.2 LT/day, including sulfur values
recovered in tail gas treatment.
Costs calculated on a mid-1974 basis.
-------
APPENDIX C(6)
Estimating Bases:
Component
Investment Cost
Estimated Value
$1.28 x 106/100 LT/day (Max
capacity 100.LT/day for
each train)
2 trains, 0.8 Power Factor
for capacity >100 LT/day
escalated by 25% From
Mid-1971 to Mid-1974.
Basis
Operating Costs $1.50/LT
(Including utilities,
catalysts, chemicals, etc.)
Mid-1971 Cost Basis, F.P.C.
Synthetic Gas-Coal Task Force
Report, April 1973, Page AI-25
Derived from Process
Engineering for Tail Gas,
July 1973 and some other
articles
Claus Plant Tail Gas Treatment: Several alternative processes are
available to recover sulfur values from the effluent of the Claus
plant. These processes generally treat the tail gas to 250 ppm
total sulfur content
Component
Investment Cost
Operating Cost
Estimated Value
Equal to the Claus
Plant Cost
Equal to the Claus
Plant Cost
Basis
From article "Add On Process
Slashes Claus Tail Gas
Pollution," Chemical
Engineering, Dec. 13, 1971
Accounting Method
The accounting method and financial factors used in this analysis were
taken from the FPC Task Force report on Synthetic Gas-Coal, utilizing
utility financing as developed in a previous Booz, Allen study for
the EPA
-------
APPENDIX C(7)
Table C-2
SUMMARY: INCREMENTAL INVESTMENT AND
OPERATING COSTS SYSTEM NO. 2
Incremental Investment
Component $10
Amine Process For Acid-Gas Removal 15.8
Claus Sulfur Recovery 6.8
Claus Tail Gas Cleanup 6.8
Subtotal Incremental Plant Investment 29.4
Project Contingency 4.4^
Total Incremental Plant Investment . 33.8
Start-up Costs 2.6
Interest During Construction 5.7
Working Capital 1.0
Total Incremental Capital Requirement $43.1
Incremental Annual Operating Costs
Component $1000
Labor
Direct Operating Labor (5 men/shift @ $5.0/hr, 8304 hrs) 207.6
Maintenance Labor 507.0
Supervisory 107.2
Administrative and General Overhead 493.1
Other Direct Costs
Amine Steam 6319.6
Amine Power 1460.9
Amine Cooling Water 379.2
Amine Chemicals 1369.2
Amine Product Loss 221.9
Claus Utilities and Chemicals , 200.6
Claus Tail Gas Utilities and Chemicals 200.6
Operating Supplies 62.3
Maintenance Supplies 507.0
Local Taxes and Insurance 912.6
Incremental Gross Operating Cost 12948.8
By-Product Sulfur Credit —1337.7
Incremental Net Operating Cost 11611.1
Incremental Annual Revenue Required 76794.3
Annual Gas Production, 10 Btu 79037.1
Incremental Gas Cost Due to Sulfur Removal,
C/10 Btu 21.2
-------
VII. SULFUR PROJECTIONS
-------
VII. SULFUR PROJECTIONS
Based on the levels of sulfur abatement expected from clean
fuel conversion plants which have been developed in this report it is
possible to project national sulfur emissions from these facilities
through the year 1990. The projections are estimated on the number
and type of facilities expected to be constructed as well as on the rate
of construction which may be achieved by the clean fuels industry.
In this chapter, guidelines are described by which these construc-
tion timetables for high-Btu, low-Btu and pyrolysis gas plants can be
estimated. The resulting sulfur emissions from treating the off-gases
from these facilities are then calculated.
1. PROPOSED SCENARIOS FOR DEVELOPMENT OF A CLEAN
FUELS INDUSTRY
There are many complex factors that contribute to determining
the level and timetable for clean fuel plant construction programs in
the United States. No comprehensive attempt has been made to assess
the impact of these factors in this study. Reference has been made,
however, to a number of reports which have assessed the impact of
different factors on planned and projected heavy fossil-fuel conversion
plant construction levels. Data from some of these sources* were
used where appropriate in developing the sulfur emissions projections
given in this chapter.
The Final Report of the Supply-Technical Advisory Task Force —
Synthetic Gas-Coal prepared for the Federal Power Commission,
April 1973. Dr. Henry R. Linden, "Review of World Energy
Supplies, " prepared for the 12th World Gas Conference, Nice,
France, June 1973, included in "Clean Fuels from Coal Sympo-
sium Papers" (sponsored by IGT, September 1973). Report to
Project Independence Blueprint by the Interagency Task Force
on Synthetic Fuels from Coal, for the Federal Energy Adminis-
tration, September 1974.
VII-1
-------
Two alternative scenarios (Business-As-Usual and Accelerated
Growth) were considered which represent courses of action that may be
taken depending on international political considerations, domestic
energy requirements, and the estimated economic benefits of this
developing technology. A third scenario (Crash Development) represents
the upper bound on the size of the clean fuels industry. The rate of
growth in this scenario is assumed to be unconstrained by fiscal and
regulatory limitations. It is realized that this level of development
is not expected to be achieved. This scenario is included in the dis-
cussion, however, to provide an analytic basis for estimating maximum
sulfur emission levels. Each of these three scenarios is discussed
below.
(1) Business-As-Usual
The Business-As-Usual scenario presumes a continuation
of current policies. It assumes that the clean-fuels industry will
continue to be subjected to the same constraints, market pressures
(domestic and international), and government regulations that
have existed in the past. Under this scenario, the design, con-
struction and operation of new process facilities require the
traditional intermediate steps of construction of miniplants,
PDU's*, demonstration plants and construction of commercial
scale plants subject to market demand. It is assumed that there
will continue to be no Federal Government construction loan
guarantees.
(2) Accelerated Growth
In the Accelerated Growth scenario, an increased rate of
plant construction is assumed to be possible by compressing the
historical development routes traditionally followed and by
stimulating the delivery of supplies and materials to meet these
tightened construction schedules. To make an accelerated
industry growth rate an attractive alternative, government
incentives such as the following are assumed:
Process Development Units
VII-2
-------
Government-guaranteed loans, tax incentives and
price supports
Streamlining of construction permit requirements
Modifying water allocation priorities and stretching
of EPA pollution control schedules
Increased leasing of public lands.
(3) Crash Development
This scenario assumes an industry crash expansion program
to maximize the nations clean fuels capacity. It assumes no
restrictive government involvement, no constraints as to the
level or availability of funding, a very high level of process
R&D, and no restrictions on the use of national resources. The
only factor limiting growth is the lead time required for plant
construction. This scenario, though highly improbable, permits
an estimate of the level of sulfur emissions which would result
if the industry developed at the maximum possible rate.
The analysis given in preceding chapters has addressed the control of
sulfur from typical high-Btu pipeline quality gas streams, typical
low-Btu utility gas streams and a typical pyrolysis gas stream. The
number of facilities to produce these fuel gases will be projected under
each of the three scenarios just outlined.
2. PROJECTIONS OF THE NUMBER OF CLEAN FUELS PLANTS
TO BE CONSTRUCTED BY 1990
(1) Facilities Producing High-Btu Pipeline Gas
For each of the three scenarios, the projected annual
production capacities for pipeline quality gas are reported in
VII-3
-------
Table VII-1. These projections, taken from the Report to Project
Independence Blueprint*, were also cited in the Project Indepen-
dence Report prepared by the Federal Energy Administration.t
Table VII-1
U.S. Coal-to-SNG Capacity (xl()12ft3/yr)
Business- As-Usual
Year Scenario
1980
1985
1990
0. 1
0. 5
1.4
Accelerated Growth Crash Development
Scenario Scenario
0. 1
1. 1
2.8
0. 5
2. 5
4.9
Since coal gasification plants of this type will be sized to produce
about 250 x 109 Btu/day (63 x 109 kcal/day) of a 900-1000 Btu/
ft3 (8000-8900 kcal/m3) gas, the annual capacity of each plant
(assuming a 90 percent stream factor) is 82-86 x 10 ft3/yr
(2. 3-2. 4 x 109 m /yr). The numbers of these plants necessary
to achieve the projected national capacities of Table VII-1 were
calculated and are shown in Table VII-2.
Table VII-2
Projected Number of Facilities Producing High-Btu Gas
Business-As-Usual Accelerated Growth Crash Development
Year Scenario Scenario Scenario
1980
1985
1990
1
6
17
1
12
33
5
.29
57
op. cit.
Project Independence Report prepared by the Federal Energy
Administration, November 1974.
Ft3/yr x 0. 028 = m3/yr
VII-4
-------
These estimates compare favorably with those developed
in other reports. For example, a recent study*, using assump-
tions similar to those for the Accelerated Growth Scenario''",
projects 37 plants by 1990 (compared to 33 plants indicated in
Table VII-2). Data developed in another study* also closely
matches the projections in Table VII-2. The data from this
source § projects 3, 11, and 24 plants for 1980, 1985 and 1990,
respectively. This compares favorably with the projections
of 1, 12 and 33 plants given in Table VII-2.
(2) Facilities Producing Low-Btu Utility Gas
Because coal conversion to low-Btu utility gas (usually
ranging between 100 and 300 Btu/ft3; 1000-3000 kcal/m3) is not
energy conservative (from mine to user), it is not considered in
any accelerated growth or crash development scenario. Develop-
ment programs are expected to proceed under the guidelines
assumed for the Business-As-Usual case.
The impetus for construction of low-Btu gasification
facilities is not to ensure the continued existence of the elec-
trical utility industry (as can be argued in the case of the pipe-
line gas industry in discussing high-Btu synthetic gas). Instead
their present attractiveness is due to the reduced emissions
Linden, op. cit.
Assuming heating values of 1,032 Btu/ft3 (9183 kcal/.m3) for
product gas; gas production capacity of 10*° ft3/day (283 x
m3/day); plant capacities of 250 x 109 Btu/day (63 x lO9 kcal/day);
90% stream factor.
The Final Report of the Supply-Technical Advisory Task Force
Synthetic Gas-Coal prepared for the Federal Power Commis-
sion, April 1973.
Assumes an accelerated growth scenario. The 1973 data base
used in this reference was updated for this comparison.
VII-5
-------
possible. The Report to Project Independence Blueprint*
indicates that the construction of these facilities will not be-
come economically attractive until high-temperature turbine
combined-cycle systems have been developed. The overall
system of coal gasification coupled to combined-cycle power
generation is more efficient than the current alternative of
direct combustion of the coal under steam boilers. The
Report to Project Independence Blueprint assumes that this
technology will be developed in time to permit the first com-
mercial plant to be operational in 20 years. It is felt that,
considering the reluctance of some electric utilites to accept
stack gas desulfurization as an approach to meeting EPA New
Source Performance Standards, low-Btu gas purification
holds much promise as a preferred alternative toward meeting
these standards. The estimated time to the first commercial
plant, therefore, has been moved up 10 years to 1985. The
continued rate of installation of these low-Btu gasification
facilities is assumed to be similar to the rate estimated for
construction of high-Btu gasification plants under the Business-
As-Usual scenario. The projected number of these coal-to-
clean energy plants (sized to produce about 850-950 x 10" ft^/day
[24-27 x 10^ m3/day] of a 150 Btu/ft3 [1335 kcal/m3] gas)f is
shown in Table VII-3.
Table VII-3
Projected Rate of Commercialization of Low-Btu
Utility Gas Conversion Plants
Year
1980
1985
1990
Number of Plants
*
t
op. cit.
Approximately 130 to 140 x 109 Btu/day (33-35 x 109 kcal/day)
of gas is capable of generating about 650 MWh/h of electrical
power when fired under boilers. Over thirty percent additional
power may be generated during the years indicated if the gas is
fired through combined-cycle systems.
VII-6
-------
(3) Facilities Producing Pyrolysis Gas
In the context of this study, pyrolysis gas refers to an
intermediate heating value fuel gas of about 450 Btu/ft
(4000 kcal/m^) which may be generated through the pyrolysis
(heating in absence of oxygen) of a coal or oil shale fuel.
This pyrolysis unit operation is common to the liquefaction
processes which are nearest to commercialization. As such
the first of the liquid fuel conversion plants brought online
will most likely contain pyrolysis operations. As technological
process developments continue, however, one or more of the
second generation hydrogeneration-type liquefaction processes
currently discussed in the literature is expected to reach com-
mercialization. The comparative attractiveness of pyrolysis
processes will then begin to wane and their continued commer-
cialization will likely cease. The number of pyrolysis plants
projected in this report assumes the decreasing rate of com-
mercialization as proposed in the Final Report of the Supply-
Technical Advisory Task P'orce — Synthetic Gas-Coal. *
For plants sized to produce 50,000 bbl/day of syncrude,
the projections given in Table VII-4 were derived:
Table VII-4
Projected Number of Pyrolysis Plants
Business-As-Usual Accelerated Growth Crash Development
Y ear
Scenario Scenario Scenario
1980 006
1985 0 12 18
1990 2 20 22
op. cit. The data are based on the expected declining commer-
cialization of Lurgi plants for high-Btu gas manufacture
as second-generation processes are developed.
VII-7
-------
3. PROJECTED SULFUR EMISSIONS
(1) Feedstock Variations
To project sulfur emissions for the number and type of
clean fuel plants just presented, it has been assumed that the
typical raw feeds to generate the gas streams desulfurized
will include a 4. 5 percent (high-sulfur content) Eastern bitu-
minous coal and a 0. 9 percent (low-sulfur content) Western
lignite or subbituminous coal. Since economics demand that
plants be sited close to the mine, and most mines capable of
supporting these projected plants are located in Western states,
most of the new plants are expected to use low-sulfur Western
coal. Using siting data presented by the Supply-Technical
Advisory Task Force—Synthetic Gas-Coal, * it is assumed
here that 80 percent of the projected plants will use low-sulfur
coal and 20 percent will use high-sulfur feed.t
(2) Sulfur Emissions
Table VII-5 summarizes the estimated levels of sulfur
emissions expected from treating the gas streams analyzed in
Chapters IV through VI. The following sections briefly restate
these summary findings in terms of per-plant daily emissions.
1. High-Btu Gas Generation
From the analysis in Chapter IV, the estimated
levels of sulfur emitted from desulfurizing high-Btu gas
streams amount to 10 tons*/day if high-sulfur fuel is
used and 3. 5 tons'1"/day (on a per-plant basis) if a low-
sulfur fuel is used. Essentially complete sulfur removal
from the product gas is assumed.
* op. cit.
t Report to Project Independence Blueprint (op. cit. ) projects a
60:40 usage ratio (high- to low-sulfur feed).
-t Short tons, reference footnote p. 1-4.
VII-8
-------
-------
2. Low-Btu Gas Generation
Plant emissions from low-Btu coal-to-gas conver-
sion facilities are composed of sulfur lost to the atmo-
sphere during purification of the gas stream generated as
well as sulfur remaining in the treated gas stream that,
when combusted will eventually contribute to additional
i emissions. .
Accounting for the sulfur remaining in the product
gas is necessary since all the sulfur need not be removed
as a process requirement, as was required for the high-
Btu case. The levels of sulfur remaining in the low-Btu
gas streams can vary significantly, depending on the con-
trol system applied. From the analysis of Chapter V,
control processes are now commercially available which,
when applied, result in reducing sulfur concentrations
in the product gas to 0.4 Ib SO2/106 Btu (0.72 kg/106 kcal)
when using high-sulfur coal and 0. 1 Ib SO2/106 Btu (0. 18 kg/
10° kcal) for low-sulfur coal. If a Glaus plant is used for
sulfur recovery the expected off-gas will be about 250 ppm.
For a 130 x 10§ Btu/day (32. 750 x 109 kcal/day) plant,
this emission will be on the order of 0. 5 tons*/day. In-
cluding these Glaus plant emissions with those generated
upon combustion of the product gas, the total expected
emissions from these facilities will be approximately 14
tons*/day of sulfur for the high-sulfur feed and 9 tons*/
dayt if using low-sulfur Western coal. . .. -
3. Pyrolysis Gas Generation
The pyrolysis gas characterized in Chapter II, if
desulfurized by the conventional processing schemes
applied in Chapter VI and then burned, will yield
Short tons, reference footnote p. 1-4.
Engineering analyses include emissions levels of about 4 tons/
day but sulfur recovery data quoted by process licensors cor-
respond to 9 tons daily.
VII-10
-------
approximately 0. 13 Ib SO2/106 Btu (0. 23 kg/106 kcal) in
the gas. The analysis in Chapter VI indicates daily sulfur
stack emissions of 8 tons*/day (calculated as elemental
sulfur) for the combustion of pyrolysis gas in a 50, 000 bbl/
day coal-to-syncrude facility. These emissions, however,
are extremely sensitive to variations in the sulfur content
of the feedstock and rise to about 15 tons* daily when an
Eastern coal is used. Due to the uncertainty in defining
precise feeds for the first of these plants, the 15 ton*/
day level was selected to conservatively reflect the ex-
pected sulfur emission levels. However, since the syn-
crude product yields from a Western coal would be higher
than for an Eastern coal,' Western fuels may be a more
logical choice for pyrolysis facilities.
The emissions described above result from the pro-
cessing and combusting of the pyrolysis off-gas and do not
include sulfur that may be left in the product oil or by-
product char. A portion of the sulfur from these two
sources might also be discharged onsite, as discussed
more fully in a previous report to the EPA.*
(3) Sulfur Projections
The extent to which low-sulfur Western coals and high-
sulfur Eastern coals will be used in the plants expected to be
constructed for each of the three growth scenarios discussed
earlier has been taken to be 80:20 for each of the basic facility
types. By applying the sulfur emissions levels estimated for
each of these plants, the total level of sulfur has been derived
on a national basis through 1990. Table VII-6 presents the
national projections of sulfur emissions and Table VII-7 sum-
marizes the results.
* Short or metric tons.
t . Chapter VIII, Booz, Allen & .Hamilton Inc. Report No. 9075-015
to the Environmental Protection Agency, Emissions from Pro-
cesses Producing Clean Fuels, March 1974.
* Ibid.
VII-11
-------
This page is intentionally left blank.
VII-12
-------
Table VII-6
Year
1980
1985
1990
Number of Plants
Business -As -Usual Scenario
Type Conversion Plant
Pipeline Gas
(Sulfur Emissions,
Utility Gas
(Sulfur Emissions,
Pyrolysis Gas
(Sulfur Emissions,
Pipeline Gas
(Sulfur Emissions,
Utility Gas
(Sulfur Emissions,
Pyrolysis Gas
(Sulfur Emissions,
Pipeline Gas
(Sulfur Emissions,
Utility Gas
(Sulfur Emissions,
Pyrolysis Gas
(Sulfur Emissions,
T/D)*
T/D)
T/D)
T/D)
T/D)
T/D)
T/D)
T/D)
T/D)
Low Sulfur
Feed
1
(3.5)
0
0
4
(14)
1
(4)
0
14
(49)
6
(54)
2
(30)
High Sulfur
Feed
0
0
0
1
(10)
0
0
3
(30)
2
(28)
0
Total
1
(3.5)
0
0
5
(24)
1
(4)
0
17
(79)
8
(82)
2
(30)
Accelerated Growth Scenario
Low Sulfur
Feed
1
(3.5)
0
0
10
(35)
1
(4)
1.0
(150)
26
(91)
6
(54)
16 '
(240)
High Sulfur
Feed
0
0
0
2
(20)
0
2
(30)
7
(70)
2
(28)
4
(60)
Total
1
(3.5) .
0
0
12
(55)
1
(4)
1.2
(180)
33
(161)
8
(82)
20
(300)
National Projection of Sulfur E
Crash Development Scenario
Low Sulfur
Feed
4
(14)
0
5
(75)
23
(81)
1
(4)
14
(210)
46
(161)
6
(54)
17
(255)
High Sulfur
Feed
1
(10)
0
1
(15)
6
(60)
0
4
(60)
11
(110)
2
(20)
5
(75)
Total
5
(24)
0
6
(90)
29
(141)
1
(4)
18
(270)
57
(271)
8
(82)
22
(330)
Tons/day either on a short or metric ton basis.
VII-13/14
-------
Table VII-7
Total National Sulfur Emissions*, Tons/Day
Scenario
Business -As -Usual
Accelerated Growth
Crash Development
1980
3.5
3.5 •
114.0
1985
28
239
415
1990
1.91
543
683
From these results, the maximum possible impact on atmos-
pheric emissions, due to all clean fuels facilities which are projected
to be installed across the nation, is projected to reach 683 tons*/day
(calculated as elemental sulfur) by 1990. This is significantly less
than the sulfur emissions that would be produced if an equivalent
amount of heat energy were generated by producing electricity from
direct combustion of coal as shown in Table VII-8. On a national
basis the amounts shown in Table VII-8, which summed, yield
17, 776 tons*/day or 26 times more sulfur than the expected emis-
sions produced by applying current coal gasification technology.
Short tons, reference footnote p. 1-4
VII-15
-------
I
I—'
O5
Table VII-8
Comparison of Sulfur Emissions From
Clean Fuels Plants and Electric
Generating Stations Producing
Equivalent Heat Energy Output
Type of
Facility
High-Btu Gasification
(250 x 109 Btu/Day Plant)
Low-Btu Gasification
(130 x 109 Btu/Day Plant)
Pyrolysis
(290 x 109 Btu/Day Plant)
Tons of
Sulfur*/Day From
Clean Fuels Plant
4. 75
10. 25
15
Tons of
Sulfur/Day From
Equivalent Electric
Generating Plants^
200
104
252
Derived from Table VII-6
Assumes conformance with Federal New Source Performance
Standards for Sulfur Emissions from Coal Fired Boilers.
-------
BIBLIOGRAPHY
"A New Approach to Desulfurization, " The Oil and Gas Journal, p. 74,
Nov. 27, 1967.
Barry, C. B., "Reduce Claus Sulfur Emission, " Hydrocarbon Pro-
cessing, 51_, 4, p. 102-106, April 19.72.
Barthel, Y., et al., "Treat Claus Tail Gas, " Hydrocarbon Process-
Ing, 50. 5, p. 89-91, May 1971.
Beavon, D. K., "Add-On Process Slashes Claus Tail Gas Pollution, "
Chemical Engineering, p. 71-73, Dec. 13, 1971.
Bensen, H. E. , "Hot Carbonate Plants: How Pressure Affects Costs, "
Petroleum Refiner, 40. 4, p. 107-108.
Bensen, H. E., and Field, J. H., The New Benfield Process. Publi-
cation of the Benfield Corp., Pittsburgh, Pa.
Benson, H. E., and Parrish, R. W., "Hi Pure Process Removes
CO^/H^S, " Hydrocarbon Processing, Vol. 53, No. 4, April 1974,
pp. 75-77.
Bienstock, D., and Field, J. H., Corrosion. 17:337t-339t (1961).
Blake, R. J. , "How Acid-Gas Treating Processes Compare, " The Oil
and Gas Journal. Jan. 9, 1967, pp. 150-8.
Bocard, J. P., and Mayland, B. J., "New Charts for Hot Carbonate
Process, " Hydrocarbon Processing and Petroleum Refiner, Vol. 41,
No. 4, Apr. 1962, pp. 128-32.
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Clean Fuels, March 1974.
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Treating, " Proceedings of the 1968 Gas Conditioning Conference,
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Bratzler, K., and Doerges, A., "Amisol Process Purifies Gases, "
Hydrocarbon Processing. Vol. 53, No. 4, April 1974, pp. 78-80.
Buckingham, P. A. , "Fluor Solvent Process Plants: How They Are
Working, " Hydrocarbon Processing, 43, 4, 113-116 (1964).
Cameron, L. C., "Aquitaine Improves Sulfeen Process for More t^S
Recovery, " The Oil and Gas Journal, June 24, 1974, pp. 110-114.
Chalmers, F. S. , "Citrate Process Ideal for Glaus Tailgas Cleanup, "
Hydrocarbon Processing, Vol. 53, No. 4, April 1974, pp. 75-77.
Cronenberg, J. W. , Paper presented at the January 1962 Meeting of
California Natural Gasoline Association.
Crow, J. H., and Baumann, J. C., "Versatile Process Uses Selec-
tive Absorption, " Hydrocarbon Processing, Vol. 53, No. 10,
October 1974, pp. 131-132.
Dailey, L. W., "Maximizing Ore Stream Time for Large Plants, "
Chemical Engineering Progress, 66, 12, p. 34-41 (1970).
Dailey, L. W. , "Present Status of the SNPA-DEA Process, " Pro-
ceedings of the 49th Annual Convention of the Natural Gas Processors
Association. Denver, Colo., Mar. 17-19, 1970, pp. 78-82.
Deal, C. H., et al. , Patent No. 3,363,989, Jan. 16, 1968.
Dingman, J. C., Allen, D. L., and Moore, T. F., "Minimize Cor-
rosion in MEA Units, " Hydrocarbon Processing. Vol. 45, No. 9,
Sept. 1966, pp. 285^90.
Dingman, J. C., and Moore, T. F., "Compare DGA and MEA Sweet-
ening Methods, " Hydrocarbon_Processing, Vol. 47, No. 7, July 1968,
pp. 138-40.
Dingman, J. C., and Moore, T. F., "Gas Sweetening with Diglycola-
mine, " Proceedings of the 1968 Gas Conditioning Conference. Uni-
versity of Oklahoma, Norman, Okla.
Dunn, C. L. , Freitas, E. R. , Hill, E. S. , and Scheller, J. E. R. ,
"Shell Reveals Commercial Data on Sulfinol Process, '.' The Oil and
Gas Journal. Mar. 29, 1965, pp. 89-92.
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Ellwood, P., "Meta-Vanadates Scrub Manufactured Gas," Chem.
Eng. , pp. 128-130, July 20, 1964.
El Paso National Gas Company, Federal Power Commission, Filing,
Docket CP 73-131.
Fitzgerald, K. J., and Richardson, J. A., "How Gas Composition
Affects Treating Process Selection, " Hydrocarbon Processing,
Vol. 45_, No. 7, July 1966, pp. 125-9.
Fitzgerald, K. J., and Richardson, J. A., "New Correlations En-
hance Value of Monoethanolamine Process, " The Oil and Gas Journal,
Oct. 24, 1966, pp. 110-18.
"Gas Sweetening Process Leaves in CC>2, " The Oil and Gas Journal,
p. 58, Jan. 3, 1966.
Gaumond, P., L'Industrie Chimique, No. 499 (Feb. 1959).
Gleason, M. N. , Clinical Toxicology of Commercial Products,
Baltimore, Maryland, W & W Co., 1957.
f
Goar, B. G., "Sulfinol Process Has Several Key Advantages, "
The Oil and Gas Journal, June 30, 1969, pp. 117-20.
Goar, B. G., "Today's Gas Treating Processes, " The Oil and Gas
Journal. July 12, 1972, July 19, 1972.
Goar, B. G. , "Today's Sulfur Recovery Processes, " Hydrocarbon
Processing, Vol. 4^7, No. 9, pp. 248-51, September 1968.
Goddin, C. S. , Hunt, -E. B., and Palm, J. W., "CBA Process Ups
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October 1974, pp. 122-724.
Groenendaal, W. , and Van Meuck, H. C. A., "Shell Launches Its
Glaus Off-Gas Desulfurization Process, " Petroleum and Petro-
chemical International, 12, 9, p. 54-58, Sept. 1972.
Gustafson, K. J. , and Healy, Jr., M. J., "Removal of Hydrogen
Sulfide From Natural Gas/Carbon Dioxide Mixtures With Molecular
Sieves, " Proceedings of the 1968 Gas Conditioning Conference,
University of Oklahoma, Norman, Okla.
Haines, H. W., Van Wielingan, G. A., and Palmer, G. H., "Re-
cover Sulfur With Zeolites, " Petroleum Refiner, Vol. 40, No. 4,
p. 123, April 1961.
B-3
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Hasebe, Dr. N., "Hydrogen Sulfide Removal by Takahax Liquid
Purification Process, " secondary report by Tokyo Gas Co., Ltd.,
Tokyo, Japan.
Hayford, J. S., "Process Cleans Tail Gases, " Hydrocarbon Process-
ing. October 1973, pp. 95-96.
Hegwer, A. M., and Harris, R. A., "Selexol Solves High H2S/CO2
Problem. " Hydrocarbon Processing, Vol. 49, No. 4, Apr. 1970,
pp. 103-4.
Herbert, W., et al., "Methanol, " U. S. Patent 2, 863, 527 (1958),
December 8.
Hochgesand, Dr. Ing. G., and Wendt, Jr., C. J. , "The Purisol
Process for Acid Gas Treatment, " Proceedings of the 1969 Gas Con-
ditioning Conference, University of Oklahoma, Norman, Okla.
Holbrook, O. C. , "Ethylene Carbonate, " U. S. Patent 3, 214, 892 (1965),
November 2.
Holder, H. L., "Diglycolamine —A Promising New Acid-Gas Remover, "
The Oil and Gas Journal. May 2, 1966, pp. 83-6.
Hydrocarbon Processing. 40, 9, pp. 175-178, Sept. 1961.
Hydrocarbon Processing. 49, 9, pp. 187-191, Nov. 1970.
Hydrocarbon Processing, 50, 5, pp. 97-102, May 1971.
Hydrocarbon Processing, 45, 5, pp. 149-52, May 1966.
Hydrocarbon Processing, 48. 9, pp. 131-36, Sept. 1969.
Hydrocarbon Processing, 48, 9, pp. 137-40, Sept. 1969.
Interagency Task Force on Synthetic Fuels From Coal, Report to
Project Independence Blueprint, Federal Energy Administration,
September 1974.
Jennett, E., and Ackerman, Jr., R. H., "An Assessment of the
Giammarco-Vetrocoke Process in U. S. Gas Treating Operations —
Theory and Practice, " Proceedings of the 1964 Gas Conditioning
Conference, University of Oklahoma, Norman, Okla.
B-4
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Jennett, E. , "Six Case Studies Throw Light on the Giammarco-
Vetrocoke Process, " The Oil and Gas Journal, Apr. 30, 1962,
pp. 72-7.
Kamlet, J. , "Sulfolane, " U. S. Patent 3, 039, 251 (1962), June 19. .
Klein, J. P., "Developments in Sulfinol and A dip Processes Increase
Uses, " Oil and Gas International, 10, 4, p. 109-111, Sept. 1970.
Knapp, Dr. Helmut, "Low Temperature Absorption — The Rectisol
Process, " Proceedings of the 1968 Gas Conditioning Conference,
University of Oklahoma, Norman, Okla.
Knudson, J. C., "Air Pollution Controls to Meet Washington State
Kraft Mill Standards, " paper presented at the Pacific Northwestern
International Section, Air Pollution Control Association; Spcikane,
Wash., Nov. 16-18, 1970.
Kohl, A. L., and Buckingham, P. A., HP/PR, 3_9 (5), 193-196,
(May 1960).
Kohl, A. L., and Riesenfeld, F. C., Gas Purification. New York,
McGraw-Hill, I960.*
Kutsher, G. S., Smith, G. A., and Greene, P. A., "Now Sour-Gas
Scrubbing by the Solvent Process, " The Oil and Gas Journal, Mar. 20,
1967, pp. 116-118.
Linden, Harry R., "Review of World Energy Supplies, " Clean Fuels
From Coal Symposium, Nice, France, September 1973.
"M-Pyrol, " Publication of GAF Corp. , 1972.
Maddox, Dr. R. N., and Burns, M. D., "Designing A Hot Carbonate
Process, " The Oil and Gas Journal. Nov. 13, 1967, pp. 122-31.
Maddox, Dr. R. N., and Burns, M. D., "Economical New Sour-Gas
Treating Methods Available, " The Oil and Gas Journal, Jan. 22, 1968,
pp. 91-4.
The second edition, printed by Gulf Publishing Co., Houston,
1974 was not published in time to be considered in this report.
B-5
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Maddox, Dr. R. N., and Burns, M. D., "Hot Carbonate — Another
Possibility, " The Oil and Gas Journal. Oct. 9, 1967, pp. 167-73.
Maddox, Dr. R. N., and Burns, M. D. , "iron-Oxide Process Design
Calculations, " The Oil and Gas Journal, pp. 74-75, Aug. 12, 1968.
Maddox, Dr. R. N., and Burns, M. D., "Liquid Absorption —
Oxidation Processes Show Much Promise, " The Oil and Gas Journal.
pp. 100-103, May 13, 1968.
Maddox, Dr. R. N. , and Burns, M. D. , "Liquid Absorption —
Oxidation Processes, " The Oil and Gas Journal, pp. 90-95, June 3,
1968.
Maddox, Dr. R. N., and Burns, M. D. , "MEA Process to Be Con-
sidered First, " I^i£_OJl_an^_Ga^_j£urna.l, Aug. 21, 1967, pp. 83-5.
Maddox, Dr. R. N., and Burns, M. D. , "Physical Solution Is the Key
to These Treating Processes, " The Oil and. Gas Journal, Jan. 8, 1968,
pp. 78-81.
Maddox, Dr. R. N., and Burns, M. D., "Solids Processes for Gas
Sweetening, " The Oil and Gas Journal, pp. 90-93, June 17, 1968.
^
Mason, J. R. , and Griffith, T. E. , "A Case History — Conversion
of a Sweetening Solution from MEA to DGA, " Proceedings of the 1969
Gas Conditioning Conference, University of Oklahoma, Norman, Okla.
McKetta, J. J., Jr., ed. Advances in Petroleum Chemistry and
Refining, Vol. 6, pp. 315-448, Interscience Publishers, New York,
1964.
Morse, R. J., "Catacarb CO2 Cuts Costs, Enjoys Big Growth, "
The Oil and Gas Journal, Apr. 22, 1968, pp. 184-5.
Moyes, A. J., and Vasan, S., "Holmes — Stretford ^S Removal
Process Proved in Use, " The Oil and Gas Journal, September 2, 1974,
pp. 56-58
"NG/SNG Handbook. " Hydrocarbon Processing. ££, 4. pp. 93-132,
April'1971.
B-6
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Nelson, W. L. , "A Look at Sulfur-Recovery Costs, " The Oil and Gas
Journal. March 18, 1974, pp. 120-123.
Nelson, W. L. , Petroleum Refinery Engineering, New York, McGraw-
Hill, 1958.
"1971 Refining Processes Handbook," Hydrocarbon Processing, 51, 9,
p. 150-184, Sept. 1972. '•
"Natural Gas Desulfurization Looks to a New Absorbent, " Chemical
Engineering, Feb. 12, 1968, p. 66.
"New Process Has Wide Scope, " The Oil and Gas Journal, May 20,
1968, pp. 85-6.
"New Process Removes Stack-Gas Sulfur, " The Oil and Gas Journal,
pp. 49-50, July 13, 1970.
Nicklin, T., and Brunner, E., The Institution of Gas Engineers,
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Processing, February 1973, pp. 81-85.
Perry, Charles R., "Design and Operating Amine Units for Trouble
Free Unattended Operation, " Proceedings of the 1969 Gas Condition-
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Perry, Charles R., "Basic Design and Cost Data on MEA Treating
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Petroleum Refiner. 36, 9, pp. 233-235, Sept. 1957.
Petroleum Refiner, 34, 6, pp. 118-122, June 1955.
Petroleum Refiner. 3_4, 9, pp. 152-154, Sept. 1955.
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Pippig, H., Gas u. Wasserfach, 94-62 (1953).
B-7
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Richardson, J. A., Gas Processing (Canada), p. 32, Fall 1969.
Riesenfeld, F. C., and Blohm, C. L., "Acid Gas Removal Processes
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Riesenfeld, F. C., and Mullowney, J. F., HP/PR, 38_(5), pp. 161-
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Rushton, D. W., and Hays, W., The Oil and Gas Journal. Sept. 18,
1961, 103-104.
Sax, Irving N., Dangerous Properties of Industrial Materials
(3rd edition), New York, Reinhold Book Corp., 1968.
Scholz, W. H., "A Low Temperature Scrubbing Process for Gas
Purification, " Linde A. G., Munich.
"Selexol Solvent Processes for Acid Gas Removal, " Bulletin of Allied
Chemical Corp., 1967.
Sudduth, L. G., et al., "Evaluation of Sulfur-Plant Efficiency — A
New Stoichiometric Method, " The Oil and Gas Journal, p. 102,
Dec. 14, 1970.
Swaim, Jr., C. Donald, "Gas Sweetening Processes of the 1960's, "
Hydrocarbon Processing, Vol. 49, No. 3, Mar. 1970, pp. 127-30.
Synthetic Gas-Coal Task Force, Final Report for the Federal Power
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Taylor, W. C., "Experience in the Disposal and Utilization of Sludge
From Lime-Limestone Scrubbing Processes, " Combustion, October
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The Oil and Gas Journal, 69, 41, pp. 75-77, Oct. 11, 1971.
B-8
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The Oil and Gas Journal, 70. 24, p. 94, June 12, 1972.
Thomas, T. L., and Clark, E. L., "Molecular Sieves Reduce Eco-
nomic, Operational Process Problems, " The Oil and Gas Journal,
pp. 112-115, Mar. 20, 1967.
Thormann, K., et al., "n-Methyl Pyrrolidone, " U. S. Patent
3, 120, 993 (1964), February 11.
Townsend, F. M., Patent No. 3,170,766, Feb. 23, 1965.
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Petroleum Refiner. Vol. 37, No. 11, p. 263, November 1958.
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March 1969.
Wendt, Jr., C. J., and Dailey, L. W., "Gas Treating: The SNPA
Process. " Hydrocarbon Processing. Vol. £6, No. 10, Oct. 1967,
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Wiewiorowski,. T. K., Patent No. 3,447,903, June 3, 1969.
Woertz, B. B., et al., "Methyl Cyanoacetate, " U. S. Patent
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