United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards .. noo
Research Triangle Park NC 27711 May 1982
Air
Draft
EIS
Emissions
in On-Shore
Natural Gas
Production Industry —
Background Information
for Proposed Standards
Preliminary Draft
-------
NOTICE
This document has not been formally released by EPA and should not now be construed to represent Agency policy.
It is being circulated for comment on its technical accuracy and policy implications.
SO2 Emissions in On-Shore
Natural Gas
Production Industry —
Background Information
for Proposed Standards
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
May 1982
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'6 Emission Standards and Engineering Division of the Office of Air
annanHQ
produce s not ?rl H f ?? dS' EPA' and approved *>r publication. Mention of trade names or commercial
availab \l thrmmh fh ! 1 C°"stltute endorsement or recommendation for use. Copies of this report are
Ste *£* ? 2 r 9^1 (^ ! 6rViCeS Office {MD-35)' U'S- Environmental Protection Agency. Research
Springtld Virginia 221 61 ^ thS Natl"°nal Technical Information Services, 5285 Port Royal Road,
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TABLE OF CONTENTS
Section Page
1 SUMMARY 1-1
1.1 Regulatory Alternatives 1-1
1.2 Environmental Impact 1-2
1.3 Economic Impact 1-2
2 INTRODUCTION 2-1
2.1 Background and Authority for Standards 2-1
2.2 Selection of Categories of Stationary Sources . . 2-4
2.3 Procedure for Development of Standards of
Performance 2-6
2.4 Consideration of Costs 2-8
2.5 Consideration of Environmental Impacts 2-9
2.6 Impact on Existing Sources 2-10
2.7 Revision of Standards of Performance 2-11
3 THE ONSHORE NATURAL GAS PRODUCTION INDUSTRY 3-1
3.1 General Description 3-1
3.2 Sulfur Recovery Operations and Sulfur
Dioxide (S02) Emissions 3-7
3.2.1 Claus Sulfur Recovery Process 3-7
3.2.2 Claus Tail Gas Cleanup Processes 3-8
3.3 Baseline Control Emissions Levels 3-9
3.3.1 Sweetening Operation Emissions 3-11
3.3.2 Sulfur Recovery Operation Emissions .... 3-12
3.3.3 Baseline Control Emission Levels 3-12
3.4 References for Chapter 3 3-15
4 EMISSION CONTROL TECHNIQUES 4-1
4.1 General Description 4-1
m
-------
TABLE OF CONTENTS (continued)
Section
4.2 Sulfur Emission Control Technologies Used
In the Industry .....•••
4.2.1 Incineration 4-2
4.2.2 2-Stage Claus Sulfur Recovery Process ... 4-2
4.2.3 3-Stage Claus Sulfur Recovery Process ... 4-4
4.2.4 Recycle Selectox Process 4~9
4.2.5 3-Stage Claus Unit with Tail Gas
Clean-up Processes 4~H
4.3 Comparison of Source Emission Data and
Ralph M. Parsons Design Study 4-25
4.4 References for Chapter 4 4-27
5 MODIFICATION AND RECONSTRUCTION 5-1
5.1 Background 5-1
5.1.1 Modification 5-1
5.1.2 Reconstruction 5-2
5.2 Applicability to Onshore Production Industry . . . 5-3
5.2.1 Modifications to Onshore Production
Industry 5-3
5.2.2 Reconstructions to Onshore Production
Industry 5-4
5.3 References for Chapter 5 5-4
6 MODEL PLANTS AND REGULATORY ALTERNATIVES 6-1
6.1 Model Plants 6-1
6.1.1 Model Plant Sizes 6-14
6.1.2 H2S/C02 Volume Percent Ratio 6-14
6.1.3 Baseline Control Levels 6-14
6.2 Regulatory Alternatives 5_16
7 ENVIRONMENTAL IMPACT 7-!
7.1 Air Pollution Impact 7_1
7.1.1 Dispersion Modeling Results 7_-^
7.1.2 Effects of Regulatory Alternatives on
Nationwide S02 Emissions . . -, 0
if.
7.1.3 Secondary Impacts on Air Quality 1-12
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TABLE OF CONTENTS (continued)
Section Page
7.2 Water Pollution Impact 7-12
7.3 Solid Waste Disposal Impact 7-13
7.4 Energy Impacts 7-13
7.5 Other Environmental Concerns 7-21
7.5.1 Irreversible and Irretrievable
Commitment of Resources 7-21
7.5.2 Environmental Impact of Delayed Standards . 7-21
7.6 References for Chapter 7 7-22
8 COST ANALYSIS 8-1
8.1 Cost Analysis of Regulatory Alternatives 8-1
8.1.1 New Facilities 8-1
8.1.2 Modified or Reconstructed Facilities . . . 8-10
8.2 Other Cost Considerations 8-10
8.3 References for Chapter 8 8-18
9 ECONOMIC ANALYSIS OF THE ONSHORE NATURAL GAS
PRODUCTION INDUSTRY S02 NSPS 9-1
9.1 Industry Profile 9-1
9.1.1 Onshore Natural Gas Production Industry . . 9-1
9.1.2 Onshore Natural Gas Sulfur Recovery
Industry—Growth and Projections 9-33
9.2 Economic Impact Analysis 9-60
9.2.1 Economic Impact Assessment Methodology . . 9-63
9.2.2 Economic Impact of S02 NPSP Regulatory
Alternatives - Sour Gas Sweetening and
Sulfur Recovery Plants 9-77
9.3 Potential Socioeconomic and Inflationary Impacts . 9-95
9.4 References for Chapter 9 9-98
APPENDICES
A - Evolution of the Background Information Document . A-l
B - Index to Environmental Impact Considerations . . . B-l
C - Emission Source Tests Data C-l
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TABLE OF CONTENTS (concluded)
Section
D - Emission Measurement and Continuous Monitoring . . D-l
E - Sulfur Recovery Study - Onshore Sour Gas
Production Facilities ..... • .........
F - Unit Natural Gas Production Cost Equation
VI
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LIST OF TABLES
Table
1-1 Assessment of Environmental, Energy, and Economic
Impacts for Each Regulatory Alternative Considered
for Onshore Natural Gas Production Industry 1-3
3-1 Major Sweetening Processes 3-4
3-2 Baseline Controls and Baseline Emission Levels 3-14
4-1 Comparison of Source Emission Tests Data and the
Ralph M. Parsons Design Study for Claus Sulfur
Recovery Facilities 4-26
6-1 Model Plant Parameters 6-2
6-2 Onshore Natural Gas Production Model Plants, Baseline
Controls and Regulatory Alternatives 6-15
7-1 Summary of S02 Concentrations from Dispersion Modeling
Analyses for Each Model Plant and Regulatory Alternative
on the Basis of th Houston and Amarillo Data 7-3
7-2 Estimated S02 Emissions (1983-1987) from Projected
New Onshore Natural Gas Production Facilities
(Regulatory Alternative I) 7-5
7-3 Estimated S02 Emissions (1983-1987) from Projected
New Onshore Natural Gas Production Facilities
(Regulatory Alternative II) 7-6
7-4 Estimated S02 Emissions (1983-1987) from Projected
New Onshore Natural Gas Production Facilities
(Regulatory Alternative III) 7-7
7-5 Estimated S02 Emissions (1983-1987) from Projected
New Onshore Natural Gas Production Facilities
(Regulatory Alternative IV) 7-8
7-6 Estimated S02 Emissions (1983-1987) from Projected
New Onshore Natural Gas Production Facilities
(Regulatory Alternative V) 7-9
7-7 Estimated S02 Emissions (1983-1987) from Projected
New Onshore Natural Gas Production Facilities
(Regulatory Alternative VI) 7-10
7-8 Regulatory Alternative Effectiveness for Reducing
S02 Emissions from Projected Added New Onshore
Natural Gas Production Facilities 7-11
vii
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LIST OF TABLES (continued)
Table
Page
7-9 Energy Impact Analysis (Regulatory Alternative I) . • • 7-14
7-10 Energy Impact Analysis (Regulatory Alternative II) . . < 7-15
7-11 Energy Impact Analysis (Regulatory Alternative III) • • 7-16
7-12 Energy Impact Analysis (Regulatory Alternative IV) ... 7-17
7-13 Energy Impact Analysis (Regulatory Alternative V) ... 7-18
7-14 Energy Impact Analysis (Regulatory Alternative VI) ... 7-19
7-15 Onshore Natural Gas Production Sulfur Recovery
Facilities Projected National Fifth-Year (1987)
Energy Requirements for the Regulatory
Alternatives 7-20
8-1 Fixed-Capital Costs for 39 Cases of Sulfur Intake/Acid
Gas H2S/C02 Ratio/Sulfur Recovery Technology
Combinations 8-2
8-2 Fixed-Capital Costs for Each New Model Plant/
Regulatory Alternative Combinations 8-5
8-3 Components of Net Annualized Costs and Factors
To Calculate These Components 8-6
8-4 Net Annualized Costs for 39 Cases of Sulfur Intake/
Acid Gas H2S/C02 Ratio/Sulfur Recovery Technology
Combinations 8-8
8-5 Net Annualized Costs for Each New Model Plant/
Regulatory Alternative Combinations 8-9
8-6 Cost Analysis of Regulatory Alternatives for
Model Plant #1 8-11
8-7 Cost Analysis of Regulatory Alternatives for
Model Plant #2 8-12
8-8 Cost Analysis of Regulatory Alternatives for
Model Plant #3 8-13
8-9 Cost Analysis of Regulatory Alternatives for
Model Plant #4 8-14
8-10 Cost Analysis of Regulatory Alternatives for
Model Plant #5 8-15
8-11 Cost Analysis of Regulatory Alternatives for
Model Plant #6 8-16
8-12 Cost Analysis of Regulatory Alternatives for
Model Plant #7 8-17
9-1 Number, Average Size, and Total Production of
Producing Gas Wells, by State (Revised 1979
Figures) 9-4
vi ti
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LIST OF TABLES (continued)
Page
Estimated Costs of Drilling and Equipping Onshore
Wells, by Depth Intervals - 1979 9-6
9-3 Estimated Costs for Drilling and Equipping Onshore
Natural Gas Wells for Selected Well Depths, 1980 .... 9-7
9-4 Estimated Onshore Natural Gas Production Costs for
Selected Well Depths and Base Year Flow Rates,
1980 9-8
9-5 Onshore Natural Gas Sulfur Recovery Facility
Operators, 1979 9-11
9-6 Onshore Natural Gas Sulfur Recovery Facilities 9-13
9-7 Observed Frequency of Sulfur Recovery Plants by H2S
Percentage in Sour Natural Gas and Plant Capacity,
1980 9-22
9-8 Onshore Natural Gas Sulfur Recovery Facilities and
Sulfur Intake Capacity Utilization, 1950-1982 9-24
9-9 Sulfur Intake Capacity Distribution of Onshore
Natural Gas Sulfur Recovery Facilities, 1950-1982 . . . 9-27
9-10 Production of Energy by Type, United States 9-29
9-11 Aggregate Retail Price Elasticities of Demand, U.S. . . 9-31
9-12 Domestic Sulfur Supply - 1978 Statistics 9-35
9-13 Natural Gas Gross Withdrawals and Marketed Onshore
and Offshore Production, 1949-1979 9-37
9-14 Financial Data for the Natural Gas Industry 1976-1981
and 1983-1985 Estimates 9-41
9-15 Recovered Elemental Sulfur Produced in the United
States, 1960-1980 9-43
9-16 Time-Price Relationship for Sulfur, 1955-1981 9-44
9-17 Published Price for Liquid Sulfur at Tampa Terminals . . 9-46
9-18 Projected Lower-48 States Conventional Natural Gas
Production, 1980-2000 9-47
9-19 Projections of Natural Gas Supply: Comparison of
1990 Forecasts 9-49
9-20 Derivation of Newly Discovered Onshore Conventional
Natural Gas Production for a Specified Year,
1977-1987 9-51
9-21 Projected New Sulfur Recovery Capacities for the
Period of 1983-1987 9-52
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LIST OF TABLES (continued)
Table
9-22 Sulfur Recovered Per Unit Volume of Processed Sour
Natural Gas, 1954-1980 ................. y"D<3
9-23 Projected Added New Sulfur Recovery Facilities and
Their Sulfur Intake Size Distribution, 1983-1987 .... y-a/
9-24 Estimated Natural Gas Production, Onshore Volume,
Sweetened Volumes, Volumes Associated with Sulfur
Recovery, 1980 and 1987 ................ 9"58
9-25 Natural Gas Prices: History and Projections for
1965-1995 ....................... 9"59
9-26 Unit Emissions Control Costs and Expected
Profitability Impacts ................. 9~61
9-27 Increases in the Cumulative Number of Nonviable
Onshore Sour Natural Gas Sulfur Recovery Plants Due
to S02 NSPS ...................... 9-62
9-28 Onshore Sour Natural Gas Production Model Plants'
Estimated 1987 Sweet Gas Sales Per Plant ........ 9-71
9-29 Onshore Sour Natural Gas Production Model Plants'
Estimated 1987 Sulfur Sales by Regulatory Alternatives
per Plant ....................... 9-72
9-30 Estimated Onshore Natural Gas Production Costs and
Probability Estimates for Selected Well Depths and
Base Year Flow Rates, 1980 ............... 9-74
9-31 Onshore Sour Natural Gas Production Model Plants'
Bef ore-Tax Annual i zed Cost of S02 NSPS Regulatory
Alternatives per Plant ................. 9-78
9-32 Onshore Sour Natural Gas Production Model Plants'
After-Tax Annual i zed Cost of S02 NSPS Regulatory
Alternatives per Plant ................. 9-79
9-33 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 1) ..... 9-80
9-34 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 2A) ..... 9-81
9-35 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 2B) ..... 9-82
9-36 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 3A) ..... 9-83
9-37 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 3B) ..... 9-84
9-38 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 4) ..... 9-85
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LIST OF TABLES (continued)
Table Page
9-39 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 5) 9-86
9-40 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 6) 9-87
9-41 Onshore Sour Natural Gas Production Model Plants'
Emission Control Cost per Mcf (Model Plant 7) 9-88
9-42 Onshore Sour Natural Gas Production, Total Before
Tax Net Annualized Cost of S02 NSPS Regulatory
Alternatives, 1987 9-96
B-l Index to Environmental Impact Considerations B-2
C-l Sampling/Analysis Parameters and Methodology at
Warren Petroleum's Monument Plant Facility C-5
C-2 Warren Petroleum's Monument Plant Facility Test
Results Summary C-6
C-3 Warren Petroleum's Monument Plant Facility: Daily
Average Stack Gas Velocity, Temperature, Composition
and Actual Flow Rate During the Test Period C-8
C-4 Daily S02, H2S (as S02) and TRS (as S02) Emissions
During the Test Period C-9
C-5 Daily N0x Test Results and Stack Emissions C-10
C-6 Warren Petroleum's Monument Plant Facility Operating
Conditions During the Test Period C-ll
C-7 Sampling/Analysis Parameters and Methodology at Getty
Oil's New Hope Facility C-17
C-8 Getty Oil's New Hope Facility Test Results Summary . . . C-18
C-9 Getty Oil's New Hope Facility: Daily Average Stack
Gas Velocity, Temperature, Composition and Actual
Flow Rate During the Test Period C-20
C-10 Daily S02, H2S (as S02) and TRS (as S02) Emissions
During the Test Period C-21
C-ll Daily NOX Test Results and Stack Emissions C-22
C-12 Getty Oil's New Hope Facility Operation Conditions
During the Test Period C-23
C-13 Sampling/Analysis Parameters and Methodology at
Shell Oil's Thomasville Facility C-28
C-14 Shell Oil's Thomasville Facility Test Results
Summary C-29
-------
LIST OF TABLES (continued)
Table
C-15 Shell Oil's Thomasville Facility: Daily Average
Stack Gas Velocity, Temperature, Composition and Actual
Flow Rate During the Test Period • • •
C-16 Daily S02, H2S (as S02) and TRS (as S02) Emissions
During the Test Period • L
C-17 Daily N0x Test Results and Stack Emissions C-33
C-18 Shell Oil's Thomasville Facility Operating Conditions
During the Test Period c~34
C-19 Comparison of EPA/Emissions Measurement Branch (EMB)
Tests Results and the Company's Operations Support
Laboratory Test Results at the Thomasville Facility . . C-36
C-20 Exxon's Blackjack Creek Facility Annual Stack
Emission Tests Data C-40
C-21 Shell Oil's Bryans Mill Facility Source Emission
Tests Data C-41
C-22 Shell Oil's Person Plant Facility Source Emission
Tests Data C-43
E-l Feed Gas Compositions E-8
E-2 End-of-Run Sulfur Emission as S02 and Stack Height
(Acid Gas Ratios - 80/20 and 50/50) E-9
E-3 End-of-Run Sulfur Emission as S02 and Stack Height
(Acid Gas Ratio - 20/80) E-10
E-4 End-of-Run Sulfur Emission as S02 and Stack Height
(Acid Gas Ratio - 12.5/87.5) E-ll
E-5 Composition of Exit Gases (Ib mols/hr) End-of-Run
(Acid Gas Ratios - 80/20 and 50/50) E-13
E-6 Composition of Exit Gases (Ib mols/hr) End-of-Run
(Acid Gas Ratio - 20/80) E-14
E-7 Composition of Exit Gases (Ib mols/hr) End-of-Run
(Acid Gas Ratio - 12.5/87.5) E-15
E-8 Investment Costs and Sulfur Emissions (End-of-Run)
(Acid Gas Ratios - 80/20 and 50/50) E-36
E-9 Investment Costs and Sulfur Emissions (End-of-Run)
(Acid Gas Ratio - 20/80) E-37
E-10 Investment Costs and Sulfur Emissions (End-of-Run)
(Acid Gas Ratio - 12.5/87.5) E-38
E-ll Summary of Investment Costs by Units (MM$) (Acid
Gas Ratios - 50/50 and 80/20) E-39
xn
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LIST OF TABLES (concluded)
Jable Page
E-12 Summary of Investment Costs by Units (MM$) (Acid
Gas Ratio - 20/80) E-40
E-13 Summary of Investment Costs by Units (MM$) (Acid
Gas Ratio - 12.5/87.5) E-41
E-14 Cost of Initial Charge of Catalysts and Chemicals
(Acid Gas Ratios - 80/20 and 50/50) E-43
E-15 Cost of Initial Charge of Catalysts and Chemicals
(Acid Gas Ratio - 20/80) E-44
E-16 Cost of Initial Charge of Catalysts and Chemicals
(Acid Gas Ratio - 12.5/87.5) E-45
E-17 Utilities and Catalyst Costs - Recycle Selectox
2-Stage Process E-47
E-18 Utilities and Catalyst Costs - Claus Process - No Tail
Gas or Waste Heat Recovery Units E-48
E-19 Utilities and Catalyst Costs - Claus Process - With
Waste Heat Recovery - No Tail Gas Unit E-49
E-20 Utilities and Catalyst Costs - BSR/MDEA Tail Gas
Cases E-50
E-21 Utilities and Catalyst Costs - Recycle Selectox
3-Stage Process E-51
E-22 Utilities and Catalyst Costs - Beavon Sulfur Removal
Process (BSRP) E-52
E-23 Utilities and Catalyst Costs - BSR/Selectox Process . . E-53
E-24 Utilities and Catalyst Costs - Sulfreen Process .... E-54
E-25 Sulfur Recovered (LT/D), Average During Run (Acid
Gas Ratios - 80/20 and 50/50) E-56
E-26 Sulfur Recovered (LT/D), Average During Run (Acid
Gas Ratio - 20/80) E-57
E-27 Sulfur Recovered (LT/D), Average During Run (Acid
Gas Ratio - 12.5/87.5) E-58
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LIST OF FIGURES
Figure
3-1 Production and processing operations and associated
emissions 3-2
3-2 Typical sour natural gas amine sweetening facility ... 3-6
3-3 Glaus tail gas clean-up processes 3-10
4-1 Flow diagram for a two-stage Glaus sulfur recovery
plant • 4-3
4-2 Flow diagram for a three-stage Glaus sulfur recovery
facility utilizing the straight-through process
configuration .- 4-7
4-3 Flow diagram for the split-flow configuration of
the Glaus sulfur recovery process 4-8
4-4 Flow diagram for the sulfur recycle configuration of
the Glaus sulfur recovery process 4-10
4-5 Recycle Selectox 2-stage process 4-12
4-6 Recycle Selectox 3-stage process 4-13
4-7 Flow diagram for the Shell Glaus Off-gas Treatment
(SCOT) process ..... 4-16
4-8 Flow diagram for the Sulfreen tail gas clean-up
process 4-18
4-9 Flow diagram for the Beavon Sulfur Removal process
(BSRP) 4-20
4-10 Flow diagram for the BSR/Selectox I Glaus tail gas
clean-up process 4-22
9-1 Sulfur recovery facility additions, 1950-1982 9-25
9-2 Sulfur recovery capacity additions, 1950-1982 9-26
9-3 U.S. domestic sulfur production from various sources
for the period 1950-1980 9-32
9-4 Trends in the production of sulfur in the U.S 9-34
9-5 Natural gas gross withdrawals and marketed
production 9~38
9-6 Onshore and offshore marketed natural gas production . . 9-39
xiv
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LIST OF FIGURES (concluded)
Figure Page
9-7 Selected natural gas prices—three categories for
the period 1955-1979 9-40
9-8 Approximate cumulative distribution of natural
gas production costs from new wells in 1987
(1980 $/Mcf) 9-75
C-l Simplified flow diagram for Warren Petroleum's
Monument plant facility C-4
C-2 Summary of liquid sulfur production, stack S02
emissions and sulfur recovery efficiency at
Warren Petroleum's Monument plant facility ....... C-7
C-3 Simplified flow diagram for Getty Oil's New
Hope facility C-15
C-4 Summary of liquid sulfur production, stack S02
emissions and sulfur recovery efficiency at Getty
Oil's New Hope facility C-19
C-5 Simplified flow diagram for Shell Oil's Thomasville
facility C-26
C-6 Summary of liquid sulfur production, stack S02
emissions and sulfur recovery efficiency at Shell
Oil's Thomasville facility C-30
C-7 Simplified flow diagram for Exxon's Blackjack Creek
facility C-39
E-l Recycle Selectox 2-stage process E-17
E-2 Recycle Selectox 3-stage process E-18
E-3 Claus 2-stage process E-21
E-4 Claus 3-stage process E-22
E-5 Claus sulfur-burning 2-stage process E-23
E-6 Claus sulfur-burning 3-stage process E-24
E-7 Thermal oxidizers, waste heat boilers, and stacks . . . E-26
E-8 BSR/MDEA process E-28
E-9 Beavon Sulfur Removal Process (BSRP) E-30
E-10 Sulfreen process E-32
E-ll BSR/Selectox process E-34
xv
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1. SUMMARY
Standards of performance for new stationary sources are established
under Section 111 of the Clean Air Act (42 U.S.C. 7411), as amended in
1977. Section 111 directs the Administrator to establish standards of
performance for any category of new stationary source of air pollution
which ". . . causes or contributes significantly to air pollution which
may reasonably be anticipated to endanger public health or welfare."
This background information document (BID) supports the proposed stan-
dards, which would control sulfur dioxide (S02) emissions from onshore
natural gas production facilities.
The onshore natural gas production industry is involved in producing
pipeline quality (sweet) natural gas. Over 80 percent of the onshore
production, and all of the offshore production is sweet. The remaining
fraction, however, contains acid gases (sour gases) and is routinely
sweetened to reduce the hydrogen sulfide (H2S) and carbon dioxide (C02)
content to levels that are acceptable for pipeline distribution. Elemental
sulfur may be recovered from H2S in the separated acid gas (H2S and C02)
stream for those onshore production facilities that sweeten the sour
gas. The residual H2S is oxidized to S02, and released to the atmosphere.
1.1 REGULATORY ALTERNATIVES
To evaluate the environmental, economic, and energy impacts associated
with implementation of a standard for the onshore natural gas production
industry, the Administrator has examined a number of regulatory alternatives
for controlling S02 emissions. The six regulatory alternatives selected
for evaluation are summarized as follows:
o Regulatory Alternative I - No standards of performance would
be promulgated for the onshore natural gas production facilities.
This alternative assumes that current state and local regulations
1-1
-------
are applied to the industry (baseline control). Baseline
control technologies range from incineration (zero percent S02
reduction) to the Claus process (2- or 3-stage, 91.3 to
96.6 percent S02 reduction) depending on plant size and acid
gas H2S/C02 ratio.
o Regulatory Alternatives II through VI - Regulatory Alternatives II
through VI apply four control technologies in different combi-
nations to differing plant sizes resulting in progressively
more stringent levels of S02 emissions reduction. The technologies
include the Claus process (2-stage, 91.3 to 95.1 percent S02
reduction; 3-stage, 93.4 to 96.6 percent S02 reduction), the
Sulfreen process (97.5 to 98.5 percent S02 reduction), The
Shell Claus Offgas Treatment process (99.87 to 99.98 percent
S02 reduction) and the Beavon Sulfur Recovery process (99.87 to
99.98 percent S02 reduction). Regulatory Alternatives II
through VI progressively increase in cost per megagram of S02
reduced. The impacts of each regulatory alternative are
assessed through analyses of their impacts on individual plant
sizes. Nationwide impacts are determined based on a projected
distribution of plant sizes to be constructed.
1.2 ENVIRONMENTAL IMPACT
The environmental and energy impacts of the regulatory alternatives
are summarized in Table 1-1. Regulatory Alternative I has the only
adverse air impact while Alternatives III through VI produce significant
emission reductions. No adverse water or solid waste impacts are associated
with any of the regulatory alternatives. Regulatory Alternative IV
produces the maximum emission reductions without large adverse energy
impacts. The environmental and energy impacts are discussed in detail
in Chapter 7 of the BID.
1.3 ECONOMIC IMPACT
The estimated economic impacts also are summarized in Table 1-1.
Regulatory Alternatives V and VI have large adverse economic impacts.
The economic impacts of Regulatory Alternatives I through IV range from
1-2
-------
Table 1-1. ASSESSMENT OF ENVIRONMENTAL, ENERGY, AND ECONOMIC IMPACTS FOR EACH REGULATORY
ALTERNATIVE CONSIDERED FOR ONSHORE NATURAL GAS PRODUCTION INDUSTRY3
Administrative
alternative
Regulatory Alternative I
Regulatory Alternative II
Regulatory Alternative III
Regulatory Alternative IV
Regulatory Alternative V
Regulatory Alternative VI
Air
impact
-3**
+2**
+3**
+4**
+4**
+4**
Water
impact
0
0
0
0
0
0
Solid
waste
impact
0
0
0
0
0
0
Energy Economic
impact impact
0 0
-1** 0
_!** _!**
_!** _!**
_!** -3**
_^** -5**
KEY: + Beneficial impact
- Adverse impact
0 No impact
1 Negligible impact
2 Small impact
3 Moderate impact
4 Large impact
5 Very large impact
* Short term impact
** Long term impact
***
Irreversible impact
-------
no impact to a small adverse impact. Regulatory Alternative IV has the
greatest beneficial air quality impact without a large adverse economic
impact. The economic impacts are discussed in detail in Chapter 9 and
cost analyses are discussed in Chapter 8 of the BID.
1-4
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2. INTRODUCTION
2.1 BACKGROUND AND AUTHORITY FOR STANDARDS
Before standards of performance are proposed as a Federal regulation,
air pollution control methods available to the affected industry and the
associated costs of installing and maintaining the control equipment are
examined in detail. Various levels of control based on different technolo-
gies and degrees of efficiency are expressed as regulatory alternatives.
Each of these alternatives is studied by EPA as a prospective basis for a
standard. The alternatives are investigated in terms of their impacts on
the economics and well-being of the industry, the impacts on the national
economy, and the impacts on the environment. This document summarizes the
information obtained through these studies so that interested persons will
be privy to the information considered by EPA in the development of the
proposed standard.
Standards of performance for new stationary sources are established
under Section 111 of the Clean Air Act (42 U.S.C. 7411) as amended, herein-
after referred to as the Act. Section 111 directs the Administrator to
establish standards of performance for any category of new stationary
source of air pollution which ". . . causes, or contributes significantly
to air pollution which may reasonably be anticipated to endanger public
health or welfare."
The Act requires that standards of performance for stationary sources
reflect, ". . . the degree of emission reduction achievable which (taking
into consideration the cost of achieving such emission reduction, and any
nonair quality health and environmental impact and energy requirements) the
Administrator determines has been adequately demonstrated for that category
of sources." The standards apply only to stationary sources, the construc-
tion or modification of which commences after regulations are proposed by
publication in the Federal Register.
2-1
-------
The 1977 amendments to the Act altered or added numerous provisions
that apply to the process of establishing standards of performance.
1. EPA is required to list the categories of major stationary sources
that have not already been listed and regulated under standards of perfor-
mance. Regulations must be promulgated for these new categories on the
following schedule:
a. 25 percent of the listed categories by August 7, 1980.
b. 75 percent of the listed categories by August 7, 1981.
c. 100 percent of the listed categories by August 7, 1982.
A governor of a State may apply to the Administrator to add a category not
on the list or may apply to the Administrator to have a standard of perfor-
mance revised.
2. EPA is required to review the standards of performance every
4 years and, if appropriate, revise them.
3. EPA is authorized to promulgate a standard based on design, equip-
ment, work practice, or operational procedures when a standard based on
emission levels is not feasible.
4. The term "standards of performance" is redefined, and a new term
"technological system of continuous emission reduction" is defined. The new
definitions clarify that the control system must be continuous and may
include a low- or non-polluting process or operation.
5. The time between the proposal and promulgation of a standard under
section 111 of the Act may be extended to 6 months.
Standards of performance, by themselves, do not guarantee protection
of health or welfare because they are not designed to achieve any specific
air quality levels. Rather, they are designed to reflect the degree of
emission limitation achievable through application of the best adequately
demonstrated technological system of continuous emission reduction, taking
into consideration the cost of achieving such emission reduction, any
nonair-quality health and environmental impacts, and energy requirements.
Congress had several reasons for including these requirements. First,
standards with a degree of uniformity are needed to avoid situations where
some States may attract industries by relaxing standards relative to other
States. Second, stringent standards enhance the potential for long-term
2-2
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growth. Third, stringent standards may help achieve long-term cost savings
by avoiding the need for more expensive retrofitting when pollution ceilings
may be reduced in the future. Fourth, certain types of standards for coal-
burning sources can adversely affect the coal market by driving up the
price of low-sulfur coal or effectively excluding certain coals from the
reserve base because their untreated pollution potentials are high. Con-
gress does not intend that new source performance standards contribute to
these problems. Fifth, the standard-setting process should create incen-
tives for improved technology.
Promulgation of standards of performance does not prevent State or
local agencies from adopting more stringent emission limitations for the
same sources. States are free under Section 116 of the Act to establish
even more stringent emission limits than those established under Section 111
or those necessary to attain or maintain the National Ambient Air Quality
Standards (NAAQS) under Section 110. Thus, new sources may in some cases
be subject to limitations more stringent than standards of performance
under Section 111, and prospective owners and operators of new sources
should be aware of this possibility in planning for such facilities.
A similar situation may arise when a major emitting facility is to be
constructed in a geographic area that falls under the prevention of signi-
ficant deterioration of air quality provisions of Part C of the Act. These
provisions require, among other things, that major emitting facilities to
be constructed in such areas are to be subject to best available control
technology. The term Best Available Control Technology (BACT), as defined
in the Act, means
... an emission limitation based on the maximum degree of
reduction of each pollutant subject to regulation under
this Act emitted from, or which results from, any major
emitting facility, which the permitting authority, on a
case-by-case basis, taking into account energy, environ-
mental, and economic impacts and other costs, determines is
achievable for such facility through application of produc-
tion processes and available methods, systems, and techniques,
including fuel cleaning or treatment or innovative fuel
combustion techniques for control of each such pollutant.
In no event shall application of 'best available control
technology1 result in emissions of any pollutants which
will exceed the emissions allowed by any applicable standard
established pursuant to Sections 111 or 112 of this Act.
(Section 169(3))
2-3
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Although standards of performance are normally structured in terms of
numerical emission limits where feasible, alternative approaches are some-
times necessary. In some cases physical measurement of emissions from a
new source may be impractical or exorbitantly expensive. Section lll(h)
provides that the Administrator may promulgate a design or equipment stan-
dard in those cases where it is not feasible to prescribe or enforce a
standard of performance. For example, emissions of hydrocarbons from
storage vessels for petroleum liquids are greatest during tank filling.
The nature of the emissions, high concentrations for short periods during
filling and low concentrations for longer periods during storage, and the
configuration of storage tanks make direct emission measurement impractical.
Therefore, a more practical approach to standards of performance for storage
vessels has been equipment specification.
In addition, Section lll(j) authorizes the Administrator to grant
waivers of compliance to permit a source to use innovative continuous
emission control technology. In order to grant the waiver, the Admini-
strator must find: (1) a substantial likelihood that the technology will
produce greater emission reductions than the standards require or an equi-
valent reduction at lower economic energy or environmental cost; (2) the
proposed system has not been adequately demonstrated; (3) the technology
will not cause or contribute to an unreasonable risk to the public health,
welfare, or safety; (4) the governor of the State where the source is
located consents; and (5) the waiver will not prevent the attainment or
maintenance of any ambient standard. A waiver may have conditions attached
to assure the source will not prevent attainment of any NAAQS. Any such
condition will have the force of a performance standard. Finally, waivers
have definite end dates and may be terminated earlier if the conditions are
not met or if the system fails to perform as expected. In such a case, the
source may be given up to 3 years to meet the standards with a mandatory
progress schedule.
2.2 SELECTION OF CATEGORIES OF STATIONARY SOURCES
Section 111 of the Act directs the Administrator to list categories of
stationary sources. The Administrator "... shall include a category
2-4
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of sources in such list if in his judgement it causes, or contributes
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare." Proposal and promulgation of standards
of performance are to follow.
Since passage of the Clean Air Amendments of 1970, considerable
attention has been given to the development of a system for assigning
priorities to various source categories. The approach specifies areas of
interest by considering the broad strategy of the Agency for implementing
the Clean Air Act. Often, these "areas" are actually pollutants emitted by
stationary sources. Source categories that emit these pollutants are
evaluated and ranked by a process involving such factors as: (1) the level
of emission control (if any) already required by State regulations, (2) esti-
mated levels of control that might be required from standards of performance
for the source category, (3) projections of growth and replacement of
existing facilities for the source category, and (4) the estimated incremental
amount of air pollution that could be prevented in a preselected future
year by standards of performance for the source category. Sources for
which new source performance standards were promulgated or under development
during 1977, or earlier, were selected on these criteria.
The Act amendments of August 1977 establish specific criteria to be
used in determining priorities for all major source categories not yet
listed by EPA. These are: (1) the quantity of air pollutant emissions
that each such category will emit, or will be designed to emit; (2) the
extent to which each such pollutant may reasonably be anticipated to endan-
ger public health or welfare; and (3) the mobility and competitive nature
of each such category of sources and the consequent need for nationally
applicable new source standards of performance.
The Administrator is to promulgate standards for these categories
according to the schedule referred to earlier.
In some cases it may not be feasible immediately to develop a standard
for a source category with a high priority. This might happen when a
program of research is needed to develop control techniques or because
techniques for sampling and measuring emissions may require refinement. In
the developing of standards, differences in the time required to complete
2-5
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the necessary investigation for different source categories must also be
considered. For example, substantially more time may be necessary if
numerous pollutants must be investigated from a single source category.
Further, even late in the development process the schedule for completion
of a standard may change. For example, inablility to obtain emission data
from well-controlled sources in time to pursue the development process in a
systematic fashion may force a change in scheduling. Nevertheless, priority
ranking is, and will continue to be, used to establish the order in which
projects are initiated and resources assigned.
After the source category has been chosen, the types of facilities
within the source category to which the standard will apply must be deter-
mined. A source category may have several facilities that cause air pollu^
tion, and emissions from some of these facilities may vary from insignificant
to very expensive to control. Economic studies of the source category and
of applicable control technology may show that air pollution control is
better served by applying standards to the more severe pollution sources.
For this reason, and because there is no adequately demonstrated system for
controlling emissions from certain facilities, standards often do not apply
to all facilities at a source. For the same reasons, the standards may not
apply to all air pollutants emitted. Thus, although a source category may
be selected to be covered by a standard of performance, not all pollutants
or facilities within that source category may be covered by the standards.
2.3 PROCEDURE FOR DEVELOPMENT OF STANDARDS OF PERFORMANCE
Standards of performance must (1) realistically reflect best demon-
strated control practice; (2) adequately consider the cost, the nonair-
quality health and environmental impacts, and the energy requirements of
• '' ••',
such control; (3) be applicable to existing sources that are modified or
reconstructed as well as new installations; and (4) meet these conditions
for all variations of operating conditions being considered anywhere in the
country.
The objective of a program for developing standards is to identify the
' "" " ' 17r''' ' '
best technological system of continuous emission reduction that has been
' :' '''>, '' -',.,"•!. '-
adequately demonstrated. The standard-setting process involves three
principal phases of activity: (1) information gathering, (2) analysis of
the information, and (3) development of the standard of performance.
2-6
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During the information-gathering phase, industries are queried through
a telephone survey, letters of inquiry, and plant visits by EPA representa-
tives. Information is also gathered from many other sources to provide
reliable data that characterize the pollutant emissions from well-controlled
existing facilities.
In the second phase of a project, the information about the industry
and the pollutants emitted is used in analytical studies. Hypothetical
"model plants" are defined to provide a common basis for analysis. The
model plant definitions, national pollutant emission data, and existing
State regulations governing emissions from the source category are then
used in establishing "regulatory alternatives." These regulatory alterna-
tives are essentially different levels of emission control.
EPA conducts studies to determine the impact of each regulatory alterna-
tive on the economics of the industry and on the national economy, on the
environment, and on energy consumption. From several possibly applicable
alternatives, EPA selects the single most plausible regulatory alternative
as the basis for a standard of performance for the source category under
study.
In the third phase of a project, the selected regulatory alternative
is translated into a standard of performance, which, in turn, is written in
the form of a Federal regulation. The Federal regulation, when applied to
newly constructed plants, will limit emissions to the levels indicated in
the selected regulatory alternative.
As early as is practical in each standard-setting project, EPA represen-
tatives discuss the possibilities of a standard and the form it might take
with members of the National Air Pollution Control Techniques Advisory
Committee. Industry representatives and other interested parties also
participate in these meetings.
The information acquired in the project is summarized in the Background
Information Document (BID). The BID, the standard, and a preamble explaining
the standard are widely circulated to the industry being considered for
control, environmental groups, other government agencies, and offices
within EPA. Through this extensive review process, the points of view of
expert reviewers are taken into consideration as changes are made to the
documentation.
2-7
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A "proposal package" is assembled and sent through the offices of EPA
Assistant Administrators for concurrence before the proposed standard is
officially endorsed by the EPA Administrator. After being approved by the
EPA Administrator, the preamble and the proposed regulation are published
in the Federal Register.
As a part of the Federal Register announcement of the proposed regula-
tion, the public is invited to participate in the standard-setting process.
EPA invites written comments on the proposal and also holds a public hearing
to discuss the proposed standard with interested parties. All public comments
are summarized and incorporated into a second volume of the BID. All
information reviewed and generated in studies in support of the standard of
performance is available to the public in a "docket" on file in Washington,
D. C.
Comments from the public are evaluated, and the standard of performance
may be altered in response to the comments.
The significant comments and EPA's position on the issues raised are
included in the "preamble" of a "promulgation package," which also contains
the draft of the final regulation. The regulation is then subjected to
another round of review and refinement until it is approved by the EPA
Administrator. After the Administrator signs the regulation, it is published
as a "final rule" in the Federal Register.
2.4 CONSIDERATION OF COSTS
Section 317 of the Act requires an economic impact assessment with
respect to any standard of performance established under Section 111 of the
Act. The assessment is required to contain an analysis of: (1) the costs
of compliance with the regulation, including the extent to which the cost
of compliance varies depending on the effective date of the regulation and
the development of less expensive or more efficient methods of compliance;
(2) the potential inflationary or recessionary effects of the regulation;
(3) the effects the regulation might have on small business with respect to
competition; (4) the effects of the regulation on consumer costs; and (5)
the effects of the regulation on energy use. Section 317 also requires that
the economic impact assessment be as extensive as practicable.
2-8
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The economic impact of a proposed standard upon an industry is usually
addressed both in absolute terms and in terms of the control costs that
would be incurred as a result of compliance with typical, existing State
control regulations. An incremental approach is necessary because both new
and existing plants would be required to comply with State regulations in
the absence of a Federal standard of performance. This approach requires a
detailed analysis of the economic impact from the cost differential that
would exist between a proposed standard of performance and the typical
State standard.
Air pollutant emissions may cause water pollution problems, and cap-
tured potential air pollutants may pose a solid waste disposal problem. The
total environmental impact of an emission source must, therefore, be ana-
lyzed and the costs determined whenever possible.
A thorough study of the profitability and price-setting mechanisms of
the industry is essential to the analysis so that an accurate estimate of
potential adverse economic impacts can be made for proposed standards. It
is also essential to know the capital requirements for pollution control
systems already placed on plants so that the additional capital requirements
necessitated by these Federal standards can be placed in proper perspective.
Finally, it is necessary to assess the availability of capital to provide
the additional control equipment needed to meet the standards of performance.
2.5 CONSIDERATION OF ENVIRONMENTAL IMPACTS
Section 102(2)(C) of the National Environmental Policy Act (NEPA) of
1969 requires Federal agencies to prepare detailed environmental impact
statements on proposals for legislation and other major Federal actions
significantly affecting the quality of the human environment. The objective
of NEPA is to build into the decisionmaking process of Federal agencies a
careful consideration of all environmental aspects of proposed actions.
In a number of legal challenges to standards of performance for various
industries, the United States Court of Appeals for the District of Columbia
Circuit has held that environmental impact statements need not be prepared
by the Agency for proposed actions under Section 111 of the Clean Air Act.
Essentially, the Court of Appeals has determined that the best system of
emission reduction requires the Administrator to take into account counter-
2-9
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productive environmental effects of a proposed standard, as well as economic
costs to the industry. On this basis, therefore, the Court established a
narrow exemption from NEPA for EPA determination under Section 111.
In addition to these judicial determinations, the Energy Supply and
Environmental Coordination Act (ESECA) of 1974 (PL-93-319) specifically
exempted proposed actions under the Clean Air Act from NEPA requirements.
According to Section 7(c)(l), "No action taken under the Clean Air Act
shall be deemed a major Federal action significantly affecting the quality
of the human environment within the meaning of the National Environmental
Policy Act of 1969" (15 U.S.C. 793(c)(l)>.
Nevertheless, the Agency has concluded that the preparation of environ-
mental impact statements could have beneficial effects on certain regulatory
actions. Consequently, although not legally required to do so by
Section 102(2)(C) of NEPA, EPA has adopted a policy requiring that environ-
mental impact statements be prepared for various regulatory actions, including
standards of performance developed under Section 111 of the Act. This
voluntary preparation of environmental impact statements, however, in no
way legally subjects the Agency to NEPA requirements.
To implement this policy, a separate section in this document is
devoted solely to an analysis of the potential environmental impacts asso^
ciated with the proposed standards. Both adverse and beneficial impacts in
such areas as air and water pollution, increased solid waste disposal, and
increased energy consumption are discussed.
2.6 IMPACT ON EXISTING SOURCES
Section 111 of the Act defines a new source as ". . . any stationary
source, the construction or modification of which is commenced . . ." after
the proposed standards are published. An existing source is redefined as a
new source if "modified" or "reconstructed" as defined in amendments to the
general provisions of Subpart A of 40 CFR Part 60, which were promulgated
in the Federal Register on December 16, 1975 (40 FR 58416).
Promulgation of a standard of performance requires States to establish
standards of performance for existing sources in the same industry under
Section 111 (d) of the Act if the standard for new sources limits emissions
of a designated pollutant (i.e., a pollutant for which air quality criteria
2-10
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have not been issued under Section 108 or which has not been listed as a
hazardous pollutant under Section 112). If a State does not act, EPA must
establish such standards. General provisions outlining procedures for
control of existing sources under Section lll(d) were promulgated on
November 17, 1975, as Subpart B of 40 CFR Part 60 (40 FR 53340).
2.7 REVISION OF STANDARDS OF PERFORMANCE
Congress was aware that the level of air pollution control achievable
by any industry may improve with technological advances. Accordingly,
section 111 of the Act provides that the Administrator ". . . shall, at
least every 4 years, review and, if appropriate, revise . . ." the standards
Revisions are made to assure that the standards continue to reflect the
best systems that become available in the future. Such revisions will not
be retroactive, but will apply to stationary sources constructed or modified
after the proposal of the revised standards.
2-11
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3. THE ONSHORE NATURAL GAS PRODUCTION INDUSTRY
The onshore crude oil and natural gas production industry involves
a large number of similar yet distinct industrial processes linked
together in widely differing combinations to meet a common purpose.
That purpose is to remove hydrocarbons and associated compounds from
subterranean deposits of oil and gas and to produce marketable products
for industrial, commercial, and residential use. On a detailed level,
the methods of removing the oil and gas from the earth, the process
operations employed, and the products produced all vary as greatly as
the types of geologic formations containing oil and gas, the properties
of the well materials obtained, and the markets for which the products
are produced. However, on a more general level, the industry can be
described by several operations and installations distinguished from one
another primarily by the purpose or function they serve.
3.1 GENERAL DESCRIPTION
Three basic operations within the onshore crude oil and natural gas
production industry that are important to the control of sulfur compounds
emissions into the atmosphere are production operations, sweetening
operations, sulfur recovery operations, and incineration operations.
Figure 3-1 shows a generalized flow diagram of major industry operations
and the emission sources associated with each operation.
Production operations for the onshore crude oil and natural gas
industry consist of bringing reservoir fluids to the surface and providing
the field processing or treatment required to produce commercial products.
The purpose of the first major operation, well drilling, is to produce a
point of access to the subterranean deposit for exploration, oil and gas
production, water injection, gas injection, or other purposes.
3-1
-------
ro
TANK BATTERt SWEETENING PROCESS
Combustion Products
i — •• Gas for Equipment •• —
»fatl»'lvf Safety Valve ,u SI
A |j l"2-M
4 Liquid/Gat («.Vt*,K',r».Hi Sweetening
T ,.,...» ijfmr*wo_i _.*
1 *•«"- gUquldHC
__., . _J u . O«<««»ott *«ld Gas
and'on | ReiV' (M2S * CV
NATURAL GAS LIQUIDS PLANT
Greatest Amount
ofHCruqltlves combustion Product)
r,,^. u.|... T IftLHC fMOltl»«S '
Safetv Valve 1 (991.
T , 1 ,- 'V
(Varylno
•^ Complexity) "^ tewpn
till
•••i Temporary
™ Pressurized
*" S UirtJUL stortgt
^Incinerator (SOgl (~1SO psl)
|| combustion
I, -^T^ , _^nr
11 i Gi* Retul «"* .- t.lf^r "^
Oil/Water ^ JyltB|| S"Hur
1 Plant
HC Storage Lost Uatar 011
t
Disposal •• TreatJiient Yeg*
(75-100 ppm Tar) Hydroearoon Rtturncd to System
Mrellne-* I,^L , ^ t* 1 StoTTge J L1 1d B.ca«,rv
| (Pressurized) | U-UiuU Recovery
1 i 1- fc».;l
Transfer
JLsai
Oil toSale/Y J
(Refinery)'' Q O O
| ^^ ^^
1 neritor
^' Tall Gas
» ri ».•.!» > Residual Tall Gi
Inclneratinr
Cl>
..„ 1 97-99t Gas to Sales
'" R (lOOllvl. Pipeline)
on Varies)
LNG Plant
(Location Variable)
IS (SO,)
»
f>~-__-^1 SULFUR PLANT
*1 Liquid 1
1 Sulfur J
Sulfur Sales
or Disposal
Figure 3-1. Production and processing operations and associated emissions.
-------
The next major processing operations applied to natural gas after
it has been removed from gas wells or gas/oil wells are the gas-liquid
separation operation and the sweetening operation. Only the fraction of
the onshore natural gas that is "sour" is sweetened. Sweetening is the
removal of hydrogen sulfide (H2S) and carbon dioxide (C02) gases present
in "sour" natural gas. Sour gas is natural gas with a H2S concentration
greater than 0.25 grains per 100 standard cubic feet. Sour natural gas
contains widely differing concentrations of H2S and C02 and trace amounts
of organic sulfur compounds such as mercaptans (RSH). H2S is rarely
less than 95 percent of the total sulfur content.2
Removal of H2S and C02 from natural gas streams is necessary to
make the natural gas suitable for consumer use. Specifications on the
degree of H2S removal allowed are essentially standard and uniform
across the United States. The maximum H2S content is 0.25 grains of H2S
per 100 standard cubic feet (4 ppmv H2S) of sweetened natural gas. This
standard remains unchanged as the criterion for "sweet gas" in most
natural gas applications. Sweet natural gas is also termed "residue
gas" in the industry. Generally, C02 may be transported in natural gas
streams as long as the quantity of C02 does not reach the point of
seriously lowering the heating value of the gas.
Currently, there are a number of processes used to sweeten sour
natural gases. These processes are listed and described briefly in
Table 3-1. Several processes are employed frequently for selective
absorption of H2S. A simplified flow diagram for a typical gas sweetening
facility is shown in Figure 3-2. Amine treating of sour natural gas for
the removal of H2S and C02 is probably the most widely utilized process
for sweetening gas in the industry. This process involves scrubbing the
gas with amine solutions that absorb H2S and C02. Regeneration (stripping
operation) of this absorbing solution produces an acid gas stream,
containing H2S, C02, the saturated amount of water vapor, and negligible
amounts of hydrocarbons. This acid gas stream is either flared,
incinerated, or processed further in a sulfur recovery facility to
recover liquid elemental sulfur from H2S in the acid gas stream.
3-3
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Table 3-1. MAJOR SWEETENING PROCESSES
Process
Status of
commerci al i zati on
Process
category
Comments
1. Ethanolamine processes
a. Monoethanolamine
(MEA)
CO
b. Methyldiethanolamine
(MDEA)
c. Diethanolamine
- (DEA)
d. Diglycolamine
(DGA)
e. Ollsopropanolamine
(DIPA)
f. Triethanolamine
(TEA)
2. Sulfinol
3. Selexol
Well established
technology (being)
displaced)
Established
technology
Well established
technology
Established
technology
Established
technology
Established
technology
Established
technology
Chemical Being replaced by more efficient
absorption systems, particularly for the trejat-
ment of high pressure natural gast.
Still preferred solvent for gas
streams containing low concentra-
tions of acid gas (H2S and C02) 3nd
essentially no minor contaminants
such as COS and CS2.3
Chemical Generally used for selective
absorption absorption of H2S in the presence of
C02.
Chemical Utilized when acid gas (H2S and C02)
absorption is less than 25-30%. Split flow DEA
more commonly used when acid gas
concentration is above 30%.
Chemical
absorption
Chemical
absorption
Chemical
absorption
Chemical &
physical
absorption
Selective for H2S and in the
presence of C02.
Technology was not commercially
adopted.
Best application is in a gas stream
having high total acid gas partial
pressures and with relatively high
ratios of H^ to C02 (i.e., ratio
1:1 or higher). Elevated pressure
required for efficient removal of
H2S.
Physical Lower initial plant costs and
absorption operating costs than MEA or Ka
Elevated pressure required for
efficient removal of H2S.
(continued)
-------
Table 3-1. Concluded
Process
Status of
commerc i al i zati on1
Process
category
Comments
4. Hot potassium carbonate
(K2C03)
5. Stretford process
6. Flour solvent process
7. Purisol
8. Iron oxide (sponge)
process
Well established
technology
(Benfield process)
Established
technology
Established
technology
Established
technology
Technology is
being displaced
Chemical
absorption
Catalytic
chemical
reaction
Physical
absorption
Physical
absorption
Catalytic
chemical
reaction
(regenerative)
9. Nickel chloride process
Very effective where 8 to 50% acid
gases are present in large
quantities. Unsuitable for gas
mixtures containing little or no
C02.
This process yields elemental sulfur
and is a combination sweetening
process/sulfur recovery plant. The
process does not remove organic
sulfur compounds.
More economical than activated hot
potassium carbonate.3 Elevated
pressure required for efficient
removal of H2S.
Particularly suitable for selective
H2S absorption in the presence of
C02.3 Elevated pressure required
for efficient removal of H2S.
Recently developed wet purification
processes are replacing oxide box
purifiers. The liquid processes
have substantial economic advantages
over the iron oxide processes.3
Disposal of the spent iron oxide can
be a problem. However, in some
situations, it is the most viable
process.
Texaco's nickel chloride sweetening
process.
aln general, if more than five facilities exist, the technology is considered to be established.
5The selection of a sweetening process depends upon H2S and C02 contents and also the type and quantity of
heavier hydrocarbons.
-------
Sweet Gas
So
vent
Absorber
CO
SOUR GAS
Solvent
Pump
Flash
Gas
JRIch Solution
Flash Tank
Coolers
Filter
ACID GAS
TO SULFUR,.
RECOVERY
PLANT
Solvent
Regenerator
Lean/Rich
Heat Exchanger
Reflux
Pump
Reclaimer
Solvent
Booster
Pump
Figure 3-2. Typical sour natural gas amine sweetening facility.
T
Steam
Degradation
Products
-------
3.2 SULFUR RECOVERY OPERATIONS AND SULFUR DIOXIDE (S02) EMISSIONS
The Glaus process is the most widely used process for converting
H2S in acid gases separated from natural gas into elemental sulfur. The
feed to the Claus plant is an acid gas stream removed from the original
sour natural gas stream by a sweetening process. Sulfur recovery
efficiencies are greater (i.e., S02 emissions are lower) with higher
concentrations of H2S in the feed stream. A number of Claus sulfur
recovery process configurations are used by the industry to accommodate
various concentrations of H2S in the acid gas feed. Currently, over
250 Claus sulfur recovery plants are operating worldwide in petroleum
refineries and onshore natural gas production facilities. Plant capacities
range from about 5 to over 1,000 metric tons of sulfur intake per day.
The Stretford process is a wet chemistry process for converting H2S
to elemental sulfur. Originally the process was used for removing H2S
from coal-derived gases; subsequently it has been applied to gases from
various sources including refinery gases and natural gas streams. The
Stretford process is highly effective in removing low concentrations of
H2S from contaminated gas streams. This process is commercially available
and is demonstrated in more than 50 plants throughout the world. However,
the Stretford process has been utilized on a limited scale in refinery
and onshore natural gas production operations in the United States.
3.2.1 Claus Sulfur Recovery Process
Claus sulfur recovery plants convert H2S to elemental sulfur by gas
phase reactions at 8 to 10 psig initial pressure (with tail gas systems
as much as 20 psig) and at high temperatures 190°C to 330°C (375°F to
625°F), using catalysts in stages. Conversion of the H2S in the acid
gas feed to elemental sulfur can be from 70 to 97 percent complete,
depending on the concentration of H2S in the acid gas feed stream, the
type of process configuration, and the number of reaction stages employed.
Several side reactions occur during the Claus process, some of which can
produce such compounds as carbonyl sulfide (COS) and carbon disulfide
(CS2). Unconverted sulfur compounds that appear in the tail gases from
Claus plants are thermally oxidized and emitted to the atmosphere as S02
or processed further for sulfur recovery in a tail gas cleanup unit.
3-7
-------
There are four main variations of the Claus process, differing
primarily in the way in which the heat balance is maintained:
1. the straight-through process,
2. the split-flow process,
3. the split-flow process with preheating of feed stream, and
4. the sulfur-recycle process.
The straight-through process is utilized when the H2S concentration in
the acid gas feed is high (greater than 50 mole percent). The split-flow
process configuration is used when the H2S concentration in the feed is
between 20 and 50 mole percent. If the feed stream is leaner in H2S
than 20 mole percent and at ambient temperature, the flame is not self
sustaining and the feed stream must be preheated to complete the Claus
reaction when the split-flow scheme is employed. The process may still
be a net heat producer. Typically, the sulfur-recycle process is used
when the acid gas feed contains less than 10 percent H2S by volume and
the problem of a self sustaining flame occurs. These ranges of H2S
concentrations are not sharply defined when used to determine which
Claus process configuration should be applied in a specific situation.
Factors such as the presence of compounds other than H2S and C02 in the
acid gas, the acid gas feed flow rate, the stability of the acid gas
composition and flow rate, past experiences of Claus plant designers,
economics, and volume percent ratio of H2S and C02 have a large influence
4
on the choice of process configuration.
3.2.2 Claus Tail Gas Cleanup Processes
Tail gas cleanup systems can be employed to process the unconverted
sulfur compounds in Claus plant tail gas. By using these systems overall
sulfur recovery is increased, and S02 emissions are reduced. Even after
condensation of product sulfur, the tail gases from Claus units contain
appreciable quantities of H2S, S02, and other sulfurous compounds.
Before 1970, tail gases from Claus plants commonly were incinerated, and
the resulting S02-containing gases vented through a stack to the
atmoshpere. Because of the regulatory emphasis since 1970 on reducing
S02 emissions, there are now several viable commercial processes available
for Claus tail gas cleanup. Nearly all these cleanup processes will
reduce S02 emissions to between 0.05 and 0.0004 Ib of S02 per pound of
3-8
-------
sulfur processed and are capable of boosting the overall sulfur recovery
efficiency of a Glaus plant from 91.30 percent to greater than
97.50 percent.5
Three tail gas cleanup processes developed for reducing S02 emissions
through extension of the Claus reaction by operation at low temperatures
are the Cold Bed Adsorption (CBA), the IFP-1 (Institut Francais du
Petrole), and the Sulfreen processes. Four other processes, the BSRP
(Beavon Sulfur Recovery Process), the BSR/Selectox I (Beavon Sulfur
Recovery/Selectox I), the SCOT (Shell Claus Offgas Treatment), and the
Cleanair processes have been developed and demonstrated to reduce emis-
sions from Claus sulfur recovery plants through conversion of the sulfur
compounds present in the tail gas to H2S, followed by H2S recovery. In
addition, the Well man-Lord and the IFP-2 processes were developed to
reduce Claus plant tail gas sulfur emissions by conversion of sulfur
compounds present in the tail gas to S02, followed by S02 recovery. The
ammonium bisulfite/ammonium thiosulfate and the MCRC (Mineral and Chemical
Resource Co.) limestone slurry sulfur recovery processes have also been
developed. All these tail gas cleanup processes are described in detail
in Chapter 4. Figure 3-3 presents these tail gas cleanup processes and
other potentially available processes.
3.3 BASELINE CONTROL EMISSIONS LEVELS
Emissions of sulfur from onshore natural gas production operations
originate from H2S contained in "sour" natural gas deposits. This
sulfur is emitted as H2S (trace amounts) and S02, with the majority of
sulfur emissions occurring as S02. The major sulfur emissions sources
within onshore production operations are as follows:
1. S02 from incinerated acid gas emitted from sweetening operations,
2. S02 from incinerated tail gas emitted from sulfur recovery
operations, and ^
3. S02 from incinerated residual tail gas emitted from tail gas
cleanup systems on sulfur recovery plants.
Nationwide sulfur dioxide emissions from the existing onshore natural
gas sulfur recovery facilities in the onshore production industry are
estimated to be 250,000 megagrams per year. These estimates are based
3-9
-------
OJ
I
Claus Tail-Gas Cleanup Processes
1
. 1
Dry- Bed Process
Oxidize
to S02
and
Absorb
or
React
SI
:
1
Wet Scrubbing Process
Extend
Claus
Reaction
on
Solid Bed
I
r
Extend
Claus
Reaction
In
Liquid
Phase
with
Catalj
Westvaco Sulfreen
-------
on the 89 sulfur recovery facilities presented in Table 9-6. The estimates
include those onshore production facilities that do not recover sulfur
but simply incinerate the acid gases from the sweetening units.
3-3-l Sweetening Operation Emissions
Sulfurous emissions from sweetening systems of sour natural gas
plants usually occur as either H2S or S02. Nearly all "sour" natural
gas is routed to a gas sweetening facility where the H2S is removed and
becomes part of the acid gas stream. At plants where the quantities of
sulfur available in the feed gas are considered too low to be economically
feasible to recover, the acid gas is often not treated for sulfur recovery.
In fact, the cost would prohibit the constructing and operating of
sulfur recovery units in such situations. In such cases, the sulfur in
the acid gas is either vented to the atmosphere as H2S or burned with
fuel gas and air in a flare or incinerator and emitted to the atmosphere
as S02. However, the H2S in acid gas is most often converted to S02
before being emitted to the atmosphere, and the fraction of H2S emissions
is therefore very small compared to the total sulfur emissions in the
United States. Several factors, such as the H2S concentration in the
gas, state regulations, and population densities affect whether the H2S
in acid gas is converted to S02 before being emitted to the atmosphere.
In addition, nitrogen oxides (NO ), hydrocarbons (HC), and parti-
f\
culate matter may be emitted during combustion of acid gas with fuel
gas. However, incinerators and flares at gas sweetening plants operate
at temperatures ranging from approximately 593°C to 704°C (1,100°F
to 1,300°F). At these temperatures, the combustion of H2S to S02 is
over 99 percent complete, and significant amounts of nitrogen oxides are
not formed in this low temperature range. Particulate matter and
hydrocarbons emitted from sweetening operations result from incomplete
combustion of the acid gas. Incomplete combustion can be caused by
insufficient fuel value in the gas mixture or inadequate mixing of fuel
and air. These factors are considered in incinerator and flare design
and operating procedures to insure complete oxidation of H2S and other
reduced sulfur compounds to S02. Therefore, smokeless flares and
incinerators usually do not produce significant amounts of particulate
or hydrocarbons.
3-11
-------
3.3.2 Sulfur Recovery Operation Emissions
Nearly all sulfur originating in raw natural gas is extracted
during sweetening operations and, if not emitted to the atmosphere after
sweetening, is then routed in the acid gas to a Claus sulfur recovery
plant. Unless a tail gas cleanup unit is applied, the exhaust gas
leaving the Claus plant is incinerated, and consequently the tail gas
sulfur is emitted to the atmosphere primarily as S02.
As in the case of burning acid gas, nitrogen oxides, hydrocarbons,
and particulate matter may be emitted from Claus tail gas incineration.
However, these emissions normally would be insignificant for the same
reasons cited for acid gas flaring or incineration.
Sulfur compounds emissions from sulfur recovery operations are
influenced by several parameters, including Claus plant reactor bed
temperatures, age and condition of the catalyst used in the Claus process,
the H2S and C02 concentrations in the acid gas feed, the number of
conversion stages in the Claus plant, and the percent capacity at which
the Claus plant is operated.
3.3.3 Baseline Control Emission Levels
3.3.3.1 S02 Baseline Control Emission Levels. The S02 baseline
emission level is the level of emission control (1982 State S02 controls)
that would exist in the onshore production industry in the absence of
any additional EPA standards. This baseline emission level is estab-
lished to facilitate comparison of the economic, energy and environmental
impacts of the regulatory alternatives. Current control technologies
that represent industry practice are described in Chapter 4. Achievable
emission reduction levels from the application of these current control
technologies are described briefly in Chapter 7. Current industry
practice, data from literature and vendors, and existing State requirements
for sulfur recovery from onshore production activities provide the basis
for selection of the S02 baseline control emission levels.
Current technologies that represent industry practice can be classified
as (1) sweetening operations with incineration of acid gases, and
(2) sweetening operations followed by sulfur recovery with incineration
of Claus tail gases. Assessment of actual industry practice includes
considerations for sulfur recovery plant size, H2S and C02 concentrations
3-12
-------
in the acid gas feed, and number of Glaus unit catalytic stages. Three
baseline controls have been developed for the onshore natural gas production
industry based upon current industry practice. These baseline controls,
which are applied following sweetening operations, are:
o Incineration
o Sulfur recovery and incineration (Claus-2 stage)
o Sulfur recovery and incineration (Claus-3 stage)
These baseline controls form the basis of the model plants for
which cost analysis and economic impact study will be conducted. While
incineration does not reduce S02 emissions, it represents a no control
option, and as such is included in this discussion of control technology
options. Current control technologies demonstrated at the existing
facilities for efficient, economical, and continuous reduction of S02
emission levels under normal operating conditions are represented through
these baseline controls.
Baseline controls and baseline emission levels for S02 are presented
in Table 3-2. An assessment of the baseline control is also presented
in Table 3-2, which shows sulfur recovery efficiency under normal operating
conditions for a specified acid gas H2S/C02 volume percent ratio.
Specific emission regulations for sulfur recovery plant facilities
currently are applied at the State level. Direct interface with national
regulations is usually confined to diffusion modeling to show compliance
with ambient standards and significant deterioration standards. The
degree to which applicable State regulations require S02 emission reduc-
tions depends on the size of the sulfur recovery plant and the H2S and
C02 concentrations in the acid gas feed stream to the Claus unit. Many
states have specific emissions standards for sulfur-recovery plants,
while some use a case-by-case approach based on meeting ambient standards.
3.3.3.2 H?S Baseline Control Emission Levels. Current practice of
the onshore natural gas production industry is to flare or incinerate
unprocessed acid gases, Claus unit tail gases, and residual tail gases
(from tail gas cleanup systems) before releasing them into the ambient
atmosphere. It is assumed that during thermal oxidation, operated at or
above 650°C (1,200°F), all sulfur compounds, including H2S, COS, and
3-13
-------
Table 3-2. BASELINE CONTROLS AND BASELINE EMISSION LEVELS
Baseline controls
(no NSPS)
Incinerator
Claus-2 stage
Claus-3 stage
Claus-3 stage
Claus-3 stage
Claus-3 stage
Claus-3 stage
Size
(sulfur intake), Mg/d
5.1
10.2
101.6
563.8
563.8
1,015.9
1,015.9
Acid gas feed
H2S/C02 ratio by volume
b
b
b
50/50
80/20
50/50
80/20
Baseline emission levels.
S02 emissions, 103 Mg/y
(percent sulfur recovery)
3.56
(0.00)
0.62
(91.30)c
4.69
(93.39)
15.59
(96.05)
13.26
(96.64)
28.07
(96.05)
23.87
(96.64)
350 days/year operation.
^Covers the entire ratio range from 12.5/87.5 to 80/20.
cr.
Figures based upon 12.5/87.5 ratio.
-------
CS2, are converted to S02. Therefore, separate regulations for H2S
emissions from the gas processing industry have not been established,
because these emissions are considered negligible in total amount.
However, any significant emissions of H2S from the onshore production
industry is not permitted.
3.4 REFERENCES FOR CHAPTER 3
1. Railroad Division of Texas, Oil and Gas Division. Rules Having
Statewide Application to Oil, Gas, and Geothermal Resource Operations
with the State of Texas. Austin, Texas. October 1979.
2. U.S. Environmental Protection Agency. Atmospheric Emissions Survey
of the Sour Gas Processing Industry. Publication No. EPA-450/3-75-076.
Research Triangle Park, North Carolina. October 1975.
3. Kohl, Arthur L. and Fred C. Riesenfeld. Gas Purification. Gulf
Publishing Company. Houston, Texas. Third Edition. 1979.
4. Paskall, Harold G. Capability of the Modified-Claus Process.
Western Research & Development. Alberta, Canada. March 1979.
5. The Ralph M. Parsons Company. Engineers/Constructors. Sulfur
Recovery Study - Onshore Sour Gas Production Facilities - for TRW
Environmental Engineering Division. July 1981. The study is
presented in Appendix E.
6. State Air Laws. Environmental Reporter. The Bureau of National
Affairs, Inc. Washington, D.C. 1979-1981.
3-15
-------
4. EMISSION CONTROL TECHNIQUES
4.1 GENERAL DESCRIPTION
For many years the Claus Sulfur Recovery Process has been utilized
to convert hydrogen sulfide (H2S) recovered from sour natural gas treating
processes into elemental sulfur. This process is the first major step
in reducing the amount of this noxious gas that reaches the atmosphere.
Practically all of the onshore sulfur recovery plants in this country
are based on some version of the Claus process for recovering sulfur
from H2S.
Since 1938, the principal improvements to the Claus process have
been obtained by sequential addition of more catalytic reactors, with
sulfur and heat removal between the reactors to shift the equilibrium of
the reaction towards higher sulfur removals. This process has now
advanced to the point that sulfur recovery efficiencies have increased
from the 90 to 92 percent levels first obtained in the late 1940's to
1 2
present recovery efficiency levels of up to 97 percent of inlet sulfur. '
Numerous processes have also been developed during the past decade to
remove residual sulfur compounds from Claus plant tail gas. Several of
these tail gas cleanup processes are designed to boost the sulfur recovery
capability of the Claus system to 99.9 percent recovery of sulfur con-
tained in the acid gas feed to the Claus plant.
In general, the sulfur compound emission conversion or control
techniques utilized in the sour natural gas production industry consist
of incinerators and flaring units, two- and three-stage Claus sulfur
recovery units, and a variety of Claus tail gas cleanup systems. Factors
such as the H2S and carbon dioxide (C02) concentrations in the acid gas
feed, the expected throughput (sulfur intake) of the facility, the
location, and economics greatly influence the Claus process configuration,
4-1
-------
the number of Glaus reactors, and the type of tail gas cleanup unit, if
any, selected for a particular sulfur recovery facility.
4.2 SULFUR EMISSION CONTROL TECHNOLOGIES USED IN THE INDUSTRY
4.2.1 Incineration
Incineration is a temperature-controlled process in which fuel gas
and air are supplied to the incinerator in sufficient quantities to
maintain a constant temperature of 593°C - 704°C (1100°F - 1300°F) to
ensure complete oxidation of H2S and other reduced sulfur compounds,
such as carbon disulfide (CS2) and carbonyl sulfide (COS), to sulfur
dioxide (S02). Employing incineration does not reduce the total amount
of sulfur compound emissions, however, the technique does convert H2S
into less toxic S02. If the H2S concentration in the acid gas discharged
from a natural gas sweetening facility is very low or the acid gas
throughput is small, the acid gas usually is incinerated and the resultant
S02 discharged into the atmosphere. Incineration is always employed as
the final step in the Claus sulfur recovery process (with no tail gas
cleanup unit). If a tail gas cleanup unit is applied to the Claus
plant, the residual tail gas from the cleanup unit is generally incinerated.
However, incineration is not used with the Beavon Sulfur Removal
Process (BSRP). In this process the incinerator is kept as a stand-by
unit and used only when necessary.
4.2.2 2-Stage Claus Sulfur Recovery Process
A Claus sulfur recovery facility utilizing two catalytic stages
generally is capable of attaining recovery design efficiencies of up to
93.8 percent, depending on the H2S concentration in the acid gas fed to
the Claus unit. If the H2S concentration in the acid feed gas is as low
as 15 percent by volume, however, a two-stage Claus plant may be able to
4
achieve only a 91.3 percent sulfur recovery design efficiency.
A flow diagram for a typical two-stage Claus sulfur recovery plant
is shown in Figure 4-1. The first step in the Claus process is the
complete oxidation of one-third of the H2S in the acid gas to S02 (the
thermal phase):
3H2S + |02 iQgoa^ S02 + H20 + 2H2S + 520.9 kJ (4-1)
4-2
-------
Thermal Stage
HP Steam |_P Steam
Catalytic Stages
Acid
Air
i
Reaction
Furnace
Wa
er
i
Condenser
Water
Reheater
Reheater
(Converter \
No. 1 J
Sulfur
LP Steam
Condenser
T
~O
Fuel
Air
(Converter "\
No. 2 )
Water
Sul
fur
LP S
team
Condenser
T
I
Incinerator Stack
Water
Sulfur
Figure 4-1. Flow diagram for a two-stage Claus sulfur recovery plant.
-------
This step is carried out in a reaction furnace, and the released energy
is recovered and used to generate steam. In the second step (the catalytic
phase), the remaining two- thirds of the H2S is reacted over a catalyst
with the S02 produced in the initial reaction:
2H2S + S02 > 35 + 2H20 + 92.9 W (4-2)
The flow diagram shown in Figure 4-1 indicates that the Claus process
can be separated into two phases, a thermal phase and a catalytic phase.
In the thermal phase, the temperature in the reaction furnace is usually
between 980°C and 1090°C (1800°F and 2000°F). During the catalytic
phase, the temperature is maintained below 370°C (700°F) and somewhat
above the sulfur dew point of the gas mixture. The normal operating
temperature during the catalytic phase is between 250°C and 300°C (475°F and
575°F), but the lower this temperature, the more complete is the conversion
to sulfur. Therefore, it is advantageous to provide several catalytic
stages with condensation of the sulfur formed after each stage. After
the sulfur is condensed following each Claus converter, the process gas
is preheated to reaction temperature before entering the next catalytic
reactor. The economic incentive of high sulfur prices and continued
demand for liquid sulfur induce an increasing number of producers to
recover sulfur from H2S.
4.2.3 3-Stage Claus Sulfur Recovery Process
Utilizing three catalytic stages, a typical Claus sulfur recovery
facility is capable of attaining efficiencies of 93.4 to 96.6 percent of
the sulfur in the acid gas stream under normal conditions. The sulfur
recovery efficiency of Claus plants decreases with a decrease in H2S
concentration (i.e., increase in C02 concentration) in the acid gas
feed. For Claus plants having three catalytic converter stages, the
4
following sulfur recovery efficiencies have been reported:
Sulfur Recovery
H2S/C02 Mole Percent Ratio Sulfur Recovery . Actual Efficiency
in Acid Gas Feed Design Efficiency (from API)
12.5/87.5 93.4 percent 93.7
20/80 94.5 percent 94.1
50/50 96.1 percent 95.2
80/20 96.6 percent 96.2
4-4
-------
The loss in sulfur recovery efficiency is associated with increased
concentrations of C02 in the acid gas feed because the Glaus process is
equilibrium-limited, and increased concentrations of C02 and impurities
drive the process away from the recovery of sulfur. These process
limitations occur regardless of the H2S concentration in the acid gas
feed; but they are more significant, and sulfur losses become greater as
the H2S feed concentration decreases.
To improve sulfur recoveries at Glaus plants where the acid gas
feed stream contains a lean H2S concentration, a modified Glaus process
can be utilized. Four basic configurations of the modified Glaus process
that are being employed currently by the onshore natural gas production
industry are the straight-through, split-flow, split-flow with preheating,
and sulfur recycle configurations. The differences among these process
configurations are in the methods used to produce the S02 prior to the
first converter.
4.2.3.1 Straight-Through Configuration. If the acid gas feed to
the Glaus unit contains 50 mole percent or greater of H2S, the straight-
through configuration is normally utilized, because it provides the
highest overall sulfur recovery and permits maximum heat recovery at a
high temperature. '
In the straight-through process scheme, the entire acid-gas stream
and the stoichiometric amount of air to burn one-third of the H2S to S02
are fed through a burner to the reaction furnace. Then, sufficient
retention time is provided to allow the generated S02 to react with the
unburned H2S to form sulfur vapor. At the temperatures prevailing in
the reaction furnace, typically above 1090°C (2000°F), a substantial
amount of elemental sulfur is formed. The elemental sulfur is condensed
after the gases are cooled first in a waste heat boiler and then in a
sulfur condenser. Up to 70 percent of the overall conversion of H2S to
elemental sulfur can take place in this thermal-conversion step. Although
high-pressure steam can be generated in the waste heat boiler, it is
preferable to produce low-pressure steam (15 to 50 psig) in the sulfur
condenser in order to cool the reaction gases to obtain maximum sulfur
condensation. Many designs often use the heat from the fourth condenser
to preheat boiler feed water in place of generating steam. The reaction
gases leaving the sulfur condenser are reheated and passed through the
4-5
-------
first catalytic converter where additional sulfur is produced by the
reaction of H2S with S02. The chemical reaction equations are presented
in Section 4.2.2. Although these reactions are exothermic, reheating of
the gas is necessary to maintain the temperature above the sulfur dew
point as the gas passes through the catalytic converter, because
condensation and deposition of sulfur on the catalyst causes catalyst
deactivation. The gases leaving the first catalytic converter are again
cooled, and sulfur is condensed. The process of reheating, catalytically
reacting, and sulfur condensing is repeated two more times in a three-stage
sulfur recovery unit. As conversion progresses through the catalytic
stages and more sulfur is removed from the gas mixture, the sulfur dew
point of the reaction gases is lowered, permitting operation at
progressively lower temperatures, thus improving conversion. After
leaving the last sulfur condenser, the exhaust gases are either incinerated
to convert all remaining sulfur compounds to S02 before being emitted to
the atmosphere or further treated in a separate tail gas cleanup process.
Figure 4-2 shows a flow diagram for a three-stage Glaus plant
utilizing the straight-through process configuration.
4.2.3.2 Split-Flow Configuration. The split-flow process is used
for acid gas streams containing H2S in such low concentrations that
stable combustion could not be sustained if the entire gas stream were
fed to the reaction furnace. Generally, the split-flow configuration is
employed at Glaus sulfur recovery facilities where the H2S concentration
in the acid gas feed stream is between 20 and 50 mole percent.
In the split-flow process, one-third of the acid gas is fed to the
reaction furnace, and all the H2S contained in the gas is combusted with
the stoichiometric amount of air to form S02. In this configuration,
most of the H2S fed to the furnace is oxidized to S02, and little or no
sulfur is produced in the furnace. Then, the hot gases are cooled in a
waste heat boiler and combined with the remaining two-thirds of the acid
gas before entering the first catalytic conversion stage. The Glaus
reactor and condenser train of the split-flow process configuration is
very similar or identical to that of the straight-through process.
Figure 4-3 shows a flow diagram for the split-flow configuration of
the modified Glaus process.
4-6
-------
Add Gas
™
< \
Kr
j
Drum
UD {turn
Reaction
Furnace
j
Y
Water
> /•
s
i
^
-
1
LP
— •
\—i
t
Steam
Condenser
No. 1
— *~r .,> A1r
f
V^ BFW
Blower
i
i
(Converter j
No. 1 J
Speheater
JNo. 1
\ /
fn
* , * * \_ f
•*. ~ f
LP Steam
Condenser
No. 2
~T
Sulfur BFH
(f^K
; cheater
No. 2
V •
V /*
i.. iJ
•%!
LP
)
-^
I
Steam
t
Condenser
No
. 3
f
Sulfur BFW
u] G!
Sulfur Pit
^
(Converter A
No. 3 J
>srr
LP Steam
1 & Tall
t I6"
Condenser
No. 4
t
Sulfur BFM Sulfur
11) Q]
Pump)
Liquid
"Sulfur
Figure 4-2. Flow diagram for a three-stage Claus sulfur recovery facility
utilizing the straight-through process configuration.
-------
1
Acid
va
™as '
Mr "
Reaction
Furnace
Waste
Heat
Boiler
1 i
Reheater
I Converter J
^
Condenser
).
Rentiicj
^ Converter J
i
Condenser
)
\ '
f~
( Converter J
1
Condenser
Sulfur
Sulfur
Sulfur
Figure 4-3. Flow diagram for the split-flow configuration of the
Claus sulfur recovery process.
-------
4.2.3.3 Split-Flow With Preheating of Feed Streams Configuration.
In cases where the H2S concentration in the acid gas feed is too low to
achieve a sufficiently high temperature in the reaction furnace using
the two-third bypass employed in the split-flow configuration, acid gas
preheating or the sulfur-recycle configuration is often utilized. Acid
gas preheating commonly is used to permit processing by the split-flow
method for Glaus acid gas feed streams containing 10 to 25 mole percent
H2S. In addition, recent success has been reported on the use of the
split-flow configuration with preheating of feed streams, with an acid
gas feed stream containing only 8 mole percent H2S where previously the
use of direct oxidation failed because of severe catalyst deactivation.8
In this configuration of the Claus process, adequate furnace
temperature is achieved by preheating both air and acid gas and by
adding a supplemental fuel gas to the flame. Problems with CS2 formation
are avoided by use of a specially designed burner in which a set of
concentric pipes carry the fuel gas, fuel gas air, acid gas, and process
air.
4.2.3.4 Sulfur Recycle Configuration. Generally, the sulfur
recycle configuration of the Claus process is used when the H2S
concentration in the acid gas feed to a Claus sulfur recovery facility
is less than 10 mole percent. In the sulfur recycle Claus process,
product sulfur is recycled to the furnace and burned with air to produce
S02. Then, the S02 formed in the furnace is combined with the preheated
acid gas feed stream and fed to the Claus reactors as shown in Figure 4-4.
The reactor-condenser train of the sulfur recycle configuration is
similar to that of the straight-through configuration.
4.2.4 Recycle Selectox Process
The Selectox catalyst in this process enables H2S to be oxidized to
sulfur with air at a low temperature, eliminating the need for high-
temperature combustion as in the Claus Sulfur Recovery Process.
When supplied with the proper amount of air, the oxidation of
one-third of the H2S to S02 and reaction with the remaining two-thirds
of H2S occur simultaneously in the presence of the Selectox catalyst to
form elemental sulfur:
4-9
-------
•Pa
H-»
O
Add Gas
Sulfur
Sulfur
Sulfur
Sulfur
Figure 4-4. Flow diagram for the sulfur recycle configuration of the
Claus sulfur recovery process.,
-------
H2S + 3/2 02 »S02 + H20 (4_3)
2H2S + S02 >3S + 2H20 (4_4)
The effective overall reaction is therefore:
3H2S + 3/2 02 >3S + 3H20 (4_5)
The Recycle Selectox Process is employed when the acid gas feed
strength is 5 percent H2S or less. The exothermic reaction with 5 percent
gas results in a reasonable maximum reactor outlet temperature. The gas
exiting from the Selectox reactor is cooled in a sulfur condenser that
produces steam and condenses sulfur. Gas from the sulfur condenser then
proceeds through one or two Glaus stages, each with a reheater, converter,
and sulfur condenser.
When the acid gas feed contains more than 5 percent H2S, some of
the cooled lean gas from the sulfur condenser is reheated and recycled
to the Selectox reactor inlet to maintain approximately 5 percent H2S at
the reactor inlet.
The Recycle Selectox 2-Stage Process, shown in Figure 4-5, has one
Selectox and one Glaus stage. The Recycle Selectox 3-Stage Process,
illustrated in Figure 4-6, is identical but has a second Glaus stage
4
added. Achievable design sulfur recovery efficiencies are:
Process H2S/C02 Ratio Percent Efficiency
Recycle Selectox 2-Stage 12.5/87.5 91.0
20/80 92.0
50/50 93.8
Recycle Selectox 3-Stage 12.5/87.5 94.2
20/80 95.4
The Selectox and the Glaus reactor system are the same: heating
gas to the desired inlet temperature, reaction in a converter, and
cooling the gas and condensing sulfur in a condenser. The condensers
produce low-pressure steam.
4.2.5 3-Stage Glaus Unit With Tail Gas Cleanup Processes
The trend to reduce emissions of sulfur compounds to the atmosphere
because of increasingly stringent air pollution regulations has created
4-11
-------
CONOENSATE
AIR
AIR BLOWER
CONVERTER
NO. 1
ISELECTOXI
I
CONVERTER
NO. I
(ClAUS)
IP STEAM TAIL CAS
j CONDENSER |
! NO. 2 I
BFW
LIQUID
SULFUR PIT
SULFUR
SULFUR PUMP
Figure 4-5. Recycle Selectox 2-Stage Process.
-------
I
PREHEATED
ACID GAS
KO DRUM
CONOENSATE
co
AIR
AIR BlOWEfl
I
HEHEATER
NO. 1
CONVERTER
NO. I
ISELECTOX)
HECVCIE
BLOWER { r\
IP STEAM
I CONDENSER I
I NO I
J I
•FW
CONVERTER
NO. 2
(CLAUSI
CONVERTER
NO. 3
(CLAUSI
TAIL CAS
IP STEAM
I CONDENSED I
I NO 3 I
I I
DFW
LIQUID
SULFUR
l i
SULFUR PIT
SULFUR PUMP
Figure 4-6. Recycle Selectox 3-Stage Process.
-------
the need for a new group of processes designed to clean up the tail gas
from Claus sulfur recovery units. There are four commercially available
tail gas cleanup processes which represent a wide spectrum of process
technologies and capabilities of reducing S02 emissions to the atmosphere.
These are SCOT, BSRP, Sulfreen and BSR/Selectox I processes. Several
g
other processes are at different stages of development. Prior to the
selection and application of a particular process technology, a detailed
review of all commercially viable processes should be made to determine
the most economical or optimum tail gas cleanup process scheme to be
used for reducing S02 emissions from new or existing Claus sulfur recovery
plants.
The four most widely used tail gas cleanup processes are discussed
in the following subsections. In addition, several other viable processes
for removing sulfur compounds from Claus plant tail gas are described
briefly in Subsection 4.2.5.5 of this chapter. It should be noted that
a tail gas cleanup unit can also be used with a 2-stage Claus unit and
that the number of stages is an economics decision.
4.2.5.1 3-Stage Claus Unit With SCOT. The Shell Claus offgas
treating (SCOT) process, announced to industry in 1972, was developed by
the Royal Dutch/Shell Laboratories in the Netherlands and is licensed in
the United States by the Shell Development Company in Houston. The SCOT
process is capable of increasing the sulfur recovery efficiency of Claus
units from the usual level of about 95 percent to more than 99.8 percent.
The SCOT process consists of essentially three stages: (1) heating
and reduction; (2) cooling and quenching; and (3) H2S absorption, stripping,
and recycle. In the first SCOT stage, the Claus plant tail gas is
heated to about 300°C (570°F) and reacted with hydrogen or a mixture of
hydrogen and carbon monoxide over a cobalt molybdenum catalyst. All
sulfurous compounds in the tail gas, including S02, sulfur vapor (S),
COS, and CS2, are reduced to H2S. The hot gas from these highly exothermic
reactions is cooled in a waste-heat boiler and finally quenched in a
water-quench tower to about ambient temperature. In the final stage,
the H2S in the gas is selectively absorbed in an alkanolamine solution.
The effluent gas from the SCOT absorber, containing about 200 ppmv-500 ppmv
of H2S is incinerated before it is discharged to the atmosphere. The
rich amine is stripped in a conventional manner, and the H2S-rich stream
4-14
-------
is recycled to the front of the Glaus unit. A flow diagram for the SCOT
process is given in Figure 4-7.
Several advantages of the SCOT process are (1) easy adaption to an
existing Glaus plant, (2) use of familiar process technology and equipment,
(3) easy and flexible operation, (4) elimination of secondary air and
water pollution, and (5) high degree of sulfur removal over a wide range
of operating conditions. The disadvantages are (1) higher capital cost,
(2) higher fuel usage, and (3) higher heating and cooling requirements.
The SCOT process, however, is considered to be one of the most flexible
9 10
tail gas cleanup processes available commercially. '
Currently, more than thirty-five SCOT units are in operation worldwide
on Claus plants ranging in size from 3 metric tons to 2,100 metric tons
3
of sulfur intake per day. Also, more than forty other SCOT systems are
in engineering, construction, or start-up phases. In onshore production
activities, one SCOT unit is in operation, and two are in engineering
and start-up phases.
4.2.5.2 2-Stage Claus Unit With Sulfreen Unit. Lurgi Apparante-
Technik of Frankfurt, West Germany and France's Societe National e des
Petrol es d'Aquitaine (SNPA) combined their efforts to develop the Sulfreen
process for Claus tail gas cleanup. The Sulfreen process, which is
essentially an extension of the Claus reaction, is capable of boosting
the overall sulfur recovery efficiency of the Claus/Sulfreen system up
4
to 98.4 percent. The percentage of sulfur recovery attainable by the
Sulfreen unit depends upon the concentration of H2S and S02 in the Claus
tail gas fed to the unit.
The Sulfreen process converts H2S and S02 contained in the tail gas
to sulfur at low temperatures of 127°C to 150°C (260°F to 300°F) by
extension of the classic Claus reaction:
2H2S + S02 - * 3S + 2H20 (4_6)
A special activated alumina is used as an adsorbent and a catalyst in
the reactors. This material was selected because of its high adsorption
capacity and ease of desorption of sulfur deposited on its surfaces.
Sulfur formed during the reaction is adsorbed as a liquid on the catalyst,
which removes it from the reaction zone, thereby allowing the reaction
4-15
-------
Hydrogenation
Reactor
Cooling Tower
Packed or Tray
Claus plant tall qas
prior to Incinerator
Fuel gas
A1r
x
Fixed-bed
reducing
catalyst
'{.P. steam
Reducing
Gas
Generator
Reactor
Effluent
Cooler
JTT
Air or
water
cooler
Clean tall gas to Incinerator
-Lean amlne from regenerator
Trav Tower Absorber
Sour-water
_^.condensate to
exlstlnq sour-
water stripper
•>-Rich amine to regenerator
H2S from regenerator
recycled back to the
front of Claus unit
Figure 4-7. Flow diagram for the Shell Claus Off-gas Treatment (SCOT) process.
-------
to move further to the right to obtain a higher conversion than in the
Claus process. This reduces entrained sulfur to a minimum. A Sulfreen
unit consists of at least two parallel reactors, one in adsorption and
one in desorption service. The number of reactors needed for a particular
Sulfreen unit is determined strictly by economic considerations. Desorption
of sulfur is accomplished by means of hot gas in a closed cycle, after a
period of operation during which the catalyst has adsorbed its limit of
sulfur. The hot gas is passed through the reactor to strip sulfur from
the catalyst. The Sulfreen unit operation is simple and differs only
slightly from that of a Claus unit. There are usually three reactors,
two of which are in adsorption service while one is being regenerated.
Since only solid adsorbents are used and no liquids are produced except
sulfur, the process is free of liquid waste disposal problems. Sulfur
that is condensed and drained to the sulfur pit is bright yellow and
99.9 percent pure and can be combined with Claus produced sulfur. A
flow diagram for the Sulfreen process is presented in Figure 4-8.
g
The Sulfreen process is a viable, commercially proven process.
Currently, at least nineteen Sulfreen tail gas cleanup units are in
operation worldwide and several other Sulfreen units are in construction.
The Sulfreen process is quite attractive for large Claus plants, due
mainly to the possibility of eliminating a fourth Claus converter and
reducing the size and height of the tail gas disposal stack when the
Sulfreen unit is utilized. Also, the process may be attractive for
smaller Claus plants where an S02 emission level of 1,500 ppmv to 2,000 ppmv
is permitted.
4.2.5.3 3-Stage Claus Unit With Beavon. The Beavon Sulfur Removal
Process (BSRP) was developed by the Ralph M. Parsons Company and Union
Oil Company of California to clean up tail gas streams from Claus sulfur
recovery units. A BSRP tail gas cleanup system applied to a three-stage
Claus unit can boost overall sulfur recovery to 99.99 percent, leaving a
sulfur concentraton of 250 ppm or less in the residual tail gas.
The BSRP process employs three distinct steps: (1) hydrogenation
of sulfurous compounds to H2S in a catalytic converter, (2) cooling of
the converter-effluent gases, and (3) conversion of the H2S in the tail
gas from the cooler to elemental sulfur by use of the Stretford process.
4-17
-------
Converters
00
Claus Plant Tall
Gas Before
Incineration
Adsorbing Adsorbing
Sulfur Sulfur
Regeneration
Adsorber Off-Gas
to incineration
1
Sulfur Wash
k
•it >» r-
i
Sul
fur
i
Uqi
Suit
i
jld
'ur
Ho
j
\
t
(
L
JT
>
V
tk
yv\
f^
--/
h
IX
t
J
i
L-
^
\
*>v
~ — i
r^
— J
1 >•
UKH,
-
_n__
.A/
v v
W
\
-ferf-fr
i
f*
;
t
^N
'i'
1
^i_
cj 3
-J
txl fe
BDller Fe
Water
^
S
Co
L
_ ^
ed_
S
ul
nd
P
fur
enser
Steam
ill
"^1
fur
Sulfur Wash
Nitrogen to
Regeneration Cyc
r
T.-..:,
1
Sul
fur
*
.Liquid
Sul fur
*
Regeneration
Gas
Furnace
Figure 4-8. Flow diagram for the Sulfreen tail gas cleanup process,
-------
First, the Glaus unit tail gas is heated to reaction temperature by
mixing it with the hot combustion products of fuel gas and air. This
combustion may be carried but with a deficiency of air if the tail gas
does not contain sufficient H2 and CO to reduce all of the S02, COS, CS2
and S to H2S. The heated gas mixture is then passed through a catalyst
bed (hydrogenation reactor) where all sulfur compounds are converted to
H2S by hydrogenation and hydrolysis. The hydrogenated gas stream is
then indirectly cooled in the reactor effluent cooler, generating steam.
The gas is further cooled by direct contact with a slightly alkaline
buffer solution before it enters the H2S-removal portion of the process.
The Stretford process is used next to remove H2S from the cooled hydro-
genated tail gas, where the H2S is absorbed in an oxidizing alkaline
solution. The oxidizing agents 'in the solution convert the H2S to
elemental sulfur. The oxidizing agents are then regenerated by contacting
with air in the oxidizer tank where the sulfur is floated off as a
slurry. This sulfur slurry is separated from the oxidizing alkaline
chemicals by filtering or centrifuging. It is res lurried with wash
water and heated to melt the sulfur. The molten sulfur flows from the
decanter to the sulfur pit. The oxidizing alkaline chemicals are returned
to the system and the wash water is discarded. Tail gas from the absorber
does not require incineration and can be vented directly to the atmosphere.
An incinerator is installed as a stand-by unit and used during the
start-up and shutdown of the BSRP tail gas cleanup unit and those occasions
when the H2S content exceeds 10 ppmv. A flow diagram for the Beavon
Sulfur Removal Process is presented in Figure 4-9.
Currently, over thirty-six BSRP plants are either operating, under
construction, or in design at twenty-two locations in the United States
and Japan.
4.2.5.4 3-Stage Claus Unit With BSR/Selectox I. The BSR/Selectox I
process, recently developed by Union Oil Company of California and the
Ralph M. Parsons Company, is a Claus tail gas cleanup system designed to
provide an overall sulfur recovery efficiency in the range of 97.84 percent
to 98.49 percent. This new process has proven to be reliable, easy to
operate, and the least costly of the known tail gas cleanup processes.
The first industrial BSR/Selectox I unit began operation during 1978 in
Lingen, West Germany.
4-19
-------
Fuel Gas
Air
Claus Plant Tall
Gas Before Incineration
ro
o
Fixed Bed
Reactor
Reactor
Effluent
Cooler
Burner
Hydrogenated
Tall Gas
Steam
1
Cooling.
Tower
Absorber Off-Gas To Incineration Or Stack
Liquid Return
J
Stretford Solution
Air
Stretford
Sulfur Scum
Sulfur (reslurry,
after water wasn)
Melter
Gas Purifying Oxldlzer
Tower Absorber
Sour Water
BFW
(To Waste
Treatment)
.Filter
or
Centrifuge
T
Purge Stream
Figure 4-9. Flow diagram for the Beavon Sulfur Removal Process (BSRP).
-------
BSR/Selectox I is a fixed bed catalytic process consisting of two
steps. The first step is also part of the older Beavon Sulfur Removal
Process. First, tail gas from the second stage of the Glaus plant is
heated to a reaction temperature of 288°C to 400°C (550°F to 750°F) in
the reducing gas generator by mixing it directly with hot products from
the combustion of fuel gas and air. Some hydrogen and carbon monoxide
are formed to supplement the hydrogen in the tail gas. The hot gas
mixture is passed through a single catalyst bed (hydrogenation reactor).
The tail gas is hydrogenated to convert S02 and elemental sulfur to H2S
and hydrolyzed to convert COS and CS2 to H2S. Then, the hydrogen sulfide-
containing gas stream is cooled in a contact condenser to reduce water
partial pressure. The purpose of cooling is to remove water vapor,
which increases conversion since water is one of the products of reaction.
In the second step of the process, the cooled gas stream is reheated to
a moderate temperature and mixed with a stoichiometric amount of air and
passed over the Selectox-32 catalyst (proprietary catalyst of Union Oil
Company) to oxidize selectively the hydrogen sulfide to elemental sulfur.
Elemental sulfur is removed by condensation and is collected in a sulfur
pit. At this point, total sulfur recovery is greater than 97 percent.
Finally, the resulting tail gas from the BSR/Selectox I unit is passed
through an additional Claus stage before incineration to increase the
total sulfur recovery to more than 98 percent. Alternatively, the tail
gas from the Selectox unit after sulfur condensation is routed to a
thermal oxidizer and stack. A flow diagram for the BSR/Selectox I
process is presented in Figure 4-10.
The BSR/Selectox I process recovers 80 to 90 percent of the sulfur
contained in Claus plant tail gas in a continuous operation that requires
no solvents or chemicals. Performance of the first industrial
BSR/Selectox I unit has proved that the operation is stable and reliable.
In addition, the process is very cost-effective for an overall sulfur
4
recovery of 97.8 to 98.5 percent.
4.2.5.5 Other Tail Gas Cleanup Processes. The tail gas cleanup
processes described here are not widely utilized on a commercial scale
in this country in the onshore natural gas production activities and are
not likely to be employed in the near future. Therefore, these processes
4-21
-------
Fuel Gas
Sto1ch1ometr1c Air-*
Hydrogenatlon
Hydrolysis
A1r
Reducing
Gas
Generator
Claus-Z Stage
Tall Gas
1
t-25
)
Steam
1
T Reactor
Effluent
Water Cooler
Reheater
I
Oxidation
Reheat
Final Glaus
s?
*
^— *
!T
1
f Selectox-32 j
r
1
LP Steam
, 1
1 1
{ Alumina j
i
|<=> 1 1
Water ,
Steam
1 i
i Water 1
Tall Gas to
Incineration
(1200 ppm S02)
*• Sulfur
» Sour Water
(50 ppm H2S)
Figure 4-10. Flow diagram for the BSR/Selectox I Claus tail gas cleanup process.
-------
and their economics have not been analyzed in detail. A few of these
processes are employed on a commercial scale elsewhere in the world.
Claus 3-stage unit with cold bed adsorption (CBA) process, developed
by Amoco Production Company, is basically an extension of the Claus
reaction on cold Claus catalyst bed at 127°C to 150°C (260°F to 300°F).
Overall sulfur recoveries can be increased to 98 percent. A final
catalytic converter is provided at a low temperature to shift the reaction
equilibrium to increase conversion to sulfur. Sulfur formed during this
process is adsorbed on the catalyst instead of leaving the converter in
the effluent vapor. Sufficient catalyst is provided to maintain the
desired rate of conversion to sulfur. The catalyst is regenerated
periodically to remove adsorbed sulfur and insure continued catalyst
activity. When regeneration is complete, the catalyst is cooled before
being used again as the CBA adsorption converter. Currently, three
units (one in the United States) are in operation at Claus plants with
3
capacities ranging from 15 to 900 metric tons of sulfur intake per day.
IFP-1 (Institut Francais du Petrole), or IFP Clauspol 1500, process
developed in France is simple in design and operation, capable of achieving
3 9
an overall sulfur recovery efficiency of approximately 99.3 percent. '
The tail gases from a one-, two-, or three-stage Claus unit enters a
vertical, packed-tower at about 127°C (260°F). Here the tail gas is
contacted with a countercurrent recirculating stream of polyethylene
glycol (molecular weight 400) containing a dissolved metal-salt catalyst.
H2S and S02 contained in the tail gas transfers from the gas phase into
liquid phase where the Claus reaction takes place. The liquid sulfur
produced (99.9 percent pure) separates from the solvent and settles to
the bottom of the reactor vessel, where it is removed through a seal
leg. The IFP-1 reactor does not reduce COS and CS2 present in the Claus
tail gas feed, and, therefore, these reduced sulfur compounds remain
unchanged in the reactor exhaust gas. It is essential that the H2S/S02
ratio is kept as near to 2:1 as possible. The treated tail gas is
incinerated and discharged to the atmosphere as S02. Currently,
approximately twenty-five units are in operation worldwide for Claus
plants ranging in size from 30 metric tons to 810 metric tons of sulfur
3
intake per day. Only a few units (non-gas applications) exist in this
country.
4-23
-------
The Cleanair process, jointly developed by the J. F. Pritchard and
Company and Texas Gulf Incorporated, is designed around three separate
process steps. During the first step, COS and CS2 compounds are reduced
by operating the Claus reactors at elevated temperatures. In the second
step, the Claus tail gas is quenched to remove water and entrained
sulfur and to reduce the temperature to 50°C (120°F). Then the cooled
gas is fed to a reactor where H2S and S02 (in a 2:1 ratio) react, lowering
the S02 concentration to less than 250 ppmv. Water and sulfur produced
during this reaction are removed. The remaining H2S is oxidized to
elemental sulfur in a Stretford unit which is the third step. The
purified gas is then incinerated to S02 and discharged. The process is
capable of recovering 99.9 percent of the sulfur from the Claus plant
tail gas, leaving no more than 50 ppmv S02 equivalent in the effluent.
The first commercial installation was made at the Gulf Oil Corporation
refinery in Santa Fe Springs, California. No unit is in operation in
the onshore production industry in this country.
In IFP-2 process, licensed by Institut Francais du Petrole of
France, the Claus plant tail gas is first catalytically incinerated to
oxidize all sulfur compounds to S02. The incinerated gas is cooled and
then fed to an ammonia scrubber, where S02 is absorbed and converted to
ammonium sulfite ((NH.^SO.,) and ammonium bisulfite (NH.HSOg). Ammonium
sulfate and thiosulfates are also formed. Gas leaving the reactor is
reheated and vented to the atmosphere at less than 250 ppmv S02. The
S02-rich solution is fed to an S02 regenerator, where the sulfite and
bisulfite are thermally decomposed to S02, NH3 and H20. Ammonium sulfate
and thiosulfate in the saturated solution drawn from the bottom of the
S02 regenerator are thermally decomposed in a sulfate reducer. Gases
from the S02 regenerator and sulfate reducer are combined with an H2S-rich
stream and fed to a catalytic reactor where they are contacted with a
polyethylene glycol solvent. The H2S and S02 react in the solution to
form elemental sulfur. Gases from the reactor are cooled to condense
out H20 and NH2 as NH4OH. The NH4OH solution is returned to the ammonia
scrubber. Any H2S or S02 which leaves the reactor and is not absorbed
by the NH4OH solution is recycled to the incinerator and from there to
4-24
-------
the ammonia scrubber. This process, when applied to Glaus unit tail
gas, is capable of reducing the S02 concentration in the residual tail
gas to 300 ppmv or less.
The Wellman-Lord process, licensed by Davy Powergas, oxidizes all
the sulfur compounds present in Claus plant tail gas to S02. Next, the
hot gases are cooled in a waste heat boiler, then quenched and fed to
the S02 absorber. The absorber is fed a lean solution of sodium sulfite,
which absorbs the S02 by reacting with it to form sodium bisulfite. The
clean gases pass to the stack, while the rich bisulfite solution is
regenerated to recover the sulfite solution. The S02 generated is piped
back to the Claus plant feed or to other processing. Effluent levels of
less than 100 ppmv S02 in the residual tail gas have consistently been
3
achieved in commercial installations. Currently, seven Wellman-Lord
S02 recovery units are in operation treating Claus sulfur recovery plant
tail gas. One unit was installed several years ago at the Chevron,
El Segundo refinery in the United States. This process is relatively
expensive.
Ammonium thiosulfate process, licensed by the J. F. Prichard and
Company for Coastal States Gas Corporation, recovers the sulfur contained
in Claus plant tail gas as an aqueous solution of ammonium thiosulfate.
The sulfur compounds in the Claus tail gas are oxidized to S02 and
absorbed by contact with a weak solution of ammonia, that produces a
solution of mixed ammonium bisulfite, ammonium sulfite and ammonium
sulfate salts. Finally, this solution is converted to ammonium thiosulfate
in a reactor. The clean tail gas contains S02 concentrations of less
3
than 900 ppmv. One unit is in operation in the United States in the
onshore production field that processes 20,000 megagrams/yr sulfur
intake.
4.3 COMPARISON OF SOURCE EMISSION DATA AND RALPH M. PARSONS DESIGN STUDY4
Table 4-1 presents a comparison of source emission test data for
ten different Claus sulfur recovery facilities with the results from the
4
Ralph M. Parsons design study. These Claus facilities vary in sulfur
intake size, number of Claus reactor stages utilized, type of tail gas
cleanup system employed, and the H2S concentrations in the acid gas feed
4-25
-------
Table 4-1. COMPARISON OF SOURCE EMISSION TESTS DATA
AND THE RALPH M. PARSONS DESIGN STUDY FOR CLAUS SULFUR
RECOVERY FACILITIES
Plant
Warren Petroleum's
Monument Facility
Process
equipment
3- stage Claus
unit
Sour gas
volumetric
flow rate
(MmVday)*
2.
1.
52
72
(d)
(o)
Acid gas Average H2S liquid
volumetric concentration in sulfur
flow rate dry acid gas recovery
(MmVday)* (volume percentage) (Mg/day)
32.5
0.06 (o)
24 17.8
(d)
(o)
Sulfur
recovery
efficiency
(percent)
94.8
94.9
Getty Oil's New Hope
Facility3
Shell Oil's
Thomasville
Facility3
Exxon's Blackjack
Creek Facility0
Shell Oil's Bryans
Hill Facility0
Shell Oil's Person
Plant Facility0
Exxon's Santa.
Rosa Facility
Exxon's Flomaton
Facility0
Aquitaine's Ram
River Facility0
Chevron's Fox h
Creek Facility0
2- stage Claus
(two trains in
parallel) with
common 3rd stage
3-stage Claus
unit
3-stage Claus
with SCOT tail
gas cleanup unit
3-stage Claus
unit
*
2- stage Claus
(two trains in
parallel) with
common 3rd stage
3-stage Claus
unit
3-stage Claus
unit
2-stage Claus
unit (four Claus
trains in paral-
lel) with Sulfreen
tail gas cleanup
4- stage Claus
unit (two trains)
1.
0.
70
77
(d)
(0)
152.4
0,17 (o)
55 128.0
(d)
(o),
95.. 0
96.2
2.
2.
0.
1.
1.
0.
0.
0.
0.
0.
83
46
85
87
83
96
97
73
88
99
(d)
(0)
(0)
(d)
(0)
(d)
Co)
(0)
(d)
(0)
N/A
N/A
1.29 (d)
1.03 (o)
0.10 (o)
0.25 (d)
0.21 (o)
0.05 (o)
0.10 (o)
0.52 (d)
0.53 (o)
3.62 (o)
3.40 (o)
1,295.
84.4 1,174-
86.4 101.
253.
68.9 199.
20.6 19.
80.1 104.
136,
20.6 130.
84 3,834..
2
0
4
9
0
4
6
1
1
0
77 3,598.0
(d)
(o)
(o)
(d)
(o)
(o)
(o)
(d)
(o)
(0)
(o)
96.
96.
99.
99.
96.
96.
95.
96.
96.
96.
94.
98.
98.
98.
,8
.64
86
98
43
5
24
5
55
7
5
0
8
65
(o)
(P.)
(o)
(P)
(o)
(P)
(o)
(P)
(o)
CP)
(o)
(o)
(P)
(o)
(P)
(o)
(P)
(o)
*At 289 K (60°F) and 1.01325 x 10sPa (1.0 standard atmosphere).
Detailed emission source test data developed by U.S. Environmental Protection Agency, Emissions Measurement
Branch. For test methods and operating conditions, refer to Appendix C of this document. Tests conducted
by Radian Corporation, Austin, Texas.
Emission source test data supplied by the plant facility. For further details on the source test data
supplied by the individual facility, refer to Appendix C of this document. The data from the facility's
files do not specify test methods.
(d) Design values.
(o) Operating values for normal or average conditions.
(p) Derived from the Ralph H. Parsons design study. Average-of-run efficiency. Refer to Appendix E.
N/A Information not available,
4-26
-------
to the Claus sulfur recovery unit. The design sulfur recovery efficiency
figures from the Parsons study are in close agreement with the source
emission tests data. The data indicate a range of sulfur recovery
efficiencies expected for Claus recovery facilities in relation to the
H2S concentration in the acid gas feed stream and the Claus unit
configuration utilized. An alphabetical designation is given for each
source of Claus sulfur recovery efficiency data, "o" for operating
(emission test) data and "p" for Parsons design study data.
4.4 REFERENCES FOR CHAPTER 4
1. GPA Panelist Outlines Claus Process Improvements in Sulfur Recovery.
Oil and Gas Journal, pp. 92-99. August 7, 1978.
2. Chute, Andrew E. Tailor Sulfur Plants to Unusual Conditions.
Hydrocarbon Processing, pp. 119-124. April 1977.
3. Gas Processing Handbook. Hydrocarbon Processing, pp. 99-170.
April 1979.
4. The Ralph M. Parsons Company. Engineers/Constructors. Sulfur
Recovery Study - Onshore Sour Gas Production Facilities. The Study
was Conducted for TRW. July 1981. The study is presented in
Appendix E.
5. Grekel, H., J. W. Palm, and J. W. Kilmer. Why Recover Sulfur from
HpS? Oil and Gas Journal, pp. 88-101. October 28, 1968.
6. Goar, B. Gene. Sulfur Recovery from Natural Gas Involves Big
Investment. Oil and Gas Journal, pp. 78-85. July 14, 1975.
7. Paskall, Harold G. Capability of the Modified-Claus Process.
Western Research & Development. Alberta, Canada. March 1979.
8. Royan, Tom S. and C. E. Loiselle. High Sulphur Recovery Achieved
from Lean Acid Gas. Paper presented at Canadian Natural Gas Processing
Meeting. Calgary, Alberta. June 14, 1978. Also published in the
Oil and Gas Journal, January 29, 1979.
9. GPA HpS Removal Panel-4 and Panel-5. Processes Clean Up Tail Gas
and More Claus Cleanup Processes. Oil and Gas Journal. August 28,
1978 and September 11, 1978.
10. Shell Claus Off-gas Treating (SCOT) Process, Patents & Licensing
Division. Shell Development Company, A Division of Shell Oil
Company.
4-27
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11. Gencq, Joseph M. and Samuel S. Tarn. Characterization of Sulfur
from Refinery Fuel Gas. U.S. Environmental Protection Agency.
Research Triangle Park, North Carolina. Publication No. EPA-
450/3-74-055. June 1974.
12. Crockett, Edward P. and Ronald E. Cannon. Summarized Comments on
BID Draft Chapters 3-6 (September 26, 1981) from American Petroleum
Institute and Gas Processors Association.
4-28
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5. MODIFICATION AND RECONSTRUCTION
5.1 BACKGROUND
An existing facility as defined in Section 60.2 of the General
Provisions (40 CFR 60) is, with reference to a stationary source, an
apparatus for which a standard of performance is promulgated, and the
construction or modification of which commenced prior to the date of
proposal of that standard. An affected facility means, with reference
to a stationary source, any apparatus to which a standard is applicable.
An existing facility may become an affected facility and therefore
subject to the standards, through modification or reconstruction, as
described below. The affected facility in the onshore natural gas
production industry is the sour natural gas sweetening operation - removal
of hydrogen sulfide (H^S) and carbon dioxide (C02) from sour natural
gas - followed by either incineration of the acid gas stream or a sulfur
recovery operation (elemental sulfur recovered from HLS in acid gas)
with final incineration of unconverted H^S. Emission standards promulgated
under Section lll(b) of the Clean Air Act apply to all facilities within
the onshore natural gas production industry that are newly constructed,
modified, or reconstructed after the date of proposal of the standard.
Uncertainties may arise as to the determination of whether any existing
facility has been "modified" or "reconstructed". These issues are
addressed in §60.14 and §60.15 , respectively of Title 40 of the Code of
Federal Regulations Part 60, which define conditions under which an
existing facility that is altered may be considered to be modified or
reconstructed.
5.1.1 Modification
Any physical or operational change to an existing facility that
results in an increase in the emission rate to the atmosphere of any
pollutant to which a standard applies may be considered a modification.
5-1
-------
Upon modification, an existing facility becomes an affected facility for
each pollutant to which a standard applies and for which there is an
increase in the emission rate to the atmosphere. This definition is
described in §60.14. Certain physical or operational changes that are
not considered a modification include:
(a) Maintenance, repair, and replacement, determined to be routine
for the facility.
(b) An increase in production rate of an existing facility without
a capital expenditure as defined in §60.2.
(c) An increase in the hours of operation.
(d) Use of an alternate fuel or raw material if prior to the
standard, the existing facility was designed to accommodate that alternative
use. A facility shall be considered to be designed to accommodate an
alternate fuel or raw Material if its use could be accomplished under
the facility's construction specifications as amended prior to the
change.
(e) The addition or use of any system or device whose primary
function is the reduction of air pollutants, except when an emission
control system is removed or replaced by a system that is determined
less environmentally beneficial.
(f) The relocation or change in ownership of an existing facility.
The above exemptions are described in detail in §60.14.
An increase in the production rate of an existing facility is
designated as a modification only if there is an increase in the emission
rate and the total cost necessary to accomplish the change constitutes a
"capital expenditure." Capital expenditure means an expenditure for a
physical or operational change to an existing facility that exceeds the
product of the applicable "annual asset guideline repair allowance
percentage (AAGRAP)" specified in the latest edition of Internal Revenue
Service (IRS) Publication 534 and the existing facility's original cost
as defined by Section 1012 of the Internal Revenue Code.
5.1.2 Reconstruction
Reconstruction means the replacement of components of an existing
facility to such an extent that (1) the fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost that would be
5-2
-------
required to construct a comparable entirely new facility, and (2) it is
technologically and economically feasible to meet the applicable standards.
An existing facility, upon reconstruction, becomes an affected
facility, irrespective of any change in emission rate. Fixed capital
cost means the capital needed to provide all the depreciable components.
5.2 APPLICABILITY TO ONSHORE PRODUCTION INDUSTRY
5.2.1 Modifications to Onshore Production Industry
This section describes typical situations in the industry and
concludes that no modifications are anticipated that would subject the
industry to compliance with the standard.
In a typical situation, an onshore natural gas production facility
processes the natural gas throughput from several wells located in one
reservoir or several reservoirs located in a given field. As this field
is further developed, production throughput will rise to the plant
capacity (design capacity) where it will normally remain steady-state
until the reservoirs are significantly depleted. During the period the
production throughput increases, the sulfur recovery will increase to
near design capacity and remain at that level. Then, during the period
of decreasing production throughput, the recovery decreases gradually to
low levels. Emissions of sulfur dioxide (SOp) may increase or decrease
during such production variations. However, the recovery efficiency is
not changed (acid gas H2S/COp ratio unchanged). Because a sulfur recovery
facility is normally designed at the maximum anticipated recovery level,
increasing or decreasing recovered sulfur production will not require
any significant physical or operational changes in the recovery facility
and will be accomplished without any capital expenditure. Therefore,
this will not constitute a modification.
In another situation, an increase in H2S/C02 volume percent ratio
in the acid gas feedstream will increase recovery efficiency and therefore
sulfur production rate. A decrease in the ratio in the acid gas feedstream
will decrease recovery efficiency and therefore sulfur production rate.
Emission rate increases when recovery efficiency decreases and vice
versa. However, these changes are accomplished without a capital
expenditure and, therefore, do not constitute a modification.
5-3
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The acid gas feed stream to a sulfur recovery facility may increase
above the originally designed capacity due to increased production
activities and/or introduction of other acid gas streams. This may
necessitate alterations to accommodate the increased production. The
alterations may include: (1) changes to the Claus reaction furnace—
increase in heat exchange capacity, auxiliary burner installation or
replacement of refractory lining, or (2) any Claus process change—split
flow, preheatj or inline burner. The alterations described may or may
not reduce emission levels, but if the alterations incur no capital
expenditure, as defined in CFR §60.2, the changes would not constitute a
modification and the existing sulfur recovery facility would not be
subject to compliance with the standard.
5.2.2 Reconstructions to Onshore Production Industry
Changes to existing facilities that would qualify as "reconstructions"
are not anticipated in the onshore natural gas production industry.
Construction of an additional catalyst reactor stage to an existing
Claus unit, or of another Claus unit in parallel with the existing Claus
unit, or of an additional Claus reactor stage in series, is not a
"reconstruction" since the replacement costs are not expected to exceed
50 percent of the cost of an entirely new facility.
5.3 REFERENCES FOR CHAPTER 5
1. Code of Federal Regulations 40, 1980 Protection of Environment,
Part-53 to Part 80. Revised as of July 1, 1980. Published by the
Office of the Federal Register.
5-4
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6. MODEL PLANTS AND REGULATORY ALTERNATIVES
This chapter defines the model plants which have been selected to
represent the onshore natural gas production industry and the regulatory
alternatives by which sulfur dioxide (SO,,) emissions from the facility
can be regulated.
6.1 MODEL PLANTS
In order to have a common basis for calculating the various impacts
of each regulatory alternative, the concept of model plants is utilized.
Hypothetical plants are defined in terms of the process, production
rate, raw materials, products, and other parameters that describe the
industry. Usually several model plants are defined to include the types
and size ranges of plants commonly found in the industry. Typically,
the model plants reflect the latest technology and describe plants that
are likely to be built as the industry expands. Dollar costs, resource
requirements, environmental impacts, and other determinations are then
made for each model plant. The results are applied in estimating economic
and related effects and levels of pollution control attainable for
selected control equipment and techniques.
A total of seven model plants have been developed to project the
environmental and economic impacts of various emission control alterna-
tives on onshore natural gas production facilities. Table 6-1 presents
process parameters and other descriptions of the onshore natural gas
production model plants. These model plants are characterized by the
sulfur intake rate to the sulfur recovery unit and by the volume percent
ratio of hydrogen sulfide (H2S) to carbon dioxide ((XL) in the acid gas
feed to the sulfur recovery unit. These model plants were developed
using process data from existing facilities along with technical data
from meeting reports, plant visit reports, and a review of the published
studies and literature.
6-1
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Table 6-1. MODEL PLANT PARAMETERS
*
Model Plant 1
1. Sulfur intake: 5.08 Mg/d (5.0 LT/D)a
2. Acid gas H2S/C02 volume percent ratio: 20/80
3. Liquid sulfur recovered: None
4. Sulfur recovery efficiency: No sulfur recovery
5. Control system (for sulfur recovery) utilized: Incinerator
(thermal oxidizer)
6. S02 emission rate: 3,555 Mg/y
7. SO2 concentration in stack gas: 53,400 ppmv
8. Stack gas composition:0
kmol/h Ib mol/h mol percent
S02 6.60 14.56 5.33
02 8.43 18.58 6.81
N2 70.31 155.00 56.81
C02 26.42 58.24 21.35
H20 12.00 26.46 9.70
Total 123.76 272.84 100.00
9. Stack gas mass flow rate: 4,042 kg/h (8,910 Ib/h)
10. Stack gas volumetric flow rate: 3.07 m3/s (6,509 acfm)b
11. Stack height: 76.2 m (250 ft)
Stack inside diameter: 0.914 m (3 ft)
12. Stack gas exit velocity: 4.66 m/s (15.3 ft/s)
Stack gas exit temperature: 1,089 K (1,500°F)
13. Utilities consumption: Fuel gas - marginal consumption
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-2
-------
Table 6-1. Continued
Model Plant 1
1. Sulfur intake: 5.08 Mg/d (5.0 LT/D)a
2. Acid gas HpS/COp volume percent ratio: 50/50
3. Liquid sulfur recovered: None
4. Sulfur recovery efficiency: No sulfur recovery
5. Control system (for sulfur recovery) utilized: Incinerator
(thermal oxidizer)
6. SOp emission rate: 3,555 Mg/y
7. S02 concentration in stack gas: 49,640 ppmv
8. Stack gas composition:0
kmol/h Ib mol/h mol percent
S02 6.60 14.56 4.96
02 14.84 32.72 11.16
N2 93.65 206.47 70.40
C02 6.60 14.56 4.96
H20 11.33 24.98 8.52
Total 133.02 293.29 100.00
9. Stack gas mass flow rate: 4,017 kg/h (8,856 Ib/h)
10. Stack gas volumetric flow rate: 3.30 m /s (6,997 acfm)b
11. Stack height: 76.2 m (250 ft)
Stack inside diameter: 0.914 m (3 ft)
12. Stack gas exit velocity: 5.03 m/s (16.5 ft/s)
Stack gas exit temperature: 1,089 K (1,500°F)
13. Utilities consumption: Fuel gas - marginal consumption
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-3
-------
Table 6-1. Continued
Model Plant 2
1. Sulfur intake: 10.16 Mg/d (10 LT/D)a
2. Acid gas H2S/C02 volume percent ratio: 12.5/87.5
3. Liquid sulfur recovered: 9.28 Mg/d
4. Sulfur recovery efficiency: 91.3 percent
5. Control system (for sulfur recovery) utilized: Claus 2-stage unit
6. SOp emission rate: 739 Mg/y
7. SOp concentration in stack gas: 6,330 ppmv
8. Stack gas composition:0
kmol/h 1b mol/h mol percent
S02 1.37 3.03 0.63
02 2.94 6.49 1.36
N2 80.29 177.00 36.98
C02 97.89 215.80 45.09
H20 34.60 76.29 15.94
Total 217.09 478.61 100.00
9. Stack gas mass flow rate: 7,359 kg/h (16,233 Ib/h)
10. Stack gas volumetric flow rate: 4.56 m /s (9,670 acfm)b
11. Stack height: 38.1 m (125 ft)
Stack inside diameter: 0.914 m (3 ft)
12. Stack gas exit velocity: 22.8 ft/s
Stack gas exit temperature: 922.0 K (1,200°F)
13. Utilities consumption:
600 psig steam 590.6 kg/h (1,302 Tb/h)
Treated boiler feedwater 1,404 kg/h (3,095 lb/h)
Electric power 59 kW q
Fuel gas 3.92 x 103 J/h (3.72 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-4
-------
Table 6-1. Continued
Model Plant 2
1. Sulfur intake: 10.16 Mg/d (10 LT/D)a
2. Acid gas H2S/C02 volume percent ratio: 20/80
3. Liquid sulfur recovered: 9.33 Mg/d
4. Sulfur recovery efficiency: 91.8 percent
5. Control system (for sulfur recovery) utilized: Claus 2-stage unit
6. S02 emission rate: 701 Mg/y
7. S02 concentration in stack gas: 8,820 ppmv
8. Stack gas composition:0
kmol/h Ib mol/h mol percent
S00 1.30 2.87 0.88
1.95 4.29 1.32
61.10 134.70 41.39
56.25 124.00 38.10
27.02 59.57 18.31
147.62 325.43 100.00
9. Stack gas mass flow rate: 4,820 kg/h (10,626 Ib/h)
10. Stack gas volumetric flow rate: 3.10 m3/s (6,575 acfm)b
11. Stack height: 38.1 m (125 ft)
Stack inside diameter: 0.914 m (3 ft)
12. Stack gas exit velocity: 4.72 m/s (15.5 ft/s)
Stack gas exit temperature: 922.0 K (1,200°F)
13. Utilities consumption:
600 psig steam 385 kg/h (848 Ib/h)
Treated boiler feedwater 1,313 kg/h (2,894 Ib/h)
Electric power 56 kW q fi
Fuel gas 2.47 x 1(T J/h (2.34 x 10b Btu/h)
14. Operating schedule: 24 hr/d, 350 d/y
(continued)
6-5
-------
Table 6-1. Continued
Model Plant 2
1. Sulfur intake: 10.16 Mg/d (10 LT/D)a
2. Acid gas H2S/C02 volume percent ratio: 50/50
3. Liquid sulfur recovered: 9.53 Mg/d
4. Sulfur recovery efficiency: 93.8 percent
5. Control system (for sulfur recovery) utilized: Claus 2-stage unit
6. S02 emission rate: 526 Mg/y
7. SO 2 concentration in stack gas: 12,680 ppmv
8. Stack gas composition:
kmol/h 1b mol/h mol percent
S02 0.98 2.15 1.27
02 0.91 2.00 1.18
N2 41.02 90.43 53.34
C02 14.59 32.16 18.97
H£0 19.40 42.78 25.24
Total 76.90 169.52 100.00
9. Stack gas mass flow rate: 2,233 kg/h (4,922 Ib/h)
^ K
10. Stack gas volumetric flow rate: 1.62 m /s (3,425 acfm)
11. Stack height: 30.5 m (100 ft)
Stack inside diameter: 0.914 m (3 ft)
12. Stack gas exit velocity: 2.45 m/s (8.1 ft/s)
Stack gas exit temperature: 922.0 K (1,200°F)
13. Utilities consumption:
600 psig steam 108 kg/h (239 Ib/h)
Treated boiler feedwater 1,161 kg/h (2,560 Ib/h)
Electric power 51 kW q c
Fuel gas 1.002 x 1CT J/h (0.95 x 10 Btu/hr)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-6
-------
Table 6-1. Continued
Model Plant 3
1. Sulfur intake: 101.6 Mg/d (100 LT/D)a
2. Acid gas H2S/C02 volume percent ratio: 12.5/87.5
3. Liquid sulfur recovered: 94.87 Mg/d
4. Sulfur recovery efficiency: 93.39 percent
5. Control system (for sulfur recovery) utilized: Claus 3-stage unit
6. S02 emission rate: 5,639 Mg/y
7. S02 concentration in stack gas: 4,830 ppmv
8. Stack gas composition:0
so2
°2
N,
co£
Total 2,168.26 4,780.62 100.00
9. Stack gas mass flow rate: 73,440 kg h (161,914 Ib/h)
10. Stack gas volumetric flow rate: 25.0 m/s (52,950 acfm)b
11. Stack height: 91.4 m (300 ft)
Stack inside diameter: 1.37 m (4.5 ft)
12. Stack gas exit velocity: 16.9 m/s (55.5 ft/s)
Stack gas exit temperature: 505 K (450°F)
13. Utilities consumption:
Treated boiler feedwater 29,590 kg/h (65,230 Ib/h)
Electric power 308 kW q -
Fuel gas 39.90 x 10s J/h (37.84 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
kmol/h
10.48
29.35
801.04
979.59
347.80
Ib mol/h
23.11
64.71
1,766.00
2,160.00
766.80
mol percent
0.48
1.36
36.94
45.18
16.04
6-7
-------
Table 6-1. Continued
Model Plant 3
1. Sulfur intake: 101.6 Mg/d (100 LT/D)a
2. Acid gas H2S/C02 volume percent ratio: 20/80
3. Liquid sulfur recovered: 96.0 Mg/d
4. Sulfur recovery efficiency: 94.50 percent
5. Control system (for sulfur recovery) utilized: Claus 3-stage unit
6. S02 emission rate: 4,687 Mg/y
7. S02 concentration in stack gas: 5,910 ppmv
8. Stack gas composition:0
so2
°2
N2
co2
kmol/h
8.71
19.34
608.70
563.72
272.50
Ib mol/h
19.21
42.64
1,342.00
1,243.00
600.80
mol percent
0.59
1.31
41.32
38.28
18.50
Total 1,472.97 3,247.65 100.00
9. Stack gas mass flow rate: 47,960 kg/h (105,729 Ib/h)
10. Stack gas volumetric flow rate: 16.98 m3/s (35,972 acfm)b
11. Stack height: 83.8 m (275 ft)
Stack inside diameter: 1.22 m (4 ft)
12. Stack gas exit velocity: 14.5 m/s (47.7 ft/s)
Stack gas exit temperature: 505 K (450°F)
13. Utilities consumption:
Treated boiler feedwater 23,480 kg/h (51,770 Ib/h)
Electric power 273 kW
Fuel gas 25.62 J/h (24.30 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-8
-------
Table 6-1. Continued
Model Plant 3
1. Sulfur intake: 101.6 Mg/d (100 LT/D)a
2. Acid gas H2$/C02 volume percent ratio: 50/50
3. Liquid sulfur recovered: 97.57 Mg/d
4. Sulfur recovery efficiency: 96.05 percent
5. Control system (for sulfur recovery) utilized: Claus 3-stage unit
6. S02 emission rate: 3,368 Mg/y
7. S02 concentration in stack gas: 8,170 ppmv
8. Stack gas composition:0
kmol/h
S02 6.26
02 9.00
N2 408.30
C02 146.83
H20 195.86
Total 766.25 1,689.25 100.00
9. Stack gas mass flow rate: 22,120 kg/h (48,768 Ib/h)
10. Stack gas volumetric flow rate: 8.83 m3/s (18,710 acfm)b
11. Stack height: 68.6 m (225 ft)
Stack inside diameter: 0.914 m (3 ft)
12. Stack gas exit velocity: 13.4 m/s (44.1 ft/s)
Stack gas exit temperature: 505 K (450°F)
13. Utilities consumption:
Treated boiler feedwater 16,624 kg/h (36,650 Ib/h)
Electric power 233 kW q
Fuel gas 10.66 x 10s J/h (10.11 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
Ib mol/h
13.81
19.84
900.10
323.70
431.80
mol percent
0.82
1.18
53.28
19.16
25.56
6-9
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Table 6-1 Continued
Model Plant 4
1. Sulfur intake: 563.8 Mg/d (555 LT/D)a
2. Acid gas HLS/CO,, volume percent ratio: 50/50
3. Liquid sulfur recovered: 541.5 Mg/d
4. Sulfur recovery efficiency: 96.05 percent
5. Control system (for sulfur recovery) utilized: Claus 3-stage unit
6. S02 emission rate: 18,711 Mg/y
7. S02 concentration in stack gas: 8,200 ppmv
8. Stack gas composition:0
kmol/h 1b mol/h mol percent
0.82
1.17
53.29
19.16
25.56
so2
°2
N2
co2
H20
34.8
49.9
2,266.0
814.9
1,086.85
76.7
110.1
4,995.6
1,796.5
2,396.5
Total 4,252.45 9,375.4 100.00
9. Stack gas mass flow rate: 122,770 kg/h (270,663 Ib/h)
"5 K
10. Stack gas volumetric flow rate: 49.0 m /s (103,844 acfm)
11. Stack height: 137.2 m (450 ft)
Stack inside diameter: 1.83 m (6 ft)
12. Stack gas exit velocity: 18.65 m/s (61.2 ft/s)
Stack gas exit temperature: 505 K (450°F)
13. Utilities consumption:
Treated boiler feedwater 91,886 kg/h (202,575 Ib/h)
Electric power 1,040 kW q -
Fuel gas 73.0 x 10y J/h (69.2 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-10
-------
Table 6-1. Continued
Model Plant 5
1. Sulfur intake: 563.8 Mg/d (555 LT/D)
2. Acid gas H2S/C02 volume percent ratio: 80/20
3. Liquid sulfur recovered: 544.9 Mg/d
4. Sulfur recovery efficiency: 96.64 percent
5. Control system (for sulfur recovery) utilized: Claus 3-stage unit
6. S02 emission rate: 15,890 Mg/y
S02 concentration in stack gas: 12,700 ppmv
Stack gas composition:0
Ib mol/h
65.10
79.70
4,379.3
521.4
79.7
mol percent
1.27
1.56
85.44
10.17
1.56
Total 2,324.7 5,125.2 100.00
9. Stack gas mass flow rate: 69,768 kg/h (153,812 Ib/h)
Q U
10. Stack gas volumetric flow rate: 26.8 m /s (56,768 acfm)
11. Stack height: 121.9 m (400 ft)
Stack inside diameter: 1.60 m (5.25 ft)
12. Stack gas exit velocity: 43.7 ft/s
Stack gas exit temperature: 505 K (450°F)
13. Utilities consumption:
Treated boiler feedwater 83,579 kg/h (184,260 Ib/h)
Electric power 930 kW q ,.
Fuel gas 48.66 x 10y J/h (46.15 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-11
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Table 6-1. Continued
Model Plant 6
1. Sulfur intake: 1015.9 Mg/d (1,000 LT/D)a
2. Acid gas FLS/CO^ volume percent ratio: 50/50
3. Liquid sulfur recovered: 975.8 Mg/d
4. Sulfur recovery efficiency: 96.05 percent
5. Control system (for sulfur recovery) utilized: Claus 3-stage unit
6. S02 emission rate: 33,709 Mg/y
7. S02 concentration in stack gas: 8,170 ppmv
8. Stack gas composition:0
kmol/h Ib mol/h mol percent
0.82
1.17
53.29
19.16
25.56
so2
°2
N,
co2
H20
62.6
90.0
4,083.0
1,468.0
1,959.0
138.10
198.40
9,001.00
3,237.00
4,318.00
Total 7,662.6 16,892.50 100.00
9. Stack gas mass flow rate: 221,210 kg/h (487,676 Ib/h)
10. Stack gas volumetric flow rate: 88.3 m3/s (187,105 acfm)b
11. Stack height: 182.9 m (600 ft)
Stack inside diameter: 2.13 m (7 ft)
12. Stack gas exit velocity: 24.7 m/s (81.0 ft/s)
Stack gas exit temperature: 505 K (450°F)
13. Utilities consumption:
Treated boiler feedwater 165,560 kg/h (365,000 Ib/h)
Electric power 1,876 kW q ,.
Fuel gas 131.4 x 10y J/h (124.6 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
(continued)
6-12
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Table 6-1. Concluded
Model Plant 7
1. Sulfur intake: 1015.9 Mg/d (1,000 LT/D)a
2. Acid gas H2S/C02 volume percent ratio: 80/20
3. Liquid sulfur recovered: 981.8 Mg/d
4. Sulfur recovery efficiency: 96.64 percent
5. Control system (for sulfur recovery) utilized: Claus 3-stage unit
6. S02 emission rate: 28,630 Mg/y
7. S02 concentration in stack gas: 12,700 ppmv
8. Stack gas composition:0
kmol/h Ib mol/h mol percent
1.27
1.56
85.44
10.17
1.56
so2
°2
N2
co2
H20
53.2
65.1
3,579.0
426.1
65.1
117.3
143.6
7,890.7
939.4
143.6
Total 4,188.5 9,234.6 100.00
9. Stack gas mass flow rate: 125,708 kg/h (277,139 Ib/h)
10. Stack gas volumetric flow rate: 48.3 m3/s (102,284 acfm)b
11. Stack height: 167.6 m (550 ft)
Stack inside diameter: 1.83 m (6 ft)
12. Stack gas exit velocity: 18.4 m/s (60.3 ft/s)
Stack gas exit temperature: 505 K (450°F)
13. Utilities consumption:
Treated boiler feedwater 150,593 kg/h (332,000 Ib/h)
Electric power 1,676 kW q ,.
Fuel gas 87.68 x 103 J/h (83.16 x 10b Btu/h)
14. Operating schedule: 24 h/d, 350 d/y
aLT/D - long tons (2,240 Ib) per day
acfm - actual cubic feet per minute at 1.0 standard atmosphere
(1.01325 x 10* Pa), 505 K (450°F)
cMay contain trace amounts of H2S, CO, COS, and CS?
6-13
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6.1.1 Model Plant Sizes
The sizes of the model plants specified in Table 6-1 span the sizes
currently existing in the industry and are also representative of the
sulfur recovery capacity of projected future plants within the industry.
The smallest model plant represents 5.08 Mg/d (5 LT/D) of sulfur intake
to sulfur recovery unit, and the largest model plant represents 1,015.9 Mg/d
(1,000 LT/D) of sulfur intake to sulfur recovery unit. The sizes of the
remaining model plants are 10.16 Mg/d (10 LT/D), 101.6 Mg/d (100 LT/D)
and 563.8 Mg/d (555 LT/D).
6.1.2 HsS/COg Volume Percent Ratio
The ratio of volume percent concentration of HpS to that of COp in
the acid gas feed to the sulfur recovery unit was considered in the
development of each model plant. The ratio, as found in the industry
practice, ranged from 12,5 percent hLS/sy.S percent COp to 80 percent
H2S/20 percent CO—
6.1.3 Baseline Control Levels
Baseline controls are defined as those levels of control expected
to be utilized in new facilities in the absence of a standard. Baseline
controls are used to assess incremental environmental, economic, and
energy impacts of each regulatory alternative applied to the model
plants.
Baseline control technology for sulfur recovery plants was chosen
according to the amount of sulfur available for processing. Generally
the larger the rate of sulfur intake and the higher the concentration of
. FLS in the gas, the higher the degree of control of emitted S02.
Three levels of control have been determined to specify baseline
control technologies in the model plants. Existing regulations and
existing control levels in current industry practice were reviewed in
determining these control levels. Table 6-2 presents baseline control
levels for each model plant (see Regulatory Alternative I). Model
Plant 1 incorporates sweetening of sour natural gas and thermal oxidation
(without sulfur recovery) of H^S in the acid gas separated in sweetening
unit into S02 that is then released through an incinerator stack into
the ambient atmosphere. Model Plant 2 incorporates sweetening of sour
6-14
-------
Table 6-2. ONSHORE NATURAL GAS PRODUCTION MODEL PLANTS, BASELINE
CONTROLS AND REGULATORY ALTERNATIVES
Regulatory Alternative
I II
Size Acid gas feed Baseline
Model (sulfur intake) H2S/C02 ratio control
plant Mg/d LT/D by volume (no NSPS)
1 5.1 5 a Incinerator Incinerator
Z 10.2 10 a Claus 2-stage Claus 2-stage
3 101.6 100 a Claus 3- stage Claus 3-stage
4 563.8 555 50/50 Claus 3-stage Sulfreen
cr>
5 563.8 555 80/20 Claus 3-stage Sulfreen
6 1,015.9 1,000 50/50 Claus 3-stage Sulfreen
7 1,015.9 1,000 80/20 Claus 3-stage Sulfreen
III
Claus 2-stage
Claus 3-stage
Sul f reen
Sulfreen
SCOT/BSRMDEA
or BSRP
Sulfreen
SCOT/BSRMDEA
or BSRP
IV
Claus 3-stage
Claus 3-stage
Sulfreen
SCOT/BSRMOEA
or BSRP
SCOT/BSRMDEA
or BSRP
SCOT/BSRMDEA
or BSRP
SCOT/BSRMDEA
or BSRP
V
Claus 3-stage
Sulfreen
SCOT/BSRMDEA
or BSRP
SCOT/BSRMDEA
or BSRP
SCOT/BSRMDEA
or BSRP
SCOT/BSRMDEA
or BSRP
SCOT/BSRMDEA
or BSRP
VI
Sulfreen
Sulfreen
SCOT/
BSRMDEA
or BSRP
SCOT/
BSRMDEA
or BSRP
SCOT/
BSRMDEA
or BSRP
SCOT/
BSRMDEA
or BSRP
SCOT/
BSRMDEA
or BSRP
aCovers entire ratio range from 12.5/87.5 to 80/20.
SCOT Shell Claus Offgas Treatment
BSRMOEA Beavon Sulfur Recovery Methyldiethanolamine (HDEA); BSRMDEA equivalent to SCOT
BSRP Beavon Sulfur Recovery Process
-------
natural gas, Claus 2-stage sulfur recovery from acid gas with thermal
oxidation of unconverted H^S into SOp and subsequent release into the
ambient atmosphere through an incinerator stack. Model Plants 3 through
7 incorporate sweetening of sour natural gas, Claus 3-stage sulfur
recovery from acid gas with thermal oxidation of unconverted hLS into
SOp and subsequent release into the ambient atmosphere through an
incinerator stack.
6.2 REGULATORY ALTERNATIVES
The purpose of this section is to define the various regulatory
alternatives and consider their effectiveness for reducing baseline
control emissions. The effects of a regulatory alternative can be
assessed from a summation of its effects on a combination of individual
model plants. Six regulatory alternatives have been developed to perform
analyses on the model plants. These regulatory alternatives are summa-
rized in Table 6-2. These alternatives entail various degrees of emission
control and are developed based upon cost effectiveness values derived
from design data and cost figures provided by the Ralph M. Parsons
Company. The data and figures from the Parsons are presented in detail
in Appendix E. The impacts of each alternative will be evaluated in the
economic, environmental, and SCL dispersion analyses. Sulfur recovery
control technologies presented in Table 6-2 represent those technologies
currently in use in the industry and expected to be used for many years.
Under Regulatory Alternative I, no new source performance
standard (NSPS) would be promulgated for the onshore natural gas production
industry. This alternative uses baseline emission controls. Regulatory
Alternatives II through VI were selected as groups of processes that
display increasing values of cost effectiveness. Cost effectiveness is
defined as net annualized costs required to operate the control system
minus net annualized costs required to operate the baseline control
system divided by the additional amount (megagrams) of S02 emissions
reduced beyond the baseline.
6-16
-------
7. ENVIRONMENTAL IMPACT
The environmental impacts associated with each regulatory alternative
are discussed with respect to both primary and secondary incremental
impacts on air, water, solid waste, and energy resulting from the use of
alternative control systems. Impacts of establishing emission standards
(based upon application of the different control systems) are compared
with the impacts of not proposing or promulgating standards of performance
for new sources. Both beneficial and adverse impacts are assessed for
each of the model plants presented in Chapter 6. The regulatory
alternatives described for the model plants consist of various sulfur
recovery and/or tail gas treatment units. The applicable sulfur recovery
efficiencies are applied to predict the long-term effects on nationwide
emissions that could result from promulgation of each regulatory
alternative.
7.1 AIR POLLUTION IMPACT
7.1.1 Dispersion Modeling Results
As part of an air pollution impact study, a dispersion modeling
analysis of the regulatory alternatives for each model plant (Table 6-2)
was conducted. The locations of natural gas production facilities are
generally in non-urban areas; moreover, S02 is released into the atmosphere
through a tall stack. Therefore, a single source model (CRSTER) was
used. It was also determined that no treatment of (building) downwash
was required. The model was used to calculate maximum concentration
(ambient) for averaging periods of 1-hour, 3-hour, 24-hour and a year at
various radial distances. The six radial locations ranged from 0.4 to
15 kilometers. Meteorology data from locations in West Texas and the
Western Gulf Basin regions were reviewed. Two surface and upper air
data sets, one for Houston and the other for Amarillo, were selected.
-------
In total, 72 scenarios were tested, twelve model plants each with six
regulatory alternatives. Table 7-1 summarizes the results for the
1-hour, 3-hour, 24-hour and annual averaging periods for both the Houston
data and the Amarillo data. For each model plant and regulatory alternative
combination, the highest second high (for short-term periods) or highest
(for the annual average) S02 concentration in microgram per cubic meter
is presented, independent of location distance. The results indicate
that all of the scenarios tested meet national ambient air quality
standard (NAAQS) levels. The methods, data bases and results are documented
in the report available in the Onshore S02 Docket No. A-80-20.
7.1.2 Effects of Regulatory Alternatives on Nationwide S02 Emissions
The summary of impacts for the model plants with each of the six
regulatory alternatives (presented in Table 6-2) was extrapolated to
estimate the national air quality impact over the period from 1983
through 1987. Using past onshore natural gas sulfur recovery facility
growth (Table 9-6) that is based upon December 1979 data from the Chemical
Economics Handbook—Stanford Research Institute (SRI) International for
the period from 1951 through 1980, and the data on new onshore natural
gas production from the American Gas Association (AGA), the future
growth of the industry for the time period of interest may be projected.
Information outlining the methodology used to develop this 5-year projection
is contained in Chapter 9. It was found that for 1980 the actual capacity
for an average facility was 72.6 percent of the facility's design
capability. However, considering anticipated increases in production
activity by 1982 due to both larger energy demand and demand for domestic
sulfur supplies, 75 percent actual capacity was assumed to better represent
current trends. Thus 75 percent of the design capability of the industry
was used to calculate S02 emissions for projected new facilities.
The projected total new onshore natural gas production capacities
for 1983 through 1987 with sweetening and those with sweetening as well
as sulfur recovery are listed in Table 9-21. The difference between
these two capacities yields the new capacity without sulfur recovery.
The H2S removed from this natural gas is incinerated and released to the
atmosphere. This estimates nationwide uncontrolled S02 emissions. The
number of projected facilities not recovering sulfur may then be calculated
7-2
-------
Table 7-1. SUMMARY OF S(L CONCENTRATIONS FROM DISPERSION MODELING ANALYSES FOR EACH MODEL
PLANT AND REGULATORY ALTERNATIVE ON THE BASIS OF THE HOUSTON AND AMARILLO DATA
Ac Id fat
IMol H.S/CO,
•lent Mtio
U 20/80
16 50/50
U 12.5/67.5
• 20/80
It 50/50
M 12.5/87.5
• 20/80
1C 50/50
4 50/50
1 60/20
6 50/50
I 60/20
Heeulatory Alternative*
Hour 3 Hour
719.0 347.0
686.0 337.0
142.0 72.1
183.0 91.1
313.0 191.0
275.0 115.0
126.0 150.0
399.0 225.0
1008.0 401.0
1253.0 529.0
1383.0 493.0
1564.0 622.0
1
24 Hour Annual
80.4 10.0
65.9 9.65
10.5 1.61
35.9 4.33
70.9 6.72
31.2 3.93
41.7 5.02
53.5 6.60
124.0 14.0
155.0 18.2
189.0 16.7
192.0 21.1
II
1 Hour 3 Hour
719.0 347.0
686.0 337.0
142.0 72.1
183.0 91.9
313.0 191.0
275.0 115.0
328.0 150.0
399.0 225.0
400.0 162.0
561.0 237.0
5(1.0 200.0
(99.0 376.0
24 Hour
80.4
65.9
30.5
35.9
70.9
33.2
41.7
53.5
50.2
69.4
76.7
H.O
Annual 1 Hour
10.0 217.0
9.65 320.0
1.61 97.9
4.11 125.0
8.72 188.0
1.91 114.0
5.02 140.0
(.60 238.0
5.65 406.0
8.11 11.2
6.79 561.0
9.66 14.4
III
1 Hour 24 Hour
131.0 47.9
182.0 55.1
60.9 26.1
78.2 12.5
115.0 42.6
48.7 15.7
75.7 24.6
140.0 36.1
162.0 50.2
7.71 1.64
200.0 76.7
7.77 2.66
Annual 1 Hour 1 Hour
5.91 174.0 105.0
7.05 258.0 146.0
1.02 97.9 (0.9
1.87 125.0 78.2
5.24 188.0 115.0
1.64 114.0 48.7
2.86 140.0 75.7
4.67 238.0 140.0
8.65 20.0 10.7
0.134 11.2 7.71
6.79 22.5 11.4
0.276 14.4 7.77
IV
24 Hour Annual
38.1 4.724
44.2 5.64
26.1 3.02
32.5 1.87
42.6 5.24
15.7 1.84
24.6 2.88
38.3 4.67
3.90 0.384
3.64 0.334
4.20 0.425
2.86 0.276
V
1 Hour 3 Hour 24 Hour
174.0 105.0 38.3
256.0 146.0 44.2
130.0 77.8 28.3
170.0 94.0 11.4
246.0 124.0 14.7
6.61 1.57 1.36
10.1 6.76 2.56
19.7 11.8 5.13
20.0 10.7 3.90
11.2 7.71 3.64
22.5 11.4 4.20
14.4 7.77 2.8C
Annual 1 Hour
4.72 126.0
5.64 169.0
0.952 130.0
3.95 170.0
4.56 246.0
1.50 (.61
0.335 10. 1
0.594 19.7
0.384 20.0
0.314 11.2
0.425 22.5
0.276 14.4
VI
3 Hour 24 Hour Amal
(4.1 17.4 2.30
95.9 19.1 2.51
77.8 28.1 0.952
94.0 11.4 1.95
124.0 34.7 4.S6
1.57 1.35 1.50
6.76 2.56 (.335
11.6 5.13 0.594
10.7 1.90 0.384
7.71 1.64 0.334
11.4 4.20 0.425
7.77 2.66 0.276
I
OJ
•Highest itant high In ulcrogr-i per »3 for 1 dour. 3 Hour end 24 hour avenging period! highest In •tcragrn per t? tar emual averaging period.
Model
PUnl
U
»
2C
31
4
i
6
7
Acid g»
H,S/CO,
PJtlo 2
20/80
12.5/87.5
50/50
20/80
50/50
60/20
50/50
80/20
1 Hour
713.0
-
997.0
_
1344.0
3 Hour
4(2.0
-
443.0
-
610.0
>
24 Hour Annul)
71.2 12.5
-
130.0 21.1
-
175.0 25.8
1 Hour
713.0
-
404.0
-
545.0
3 Hour
462.0
-
179.0
-
247.0
II
24 Hour
71.2
52.6
-
71.0
Regulatory Alternative*
III IV
Annul 1 Hour 3 Hour 24 Hour Annul 1 Hour 3 Hour 24 Hour Annual 1 Hour
12.5 -- - ______
102.0 69.8 27.1 4.37 102.0 69.6 27.1 4.37
8.64 404.0 179.0 52.4 8.64 -
11.5 8.69 3.97 0.572 11.5 8.69 3.97 0.572 11.5
10.5 545.0 247.0 71.0 10.5 30.0 15.1 5.05 0.639 30.0
.
V VI
3 Hour 24 Hour Annul 1 Hour 3 Hour 24 Hour Annull
-
- _
- _ _
6.69 3.97 0.572 11.5 6.69 3.97 0.572
15.1 6.06 0.639 30.0 U.I 5.06 0.619
•Highest second high I
In ulcngr-l per m3 for I hour. 1 hour, and 24 hour averaging periods highest In ilc-wau per •' for innual averaging period,
-------
from the above total uncontrolled S02 emissions. The number of uncontrolled
facilities that will be constructed between 1983 and 1987 was estimated
to be 47. By considering the numbers of facilities both recovering and
not recovering sulfur, the nationwide S02 emissions from each of the
regulatory alternatives may be projected for 1983-1987. Table 7-2 lists
the S02 emissions resulting from implementation of existing regulations
for new sources (Regulatory Alternative I, baseline). Tables 7-3
through 7-7 quantify the potential S02 emissions reductions beyond
baseline resulting from promulgation of a standard based upon each of
Regulatory Alternative II through VI.
Data on sulfur intake and acid gas H2S/C02 ratio from a sample of
23 operating facilities were reviewed. Percent distribution of the four
acid gas ratio (12.5/87.5, 20/80, 50/50, and 80/20) were developed for
each of the five sulfur intake range categories: <10, 10-49, 50-199,
200-199 and >1,000 Mg/d. The distribution reflects the percentage of
the 23 existing facilities' sample that produce a certain acid gas
H2S/C02 ratio.
For each daily sulfur intake size range, the product of the average
daily sulfur intake and the number of projected new sulfur recovery
facilities (Table 9-23) produces the total daily sulfur intake design
capacity. Seventy-five percent of the design capacity is chosen to
represent typical actual operating capacities in the onshore natural gas
industry. The projected daily S02 emissions are then calculated by the
product of the actual operating capacity, the fraction of the 23 existing
facilities' sample that produce a certain acid gas feed H2S/C02 ratio,
the sulfur penetration rate (1 minus sulfur recovery efficiency fraction),
and the S02 conversion factor (64 Mg S02/32 Mg S = 2.0). A typical
operating schedule of 350 days per year was assumed to calculate annual
S02 emissions by the end of 1987. When two possible sulfur recovery
processes were specified, the device most widely used in the industry
was chosen in order to calculate S02 emissions. Table 7-8 summarizes
the information contained in Table 7-3 through 7-7. Listed are the
5-year projected emission reductions and the percent reductions beyond
current control levels (Regulatory Alternative I or baseline emissions).
There would be a reduction from the baseline (Alternative I) of 15 percent
7-4
-------
Table 7-2.
ESTIMATED S02 "EMISSIONS (1983-1937) FROM PROJECTED MEW ONSHORE NATURAL GAS
PRODUCTION FACILITIES (REGULATORY ALTERNATIVE I)
I
en
Sul fur
intake ,
Mg/d
59
10
102
564
1,016
Number
of new
facilities3
47
21
6
3
1
Total
sulfur.
intake0,
Mg/d
176
158
459
1,269
762
Acid gas feed
H2S/C02 ratio
by volume
12.5/87.5
12.5/87.5
20/80
50/50
80/20
12.5/87.5
20/80
50/50
80/20
50/50
80/20
50/50
80/20
Percent
distribution
of H2S/C02
ratio"
100.0
22.2
44.4
11.2
22.2
0.0
10.0
30.0
60.0
33. Ou
67. Oh
0.0
100.0
Alternative I
sulfur
recovery
efficiency ,
percent
0.00
91.30
91.80
93.80
95.10
93.39
94.50
96.10
96.64
96.10
96.64
96.10
96.64
Projected
S02
emissions,
Mg/d
352
6.1
12
2.2
3.4
_
5.1
11
19
33
57
-
51
Total
Projected
S02
emissions ,
103 Mg/y
123
8.1
12
32
18
= 193
aBased on 5-year projection (1983-1987) of new sulfur recovery facilities added. Refer to Table 9-23.
Refers to combined total of average design values at 75% of design capacity. For example, 5 x 47 x 0.75 = 176.
GBased on sample of 23 existing facilities, these acid gas feed ratios were found.
Based on sample of 23 existing facilities. Refers to percent of sample with applicable HpS/CO,, ratio by volume.
eBased on sulfur recovery efficiencies from the Ralph M. Parsons' sulfur recovery study report. Also refer to Table 6-2.
Based on 350 days/year operating schedule and represents estimated fifth year annual S02 emissions for each size
category in 1987.
9This size refers to onshore natural gas production facilities that do not recover sulfur.
There were no facilities in the sample of 23 existing facilities in this size category. The selected percent
distribution between the ratios of 50/50 and 80/20 is that of the same ratios in the size category of 50-199.
-------
Table 7-3. ESTIMATED S02 EMISSIONS (1983-1987) FROM PROJECTED NR\I ONSHORE
NATURAL GAS PRODUCTION FACILITIES (REGULATORY ALTERNATIVE II)
CTl
Sulfur
intake ,
Mg/d
5h
10
102
564
1,016
Number
of new
facilities8
47
21
6
3
1
Total
sulfur
intake ,
Mg/d
176
158
459
1,269
762
Acid gas feed
H2S/C02 ratio
by volume
12.5/87.5
12.5/87.5
20/80
50/50
80/20
12.5/87.5
20/80
50/50
80/20
50/50
80/20
50/50
80/20
Percent
distribution
of H2S/C02
ratio
100.0
22.2
44.4
11.2
22.2
0.0
10.0
30.0
60.0
33.0]
67. 01
0.0
100.0
Alternative II
sulfur
recovery
efficiency ,
percent
0.00
91.30
91.80
93.80
95.10
93.39
94.50
96.10
96.64
98.42
98.50
98.42
98.50
Projected S02
Mg/d
352
6.1
12
2.2
3.4
5.1
11
19
13
26
23u
Totals =
Emissions
103 Mg/y
123
8.0
12
14
8.0
165
S02
emission
reduction9,
103 Mg/y
0.0
0.0
0.0
18
10
28
Based on 5-year projection (1983-1987) of new sulfur recovery facilities added. Refer to Table 9-23.
Refers to combined total of average design values at 75% of design capacity. For example, 5 x 47 x 0.75 = 176.
GBased on sample of 23 existing facilities, these acid gas feed ratios were found.
Based on sample of 23 existing facilities. Refers to percent of sample with applicable H2S/C02 ratio by volume.
p
Based on sulfur recovery efficiencies from the Ralph M. Parsons' sulfur recovery study report. Also refer to Table 6-2.
Based on 350 days/year operating schedule and represents estimated fifth-year annual S02 emissions for each size category in 1987.
Represents S02 emission reduction beyond Regulatory Alternative I (baseline control levels with no NSPS) in 1987.
This size refers to onshore natural gas production facilities that do not recover sulfur.
were no facilities in the sample of 23 existing facilities in this size category. The selected percent distribution between
the ratios of 50/50 and 80/20 is that of the same ratios in the size category of 50-199.
-------
Table 7-4. ESTIMATED S02 EMISSIONS (1983-1987) FROM PROJECTED NEW ONSHORE
NATURAL GAS PRODUCTION FACILITIES (REGULATORY ALTERNATIVE III)
Sulfur
intake ,
Mg/d
5h
10
102
564
1,016
Total
Number sul fur
of new Intake ,
facilities Mg/d
47 176
21 158
6 459
3 1,269
1 762
Acid gas feed
H2S/C02 ratio
by volume
12.5/87.5
12.5/87.5
20/80
50/50
80/20
12.5/87.5
20/80
50/50
80/20
50/50
80/20
50/50
80/20
Percent
distribution
of H2S/C02
ratio0
100.0
22.2
44.4
11.2
22.2
0.0
10.0
30.0
60.0
33. 01.
67. 01
0.0
100.0
Alternative II
sulfur
recovery
efficiency ,
percent
91.30
93.39
94.50
96.10
96.64
97.50
97.80
98.42
98.50
98.42
99.98
98.42
99.98
Projected S02
Mg/d
31
4.6
7.7
1.4
2.4
__
2.0
4.4
8.3
13
0.3
—
0.3
Totals =
Emissions
103 Mg/y
11
5.6
5.1
4.8
0.1
26
S02
emission
reduction ,
103 Mg/y
113
2.5
7.0
27
18
167
aBased on 5-year projection (1983-1987) of new sulfur recovery facilities added. Refer to Table 9-23.
Refers to combined total of average design values at 75% of design capacity. For example, 5 x 47 x 0.76 = 176.
cBased on sample of 23 existing facilities, these acid gas feed ratios were found.
Based on sample of 23 existing facilities. Refers to percent of sample with applicable H2S/C02 ratio by volume.
eBased on sulfur recovery efficiencies from the Ralph M. Parsons' sulfur recovery study report. Also refer to Table 6-2.
Based on 350 days/year operating schedule and represents estimated fifth-year annual S02 emissions for each size category in 1987.
Represents S02 emission reduction beyond Regulatory Alternative I (baseline control levels with no NSPS) in 1987.
This size refers to onshore natural gas production facilities that do not recover sulfur.
'There were no facilities in the sample of 23 existing facilities in this size category. The selected percent distribution between
the ratios of 50/50 and 80/20 is that of the same ratios in the size category of 50-199.
-------
Table 7-5. ESTIMATED S02 EMISSIONS (1983-1987) FROM PROJECTED NEW ONSHORE
NATURAL GAS PRODUCTION FACILITIES (REGULATORY ALTERNATIVE IV)
co
Sulfur
Intake ,
Mg/d
5h
10
102
564
1,016
Number
of new
facilities3
47
21
6
3
1
Total
sulfur
intake ,
Mg/d
176
158
459
1,269
762
Acid gas 'feed
H2S/C02 ratio
by volume
12.5/87.5
12.5/87.5
20/80
50/50
80/20
12.5/87.5
20/80
50/50
80/20
50/50
80/20
50/50
80/20
Percent
distribution
of H2S/C02
ratio
100.0
22.2
44.4
11.2
22.2
0.0
10.0
30.0
60.0
33.01.
67. 0J
0.0
100.0
Alternative II
sulfur
recovery
efficiency ,
percent
93.39
93.39
94.50
96.10
96.64
97.50
97.80
98.42
98.50
99.95
99.98
99.95
99.98
Projected SO
Mg/d
23
4.6
7.7
1.4
2.4
2.0
4.4
8.3
0.4
0.3
0.3
Totals
2 Emissions
103 Mg/y
8.1
5.6
5.1
0.3
0.1
= 19
S02
emission
reduction ,
103 Mg/y
115
2.5
7.0
32
18
174
Based on 5-year projection (1983-1987) of new sulfur recovery facilities added. Refer to Table 9-23.
Refers to combined total of average design values at 75% of design capacity. For example, 5 x 47 x 0.75 = 176.
cBased on sample of 23 existing facilities, these acid gas feed ratios were found.
Based on sample of 23 existing facilities. Refers to percent of sample with applicable H2S/C02 ratio by volume.
p
Based on sulfur recovery efficiencies from the Ralph M. Parsons' sulfur recovery study report. Also refer to Table 6-2.
Based on 350 days/year operating schedule and represents estimated fifth-year annual S02 emissions for each size category in 1987.
^Represents S02 emission reduction beyond Regulatory Alternative I (baseline control levels with no NSPS) in 1987.
This size refers to onshore natural gas production facilities that do not recover sulfur.
There were no facilities in the sample of 23 existing facilities in this size category. The selected percent distribution between
the ratios of 50/50 and 80/20 is that of the same ratios in the size category of 50-199.
-------
Table 7-6. ESTIMATED S02 EMISSIONS (1983-1987) FROM PROJECTED NEW ONSHORE
NATURAL GAS PRODUCTION FACILITIES (REGULATORY ALTERNATIVE V)
I
VO
Sulfur
intake3,
Mg/d
5h
10
102
564
1,016
Total
Number sulfur
of new intake ,
facilities3 Mg/d
47 176
21 158
6 459
3 1,269 .
(1269)1
1 762
Acid gas feed
H2S/C02 ratio
by volume
12.5/87.5
12.5/87.5
20/80
50/50
80/20
12.5/87.5
20/80
50/50
80/20
50/50
80/20
50/50
80/20
Percent
distribution
of H2S/C02
ratio
100.0
22.2
44.4
11.2
22.2
0.0
10.0
30.0
60.0
33. OJ
67. 01
0.0
100.0
Alternative II
sulfur
recovery
efficiency ,
percent
93.39
97.50
97.80
98.42
98.50
99.87
99.90
99.95
99.98
99.95
99.98
99.95
99.98
Projected S02
Mg/d
23
1.8
3.1
0.6
1.1
0.1
0.1
0.1
0.4
0.3
0.3
Totals =
Emissions
103 Mg/y
8.1
2.3
0.1
0.3
0.1
11
S02
emission
reduction9,
103 Mg/y
115
5.9
12
31
18
182
Based on 5-year projection (1983-1987) of new sulfur recovery facilities added. Refer to Table 9-23.
Refers to combined total of average design values at 75% of design capacity. For example, 5 x 47 x 0.76 = 176.
C8ased on sample of 23 existing facilities, these acid gas feed ratios were found.
Based on sample of 23 existing facilities. Refers to percent of sample with applicable H2S/C02 ratio by volume.
eBased on sulfur recovery efficiencies from the Ralph M. Parsons' sulfur recovery study report. Also refer to Table 6-2.
Based on 350 days/year operating schedule and represents estimated fifth-year annual S02 emissions for each size category in 1987.
Represents S02 emission reduction beyond Regulatory Alternative I (baseline control levels with no NSPS) in 1987.
This size refers to onshore natural gas production facilities that do not recover sulfur.
were no facilities in the sample of 23 existing facilities in this size category. The selected percent distribution between
the ratios of 50/50 and 80/20 is that of the same ratios in the size category of 50-199.
-------
Table 7-7. ESTIMATED S02 EMISSIONS (1983-1987) FROM PROJECTED NEH ONSHORE
NATURAL GAS PRODUCTION FACILITIES (REGULATORY ALTERNATIVE VI)
I
I—"
O
Sulfur
intake ,
Mg/d
5h
10
102
564
1,016
Number
of new
facilities3
47
21
6
3
1
Total
sulfur
intake ,
Mg/d
176
158
459
1,269
762
Acid gas feed
H2S/C02 ratio
by volume
12.5/87.5
12.5/87.5
20/80
50/50
80/20
12.5/87.5
20/80
50/50
80/20
50/50
80/20
50/50
80/20
Percent
distribution
of H2S/C02
ratio
100.0
22.2
44.4
11.2
22.2
0.0
10.0
30.0
60.0
33. Ol
67. O1
0.0
100.0
Alternative II
sulfur
recovery
efficiency ,
percent
97.50
97.50
97.80
98.42
98.50
99.87
99.90
99.95
99.98
99.95
99.98
99.95
99.98
Projected S02
Mg/d
8.8
1.8
3.1
0.6
1.1
0.1
0.1
0.4
0.3
0.3
Totals
Emissions
103 Mg/y
3.1
2.3
0.1
0.3
0.1
= 5.8
S02
emission
reduction9,
103 Mg/y
120
5.9
12
31
18
187
Based on 5-year projection (1983-1987) of new sulfur recovery facilities added. Refer to Table 9-23.
Refers to combined total of average design values at 75% of design capacity. For example, 5 x 47 x 0.76 = 176.
Based on sample of 23 existing facilities, these acid gas feed ratios were found.
Based on sample of 23 existing facilities. Refers to percent of sample with applicable H2S/C02 ratio by volume.
eBased on sulfur recovery efficiencies from the Ralph M. Parsons' sulfur recovery study report. Also refer to Table 6-2.
Based on 350 days/year operating schedule and represents estimated fifth-year annual S02 emissions for each size category in 1987.
Represents S02 emission reduction beyond Regulatory Alternative I (baseline control levels with no NSPS) in 1987.
This size refers to onshore natural gas production facilities that do not recover sulfur.
There were no facilities in the sample of 23 existing facilities in this size category. The selected percent distribution between
the ratios of 50/50 and 80/20 is that of the same ratios in the size category of 50-199.
-------
Table 7-8. REGULATORY ALTERNATIVE EFFECTIVENESS FOR REDUCING S02 EMISSIONS FROM
PROJECTED ADDED NEW ONSHORE NATURAL GAS PRODUCTION FACILITIES3
Regulatory Regulatory Regulatory Regulatory Regulatory
Alternative Alternative Alternative Alternative Alternative
II III IV V VI
S02
Reductions 28 167 174 182 187
(103 Mg/y)
S02
Reductions3 15 87 90 94 97
(percent)
Represents total reductions beyond Regulatory Alternative I (baseline level with no NSPS) for the
fifth year (1987).
-------
with Alternative II, 86 percent with Alternative III, 90 percent with
Alternative IV, 94 percent with Alternative V, and 97 percent for
Alternative VI.
7.1.3 Secondary Impacts on Air Quality
There are no secondary impacts associated with the control of
carbon dioxide (C02), nitrogen oxides (NO ), and hydrocarbons (HC).
Normal operating procedures of the sweetening process and incineration
process effectively reduce these pollutants to negligible levels. Since
more than 90 percent of the hydrogen sulfide (H2S) is converted to
elemental sulfur during the Glaus process and the residual H2S is then
incinerated to convert it to S02, H2S emissions would be insignificant.
Side reactions that occur during the Claus process produce compounds of
carbonyl sulfide (COS) and carbon disulfide (CS2), but both of these are
converted to S02 by thermal oxidation before being emitted into the
atmosphere.
7.2 WATER POLLUTION IMPACT
There would be essentially no water pollution impact associated
with any of the six regulatory alternatives. The by-products thiosulfate
(Na2S203) and sulfite (Na2S03) do tend to build up in solutions during
the Stretford process and this build-up reduces the ability of the
system to remove hydrogen sulfide (H2S). Formation of thiosulfate can
be controlled , however, to below 1% of the H2S by proper plant
2 3
operation. ' The Stretford process is used in the Beavon Sulfur Recovery
Process (BSRP) tail gas cleanup system (described in Chapter 3). The
BSRP tail gas cleanup system is specified as one of two possible tail
gas cleanup systems in Regulatory Alternatives III through VI (Table 6-2).
The by-product thiosulfate and sulfite is transferred by a purge stream
for further salt recovery treatment. Salt recovery methods that are
currently available include evaporation or spray drying, biological
degradation, and oxidative combustion. After salt recovery, the solid
waste is buried in sanitary landfills. Another salt recovery method
currently available is reductive incineration. Solids that were recovered
from spray evaporation or oxidative combustion can be reduced to a
product that can be recycled through the Stretford process resulting in
7-12
-------
economic savings and zero effluent discharge. Therefore, liquid waste
disposal problems are not considered significant.
The other sulfur recovery processes and tail gas cleanup systems
(presented in Chapter 3) specified as regulatory alternatives produce no
significant adverse water quality impacts, as the liquid sulfur is
recovered for sale.
7.3 SOLID WASTE DISPOSAL IMPACT
There would be no significant adverse impacts on the level of solid
waste produced as a result of promulgation of any one of the six Regulatory
Alternatives specified in Table 6-2. Instead, there is an economic
incentive to recover the sulfur (which is recovered in liquid, not solid
form) for sale to the sulfuric acid manufacturing industry. Once again,
as explained in Section 7.2, the Stretford process produces by-products
2 3
(thiosulfate and sulfite). ' These chemicals can be disposed of or
recovered, creating an insignificant solid waste impact. The other
possible solid wastes that are typically buried in a sanitary landfill
include: 1) spent catalysts from the reactor beds (catalyst replacement
depends on the replacement schedule, normally every 3 to 5 years);
2) recovered sulfur resulting from spillage or leakage when it is
transferred either to the liquid sulfur storage tank or transferred for
disposal or sale; and 3) spent carbon absorbers from the hydrocarbon
(HC) recovery unit (carbon absorbers typically last several years). The
spent catalyst is often used as road gravel (paving material) and has no
adverse environmental effect.
7.4 ENERGY IMPACTS
The utility requirements associated with each regulatory alternative
for each model plant are presented in Tables 7-9 through 7-14. Data on
energy utilization were developed from the Ralph M. Parsons Company's
study of onshore sour natural gas production facilities sulfur recovery.
The data on the number of new sulfur recovery facilities and the repre-
sentative sizes (sulfur intake in megagrams per day) of these projected
facilities are presented in Table 9-23. From these data, nationwide
fifth-year (1987) energy requirements were developed assuming 350 days
per year, 24 hours per day facility operation (Table 7-15). There would
7-13
-------
Table 7-9. ENERGY IMPACT ANALYSIS (REGULATORY ALTERNATIVE I)'
Sulfur
intake,
Mg/d
5
10
102
564
564
1,016
1,016
Number
new
facil ities
47
21
6
1
2
0
1
Acid gas feed
H2S/C02 ratio
by volume
b
b
b
50/50
80/20
50/50
80/20
Electric
power,
kW
-
59
308
915
817
1,876
1,676
Fuel
gas,
109 J/h
-
3.9
40.0
72.9
48.7
131.4
87.7
600 PSIG 50 PSIG Treated boiler Cooling
steam, steam, feed water, water,
kg/h kg/h kg/h m3/h
_
590.6 - 1,404
29,588
91,886
83,579
165,561
150,593
b
Utility requirements for each model plant facility.
Acid gas H2S/C02 volume percent ratio of 12.5/87.5 considered as worst case.
-------
Table 7-10. ENERGY IMPACT ANALYSIS (REGULATORY ALTERNATIVE II)'
en
Sulfur
intake
Mg/d
5
10
102
564
564
1,016
1,016
Number
new
facilities
47
21
6
1
2
0
1
Acid gas feed
H2S/C02 ratio
by volume
b
b
b
50/50
80/20
50/50
80/20
Electric
power,
kW
-
59
308
1,300
1,162
2,863
2,558
Fuel
§as,
^ J/h
-
3.9
40
70
47
126
84
600 PSIG 50 PSIG Treated boiler Cooling
steam, steam, feed water, water,
kg/h kg/h kg/h mVh
_
590.6 - 1,404
29,588
93,664
85,196
168,764
153,506
Utility requirements for each model plant facility.
3Acid gas H2S/C02 volume percent ratio of 12.5/87.5 considered as worst case.
-------
Table 7-11. ENERGY IMPACT ANALYSIS (REGULATORY ALTERNATIVE III)3
Sulfur
intake,
Mg/d
5
10
102
564
564
1,016
1,016
Number
new
facilities
47
21
6
1
2
0
1
Acid gas feed
H2S/C02 ratio
by volume
b
b
b
50/50
80/20
50/50
80/20
Electric
power,
kW
59
61
490
1,300
2,165
2,863
3,900
Fuel
gas,
109 J/h
2.0
4.0
34.8
70
65
126
117
600 PSIG 50 PSIG
steam, steam,
kg/h kg/h
295.3
732.6
-
-
9,435
-
17,000
Treated boiler
feed water,
kg/h
702
1,500
30,000
93,664
56,610
168,764
102,000
Cooling
water,
m3/h
-
-
-
-
710
-
1,280
al)tility requirements for each model plant facility.
Acid gas H2S/C02 volume percent ratio of 12.5/87.5 considered as worst case.
-------
Table 7-12. ENERGY IMPACT ANALYSIS (REGULATORY ALTERNATIVE IV)a
I
I-J
-^J
Sulfur
intake,
Mg/d
5
10
102
§64
564
1,016
1,016
Number
new
facilities
47
21
6
1
2
0
1
Acid gas feed
H2S/C02 ratio
by volume
b
b
b
50/50
80/20
50/50
80/20
Electric
power,
kW
30.5
61
490
2,170
2,165
4,513
3,900
Fuel
gas,
109 J/h
2.0
4.0
34.8
120
65
216
117
600 PSIG
steam,
kg/h
366.3
732.6
-
-
-
-
-
50 PSIG
steam,
kg/h
-
-
-
33,710
9,435
60,738
17,000
Treated boiler
feed water,
kg/h
750
1,500
30,000
71,470
56,610
128,775
102,000
Cooling
water,
m3/h
-
-
-
2,065
710
3,720
1,280
aUtility requirements for each model plant facility.
Acid gas H2S/C02 volume percent ratio of 12.5/87.5 considered as worst case.
-------
Table 7-13. ENERGY IMPACT ANALYSIS (REGULATORY ALTERNATIVE V)a
--J
1
I—"
00
Sulfur
intake,
Mg/d
5
10
102
564
564
1,016
1,016
Number
new
facilities
47
21
6
1
2
0
1
Acid gas feed
H2S/C02 ratio
by volume
b
b
c
50/50
80/20
50/50
80/20
Electric
power,
kW
30.5
49
1,020
2,170
2,165
4,513
3,900
Fuel
gas,
109 J/h
2.0
3.5
50.6
120
65
216
117
600 PSIG 50 PSIG
steam, steam,
kg/h kg/h
366.3
-
35,164
33,710
9,435
60,738
17,000
Treated boiler
feed water,
kg/h
750
3,000
24,771
71,470
56,610
128,775
102,000
Cooling
water,
m3/h
-
-
1,368
2,065
710
3,720
1,280
aUtility requirements for each model plant facility.
Acid gas H2S/C02 volume percent ratio of 12.5/87.5 considered as worst case.
H2S/C02 volume percent ratio of 20/80 considered.
-------
Table 7-14. ENERGY IMPACT ANALYSIS (REGULATORY ALTERNATIVE VI)a
Sulfur
intake,
Mg/d
5
10
102
564
^ 564
vo
1,016
1,016
Number
new
facilities
47
21
6
1
2
0
1
Acid gas feed
H2S/C02 ratio
by volume
b
b
c
50/50
80/20
50/50
80/20
Electric
power,
kW
24.5
49
1,020
2,170
2,165
4,513
3,900
Fuel
§as,
AU J/h
1.8
3.5
50.6
120
65
216
117
600 PSIG 50 PSIG
steam, steam,
kg/h kg/h
-
-
35,164
33,710
9,435
60,738
17,000
Treated boiler
feed water,
kg/h
1,500
3,000
24,771
71,470
56,610
128,775
102,000
Cooling
water,
m3/h
-
-
1,368
2,065
710
3,720
1,280
aUtility requirements for each model plant facility.
by
Acid gas H2S/C02 volume percent ratio of 12.5/87.5 considered as worst case.
CH2S/C02 volume percent ratio of 20/80 considered.
-------
Table 7-15. ONSHORE NATURAL GAS PRODUCTION SULFUR RECOVERY FACILITIES PROJECTED.NATIONAL
FIFTH-YEAR (1987) ENERGY REQUIREMENTS9 FOR THE REGULATORY ALTERNATIVES0
Electric power
(106 kWh/y)
Fuel gas
(1014 J/y)
600 PSIG steam
(107 kg/y)
50 PSIG steam
(108 kg/y)
Treated boiler
feed water
(108 kg/y)
Cooling water
(107 m3/y)
Regulatory Regulatory
Alternative Alternative
I II
61.4 77.8
48.8 47.9
10.4 10.4
- —
51.8 52.5
-
Regulatory
Alternative
III
138.8
59.1
24.6
3.0
46.5
2.3
Regulatory
Alternative
IV
134.8
63.3
27.4
5.9
44.8
4.0
Regulatory
Alternative
V
159.4
70.4
14.5
23.6
44.8
10.9
Regulatory
Alternative
VI
157.0
69.6
-
23.6
47.7
10.9
Based on projected number of new sulfur recovery facilities constructed from 1983-1987. Refer to
Table 9-23.
"'Extracted from Table 6-2.
-------
be an increase in energy usage over Regulatory Alternative I of 1.2 percent
with Alternative II; 25.7 percent with Alternative III; 33.7 percent
with Alternative IV; 49.4 percent with Alternative V; and IV; and
47.7 percent with Alternative VI. These increased energy requirements
result from greater sulfur recovery efficiency requirements for small
and medium size sulfur recovery facilities.
7.5 OTHER ENVIRONMENTAL CONCERNS
7.5.1 Irreversible and Irretrievable Commitment of Resources
The six regulatory alternatives defined in Chapter 6 would not
preclude the development of future control options nor would they curtail
any beneficial use of environmental resources. No long-term environmental
losses would result from the regulatory alternatives.
7.5.2 Environmental Impact of Delayed Standards
The only environmental impact on air pollution associated with a
delay in proposing and promulgating the standard would be an increase in
S02 emissions attributable to the construction of new sulfur recovery
units without tail gas treatment systems. Additional S02 emissions from
the currently uncontrolled small facilities with sulfur intakes less
than 10 megagrams per day would result provided that a standard based on
Regulatory Alternatives III, IV, V, or VI is delayed.
Delaying the standard would result in possible water and solid
waste impact reductions, but the related reductions would be minimal
compared with the air quality benefits attributable to promulgation of
the standard.
Energy utilization by the industry would be less if the standard
were delayed; however, the industry can reduce this additional expense
with credits derived from the sale of the recovered sulfur.
7-21
-------
7.6 REFERENCES FOR CHAPTER 7
1. "State Air Laws." Environmental Reporter. The Bureau of National
Affairs, Inc. Washington, D.C. 1979-1981.
2. A.J. Moyes and J.S. Wilkinson. "High-Efficiency Removal of H2S
from Fuel Gases and Process Gas Streams." Process Engineering,
September 1973, pp. 101-105.
3. A.L. Kohl and F.C. Riesenfeld. Gas Purification, 2nd ed. Gulf
Publishing Company. Houston, Texas. 1974., pp. 432-441.
4. Srini Vasan. "Holmes-Stretford Process Offers Economic H2S Removal."
Oil and Gas Journal. January 2, 1978.
5. Ralph M. Parsons Company Engineers/Constructors. Sulfur Recovery
Study - Onshore Sour Gas Production Facilities. The Study was
conducted for TRW. July 1981. Section 6, pp. 1-9. The study is
presented in Appendix E.
7-22
-------
8. COST ANALYSIS
8.1 COST ANALYSIS OF REGULATORY ALTERNATIVES
This section summarizes the cost analysis data. It presents estimates
of the fixed capital costs, annualized costs, S02 emission reductions
and cost effectiveness for each of the six regulatory alternatives
applied to all seven model plants. The estimates are based upon cost
data developed in a study conducted by a sulfur recovery equipment
vendor. The cost analysis and data presented in this chapter are
applicable to sulfur recovery technologies used for onshore sour natural
gas production facilities. Cost estimates for sulfur recovery opera-
tions conducted offshore may vary widely from the data presented in this
chapter. The regulatory alternatives, baseline controls, and model
plants are presented in Table 6-2.
8.1.1 New Facilities
In this section, the installed capital and annualized costs (total
annualized costs excluding credits and net annualized costs including
credits) associated with each regulatory alternative are presented for
all seven model plants. S02 emissions reductions and cost effectiveness
for each regulatory alternative also are summarized for each new model
plant facility. All costs are for new facilities.
8.1.1.1 Capital Costs. The fixed capital costs that represent the
initial investment for control equipment and installation for 39 different
cases, which represent the size and acid gas ratio ranges in the industry,
are presented in Table 8-1. The cases consider different model plant
sizes and combinations of sulfur recovery/tail gas processes and acid
gas H2S/C02 ratios. The cost estimates are based upon the following
assumptions:
8-1
-------
Table 8-1. FIXED-CAPITAL COSTS FOR 39 CASES OF SULFUR INTAKE/ACID GAS
H2S/C02 RATIO/SULFUR RECOVERY TECHNOLOGY COMBINATIONS1
Case
No.
1
2
3
4
5
6
7
8
00
ro 9
10
11
12
13
14
15
16
17
18
19
20
Size
(sulfur intake)
Mg/d LT/D
5.1
5.1
5.1
5.1
5.1
10.2
10.2
10.2
10.2
10.2
10.2
10.2
10.2
10.2
10.2
101.6
101.6
101.6
101.6
101.6
5
5
5
5
5
10
10
10
10
10
10
10
10
10
10
100
100
100
100
100
Acid gas feed
H2S/C02 ratio
by volume
50/50
20/80
50/50
20/80
12.5/87.5
50/50
20/80
12.5/87.5
20/80
12.5/87.5
50/50
20/80
12.5/87.5
20/80
12.5/87.5
50/50
20/80
12.5/87.5
20/80
12.5/87.5
Sulfur recovery
technology
No recovery
No recovery
Recycle Selectox-2
stage
Recycle Selectox-2
stage
Recycle Selectox-2
stage
Claus-2 stage
Claus-2 stage
Claus-2 stage
Recycle Selectox-2
stage
Recycle Selectox-2
stage
Claus-3 stage
Claus-3 stage
Claus-3 stage
Recycle Selectox-3
stage
Recycle Selectox-3
stage
Claus-3 stage
Claus-3 stage
Claus-3 stage
Recycle Selectox-3
stage
Recycle Selectox-3
stage
Cost
$
1,280,000
1,280,000
2,450,000
2,440,000
2,460,000
2,950,000
3,400,000
3,530,000
2,700,000
2,720,000
3,320,000
3,740,000
3,800,000
3,140,000
3,190,000
6,490,000
9,100,000
11,270,000
8,760,000
10,220,000
Case
No.
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Size
(sulfur intake)
Mg/d LT/D
101.6
101.6
101.6
101.6
101.6
101.6
101.6
101.6
1016.0
1016.0
563.9
1016.0
563.9
1016.0
563.9
1016.0
563.9
1016.0
563.9
100
100
100
100
100
100
100
100
1000
1000
555
1000
555
1000
555
1000
555
1000
555
Acid gas feed
H2S/C02 ratio
by volume
50/50
20/80
50/50
20/80
50/50
20/80
50/50
20/80
80/20
50/50
20/80
50/50
20/80
50/50
20/80
50/50
20/80
50/50
20/80
Sulfur recovery
technology
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
BSRP
Claus-3 stage with
BSRP
Claus-3 stage with
Sul f reen
Claus-3 stage with
Sul f reen
Claus-2 stage with
BSR/Selectox
Claus-2 stage with
BSR/Selectox
Claus-3 stage
Claus-3 stage
Claus-3 stage
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
BSRP
Claus-3 stage with
BSRP
Claus-3 stage with
Sul f reen
Claus-3 stage with
Sul f reen
Claus-2 stage with
BSR/Selectox
Claus-2 stage with
BSR/Selectox
Cost
$
12,030,000
20,800,000
9,220,000
11,700,000
8,310,000
10,970,000
7,630,000
10,720,000
22,490,000
26,350,000
26,480,000
48,500,000
68,360,000
30,980,000
30,360,000
29,910,000
30,130,000
30,260,000
30,760,000
-------
(1) Barometric pressure is 14.7 psia;
(2) Acid gases are available at 38°C (100°F) and 24.7 psia,
saturated with water, and containing 0.5 mole percent methane
(wet basis);
(3) Steam is produced at 250, 50, and 15 psig from the Claus
stages;
(4) Thermal oxidizers are operated at 649°C (1,200°F) with
25 percent excess air (to reduce H2S content below 10 ppmv);
(5) For cases with waste heat boilers associated with thermal
oxidizers, steam is produced at 250 psig for the 102 Mg/d
(100 LT/D) cases and at both 600 and 250 psig for each of the
564 or 1,016 Mg/d (555 or 1,000 LT/D) cases;
(6) Treated, deaerated boiler feedwater is available at 320 psig
and 110°C (230°F);
(7) Cooling water is available at 29°C (85°F) and is returned at
43°C
(8) Incinerator stack heights vary from 30.5 to 183 m (100 to
600 ft) depending on the quantity of sulfur dioxide emissions;
stack height was set to achieve approximately uniform levels
of ground- level S02 concentrations;
(9) Investment costs are based on January 1981 Gulf Coast prices;
(10) In the BSR (hydrogenation) sections, steam is produced in the
102 Mg/d (100 LT/D) units at 50 psig and in the 564 or 1,016 Mg/d
(555 or 1,000 LT/D) units at 450 and 50 psig;
(11) For the cases with 1,016 Mg/d (1,000 LT/D) sulfur input feeding
acid gas with a 50/50 H2S/C02 ratio, the plants are approximately
the maximum economical size and weaker gases would require
building two trains. In order to keep all cases in only one
train, the maximum sulfur input with 20/80 H2S/C02 acid gas
feed is 564 Mg/d (555 LT/D). These plants are about the same
physical size as the 1,016 Mg/d (1,000 LT/D) plants with
50/50 H2S/C02 acid gas feed; and
8-3
-------
(12) Initial charge of catalysts is included in the fixed capital
costs.
The fixed capital costs of the regulatory alternatives for each
model plant are taken from the data in Table 8-1 . Those model
plant/regulatory alternative combinations, for which case-specific costs
were not estimated, were calculated through interpolation of the cost
numbers based upon the model plant size for cases with identical sulfur
recovery technology and acid gas H2S/C02 ratio. The fixed-capital costs
for each new model plant/regulatory alternative combination are presented
in Table 8-2. In addition, the fifth year (1987) aggregate fixed-capital
costs for all plants projected for construction in the period 1983
through 1987 are listed at the base of each regulatory alternative
column.
8.1.1.2 Annualized Costs. The net annualized cost is the summation
of annualized capital costs, other operating costs, general expense
costs and credits from steam and elemental sulfur generated by the
control processes. Credit components are deducted from the cost components.
An operating schedule of 24 hours per day and 350 days per year was used
to calculate operating cost components. Table 8-3 lists the 19 cost
components, 7 credit components and the cost (and credit) factors used
to estimate each component. The cost (and credit) factors presented in
Table 8-3 were used to calculate the net annualized costs for the 39 cases
for which case-specific fixed-capital costs were estimated. The net
annualized costs for these 39 cases, which represent the size and acid
gas ratio ranges in the industry, are presented in Table 8-4. These
data are the basis for estimating net annualized costs for specific new
model plant/regulatory alternative combinations in Table 8-5. Those
model plant/regulatory alternative combinations for which case-specific
costs were not estimated were calculated through interpolation of the
cost numbers .based upon the model plant size for cases with identical
sulfur recovery technology and acid gas H2S/C02 ratio. The net annualized
costs for each model plant/regulatory alternative combinations are
presented in Table 8-5. In addition, the fifth year (1987) aggregate
net annualized costs for all plants projected for construction in the
period 1983 through 1987 are listed at the base of each regulatory
alternative column.
8-4
-------
Table 8-2. FIXED-CAPITAL COSTS FOR EACH NEW MODEL PLANT/REGULATORY ALTERNATIVE COMBINATIONS
oo
Regulatory alternative fixed-capital costs,
103 $
Model
plant
1
2
3
4
5
6
7
Fifth year
total for
all plants
Projected number
(five year total)
47
21
6
1
2
0
1
78
I
1,280
2,950
6,490
17,700
15,200
26,350
22,490
231,640
II
1,280
2,950
6,490
20,500
16,750
29,910
24,100
239,150
III
2,330
3,320
8,310
20,500
30,200
29,910
40,400
350,640
IV
3,200
3,320
8,310
33,250
30,200
48,500
40,400
404,030
V
3,200
8,200
20,800
33,250
30,200
48,500
40,400
581,450
VI
7,500
8,200
20,800
33,250
30,200
48,500
40,400
783,550
-------
Table 8-3. COMPONENTS OF NET ANNUALIZED COSTS AND
FACTORS TO CALCULATE THESE COMPONENTS
Net Annualized Costs = Operating Costs + General Expenses - Steam and
Sulfur Credits.
A. Operating Costs:
1. Direct costs:
a. Utilities consumed: Based upon 24 h/d, 350 d/y schedule.
1. 600 PSIG steam, $15.98/Mg
2. 50 PSIG steam, $12.68/Mg
3. Treated boiler feed water, $3.31/Mg
4. Cooling water, $13.21/103m3 circulated
5. Electric power, $0.05/kWh
6. Fuel gas, $4.74/109J
7. Catalyst and chemical, ranging $2.27/day to $3,579/day
depending upon size and technology.
b. Utilities generated (credits): Based upon 24 h/d, 350 d/y schedule.
8. 600 PSIG steam, $15.98/Mg
9. 450 PSIG steam, $15.43/Mg
10. 250 PSIG steam, $14.88/Mg
11. 50 PSIG steam, $12.68/Mg
12. 15 PSIG steam, $9.92/Mg
13. Steam condensate, $2.76/Mg
14. Sulfur recovered, $98.42/Mg
c. Operating labor: Based on 8 hr/operator (or supervisor),
3 shifts/d, 365 d/y schedule.
15. Operators per shift: ($14.50/h rate)
Cases (Refer to Table 8-4) Number per shift
1 and 2 negligible
3,4,5,9,10,14,15,19,20 0.75
6,7,8,11,12,13,16,17,18,29,30,31 1.25
All others 2.25
16. Supervisors per shift: ($18.80/h rate)
All cases except 1 and 2 0.25
d. Maintenance and repair:
17- Labor, 1.5% of fixed-capital costs
18. Materials, 2% of fixed-capital costs
(continued)
8-6
-------
Table 8-3. Concluded
e. Operating supplies:
19. Operating supplies, 10% of operating labor
f. Laboratory charges
20. Laboratory charges, 10% of operating labor
2. Fixed charges:
21. Capital charges - fixed-capital costs x ———-^*-
(1 + i)n-l
= 0.11746 x fixed-capital costs
where, i = 10% (interest rate)
n = 20 years (equipment life)
22. Local taxes, 1% of fixed-capital costs
23. Insurance, 0.6% of fixed-capital costs
3. Plant overhead costs:
24. Plant overhead, 25% of operating labor plus maintenance
and repair
B. General Expenses:
1. Administrative costs:
25. Administration, ~]% of total annualized costs
2. Distribution and selling costs:
26. Distribution and selling, 1% of total annualized costs
Source: (i) The factors to calculate components 20, 22, 25, and 26
were taken from Reference 2.
(ii) The factor to calculate component 21 was taken from
Reference 3.
(iii) The factors to calculate the remaining components were
taken from Reference 1.
8-7
-------
Table 8-4. NET ANNUALIZED COSTS FOR 39 CASES OF SULFUR INTAKE/ACID GAS
H2S/C02 RATIO/SULFUR RECOVERY TECHNOLOGY COMBINATIONS3
Case
No.
1
2
3
4
5
6
7
B
9
10
11
12
13
14
15
16
17
18
L9
10
Size
(sulfur intake)
Mg/d LT/D
5.1
5.1
5.1
5.1
5.1
10.2
10.2
10.2
10.2
10.2
10.2
10.2
10.2
10.2
10.2
101.6
101.6
101.6
101.6
101.6
5
5
5
5
5
10
10
10
10
10
10
10
10
10
10
100
100
100
100
100
Acid gas feed
H2S/C02 ratio
by volume
50/50
20/80
50/50
20/80
12.5/87.5
50/50
20/80
12.5/87.5
20/80
12.5/87.5
50/50
20/80
12.5/87.5
20/80
12.5/87.5
50/50
20/80
12.5/87.5
20/80
12.5/87.5
Sulfur recovery
technology
No recovery
No recovery
Recycle Selectox-2
stage
Recycle Selectox-2
stage
Recycle Selectox-2
stage
Claus-2 stage
Claus-2 stage
Claus-2 stage
Recycle Selectox-2
stage
Recycle Selectox-2
stage
Claus-3 stage
Claus-3 stage
Claus-3 stage
Recycle Selectox-3
stage
Recycle Selectox-3
stage
Claus-3 stage
Claus-3 stage
Claus-3 stage
Recycle Selectox-3
stage
Recycle Selectox-3
stage
Cost
$/year
231,365
231,365
537,876
573,067
608,373
512,149
691,324
795,924
514,668
580,363
576,982
753,471
849,862
596,480
684,596
(2,569,608)
(1,666,958)
(463,637)
(1,694,062)
(948,202)
Case
No.
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Size
(sulfur intake)
Mg/d LT/D
101.6
101.6
101.6
101.6
101.6
101.6
101.6
101.6
1016.0
1016.0
563.9
1016.0
563, 9
1016.0
563.9
1016. 0
563.9
1016.0
563.9
100
100
100
100
100
100
100
100
1000
1000
555
1000
555
1000
555
1000
555
1000
555
Acid gas feed
H2S/C02 ratio
by volume
50/50
20/80
50/50
20/80
50/50
20/80
50/50
20/80
80/20
50/50
20/80
50/50
20/80
50/50
20/80
50/50
20/80
50/50
20/80
Sulfur recovery
tec hnol logy
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
BSRP
Claus-3 stage with
BSRP
Claus-3 stage with
Sulfreen
Claus-3 stage with
Sulfreen
Claus-2 stage with
BSR/Selectox
Claus-2 stage with
BSR/Selectox
Claus-3 stage
Claus-3 stage
Claus-3 stage
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
SCOT/BSRMDEA
Claus-3 stage with
BSRP
Claus-3 stage with
BSRP
Claus-3 stage with
Sulfreen
Claus-3 stage with
Sulfreen
Claus-2 stage with
BSR/Selectox
Claus-2 stage with
BSR/Selectox
Cost
$/year
34,738
5,590,552
(1,707,122)
(793,079)
(2,014,549)
(1,217,247)
(2,364,802)
(1,697,336)
(38,439,508)
(36,912,577)
(14,353,713)
(20,345,209)
18,787,646
(33,884,038)
(13,625,880)
(36,830,877)
(15,009,103)
(36,670,098)
(17,395,397)
Compiled from data contained in References 1, 2, and 3. Values in parentheses indicate credits.
-------
Table 8-5. NET ANNUALIZED COSTS FOR EACH NEW MODEL PLANT/REGULATORY ALTERNATIVE COMBINATIONS'
Regulatory alternative
103
Model
plant
1
2
3
4
5
6
7
Fifth year
total
Projected number
(five year total)
47
21
6
1
2
0
1
78
I
230
510
(2,570)
(19,300)
(20,600)
(36,900)
(38,500)
(92,800)
II
230
510
(2,570)
(19,000)
(20,500)
(36,800)
(38,400)
(92,300)
III
600
580
(2,020)
(19,000)
(16,400)
(36,800)
(32,700)
(56,300)
net annual ized costs,
$/y
IV
750
580
(2,020)
(8,880)
(16,400)
(20,300)
(32,700)
(39,200)
V
750
1,200
5,590
(8,880)
(16,400)
(20,300)
(32,700)
19,400
VI
> 10, 700
1,200
5,590
(8,880)
(16,400)
(20,300)
(32,700)
487,000
Values in parentheses indicate credits.
-------
8.1.1.3 Cost Effectiveness. To determine cost effectiveness for
each individual model plant in Regulatory Alternatives II through VI,
the net annualized costs (from Table 8-5) associated with each of these
regulatory alternatives were subtracted from the net annualized costs
associated with the baseline controls (Regulatory Alternative I) and
then divided by the S02 emissions reductions (from sulfur recovery
efficiency of the technologies in Table 6-2 ) for each of the regulatory
alternatives (II through VI) beyond the Regulatory Alternative I emissions.*
Cost effectiveness was calculated for each model plant size. Incremental
cost effectiveness also was calculated, that is net annualized costs per
megagram S02 reduced to go from Regulatory Alternative II to its next
more stringent Regulatory Alternative III, and so on. Incremental cost
effectiveness was calculated for each model plant size in each regulatory
alternative. Cost effectiveness and incremental cost effectiveness in
each regulatory alternative for each model plant size are presented in
Table 8-6 through 8-11. Fixed-capital costs, net annualized costs, S02
emissions and steam and sulfur credits for Regulatory Alternative I in
each model plant were taken as baseline values in Table 8-6 through
Table 8-11. Considering these baseline values as zero, the incremental
values for the respective fixed-capital costs, net annualized costs, S02
emissions and steam/sulfur credits associated with Regulatory Alternatives II
through VI were determined and presented in Table 8-6 through 8-11.
8.1.2 Modified or Reconstructed Facilities
As stated in Chapter 5 of this document, no physical or operational
changes in the industry are anticipated that would qualify an existing
facility as "modification." Also, the cost attributable to any replacement
would not exceed 50 percent of the cost to construct a comparable,
entirely new facility. Consequently, no situations are anticipated that
would constitute a "reconstruction" to an exisiting facility. Therefore,
the costs for "modification" or "reconstruction" have not been developed.
8.2 OTHER COST CONSIDERATIONS
No other regulatory requirements are being imposed on the affected
facilities. Because affected facilities are expected already to be in
compliance with any existing applicable regulations, no additional costs
are incurred.
8-10
-------
Table 8-6. COST ANALYSIS OF REGULATORY ALTERNATIVES FOR MODEL PLANT #1
CO
I
I
(baseline control
level)
Parameters 12.5/87.5
Fixed-capital cost, $ (103) 0
Total annuali zed costs before 0
sulfur and steam credits,
$/y (103)
Sulfur credit, $/y (103) 0
Steam credit, $/y (1Q3) 0
Net annuali zed costs after 0
sulfur and steam credits,
$/y (103)
S02 emissions reductions 0
from the baseline control level, Mg/y
Cost effectiveness3 ($/Mg
S02 emission reduction)
Incremental cost
effectiveness ($/Mg S02
emission reduction)
Regulatory alternatives
II III IV V VI
12.5/87.5 12.5/87.5 12.5/87.5 12.5/87.5 12.5/87.5
0 1,050 1,920 1,920 6,220
0 592 755 755 >10,720
0 163 164 164 171
0 60 75 75 78
0 369 516 516 > 10, 500
0 3,250 3,320 3,320 3,470
114 155 155 >3,OOQ
144 1,930 - 68,200
aCost effectiveness = Net annualized costs of the given regulatory alternative minus net annuali'zed costs of the baseline
control level divided by the annual megagrams S02 emissions further reduced from the baseline control level.
Incremental cost effectiveness = Difference between net annualized costs of the given and the previous regulatory
alternative divided by the difference in the annual megagrams S02 emissions between the same alternatives.
-------
Table 8-7. COST ANALYSIS OF REGULATORY ALTERNATIVES FOR MODEL PLANT #2
co
i
ro
Regulatory alternatives
I
(baseline control
Parameters level)
50/50
Fixed-capital cost, $ (103) 0
Total annual ized costs before 0
sulfur and steam credits,
$/y (103)
Sulfur credit, $/y (103) 0
Steam credit, $/y (103) 0
Net annuali zed costs after 0
sulfur and steam credits,
$/y (103)
S02 emissions reductions from 0
the baseline control level, Mg/y
Cost effectiveness3 ($/Mg
S02 emission reduction)
Incremental cost
effectiveness0 ($/Mg S02
emission reduction)
II
50/50
0
0
0
0
0
0
-
-
Ill
50/50
370
78
8
5
65
164
396
396
IV V
50/50 12.5/87.5
370 5,250
78 1,050
8 13
5 350
65 684
164 263
396 2,600
6,250
•
VI
12.5/87.5
5,250
1,050
13
350
684
263
2,600
_
Cost effectiveness = Net annualized costs of the given regulatory alternative minus net annualized costs of the baseline
control level divided by the annual megagrams S02 emissions further reduced from the baseline control level.
Incremental cost effectiveness = Difference between net annualized costs of the given and the previous regulatory
alternative divided by the difference in the annual megagrams S02 emissions between the same alternatives.
-------
Table 8-8. COST ANALYSIS OF REGULATORY ALTERNATIVES FOR MODEL PLANT #3
00
I
OJ
Regulatory alternatives
I II III IV V VI
(baseline control
Parameters level)
50/50 50/50 50/50 50/50 50/50 50/50
Fixed-capital cost, $ (103) 0
Total annuali zed costs before 0
sulfur and steam credits,
$/y (103)
Sulfur credit, $/y (103) 0
Steam credit, $/y (103) 0
Net annual ized costs after 0
sulfur and steam credits,
$/y (103)
S02 emissions reductions from 0
the baseline control level, Mg/y
Cost effectiveness3 ($/Mg
S02 emission reduction)
Incremental cost
effectiveness ($/Mg S02
emission reduction)
0 1,820 1,820 14,300 14,300
0 671 671 9,370 9,370
0 83 83 135 135
0 33 33 1,070 1,070
0 555 555 8,160 8,160
1,690 1,690 1,690 2,740 2,740
329 329 2,980 2,980
329 - 7,220
Cost effectiveness = Net annualized costs of the given regulatory alternative minus net annualized costs of the baseline
control level divided by the annual megagrams S02 emissions further reduced from the baseline control level.
Incremental cost effectiveness = Difference between net annualized costs of the given and the previous regulatory
alternative divided by the difference in the annual megagrams S02 emissions between the same alternatives.
-------
Table 8-9. COST ANALYSIS OF REGULATORY ALTERNATIVES FOR MODEL PLANT #4
CO
I
Regulatory alternatives
I II III IV V VI
(baseline control
Parameters level)
50/50 50/50 50/50 50/50 50/50 50/50
Fixed-capital cost, $ (103) 0
Total annuali zed costs before 0
sulfur and steam credits,
$/y (103)
Sulfur credit, $/y (103) 0
Steam credit, $/y (103) 0
Net annuali zed costs after 0
sulfur and steam credits,
$/y do3)
S02 emissions reductions from 0
the baseline control level , Mg/y
Cost effectiveness3 ($/Mg
S02 emission reduction)
Incremental cost
effectiveness0 ($/Mg S02
emission reduction)
2,800 2,800 15,600 15,600 15,600
1,060 1,060 11,000 11,000 11,000
460 460 758 758 758
300 300 -200 *200 -200
300 300 10,500 10,500 10,500
9,360 9,360 15,400 15,400 15,400
32 32 679 679 679
32 - 1,680
Cost effectiveness = Net annualized costs of the given regulatory alternative minus net annualized costs of the baseline
control level divided by the annual megagrams S02 emissions further reduced from the baseline control level.
Incremental cost effectiveness = Difference between net annual!zed costs of the given and the previous regulatory
alternative divided by the difference in the annual megagrams S02 emissions between the same alternatives.
-------
Table 8-10. COST ANALYSIS OF REGULATORY A! TERNATIVES FOR MODEL PLANT #5
oo
i
Regulatory alternatives
I II III IV V VI
(baseline control
Parameters level)
80/20 80/20 80/20 80/20 80/20 80/20
Fixed-capital cost, $ (103) 0
Total annual i zed costs before 0
sulfur and steam credits,
$/y (103)
Sulfur credit, $/y (103) 0
Steam credit, $/y (103) 0
Net annual i zed costs after 0
sulfur and steam credits,
$/y (10a)
S02 emissions reductions from 0
the baseline control level, Mg/y
Cost effectiveness3 ($/Mg
S02 emission reduction)
Incremental cost
effectiveness0 ($/Mg S02
emission reduction)
1,550 15,000 15,000 15,000 15,000
672 4,680 4,680 4,680 4,680
361 649 649 649 649
280 -190 -190 -190 -190
31 4,220 4,220 4,220 4,220
7,340 13,200 13,200 13,200 13,200
4 320 320 320 320
4 717 - -
aCost effectiveness = Net annualized costs of the given regulatory alternative minus net annualized costs of the baseline
control level divided by the annual megagrams S02 emissions further reduced from the baseline control level.
Incremental cost effectiveness = Difference between net annualized costs of the given and the previous regulatory
alternative divided by the difference in the annual megagrams S02 emissions between the same alternatives.
-------
Table 8-11. COST ANALYSIS OF REGULATORY ALTERNATIVES FOR MODEL PLANT #6
CD
I
CTl
Regulatory alternatives
I II III IV V VI
(baseline control
Parameters level)
50/50 50/50 50/50 50/50 50/50 50/50
Fixed-capital cost, $ (103) 0
Total annuali zed costs before 0
sulfur and steam credits,
$/y (103)
Sulfur credit, $/y (103) 0
Steam credit, $/y (103) 0
Net annual i zed costs after 0
sulfur and steam credits,
$/y (103)
S02 emissions reductions from 0
the baseline control level, Mg/y
Cost effectiveness3 ($/Mg
S02 emission reduction)
Incremental cost
effectiveness ($/Mg S02
emission reduction)
3,560 3,560 22,200 22,200 22,200
1,240 1,240 17,700 17,700 17,700
830 830 1,370 1,370 1,370
332 332 -230 -230 -230
82 82 16,600 16,600 16,600
16,900 16,900 27,700 27,700 27,700
5 5 597 597 597
5 - 1,520
b
Cost effectiveness = Net annual i zed costs of the given regulatory alternative minus net annual'ized costs of the baseline
control level divided by the annual megagrams S02 emissions further reduced from the baseline control level.
Incremental cost effectiveness = Difference between net annualized costs of the given and the previous regulatory
alternative divided by the difference in the annual megagraras S02 emissions between the same alternatives.
-------
Table 8-12. COST ANALYSIS OF REGULATORY ALTERNATIVES FOR MODEL PLANT #7
Table 8-12.
00
i
Regulatory alternatives
I II III IV V VI
(baseline control
Parameters level)
80/20 80/20 80/20 80/20 80/20 80/20
Fixed-capital cost, $ (103) 0
Total annuali zed costs before 0
sulfur and steam credits,
$/y (io3)
Sulfur credit, $/y (IO3) 0
Steam credit, $/y (IO3) 0
Net annuali zed costs after 0
sulfur and steam credits,
$/y (IO3)
S02 emissions reductions from 0
the baseline control level, Mg/y
Cost effectiveness3 ($/Mg
S02 emission reduction)
Incremental cost?
effectiveness0 ($/Mg S02
emission reduction)
1,610 17,900 17,900 17,900 17,900
1,040 6,690 6,690 6,690 6,690
651 1,170 1,170 1,170 1,170
303 -210 -210 -210 -210
84 5,730 5,730 5,730 5,730
13,200 23,800 23,800 23,800 23,800
6 241 241 241 241
6 536
aCost effectiveness = Net annualized costs of the given regulatory alternative minus net annual 1 zed costs of the baseline
control level divided by the annual megagrams S02 emissions further reduced from the baseline control level.
Incremental cost effectiveness = Difference between net annualized costs of the given and the previous regulatory
alternative divided by the difference in the annual megagrams S02 emissions between the same alternatives.
-------
8.3 REFERENCES FOR CHAPTER 8
1. The Ralph M. Parsons Company, Engineers/Constructors. Sulfur
Recovery Study-Onshore Sour Natural Gas Production Facilities. The
study was conducted for TRW. July 1981. The study is presented in
Appendix E.
2. Peters, M.S., and K.D. Timmerhaus. Plant Design and Economics for
Chemical Engineers, Second Edition. McGraw-Hill Book Company, New
York, 1968.
3. U.S. EPA, Economics Analysis Branch, Capital and Operating Costs of
Selected Air Pollution Control Systems. EPA 450/5-80-002.
8-18
-------
9. ECONOMIC ANALYSIS OF THE ONSHORE NATURAL GAS
PRODUCTION INDUSTRY S02 NSPS
9.1 INDUSTRY PROFILE
This section describes the general business and economic conditions of
the onshore natural gas production industry. The primary focus of the
discussion is on the production facilities that recover elemental liquid
sulfur from acid gas which is separated from sour natural gas.
Projections for the year 1987, five years after a proposal date of
1982 for the NSPS for new sources, were developed for the industry. The
growth projections are presented to illustrate the future trend of the
industry. The profile and the projections, including significant factors
and trends in the industry, are presented to aid in the determination of
economic impacts of the proposed standards. The energy and environmental
impact analyses also were conducted based upon these projections. The
economic impacts are described in subsequent sections.
9.1.1 Onshore Natural Gas Production Industry
The natural gas system in the United States consists of producers,
processors, dealers, interstate and intrastate pipelines, distributors and
consumers. The production industry includes hundreds of firms engaged in
the exploration, drilling, producing and processing of natural gas. A
relatively small number of companies dominate the industry. The American
Association of Petroleum Geologists (AAPG) states that the 16 largest firms
in the industry found 53.7 percent of 2.8 billion barrels of crude oil and
40.3 percent of 41.3 trillion cubic feet of natural gas discovered during
the period from 1969 to 1978. Also, the AAPG states that the 16 largest
companies accounted for about 60 percent of industry expenditures for
geological and geophysical information and lease acquisition. However,
9-1
-------
these large companies spend almost twice as much money as smaller firms on
predrilling exploration and one-half as much as the others on wildcat
drilling.
Some companies engage in the operations of drilling, producing and
processing of natural gas. Additionally, if the natural gas is sour,
companies incorporate a sweetening operation that removes H2S and C02 from
the sour natural gas. Sulfur may then be removed from the separated acid
gas. Other companies drill for and produce sour natural gas, but contract
with companies owning sweetening facilities to perform the sweetening and
sulfur recovery operations for them. Individual ownership or joint
ownership in one or all of these operations exists in this industry. In
recent years, about 19 percent of the onshore natural gas is estimated to
have undergone sweetening. Roughly one third of this or 6.3 percent has
been associated with natural gas sulfur recovery.
About two-thirds of all natural gas is transmitted in pipelines across
state lines to be sold in various metropolitan areas. The remainder is
sold in intrastate markets. Approximately 100 pipeline companies operate
the interstate pipeline network. The pipeline sector of the industry tends
to be dominated by large companies more than the production sector. In
1971, the four largest pipeline companies accounted for 35 percent of the
total interstate pipeline volume, while the 20 largest companies
transported over 93 percent of the gas.
Companies involved in final distribution of the gas constitute the
least concentrated sector of the industry. Over 1,600 companies buy gas
from pipelines and distribute it to various communities. Because they
operate in different service areas, these companies rarely compete with one
another, except in input markets, and are often regulated by state or local
agencies.
There is some vertical integration in the industry with pipeline
companies often owning producing wells. However, few companies engage in
production, transmission and distribution of the gas. In contrast,
horizontal integration is quite extensive. In the production sector,
9-2
-------
many companies produce crude oil and natural gas liquids in addition to
natural gas although no one company predominates. In .addition, many have
investments in coal, oil shale, synfuels and mineral industries.
9.1.1.1 Number, Size and Location of Natural Gas Wells. The American
Gas Association (AGA) reports that in 1979 over 20 trillion cubic feet of
natural gas were produced by nearly 170,000 producing gas wells located in
30 states. The leading producing states are Texas, Louisiana, Oklahoma,
New Mexico and Kansas. The number of wells and production by state are
shown in Table 9-1 which lists the states in rank order according to
2
average gas well size (flow rate) based on revised 1979 figures from AGA.
The largest wells on average by state are located in Alaska and produce
over 10,000 Mcfd. The smallest wells on average by state are located in
Oregon, Indiana and Maryland where the average gas wells produce less than
10 Mcfd. Nonassociated (non-oil producing) gas wells which produce less
than a maximum of 60 Mcfd are defined by the Natural Gas Policy Act to be
stripper gas wells.
It is estimated, based on the figures in Table 9-1, that the
distribution of domestic gas wells and production by well size is
approximately as follows.
Percent of Percent of
Well Size Total Wells Total Production
(Mcfd)~~
Less than 100 43 2
100-400 25 20
400-800 22 36
More than 800 10 42
OT TOU
At the low end of the well size distribution, about 43 percent of all
producing gas wells supply two percent of total production. At the high
end, about ten percent of the wells supply 42 percent of total net wellhead
production from dry gas and condensate wells. Excluded from this
distribution are oil wells which also produce gas.
9-3
-------
Table 9-1. NUMBER, AVERAGE SIZE, AND TOTAL PRODUCTION OF PRODUCING GAS WELLS,
BY STATE (REVISED 1979 FIGURES)
Oregon
Indiana
Maryland
Pennsylvania
Tennessee
West Virginia
New York
Kentucky
Ohio
Montana
Illinois
Virginia
yo Colorado
i Kansas
•** Arkansas
New Mexico
South Dakota
Oklahoma
Nebraska
Texas
California
Utah
Uyomi ng
Arizona
Alabama
Mississippi
Michigan
Louisiana
North Dakota
Alaska
Average gas
well size
Mcfd a/
1
1
6
13
16
17
19
21
21
81
85
91
205
207
215
239
252
354
439
553
612
891
923
953
957
1,155
1,185
1,381
1,595
10,641
Number
of
wells
5
655
12
19,800
184
24,725
2,200
7,883
15,827
1,881
51
258
2,574
10,544
1,402
13,598
10
14,417
20
35,650
1,117
182
1,236
1
250
433
376
14,464
78
58
Cumulative
wells
5
660
672
20,472
20,656
45,381
47,581
55,464
71,291
73,172
73,223
73,481
76,055
86,599
88,001
101,599
101,609
116,026
116,046
151 ,696
152,813
152,995
154,231
154,232
154,482
154,915
155,291
169,755
169,833
169,891
Total state
production
(MMcfy)
2
350
28
96,313
1,067
150,505
15,500
59,520
123,431
55,577
1,585
8,544
192,438
798,563
109,923
1,185,999
919
1,861,971
3,208
7,201,973
249,459
59,165
416,246
348
87,312
182,494
162,691
7,292,278
45,400
225,280
Cumulative
production
(MMcfy)
2
352
380
96,693
97,760
248,265
263,765
323,285
446,716
502,293
503,878
512,422
704 ,860
1,503,423
1,613,346
2,799,345
2,800,264
4,662,235
4,665,443
11,867,416
12,116,875
12,176,040
12,592,286
12,592,634
12,679,946
12,862,440
13,025,131
20,317,409
20,362,809
20,588,089
a/ Net wellhead production, dry gas and condensate wells only.
Source: Gas Facts. AGA, 1981, Tables 16 and 25.
-------
9.1.1.2 Natural Gas Production Cost from New Wells. The cost of
producing natural gas is highly variable and depends on many factors such
as drilling depth, probability of drilling a producing well, well flow
rates, etc. Among these factors, drilling costs are the most important.
In 1979, the petroleum industry spent approximately $16.1 billion for
drilling and equipping onshore and offshore oil and gas wells and dry
holes. The average depth of gas wells in 1979 was 5,493 feet. The average
cost per foot was $80.66, up from $68.37 in 1978. Table 9-2 shows that the
industry spent $12.8 billion for drilling and equipping 47,263 onshore oil
and gas wells and dry holes. The average depth of onshore gas wells in
1979 was 5,337 feet. The average cost of drilling an onshore gas well was
$367,710 in 1979. Costs for drilling and equipping onshore gas wells
through the "Christmas tree" (wellhead) are analyzed in Table 9-3 for
selected depth intervals. Average costs per well by depth interval from
the Joint Association Survey data are allocated a share of dry hole
drilling costs and escalated 17.2 percent to obtain an estimated cost of
drilling and equipping a producing gas well in 1980 dollars. At 2,000,
4,000, 8,000 and 12,000 feet, the estimated drilling costs per well are
$89,000, $211,000, $949,000 and $1,875,000, respectively. 3
Drilling costs are combined with Department of Energy estimates of
additional field equipment costs and annual operating and maintenance
costs. In Table 9-4 these total unit wellhead production costs are
estimated. Field equipment costs and operating and maintenance costs are
variable with gas flow rate. As shown in Table 9-4, field equipment costs
(including dehydrators, field gathering pipelines, etc.) between the
"Christmas tree" and point of transfer typically average $15,000 for a gas
well producing 50 Mcfd and $64,000 for a well producing 5,000 Mcfd. Annual
operating and maintenance costs average $6,000 per year for a gas well
producing 50 Mcfd and $29,000 for a gas well producing 5,000 Mcfd. These
4 5
costs are expressed in 1980 dollars. '
Estimated average unit total costs (1980 $/Mcf) for new wells at the
selected depths and flow rates are also shown in Table 9-4. The unit costs
shown in Table 9-4 are based on the following assumptions: 20 percent
9-5
-------
Table 9-2. ESTIMATED COSTS OF DRILLING AND EQUIPMENT ONSHORE* WELLS, BY DEPTH INTERVALS - 1979
TOTAL NUMBER OF HELLO,
FOOTAGE DRILLED,ANO COSTS AVERAGE DEPTH AND COST PER WELL
DEPTH INTERVAL
(FEET)
NELLS
FOOTAGE 0 - 1.249
COSTS S
HELLS
FOOTAGE 1,250 - 2,499
COSTS I
NELLS
FOOTAGE 2,500 - 3,749
COSTS t
NELLS
FOOTAGE 3,750 - 4,999
COSTS >
NELLS
FOOTAGE 5,000 - 7,499
COSTS t
f HELLS
01 FOUTAGt 7,500 - 9,999
COSTS *
HELLS
FOOTAGE 10,000 - 12,499
COSTS »
NELLS
FOOTAGt 12,500 • 14.999
COSTS i
NELLS
FOOTAGE 15,000 - 17,499
COSTS 1
HELLS
FOOTAGE 17,500 - 19,999
COSTS 1
HELLS
FOOTAGE 20,000 t OVER
COSTS i
TOTAL nELLS
TOTAL FOOTAGE
TOTAL COSTS «
OIL
NELLS
3,124
2,593,461
06,306,465
3,679
6.742,062
241,163,201
3,749
11,666,331
'101,962,239
2,545
11,174,192
410,452,099
2.924
17,753.697
606,370,701
2,121
10,180,438
1,005,358,592
529
5,797,665
549,«0(«.I67
102
2.409,96tt
265,191,467
36
577,943
95,730,409
1
18,500
2,625,521
4
86,526
19, |0«, 100
16,69'!
77,020,96}
3,903, 7S7, 002
GAS
HELLO
012
725,740
22,057.939
2.240
4,465,634
142,526,662
2,602
0,271,775
273.660,295
2,220
9,607,559
314,233,646
2,638
16,007,766
665,066,394
1,454
12,713.366
639,442,405
966
10,692,591
1,026,150,996
423
5,735,964
746,345,379
181
2,921,106
520,415,261
62
1,149,520
260,626,636
20
442,077
169,066,312
13,626
72,733,130
5,010,420,429
DRV
HOLES
1,405
1,056,301
26,102,966
2.126
4,026,641
95,923,692
2,717
6,527,705
193,936,405
2,516
11,011,375
257,064,607
2,666
17,562,450
514,402.953
1,481
12,753,621
560,625,002
916
10,123,172
719,506,625
435
5,675,3.12
598,673,500
156
2,512,462
363,136,290
72
1,335,766
294.558,344
27
580,623
231,767,935
l«,743
75,365,52*
3,677,721,739
TOTAL
5,341
4,375,582
137,147,410
0,055
15,234,337
474,615,775
9,060
20.405,011
'069.560,939
7,283
31,793.126
961,749,954
8,450
51.324,131
2,005,042,040
5,056
43,647.427
2.505.426,079
2,4||
26,613.426
2,297,065,606
1,040
14,021,264
1,630,210,346
373
6,011,513
979,261,959
135
2,503,794
565,012,505
51
1,109.226
419,964,347
47,263
225.119,641
12,671,699,170
OIL
030
27,652
1,032
6S,S5|
1,117
107,210
4,190
161,277
6.071
275.776
0,571
511,720
10,959
1,036,578
13,241
1,566,986
16,053
2,659,170
10,500
2.625,521
21,611
4,777,025
4,076
210,047
OAO
093
20, ISO
1,906
63,402
1,179
105,100
4,127
141,546
6,060
259,692
0,743
577,133
11,060
1,064,330
13,560
1,764,409
16,130
2,075,222
10,540
4,332,719
22,103
0,453,415
5,317
167,710
DRV
751
20,002
1,092
45,076
1,110
71,179
4,171
102,090
6,001
170,117
0,611
192,049
11,051
705,407
11,506
1,176,260
16,105
2,127.009
10,552
4,091,000
21,504
0,504,710
5,111
261,021
TOfAt
•»»*•»•
019
43,71*
1,091
1,141
95,695
4,165
114,000
6,071
217,17)
0,612
495,539
11,010
952,744
-11,401
1,567,509
16,116
2,625,426
10,546
4,191,201
21,749
6,234,595
4,761
272,146
* Includes the following states and areas which are not showh separately: Arizona. Idaho. Htssourl. Nevada. Oregon South Dakota
Tennessee, and Virginia Note: Includes Alaska-Onshore ' * ' ""Kola.
Source: AGA,'1979 Joint Association Survey on Drilling Costs, February, 1981 ed_ Table 4
-------
Table 9-3. ESTIMATED COST FOR DRILLING AND EQUPPING ONSHORE, NATURAL GAS
WELLS FOR SELECTED WELL DEPTHS, 1980
(Well depth)
2,000 4,00087000 12,000
Cost per onshore gas well 1979$ 63,000 142,000 578,000 1,064,000
drilled
Dry hole factors I/ 1.2 1.3 1.4 1.5
Cost per producing 1979$ 76,000 180,000 810,000 1,600,000
gas well drilled
Escalation factor 2/ 1.172 1.172 1.172 1.172
Cost per producing 1980$ 89,000 211,000 949,000 1,875,000
gas well drilled
\J Dry hole cost factor equals the ratio of total cost divided by total
costs for gas and oil wells, by depth interval
2J American Petroleum Institute, 1979 Joint Association Survey on Drilling
Costs, February 1981, edition.Table 3 page 9.
9-7
-------
CO
Table 9-4. ESTIMATED ONSHORE NATURAL GAS PRODUCTION COSTS FOR SELECTED WELL
DEPTHS AND BASE YEAR FLOW RATES, 1980
Well depth (feet)
2,000 4,000
Flow rate
(Mcfd)
50
250
500
1,000
5,000
10,000
!/
y
Source
Source:
Drilling and equipment cost per
productive gas well \J (1980 $)
Unit '
Field equipment Annual O&M variable
cost 2/ 3/ cost 2/ cost 4/
(1980$)
15,000
26,000
35,000
43,000
64,000
87,000
is Table 9-3.
"Aggregate Average
DOE, Dallas, TX,
(1980 $/yr) (1980$/Mcf)
6,000 ($.36/Mcf .93
12,000 ($.14 Mcf) .88
15,000 ($.09/Mcf) .47
20,000 ($.06/Mcf) .25
29,000 ($.02/Mcf) .06
44,000 ($.01/Mcf) .03
Annual Gas Well Operating
(1981 figures deflated to
Costs vs
1980 by 95
8,000
89,000 211,000 949,000
Unit total cost
4.31
1.02
.56
.31
.08
.05
1QRH
8.95
1.95
1.02
.54
.12
.07
Production Capacity
6) (See
Reference 5).
q* /Ms*-p
36.99
7.55
3.83
1.94
.40
.21
1981"
12,000
1,875,000
72.18
14.59
7.35
3.70
.75
.39
3/ Includes field equipment between "Christmas tree" and point of transfer. Does not include sour gas
sweetening or sulfur recovery equipment.
4/ Unit variable costs include field equipment costs and operating and maintenance costs.
-------
royalty payments, 15 percent depletion allowance, production decline rate
of 6 percent per year, operating cost decline rate of 6 percent per year,
20-year well life, 8 percent inflation, 10 percent nominal industry
weighted cost of capital, 47 percent marginal corporate income tax rate, 10
percent investment tax credit rate, and accelerated cost recovery system
(over ten years). The equation for estimating the average unit costs in
Table 9-4 is shown in Appendix F.
The unit costs estimated in Table 9-4 illustrate the variability of
production costs from new gas wells. The magnitude of the costs are
indicative of average production costs under the assumed conditions.
Variation of those conditions and individual well circumstances naturally
affect actual costs.
Based on the data presented above, it is seen that the total unit cost
of natural gas production from individual producing new wells ranges over
at least four orders of magnitude (e.g. from $.05 per Mcf to over $70.00
per Mcf). Although the average cost of new natural gas for an individual
producer, gas field or composite for the industry is indeterminant from the
data presented above due to a lack of new well characteristics (flow rates,
decline rates, and depth, Table 9-4 does indicate several important
characteristics of the industry. First, new gas production requires large
front-end investments for exploration and development drilling. Second,
there is a significant risk that any individual well will be dry or too
small to recover total costs. Also, operating costs are relatively small
so that after drilling costs are sunk, it is often economical for the
operator to produce the well to cover short run variable costs while making
some contribution, however small, to capital recovery. Consequently, some
wells produce at a loss against total cost. Economic profits on individual
wells or gas fields are inversely related to well depth and positively
related to well flow rate, all other things being equal.
9.1.1.3 Natural Gas Sulfur Recovery Facilities
In 1980, there were 31 companies that owned a total of 89 onshore
natural gas sulfur recovery facilities. These facilities had a total
capacity of approximately 10,600 megagrams of recovered sulfur per day.
9-9
-------
Table 9-5 presents these 31 companies, their sulfur recovery facilities,
* c
and their combined daily capacity. Table 9-5 indicates that no single
company operator controls the industry. However, a major fraction of the
combined sulfur recovery capacity is controlled by a relatively small
number of companies. The five largest operators have a combined capacity
of 8,238 megagrams of recovered sulfur per day, which is 77.4 percent of
the total combined capacity of the industry. In addition, the 15 largest
operators have a combined capacity of 10,250 megagrams per day or 96.3
percent of the total industry capacity. The remaining 16 operators have a
combined capacity of 3.7 percent of the total. This distribution implies
that small producers tend to leave processing activities to the larger
firms. Some of these smaller operators are gas transmission (pipeline)
companies engaged in the production of oil and gas. However, most of these
sulfur recovery facility operators are diversified oil and gas producing
companies and are ranked among the largest 100 industrial corporations
listed by Fortune Magazine.
Table 9-6 presents a list of the onshore natural gas sulfur recovery
facilities and the location, year commissioned and capacity of each
facility. Data on daily sulfur recovery for three facilities were not
available. The combined sulfur recovery capacity of the 86 facilities is
10,600 megagrams per day, which indicates that the average capacity per
facility is approximately 125 megagrams per day. Table 9-6 also presents
data on the volume percentage of H^S in the sour natural gas stream for
each facility. The H^S concentrations range from 1 to 45 volume percent,
which indicates that the composition of sour natural gas varies from one
well to the other. Also, plants with a larger sulfur recovery capacity
tend to be associated with higher H2S percentages in the sour natural gas.
This is indicated by the observed distributions shown in Table 9-7 which
are based on the plant data in Table 9-6. The hLS percentage in the sour
natural" gas determines in part the ratio of sulfur to hydrocarbons in the
sour natural gas stream. A higher H2S percentage yields more sulfur and
less hydrocarbons. For example, sour natural gas from one well may be
9-10
-------
TaWa 9-5 ONSHORE NATURAL GAS SULFUR RECOVERY FACILITY OPERATORS, 1979
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16 .
17
18
Company/operator
Shell Oil Company
Exxon Company USA
Amoco Production Company
Pursue Gas Processing and Petroleum
Company (Mid- American Oil and Gas
and Pursue Energy Corporation)
Chevron U.S.A., Inc. (Standard Oil
Company of California)
Getty Oil Company
Warren Petroleum Company (Gulf Oil
Corporation)
Phillips Petroleum Company
El Paso Natural Gas Company
Cities Service Company
Aminoil U.S.A., Inc. (R.J. Reynolds
Industries, Inc.)
Texaco, Inc.
Husky Oil Company
Trans-Jeff Chemical Corporation
Marathon Oil Company
Colorado Interstate Gas Company
(Coastal States Gas Corporation)
Atlantic Richfield Company
Natural Gas Pipeline Company of
America
(conti
9-11
Number of
operating facilities
7
7
10
1
1
3
6
5
5
4
2
9
3
1
2
1
2
4
nued)
Daily sulfur
intake capacity
(combined), Mg/d
2,207
1,974
1,962
1,095
1,000
354
281
279
276
271
230
90.3
85
80
66
66
49
47
-------
Table 9-5. Continued
Number
Company/operator
Number of
operating facilities
Daily sulfur
intake capacity
(combined), Mg/d
19
20
21
22
23
24
25
26
27
28
29
3P
31
Tonkawa Gas Processing Company
(Texas Oil and Gas Corporation)
Intratex Gas Company (Houston
Natural Gas Company)
Diamond Shamrock Corporation
Sinclair Oil Corporation (Little
America Refining Company)
MGF Oil Corporation
Union Oil Company 'of California
Lone Star Gas Company
Northern Natural Gas Company
Suburban Propane Gas Corporation
Pioneer Gas Products Company
(Pioneer Corporation)
Westland Oil Development
Corporation
Gulf Energy and Development
Corporation
Dorchester Gas Corporation
TOTAL
2
1
1
1
1
1
1
1
1
2
1
1
2
89
35
33
30
25
22
18
15
14
14
9
5.5
5
3
10,640.8
Source: Chemical Economics Handbook - Stanford Research Institute (SRI)
International, December, 1979.
9-12
-------
Table 9-6. ONSHORE NATURAL GAS SULFUR RECOVERY FACILITIES (CEH December 1979)
Company and
name of plant
AHINOIL USA. INC.
(R.J. Reynolds Industries
Inc. subsidiary)
(1) Birthright plant
(2) Tioga plant
AMOCO PRODUCTION COMPANY
(Standard Oil Company of
Indiana subsidiary)
(3) South Fuller-ton -
Andrews plant
(4) Sundown - Level land
plant
(5) Midland Farms plant
(6) Edgewood plant
(7) West Vantis plant
(8) North Cowden -
Goldsmith plant
(9) Empire Abo - Artesia.
2 plants (3 trains)
(10) Elk Basin - Powell
plant (2 trains)
(11) Beaver Creek -
Riverton plant
(12) Whitney Canyon -
Evanston plant
Location
State/county coi
Texas/Hopkins
North Dakota/
Williams
Texas/Andrews
Texas/Hockley
Texas/Andrews
Texas/Van Zandt
Texas/Wood
Texas/Ector
New Mexico/Eddy
Wyoming/Park
Wyoming/Fremont
Wyoming/Uinta
Year
missioned
1963
1953.
1963.
1967
1968
1952
1954
1964
1963
1953
1960.
1975.
1977
1949.
1974
1965
1982
MMscf/
day"
30
105
10
40
45
60
50
45
51
16
66
N.A.
Mega-
grams
daily
30
200
6
49
11
356
81
33
71
134
71
1.150
Capacity3
Mole percent
HjS in sour
natural gas
2.61
4.98
1.57
3.20
I
0.64
15.51
4.23
1.92
3.64
21.89
2.81
e
Thousand
megagrans
annually
11
73
2
17
4
128
29
12
26
50
25
400
1978
production
thousand
negagrams
N.A."
N.A.
1.3
14.7
3.8
71.6
8.5
11.0
16.0
24.0
3.0
N.A.
Designer
N.A.
N.A.
National
Tank
Fluor
Staff
Brown & Root
Trend
Construction
Girdler
Olson Fraily
Olson; Stone
and Webster
Dresser
N.A.
Remarks
Owned 54X by
ABOCO
Owned 49X by
Amoco
Owned 50X by
Amoco
Owned 50X by
Amoco
(continued)
-------
Table 9-6. Continued
I
I—1
•£>
Company and
name of plant
Location
State/county
Year
commissioned
MMscf/
day"
Mega-
grams
daily
Capacity
Mole percent
H2S in sour.
natural gas
Thousand
negagrams
annually
1978
production
thousand
oegagraos Designer
Remarks
ATLANTIC RICHFIELD COMPANY
(13) Artesia plant New Mexico/Eddy
1966
N.A.
41
(14) Fashing plant
CHEVRON USA. INC.
(Standard Oil Company of
California subsidiary)
(15) Carter Creek plant
CITIES SERVICE COMPANY
(16) Myrtle Springs -
Canton plant
Texas/Atascosa before 1961 12
1.74
Wyoming
Texas/Van Zandt
1982
1968
N.A, 1,000
30
236
20.56
350
86
15.0
1.1
N.A.
41.0
N.A. Owned 50X by
Atlantic
Richfield
N.A.
N.A.
N.A.
(17) West Sentnole plant
(18) Welch plant
(19) Bluitt-Milnesand
COLORADO INTERSTATE GAS
COMPANY (Coastal States
Gas Corporation
subsidiary)
(20) Table Rock - Rock
Springs plant
DIAMOND SHAMROCK
CORPORATION
(21) McKee - Sunray plant
Texas/Gaines before 1961 40 11 0.72
Texas/Dawson 1970 30 4 0.35
New Mexico/ 1967 40 20 1.31
Roosevelt
Wyoming/ 1980 N.A. 66
Sweetwater
Texas/Moore 1951 375 30 0.21
4 2.2 N.A.
1.44 N.A. N.A.
7.2 N.A. N.A.
24 N.A. N.A.
10 6.2 Ford, Bacon
& Davis
(continued)
-------
Table 9-6. Continued
vo
1
I—1
en
Company and
name of plant
DORCHESTER GAS
CORPORATION
(22) Bid Lake - Texon
plant
(23) Marshall plant
EL PASO NATURAL GAS
COMPANY
(24) Goldsmith plant
(25) McElroy - Crane
plant
(26) Odessa plant
(Odessa Natural Gas
Corporation)
(27) Eunice plant
(28) JAL *4A plant
EXXON COMPANY USA
(29) Flomaton plant
(30) Big Escambia Creek
plant (2 trains)
(31) Fanny Church Field
plant
(32) Jayfield plant
(9 trains)
Location
State/county
Texas/Reagan
Texas/Potter
Texas/Ector
Texas/Crane
Texas/Ector
New Mexico/Lea
New Mexico/Lea
Alabama/Escambia
Alabama/Escambia
Alabama/Escambia
Florida/Santa
Rosa & Escambia
Year
commissioned
1963
1960
1956
1958
1950
before 1961
1971
1972
1974.
1977 '
1971
1970.
1973
MMscf/
day6
5
100
17
35
168
88
185
35
N.A.
N.A.
112
Mega-
grams
daily
3
N.A.
145
74
27
30
N.A.
122
915
N.A.
820
Capacity8
Mole percent
H2S in sour
natural gas
1.57
-
22.3
5.53
0.42
6.89
-
9.11
-
-
19.14
Thousand
megagrans
annually
1
N.A.
50
25
10
11
N.A.
42
315
N.A.
300
1978
production
thousand
megagrams
N.A.
N.A.
12.5
15.4
6.0
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
Designer
Stilwell
Engineering
N.A.
N.A.
N.A.
Graff
N.A.
N.A.
Hudson
Ortloff
N.A.
Delta (4).
Ortloff (4).
Cenatco (1)
Remarks
Partly owned
by Sid
Richardson
Carbon Company
Formerly
operated by
Mallard
Exploration Co.
(continued)
-------
Table 9-6. Continued
Company and
name of plant
(33) Blackjack Creek
plant
(34) Sand Hills plant
(2 plants)
(35) Jourdanton plant
GETTY OIL COMPANY
(36) Hatters Pond plant.
Satsuma
(37) New Hope - Scroggins
plant (2 trains)
(38) Texas plant
GULF ENERGY AND
DEVELOPMENT CORPORATION
*-* (39) Navarro County plant
HUSKY OIL COMPANY
(40) Cheyenne plant
(2 plants)
(41) Ralston plant
(42) Santa Maria
Operations plant
INTRATEX GAS COMPANY
(Houston Natural Gas
Company subsidiary)
(43) Mi Vida plant
(3 plants)
Location
State/county coi
Florida/Santa
Rosa
Texas/Crane
Texas/Atascosa
Alabama/Mobile
Texas/Franklin
Texas/Freestone
Texas/Navarro
WyoMing/Laranie
Wyoming/Park
California/Santa
Barbara
Texas/Reeves
Year
missioned
1974
1971
1968
1979
1960
1969
1972
1974.
1980
1964.
1966
1979
1970.
1974.
1974
MMscf/
day6
N.A.
90
26
15
50
N.A.
15
N.A.
7.3
35
150
Capacity
Mega- Mole percent
grans HZS in sour
daily natural gas
76
22 ' 0.64
19 1.91
12 2.09
228 11.92
114
5 '0.87
30
45 16. 1
10 0.75
33 0.58
Thousand
negagrams
annually
26
7
6
4
83
41
2
5
10
16
3
12
1978
production
thousand
•egagrams
N.A.
6.9
5.9
N.A.
29.0
20.2
O.B
N.A.
N.A.
N.A.
N.A.
5.9
Designer Remarks
Ortloff
National
Sulfur
Hudson
Delta
Brown & Root
Delta
N.A.
N.A.
N.A,
N.A.
R. L. Fraily
N.A,
(continued)
-------
Table 9-6. Continued
10
I
Company and
name of plant
LONE STAR GAS COMPANY
(44) Warwlnk - Pyote
plant
MARATHON OIL COMPANY
(45) Indian Basin -
Artesia plant
(2 trains)
(46) Yates - Iraan plant
(2 trains)
MGF OIL CORPORATION
(47) Dimmit County plant
NATURAL GAS PIPELINE
COMPANY OF AMERICA
(Peoples Gas Company
subsidiary)
(48) Herscher plant
(49) St. Elmo plant
(SO) Kermit plant
(51) Maud-Redwater plant
NORTHERN NATURAL GAS
COMPANY
(52) Hobbs plant
PHILLIPS PETROLEUM COMPANY
(53) Chatom plant
Location
State/county
Texas/Ward
New Mexico/Eddy
Texas/Pecos
Texas/Oimmit
Illinois/
Kankakee
Illinois/Douglas
Texas/Winkler
Texas/Bowie
New Mexico/Lea
Alabama/
Washington
Year
commissioned
1974
1967.
1975
1967.
1974
1972
1972
1973
1973
1974
1969
1974
MMscf/
dayb
N.A.
220
25
N.A.
N.A.
N.A.
N.A.
N.A.
220
25
Capacity3
Mega- Mole percent
grams H2S in sour
daily natural gas
15
41 0.49
25 2.61
22
'
1
9
11
26
14 0.17
132 13.8
Thousand
megagrans
annually
5.4
15
9
8
<1
2
4
9
5
56
1978
production
thousand
megagrams Designer Remarks
N.A. N.A.
N.A. Ortloff.
Trenthaia
9.2 Ortloff.
Trenthan
3.8 N.A.
0.1 Pritchard
0. 6 Holmes/Gas
Machinery
0.9 B.S. & B.
2.0 Graff /Trent ham
N.A. N.A.
N.A. Staff
(continued)
-------
Table 9-6. Continued
I
I—1
00
Company and
name of plant
(54) Stamps - McKamie
plant
(55) Andrews plant
(56) Fuller-ton plant
(57) Artesia plant
PIONEER GAS PRODUCTS
COMPANY (Pioneer Corpora-
tion subsidiary)
(58) Madil) plant
(59) Goldsmith plant
PURSUE GAS PROCESSING &
PETROLEUM COMPANY (Mid-
American Oil & Gas and
Pursue Energy Corporation)
(60) Rank in County plant
UNION OIL COMPANY OF
CALIFORNIA
(61) Chunchula plant
SHELL OIL COMPANY
(62) Manistee plant
Location
State/county
Arkansas/
Lafayette
Texas/Andrews
Texas
New Mexico/Eddy
Oklahoma/
Marshall
Texas/Ector
Mississippi/
Rankin
Alabama/Mobile
Michigan/
Manistee
Year
commissioned
1944
1967
1975
1973
1967
1967
1981
1979
1973
MMscf/
day"
35
115
55
43
27
50
N.A.
N.A.
350
Mega-
grans
daily
22
22
66
37
4
5
1.095
18
17
Capacity
Mole percent
H2S in sour
natural gas
1.64
0.5
3.14
2.25
0.39
0.26
i
—
-
0.13
Thousand
megagrams
annually
8
8
24
13
1
1.8
400
6
6
1978
production
thousand
negagrams Designer Remarks
N.A. Staff
4.0 Staff
23.5 Staff
N.A. Staff
N.A. Ortloff
N.A. N.A.
N.A. N.A.
N.A. N.A.
N.A. N.A.
(continued)
-------
Table 9-6. Continued
10
Company and
name of plant
(63) Goodwater plant
(64) Thomasville plant
(65) Bryan's Mill -
Oouglasville plant
(66) Person - Hobson
plant
(67) Eustace Field plant
(Smackover Shell
Ltd.)
(68) Stateline plant
SINCLAIR OIL CORPORATION
(Little America Refining
Company subsidiary)
(69) Sinclair plant
SUBURBAN PROPANE GAS
CORPORATION
(70) Perry (Dimmit
County) plant
TEXACO. INC.
(71) Andrews County
plant
(72) Ector County plant
(73) Franklin County
plant
(74) Hock ley County plant
Capacity3 1978
Mega- Mole percent Thousand production
Location Year MMscf/ grams H2S in sour megagrams thousand
State/county commissioned day daily natural gas annually megagrams Designer Remarks
Mississippi/ 1973
Clarke
Mississippi/ 1979
Kankin
Texas/Cass 1961
Texas/Karnes 1962
Texas/Henderson 1980
Montana 1980
Wyoming/Carbon 1964
Texas/Oimmit 1975
Texas/Andrews 1976
Texas/Ector 1979
Texas/Franklin 1979
Texas/Hockley 1974
15 41 7.15 15 N.A. N.A.
100 1,275 26 to 45 465 N.A. N.A.
(avg 35)
70 178 6.65 65 55.0 N.A.
60 16 0.7 6 4.0 N.A.
N.A. 670 - 244 N.A. N.A.
N.A. 10 3 N.A. N.A.
N.A. 25 9 4.0 Parsons
10 14 3.66 5 2.0 N.A.
20 5.5 0.72 2 N.A. N.A.
N.A. 2.7 - 1 N.A. N.A.
N.A. 41 - 15 N.A. N.A.
N.A. 8.2 - 3 N.A. N.A.
(continued)
-------
Table 9-6. Continued
I
ro
o
Company and
name of plant
(75) Hopkins County plant
(76) Midland County plant
(77) Wood County plant
(78) Eddy County plant
(79) Santa Rosa County
plant
TONKAWA GAS PROCESSING
COMPANY (Texas Oil & Gas
Corporation)
(80) Coyanosa plant
(81) Clarke County -
Harmony plant
TRANS- JEFF CHEMICAL
CORPORATION
(82) Tilden plant
WARREN PETROLEUM COMPANY
(Gulf Oil Corporation)
(83) Monument plant
(84) Little Knife -
Kildeer plant
(85) Coma - Sulfur
Springs plant
(86) Fashing - Kenedy
plant
(87) Sand Hills plant
Location Year
State/county commissioned
Texas/Hopkins
Texas/Midland
Texas/Wood
New Mexico/Eddy
Florida/Santa
Rosa
Texas/Pecos
Mississippi/
Clarke
Texas/McMullen
New Mexico/Lea
North Dakota/
Dunn
Texas/Hopkins
Texas/Karnes
Texas/Crane
1974
1974
1978
1978
1978
1976
1976
1960,
1962
1977
1978
1965
1960
1964
Capacity3
Mega- Mole percent
HMscf/ grams H2S in sour
day daily natural gas
N.A. 5.5
N.A. 2.7
N.A. 11
22.5 2.7 0.31
N.A. 11
75 25 0.87
N.A. 10
i
N.A. 80
N.A. 25
N.A. 71
6 25 10.9
N.A. 45
N.A. 44
Thousand
negagrams
annually
2
1
4
1
4
9
4
29
9
26
9
16
16
1978
production
thousand
negagrans Designer Remarks
N.A.
N.A.
N.A.
N.A.
N.A.
6.0
6.0
23.5
7.0
N.A.
5.0
10.2
9.2
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
N.A.
Dresser
Graff
Dresser
(continued)
-------
Table 9-6. Concluded
UD
ro
Company and
name of plant
(88) Waddell plant
WE STL AND OIL DEVELOP-
MENT COPHORAT10N
(89) Maud Field plant
Location
State/county
Texas/Crane
Texas/Bowie
Year
commissioned
1949
1975
MMscf/
day"
N.A.
N.A.
Capacity
Mega- Mole percent
grans H2S in sour,
daily natural gas
71
5.5
Thousand
aegagrams
annually
26
2
1978
production
thousand
megagrams Designer Remarks
16.5 Graff
2.0 N.A.
aData reflects maximum sulfur intake capacity of Claus units. Some capacities may have been adjusted downward to account for decreased sour natural
gas throughputs. Data from Chemical Economics Handbook - SRI International. December 1979.
Data from I960 Worldwide Directory of Plants in the Hydrocarbon Processing Industry - Gulf Publishing Company, Houston. Texas.
""Derived values.
(1) for 86 facilities, combined daily sulfur intake capacity is 10640.8 megagrams (data on three facilities not available).
(2) For 82 facilities, combined daily sulfur intake capacity is 6725.8 megagrams (four facilities are expected to be in operation in the period
of 1981-1982).
dNot available.
eNot applicable.
Source: Chemical Economics Handbook - Stanford Research Institute (SRI) International. December, 1979.
-------
Table 9-7. OBSERVED FREQUENCY OF SULFUR RECOVERY PLANTS BY H?S PERCENTAGE IN SOUR
NATURAL GAS AND PLANT CAPACITY, 1980 c
Plant capacity
Megagrams
daily
Less than 10
10-49
50-99
100-199
200 - more
Total
H«S percentage in sour natural gas
.5
4
6
To"
1
2
9
IT
2
2
5
T
3
1
3
2
6
456
1
2 1
1
ITT
7 8 9 10
1
1 1
2 1
15
1
1
1
3"
20 or
more
1
2
3
6
Total
9
27
5
5
5
5T
Source: Based on Table 9-6
no
ro
-------
composed of 5 percent H^S, 10 percent C02, and the balance (85 percent)
hydrocarbons and the gas from another well may be composed of 45 percent
H-S, 15 percent C02 and 40 percent hydrocarbons.
Sulfur recovered from onshore produced natural gas was 1,707,000
megagrams in the year 1980 or 4,877 megagrams per day (1 year = 350 days).
This represents 72.5 percent utilization of the industry's capacity of
6,726 megagrams per day in the year 1980. The percentage of capacity
utilization in the industry for the years from 1951 through 1980 and the
number of new facilities added each year and their capacities are presented
in Table 9-8.
The onshore natural gas sulfur recovery industry has added 1 to 9 new
facilities each year since 1971. The addition of new operating facilities
is presented in Figure 9-1 for each year from 1971 through 1982 and for
each 5-year period from 1950 through 1970. Similarly, the total new sulfur
recovery capacity added for each 5-year period from 1950 through 1970 and
for each year from 1971 through 1982 is shown in Figure 9-2.
However, not all capacity additions mean expanded output. The
capacity of a sulfur recovery facility is generally designed to accommodate
the highest potential sulfur input to the facility. This is in order to
insure that the primary operation at the site will never be shut down
because of failure of the sulfur recovery operation.
The size distribution for seven size categories of existing sulfur
recovery facilities is presented in Table 9-9. By 1982, sixty-two
facilities, representing 69.7 percent of total, fall in the smallest two
categories (less than 10 and 10 to 49 Mg/day), and the average capacity of
these facilities is approximately 10.2 megagrams per day. The fifth and
sixth categories (200 to 499 and 500 to 999 Mg/day) include seven
facilities (7.9 percent of total) with an average capacity of approximately
564 megagrams per day. The last category (1,000 and above Mg/day) includes
four facilities (4.5 percent of total) with an average capacity of
approximately 1,016 megagrams per day. Also, Table 9-9 indicates that the
capacity distribution at the end of 1972 is about the same as that at the
9-23
-------
Table 9-8. ONSHORE NATURAL GAS SULFUR RECOVERY FACILITIES
AND SULFUR INTAKE CAPACITY UTILIZATION, 1950-1982
ro
Cumulative
Number of Newly constructed facilities
Year
Before 1950
1951-1955
1956-1960
1961-1965
1966-1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
operating
facilities
4
9
16
30
45
48
53
58
67
70
73
74
78
83
85
87
89
Number
4
5
7
14
15
3
5
5
9
3
3
1
4
5
2
2
2
New capacity
added, Mg/d
254
323
643
923
1,404
22
1,420
115
1,210.4
85.5
40.5
25
95.7
83.7
81
1,765
2,150
Cumulative
capacity,
Mg/d
254
577
1,220
2,143
3,547
3,569
4,989
5,104
6,314.4
6,399.9
6,440.4
6,465.4
6,561.1
6,644.8
6,725.8
8,490.8
10,640.8
Sulfur
recovered,
103 Mg
N.A.b
178.3
(1955)
330
(1960)
522
(1965)
627
(1970)
638
819
1,046
1,219
1,364
1,298
1,426
1,753
1,760
1,707
N.A.
N.A.
Percent capacity
utilization
c
88.3
77.3
69.6
50.5
51.1
46.9
58.6
55.2
60.9
57.6
63.0
76.3
75.7
72.6
—
—
Derived values based on 350 days/year operating schedule.
Not available.
-------
U3
ro
en
16
M
C
14
•o
•o
u
ID
12
10
o>
o
S 8
f 6
to
fc
0
il
I
P
Before 1951-1956- 1961-1966-1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982
1950 1955 1960 1965 1970
Year
Figure 9-1. Sulfur recovery facility additions, 1950-1982.
-------
en
>>
CO
I
o
si
-«J
2
2200
2000
1800
1600
1400
1200
1000
800
600
400
200
0
m
i
Before 1951- 1956- 1961- 1966- 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982
1950 1955 1960 1965 1970
Year
Figure 9-2. Sulfur recovery capacity additions, 1950-1982.
-------
Table 9-9. SULFUR INTAKE CAPACITY DISTRIBUTION OF ONSHORE
NATURAL GAS SULFUR RECOVERY FACILITIES, 1950-1982
ro
Cumulative number of facilities
< than 10,
Year Mg/d
Before 1950
1951-1955
1956-1960
1961-1965
1966-1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
Percent distribution
at the end of 1972
Percent distribution
at the end of 1982
-
-
1
3
7
9
11
12
15
16
17
17
18
19
19
19
19
20.8
21.4
10-49,
Mg/d
2
6
7
15
23
24
25
28
31
33
35
36
38
42
43
43
43
47.2
48.3
Sulfur
50-99,
Mg/d
1
1
4
6
6
6
6
6
7,
8
8
8
9
9
10
10
10
11.3
11.2
intake size
100-199.
Mg/d
1
1
2
3
4
4
5
5
6
6
6
6
6
6
6
6
6
9.4
6.7
range
200-499, 500-999, 1,000 and >,
Mg/d Mg/d Mg/d
-
1
2
3
4
4
4
4
4
4
4
4
4
4
4
4
4
7.5
4.5
-
-
-
-
1
1
1
1
1
2
2
2
2
2
2
3
3
1.9
3.4
-
-
-
-
-
-
1
1
1
1
1
1
1
1
1
1
4
1.9
4.5
Source: Table 9-6.
-------
end of 1982. Therefore, the capacity distribution estimated at the end of
1982 is projected to remain unchanged for the period from 1983 through 1987
and is taken as the basis for further analyses.
Sulfur recovery facilities are not uniformly located across the United
States. Normally, the facility is operated at the field where the sour
natural gas is produced. Forty-nine facilities are located in Texas and 10
facilities in New Mexico. The Mississippi-Alabama-Florida region contains
13 facilities and Wyoming has 8 facilities.
Employment in natural gas sulfur recovery is not labor intensive. The
operations are automated and, therefore, are controlled by instrumentation.
Approximately 10 persons are employed in labor, supervision, maintenance/
repair and administration in a typical onshore natural gas sulfur recovery
facility of 100 megagrams sulfur intake per day. Installation of
additional control equipment to enhance sulfur recovery and thereby reduce
sulfur compounds emissions should not significantly increase the number of
employees per facility.
9.1.1.4 Natural Gas Market. Although the natural gas component of
total domestic energy production has decreased from 40 percent in 1973 to
34 percent in 1980 as indicated in Table 9-10, the natural gas production
industry is expected to continue to supply a significant fraction of total
domestic energy demand. Exploration and production activities for natural
gas are anticipated to continue to increase as a result of phased natural
gas price deregulation and expected price increases. But the U.S. supply
of natural gas from domestic production is price inelastic, according to
Neri (1977) who reports that the 1980 implied price elasticities for
domestic natural gas production are 0.06 and 0.24 for the American Gas
Association (AGA) TERA Model (1973) and the MacAvoy-Pindyck (M-P) models
(1975), respectively. Both models are based on similar theoretical
concepts with respect to exploration and discovery processes but differ in
estimation of the processes. The TERA model relies upon econometric and
engineering elements. The M-P model is econometric in approach. Both deal
with the long-run dynamic behavior of drilling, new discoveries, reserve
additions and production.
9-28
-------
Table 9-10. PRODUCTION OF ENERGY BY TYPE, UNITED STATES (Quadrillion Btu)
I
ro
UD
1973
1974
1975
1976
1977
1978
1979
1980
Coal1
f
14.366
14.468
15.189
15.853
15.829
15.037
17.651
18.877
Crude
oil2
19.493
18.575
17.729
17.262
17.454
18.434
18.104
18.250
NGPL3
2.569
2.471
2.374
2.327
2.327
2.245
2.286
2.263
Natural
gas
(dry)
22.187
21.210
19.640
19.480
19.565
19.485
20.076
19.754
Hydro-
electric
power
2.861
3.177
3.155
2.976
2.333
2.958
2.954
2.913
Nuclear
electric
power
0.910
1.272
1.900
2.111
2.702
2.977
2.748
2.704
Other5
0.046
0.056
0.072
0.081
0.082
0.068
0.089
0.114
Total
energy
produced
62.433
61.229
60.059
60.091
60.293
61.204
63.907
64.876
% NG
of
total
40
39
37
36
36
36
35
34
Totals may not equal sum of components due to independent rounding.
1
Includes bituminous coal, lignite and anthracite.
Includes lease condensate.
4 Natural gas plant liquids.
^ Includes industrial and utility production of hydropower.
Includes geothermal power and electricity produced from wood and waste.
R = Revised data
Source: U.S. Department of Energy, Energy Information Administration calculations.
July 1981.
Monthly Energy Review,
-------
Domestic aggregate retail price elasticities of demand for solid
fuels, natural gas, electricity and petroleum are shown in Table 9-11.
These elasticities represent the change in final demand for each fuel with
respect to a change in the price of all four aggregate fuel types.
Therefore, the diagonal corresponding to direct price elasticity should
have a negative sign. For example, the domestic retail price elasticity
for natural gas is -.426, indicating a rather price inelastic aggregate
retail demand. Electricity has the highest cross price elasticity with
respect to natural gas with a value of .228, indicating that a one percent
increase in the retail natural gas price causes a .228 percent increase in
the aggregate quantity demanded of electricity. All of the cross price
8
elasticities are positive, representing interfuel substitution.
The U.S. is a net importer of natural gas and imports have remained
fairly constant since 1973, ranging from 953 billion cubic feet in 1975 to
1,253 billion cubic feet in 1979. Imports are mainly from Canada, Mexico
and Algeria and were 994 billion cubic feet in 1980. Exports of natural
gas declined from 77 billion cubic feet in 1973 to 55 billion cubic feet in
1980. Exports are primarily to Japan and Mexico.
9.1.1.5 Sulfur Market. Over 90 percent of sulfur produced in the
U.S. is consumed as feedstock in the manufacturing of sulfuric acid, which
in turn is utilized in the fertilizer industry and other industries. De-
mand for sulfur is derived from the demand for sulfuric acid and is likely
to be somewhat inelastic with respect to price but elastic with respect to
industrial production and income in sulfur consuming industries.
Domestic sulfur production from various sources for the period from
1950 through 1980 is shown in Figure 9-3. This figure indicates that
Frasch mines are the main source of domestic sulfur. Over the last 30
years, Frasch production has increased unsteadily upward. Frasch
production reached a peak in 1974 at about 8 million metric tons.
Production has decreased since 1974. The Frasch mining segment of the
sulfur industry is experiencing high energy costs and resource depletion.
The share of total sulfur production that is recovered from petroleum
refineries, natural gas sulfur recovery and smelter gases has increased
from 2 percent of the total in 1950 to over 38 percent in 1978. These
9-30
-------
Table 9-11. AGGREGATE RETAIL PRICE ELASTICITIES OF DEMAND, U.S.
(Estimate for 1985)
With respect to
Solid fuels
Natural gas
Electricity
Petroleum
Source: The Global
Solid
fuels
-.215
.005
.011
.002
2000 Report
Price
Natura
gas
.030
-.426
.052
.013
to the
elasticity of demand
1
Electricity
.131
.228
-.376
.077
President, (Volume III:
Petroleum
.031
.062
.111
-.263
Documentation), A report prepared by the Council on Environmental
Quality and the Department of State. April 1981. p. 301.
9-31
-------
VI
c
u
5
I
CO
ro
c
o
o
-o
o
a.
8
7
6
5
4
3
2
1
0
1950
Recovered/
1955
1960
1965
Year
1970
1975
1980
Figure 9-3. U.S. domestic sulfur production from various sources for the period 1950-1980.'
-------
trends are shown in Figure 9-4 and Table 9-12. Table 9-12 also shows that
in 1978 natural gas sulfur recovery ranked as the fourth most important
source of sulfur production following Frasch mines, recovery from petroleum
g
refineries and elemental imports.
Recovered sulfur is expected to show continued steady growth because
of environmental considerations. Too, sulfur recovery that is required by
environmental regulations is effectively nondiscretionary, usually being
the by-product of another industry. Consequently, the recovered elemental
sulfur segment of total sulfur supply tends to be highly price inelastic.
Mined sulfur and imports are likely to be more price elastic than recovered
sulfur.
Exports of sulfur declined to 1.6 million megagrams in 1982, while
imports remained steady at 2.5 million megagrams. Annual sulfuric acid
exports are small and less than 100,000 megagrams. Sulfuric acid imports
are also small and under 500,000 megagrams per year. Exports are primarily
to Canada and Mexico. Imports are mainly from Canada.
9.1.2 Onshore Natural Gas Sulfur Recovery Industry—Growth and Projections
This section discusses the historical production of natural gas, the
price history of natural gas, the production history of liquid sulfur
recovered from onshore natural gas production operations, and the price
history of liquid sulfur. Natural gas production is projected for the
years 1985, 1990 and 2000 and distributed in the categories of onshore,
offshore, and discoveries from existing fields and new fields. Also, this
section presents the new sulfur recovery capacity added each year for the
period from 1950 through 1982 and the projected number, sizes and
capacities of new facilities that are projected to be constructed and in
operation during the period from 1983 through 1987.
9.1.2.1 Historical Data. Marketed production of natural gas
increased from 5.42 trillion cubic feet in 1949 to a peak of 22.65 trillion
cubic feet in 1973. Increases in marketed production from 1949 through
1973 averaged 6.0 percent annually. In 1974 and 1975, marketed production
decreased 4.6 percent and 6.9 percent, respectively. After 1976, marketed
production declined slightly to 19.7 trillion cubic feet in 1979.
9-33
-------
UD
I
CO
o
•r"
•M
U
1
O.
•M
c
01
o
OJ
o.
3
O-
100
90
80
70
60
50
40
30
20
10
Frasch
Recovered
Other Forms
0 L_i—i i i I
i i i i L
1950
1955
1960
1965
Year
1970
1975
1980
Figure 9-4. Trends in the production of sulfur in the United States.9
-------
Table 9-12. DOMESTIC SULFUR SUPPLY - 1978 STATISTICS
Source Percent of Total
(1)
(2)
(3)
(4)
(5)
(6)
Frasch mining
Recovered from petroleum refineries
Recovered from natural gas
Smelter gases
Other3
Elemental imports
41.4
16.9
12.9
8.1
4.7
16.0
Includes pyrites (imported and domestic), stocks, and various sulfur-
containing compounds produced directly without any elemental sulfur
requirements. Not included are imports of such sulfur-containing
materials as hUSO, and liquid SOg.
Source: Chemical Handbook - Stanford Research Institute (SRI) International,
December, 1979.
9-35
-------
Total gross withdrawals of natural gas from both gas wells and oil
V
wells generally follow the same trend as marketed production. However, the
volume of natural gas withdrawn from oil wells has remained relatively
constant at about three to five trillion cubic feet per year from 1949 to
the present. Table 9-13 presents total natural gas production distributed
between onshore and offshore production for the years 1949 through 1979.
Onshore production declined from 99.1 percent of the total in 1954 to 72.4
percent of the total in 1979. Figure 9-5 shows natural gas gross
withdrawals and marketed production from gas wells and oil wells from 1949
1?
through 1979. The difference between gross withdrawals and marketed
production represents quantities from gas wells and oil wells that were
either vented, flared or used for reservoir repressuring. In 1978, there
were nearly 157,000 producing gas wells in the United States. Although
most natural gas is produced from natural gas wells, about 18 percent is
produced from crude oil wells. Figure 9-6 portrays onshore and offshore
natural gas production for the period from 1954 through 1979.
The nominal price of natural gas remained reasonably steady for the
long period from 1955 through 1970. Since 1973, the price has increased
steadily in real terms. Figure 9-7 shows selected natural gas prices for
2
three categories for the period from 1955 through 1979. In 1979, the
price of natural gas at the wellhead was $1.13 per million Btu, $1.85 per
million Btu at the city gate and $2.50 per million Btu delivered to the
ultimate customer. Deregulation of the price of natural gas before the end
of 1985 will boost the revenues and profitability margins for the industry.
This will contribute to growth in capital availability potentially to be
used for more drilling, deeper drilling and increased exploration and
production of tight gas formations.
Since the Oil Embargo in 1973, the financial condition of the onshore
crude oil and natural gas production industry has been improving steadily
in both revenues and net profits. Composite financial data shown in
Table 9-14 reveal increased revenues from $15,292 million in 1976 to
$38,000 million in 1980. During the same period, net profits increased
from $1,155 million to $1,925 million. Composite net profit margins as a
percent of sales declined from 7.6 percent in 1976 to 5.1 percent in 1980.
9-36
-------
Table 9-13. NATURAL GAS GROSS WITHDRAWALS AND MARKETED ONSHORE AND OFFSHORE PRODUCTION, 1949-1979
Production in Trillion Cubic Feet
Year
1949
1950
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979b
From
Gas Wells
4.99
5.60
5.48
6.84
7.10
7.47
7.84
8.31
8.72
9.15
10.10
10.85
11.20
11.70
12.61
13.11
13.52
13.89
15.35
16.54
17.49
18.59
18.93
19.04
19.37
18.67
17.38
17.19
17.42
17.39
17.17
From
Oil Wells
2.56
2.38
3.21
3.43
3.55
3.52
3.88
4.07
4.19
3.99
4.13
4.23
4.27
4.34
4.37
4.43
4.44
5.14
4.91
4.79
5.19
5.19
5.16
4.97
4.70
4.18
3.72
3.75
3.68
3.91
3.75
Gross
Withdrawals
7.55
8.48
9.69
10.27
10.65
10.98
11.72
12.37
12.91
13.15
14.23
15.09
15.46
16.04
16.97
17.54
17.96
19.03
20.25
21.33
22.68
23.79
24.09
24.02
24.07
22.85
21.10
20.94
21.10
21.31
20.92
Marketed3
Production
5.42
6.28
7.46
8.01
8.40
8.74 ,
9.41
10.08
10.68
11.03
12.05
12.77
13.25
13.88
14.75
15.55
16.04
17.21
18.17
19.32
20.70
21.92
22.49
22.53
22.65
21.60
20.11
19.95
20.03
19.97
19.67
Onshore
Production
NA
NA
NA
NA
NA
3.66
9.28
9.94
10.51
10.77
11.70
12.33
12.77
13.24
13.99
14.70
15.10
15.84
16.33
17.00
17.86
18.70
18.74
18.77
18.67
17.37
15.85
15.65
15.49
14.87
14.25
Offshore
Production
NA
NA
NA
NA
NA
0.08
0.13
0.14
0.17
0.26
0.35
0.44
0-.48
0.64
0.76
0.85
0.94
1.37
1.84
2.32
2.84
3.22
3.75
3.76
3.98
4.23
4.26
4.30
4.54
5.10
5.42
Percentage .
Onshore
NA .
NA
NA
NA
NA
99.1
98.6
98.6
98.4
97.6
97.1
96.6
96.4
95.4
94.8
94.5
94.1
92.0
89.9
88.0
86.3
85.3
83.2
83.3
82.4
80.4
78.8
78.4
77.3
74.5
72.4
Offshore
NA
NA
NA
NA
NA
0.9
1.4
1.4
1.6
2.4
2.9
3.4
3.6
4.6
5.2
5.5
5.9
8.0
10.1
12.0
13.7
14.7
16.8
16.7
17.6
19.6
21.2
21.6
22.7
25.5
27.6
NA = Not Available.
Marketed production is derived. It is gross withdrawals from producing reservoirs less gas used for reservoir
representing and quantities vented and flared.
Estimated, based on reported data through November.
c Data from U.S. Department of the Interior, Geological Survey - Conservation Division, Outer Continental Shelf
Statistics.
Note: Sum of components may not equal total due to independent rounding. Beginning with 1965 data, all volumes
are shown on a pressure base of 14.73 psia at 60°F. For prior years, the pressure base is 14.65 psia at
60° F.
Sources:
• 1949 through 1975, U.S. Department of the Interior, Bureau of Mines, Minerals Yearbook, "Natural Gas"
chapter.
• 1976 through 1978, U.S. Department of Energy, Energy Information Administration, Natural Gas Production
and Consumption, annual.
9-37
-------
1IIIIIIIIIIII1 L ' »IIIIT~
' ' ' x*^,'1'' i-'."'-' '"*V '
s y^jV/.'j-'^V'VicSk
Gross Withdrawals rfte-l&^*&\
I ^ >?•'.-• «^»»i-/»--'iv»'<77^(%\
is >» yC'^'i^-vj-^V.'-'.*'-.-;-• '-f-'vA
J»8ili^Si
20
1 | I I I
T) From Gas Well
From Oil Well
20
IT)
I
CO
CO
•I
4)
O
15
15
r: io|
10
iliililiiliMlii
1949
1954
1959
1964
1969
1974
1979
Figure 9-5. Natural gas gross withdrawals and marketed production.12
-------
u
2
a
o
24
22
20
18
16
14
12
10
8
6
'4
2
Total Marketed
Offshore
0
1954
1959 1964 1969
Year
1974
1979
Figure 9-6.
Onshore and offshore marketed natural
gas production.2
9-39
-------
2.50
CD
I
CO
c
o
t
a
1955
1960
1965
1970
1975 78 79
Year
Figure 9-7. Selected natural gas prices — three categories for the period 1955-1979.
-------
Table 9-14. FINANCIAL DATA FOR THE NATURAL GAS INDUSTRY 1976-1981 and
1983-1985 ESTIMATES (Current dollars)
I
-p»
Item
Revenues ($mill)
Net Profit ($mill)
Income Tax Rate
Net Profit Margin
Long-term Debt Ratio
Common Equity Ratio
Total Capital ($mill)
Net Plant ($mill)
% Earned Total Capital
% Earned Net Worth
% Earned Comm. Equity
% Retained to Comm. Equity
% All Dividends to Net Profit
Average Annual P/E Ratio
Average Annual Dividend Yield
Fixed Charge Coverage
1976
15,292
1,155
44.4%
7.6%
54.3%
41.0%
19,538
18,356
8.0%
12.9%
13.5%
7.5%
48%
7.1
6.3%
278%
1977
19,430
1,356
43.1%
7.0%
50.8%
44.4%
20,207
19,865
8.8%
13.6%
14.2%
8.0%
47%
7.6
5.8%
281%
1978
22,463
1,399
43.9%
6.2%
48.5%
46.8%
20,611
21,423
8.9%
13.2%
13.7%
7.2%
50%
7.1
6.6%
284%
1979
30,357
1,702
43.2%
5.6%
48.0%
47 . 1%
22,236
23,453
9.8%
14.7%
15.4%
8.9%
45%
6.8
6.3%
287%
1980
38,000
1,925
44.0%
5.1%
48.5%
48.0%
23,750
26,000
10.5%
15.5%
16.0%
9.0%
45%
NA
NA
290%
1981
46,000
2,200
45.0%
4.8%
47.0%
50.0%
26,000
27,000
10.5%
15.5%
16.0%
9.0%
45%
NA
NA
295%
83-85E
70,000
3,200
47.0%
4.6%
45.5%
53.0%
35,500
33,000
11.5%
16.5%
17.0%
9.5%
45%
8.0
6.0%
310%
E = Estimates
NA = Not available
Source: A. Bernhard & Company. "Natural Gas Industry." Value Line Investment Survey, July 18, 1980.
-------
This fact indicates that production costs have risen at a faster pace than
prices. Also, total capital has grown at a slower pace than revenues and
profits. Consequently, return on total assets and return on equity have
improved. According to Value Line Investment Survey, the composite
industry will continue to have a healthy financial future into the 1980's.
It is projected in 1983-85 that the industry will have a composite net
profit margin of 4.6 percent on annual revenues of approximately $70
billion in current dollars. The long term debt ratio is projected to be
45.5 percent. Total capital is projected to increase to $35,500 million in
current dollars or 51 percent of revenues in 1983-85.
Table 9-15 shows recovered sulfur production from natural gas plants
g
and from petroleum refinery operations for the years 1960 through 1980.
For the period 1971-1980, recovered sulfur from natural gas plants accounts
for 39 to 46 percent of the total recovered sulfur production and sulfur
recovered from petroleum refinery operations accounts for 54 to 61 percent.
Separate data for natural gas plants and petroleum refineries for the years
1960 through 1970 were not available. Therefore, the production figures
for these years are derived values based upon the average of 43 percent of
recovered sulfur from natural gas plants and 57 percent from petroleum
refinery operations, which prevails in the period from 1971 through 1980.
During the period from 1973 to 1979 when natural gas production
remained relatively constant, the production of sulfur recovered from
natural gas increased 68 percent from 1,063,000 megagrams in 1973 to
1,760,000 megagrams in 1979. A contributing factor to this growth was that
sulfur recovery from natural gas was becoming economically attractive and
will continue to capture increased portions of total sulfur production.
Sulfur prices during the last 27 years are shown in Table 9-16 in
terms of actual and constant 1980 dollars per ton. Approximately 90
percent of all sulfur shipments are reflected in this table. Prices are
based on the average reported rates for elemental sulfur (Frasch and
recovered) f.o.b. mine or plant.
An ample supply of Frasch stocks resulted in a fairly stable sulfur
market prior to 1964. Market prices rose in 1967 and 1968 due to the rapid
9-42
-------
Table 9-15. RECOVERED ELEMENTAL SULFUR PRODUCED IN THE UNITED STATES, 1960-1980
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
Total
(103 Mg)
779
872
914
962
1,037
1,234
1,259
1,288
1,375
1,437
1,480
1,620
1,981
2,455
2,674
3,017
3,188
3,624
4,062
4,070
3,930
From natural
gas plants
(103 Mg)
335a
375
393
413
446
530
541
554
591
618
637
648
832
1,063
1,238
1,364
1,298
1,426
1,753
1,760
1,707
Percentage of the
total from natural
gas plants
43.0
43.0
43.0
43.0
43.0
43.0
43.0
43.0
43.0
43.0
43.0
40.0
42.0
43.3
46.3
45.2
40.7
39.3
43.2
43.2
43.4
From petroleum
refineries
(103 Mg)
444b
497
521
549
591
704
718
734
784
819
843
972
1,149
1,392
1,436
1,653
1,890
2,198
2,309
2,310
2,223
Percentage of the
total from petroleum
refineries
57.0
57.0
57.0
57.0
57.0
57.0
57.0
57.0
57.0
57.0
57.0
60.0
58.0
56.7
53.7
54.8
59.3
60.7
56.8
56.8
56.6
Figures for the years 1960 through 1970 are derived values based on the assumption that sulfur-
recovered from natural gas is 43 percent of the total recovered sulfur production.
Figures for the years 1960 through 1970 are derived values based on the assumption that sulfur
recovered from petroleum refining operations is 57 percent of the total recovered sulfur
production
Source: Bureau of Mines Minerals Yearbook, 1960-1980 reprints
9-43
-------
Table 9-16. TIME-PRICE RELATIONSHIP FOR SULFUR, 1955-1981 a/
Year
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
Average annual
Actual
prices
27.50
26.07
24.02
23.44
23.09
22.76
22.75
21.41
19.67
19.87
22.12
25.36
32.12
39.49
26.62
22.77
17.19
16.76
17.56
28.42
44.91
45.72
44.38
45.17
55.75
88.93
111.00 P/
price, dollars per metric ton
Based on
constant 1980 dollars
80.21
73.68
65.65
62.98
60.61
58.79
58.23
53.81
48.70
48.45
52.79
58.63
72.09
84.90
54.43
44.18
31.77
29.74
29.48
43.88
63.47
61.41
56.32
53.42
60.78
88.93
NA
NA - Not available
£/ Preliminary
a/ Frasch and recovered sulfur, f.o.b. mine/plant
Source: Bureau of Mines, Sulfur Mineral Commodity Profile, 1979
9-44
-------
growth in the fertilizer industry and a shortage of sulfur supply. In late
1968, a serious oversupply developed which le'd to a general collapse of the
sulfur market through 1973.
There have been several factors contributing to dramatic sulfur price
increases since 1974. Among these are: the rapid expansion of the
fertilizer industry and its ability to pass on sulfur costs to farmers,
logistic problems restricting delivery from other sources, and higher
production costs as well as a continued dependency upon Frasch sulfur.
Table 9-17 presents a history of published prices for liquid sulfur at
Tampa terminals in Florida for the period from 1969 through 1979. Tampa is
one of several major Gulf ports where sulfur is traded in large volumes and
market trends can be observed. Actual prices received by producers would
depend on local sulfur markets or transportation costs to a suitable
market, such as Tampa. The price has increased over 200"percent from
$30.51 per metric ton in September 1973 to $93.99 per metric ton in
November 1979. Historically, the sulfur price has been quite unstable.
The March 1981 price was $140 per long ton f.o.b. Tampa. '
9.1.2.2 Five-Year Projections. In this subsection, projections for
the number of new facilities constructed in the years 1983 through 1987 are
developed. The size distribution of new facilities is developed based upon
the industry's historical trend. Information on the projection of natural
gas prices with deregulation are discussed.
Production of natural gas by conventional techniques has exceeded the
rate of reserve additions in recent years. Consequently, conventional
reserves and conventional production are expected to continue declining.
Annual production of conventional natural gas is expected to decline
roughly 1.5 to 2.0 trillion cubic feet every five years through 1995. The
production of associated and dissolved gas in oil is expected to decline
less rapidly than the production of nonassociated gas, due to higher price
incentives for crude oil. Total domestic natural gas production is
expected to trend downward.
Table 9-18 presents projected lower 48 states conventional natural gas
production for the period from 1980 through 2000. In 1985, the
9-45
-------
Table 9-17. PUBLISHED PRICE FOR LIQUID SULFUR
AT TAMPA TERMINALS
Date
December 12, 1969
February 1, 1970
November 1, 1970
March 10, 1971
July 7, 1973
September 12, 1973
May 1, 1974
June 6, 1974
July 22, 1974
January 1, 1975
April 24, 1975
December 1, 1975
May 1, 1978
February 9, 1979
June 10, 1979
September 1979
November 1979
March 1981
Source: Chemical Economi
(SRI), December
Pri ce
(current dollars)
Dollars per Dollars per
long ton metric ton
32.00
30.00
27.00
25.00
28.00
31.00
36. 50
42.00
50.00
57.00
61.00
65.00
68.50
73.25
78.25
85.75
95.50
140.00
es Handbook -
1979 and Chemi
31.49
29.53
26.57
24.60
27.56
30.51
35.92
41.34
49.21
56.10
60.04
63.97
67.42
72.09
77.01
84.40
93.99
137.79
Stanford Research Institute
cal and Engineering News
Vol. 59 March 23, 1981, p. 25.
9-46
-------
Table 9-18. PROJECTED LOWER-48 STATES
CONVENTIONAL NATURAL GAS PRODUCTION, 1980-2000
Production, trillion standard cubic feet
Gas source 1980 1985 1990 1995 2000
Onshore
Old inter3
Old intraa
Old direct sale
New
Offshore
Old inter3 'b
New inter
Total
Old inter
Old intra
Old direct sale
New
TOTALd
4.9
3.6
4.0
1.5
5.6
0.1
10.5
3.6
4.0
1.6
19.7
3.6
2.4
2.6
3.6
4.1
3.4
7.7
2.4
2.6
7.0
19.7
2.0
1.3
1.5
4.9
1.4
6.6
3.4
1.3
1.5
11.5
17.7
1.1
0.7
0.8
4.8
0.7
6.5
1.5
0.7
0.8
11.3
14.6
0.7
0.4
0.5
3.8
nil
5.4
0.7
0.4
0.5
9.2
10.8
Includes gas used as compressor fuel and net storage injections.
Including new additions from pre-1977 leases.
cPost-1976 leases only.
Totals may not add due to independent rounding.
Source: American Gas Association, Gas Supply and Statistics, Total Energy
Resource Analysis Model (TERA) 80-1, Appendix A. Figure A-2, p.21,
9-47
-------
production is projected to be 19.7 trillion cubic feet, decreasing to 18.5
and 17.7 trillion cubic feet in 1987 and 1990, respectively.
Natural gas supply projections are conducted by various oil and gas
companies as well as government and independent study groups. Table 9-19
presents a comparison of 1990 projection forecasts presented by the
Department of Energy (DOE), the American Gas Association (AGA), Exxon,
Tenneco and other private study groups. AGA's forecast of 16.3
quadrillion Btu per year is 2.8 percent lower than DOE's forecast of 17.8
quadrillion Btu per year, and Exxon's forecast of 14.9 quadrillion Btu is
16.3 percent lower than DOE's forecast. The AGA's forecast of projected
lower 48 states conventional natural gas production was chosen for the
present analyses, because the AGA's forecast provides, as shown in Table
9-18, a detailed breakdown of the production including newly discovered
onshore and offshore categories among others, and the AGA's forecast
compares well with the Exxon's, Tenneco's and DOE's as indicated in Table
9-19. Projections for the amount of sulfur that will be recovered from
natural gas are not available. However, it is expected that with the
increased new onshore discoveries of natural gas and increased deep well
drilling activities, recovery of elemental sulfur will increase. Full
sulfur recovery capacity utilization is expected with the consideration of
limiting factors, such as the sour gas supply rate.
A projection of the number of new onshore natural gas sulfur recovery
facilities was based upon:
(1) historical data on the sulfur intake capacity distribution of the
existing 89 onshore natural gas sulfur recovery facilities,
(2) the projected new discovery of onshore natural gas for the period
1983-1987,
(3) the projected sulfur composition of the newly discovered gas, and
(4) the distribution among various plant sizes of the projected
sulfur production from newly discovered gas and, therefore, the
number and size distribution of new facilities.
The following factors were also considered in making these
projections:
9-48
-------
Table 9-19. PROJECTIONS OF NATURAL GAS SUPPLY: COMPARISON OF 1990 FORECASTS (Quadrillion Btu)
UD
1979 Projections for 1990
Units
1978
Actual
DOE/
EIA a/
AGAb
DPPC
Paced
e f
Exxon Tenneco
Domestic Production
Conventional
North Alaska
Synthetic Gas
Subtotal
19
0
19
.5
9
.2
.7
17.8 15
0.9
0.3
19.0 19
.3-17
1.6
1.1
.9-21
.3
.9
16.9
0.4
0.6
18.0
16
1
0
18
.1
.0
.8
.0
14.9
g
0.6-1.0
15.5-15.9
14.8
1.0
1.5
17.3
Net Imports
Pipeline
Liquefied Natural
Subtotal
Total Supply
a
b
c
d
e
0
Gas
0
20
DOE/EIA 1979 Annual Report to
American Gas Association, The
.9
h
.9
.6
0
0.8
0.8
19.8 24
Congress, middle range
Future
Data Resources, Inc., Energy Review,
The Pace Company
1979.
Exxon Company, U.
2.1
2.0
4.2
.1-26
.1
2.0
1.0
3.1
21.0
1
0
2
20
.4
.8
.2
.2
1.8
0.8
2.7
18.2-18.6
2.0
3.1
5.1
22.4
forecast.
for Gas Energy in the
Winter 1980.
Consultants and Engineers, Inc., The
S.A. , Energy
Outlook
Pace
1980-2101, December
United
Energy
1979.
States, June
and
1979.
Petrochemical
Outlook to 2000,
October
Tenneco Oil Company, Energy 1979-2000, June 1979.
9 Included in conventional production.
h Less than 0.5 quadrillion Btu.
Note: Non-EIA projections converted from trillion cubic feet with 1,020 Btu per cubic foot. Numbers may not
add to totals because of rounding.
-------
(1) The combined sulfur intake capacity of the 89 existing sulfur
recovery facilities operated by 31 companies is approximately
10,640 megagrams per day (Tables,9-5, 9-6).
(2) Historically, the percent capacity utilization of these
facilities has ranged from as high as 88 percent to as low as 47
percent (Table 9-8).
(3) Recovered sulfur produced in the U.S. has consistently increased
from 335,000 megagrams in 1960 to 1,707,000 megagrams in 1980
(Table 9-15).
(4) The price of liquid sulfur has increased from $32 per megagram in
December 1969 to $94 per megagram in November 1979 (Table 9-17).
9.1.2.2.1 Sulfur Intake Capacity Distribution. Table 9-9 indicates
that the percent distribution of sulfur intake capacity of all existing
facilities at the end of 1972 is the same as percent distribution at the
end of 1982. The Oil and Gas Journal lists recent worldwide construction
of 22 sulfur recovery units with a size distribution of 63 percent at 0-34
Mg/D, 23 percent at 35-74 Mg/D and 14 percent at greater than 500 Mg/D.
The Oil and Gas Journal's distribution compares well with the 1972 and 1982
distributions among the existing 89 facilities. Therefore, the 1982
distribution was considered the basis for the distribution of the projected
sulfur in newly discovered gas among various plant sizes.
9.1.2.2.2 Projected New Onshore Natural Gas Production. Projected
new onshore natural gas production for each individual year 1983-1987 was
derived from the American Gas Association's (AGA) data (Table 9-18). This
derivation is presented herewith in a tabular form (Table 9-20). An
average of 6.2 percent per year depletion was assumed for new discoveries
(from National Petroleum Council's U.S. Energy Outlook - Oil and Gas
Availability, 1974). The projected new production discovered in each year
is as indicated in Table 9-21.
9.1.2.2.3 Projected Sulfur in New Discovered Onshore Natural Gas.
Sulfur (as H«S) in sour natural gas that is further processed for sulfur
recovery has increased at a consistent rate. Table 9-22 indicates that the
sulfur content increased from 1.32 mole percent (average) in 1960 to 5.92
mole percent (average) in 1980. The sulfur content values in Table 9-21
9-50
-------
Table 9-20. DERIVATION OF NEWLY DISCOVERED ONSHORE CONVENTIONAL
NATURAL GAS PRODUCTION FOR A SPECIFIED YEAR, 1977-1987
Cumulative
Production
(tscf) New onshore production, trillion standard cubic feet (tscf)
Year 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987
1977 0.27 Q.27
1978 0.68 0.25 0.43
1979 1.09 0.238 0.403 0.449
1980 1.50 0.223 0.378 0.421 0.478
1981 1.92 0.209 0.355 0.395 0.448 0.513
1982 2.34 0.196 0.333 0.371 0.421 0.481- 0.538
1983 2.76 0.184 0.312 0.348 0.3,95 0.451 0.505 0.565
1984 3.18 0.172 0.293 0.326 0.370 0.423 0.473 0.530 0.593
1985 3.60 0.162 0.275 0.306 0.347 0.397 0.444 0.497 0.556 0.616
1986 3.86 0.152 0.258 0.287 0.326 0.372 0.416 0.466 0.522 0.578 0.483
1987 4.12 0.142 0.242 0.269 0.305 0.349 0.391 0.437 0.489 0.542 0.453 0.501
Note: (1) "Newly discovered" means that produced after April 20, 1977.
(2) Column 2 indicates cumulative new discovered production from April 20, 1977 onwards.
For example, the 1980's cumulative new production of 1.5 tscf is the production oeyond
April 20, 1977 through 1980.
(3) Newly discovered production for an individual year is indicated by the last number in
the row for a specified year. For example, 1980's individual newly discovered production
(produced in 1980 only) is 0.478 tscf. A new discovery depletion rate of 6 percent is
applied to derive individual newly discovered production for a specified year. For example,
the newly discovered production in 1978 only is equal to 1978's cumulative production of
0.68 tscf minus 94 percent of 1977's individual production of 0.27 tscf, that is 0.68 tscf
minus 0.25 tscf. This gives 0.43 tscf as individual new production for 1978.
9-51
-------
Table 9-21. PROJECTED NEW SULFUR RECOVERY CAPACITIES FOR THE PERIOD OF 1983-1987
I
en
Onshore new discovery
Year
1983
1984
1985
1986
1987
Total in
the period
of 1983-1987
Onshore
discovery in
the specified
year
106 ft3
565 ,000
593,000
616,000
483 ,000
501,000
2,758,000
Processed for
sweetening of
sour natural gasa,
106 ft3
107,350
112,670 '
117,040
91,770
95,190
524,020
Processed for.
sulfur recovery ,
106 ft3
80,510
84,500
87,780
68,830
71,390
393,010
H2S in sour
natural gas,
mole percent
7.25
7.75
8.25
8.75
9.25
-
New sulfur recovery
capacity added in
the specified year,
103 Mg/y
223
251
277
230
253
1,234
New sulfur recovery
capacity added in
the specified year ,
Mg/d
638
716
791
658
722
3,525
Derived values based upon 19 percent of the onshore being sour and the remaining 81 percent being sweet.
Derived values based upon 75 percent of the sour onshore new discovery for the projected period 1983-1987 is processed for sulfur
recovery.
C350 days/year operating schedule.
-------
Table-9-22 SULFUR RECOVERED PER UNIT VOLUME OF PROCESSED SOUR NATURAL GAS,
1954-1980
Onshore natural
gas production,
Year 1012 ft3
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
8.66
9.28
9.94
10.51
10.77
11.70
12.33
12.77
13.24
13.99
14.70
15.10
15.84
16.33
17.00
17.86
18.70
18.74
18.77
Onshore production
processed for Sulfur recovery
sulfur recovery3, from natural gas,
1012ft3 103 Mg
.548
.587
.629
.665
.682
.741
.780
.808
.838
.886
.931
.956
1.003
1.034
1.076
1.131
1.184
1.186
1.188
N.A.C
N.A.
N.A.
N.A.
N.A.
N.A.
335
375
393
413
446
530
541
554
591
618
637
648
832
Sulfur recovered ,
kg/103 ft3 sour
natural gas
_d
-
-
-
-
—
0.431
0.463
0.467
0.467
0.481
0.553
0.539
0.535
0.549
0.549
0.539
0.544
0.699
Sulfur (as H2S)b in
sour natural gas
processed for sulfur
recovery, mole percent
-
—
—
-
—
—
1.32
1.43
1.44
1.43
1.47
1.71
1.66
1.65
1.69
1.68
1.66
1.68
2.15
(continued)
-------
Table 9-22. Continued
VO
I
Onshore natural
gas production,
Year 1012 ft3
1973
1974
1975
1976
1977
1978
1979
1980
18.67
17.37
15.85
15.65
15.49
14.87
14.25
14.00
Onshore production
processed for
sulfur recovery ,
1012ft3
1.182
1.100
1.003
.991
.991
.941
.902
.886
Sulfur recovery
from natural gas,
103 Mg
1,063
1,238
1,364
1,298
1,426
1,753
1,760
1,707
i
Sulfur recovered ,
kg/103 ft3 sour
natural gas
0.898
1. 125
1.361
1.311
1.456
1.864
1.950
1.928
Sulfur (as H2S)b in
sour natural gas
processed for sulfur
recovery, mole percent
2.77
3.46
4.18
4.03
4.47
5.73
6.00
5.92
Based upon 19 percent of the total onshore production for the period 1960-1980 being sour and the remaining
81 percent being sweet. Thirty-three percent of the sour gas for the period 1960-1980 is further processed for
sulfur recovery.
Derived values based upon average sulfur recovery efficiency of 85 percent.
cData on recovered sulfur from the onshore natural gas produced prior to 1960 is not available.
Not applicable.
-------
were derived based on the following: (1) 19 percent of total onshore
production was sour and, therefore, was sweetened and (2) one-third of the
11 17 18
sour gas was further processed for sulfur recovery. ' This represents
an average of 6.3 percent of the total onshore production that was
19 20
processed for sulfur recovery in the 1960-1980 period. ' These
sulfur content values in sour natural gas were derived because no reliable,
documented data or information is currently available. For projected
sulfur in the new gas, it is assumed that 19 percent of the total onshore
production will be sour and three-fourths of the sour gas will be further
99 ?? ?4
processed for sulfur recovery. ">">^ That is, an average of 14.25
percent of the total new onshore discovery will be processed for sulfur
recovery. Therefore, the remainder (4.75 percent) will be incinerated
without sulfur recovery. This view is supported by two facts: (1)
increased deep well drilling activities will be enhanced by price
deregulation; and (2) the increasing price of recovered sulfur compounded
with the decreased supply from Frasch mines. With expanded deep well
drilling, more sour gas is likely to be discovered and the sulfur content
of it is likely to be increased. Also, with the increased price of
recovered sulfur, it becomes more feasible to recover sulfur. Therefore,
in the absence of any reliable information or data, the sulfur content (as
hLS) in new onshore discoveries was estimated through extrapolation of the
derived values on sulfur content in sour natural gas produced onshore from
1960 through 1980. The sulfur content values for the period of 1983
through 1987 and the projected new sulfur recovery capacity are indicated
in Table 9-21. In 1987 the average H,,S percentage in new sour natural gas
discoveries is projected to be 9.25 percent.
9.1.2.2.4 Distribution of New Sulfur in Various Plant Sizes. The
projected sulfur in the new onshore discovery for the period 1983-1987 was
distributed among various plant sizes according to the 1982 plant size
distribution. It is assumed that all new discoveries will require
construction and operation of new sulfur recovery facilities. This
resulted in 31 facilities processing gas for sulfur recovery during the
period 1983-1987. The sulfur (1.65 mole percent) in the portion of the new
gas that is sweetened and incinerated without sulfur recovery was also
divided among the remaining facilities of average size 5.1 megagrams per
9-55
-------
day. Table 9-6 indicates that two facilities between 5 megagrams per day
and 10 megagrams per day sulfur intake have an average of 1.65 mole percent
HLS in their sour natural gas input. This resulted in 47 facilities that
sweeten the sour gas but do not recover the sulfur. Projected new sulfur
recovery facilities are presented in Table 9-23.
The projected volumes of new onshore natural gas in 1980 and 1987 by
category relevant to this analysis are summarized in Table 9-24. In 1987,
domestic production is projected to be 18.5 trillion cubic feet. Including
imports and total domestic natural gas, total natural gas supply is
expected to be approximately 20 trillion cubic feet. New onshore natural
gas production is projected to be 2.8 trillion cubic feet. Nineteen
percent of this is assumed to be sour, that is .52 trillion cubic feet will
require sweetening at new facilities. The total volume of new onshore
natural gas associated with sulfur recovery in new facilities is projected
to be three-fourths of .52 trillion cubic feet or .39 trillion cubic feet.
This will represent approximately 2 percent of the total estimated domestic
natural gas supply of 20 trillion cubic feet in 1987. Thus, in 1987, the
considered S02 NSPS regulation will apply to just 2.0 percent of the total
domestic natural gas supply. This figure places an upper bound on any
supply quantity impact of these regulations in 1987. Further, considering
the price elasticity of domestic retail natural gas demand (-.426), the
maximum potential retail price impact is less than a 5 percent price
increase. These impacts are further clarified in the next section of this
chapter.
By 1985, almost all categories of natural gas production will be
deregulated. Very little new gas will be subject to controls; most old
intrastate gas will be decontrolled and the quantity of old interstate gas
that remains controlled will decline rapidly over time. Natural gas prices
are projected by the U.S. Department of Energy to increase because of the
Natural Gas Policy Act and phased deregulation of prices during the period
from 1983 through 1987. Deregulated prices are expected to boost
exploration and production activities. The history and projections for
21
natural gas prices are summarized in Table 9-25. In 1987, the average
wellhead price of new natural gas, including intrastate and interstate, is
interpolated to be $4.80 per Mcf in 1980 dollars.
9-56
-------
Table 9-23. PROJECTED ADDED NEW SULFUR RECOVERY FACILITIES
AND THEIR SULFUR INTAKE SIZE DISTRIBUTION,
1983-1987
Year
1983
1984
1985
1986
1987
Number
Percent of
total number
(Avg. size 10),
Mg/d
3
5
5
3
5
21
67.7
(Avg. size 102),
Mg/d
1
2
1
1
1
6
19.4
(Avg. size 564),
Mg/d
-
1
-
1
1
3
9.7
(Avg. size 1,016),
Mg/d Total
4
8
1 7
5
-j
1 31
3.2 100
New sulfur
recovery
capacity added,
Mg/d
210
612
1,692
1,016
3,530
-------
Table 9-24. ESTIMATED NATURAL GAS PRODUCTION, ONSHORE VOLUME,
SWEETENED VOLUMES, VOLUMES ASSOCIATED WITH SULFUR RECOVERY,
1980 AND 1987
Category 1980
(tcf)
Natural gas production (lower 48 states) 19.7
Onshore natural gas production a/ 14.0
Onshore natural gas treated b/ 2.7
for HpS removal
Onshore natural gas associated .9
with sulfur recovery
New onshore natural gas d_/
production
New onshore natural gas treated d/
for HpS removal in new facilities b/
New onshore natural gas associated d/
with sulfur recovery in new facilities c/
Baseline
1987 (est.)
(tcf)
18.5
11.1
2.1
0.7
2.8
.52
.39
a/ 1987 estimates assumed 60 percent of domestic supply is onshore.
IF/ Nineteen percent of onshore gas is sour.
£/ Seventy-five percent of new sour natural gas is projected to be treated
for sulfur recovery.
d/ Not applicable.
9-58
-------
Table 9-25.
NATURAL GAS PRICES:
(1980 Dollars per Thousand Cubic Feet)
HISTORY AND PROJECTIONS FOR 1965-1995
d
Price
History'
1965
1973
1978
Projection
1985
1990 1995
Domestic Wellhead Prices
Old Interstate
New Interstate
Old Intrastate
New Intrastate
North Alaska
Average
Synthetic Gas Prices
High-Btu Coal Gas
Medium-Btu Coal Gas
Imported Gas Prices
Canadian Gas
Mexican Gas
Liquefied Natural Gas
Delivered Prices
Residential
Commercial
Raw Material
Large boilers
Industrial, Other
Refineries
Electric Utilities
Alternative Fuel Cost
NA
NA
NA
NA
NA
NA
2.55
1.74
NA
NA
0.85
NA
0.97
NA
NA
NA
NA
NA
NA
2.
1.
.22
.59
NA
NA
0.84
NA
0.69
1.01
NA
NA
NA
1.10
4.88
3.59
5.15
2.63
NA
1.68
3.02
2.5.9
NA
NA
1.76
NA
1.88
5.19
4.03
6.77
6.77
6.44
5.
5,
.90
.32
4.67
5.71
4.73
4.96
5.17
6.79
1.29 1.52
4.
3.
40
62
4.67
2.02
4.57
4.91
7.54
7.54
7.00
6.26
5.69
4.88
4.95
4.92
4.83
4.82
5.00
4.12
5,
2,
7,
6,
25
02
0.39 0.38 1.11 3.55 3.73 4.55
5.13
5.93
9.28
9.28
8.39
03
46
5.68
5.73
5.69
5.59
7.57 9.04
Source for historical data is Volume 2 of the EIA Annual Report to
Congress, 1979, and the following EIA Energy Data Reports: Natural Gas
Production and Consumption, 1978; United States Imports and Exports of
, Natural Gas, 1978; and, Natural and Synthetic Gas, 1978.
Projections for the middle oil price scenario.
j Major fuel-burning installations.
Inflated by GNP implicit price deflator, 9.0 percent from 1979 dollars to
1980 dollars.
Notes: NA = Not available.
— = Not applicable.
Source: DOE/EIA Annual Report to Congress. 1980, Vol. 13, pg,
90.
9-59
-------
9.2 ECONOMIC IMPACT ANALYSIS
This section discusses the economic analysis methodology and expected
impacts of alternative regulations controlling sulfur dioxide (SCL)
emissions from sour natural gas sweetening and sulfur recovery processes.
Total additional before-tax annualized costs of controls in 1987, the
fifth year of controls, for the projected seventy-eight new natural gas
sulfur recovery plants range from zero under Regulatory Alternatives I and
II to over $100 million under Regulatory Alternative VI.
Aggregate after-tax annualized emissions control costs amount to less
than one percent of the total projected value of new onshore natural gas
production in 1987 under Regulatory Alternatives I through IV. Under
Regulatory Alternative V, this ratio rises to 2 percent. Thus, under
Regulatory Alternatives I through V, the impacts of S02 emissions
regulations on expected returns from natural gas exploration and
development are relatively small and the effects on exploration for and
development of new natural gas fields is expected to be negligible. In
contrast, under Regulatory Alternative VI, the aggregate after-tax
annualized emissions control cost is substantial, amounting to 12.1 percent
of the value of new onshore natural gas production. Under this regulatory
alternative, the impacts on exploration and development of gas fields could
be substantial.
Unit emissions control costs serve as a useful indicator of
profitability impacts per Mcf on individual regulated plants, assuming no
natural gas price impacts. As shown in Table 9-26, across all model
plants, unit emissions control costs range from zero under Regulatory
Alternative 1 to more than $9.64 per Mcf under Regulatory Alternative VI.
In general, and assuming that the effects of the regulations on the
exploration for and development of new natural gas are negligible, natural
gas production and price impacts are expected to be negligible under
Regulatory Alternatives I through VI.
Under Regulatory Alternative VI, additional emissions control costs
are estimated to cause 26 projected small (Model 1) natural gas sulfur
recovery plants to become economically nonviable, i.e., unable to recover
total production costs (see Table 9-27). It is further estimated that 15
9-60
-------
Table 9-26. UNIT EMISSIONS CONTROL COSTS AND EXPECTED PROFITABILITY IMPACTS (1980$/Mcf)
I
en
Regulatory alternative
Size
Model (joilfur intake)
plant Mg/d
1 5.1
2a 10.2
2b 10.2
3a 101.6
3b 101.6
4 563.8
5 563.8
6 1,015.9
7 1,015.9
LT/d
5
10
10
100
100
555
555
1,000
1,000
Acid gas feed
H0S/C00 ratio
C- C.
by volume
12.5/87.5
50/50
12.5/87.5
50/50
20/80
50/50
80/20
50/50
80/20
I
Baseline
control
level
0
0
0
0
0
0
0
a/
0
II
0
0
0
0
0
0
0
a/
0
III
.02 to
.00 to
.00 to
.01 to
.00 to
.00 to
.00 to
a/
.02 to
.30
.02
.04
.06
.16
.01
.09
.07
IV
.02 to
.01 to
.00 to
.01 to
.00 to
.07 to
.02 to
a/
.02 to
.40
.02
.04
.06
.16
.33
.09
i
.07
V
.02 to
.01 to
.01 to
.14 to
.15 to
.07 to
.02 to
a/
.02 to
.40
.19
.38
1.41
2.54
.33
.09
t
.07
VI
.60 to >
.01 to
.01 to
.14 to
.15 to
.07 to
.02 to
a/
.02 to
9.64
.19
.38
1.41
2.54
.33
.09
.07
a/ Not estimated. No plants are projected for this model plant.
-------
en
ro
Table 9-27. INCREASES IN THE CUMULATIVE NUMBER OF NONVIABLE ONSHORE SOUR NATURAL GAS
SULFUR RECOVERY PLANTS DUE TO S02 NSPS, 1987
Regulatory alternative
Size
Model (sulfur intake)
plant Mg/d
1 5.1
2a 10.2
2b 10.2
3a 101.6
3b 101.6
4 563.8
5 563.8
6 1,015.9
7 1,015.9
LT/d
5
10
10
100
100
555
555
1,000
1,000
Acid gas feed
H0S/C09 ratio
L. i.
by volume
12.5/87.5
50/50
12.5/87.5
50/50
20/80
50/50
80/20
50/50
80/20
I
Baseline
control
level
0
0
0
0
0
0
0
0
0
II
0
0
0
0
0
0
0
0
0
III
0
0
0
0
0
0
0
0
0
IV
0
0
0
0
0
0
0
0
0
V
0
0
0
<1
<1
0
0
0
0
VI
26 aj
0
0
<1
<1
0
0
0
0
a/ Fifteen of these 26 nonviable plants will likely be curtailed due to S0? NSPS.
-------
of these nonviable plants will be curtailed under Regulatory Alternative VI
because unit variable costs (including emissions control costs) will exceed
the expected price. The decline in natural gas production associated with
these potential curtailments amounts to .013 trillion cubic feet, or less
than one tenth of one percent of the projected U.S. natural gas supply.
Consequently, natural gas price impacts are also expected to be negligible.
Sulfur supplies are expected to increase slightly as a result of
regulations which require increased sulfur recovery efficiency. Under
Regulatory Alternatives IV, V and VI, natural gas sulfur recovery would
increase by approximately 0.1 million metric tons. This represents about a
0.5 percent increase in total projected sulfur supply in 1987 and could
cause a slight decrease in local market sulfur prices.
The remainder of Chapter 9 is organized as follows. A discussion of
the impact assessment methodology is presented in Section 9.2.1. Section
9.2.2 presents a detailed discussion of the estimated economic impacts of
each S0£ regulatory alternative. Section 9.3 describes the potential
socioeconomic and inflationary impacts.
9.2.1 Economic Impact Assessment Methodology
Each regulatory alternative will have two effects on the decisions of
firms to produce onshore natural gas from new fields. First, by increasing
the expected total costs of exploring for and processing onshore natural
gas, the regulatory alternatives reduce the expected returns to firms from
exploration for and exploitation of new natural gas fields I/.
Thus, firms will be likely to reduce levels of exploration activities,
thereby reducing the number of fields that will be discovered. Second, by
increasing the costs of obtaining gas from discovered sour natural gas
fields, regulatory alternatives may reduce the production of gas from those
fields. In this analysis, the impacts of the regulatory alternatives on
the rate of exploration and discovery of new fields are assessed
qualitatively. The effects of the regulatory alternatives on the rate of
production of natural gas from discovered fields are assessed
quantitatively.
T7To the extent that exploration activities are non-directional (that
is, concerned with the discovery of hydrocarbons in the form of oil
and/or natural gas) the effect of the regulation on exploration
activities will be diminished.
9-63
-------
The methodology used in the analysis is as follows. Initially, it is
assumed that the baseline forecasts of the number and size of potential
natural gas sulfur recovery plants presented in Table 9-23 is unaffected by
each regulatory alternative. This amounts to the assumption that the
effects of each standard on expected returns to exploration for and
exploitation of new natural gas fields are negligible and therefore that
these activities will not be curtailed as a result of the regulatory
alternatives. The validity of this assumption for each regulatory
alternative is examined carefully. The methodology used to carry out this
assessment is described later in this section.
Second, the percent hLS in sour natural gas is estimated for each
model plant projected to be constructed under the baseline scenario. These
projections about the quality of natural gas in each plant are obtained
using the data presented in Table 9-7 on the distribution by percent H2S
and by plant size of plants operating in 1980. These data are adjusted to
account for the forecasted increase, from 5.92 percent to 9.25 percent
(presented in Tables 9-21 and 9-22), in the proportion of hLS in sour
natural gas between 1980 and 1987 _!_/. It is necessary to estimate the
distribution of plants by hLS percentage and sulfur capacity in order to
calculate the level of sweet gas output for each model plant. This
estimate is required to calculate unit emissions control costs.
Third, long run baseline average total costs of producing sweetened
natural gas from new wells in 1987 (measured in 1980 constant dollars) are
estimated. The estimation procedure is as follows. Data on new well
on-shore natural gas production costs for 1980 were obtained from the API
and DOE. These data are presented in Table 9-4. These cost estimates are
\l Between 1980 and 1987, the average proportion of hLS by volume in sour
natural gas is expected to rise from 5.92 percent to 9.25 percent.
The distribution of plants by percent hLS natural gas presented in
Table 9-7 is qualitatively adjusted to take account of this projected
increase in hLS concentration to obtain the distribution of plants by
hLS concentration presented in Tables 9-33 through 9-41.
9-64
-------
adjusted to reflect costs of production in 1987 under the assumption that
the average total costs of new gas production will, in the absence of
regulation, rise to $4.80 per Mcf from the 1980 level of $2.00 per Mcf.
This forecasted rise in real production costs is predicated on the
assumption that the natural gas industry is competitive and that in the
long run, average total costs of production from new wells will be equal to
the expected price of natural gas. In this case, the expected price is
assumed to be the forecasted deregulated natural gas price of $4.80 per
Mcf If. Total costs of production vary from well to well as a result of
differences in well depths and gas flow rates. These differences may be
substantial, ranging from $.05 per Mcf to $72.18 per Mcf in terms of 1980
dollars. Clearly, if a firm knew before the fact that the unit total costs
of producing natural gas from an individual well would exceed average
revenues from the sale of that gas (that is, the market price of natural
gas), it would not drill the well. However, in general, until the well has
been drilled and is in operation, the firm does not know what its unit
total costs of production will be. Consequently, once the well has been
drilled, the firm bases its decision on whether or not it will operate the
well, on whether or not unit variable costs of production exceed average
revenues (i.e., the well-head price). Unit variable costs of production of
natural gas are relatively small when compared to unit total costs, ranging
from a minimum of $.03 per Mcf to a maximum of $.93 per Mcf in terms of
1980 constant dollars. (See Table 9-4, Column 4.) Note that unit variable
costs of production include field equipment costs and operating and
maintenance costs. These are costs that can be avoided by firms if they
decide not to produce gas from a given field, once the depth of the field
and well sizes have been determined. Further note that unit variable
costs, defined as costs that could be avoided once the nature of the well
has been determined, also include all costs associated with compliance with
each regulatory alternative because these costs could also be avoided by
the firm if it decided not to produce gas from a particular well. The
_!/ This forecast price was obtained from DOE and is measured in terms of
constant 1980 dollars.
9-65
-------
methodology used to compute before-tax and after-tax costs of pollution
control for each model plant is presented in Section 9.2.1.1. In the case
of non-processing gas producing firms that sell sour gas to processors, the
cost of compliance would be reflected in increased charges by the
processing company to cover the costs associated with the regulatory
alternatives, or alternatively, an equivalent reduction in the well head
price paid for the sour gas. In the case of gas producing/processing
companies, costs of compliance would be directly incurred.
The above discussion provides a simple decision rule for the firm with
respect to whether or not it will choose to produce and process gas from
any given well. If price exceeds unit variable cost then the well will be
utilized to produce natural gas. Under the assumed baseline, all of the 78
facilities forecasted to be constructed will be used to process natural gas
as the forecasted deregulated price of $4.80 per Mcf exceeds the maximum
forecasted unit variable cost of $0.93 per Mcf. Curtailments will occur as
a result of each regulatory alternative if and only if unit pollution
control costs exceed the difference between the predicted price and
pre-regulation unit variable costs, given the assumption that the impacts
of the regulatory alternative on exploration and exploitation of new fields
are negligible.
The extent to which each regulatory alternative is likely to affect
exploration and drilling activities is assessed in two ways. First, the
impact of each regulatory alternative on the expected number of facilities
that will recover, or more than recover, all costs of production (that is
the number of facilities that are expected to be independently economically
viable) is calculated. These data provide a qualitative measure of the
extent to which the regulatory alternatives will reduce expected returns
from exploration for and exploitation of potential natural gas fields.
Second, the total costs of each regulatory alternative relative to the
value of total new gas production are computed. The methodology used to
estimate the effect of each regulatory alternative on the potential
economic viability of processing operations predicted under the baseline
scenario requires further discussion. This discussion is presented in
9.2.1.2.
9-66
-------
The above analysis is carried out under the assumption that the well
head price for sweet gas will be unaffected by any of the regulatory
alternatives. The basis for this assumption is as follows. Sour natural
gas cannot be sold at sweet natural gas prices. Either it is priced below
sweet gas or it is non-marketable. The main reason for a differential
between sour and sweet natural gas prices, according to industry sources,
is that H2S in natural gas is corrosive to compressors, valves and other
pipeline and natural gas processing equipment. Pipeline companies are
therefore reluctant to accept natural gases with a high hLS concentration.
Consequently, sour gas must be sweetened, i.e., the H2S must be removed, or
blended with sweet natural gases in order to be marketable as sweet gas
according to industry standards.
Sweetening is performed by either producers, gas processors or
pipeline companies. These operations may be vertically integrated or
independent operations depending on local market conditions. It is common
practice for gas processors and pipeline companies to charge producers and
dealers (third parties) a treating fee for sulfur removal against sour gas.
This practice pushes sweetening costs backward to the producer. The
producer then chooses either to sell sour gas at the sour gas price, to
install and operate his own sweetener and sell sweetened natural gas or to
cap his sour gas producing well(s). The alternative to cap the sour gas
well(s) may be a temporary measure until a sufficient number of exploration
wells are drilled and enough gas is discovered to justify further field
development costs.
Under existing and expected market conditions, producers and their
leaseholders (royalty owners) bear the cost of sweetening their produced
sour natural gases. Regulations which require additional emissions control
costs on new sweetening and new sulfur recovery operations in the onshore
natural gas production industry will effectively increase the sour gas
sweetening cost in new plants over baseline. Producers and leaseholders of
new sour gas will incur lower net incomes compared to the baseline.
Individually, sour gas producers are not expected to be able to pass-on
additional emissions control costs because this would require sweetened
natural gas to sell at a premium over naturally sweet gas. Historically,
9-67
-------
producers have been unable to obtain such a premium and none is expected in
the future. Thus, if natural gas prices were to increase due to SCL
emissions regulations, they would only increase as a result of plant
curtailments and associated supply shifts. But, as shown in Table 9-24,
even in the unlikely event that all new sour natural gas sulfur recovery
plants and their associated natural gas production were curtailed, the loss
of domestic natural gas supply would not exceed .39 trillion cubic feet,
less than 2 percent of total domestic natural gas supply. The expected
number of curtailments under the most stringent regulatory alternative, is
much less severe, and in the order of less than one tenth of one percent of
projected domestic consumption, implying a negligible increase in domestic
prices. (See Table 9-32.)
9.2.1.1 Annualized and Unit Emissions Control Costs. Before-tax
annualized costs (BTAC) and after-tax annualized costs (ATAC) of emissions
controls are computed for each model plant and regulatory alternative by
using the following equations:
BTAC = I CRF + 0&MQ (1)
ATAC = I CRF TAXF + (1-t) 0&MQ (2)
where,
I = initial base year investment
O&M = annual operating & maintenance costs less applicable
by-product (sulfur and steam) credits
r(l+r)n
CRF = — ^ - <— , the capital recovery factor
r = the real cost of capital
n = economic life of the asset, i.e. the capital recovery period
(variable by asset)
9-68
-------
TAXF = 1-itc - t PVDEP
\
itc = investment tax credit rate
t = corporate income tax rate
PVDEP = present value of annual depreciation factors per $1
of investment, i.e.
Y DEP
PVDEP = Z
y = 1 (l+d)y
Y = length of the depreciation period, 3, 5, 10 or 15 years
d = nominal discount rate (the weighted nominal cost of capital)
DEP = annual depreciation factors calculated using the most
advantageous depreciation methods for the firm, either (1)
rapid amortization of pollution control investments or (2)
accelerated cost recovery as allowed by the 1981 Economy
Recovery Act.
Inflation and the weighted, nominal, after-tax cost of capital are
projected to be 8 and 10 percent, respectively. The inflation rate is
based on recent estimates obtained from the DRI econometric model of the
25
U.S. economy. The nominal weighted after-tax cost of capital for the
natural gas industry was based on a composite natural gas industry stock
price earnings ratio of 7 to 8. In addition, the marginal corporate income
tax rate was assumed to be 47 percent and the debt ratio was assumed to be
45 percent, and the nominal pre-tax interest rate on new debt for domestic
corporations was estimated to be 13 percent.
Unit emissions control cost for each model plant, measured in 1980
dollars per Mcf of sweet gas, are computed using the following equation.
Unit emissions = _ ATAC _ (3)
control cost Sweet gas volume
9-69
-------
where ATAC is the after-tax annualized cost of emission controls as defined
in Equation 2. Sweet gas volume is a function of the sulfur intake of the
natural gas sulfur recovery plant and the H2S and hLS/CCL ratios in the
sour natural gas (See Table 9-28, Footnote a).
The estimated 1987 baseline sweet gas sales and sulfur sales
associated with each model plant and regulatory alternative are shown in
Tables 9-28 and 9-29, respectively- Natural gas and sulfur volumes
associated with each level of sales can be derived by simply dividing each
level of sales by the appropriate baseline price per unit. For natural
gas, the baseline price is $4.80 per Mcf. For sulfur, the baseline price
is $98.43 per Mg.
Model plants 2 and 3 were split to show two levels of H2S/C02 in acid
gas.
9.2.1.2 Viability of Regulated Plants. In the context of this
analysis, a new onshore natural gas sulfur recovery plant and its
associated natural gas production is defined to be economically viable if
the wellhead gas price is greater than or equal to its actual unit
production costs for drilling and equipping wells (including dry holes).
These costs include field equipment, operating and maintenance
expenditures, sweetening costs and baseline net sulfur recovery revenues.
In post regulation scenarios, incremental SCL emission control costs are
also included in addition to exploration and development drilling costs.
Note that this definition of new^plant economic viability also takes
into account the recovery of total production costs on average, including
a return on investment. A plant is economically nonviable if it fails to
recover total production cost as defined above. It is important to
recognize, as was noted above, that although a particular operation may
prove to be economically nonviable, it will never-the-less be operated if
all variable costs of production are covered, that is, as long as the price
of natural gas exceeds variable operating costs, the plant will operate.
Under the baseline scenario, given the above definition of economic
viability, of the 78 projected sulfur recovery plants, 62 of the
development and processing facilities are economically viable. Sixteen are
not. All 78 sulfur recovery plants will be operated because their variable
9-70
-------
Table 9-28. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' ESTIMATED 1982 SWEET GAS SALES a/ PER PLANT
UD
Model
plant
1
2a
2b
3a
3b
4
5
6
7
Size
(sulfur Intake)
Mg73 LTTd"
5.1
10.2
10.2
101.6
101.6
563.8
563.8
1,015.9
1,015.9
5
10
10
100
100
555
555
1 ,000
1,000
Acid gas feed
H2S/C02 ratio
by volume
12.5/87.5
50/50
12.5/87.5
50/50
20/80
50/50
80/20
50/50
80/20
Percent H»S in sour natural gas
.5
42.8
88.4
85.7
884
870
4,904
4,923
8,837
8,870
1
20.5
43.7
41.1
437
424
2,428
2,446
4,373
4,407
2
9.4
21.4
18.7
214
201
1.189
1,208
2,142
2,176
3
5.7
14.0
11.3
140
126
776
795
1,398
1,432
4
mill •
3.8
10.3
7.6
103
89
570
588
1,027
1,060
5
ion 1980
2.7
8.0
5.4
80
67
446
464
803
837
6
dollars-
1.9
6.5
3.9
66
52
363
382
655
688
7
1.4
5.5
2.8
55
41
304
323
548
582
8
1.0
4.7
2.0
47
34
260
279
469
502
9
0.7
4.1
1.4
41
27
226
244
407
440
10
0.4
3.6
0.9
36
22
198
217
357
390
15
NA
2.
NA
21
7
116
134
208
242
20
NA
1 1.3
NA
13
0
74
93
134
167
NA = Not applicable.
a/ Sweet gas sales equals sweet gas volume times price. Price Is assumed to be $4.70/MMBtu ($4.80/Mcf) (the Department of Energy's 1987 projected
well head price In 1980 dollars). Sweet gas volume (bcfy) equals .0092982 M 1 - c - fl. where S = sulfur Intake (LT/d), c = H^S ratio In sour
natural gas, and r = H,S/C09 ratio. c L r-"
-------
Table 9-29. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' ESTIMATED 1987 VALUE OF SULFUR SALES b/
BY REGULATORY ALTERNATIVES PER PLANT
10
ro
Regulatory alternative
Size
Model isulfur intake^
plant Mg/d
1 5.1
2 10.2
3 101.6
4 563.8
5 563.8
6 1,015,9
7 1,015.9
LT/d
5
10
100
555
555
1,000
1,000
I II
Acid gas feed Baseline
H0S/C00 ratio control
by volume
a
a
a
50/50
80/20
50/50
80/20
level
.00°
.328
3.361
18,654
18.771
33.615
33.822
.00C
.328
3.361
19.114
19,132
34.445
34.473
III
ml linn 1
.163
.326
3.444
19.114
19,420
34,445
34.991
IV
L980 dollar:
.164
.336
3.444
19.412
19.420
34.980
34.991
V
.164
.341
3.496
19.412
19.420
34.980
34.991
VI
.171
.341
3.496
19.412
19.420
34.980
34. §91
a/ Covers the entire ratio from 12/.5/87.5 to 80/20.
&/ Sulfur price is $98:43/Mg ($100/LT). Operation is 350 days per year.
c/ Sulfur is not recovered.
-------
unit costs are smaller than the predicted wellhead price for sweet gas of
$4.80 per Mcf. The estimation procedure used to calculate the number of
natural gas sulfur recovery operations that would be economically viable
under the baseline scenario is as follows.
A probability distribution of total unit production costs of natural
gas from new sour wells was estimated utilizing the distribution of gas
production by well size (Table 9-1) and the distribution of the numbers of
new wells drilled by depth (Table 9-2). It is assumed that existing well
sizes (flow rates) reflect expected new well sizes and that well size and
well depth are independent. The marginal and bivariate distributions of
well depth, flow rate and the combination of well depth and flow rate thus
obtained are shown in Table 9-30.
The probability estimates are created in order to approximate the
distribution of 1979-1980 natural gas production costs to the wellhead from
new wells. The distribution indicates that, in 1979-80 total unit
production costs associated with production from new wells, averaged over
the entire distribution, were approximately $2.00 per Mcf.
For the reasons discussed in Section 9.2.1 above, by 1987, average
total unit production costs are assumed to increase to $4.80 in terms of
1980 constant dollars. It is also assumed that total unit costs of
production rise in proportion to the increase in average total unit costs
across the entire distribution of production costs of gas from new wells.
The resulting predicted cumulative distribution of the cost of producing
natural gas from new wells in 1987 is constructed and plotted in
Figure 9-8.
Utilizing this cumulative distribution function, it is apparent that
approximately 20 percent of all natural gas produced from new sour gas
wells will have total unit operating costs in excess of $4.80 per Mcf.
Just over 60 percent will have total unit production costs below $2.40 per
Mcf. Approximately 10 percent is forecasted to cost between $2.40 and
$3.60 per Mcf and a further 10 percent to cost between $3.60 and $4.80 per
Mcf. This implies that under the baseline scenario 62 of the 78 projected
natural gas sulfur recovery facilities and their associated natural gas
production will be economically viable while 16 will not.
9-73
-------
Table 9-30. ESTIMATED ONSHORE NATURAL GAS PRODUCTION COSTS AND PROBABILITY ESTIMATES
FOR SELECTED WELL DEPTHS AND BASE YEAR FLOW RATES, 1980
Drilling and equipment cost per
productive gas well a/ (1980$):
P(d) d/
2,000
89,000
.30
Field equipment Annual O&M
Flow rate P(r) cost b/ c/ cost b/
(Mcfd) (1980$) (198C
50 .02 15,000 6,000
250 .20 26,000 12,000
500 .36 35,000 15,000
1,000 .40 43,000 20,000 i
5,000 .02 64,000 29,000 i
10,000 .00 87,000 44,000 i
a/ Source 1s Table 9-3.
b/ Source: "Aggregate Average Annual Gas Well Ope
)t/vrl
$.36/Mcf 4.31 (.006)
$.14/Mcf 1.02 (.060
$.09/Mcf .56 (.108
$.06/Mcf .31 (.120
$.02/Mcf) .08 (.006)
$.01/Mcf) .05 (.000)
Well depth (feet)
4,000 8,000
211,000 949,000
.50 .10
12,000
1,875,000
.10
Unit total cost and (P(r,d)) -1
IQflO t/Mrf
8.95 .01 36.99
1.95 .10 7.55
1.02 .18 3.83
.54 .20 1.94
.12 .01 .40
.07 .00 .21
.002) 72.18
.020 14.59
.036 7.35
.040 3.70
.002 .75
.000 .39
(.002)
(.020
.036
.040
.002
.000)
'rating Costs vs Production Capacity 1981"
eference 5.)
cj Includes field equipment between "Christmas tree" and point of transfer. Does not Include sour gas sweetening or sulfur recovery equipment.
Al P(x) = probability estimates for well depth (d), flow rate (r), and flow rate and well depth (r.d).
-------
FIGURE 9-8. APPROXIMATE CUMULATIVE DISTRIBUTION OF NATURAL GAS
PRODUCTION COST FROM NEW WELLS IN 1937 (1980 $/Mcf)
CUMPROB
1.0
0.9
0.8
0.7 I T7
? I; -10* /
tn
0.6 +
0.5
0.4
0.3
0.2
0.1 +
0.0
0 2.4' 3.6 4.8
9.6 12.0 14.4 16.8 19.2 21.6 24.0 26.4
Cost of producing natural gas from new wells (1980 $/Mcf)
28.8 31.2 33.6 36.0 Assumed 1987
-------
The projected distribution of 1987 wellhead production costs from new
sour gas wells is used to estimate the corresponding distribution of long
run baseline unit producers' surplus. Unit producer surplus is measured as
price less baseline long run unit production cost per Mcf. The resulting
preregulation distribution of unit producer's surplus is summarized below:
Baseline
unit
Wellhead Production producers' Estimated
price costs surplus probability
sweet gas) (% of production)
4.80 <2.40 >2.40 60
4.80 2.40 to 3.60 (3.00) 1.20 to 2.40 (1.80) 10
4.80 3.60 to 4.80 (4.20) 0 to 1.20 (.60) 10
4.80 >4.80 <0.0 20
Note: The numbers in parenthesis indicate the midpoint of the range.
The distribution of baseline producer surplus, constructed in the
above analysis, indicates the level of additional emissions control cost
that new sulfur recovery plants can incur and remain economically viable,
i.e., still cover total production costs. Thus, approximately 10 percent
of the new onshore natural gas production from sour natural gas is expected
to become financially nonviable if its incremental S02 emissions control
cost exceeds $.60 per Mcf. Approximately 20 percent is expected to become
nonviable if incremental control cost exceeds $1.80 per Mcf. Approximately
80 percent is projected to remain economically viable even with incremental
control costs as high as $2.40 cents per Mcf.
In order to estimate the numbers of each type of model plant that are
expected to become nonviable as a result of each regulatory alternative,
the proportions of each type of model plants expected to have negative
producer surpluses are estimated. To obtain measures of the actual number
of plants that are likely to become economically nonviable, these
proportions are multiplied by the baseline projections of the numbers of
each type of model plants. In order to assess the effect of each
9-76
-------
regulatory alternative on economic viability in the industry, the number of
projected nonviable plants under each regulatory alternative is compared
with the number of plants expected to be nonviable under the baseline
scenario.
9.2.2 Economic Impact of SO,, NSPS Regulatory Alternative - Sour Gas
Sweetening and Sulfur Recovery Plants
This section presents the economic impacts that are associated with
each regulatory alternative.
9.2.2.1 Net Annualized Costs Per Plant. The incremental before-tax
and after-tax net annualized costs for individual model plants associated
with Regulatory Alternatives I through VI are shown in Tables 9-31 and
9-32, respectively. These costs were computed using the methodology
presented in Section 9.2.1.1 and provide a basis for further economic
impact analysis. A comparison of before-tax and after-tax net annualized
costs provides a measure of the income tax consequences of the regulatory
alternatives to the firm, assuming that the firm has taxable net income and
does not pass additional emissions control costs forward to consumers or
backward to suppliers. The results indicate that almost 50 percent of the
before-tax costs of emissions control is born indirectly by the federal
government through investment tax credits and depreciation and expense
deductions.
9.2.2.2 Unit Emission Control Costs, Curtailments and Economic
Viability of Model Plants. The relative impact of SCL emission regulatory
alternatives on sour gas sweetening and sulfur recovery plants is indicated
by the magnitude of the emissions control cost per Mcf of associated sweet
gas output. Assuming no price impacts, the unit emissions control costs
also indicate profitability impacts per Mcf. The unit emissions control
costs for seven model plants, six regulatory alternatives and thirteen
different H^S percentages in sour natural gas are shown in Tables 9-33
through 9-41. The Tables also show the number of model plants distributed
according to their anticipated percent h^S in sour natural gas.
The unit emissions control costs in 1980 dollars per Mcf are compared
to the expected average 1987 wellhead price of $4.80 per Mcf for new
natural gas, projected onshore natural gas production costs from new sour
9-77
-------
Table 9-31. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' BEFORE-TAX ANNUALIZED
COST OF S09 NSPS REGULATORY ALTERNATIVES PER PLANT
I
^J
co
s
Model (sulfur
plant Mg/d
1 5.1
2 10.2
3 101.6
4 563.8
5 563.8
6 1,015.9
7 1,015.9
ize
intake)
LT/d
5
10
100
555
555
1,000
1,000
Acid gas feed
H9S/C09 ratio
by volume
a
a
a
50/50
80/20
50/50
80/20
I
Baseline
control
level
0
0
0
0
0
0
0
1
II
0
0
0
142
-56
-119
-7
Regulatory
III
310
44
452
142
3,374
-119
4,718
alternative
IV
if IQftfl Hnll
408
44
452
9,581
3,374
15,316
4,718
a
V
1 SVC-, — — — -.__ .
408
388
7,352
9,581
3,374
15,316
4,718
VI
>10,119
388
7,352
9,581
3,374
15,316
4,718
a/ Covers the entire ratio range from 12.5/87.5 to 80/20.
-------
Table 9-32. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' AFTER-TAX ANNUALIZED
COST OF S02 NSPS REGULATORY ALTERNATIVES PER PLANT
Regulatory
Size
Model (sulfur intake)
plant Mg/d
LT/d
Acid gas feed
H0S/C00 ratio
L. C.
by volume
I
Baseline
control
level
II
III
1 5.1
2 10.2
3 101.6
4 563.8
5 563.8
6 1,015.9
7 1,015.9
5
10
100
555
555
1,000
1,000
a
a
a
50/50
80/20
50/50
80/20
0
0
0
0
0
0
0
0 167
0
0
84
-25
-52
1
24
245
84
1,834
-52
2,555
alternative
IV
1 Qftfl Hnl 1 a
222
24
245
5,125
1,834
8,185
2,555
V
y*c _
222
221
3,940
5,125
1,834
8,185
2,555
VI
>5,382
221
3,940
5,125
1,834
8,185
2,555
a/ Covers the entire ratio range from 12.5/87.5 to 80/20.
-------
TABLE 9-33. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' EMISSION CONTROL COST PER MCF. I MODEL PLANT II
REGULATORY ALTERNATIVE
PERCENT
H2S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
a.o
9.0
10.0
ASSUMED
PLANT
DISTRIBUTION
14.0
9.0
9.0
5.0
5.0
5.0
0.0
0.0
0.0
0.0
0.0
47.
1
BASELINE
CONTRCL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3
0.02
0.04
0.09
0.14
0.21
0.30
0.4l
0.57
0.80*
1.15*
1.79*
4
0.02
0.05
0*11
0.19
0.28
0.40
0.55
0.76*
1*06*
1.53*
2.38**
5
0.32
0.05
0.11
0.19
0.2B
0.40
0.55
0.76 *
1*06*
1.53*
2,38**
6
0.60*
1.26*
2.76***
4.57****
6.81 ****
9.64 ****
13.35****
18.40****
25.69****
37.13 ****
57.68****
* THE PROBABILITY THAT THE PLANT IS NOW I ABLE IS APPROXIMATELY 10 PERCENT.
** THE PROBABILITY THAT THE PLANT IS NONVlABLE IS APPROXIMATELY 20 PERCENT*
*+* THE PROBABILITY THAT THE PLANT IS NONVlABLE IS GREATER THAN 20 PERCENT.
**** THE PLANT IS NONVlABLE AND ALSO WOULD BE CURTAILED.
-------
TABLE 9-34. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS* EMISSION CONTROL COST PER HCF. I MODEL PLANT 2A|
00
REGULATORY ALTERNATIVE
PERCENT
H2S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
a.o
9.0
10.0
15.0
20.0
ASSUMED
PLANT
D1STRIOUT ION
2.0
3.0
2.0
1*0
1.0
1.0
0.0
1.0
0.0
0.0
0.0
0.0
0.0
11.
1
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2
— ISftJU »/HLr— —
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3
0.00
0.00
0.01
0.01
0.01
o.oi
0.02
0.02
0.03
0.03
0.03
0.06
0.09
4
0.00
0.00
0.01
0.01
0.01
o.ot
0*02
0.02
0.03
0.03
0.03
0.06
0.09
5
0.01
0.02
0.05
0.08
0.10
0.13
0.16
0.19
0.23
0.26
0.30
0.51
0.79*
6
0.01
0.02
0.05
0.08
0.10
0.13
0.16
0.19
0.23
0.26
0.30
0.51
0.79*
* THE PROBABILITY THAT THE PLANT IS NCKVIABLE IS APPROXIMATELY 10 PERCENT,
** THE PROBABILITY THAT THE PLANT IS NONVIABLE IS APPROXIMATELY 20 PERCENT.
*+* THE PROBABILITY THAT THE PLANT IS NONVIABLE IS GREATER THAN 20 PERCENT.
-------
TABLE 9-35. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' EMISSION CONTROL COST PER HCF. I MODEL PLANT 2BI
CO
ro
REGULATORY ALTERNATIVE
PERCENT
H2S IN
SOUR
NATURAL GAS
0. 5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0.0
9.0
10.0
ASSUMED
PLANT
DISTRIBUTION
2.0
3.0
2.0
1.0
1.0
0*0
0.0
1.0
0.0
0.0
0.0
10.
1
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3
0.00
0.00
o.ol
0.01
0.02
0.02
0.03
0.04
0.06
0.08
0.14
4
0*00
0.00
0.01
o.oi
0.02
0.02
O.p3
0.04
6.06
Oi 08
0.13
5
0.01
0.03
0. 06
0.09
0*14
0.20
0.27
0.38
0.53
0.76*
1.19*
6
0.01
0.03
0.06
0.09
0.14
0.20
0.27
0.38
0.53
0.76*
1.19*
* THE PROBABILITY THAT THE PLANT IS NONylABLE IS APPROXIMATELY 10 PERCENT.
** THE PROBABILITY THAT THE PLANT IS NONVIABLE IS APPROXIMATELY 20 PERCENT.
*+* THE PROBABILITY THAT THE PLANT IS NONVIABLE IS GREATER THAN 20 PERCENT*
-------
TABLE 9-36. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS4 EMISSION CONTROL COST PER
I MODEL PLANT 3A|
CD
CO
REGULATORY ALTERNATIVE
PERCENT
H2S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
15.0
20.0
ASSUMED
PLANT
DISTRIBUTION
0.0
0.0
O'.O
0.3
0.6
0.3
0.3
0.3
0.3
0.3
0.0
0.3
0.3
3.
1
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2
0.0
0.0
0.0
0.0
1 o.o
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3
0.00
0.00
b.oi
0.01
0.01
o.oi
0.02
0.02
0.03
0.03
0.03
0.06
0.09
4
0.00
0.00
o.oi
0.01
o.oi
o.oi
0.02
0.02
0.03
0.03
0.03
0*06
0.09
5
0.02
0.04
0.09
0.14
o.ia
0.24
0.29
0.34
0.40
0.47
0.53
0.91 *
1.41*
6
0.02
0.04
0.09
0.14
0.18
0.24
0.29
0.34
0.40
0.47
0.33
0.91 *
1.41 *
* THE PROBABILITY THAT THE PLANT IS NONVIABLE IS APPROXIMATELY 10 PERCENT.
** THE PROBABILITY THAT THE PLANT IS NONVIABLE IS APPROXIMATELY 20 PERCENT*
**+ THE PROBABILITY THAT THE PLANT IS NONVIABLE IS GREATER THAN 20 PERCENT.
-------
TABLE 9-37. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' EMISSION CONTRCL CCSt PER MCF* (MODEL PLANT 3B >
00
REGULATORY ALTERNATIVE
PERCENT
H2S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
e.o
9.0
10.0
15.0
ASSUMED
PLANT
DISTRIBUTION
0.0
0.0
0.0
0.3
0.6
0.3
0.3
0.3
0.3
0.3
0.3
0.3
3.
1
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3
0.00
0.00
0.01
0.01
o.ot
0.02
0.02
0.03
0*04
0*04
o.os
0.16
4
0.00
0.00
o.ol
o.oi
6.01
0.02
0.02
0.03
0*04
d.04
0.05
0.)6
9
0.02
0.04
0.09
0.15
0.2l
0.28
0.36
0.46
0.57
0.69*
0.85*
2.54***
6
0.02
0.04
0.09
0.15
0.21
0.28
0.36
0.46
0.57
0.69*
0.85*
2.54***
* THE PROBABILltY THAT THE PLANT IS NONVlABLE IS APPROXIMATELY iO PERCENT.
+* THE PROBABILITY THAT THE PLANT IS NONVIABLE IS APPROXIMATELY 20 PERCENT.
*+* THE PROBABILITY THAT THE PLANT IS NONVIABLE IS GREATER THAN 20 PERCENT.
-------
TABLE 9-38. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS1 EMISSION CONTROL COSt PER MCf. IMOOEL PLANT 41
00
CJ1
PERCENT
H2S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
15.0
20.0
ASSUMED
PLANT
DISTRIBUTION
-0.0
0.0
0.0
0.0
0.0
0.0
0.1
0.0
0.1
0.0
Oil
0.2
0.5
1.
1
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0*0
REGULATORY
2
1 on/1 4 tur
—— —— tVOU >/nC
0.00
0.00
0.00
0.00
0.00
OiOO
OiOO
0*00
OiOO
OiOO
0.00
0.00
0.01
ALTERNATIVE
3
0.60
0.00
0.00
0.00
0.00
0.00
0.00
0.00
o.oo
0.00
0.00
0.00
o.oi
4
0.01
o.oi
0.02
0.03
0.04
0.06
0.07
o.oa
0.09
0*11
d.i2
0.21
0*33
5
0.01
0.01
0.02
0.03
0.04
0.06
0.07
0.08
0.09
0*11
0*12
0.21
0.33
6
0.01
0.01
0.02
0.03
0.04
0.06
0.07
0.08
0.09
0.11
0.12
0.21
0.33
-------
TABLE 9-39. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' EMISSION CONTROL CQSf PE8 MCF* I MODEL PLANT 51
REGULATORY ALTERNATIVE
PERCENT
112 S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
f> 4.0
CO 5.0
<* 6.0
7.0
a.o
9.0
10.0
15.0
20.0
ASSUMED
PLANT
DISTRIBUTION
0.0
0.0
0.0
0.0
0.0
0.0
0.2
0.0
0.2
0.0
0.2
0.1
1.0
2.
1
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0*0
0.0
0.0
0.0
0.0
0.0
2
1 VoU 9/ni.l
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
3
0.00
0.00
o.oi
0.01
o.ol
0.02
0.02
0.03
0.03
0.04
0.04
0.07
0.09
4
0.00
0.00
0.01
0.01
0.01
0.02
0.02
0.03
0.03
0.04
0.04
0.0?
0.09
5
0.00
0.00
0.01
0.01
0.01
0.02
0.02
0.03
0.03
0.04
0.04
0.07
0.09
6
0.00
0.00
0.01
0.01
0.01
0.02
0.02
0.03
0.03
0.04
0.04
0.07
0.09
-------
TABLE 9-40.. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS* EMISSION CONTROL COST PER MCF. I MODEL PLANT 61
REGULAtORY ALTERNATIVE
PERCENT
H2S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
6.0
9.0
10.0
15.0
20.0
ASSUMED
PLANT
DISTRIBUTION
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.
I
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2
— —I MHO 9/MLI — —
-0.00
-0.00
-0.00
-OiOO
-0.00
,-0.00
-0.00
-0*00
-0.00
-0*00
-0.00
-0.00
-0.00
3
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-0.00
-o.od
-0.00
•^0.00
-0.00
-0.00
-0.00
4
0.00
o.oi
0.02
0.03
0.04
0.05
0.06
0*07
o.oa
0.10
0.11
0.19
0.29
5
-
0.00
o.oi
0.02
0.03
0.04
0.05
0.06
0.07
o.oa
0.10
0.11
0.19
0.29
6
0.00
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0.10
0.11
0.19
0.29
-------
TABLE 9-41. ONSHORE SOUR NATURAL GAS PRODUCTION MODEL PLANTS' EMISSION CONTRCL COST PER MCF. (MODEL PLANT 7)
UD
00
00
REGULATORV ALTERNATIVE
PERCENT
H2S IN
SOUR
NATURAL GAS
0.5
1.0
2.0
3.0
4.0
5.0
6.0
7.0
6.0
9.0
10.0
15.0
20.0
ASSUMED
PLANT
DISTRIBUTION
0.0
0.0
0.0
0.0
0.0
0.0
0.1
0.0
0.1
0.0
o.i
0.2
0.5
1*
1
BASELINE
CONTROL
LEVEL
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
b.o
0.0
0.0
0.0
0.0
2
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
O.OG
0.00
0.00
0.00
3
0.00
0.00
o.ol
o.ol
o.ol
o.ol
0.02
Qi02
0.02
0.03
0.03
0.09
0.07
4
0.00
0.00
0.01
0.01
O.oi
0.01
0.02
0.02
0.02
0.03
0.03
0.05
'0.07
5
0.00
0.00
OiOl
0.01
0.01
0.01
0.02
0.02
0.02
0.03
0.03
0.05
0.07
6
b.oo
0.00
0.01
0.01
0.01
0.01
•0.02
0.02
0*02
0.03
0.03
0.05
0.07
-------
gas wells and projected baseline unit producer surplus. If the unit
emissions control cost exceeds $.60 per Mcf, it is marked with one asterisk
(*) which indicates a 10 percent estimated probability that a given model
plant would be economically nonviable because of S02 NSPS at that level of
emissions control costs. If the unit emission control cost exceeds $1.80
per Mcf, it is marked with two asterisks (**) which indicate a 20 percent
estimated probability that a given model plant would be economically
nonviable because of S02 NSPS at that level of emissions control cost.
Three asterisks (***) indicate that the incremental control costs are over
$2.40 per Mcf, a level which exceeds half of the projected baseline price
for new natural gas in 1987 and which would indicate more than a 20 percent
probability that a given model plant would not be economically viable
because of S02 NSPS. As shown in Table 9-33, four asterisks (****)
indicate that unit control costs exceed $3.87 per Mcf, a level certain to
cause nonviability of most model plants and likely to cause curtailment as
well since total variable costs would probably exceed price.
Under Regulatory Alternatives I through V, plant curtailments are
predicted to be zero. Under Regulatory Alternative VI, at most fifteen
Model 1 plants will be curtailed. The decline in natural gas production
associated with these potential curtailments amounts to .013 trillion cubic
feet, less than one tenth of one percent of projected U.S. natural gas
supply.
The above projection of curtailments is based on the assumption that
exploration and development of new gas fields are unaffected by the
regulation. In order to qualitatively assess the reasonableness of this
assumption, the increase in the number of plants that are economically
nonviable is calculated for each regulatory alternative utilizing the
methodology described in Section 9.2.1.2.
The HpS in sour gas associated with the forty-seven Model 1 plants
ranges from 0.5 to 5.0 percent. In this range, the unit emissions control
costs and increases in the number of economically nonviable Model 1 plants
are estimated as follows from Table 9-33:
9-89
-------
Increase1 in the
Regulatory Emissions control mimber-0f nonviable
Alternative cost (1980 $/Mcf) Model 1 plants
I .00 0
II .00 0
III .02 to .30 0
IV .02 to .40 0
V .02 to .40 0
VI .60 to 9.64 26
The HoS in sour gas associated with the eleven Model 2a plants ranges
from 0,5 to 7.0 percent. In this range, the unit emissions control costs
and increases in the number of economically nonviable Model 2a plants are
estimated as follows from Table 9-34:
Increases in the
number of nonviable
Model 2a plants •.,..
0
0
0
0
0
0
The H2S in sour gas associated with the ten Model 2b plants ranges
from 0.5 to 7.0 percent. In this range, the unit emissions control costs
and increases in the number of economically nonviable Model 2b plants are
estimated as follows from Table 9-35.
Increases in the
Regulatory Emissions control number of nonviable
Alternative cost (1980 $/Mcf) Model 2b plants
I .00 0
II .00 0
III .00 to .04 0
IV .00 to .04 0
* V .01 to .38 0
, VI .01 to .38, , 0
The hLS in sour gas associated with the three Model 3a plants ranges
from 3.0 to 15.0 percent. In this range, the unit emissions control costs
9-90
Regulatory
Alternative
*
I
II
III
IV
V
VI
Emissions control
cost (1980 $/Mcf)
.00
.00
.00 to .02
.01 to .02
.01 to .19
.01 to .19
-------
and increases in the number of economically nonviable Model 3a plants are
estimated as follows from Table 9-36.
Increases in the
Regulatory Emissions control number of nonviable
Alternative cost (1980 $/Mcf) Model 3a plants
I .00 0
II .00 0
III .01 to .06 0
IV .01 to .06 0
V .14 to 1.41 <1
VI .14 to 1.41 <1
The hLS in sour gas associated with the three Model 3b plants ranges
from 3.0 to 15.0 percent. In this range, the unit emissions control costs
and increases in the number of economically nonviable Model 3b plants are
estimated as follows from Table 9-37.
Increase in the
number of nonviable
Model 3b plants
0
0
0
0
The H2S in sour gas associated with the one Model 4 plant ranges from
6.0 to 20.0 percent. In this range, the unit emissions control costs and
increases in the number of economically nonviable Model 4 plants are
estimated as follows from Table 9-38.
Increase in the
Regulatory Emissions control number of nonviable
Alternative cost (1980 $/Mcf) Model 3b plants
I .00 0
II .00 to .01 0
III .00 to .01 0
IV .07 to .33 0
V .07 to .33 0
VI .07 to .33 0
9-91
Regulatory
Alternative
I
II
III
IV
V
VI
Emissions control
cost (1980 $/Mcf)
.00
.00
.00 to .16
.00 to .16
.15 to 2.54
.15 to 2.54
-------
The h^S in sour gas associated with the two Model 5 plants ranges from
6.0 to 20.0 percent. In this range, the unit emissions control costs and
increases in the number of economically nonviable Model 5 plants are
estimated as follows from Table 9-39.
Increase in the
Regulatory Emissions control number of nonviable
Alternative cost (1980 $/Mcf) Model 3b plants
I .00 0
II .00 0
III .02 to .09 0
IV .02 to .09 0
V .02 to .09 0
VI .02 to .09 0
No plants are projected for model plant number 6.
The HpS in sour gas associated with the one Model 7 plant ranges from
6.0 to 20.0 percent. In this range, the unit emissions control costs and
increases in the number of economically nonviable Model 7 plants are
estimated as follows from Table 9-41:
Increase in the
Regulatory Emissions control number of nonviable
Alternative cost (1980 $/Mcf) Model 3b plants
I .00 0
II .00 0
III .02 to .07 0
IV .02 to .07 • 0
V .02 to .07 0
VI .02 to .07 0
The above analysis indicates that the incremental emissions control
costs are not expected to cause any increase in the number economically
nonviable plants under Regulatory Alternatives I through V. Twenty-six
small (Model 1) plants are estimated to become nonviable under Regulatory
Alternative VI.
9-92
-------
Thus, it appears that Regulatory Alternatives I through V will have
virtually no effect on incentives to explore for and develop new natural
gas fields. Regulatory Alternative VI appears to reduce the expected long
run economic viability of relatively small (Model 1) plants. Consequently,
to obtain a more direct measure of the impact of Regulatory Alternatives I
through VI on expected returns to natural gas exploration, the ratio of the
expected aggregate cost of each regulatory alternative to the wellhead
value of projected new gas production is calculated. These estimates are
presented below:
Estimated Projected
aggregate wellhead value Cost to
Regulatory annualized of new onshore natural value
alternative cost _!/ gas production 2J ratio
(millions 1980$) (millions of 1980$) (percent)
I 0.0 2,405 0.0
II 0.0 2,405 0.0
III 15.7 2,405 0.7
IV 23.2 2,405 1.0
V 49.0 2,405 2.0
VI >291.0 2,405 12.1
Under Regulatory Alternatives I through IV, the aggregate costs of
compliance are less than 1 percent of the total projected value of new
onshore natural gas production in 1987. Under Regulatory Alternative V,
this figure rises to 2 percent. Thus, under Regulatory Alternatives I
through V, the impacts of SO^ emissions control costs on expected returns
from natural gas exploration and development are relatively small. In
contrast, under Regulatory Alternative VI, these impacts are substantial,
amounting to 12.1 percent of the value of new onshore natural gas
production. These results suggest that the effects of Regulatory
Alternatives I through V on exploration and development are likely to be
negligible. Under Regulatory Alternative VI, however, these impacts could
be substantial.
JY Based on 53 percent of the aggregate before tax annualized cost
(Table 9-42).
21 Based on .501 trillion cubic feet (Table 9-21) and $4.80/Mcf.
9-93
-------
9.2.2.3 Expected Quantity and Price Impacts Due to SOp NSPS. Sulfur
dioxide emissions regulations on new onshore sour natural gas production
facilities are not expected to cause significant quantity or price impacts
in either the natural gas or sulfur markets. No change in natural gas
production or price is indicated under Regulatory Alternatives I through V
since no plants are expected to become curtailed as a result of the regula-
tions. A slight reduction in sour natural gas production could occur under
Regulatory Alternative VI due to severe cost impacts and possible
curtailments among the smallest sulfur recovering plants. The initial
impact would decrease natural gas supply by less than one tenth of one
percent, a minimal adjustment in aggregate supply.
Sulfur recovery from onshore natural gas would increase slightly as a
result of regulations that progressively require a greater percentage of
available sulfur to be recovered. This would increase new onshore natural
gas sulfur recovery from 1.2 million metric tons in the baseline to 1.3
million metric tons under Regulatory Alternatives IV, V and VI. This
represents about a 0.5 percent increase in total projected sulfur supply in
1987. This could cause a slight decrease in local sulfur prices in markets
near new natural gas sulfur recovery. These effects would be most likely
occur in Texas, New Mexico, Wyoming, Alabama, Mississippi, Arkansas, and
North Dakota where new onshore sour natural gas discoveries can be
expected.
9-94
-------
9.3 POTENTIAL SOCIOECONOMIC AND INFLATIONARY IMPACTS
\
Sulfur dioxide emissions regulations on new onshore sour natural gas
sulfur recovery facilities are not expected to cause major socioeconomic or
inflationary impacts. No curtailments of expansion of new plants are
projected, except under Regulatory Alternative VI where incremental
emissions control costs exceed an affordable level for Model 1 plants.
Consequently, Regulatory Alternative VI would cause some new plant and
natural gas supply curtailments and natural gas prices would increase by at
most .01 to .02 percent under Regulatory Alternative VI.
Total additional before-tax annualized costs of controls in 1987, the
fifth year of controls, for the projected seventy-eight new natural gas
sulfur recovery plants are estimated as follows:
Regulatory Total additional before-tax
alternative, S00 annualized cost, 1987
(million 1980 dollars)
I 0.0
II 0.0
III 29.7
IV 43.8
V 92.4
VI >548.8
These estimates are derived at the bottom of Table 9-42. The total
before-tax annualized cost of Regulatory Alternative VI exceeds $100
million.
Individual natural gas sulfur recovery plant operators are not
expected to be able to pass additional sulfur emissions control costs
forward into consumer sectors. Costs may be passed backward to sour gas
producers, but often the natural gas sulfur recovery and sour natural gas
production will be vertically integrated. Sour gas producers are generally
expected to absorb the additional emissions control costs out of cash flows
from the sale of sweet gas and recovered sulfur.
A slight increase in sulfur production may occur due to increased
recovery of available sulfur over baseline. This might cause sulfur prices
to fall slightly. The impacts, however, are expected to be small and local
in nature. Sulfur supply and price impacts will tend to be regional,
9-95
-------
a/
10
I
ID
Table 9-42. ONSHORE SOUR NATURAL GAS PRODUCTION, TOTAL BEFORE TAX NET ANNUALIZED COST -y
OF S02 NSPS REGULATORY ALTERNATIVES, 1987
Model
plant
1
2
3
4
5
6
7
Total
Size
(sulfur intake)
Mg/d
5.1
10.2
101.6
563.8
563.8
1,015.9
1,015.9
LT/d
5
10
100
555
555
1,000
1,000
Cumulative
number of new
plants
47
21
6
1
2
0
1
78
I
Baseline
control
level
0
0
0
0
0
0
0
0
II
MI 1
0.0
0.0
0.0
.1
-.1
0.0
0.0 '
-0.0
Regulatory alternative
III
IV
lions of 1980 dollars-
14.6
.9
2.7
.1
6.7
0.0
4.7
29.7
19.2
.9
2.7
9.6
6.7
0.0
4.7
43.8
V
19.2
8.1
44.1
9,6
6.7
0.0
4.7
92.4
VI
>475.6
8.1
44.1
9.6
6.7
0.0
4.7
>548.8
- The total costs for each model plant segment equals the number of model plants per segment times the
before-tax annualized cost per plant. (Table 31)
-------
occurring in areas where new discoveries of sour natural gases are
expected. These effects are deflationary but the impacts on retail
consumer prices will be negligible because sulfur is an industrial
chemical. Sulfur consuming industries, particularly fertilizer
manufacturers, could benefit from slightly expanded sulfur supply and lower
price. Sulfur importers to the U.S. and the Frasch mining segment of the
sulfur industry may be adversely impacted by increased sour natural gas
sulfur recovery, but again expected impacts will be slight regardless of
the regulatory alternative.
No significant net employment, productivity or balance of payments
impacts are expected as a result of sulfur emissions regulations on the
onshore natural gas production industry. Some slight displacements
could occur if the natural gas industry shifts production resources away
from known marginal sour gas reserves toward exploration and development of
known sweet gas reserves.
9-97
-------
9.4 REFERENCES FOR CHAPTER 9
1. Oil & Gas Journal, January 28, 1980, p. 81
2. American Gas Association, Department of Statistics, Gas Facts - 1979
Data.
3. American Petroleum Institute, 1979 Joint Association Survey on
Drilling Costs. February, 1981.
4. U.S. Department of Energy, Energy Information Administration, Cost and
Indexes for Domestic Oil and Oilfield Equipment and Production
Operations, 1980.
5. Personal telephone communication between Mr. J. Wagner of DPRA Inc.
with Mr. Velton Funk, DOE EIA, Dallas, Texas on February 17, 1982.
6. Stanford Research Institute (SRI) International, Chemical Economics
Handbook, December 1979.
7. Neri, J. A. "An Evaluation of Two Alternative Supply Models of
Natural Gas", The Bell Journal of Economics, Spring 1977, pp. 289-302.
8. The Council on Environmental Quality and the Department of State, The
Global 2000 Report to the President (Volume III: Documentation), April
1981. p. 301.
9. U.S. Department of the Interior, Bureau of Mines, Minerals Yearbook -
Sulfur and Pyrites, 1960 to 1980 Preprints.
10. U.S. Bureau of Mines. Sulfur: Mineral Commodity Profile, 1979.
11. U.S. Department of Energy, Energy Information Administration. Annual
Report to Congress-1979, Volume Two (of three): Data, U.S. Department
of the Interior, U.S. Geological Survey-Conservation Division, Outer
Continental Shelf Statistics, June 1980.
12. U.S. Department of Energy, Energy Information Administration, Annual
Report to Congress-1979, Volume Two (of three): Data.
13. A. Bernhard & Company. "Natural Gas Industry." Value Line Investment
Survey. July 18, 1980.
14. Stanford Research Institute (SRI) International, Chemical Economics
Handbook. December 1979.
15. American Gas Association, "Total Energy Resource Analysis Model (TERA)
80-1," Gas Supply and Statistics. Appendix A, Figure A-2, p. 21.
9-98
-------
16. U.S. Department of Energy, Energy Information Administration, Annual
Report to Congress-1979. Volume Three (of three): Projections.
17. TRW Environmental Engineering Division, Research Triangle Park, North
Carolina, for U.S. EPA, Office of Air Quality Planning and Standards,
Emission Standards and Engineering Division, Source Category Survey
Report - Phase I Onshore Production, March 19, 1980.
18. Personal communication between Mr. K. Joshi of TRW Environmental
Engineering Division with Mr. Richard M. Schulze of Trinity
Consultants in Richardson, Texas, on April 23, 1981.
19. Documented meeting between TRW, EPA and API Task Force held July 21
and 22, 1980 at TRW Environmental Engineering Division offices in
Research Triangle Park, North Carolina.
20. U.S. Environmental Protection Agency. Industrial Environmental
Research Laboratory, Research Triangle Park, North Carolina,
Multimedia Assessment of the Natural Gas Processing Industry,
EPA-600/2-79-077, April 1979, section 5, p. 28.
21. U.S. Department of Energy, Energy Information Administration, Annual
Report to Congress-1979, Volume Three (of three): Projections.
22. Personal communication between Mr. K. Joshi of TRW Environmental
Division with Mr. E. E. Ellington of Purwin & Gertz, Inc. in Dallas,
Texas, on August 27, 1981.
23. Personal communication between Mr. K. Joshi of TRW Environmental
Division with Mr. James Myers of Texas Air Control Board, Permit
Section in Austin, Texas, on August 27, 1981.
24. Personal communication between Mr. K. Joshi of TRW Environmental
Division with Mr. David Parnell of Ford, Bacon and Davis Engineers and
Constructors in Dallas, Texas, on August 28, 1981.
25. Data Resources, Inc., Trend!ong 2005 Forecasts. September, 1980.
9-99
-------
APPENDIX A - EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
-------
A.I LITERATURE REVIEW
Date Source
August 28, 1974 (Report)
EPA-68-02-0611
December 1974
October 1975
(Report)
EPA-650/2-75-030
(Report)
EPA-450/3-75-076
February 20, 1976 (Report)
EPA-68-02-2082
January 1977 (Draft report)
EPA
March 2 and 3, 1977 U.S. EPA NAPCTAC
Minutes of Meeting
(first NAPCTAC)
August 1977
August 1978
(Report) EPA
AP-42
(Report)
EPA-450/3-78-047
Data or Information
Characterization of Sulfur
Recovery in Oil and Natural
Gas Production
Sulfur Compound Emissions of
the Petroleum Production
Industry
Atmospheric Emissions Survey
of the Sour Gas Processing
Industry
Economic Impact of New Source
Performance Standards on Sulfur
Recovery Plants Associated with
Natural Gas Processing Plants
An Investigation of the Best
Systems of Emissions Reduction
for Sulfur Compounds from Crude
Oil and Natural Gas Processing
Plants
Comments from API and the
industry representatives on
the proposed S02 NSPS on
crude oil and natural gas
onshore production plants.
Compilation of Air Pollutant
Emission Factors, Third Edition
Evaluation of Emissions from
Onshore Drilling, Producing,
and Storing of Oil and Gas
January 8, 1980 Rockwell International Offshore program data
February 7, 1980 Shell Oil Company
Houston, Texas
Forecast data for the lower
48 States' onshore natural gas
production conventional
facilities
A-2
-------
Date
July 29, 1980
October 6, 1980
November 25, 1980
Source
Energy Resources
Conservation Board,
the Province of
Alberta, Canada
Energy Resources
Conservation Board,
the Province of
Alberta, Canada
Benfield Corporation
Pittsburgh, PA
February 20, 1981 Getty Oil Company
Houston, Texas
April 14, 1981
April 29, 1981
May 12, 1981
May 27, 1981
July 1, 1981
July 1981
September 3, 1981
Home Oil Company, Ltd.
Alberta, Canada
Ralph M. Parsons Co.
Pasadena, California
Lone Star Gas Company
Warwink, Texas
Northern Natural Gas
Company, Midland,
Texas
Colorado Interstate
Gas Company, Table Rock,
Wyomi ng
(Subcontracted report)
Ralph M. Parsons Co.
Pasadena, California
Exxon Chemical Co.
Baton Rouge, LA
Data or Information
Sour Natural Gas Industry
Guidelines (Existing)
Sour Natural Gas Industry
Guidelines (newly promulgated)
Cost information for the Benfield
Sweetening Process for sour
natural gas
Comments and recommendations on
sulfur recovery operations
Technical and cost data on the
modified Claus sulfur recovery
facility for Carstairs-Crossfield
plant
Information and assumptions for
developing design criteria and
cost estimates for sulfur recovery
study in onshore sour gas
production facilities, presented
in Appendix E
Recovered sulfur production from
sour natural gas stream (acid gas)
at Warwink Gas Treating Plant
Recovered sulfur production from
sour natural gas stream (acid gas)
at Hobbs Sulfur Recovery facility
Recovered sulfur information
Sulfur Recovery Study, Onshore
Sour Gas Production Facilities,
presented in Appendix E
EPA requested costs information,
including total operating costs
and fixed-capital costs of the
Baytown, Texas, refinery sulfur
recovery plant by authority under
Section 114 of the Clean Air Act
(42 U.S.C. 7414)
A-3
-------
Date
September 3, 1981
Source
Pursue Gas Processing
and Petrochemicals Co.
Jackson, Mississippi
September 3, 1981 Union Oil Company
Wilmington, California
A.2 PLANT VISITS
Date
December 18, 1979
Company
Exxon Company, U.S.A.
Jay Field, Florida
December 19, 1979 Phillips Petroleum
Chatham, Mississippi
August 8, 1980
August 15, 1980
Shell Canada Resources,
Ltd.
Waterton, Alberta,
Canada
Union Oil Company
Chunchula, Alabama
Data or Information
EPA requested costs information,
including total operating costs
and fixed-capital costs of the
Brandon, Mississippi, onshore
production sulfur recovery plant
by authority under Section 114
of the Clean Air -Act
(42 U.S.C. 7414)
EPA requested costs information,
including total operating costs
and fixed-capital costs of the
Los Angeles, California, refinery
sulfur recovery plant by authority
under Section 114 of the Clean
Air Act (42 U.S.C. 7414)
Plant/Information
Blackjack Creek sulfur recovery
facility/gained familiarity with
process equipment and operating
conditions (sour natural gas
sweetening, sulfur recovery, and
tail gas cleanup operations),
information confidential
Chatham sulfur recovery facility/
gained familiarity with process
equipment and operating conditions
(sour natural gas sweetening and
sulfur recovery operations)
Waterton sulfur recovery
facility/gained familiarity with
process equipment and operating
conditions (sour natural gas
sweetening, sulfur recovery, and
tail gas cleanup operations)
Chunchula sulfur recovery
facility/gained familiarity with
process equipment and operating
conditions (sour natural gas
sweetening and sulfur recovery
operations)
A-4
-------
Date
August 19, 1980
August 21, 1980
August 22, 1980
August 26, 1980
September 9, 1980
Company
Getty Oil Company
Streetman,
Texas
Intratex Gas Company,
(Houston Natural Gas),
Pecos, Texas
Warren Petroleum Company,
(Gulf Oil), Monument,
New Mexico
Shell Oil Company
Brandon, Mississippi
Warren Petroleum
Company, (Gulf Oil),
Kildeer, North Dakota
Plant/Information
Teas sulfur recovery facility/
gained-familiarity with process
equipment and operating conditions
(sour natural gas sweetening and
sulfur recovery operations)
Mi Vida sulfur recovery facilities/
gained familiarity with process
equipment and operating conditions
(sour natural gas sweetening and
sulfur recovery operations),
information confidential
Monument sulfur recovery facility/
gained familiarity with process
equipment and operating conditions
(sour natural-gas sweetening and
sulfur recovery operations),
information confidential
Thomasville sulfur recovery
facility/gained familiarity with
process equipment and operating
conditions (sour natural gas
sweetening and sulfur recovery
operations)
Little Knife sulfur recovery
facility/gained familiarity with
process equipment and operating
conditions (sour natural gas
sweetening, sulfur recovery, and
tail gas cleanup operations),
information confidential
A.3 EMISSION SOURCE TESTING
Date
March 5-27, 1981
Company
Warren Petroleum's
Monument Plant Facility,
Monument, New Mexico
April 8-12, 1981
Getty Oil
Facility,
Texas
s New Hope
Mt. Pleasant
Data or Information
Emission rates of S02, H2S, total
reduced sulfur, and NO ; liquid
sulfur production rate; sulfur
recovery efficiency, plant
operating conditions. Developed
by and received from EPA/EMB.
Emission rates of S02, H2S, total
reduced sulfur, and NO ; liquid -
sulfur production rate; sulfur
recovery efficiency, plant
operating conditions. Developed
by and received from EPA/EMB.
A-5
-------
Date
May 12-18, 1981
Company
Shell Oil's
Thomasville Facility,
Brandon, Mississippi
1980, 1979, 1978, Exxon Company, U.S.A.
and 1977 Jay Field, Florida
1975, 1974, 1973, Shell Oil Company
and 1972 Cass County, Texas
1975, 1974
and 1973
June 4-10, 1975
Shell Oil Company
Karnes County, Texas
Exxon Company, U.S.A.
Jay Field, Florida
November 12, 1973 Exxon Company, U.S.A.
Flomaton, Alabama
September 24-27, Aquitaine of Canada, Ltd.
1974 Ram River, Alberta,
Canada
November 6-8, 1974 Chevron Standard, Ltd.
Fox Creek, Alberta,
Canada
Plant/Information
Emission rates of SO, H2S, total
reduced sulfur, and NO ; liquid
sulfur production rate; sulfur
recovery efficiency, plant
operating conditions. Developed
by and received from EPA/EMB.
Annual stack test reports (last
four years) on Blackjack Creek
sulfur recovery facility. Supplied
by the facility.
General information, flow diagrams,
and operation and test data on
Bryans Mill plant sulfur recovery
facility. Supplied by the facility.
General information, flow diagrams,
and operation and test data on
Person plant sulfur recovery
facility. Supplied by the facility.
Air pollution emission test,
composition and flow data on
Santa Rosa plant sulfur recovery
facility. Developed by and
received from EPA.
Performance test, composition
and flow data on Flomaton sulfur
recovery facility. Developed by
and received from EPA.
Air pollution emission test on
Ram River plant sulfur recovery
facility. Developed by and
received from EPA.
Emission tests on Fox Creek plant
sulfur recovery facility.
Developed by and received from
EPA.
A.4 MEETINGS WITH INDUSTRY
Date
December 1979
Attendees
American Petroleum Institute
(Environmental Task Force)
Onshore natural gas
production
A-6
-------
Date
July 1980
July 21-22, 1980
May 1, 1981
January 28, 1982
Company
American Institute of Chemical
Engineers, Philadelphia, PA
American Petroleum Institute
(Environmental Task Force)
and other representatives of
the onshore natural gas
production industry
American Petroleum Institute
(Environmental Task Force)
American Petroleum Institute
(Environmental Task Force)
A.5 REVIEW PROCESS
Date
August 14, 1981
September 25, 1981
September 25, 1981
Company
TRW
TRW
TRW
Plant/Information
Seminars concerning sour
natural gas processing
technologies
Exchange of information
among TRW, EPA and the
industry on various
agenda concerning onshore
natural gas production
Exchange of information
among TRW, EPA and the
industry on model plants,
Parsons' cost estimations,
and regulation format,
etc.
A presentation on cost
effectiveness of the
Claus 2-stage technology
when applied to sizes
less than 10.2 Mg/d sulfur
intake. A presentation
on projected growth in the
industry for 1983-1987.
Discussions among TRW, EPA
and the industry on the
items in the Agenda
involving both S02 and
VOC NSPS developments.
Data or Information
EPA concurs on the baseline control
levels, the form/number of model
plants and the regulatory
alternatives
Draft Chapters 3, 4, 5, and 6 mailed
to the industry.
Finalized concurrence memo on
baseline controls, seven model
plants and six regulatory
alternatives.
A-7
-------
Date
October 30, 1981
Company
TRW
December 23, 1981
February 1982
April 9, 1982
TRW, EPA
25 natural gas
production companies
TRW
Data or Information
Submittal of tabular costs
(Tables 8-1 through 8-42) to EPA
to be included in Chapter 8 of the
Background Information Document;
(cost effectiveness, incremental
cost effectiveness of the six
regulatory alternatives for each
of the seven model plants, total
annualized costs, sulfur and steam
credits, net annualized costs per
megagram recovered sulfur, fixed-
capital costs, sulfur recovery
efficiency and S02 emissions, and
sweetening operations costs for
all the model plants)
Decision on basis for the standard
recommending NSPS development,
including recommended size cutoffs
for affected facilities.
Analyzed industry comments on Draft
Chapters 3-6 of the Background
Information Document
Draft copies submitted to EPA of
the Background Information
Document, preamble, and
regulation for the EPA Working
Group review
A-8
-------
APPENDIX B - INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
-------
Table B-l. INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background Information Document (BID)
ro
i
ro
Background, description, and
purpose of the regulatory
alternatives and the statutory
authority.
The relationship to other
actions and proposals signi-
ficantly affected by the regu-
latory alternatives.
Industry affected by the
regulatory alternatives.
Specific processes affected
by the regulatory alternatives.
Applicable control technologies.
2. Alternatives to the action.
The regulatory alternatives from which standards will be chosen
are summarized in Chapter 1, Section 1.1, as is the statutory
authority for proposing standards.
To the extent possible, other EPA regulations and OSHA regu-
lations which apply to the affected industries are detailed in
Chapter 8, Section 8.2 and are considered in the economic impact
study in Chapter 9.
The industry and emission sources within the industry affected
by the regulatory alternatives are listed in Chapter 3.
The specific processes and facilities affected by the regulatory
alternatives are summarized in Chapter 3, Section 3.2.
The sulfur recovery technologies which can be applied to reduce
sulfur emissions from onshore natural gas production facilities
and the emission reductions which have been achieved by these
control technologies are described in detail in Chapter 4.
The various categories of alternatives to the actions which
were considered are listed below.
a. Alternative regulatory approaches. The alternative
approaches for regulating S02 emissions under Section 111 of
the Clean Air Act are outlined in Chapter 6.
b. Alternative control devices. The alternative control
devices that could be utilized by the regulatory alternatives,
and the reasons for selecting these particular alternatives
are outlined in Chapter 4.
(continued)
-------
Table B-l. CONTINUED
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background Information Document (BID)
DO
CO
Agency's comparative evaluation
of the beneficial and adverse
environmental, health, social,
and economic effects of each
reasonable alternative.
Environmental impact of the
regulatory alternatives.
Primary impact.
Primary impacts are those that
can be attributed directly to
the action, such as reduced
levels of specific pollutants
brought about by a new standard
and the physical changes that
occur in the various media with
this reduction.
a. A discussion of the Agency's comparative evaluation of the
various alternative regulatory approaches for sulfur dioxide
emissions from onshore natural gas production facilities can be
found in Chapter 6, Section 6.2.
b. A summary of the beneficial and adverse environmental
effects of the regulatory alternatives can be found in
Chapter 7. A detailed description of the economic impacts
of each alternative control level, including the capital
and annualized costs to the industry, can be found in
Chapter 8. The socioeconomic impacts of the regulatory
alternatives including potential plant closures and
maximum price increases in sweetened natural gas can be
found in Chapter 9.
Air impact analysis shows the primary impacts in Chapter 7,
Section 7.1.2.
(continued)
-------
Table B-l. CONCLUDED
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background Information Document (BID)
do
4.
a.
b.
Secondary impact.
Secondary impacts are indirect
or induced impacts. For example,
mandatory reduction of specific
pollutants brought about by a
new standard could result in the
adoption of control technology
that exacerbates another pollution
problem and would be a secondary
impact.
Other considerations.
Adverse impacts which cannot
be avoided should a regulatory
alternative be implemented.
Irreversible and irretrievable
commitments of resources that
would be involved with the
regulatory alternatives, should
one be implemented.
Other environmental impacts of the individual controls that can
be used to meet the regulatory alternatives are identified
qualitatively in Chapter 7, Sections 7.1.3, 7.2, and 7.3.
The secondary water impacts of the alternative control levels
are quantified in Chapter 7, Section 7.2.
The energy consumption impact of the alternative control levels
is quantified in Chapter 7, Section 7.4.
A summary of the potential adverse environmental and health
impacts of the regulatory alternatives and a discussion of
the significance of each impact can be found.in Chapter 7.
Factors which already exist to eliminate some of the
potential adverse impacts are identified. Those adverse
impacts that are unavoidable are also identified, along
with any steps which can be taken to minimize them.
Irreversible and irretrievable resources that would be
involved in the proposed action are discussed in Chapter 7,
Section 7.5.1.
-------
APPENDIX C - EMISSION SOURCE TESTS DATA
-------
The emission source tests data on ten Claus sulfur recovery facilities
gathered during the development of the proposed Onshore Natural Gas
Production New Source Performance Standards are summarized in this
appendix. As part of the data gathering process, detailed emission
source tests were conducted by EPA's Emissions Measurement Branch at
three facilities. These facilities are Warren Petroleum's Monument
plant facility, Getty Oil's New Hope facility and Shell Oil's Thomasville
facility and are described in Section C.I. These facilities represent
the existing industry practice for Claus sulfur recovery technology, for
the size range of sulfur intake to sulfur recovery unit, and for the
hydrogen sulfide (H2S) and carbon dioxide (C02) volume percent ratio in
the acid gas feed stream to sulfur recovery unit. The three facilities
are described; the source testing methods used are identified; and the
detailed data obtained during the tests program are presented. The
emission source tests data that were gathered from other sources for
seven additional facilities are also described. The data indicate a
range of sulfur recovery efficiencies expected for Claus facilities in
relation to the H2S and C02 concentrations in the'acid gas feed stream
and the technology utilized.
C.I PROCESS DESCRIPTION OF THE FACILITIES AND THE TESTS RESULTS
C.I.I Warren Petroleum's Monument Plant Facility
Warren Petroleum's Monument plant facility is a sour natural gas
processing facility that combines removal of associated natural gas
liquids, sour natural gas sweetening, and liquid sulfur recovery. The
natural gas feed to the plant is produced from the surrounding wells.
First, the natural gas liquids are separated, and then acid gas (H2S and
C02) in the natural gas is separated using an ethanolamine sweetening
unit. The acid gas from the sweetening unit is delivered to a Claus
sulfur recovery plant. In the Claus process sulfur is recovered from
the acid gas via a vapor phase catalytic reaction. The natural gas
processed at the facility has a higher concentration of C02 than H2S,
and since both are removed by the sweetening unit, the acid gas feed to
the Claus plant is relatively dilute in H2S content (about 24 percent by
C-2
-------
volume H2S in the acid gas feed during the test period). The facility
was treating approximately 19.9 NrnVs sour natural gas (60.7 MMscf/day)
and was producing an average of 18.3 Mg/d liquid sulfur (18 LT/D) during
the test period. A simplified flow diagram for the facility is shown in
Figure C-l. The Claus plant is a three-stage catalytic unit. Liquid
sulfur from the Claus plant is collected in a below-ground storage tank
and sold. The Claus plant tail gas is routed to an incinerator, where
any remaining H2S and other reduced sulfur compounds in the tail gas are
oxidized to S02 prior to release into the atmosphere.
Testing of the Claus plant incinerator stack gas was performed to
determine the level of S02, H2S, and total reduced sulfur (TRS) emissions.
In addition, the liquid sulfur production rate was monitored in order to
determine the sulfur recovery efficiency of the Claus plant. Table C-l
lists the various parameters measured during the testing as well as the
sampling and analysis methods used to measure these parameters.
The test results for the S02, H2S, and TRS concentration levels are
summarized in Table C-2. Table C-2 also presents liquid sulfur produc-
tion rates, S02 (including TRS expressed as S02) emission rates and
sulfur recovery efficiencies for the Claus plant during the testing
period. Figure C-2 graphically presents sulfur recovery efficiency,
stack S02 (including TRS) emission rate, and liquid sulfur production on
a daily basis for the testing period. Table C-3 presents information on
the daily average velocity, temperature, composition, and actual flow
rate of the incinerator stack gas, and Table C-4 presents daily S02, H2S
(as S02) and TRS (as S02) emission rates. The NO test results are
/\
summarized in Table C-5, and the normal plant operating conditions
during the test period are summarized in Table C-6.
Claus plant sulfur recovery efficiency for the facility was calculated
based upon the following procedure:
C-3
-------
Sweetening Unit
Sweet
Gas
Raw
Natural
Gas
Gas Liquids
Separation
Sour
Natura^
Gas
}
)
1%
)
V
<
>-
S
t
r
i
P
P
e
r
Acid
Gas
Stack Gas
Muffle
Furnace
Liquid^.
Sulfur
Sampling
Point
'Condensers
Claus Sulfur Recovery Unit
Figure C-l. Simplified flow diagram for Warren Petroleum's
Monument plant facility.
-------
Table C-l. SAMPLING/ANALYSIS PARAMETERS AND METHODOLOGY
AT WARREN PETROLEUM'S MONUMENT PLANT FACILITY
Measured parameter Methodology
Stack gas volumetric flow rate EPA Method 2
Stack gas dry molecular weight EPA Method 3
Stack gas moisture content (H20) EPA Method 4
Stack gas sulfur dioxide (S02) EPA Method 6
Stack gas nitrogen oxides (as N02) EPA Method 7
Stack gas hydrogen sulfide (H2S) EPA Method 11
Stack gas total reduced sulfur (TRS)a EPA Method 16A
Liquid sulfur production No reference method
alncludes H2S, carbon disulfide (CS2) and carbonyl sulfide (COS).
C-5
-------
Table C-2. HARREN PETROLEUM'S MONUMENT PLANT FACILITY
TEST RESULTS SUMMARY
Test
date
(1981)
3/5
3/6
3/7
3/8
3/9
3/10
3/11
3/12
3/13
? 3/17
en
3/18
3/19
3/20
3/21
3/22
3/23
3/24
3/25
3/26
3/27
Test
period
SO,, (ppm)
Range
3,040-3,580
2,900-3,980
3,550-3,730
3,800-4,350
3,390-4,250
3,190-3,470
3,250-3,420
2,540-3,280
3,730-5,140
3,640-3,740
3,230-3,590
3,070-3,470
3,390-3,910
3,430-3,580
3,380-4,430
3,140-3,770
3,440-3,730
3,510-3,560
2,520-2,950
3,150-3,330
2,520-5,140
Average
3,300
3,550
3,640
4,010
3,820
3,330
3,340
2,800
4,230
3,690
3,440
3,250
3,580
3,500
3,770
3,450
3,550
3,540
2,800
3,230
3,490
H2S TRS
(ppm) (ppm)
c c
<1 21
<1 34
<1 32
<1 c
<1 22
<1 56
1 27
2 24
<1 c
<1 22
<1 35
<1 26
<1 c
<1 48
<1 35
<1 25
<1 17
<1 19
<1 15
<1 29
S02 out
stack
kg/h Ib/h
78.0
84.0
89.3
92.4
82.1
76.3
74.3
63.2
100.3
85.3
84.9
74.3
81.8
89.4
89.6
81.6
85.9
84.8
65.3
77.5
82.0
172.0
185.1
196.9
203.6
181.0
168.1
163.7
139.4
221.2
188.0
187.1
163.7
180.3
197.0
197.5
179.8
189.3
186.9
144.0
170.8
180.8
Sulfur(s)b out
stack
Mg/d LT/D
0.94
1.01
1.07
1.11
0.99
0.91
0.89
0.76
1.21
1.03
1.02
0.89
0.99
1.08
1.08
0.98
1.03
1.02
0.78
0.94
0.99
0.92
0.99
1.05
1.09
0.97
0.90
0.88
0.75
1.19
1.01
1.00
0.88
0.97
1.06
1.06
0.96
1.01
1.00
0.77
0.92
0.97
Liquid sulfur Sulfur
production recovery
Mg/d LT/D efficiency, %
16.0
16.8
18.7
16.1
15.4
16.4
16.7
17.2
17.5
17.8
19.2
17.8
18.4
16.6
18.7
18.1
19.3
19.5
21.1
19.5
17.8
15.7
16.5
18.4
15.8
15.2
16.1
16.4
16.9
17.2
17.5
18.9
17.5
18.1
16.3
18.4
17.8
19.0
19.2
20.8
19.2
17.5
94.5
94.3
94.6
93.6
94.0
94.7
94.9
95.8
93.5
94.6
95.0
95.2
94.9
93.9
94.6
94.9
94.9
95.0
96.4
95.4
94.8
Includes S02 plus TRS expressed as S02.
Includes S02 plus TRS expressed as S.
°Test not performed.
-------
Liquid Sulfur
Production, Mg/d
Stack S02
Emissions
(includes S02
plus TRS),
kg/h
Sulfur Recovery
Efficiency, %
22
21
20
18
17
16
15
100
90
80
70
60
50
97
96
95
94
93
5 6 7 8 9 10 11 12 13 17 18 19 20 21 22 23 24 25 26 27 28
Test Date (March 1981)
Figure C-2. Summary of Liquid Sulfur Production, Stack S02 Emissions
and Sulfur Recovery Efficiency at Warren Petroleum's Monument Plant Facility.
-------
Table C-3. WARREN PETROLEUM'S MONUMENT PLANT FACILITY: DAILY AVERAGE
STACK GAS VELOCITY, TEMPERATURE, COMPOSITION AND ACTUAL FLOW RATE
DURING THE TEST PERIOD
Sampling Location: Incinerator Stack
Stack Diameter (inside): 1.4 m (55 inch)
Pi tot Tube Coefficient: 0.84
Test
date
(1981)
3/5
3/6
3/7
o 3/8
Co 3/9
3/10
3/11
3/12
3/13
3/17
3/18
3/19
3/20
3/21
3/22
3/23
3/24
3/25
3/26
3/27
% C02
(volume)
24.9
25.3
25.0
25.3
26.7
26.8
25.2
25.1
26.1
26.0
25.5
26.4
25.3
25.8
25.1
26.0
26,3
26.8
27.1
27.0
% 02
(volume)
8.5
7.5
8.0
8.3
7.5
7.5
8.0
8.2
7.8
7.9
8.1
8.0
8.1
8.1
8.3
8.0
7.9
7.6
7.6
7.8
% N2
(volume)
66.5
65.8
66.4
66.3
65.0
65.3
66.4
66.4
66.6
66.1
66.7
66.0
66.4
66.6
66.8
66.3
66.0
65.9
65.4
65.1
% H20
(volume)
15.0
15.0
15.0
15.0
15.0
15.0
15.0
15.2
15.3
15.8
13.4
14.0
14.3
13.8
14.1
13.3
14.5
15.3
15.0
15.1
* Stack
Velocity temperature
m/s ft/sec K °F
6.6
6.6
6.8
6.3
5.9
6.3
6.0
6.2
6.6
6.6
6.7
6.2
6.3
7.2
6.5
6.4
6.7
6.7
6.6
6.7
21.5
21.5
22.4
20.8
19.5
20.6
19.8
20.3
21.6
21.5
22.1
20.4
20.8
23.5
21.2
21. 0
21.9
22.0
21.5
22.0
901
899
899
899
896
899
894
894
894
900
894
904
898
899
898
900
899
900
898
897
1,163
1,158
1,158
1,158
1,154
1,159
1,150
1,150
1,150
1,160
1,150
1,168
1,156
1,159
1,156
1,160
1,158
1,160
1,157
1,155
Actual flow
rate
m3/s ACFMa
10.0
10.0
10.4
9.7
9.1
9.6
9.3
9.5
10.1
10.1
10.3
9.5
9.7
10.9
9.9
9.8
10.2
10.2
10.0
10.2
21,200
21,200
22,100
20,600
19,300
20,400
19,600
20,100
21,300
21,300
21,800
20,200
20,600
23,200
21,000
20,700
21,600
21,700
21,200
21,700
^Calculated at stack gas actual temperature and pressure.
-------
Table C-4. DAILY aS02, H2S (AS S02) AND TRS (AS S02)
EMISSIONS DURING THE TEST PERIOD
Test
date
(1981)
3/5
3/6
3/7
3/8
3/9
3/10
3/11
3/12
3/13
3/17
3/18
3/19
3/20
3/21
3/22
3/23
3/24
3/25
3/26
3/27
S02
kg/h
78.0
83.0
87.6
90.9
82.1
75.3
71.8
62.0
99.2
85.3
83.9
72.7
80.6
89.4
87.3
79.9
84.7
84.0
64.4
76.7
emission3
Ib/h
172.0
182.9
193.1
200.4
181.0
165.9
158.3
136.6
218.8
188.0
184.9
160.3
177.7
197.0
192.5
176.2
186.7
185.1
142.0
169.2
H2S emi
kg/h
<0.02
<0.02
<0.02
<0.02
<0.02
<0.02
<0.02
<0.03
0.05
<0.02
<0.02
<0.02
<0.02
<0.03
<0.02
<0.02
<0.02
<0.02
<0.02
<0.02
ssion
Ib/h
<0.05
<0.05
<0.05
<0.05
<0.05
<0.05
<0.05
<0.06
0.10
<0.05
<0.05
<0.05
<0.05
<0.06
<0.05
<0.05
<0.05
<0.05
<0.05
<0.05
TRS
kg/h
0.5
0.9
0.7
0.5
1.2
0.6
0.5
0.5
0.8
0.6
1.1
0.8
0.6
0.4
0.5
0.4
. . b
emission
Ib/h
c
1.1
1.9
1.6
c
1.1
2.7
1.4
1.2
c
1.1
1.7
1.3
c
2.5
1.8
1.3
0.9
1.0
0.8
aH2S and TRS not included.
Includes H2S, COS and CS2.
°Not available.
C-9
-------
Table C-5. DAILY NO TEST RESULTS AND STACK EMISSIONS
/\ ~
Test
Date
(1981)
3/5
3/6
3/7
3/8
3/9
3/10
3/11
3/12
3/13
3/17
3/18
3/19
3/20
3/21
3/22
3/23
3/24
3/25
3/26
3/27
Test
period
Concentration
range (ppm)
6.3 -
1.4 -
3.0 -
10.1 -
8.5 -
9.4 -
10.0 -
13.7 -
9.4 -
11.1 -
9.7 -
13.2 -
11.4 -
b
10.7 -
13.7 -
10.8 -
8.6 -
9.3 -
10.8 -
1.4 -
11.6
4.7
8.5
10.9
10.0
11.2
11.7
14.4
10.3
13.0
11.2
18.1
13.4
b
13.9
14.3
12.2
12.5
10.8
12.0
18.1
Average
concentration
(ppm)
8.7
<4.1
5.3
10.6
9.0
10.7
10.7
14.0
9.7
12.1
10.5
15.3
12.5
b
12.3
14.0
11.5
9.9
12.0
11.3
10.1
Average3 NO
emissions
kg/h Ib/h
0.15
<0.07
0.10
0.17
0.14
0.17
0.17
0.23
0.16
0.20
0.19
0.25
0.20
b
0.21
0.24
0.20
0.17
0.20
0.20
0.32
<0.15
0.21
0.38
0.31
0.38
0.37
0.50
0.36
0.44
0.41
0.55
0.45
b
0.46
0.52
0.44
0.38
0.44
0.43
11.04
NO expressed as N02.
3 x
Sample not taken.
C-10
-------
Table C-6. WARREN PETROLEUM'S MONUMENT PLANT FACILITY
OPERATING CONDITIONS DURING THE TEST PERIOD
(1) Sour natural gas volumetric flow rate to the sweetening unit:
Average: 19.9 Nm3/s(60.7 MMscf/day)a
Maximum: 20.4 Nm3/s(62.2 MMscf/day)
Minimum: 19.4 Nm3/s(59.1 MMscf/day)
(2) Concentration of H2S in sour natural gas entering the sweetening
unit (volume basis):
Average: 0.79%
Maximum: 1.03%
Minimum: 0.43%
(3) Acid gas volumetric flow rate to the Claus unit:
Average: 0.70 Nm3/s(2.12 MMscf/day)
Maximum: 0.75 Nm3/s(2.29 MMscf/day)
Minimum: 0.67 Nm3/s(2.04 MMscf/day)
(4) Acid gas composition (dry volume basis):
H2S% C02%
Average: 24.0 76.0
Maximum: 24.5 75.5
Minimum: 22.5 77.5
(5) Catalyst bed temperatures (average):
Inlet Outlet
1st Reactor 478 K (400°F) 587 K (596°F)
2nd Reactor 478 K (400°F) 493 K (427°F)
3rd Reactor 478 K (400°F) 480 K (405°F)
(6) Catalyst weights:
Reactor Bed #1 6,804 kg (15,000 Ibs)
Reactor Bed #2 8,165 kg (18,000 Ibs)
Reactor Bed #3 6,804 kg (15,000 Ibs)
(7) Dates catalyst beds changed:
Bed #1 August 1980
Bed #2 and Bed #3 March 1977
(continued)
C-ll
-------
Table C-6. Concluded
(8) Catalyst life expectancy:
3 years to 5 years
(9) Design sulfur recovery efficiency :
94.7%
Standard conditions: 288.7 K (60°F), 1.01035 x 10s Pa(29.92 in. Hg).
-------
(1) FLOW RATES
o Actual cubic meter per second (ACMS)
ACMS = Velocity x Stack Cross Sectional Area
Example: Based on average values of the test dated March 7
ACMS = 6.8 x (1'4 ml2 x n
J C w i
ACMS =10.4 m3/s
o Dry standard cubic meter per second (DSCMS) @ 288.7 K (60°F) and
1.01035 x 10s Pa (29.92 in. Hg)
ncrMc - A^MC Barometric Pressure Standard Temp „ , fv,, ,, • „
DSCMS - ACMS x standard pressure x Stack Tenp x 1~frj£j10n
Example: Based on average values of the test dated March 7
DSCMS = 10 4 fACMS^ x 0-88473 x 10* Pa 288.7 K Q_Q „,
UbLMb iu.4 tALMbj x ^ Q1035 x 10b Pa X 899 K x U U-1SJ
DSCMS = 2.5 mVs
(2) EMISSION RATES
o Emission Rates - S02 and TRS (kg/h)
Emission Rate = Concentration of Compound (PPm,dry) x DSCM$ x
compound mole wt
molar volume
Example: Based on average values of the test dated March 7
S02 Emission Rate = 3,640 (ppm^dry) x ^ ^S x O^kg SO,
60 sec 60 min
min h
S02 Emission Rate =88.3 kg/h
C-13
-------
Similarly, for a TRS concentration of 34 ppm dry, the TRS Emission
Rate is 0.8 kg/h.
Note: TRS emission rates are expressed as S02; total S02 emission
rate is therefore the sum of S02 and TRS emission rates.
(3) CLAUS PLANT SULFUR RECOVERY EFFICIENCY
Recovery Efficiency - Sulfur uur Emitted
where:
Sulfur recovered = liquid sulfur production, (Mg/d)
Sulfur emitted = S02 + TRS emission rates (expressed as
elemental sulfur), (Mg/d)
Example: Based on average values of the test dated March 7
Sulfur Recovery Efficiency =
_ 18.7 Mg/d _ 10Q%
1ft 7 Mn/d + lYftft i + n ^ kg s°2 Y 32 kg S Mg 24 h-,
18. 7 Mg/d + [(88.3 + 0.8)-^—^ x 64 kgaS02 x 1,000 kg x ~d~]
Sulfur Recovery Efficiency = 94.6%
C.I. 2 Getty Oil's New Hope Facility2
Getty Oil's New Hope Facility is a sour natural gas processing
facility that combines removal of associated natural gas liquids, sour
natural gas sweetening, and liquid sulfur recovery. After the natural
gas liquids are removed, the natural gas is sweetened using a diglycolamine
sweetening unit. Liquid sulfur is recovered from the acid gas generated
in the sweetening process by a Claus sulfur recovery unit. The natural
gas processed at the facility contains more H2S than C02, and therefore,
H2S concentration in the acid gas feed to the Claus plant is relatively
high (about 55 percent by volume H2S in the acid gas feed during the
test period). The facility was treating approximately 8.9 Nm3/s sour
natural gas (27.0 MMscf/ day) and was producing an average of 131.1 Mg/d
liquid sulfur (128 LT/D) during the test period. A simplified flow
diagram for the facility is shown in Figure C-3. The Claus plant is a
dual-train, two-stage catalytic unit, with the third catalytic reactor
C-14
-------
Sweetening Unit
Sweet
Ca*
Raw
Natural
Gas
o
>-*
en
Cas
Liquids
Separation
Sour
Natural
Gas
«
b
s
0
r
b
e
Y
v
<
)-
Acid
Gas
Stack Gas
Saaplint
Point
Incinerator
Claus Sulfur Recovery Unit
Figure C-3. Simplified flow diagram for Getty Oil's New Hope Facility.
-------
being common to both the trains. Liquid sulfur from the Glaus plant is
collected in a below-aground storage tank and sold. The Claus plant tail
gas is routed to an incinerator to oxidize the residual H2S and other
reduced sulfur compounds to S02 prior to emission to the atmosphere.
Testing of the Claus plant incinerator stack gas was performed to
determine the level of S02, H2S, and TRS emissions from the stack. In
addition, the liquid sulfur production rate was monitored in order to
determine the sulfur recovery efficiency of the Claus plant. The various
parameters measured during the testing at the facility and the sampling
and analysis methods used to measure these parameters are listed in
Table C-7.
The test results for the S02, H2S, and TRS concentration levels are
summarized in Table C-8. Table C-8 also presents liquid sulfur production
rates, S02 (including TRS expressed as S02) emission rates and sulfur
recovery efficiencies for the Claus plant during the testing period.
Figure C-4 graphically presents the sulfur recovery efficiency, stack
S02 (including TRS) emission rate, and liquid sulfur production on a
daily basis for the testing period. Table C-9 presents information on
the daily average velocity, temperature, composition, and actual flow
rate of the incinerator stack gas and Table C-10 presents daily S02, H2S
(as S02) and TRS (as S02) emission rates. The NO test results are
A
summarized in Table Oil, and the normal plant operating conditions
during the test period are listed in Table C-12.
Claus plant sulfur recovery efficiency for the facility was calculated
based upon the following procedure:
(1) FLOW RATES
o Actual cubic meter per second (ACMS)
ACMS = Velocity x Stack Cross Sectional Area
Example: Based on average values of the test dated April 8
ACMS = 17 2 meter x C1-2446 m)2 * n
sec 4
016
-------
Table C-7. SAMPLING/ANALYSIS PARAMETERS AND METHODOLOGY
AT GELL OIL'S NEW HOPE FACILITY
Measured parameter
Methodology
Stack gas volumetric flow rate
Stack gas dry molecular weight
Stack gas moisture content (H20)
Stack gas sulfur dioxide (S02)
Stack gas nitrogen oxides (as N02)
Stack gas hydrogen sulfide (H2S)
Stack gas total reduced sulfur (TRS)(
Liquid sulfur production
EPA Method 2
EPA Method 3
EPA Method 4
EPA Method 6
EPA Method 7
EPA Method 11
EPA Method 16A
No reference method
Includes H2S, CS2 and COS.
C-17
-------
Table C-8. GETTY OIL'S NEW HOPE FACILITY
TEST RESULTS SUMMARY
o
i
00
Test
date
(1981)
4/8
4/9
4/10
4/11
4/12
Test
period
S02 (ppm)
Range
8,300 -
8,950 -
9,360 -
8,930 -
8,850 -
8,300 -
9,840
13,600
10,300
9,370
9,480
13,600
Average
8,950
10,520
9,950
9,080
9,150
9,517
H2S (ppm)
Range
425 -
446 -
333 -
331 -
144 -
144 -
662
925
1,800
402
408
1,800
Average
545
637
959
359
244
549
TRS
(ppm)
1,050
1,460
977
657
787
972
Stack S02a
kg/h Ib/h
593
710
536
506
518
573
1,318
1,565
1,181
1,116
1,141
1,264
Stack .
Sulfur (S)D
Mg/d LT/D
7.0
8.4
6.3
6.0
6.1
6.8
7.1
8.5
6.4
6.1
6.2
6.9
Liquid sulfur
production
Mg/d LT/D
144.7
146.2
123.2
113.0
113.0
128.0
147.0
148.5
125.2
114.8
114.8
130.1
Sulfur
recovery
efficiency, %
95.4
94.6
95.1
95.0
94.9
95.0
Includes S02 plus TRS expressed as S02.
•'includes S02 plus TRS expressed as S.
-------
150
Liquid Sulfur 140
Production, Mg/d130
120
110
Stack S02
Emissions
(includes S0«
plus TRS),
kg/h
Sulfur
Recovery
700
600
500
96
95
Efficiency, % 94
10
11
12
Test Date (April 1981)
Figure C-4. Summary of Liquid Sulfur Production, Stack S0? Emissions
and Sulfur Recovery Efficiency at Getty Oil's New Hope Facility.
C-19
-------
Table C-9. GETTY OIL'S NEW HOPE FACILITY: DAILY AVERAGE STACK GAS
VELOCITY, TEMPERATURE, COMPOSITION AND ACTUAL FLOW RATE
DURING THE TEST PERIOD
Sampling Location: Incinerator Stack
Stack Diameter (inside): 1.24 m (49 inches)
Pitot Tube Coefficient: 0.84
o
i
ro
o
Test
date
(1981)
4/8
4/9
4/10
4/11
4/12
Stack
% C02
(volume)
16.
16.
19.
17.
17.
2
9
2
3
1
% 02
(volume)
5.4
4.8
3.0
5.3
5.4
% N2
(volume)
75.3
75.6
74.3
74.3
74.3
% H20
(volume)
26.6
27.5
29.6
26.3
26.9
Velocity
m/s ft/sec
17.2
17.6
14.1
15.5
15.6
56.5
57.6
46.4
51.0
51.3
temperature
K °F
725
729
694
753
750
845
852
790
895
890
Actual flow
rate
m3/s ACFMa
20.9
21.3
17.2
18.9
19.0
44,300
45,200
36,400
40,000
40,300
Calculated at stack gas actual temperature and pressure.
-------
Table C-10. DAILY aS02, H2$ (AS S02) AND TRS (AS S02)
EMISSIONS DURING THE TEST PERIOD
Test
date
(1981)
4/8
4/9
4/10
4/11
4/12
so2
kg/h
535
621
490
472
476
emission3
Ib/h
1,180
1,370
1,080
1,040
1,050
H2S
kg/h
33
39
46
19
13
emission
Ib/h
72
87
101
41
28
TRS
kg/h
63
88
46
34
41
emission
Ib/h
138
195
101
76
91
aH2S and TRS not included.
blncludes H2S, COS and CS2-
C-21
-------
Table Oil.
DAILY N0x TEST RESULTS AND STACK EMISSIONS
Test
date
(1981)
4/8
4/9
4/10
4/11
4/12
Concentration
range (ppm)
<3.0 - 13.0
<3.0 - <13.0
<3.0
<3.0
<3.0
Average
concentration
(ppm)
<6.3
<6.3
<3.0
<3.0
<3.0
Average
emissi
kg/h
<0.3
<0.3
<0.1
<0.1
<0.1
aNO
onsx
Ib/h
<0.6
<0.6
<0.3
<0.3
<0.3
NO expressed as N02.
C-22
-------
Table C-12. GETTY OIL'S NEW HOPE FACILITY
OPERATING CONDITIONS DURING THE TEST PERIOD
(1) Sour natural gas volumetric flow rate to the sweetening unit:
Average: 8.9 NnrVs (27.0 MMscf/day)a
Maximum: 9.2 NmVs (28.0 MMscf/day)
Minimum: 8.6 NmVs (26.1 MMscf/day)
(2) Concentration of H2S in sour natural gas entering the sweetening
unit (volume basis):
Average: 7%
Range: 6.5% - 10%
(3) Acid gas volumetric flow rate to the Claus unit:
Average: 2.0 NmVs (6.1 MMscf/day)
Maximum: 2.1 NmVs (6.4 MMscf/day)
Minimum: 1.9 NmVs (5.7 MMscf/day)
(4) Acid gas composition (dry basis):
H2S% C02%
Average: 55.0 45.0
Maximum: 55.6 44.4
Minimum: 54.4 45.6
(5) Catalyst bed temperatures:
Inlet Outlet
1st Train:
1st Reactor 490 K (423°F) 555 K (539°F)
2nd Reactor 504 K (447°F) 518 K (473°F)
2nd Train:
1st Reactor 490 K (422°F) 565 K (557°F)
2nd Reactor 505 K (450°F) 530 K (495°F)
Common Bed Reactor Average of Inlet and Outlet:
3rd Reactor 500 K (400°F)
(6) Dates catalyst beds changed:
1st Train (1st Reactor and 2nd Reactor) August 1980
2nd Train (1st Reactor and 2nd Reactor) August 1980
Common Bed Reactor 1972
(7) Design sulfur recovery efficiency :
96%
Standard conditions: 288.7 K (60°F), 1.01035 x 10s Pa (29.92 in. Hg).
Supplied by the facility.
C-23
-------
ACMS = 20.9 mVs
o Dry standard cubic meter per second (DSCMS) @ 288.7 K (60°F) and
1.01035 x 105 Pa (29.92 in. Hg)
ncrMc - APMC „ Barometric Pressure Standard Temp u -, fv,,_4.,-.._
UoLrlo ~~ rtl/rlo X r-j_ I i r* X /.. ' i T X X~Ti aC UI On
Standard Pressure Stack Temp H Q
Example: Based on average values of the test dated April 8
DSPMS = ?n 9 fAPKm y 1-011363 x 105 Pa 288.7 K n_n
uauna ^u.s ^uii; x 1-01035 x 10b Pa x 725 K x u u'
DSCMS =6.1 m3/s
(2) EMISSION RATES
o Emission rates - S02 and TRS (kg/h)
Emission Rate = Concentration of^Compound (PPm,dry) >
Compound Mole wt
molar volume
Example: Based on average values of the test dated April 8
S02 Emission Rate = 8,950 (ppm^SO,, dry) x ^ m&/s x 0.064^ SO, >
60 sec 60 min
min h
S02 Emission Rate = 529.6 kg/h
Similarly for a TRS concentration of 1,050 ppm dry, the TRS emission
rate is 62.3 kg/h.
Note: TRS emission rates are expressed as S02; total S02 emission
rate is therefore the sum of S02 and TRS emission rates.
(3) CLAUS PLANT SULFUR RECOVERY EFFICIENCY
Recovery Efficiency = .- ,.- K ; <- -, ^ i=—r-rr—r
^o-uvc.jr i_iiiuicn>_y Sulfur Recovered + Sulfur Emitted
C-24
-------
where:
Sulfur recovered = liquid sulfur production, Mg/d
Sulfur emitted = S02 + TRS emission rates (both expressed as
elemental sulfur), Mg/d
Example: Based on average values of the test dated April 8
Sulfur Recovery Efficiency =
147.0 Mg/d
147.0 Mg/d + [(529.6 kg/h S02+62.3 kg/h TRS) x ^ ^ ^ x 1>Q$j kg
Sulfur Recovery Efficiency = 95.4%
C.I.3 Shell Oil's Thomasville Facility3
Shell Oil's Thomasville facility is a sour natural gas processing
facility engaged in sweetening of the sour gas and recovering sulfur
from the acid gas generated in the sweetening operation. As the gas is
dry, no liquids are associated with the gas. Natural gas feed to the
plant is produced from six local gas wells. The gas is sweetened in a
Sulfinol sweetening unit. The Sulfinol unit was treating about 28.5 NmVs
sour natural gas (87 MMscf/day) during the test period. The acid gas
stream from the Sulfinol unit is relatively rich in H2S (about 84.4 percent
by volume H2S in the acid gas feed during the test period). The acid
gas stream is fed to a Claus sulfur recovery plant. The Claus plant was
producing an average of 1,174 Mg/d liquid sulfur (1,155 LT/D) during the
test period. A simplified flow diagram of the facility is shown in
Figure C-5. The Claus plant is a three-stage catalytic unit. A portion
of the acid gas feed stream bypasses the reaction furnace and is used to
fuel the three in-line burners (for the purpose of reheating). Liquid
sulfur from the Claus plant is collected in a below-ground storage tank
and sold. The Claus plant tail gas is routed to an incinerator to
oxidize any residual H2S and other reduced sulfur compounds to S02 prior
to release to the atmosphere.
Testing of the Claus plant incinerator stack gas was performed to
determine the level of S02, H2S, and TRS emissions. In addition, the
liquid sulfur production rate was monitored in order to determine sulfur
C-25
-------
Sweetening Unit
Sweet
Natural Gas
o
I
no
CTl
Stack Gas
Liquid.-
Sulfur
CW
Catalyst
Beds
Sampling
Point
Incinerator
Condensers
Claus Sulfur Recovery Unit
Figure C-5. Simplified flow diagram for Shell Oil's Thomasville Facility.
-------
recovery efficiency of the Claus plant. Table C-13 lists the various
parameters measured during the testing and the sampling and analysis
methods used to measure these parameters.
The test results for the S02, H2S, and TRS concentration levels are
summarized in Table C-14. Table C-14 also presents liquid sulfur
production rates, S02 (including TRS expressed as S02) emission rates,
and sulfur recovery efficiencies for the Claus plant during the test
period. Figure C-6 graphically presents sulfur recovery efficiency,
stack S02 (including TRS) emission rate, and liquid sulfur production on
a daily basis for the test period. Table C-15 presents the daily average
velocity, temperature, composition and actual flow rate of the incinerator
stack gas and Table C-16 presents daily S02, H2S (as S02) and TRS (as
S02) emission rates. The NO test results are summarized in Table C-17.
J\
Table C-18 lists normal plant operating conditions during the test
period. In addition, Table C-19 shows a comparison of the test results
obtained by the EPA/Emissions Measurement Branch and the results of the
tests conducted at the same time by the company's operations support
group trailer laboratory.
Claus plant sulfur recover efficiency for the facility was calculated
based upon the following procedure:
(1) FLOW RATES
o Actual cubic meter per second (ACMS)
ACMS = Velocity x Stack Cross Sectional Area
Example: Based on average values of the test dated May 12
ACMS = 23.0
ACMS = 151.5 mVs
o Dry standard cubic meter per second (DSCMS) @ 288.7 K (60°F)
and 1.01035 x 10s Pa (29.92 in. Hg)
ncmc - APUC v Barometric Pressure „ Standard Temp , ,. f.
DSCMS - ACMS x standard Pressure x Stack TempH x faction
M2U
C-27
-------
Table C-13. SAMPLING/ANALYSIS PARAMETERS AND METHODOLOGY
AT SHELL OIL'S THOMASVILLE FACILITY
Measured parameter
Methodology
Stack gas volumetric flow rate
Stack gas dry molecular weight
Stack gas moisture content (H20)
Stack gas sulfur dioxide (S02)
Stack gas nitrogen oxides (as N02)
Stack gas hydrogen sulfide (H2S)
Stack gas total reduced sulfur (TRS)'
Liquid sulfur production
EPA Method 2
EPA Method 3
EPA Method 4
EPA Method 6
EPA Method 7
EPA Method 11
EPA Method 16A
No reference method
Includes H2S, CS2 and COS.
C-28
-------
Table C-14. SHELL OIL'S THOMASVILLE FACILITY
TEST RESULTS SUMMARY
ro
10
Test
date
(1981)
5/12
5/13
5/14
5/15
5/18
Test
Period
S02 (ppra)
range average
8,764- 9,161
8,792- 9,352
8,615- 8,990
8,522- 8,704
9,091-10,125
8,522-10,125
8,907
9,136
8,779
8,616
9,671
9,022
H2S (ppra)
range average
13-30
20-47
43-48
16-23
23-33
13-48
19
36
46
20
28
30
TRS
(ppm)
186
314
330
245
291
273
Stack S02a
kg/h Ib/h
3,168
3,350
3,162
3,078
3,475
3,239
6,984
7,386
6,972
6,786
7,662
7,140
Stack sulfurb
Mg/d LT/D
38.0
40.2
38.0
37.0
41.7
39.0
37.4
39.6
37.4
36.4
41.0
38.4
Liquid sulfur
production
Mg/d LT/D
1,241
1,116
1,192
1,189
1,129
1,174
1,221
1,098
1,173
1,170
1,111
1,155
Sulfur
recovery
efficiency, %
97.0
96.5
96.9
97.0
96.4
96.8
alncludes S02 plus TRS expressed as S02.
^Includes S02 plus TRS expressed as S.
-------
1250
Liquid Sulfur
Production, Mg/d
1150
1100
3500
3400
Stack S02 Emissions
(includes S02 plus TRS)^3QQ
kg/h
3200
3100
3000
97
Sulfur Recovery
Efficiency, %
96 -
12 13 14 15
Test Date (May 1981)
16
Figure C-6.
Summ
and
ary of Liquid Sulfur Production, Stack S02 Emissions,
Sulfur Recovery Efficiency at Shell Oil's
Thomasville Facility.
C-30
-------
o
co
Table C-15. SHELL OIL'S THOMASVILLE FACILITY: DAILY AVERAGE STACK GAS VELOCITY,
TEMPERATURE, COMPOSITION AND ACTUAL FLOW RATE DURING THE TEST PERIOD
Sampling Location: Incinerator Stack
Stack Diameter (inside): 2.896 m (9.5 ft)
Pitot Tube Coefficient: 0.84
Test
date
(1981)
5/12
5/13
5/14
5/15
5/18
% co2
(volume)
8.1
7.9
8.4
8.3
8.6
% Q2
(volume)
2.
3.
2.
2.
2.
6
2
5
5
0
% N2
(volume)
88.6
88.4
88.5
88.6
88.7
% H20
(volume)
28.39
27.81
28.65
27.94
29.22
Velocity
m/s ft/sec
23.0
22.7
23.3
23.3
23.7
75.5
74.4
76.4
76.5
77.8
Stack
temperature
K °F
876
845
876
887
888
1,118
1,062
1,117
1,137
1,138
Actual
flow rate
m3/s ACFMa
151.5
148.7
153.4
153.9
156.2
321,000
315,000
325,000
326,000
331,000
Calculated at stack gas actual temperature and pressure.
-------
Table C-16. DAILY S02, H2S (AS S02) AND TRS (AS S02)
EMISSIONS DURING THE TEST PERIOD
Test
date
(1981)
5/12
5/13
5/14
5/15
5/18
S02 emission3
kg/h Ib/h
3,103
3,239
3,048
2,985
3,375
6,840
7,140
6,720
6,580
7,440
H2S emission
kg/h Ib/h
6.5
12.8
16.1
7.1
9.8
14.4
28.2
35.4
15.6
21.6
TRS emission
kg/h Ib/h
65.3
111.6
114.3
84.4
100.7
144
246
252
206
222
H2S and TRS not included.
Includes H2S, COS and CS2.
C-32
-------
Table C-17. DAILY NO TEST RESULTS AND STACK EMISSIONS
Testing
date
(1981)
5/12
5/13
5/14
5/15
5/18
Concentration
range (ppm)
<3.0-6.2
<3.0
<3.0-3.7
<3.0-4.7
<3.0-5.4
Average
concentration
(ppm)
<4.2
<3.0
<3.2
<3.7
<3.8
Average
N0x
emissions
kg/h Ib/h
<1.0 <2.3
<0.8 <1.7
<0.8 <1.7
<0.9 <2.0
<1.0 <2.1
NOX expressed as
C-33
-------
Table C-18. SKELLL OIL'S THOMASVILLE FACILITY
OPERATING CONDITIONS DURING THE TEST PERIOD
(1) Sour natural gas volumetric flow rate to the sweetening unit:
Average: 28.5 Nm3/s(87.0 MMscf/day)a
Maximum: 28.7 Nm3/s(87.7 MMscf/day)
Minimum: 28.5 NmVs(86.8 MMscf/day)
(2) Concentration of H2S in sour natural gas (combined from all the six
wells) entering the sweetening unit: (% H2S from the individual
gas wells ranges from 28.8% to 45.3%)
Average: 35.1%
(3) Acid gas volumetric flow rate to the Claus unit:
Average: 11.9 Nm3/s(36.4 MMscf/day)
Maximum: 12.2 Nm3/s(37.1 MMscf/day)
Minimum: 11.8 Nm3/s(36.1 MMscf/day)
(4) Acid gas composition (dry basis):
H2S% C02%
Average: 84.4 15.6
Maximum: 85.4 14.6
Minimum: 84.0 16.0
(5) Catalyst bed temperatures (average):
Inlet Outlet
1st Reactor 497 K (435°F) 603 K (625°F)
2nd Reactor 481 K (407°F) 510 K (459°F)
3rd Reactor 479 K (403°F) 486 K (415°F)
(6) Catalyst (Kaiser S-201) weights; dimensions:
Reactor Bed #1 102,285 kg (225,500 Ibs)
Reactor Bed #2 102,285 kg (225,500 Ibs)
Reactor Bed #3 102,285 kg (225,500 Ibs)
Each Bed Volume 138.8 m3 (4,902 cubic feet)
Each Bed Diameter 12.0 m (39.5 feet)
Each Bed Thickness 1.22 m (4 feet)
(7) Dates catalyst beds changed:
Bed #1, #2 and #3 April, 1979
(continued)
C-34
-------
Table C-18. Concluded
(8) Individual bed efficiency (approximate):
Bed Efficiency
#1 72%
#2 68%
#3 19%
(9) Catalyst normal life expectancy:
5 years (3 years - 5 years range)
(10) Design sulfur recovery efficiency : 97.83%
Standard conditions: 288.7 K (60°F), 1.01035 x 105 Pa (29.92 in. Hg)
Supplied by the facility.
C-35
-------
Table C-19. COMPARISON OF EPA/EMISSIONS MEASUREMENT BRANCH (EMB) TESTS RESULTS AND THE
COMPANY'S OPERATIONS SUPPORT LABORATORY TEST RESULTS
AT THE THOMASVILLE FACILITY
o
CO
Test
date
(1981)
EPA/EMB's Tests
Tests by Company's
Operations Support
Lab
EPA/EMB's Tests
Tests by Company's
5/12
5/12
5/13
5/13
% co2
(volume)
8.2
7.7
7.4
7.8
„ n - M ,n H Q Liquid sulfur Sulfur
* U2 N2 5U2 V TRS production recovery
(volume) (volume) (ppm) (ppm) (ppm) Mg/d LT/d efficiency (%)
2.5 88.6 9,161 30 186 1,241 1,221
3.5 86.4 9,460 ~ 80 1,164 1,146
3.9 88.4 9,352 40 314 1,116 1,098
3.3 86.3 9,620 56 166 1,178 1,159
97.03
96.99
96.52
97.23
Operations
Support Lab
-------
Example: based on average values of the test dated May 12
nsrMS - IM R rAPM«rt y 1.011363 x 10s Pa 288.7 K ,, Q
DSCMS - 151.5 (ACMS; x 1-01035 x 10s Pa X 876 K X u u
DSCMS = 35.8 m3/s
(2) EMISSION RATES
o Emission Rates - S02 and TRS (kg/h)
Emission Rate = Concentration of Compound (ppm?dry) x QSCMS
compound mole wt
molar volume
Example: Based on average values of the test dated May 12
8907 (PP50*'^) °'°
S02 Emission Rate = PP^*' x 35.8 mVs x 'Q x
60 sec 60 min
min x h
S02 Emission Rate = 3,093.4 kg/h
Similarly, for a TRS concentration of 186 ppm dry, the TRS Emission
Rate is 64.8 kg/h
Note: TRS emission rates are expressed as S02; total S02 emission
rate is therefore the sum of S02 and TRS emission rates.
(3) CLAUS PLANT SULFUR RECOVERY EFFICIENCY
Recovery Efficiency = Su1fur ^ffMjff Emitted
where:
Sulfur recovered = liquid sulfur production, (Mg/d)
Sulfur emitted = S02 + TRS emission rates (expressed as
elemental sulfur), (Mg/d)
Example: Based on average values of the test dated May 12
Sulfur Recovery Efficiency =
1,241 Mg/d
1,241 Mg/d + [(3,093.4 kg/h S02+64.8kg/h TRS) x
x 100%
kgSo2 1>Q kg
Sulfur Recovery Efficiency = 97.0%
C-37
-------
C.I.4 Exxon's Blackjack Creek Facility4
The Blackjack Creek facility is a sour natural gas processing
facility that employs a three-stage Claus sulfur recovery plant with a
SCOT tail gas cleanup unit. A simplified flow diagram for the facility
is shown in Figure C-7. Acid gas from sweetening unit flows to the
Claus plant at an average rate of 1.134 NmVs (3.459 MMscf/day) with an
average hydrogen sulfide concentration of 85.8 percent by volume. The
facility recovers approximately 105.2 Mg/d liquid sulfur (103.6 LT/D)
and normally operates at 99.8 percent recovery efficiency. Residual
tail gas from the SCOT unit is routed to an incinerator where the remaining
H2S and other reduced sulfur compounds are oxidized to S02 prior to
emission to the atmosphere. Table C-20 presents annual stack emissions
and sulfur recovery efficiency tests data from 1977 through 1980 that
were supplied by the facility. Sulfur recovery efficiency is calculated
as sulfur inlet minus stack sulfur emission, divided by sulfur inlet.
C.I.5 Shell Oil' Bryans Mill Facility5
The Bryans Mill facility is a Claus sulfur recovery facility that
began operation as a two-stage plant in 1962 and was expanded to a
three-stage plant in September 1967. During 1975, the average inlet
sour natural gas flow rate was 21.2 Nm3/s (64.7 MMscf/day), the average
liquid sulfur production was 191 Mg/d (188 LT/D) and H2S concentration
in the sour natural gas averaged 7.8 percent by volume. A summary of
the source emission tests conducted during 1973 and 1974 is presented in
Table C-21. During the period from March 1972 through June 1975, the
H2S/C02 volume percent ratio in the acid gas feed stream averaged 68.9/31.1
and Claus plant sulfur recovery efficiency ranged from 95.20 percent to
97.81 percent, whereas liquid sulfur production ranged from 230.3 Mg/d
(226.7 LT/D) to 164.6 Mg/d (162 LT/D). Stack gas temperature was an
average 859 K (1086°F). Sulfur recovery efficiency is equal to sulfur
production divided by the sum of sulfur production and sulfur in the
Claus tail gas.
C.I.6 Shell Oil's Person Plant Facility6
The Person Plant facility is a Claus sulfur recovery facility that
utilizes two parallel two-stage Claus trains with a common third-stage
reactor bed. The plant began operations in 1962 as two-stage unit. A
C-38
-------
Stack Gas
to Atmosphere
I
Residue Gas
(Sweetened Gas)
By pass
IO
Sour
Natural
Gas
t
Sweetening.
Operations
r
Acid Gas »
i
3-Stage c
Claus Unit U
,
^
r 1
i !
I •-
laus |^ 9rnT iim't
1 * -
!
Recycled Gas Stream] „ |
Liquid
Sulfur
i
Liquid Sulfur Storag
(H2S)
Fuel Gas
e
J
^
___^_ 1 A : ..
* 1 Air
Fuel Gas
,
Figure C-7. Simplified flow diagram for Exxon's Blackjack Creek Facility.
-------
Table C-20. EXXON'S BLACKJACK CREEK FACILITY ANNUAL STACK EMISSION TESTS DATA"
o
i
Acid gas H2S/C02
volumetric flow Total sulfur ratio
rate entering the entering the in the Sulfur recovery
Claus unit Claus unit Net inlet <-t . ,-„ acid gas efficiency, %
(includes (includes sulfur to the biacK SU2 entering Without
Test recycle flow) recycle sulfur) Claus unit emissions the Claus With SCOT
date NMVs MMscf/day Mg/d Ib/day Mg/d Ib/day kg/d Ib/day unit SCOT unit unit
3/07/80 1.134 3.459 108.2 238,540 105.4 232,458 412 908 87.5/12.5 99.81
4/19/79 1.194 3.644 108.6 239,472 105.2 231,900 422 931 85.8/14.2 99.80
4/14/78 1.110 3.386 101.4 223,595 97.9 215,886 161 354 86.7/13.3 99.92
7/20/77 1.090 3.326 101.4 223,568 97.6 215,217 216 476 85.6/14.4 99.89
97.26
96.64
96.47
96.16
Supplied by the facility.
-------
Table C-21. SHELL OIL'S BRYANS MILL FACILITY SOURCE EMISSION TESTS DATA"
Test
date
6/11/75
12/10/74
10/10/74
6/13/74
6/05/74
4/23/74
4/17/74
^ 12/18/73
^ 10/09/73
10/08/73
7/11/73
3/29/73
3/28/73
3/27/73
3/26/73
12/20/72
12/19/72
9/22/72
8/17/72
3/22/72
Liquid sulfur
production
Mg/d LT/D
212.6
207.6
207.5
196.8
211.8
223.6
205.4
181.2
178.9
199.3
198.6
164.6
182.4
191.4
208.2
177.7
194.8
230.3
184.4
222.6
209.28
204.34
204.20
193.70
208.42
220.03
202.20
178. 30
176.04
196.20
195.50
162.00
179.53
188. 37
204.93
174.88
191.73
226.68
181.44
219.10
SO, emissions
Mg/d LT/D
19.5
14.2
13.0
18.2
17.4
12.1
17.6
8.1
16.4
15.2
20.0
12.6
14.4
13.9
18.1
10.9
11.3
15.0
14.7
12.1
19.18
14.00
12.76
17.92
17.13
11.92
17.32
7.98
16.18
14.96
19.71
12.38
14.18
13.66
17.79
10.76
11.16
14.74
14.50
11.86
Sulfur
recovery
efficiency, %
95.60
96.69
96.97
95.60
96.05
97.40
95.90
97.81
95.60
96.30
95.20
96.32
96.20
96.50
95.84
97.02
97.17
96.85
96.16
97.36
H2S/C02
volume Incinerator
percent temperature
ratio K °F
69.3/28.6 887 1,137
70.2/28.3 872 1,110
862 1,092
67.7/29.8 826 1,027
68.4/30.4
853 1,075
853 1,075
Supplied by the facility.
Includes TRS.
-------
second two-stage train was placed in operation in 1965. Third-stage
converter common to both the trains along with Claus plant tail gas
incinerator were added in 1970-71 revisions. During 1975, the average
sour natural gas flow rate was 11.2 NnrVs (34.1 MMscf/day), and the
average daily sulfur production was 13.9 Mg/d (13.7 LT/D). The H2S
concentration in the sour natural gas averaged 1.12 percent by volume,
with an average acid gas feed stream H2S/C02 volume percent ratio of
20.6/79.4. Stack gas temperature averaged 822 K (1020°F). A summary of
the source emission tests conducted during 1973 through 1975 is presented
in Table C-22. Sulfur production ranged from 14.4 Mg/d (14.2 LT/D) to
23.2 Mg/d (22.8 LT/D) and sulfur recovery efficiency ranged from
92.95 percent to 97.7 percent. Sulfur recovery efficiency is equal to
sulfur production divided by the total of sulfur production and sulfur
in the Claus tail gas.
C.I.7 Exxon's Santa Rosa Facility
The Santa Rosa facility is a three-stage Claus sulfur recovery
facility processing 8.4 Nm3/s (25.7 MMscf/day) sour natural gas. The
facility produced 104.7 Mg/d liquid sulfur (103 LT/D). Acid gas flow
rate was 1.2 NnrVs (3.65 MMscf/day) with 77.3 percent by volume H2S in
it. The source emission tests conducted by EPA in June 1975 indicated
sulfur recovery efficiency of 97.7 percent achieved with 80.1 percent by
volume H2S in the acid gas feed stream (typical sulfur recovery efficiency
range 96 percent to 97 percent). The incinerator was operated at tempera-
tures of 783 K (950°F), 839 K (1050°F) and 950 K (1250°F). Total reduced
sulfur (COS, CS2 and H2S) was reduced from 219 ppmv to 18 ppmv as the
incinerator temperature was increased from 783 K (950°F) to 950 K (1250°F).
g
C.I.8 Exxon's Flomaton Facility
The Flomaton facility is a three-stage Claus sulfur recovery facility
designed to process 11.5 NnrVs (35 MMscf/day) sour natural gas with
sulfur recovery of 135.8 Mg/d (133.7 LT/D). The acid gas flow rate is
6.1 NmVs (18.5 MMscf/day) acid gas and contains 20.6 percent by volume
H2S in it. During the source emission test program in November 1973,
the facility recovered 130.1 Mg/d (128 LT/D) liquid sulfur with 96.7 percent
sulfur recovery efficiency.
C-42
-------
Table C-22. SHELL OIL'S PERSON PLANT FACILITY SOURCE
EMISSION TESTS DATA3
Liquid sulfur cn Qmn-ccl-riricb
Test production S02 emisslons
date Mg/d LT/D Mg/d LT/D
11/06/75 21.4 21.08 3.3 3.196
3/10/75 14.4 14.16 2.0 1.926
4/10/74 18.5 18.24 1.3 1.252
4/18/73 23.2 22.82 1.1 1.066
Sulfur
recovery
efficiency, %
92.95
93.63
96.68
97.70
Supplied by the facility.
'includes TRS.
C-43
-------
Q
C.I.9 Aquitaine of Canada, Ltd.'s Ram River Facility
At the Ram River facility, acid gas containing 84 percent ^S by
volume is processed by four two-stage Claus sulfur recovery units operating
in parallel. Each of the four Claus trains is designed to recover
1,016 Mg/d liquid sulfur (1,000 LT/D). The tail gases from these four
Claus plants are routed to two Sulfreen tail gas cleanup units. Each
Sulfreen unit consists of three reactors, with two in adsorption cycle
and one in regeneration cycle at any given time. This is the largest
sulfur recovery facility of its kind in Canada. During the source
emission tests conducted by U.S. EPA in September 1974, sulfur recovery
efficiency ranged from 97.4 percent to 98.3 percent (average of 98 percent)
while sulfur intake ranging from 3568 Mg/d (3512 LT/D) to 4100 Mg/d
(4036 LT/D).
C.I.10 Chevron Standard, Ltd.'s Fox Creek Facility10
The fox Creek facility consists of two four-stage Claus sulfur
recovery units, each with a capacity of recovering 1727 Mg/d (1700 LT/D)
liquid sulfur. This is the largest facility of its kind in Canada. The
acid gas feed stream containing 77 percent H2S by volume flows into each
Claus unit at an average rate of 19.7 NrnVs (60 MMscf/day). During the
source emission tests conducted by U.S. EPA in November 1974, sulfur
production from each Claus unit ranged from 1784 Mg/d (1756 LT/D) to
1814 Mg/d (1785 LT/D), with sulfur recovery efficiency ranging from
98.6 percent to 98.7 percent.
C-44
-------
C.2 REFERENCES
1. EMB Report No. 80-OSP-4. Onshore Production of Crude Oil and
Natural Gas - Sulfur Plants, Emission Test Report, S02 testing at
the Warren Petroleum Monument Plant, Monument, New Mexico. June 1981.
2. EMB Report No. 80-OSP-9. Onshore Production of Crude Oil and
Natural Gas - Sulfur Plants, Emission Test Report, S02 testing at
the Getty Oil New Hope Plant, New Hope, Texas. July 1981.
3. EMB Report No. 80-OSP-6. Onshore Production of Crude Oil and
Natural Gas - Sulfur Plants, Emission Test Report, S02 testing at
the Shell Oil Thomasville Plant, Thomasville, Mississippi. July 1981,
4. Annual stack test reports (1980, 1979, 1978, and 1977) on the
Blackjack Creek facility located in the Jay Field, Florida, submitted
to Florida Department of Environmental Regulation by Exxon Company,
U.S.A. New Orleans, Louisiana.
5. Bryans Mill plant (Cass County, Texas). Process data and general
information (operation and test data for 1975, 1974, 1973, and
1972) presented to EPA by Shell Oil Company in January 1976.
6. Person plant (Karnes County, Texas) Gas treating and sulfur plant
data (operation and test data for 1975, 1974, and 1973) for EPA by
Shell Oil Company in January 1976.
7. EMB Report No. 75-SRY-9. Air Pollution Emission Test, Emissions
from an oil and natural gas field sulfur recovery plant at Exxon
Company, U.S.A., Santa Rosa plant, Jay, Florida, February 1976.
U.S. EPA, Office of Air Quality Planning and Standards, Emission
Measurement Branch, Research Triangle Park, N.C. and additional
information on the Santa Rosa facility received from EPA.
8. Sulfur Recovery Unit Performance Test, November 12, 1973, on Flomaton
Production facility, submitted to State of Alabama, Air Pollution
Control Commission by Exxon Company, U.S.A. New Orleans, Louisiana,
and composition, flow data on the Flomaton facility received from
EPA.
9. Air Pollution Emission Test, Report No. 75-SRY-6. Source testing
of Ram River plant sulfur recovery facility. Aquitaine of Canada,
Ltd., Ram River, Alberta. November 1975. U.S. EPA, Office of Air
Quality Planning and Standards, Emission Measurement Branch, Research
Triangle Park, N.C.
10. Air Pollution Emission Test, Report No. 75-SRY-5. Source testing
of Fox Creek plant sulfur recovery facility. Chevron Standard,
Ltd., Fox Creek, Alberta. November 6-8, 1974. U.S. EPA, Office of
Air Quality Planning and Standards, Emission Measurement Branch,
Research Triangle Park, N.C.
C-45
-------
APPENDIX D - EMISSION MEASUREMENT AND CONTINUOUS MONITORING
-------
D.I EMISSION MEASUREMENT METHODS
During the standard support study for sulfur plants at onshore crude
oil and natural gas production facilities, three facilities were tested.
These facilities were equipped with Claus sulfur recovery plants followed
by tail-gas incinerators fired with natural gas.
The test program at these facilities consisted of measurement of the
sulfur recovery efficiency of the sulfur plant and the nitrogen oxides
emission rate. The sulfur omission rate was determined by sampling the
incinerator exhaust stack to measure sulfur dioxide, hydrogen sulfide, and
total reduced sulfur. EPA Reference Methods 6 and 11 (40 FR Part 60,
Appendix A) and proposed Method 16A (Federal Register, Volume 46, No. 117,
June 18, 1981), respectively, were used successfully without modification.
The exhaust gas flow rate was determined by Methods 1, 2, 3, and 4. For
Method 3, the gas composition was analyzed using thermal conductivity gas
chromatography instead of Orsat apparatus.
The incinerator exhaust sulfur rate was combined with the sulfur
recovery rates determined from plant instrumentation to calculate sulfur
recovery efficiency.
Measurements of nitrogen oxides were performed using EPA Method 7.
All gaseous measurements were conducted at a single point in the
exhaust stacks because the sampling locations at these facilities were
approximately 8-10 equivalent stack diameters downstream of disturbances,
and the velocity profiles were relatively uniform. In addition, no glass
wool plugs were used for filtration in the gaseous sampling trains because
of the low particulate concentrations in the exhaust gases.
In previous testing programs at similar facilities in petroleum
refineries, the sulfur species in the emissions were measured by a different
procedure. These facilities were equipped with Claus sulfur recovery units
and additionally with tail gas treatment units. The full test programs are
described in Appendix C of the "Standard Support and Environmental Impact
Statement, Volume I: Proposed Standards of Performance for Petroleum
Refinery Sulfur Recovery Plants," EPA Publication No. EPA-450/2-76-016a,
September 1976. EPA Method 15 (40 CFR Part 60, Appendix A), identified as
Method 18 in the above document, was used to determine individual reduced
sulfur compounds. This technique employs a field gas chromatograph equipped
D-2
-------
with a flame photometric detector. The use of a chromatographic technique
instead of a wet chemical approach, as is in proposed Method ISA, was
advantageous because the total sulfur concentrations were lower and one of
the purposes of testing was to identify the species of sulfur.
A potential limitation on the use of Method 16A at plants equipped
with a reduction-type tail gas treatment device would be that insufficient
oxygen is available in the exhaust gases to support complete oxidation of
reduced sulfur to sulfur dioxide prior to the sample collection in the
impinger train. At those locations, it will be necessary to use Method 15.
D.2 PERFORMANCE TEST METHODS.
EPA reference methods are available for all measurements necessary to
determine the emissions from sulfur recovery plants. However, the
specification of a procedure depends on the type facility tested and the
format of the regulation.
If a regulation is on the basis of an exhaust concentration limit,
then the following would apply:
1. For those plants equipped with Claus recovery units followed by
incinerators, oxidation tail gas units, or any tail gas unit followed by an
incinerator, sulfur dioxide would be determined by Method 6, hydrogen
sulfide by Method 11, and total reduced sulfur by proposed Method ISA.
2. For plants equipped with reduction-type tail gas systems without
an incinerator, sulfur dioxide would be determined by Method 6 and individual
reduced sulfur species would be determined by Method 15.
If the emissions concentration limit were based on a standardized
basis, such as dry concentration or concentration at zero percent oxygen,
additional measurements are necessary. Method 4 would be necessary to
determine a moisture content for conversion to a dry basis, and Method 3
would be necessary to measure fixed gas composition.
If the emission limitation is on a mass basis, the pollutant concentration
measurements above are required, as applicable, along with Methods 1, 2, 3,
and 4, as necessary, in order to determine the exhaust gas flow rate on the
same basis as the concentration measurement.
Finally, if the regulation is based on a percent recovery of sulfur,
the emission mass measurements above are necessary, along with a measure of
the total sulfur into the system. The most practical measure is the sulfur
D-3
-------
recovered during the test period. The sum of the sulfur recovered and the
sulfur emitted is the total sulfur to the system. Calibrated level indicators
or manual soundings of the sulfur in the product storage tanks can be used
to determine the sulfur recovered during the test period.
The averaging time for the regulation will determine how the measurements
specified above would be performed. All of the procedures except Method 15
are 30-minute to 1-hour integrated averages. A single result is available
for the sample duration. Either a single sample duration must be extended
or multiple samples taken if the averaging time is longer than the normal
sampling time. Method 15 is a semi-continuous technique that analyzes an
instantaneous sample approximately every 15 minutes. In this procedure,
the number of samples analyzed determines the test time. The maximum
practical duration for a sampling run is 3 to 4 hours, since a test is
usually defined as the average of three runs.
The new source performance standard for sulfur recovery plants in
petroleum refineries (40 CFR Part 60, Subpart J) is based on a concentration
limitation at zero percent oxygen. Methods 6 and 15 are specified depending
on the control device type. The sampling time for a run is 4 hours.
The procedures described above could not be practically or economically
used if compliance is based on a longer averaging interval or on a continual
basis. Usually, instrumental analyzers would be necessary to provide
longer term averages or continuous results. Analyzers are available that
are capable of measuring sulfur dioxide in incinerator exhausts and,
theoretically, process chromatographs and other devices are available for
measurement of reduced sulfur compounds. Instruments are also available
for continuous measurement of oxygen for continuous excess air corrections.
However, EPA has not evaluated an instrument system installed on this type
source for the specific purpose of demonstrating continual compliance.
The cost of a performance test will also depend on the format of the
standard, with the dominant factor being the averaging interval. If a test
run is specified as 4 hours, with three repetitions, then a complete test
is estimated to cost from $10,000 to $15,000 depending on the type control
device.
A specific estimate of the cost for demonstration of continual compliance
has not been developed for this source category, but the estimates for
0-4
-------
continuous compliance testing at industrial boiler facilities, which are
similar, are that an initial capital outlay of $40,000 plus $31,000/year in
operating costs would be required.
D.3 CONTINUOUS MONITORING
The instrument systems described above for demonstration of continual
compliance can be used for monitoring of operations and maintenance.
Instrument systems are available for measurement of sulfur dioxide and
oxygen, and EPA has promulgated performance specifications for these systems
in Appendix B of 40 CFR Part 60.
Instrument systems are also available for monitoring of total reduced
sulfur (TRS). EPA has developed performance specifications for TRS monitors
for future proposal.
The capital and operating costs for an instrument system used for
operations and maintenance monitoring alone are $30,000 and $10,000/year,
respectively.
D-5
-------
SULFUR RECOVERY STUDY
ONSHORE SOUR GAS PRODUCTION FACILITIES
APPENDIX E
July 1981
E-l
-------
SECTION 1 (SECTION E-l)
DESIGN BASIS
INTRODUCTION
This study was prepared for the development of New Source Performance
Standards for SO, emissions from Onshore Natural Gas Production Facilities.
This report provides investment costs, direct operating cost data, process
descriptions, process flow diagrams, and atmospheric emissions for 39 cases
with different sizes and combinations of sulfur recovery and tail gas
processes. For explanations of process names and abbreviations used,
refer to Definitions in this section.
E-2
-------
DESIGN CRITERIA AND ASSUMPTIONS
Listed below are assumptions used for design criteria and cost estimating for
this study:
(1) Barometric pressure is 14.7 psia.
(2) Acid gases are available at 100°F and 24.7 psia, saturated with
water, and contain 0.5 vol Z methane (wet basis).
(3) Steam is produced at 250, 50, and 15 psig from the Glaus units.
(4) Thermal oxidizers are operated at 1,200°F with 25% excess air (to
reduce H£S content below 10 ppmv) .
(5) For cases with waste heat boilers associated with thermal
oxidizers, steam is produced at 250 psig for the 100-LT/D cases
and at 600 and 250 psig for the 555- or 1,000-LT/D cases.
(6) Treated, deaerated boiler feedwater is available at 320 psig and
230 °F.
(7) Cooling water is available at 85 °F and is returned at 110 °F.
(8) Stack heights vary from 100 to 600 ft depending on the quantity of
sulfur dioxide emissions (see Tables 1-1, 1-2, and 1-3); stack
height was set to achieve approximately uniform levels of
ground-level SO 2 concentration.
(9) Investment costs are based on January 1981 Gulf Coast prices.
(10) In the BSR (hydrogenation) sections, steam is produced in the
100-LT/D units at 50 psig and in the 555- or 1,000-LT/D units at
450 and 50 psig.
(11) For the cases with 1,000-LT/D sulfur input feeding acid gas with a
50/50 H2S/C02 ratio, the plants are approximately the maximum
economical size and weaker gases would require building two
trains. In order to keep all cases in only one train, the maximum
sulfur input with 20/80 H2S/C02 acid gas feed is 555 LT/D.
These plants are about the same physical size as the 1,000-LT/D
plants with 50/50 H2S/C02 acid gas feed.
E-3
-------
DEFINITIONS
The following list provides definitions, terminology, and abbreviations used
in this report.
Acid Gas: The gas containing l^S (and C02> resulting from treating of
sour natural gas. Also contains small amounts of hydrocarbons and water.
BSR: The hydrogenation/hydrolysis and cooling section for converting all
sulfur compounds to H2& for further treatment as described in the
process description sections for the BSR/MDEA process, Beavon Sulfur
Removal Process (BSRP), and the BSR/Selectox process. Hydrogen required
for the hydrogenation reaction .is generated within the process.
Glaus: The name of the gas phase reaction where 2 mols of I^S combine with
1 mol of SO 2 to form 3 mols of sulfur. In what has come to be called the
Claus sulfur recovery process, a reaction furnace is included for
combustion to provide the necessary one-third of SO 2 for the reaction.
End-of-Run: After a certain period of operation, the activity of such
catalysts as alumina used in the Claus process declines to a point where
it is economical to shut down and replace it with fresh catalyst, say
after 2 years. The SO 2 emissions in the tables in this report are based
on end-of-run recoveries. The LT/D of sulfur recovered in Tables 6-9,
6-10, and 6-11 are average during run, calculated by averaging the start-
of-run and end-of-run recoveries. These average sulfur recoveries can then
be used to calculate credits for sulfur sales against operating costs.
Gas Components:
H2S Hydrogen Sulfide
S02 Sulfur Dioxide
02 Oxygen
N2 Nitrogen
CO Carbon Monoxide
CO 2 Carbon Dioxide
COS Carbonyl Sulfide
CS2 Carbon Disulfide
H20 Water
Lb Mols/Hr: The pounds per hour divided by the molecular weight of the
component.
LT/D: Long tons (2,240 pounds) per day.
MDEA: Methyl diethanolamine, used in aqueous solution to absorb l^S and
part of the CO 2 from gas.
MM: Millions.
E-4
-------
SCOT: A process proprietary to Shell Oil Company. It is believed similar to
BSR/MDEA, and published literature indicates use of extraneous hydrogen
for the hydrogenation reaction.
Selectox: A catalyst developed by Union Oil Company of California which
oxidizes H2S directly to elemental sulfur and in a temperature range
substantially lower than required for uncatalyzed oxidation.
Sour Gas: Natural gas containing H2S. When the H2S and usually the C02
are absorbed and stripped from the hydrocarbons in any of various treating
units, the stripped gas containing the H2S and C02 is called acid gas.
Thermal Oxidizer: A combustion chamber for converting all sulfur compounds in
the tail gas to S02 by burning the required amount of fuel. These are
sometimes called incinerators.
Vol. ppm or ppmv: The parts per million of a component on a volume basis.
E-5
-------
FEED GAS COMPOSITIONS
The feed gas (acid gas) compositions in pound mols per hour for all the cases
are provided in Table 1-1. In all of the cases the acid gas is saturated with
water at 100°F and 24.7 psia and contains 0.5 vol % of methane. These
conditions were assumed for this study for the sake of consistency. Actual
conditions will, of course, vary somewhat but will have a negligible effect
on the results and conclusions. Most of the solutions used to extract acid
gas from natural gas contain an amine in water, resulting in water-saturated
acid gas; some physical solvents (e.g., Selexol) produce dry acid gas.
E-6
-------
STACK HEIGHTS
The sulfur emissions as S02 in vol % and in Ib/hr are provided for each of
the cases, along with the assumed stack heights, in Tables 1-2, 1-3, and 1-4.
These stack heights were determined from experience to roughly approximate
the same ground-level concentration of SO2 for all cases.
In the various tables under "Thermal Oxidizers", the BSRP cases state No*
with a footnote: *Combustor only. At the top of the Stretford section
absorber, there is a combustor for emergency use only with a stack above the
combustor. The elevation at the top of this stack varies from about 100 to
150 ft above grade depending on the size and location of the unit.
The sulfur emissions are end of run. The vol 2 concentrations can be
converted to parts per million (ppmv) by multiplying by 10,000. The Ib/hr of
S02 can be converted to LT/D of S02 by multiplying by 0.0107.
E-7
-------
Table 1-1 (Table E-l)
Onshore Sour Natural Gas Sulfur Recovery Study for TRW
Feed Gas Compositions
H2S/C02 Ratio
80/20
50/50
Sulfur Input, LT/D 1»°°°
Case No.
Mols/hr
H2S
C02
CH4
H20
Total
H2S/C02 Ratio
Sulfur Input, LT/D
Case No.
Mols/hr
H2S
C02
CH4
H20
Total
1,000
19
2,911.2
727.8
19.0
146.3
3,804.3
5
2,4
14.56
58.24
.38
2.93
76.11
5 10
1.3 5,7
14.56 29.11
14.56 29.11
.15 .30
1.17 2.34
30.44 60.86
20/80
10 100 555
10, 10B, 21,24
6,68,8 12,14, 27,
& 8B 16, 18 30,33
29.11 291.1 1,615.7
116.44 1,164.4 6,642.8
.76 7.6 42.2
5.85 58.5 324.8
152.16 1,521.6 8,445.5
100
9,11,13
15 & 17
291.1
291.1
3.0
23.4
608.6
12.5/87
5 10
6A,6C,
4A 8A & 8C
14.56 29.11
101.92 203.77
.61 1.22
4.68 9.36
121.77 243.46
1,000
20,23,26
29 & 32
2,911.2
2,911.2
30.4
234.1
6,086.9
.5
100
10A &
IOC
291.1
2,037.7
12.2
93.6
2,350.4
E-8
-------
Table 1-2 (Table E-2)
Onshore Sour Natural Gas Sulfur Recovery Study
End-of-Run Sulfur Emission as SO2 and Stack Height
Acid Gas H2S/C02 Ratios of 80/20 and 50/50
i
vo
SULFUR
SULFUR RECOVERY UNIT
CASE
NO.
Acid
19
Acid
1
3
5
7
9
11
13
15
17
20
23
26
29
32
INPUT
{LT/D)
Gas H?S/C09
1,000
Gas H?S/C02
5
5
10
10
100
100
100
100
100
1,000
1,000
1,000
1,000
1,000
NO.
STAGES
Ratio
3
Ratio
*»
2
2
3
3
3
3
3
2
3
3
3
3
2
TYPE
- 80/20
- 50/50
No
Recycle Selectox
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
TAIL GAS
UNIT
THERMAL OXIDIZER
WASTE
HEAT
INCLUDED RECOVERY
SULFUR AS SO; STACK
HEIGHT TEMP
VOL X LB/HR (FT) (°F)
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
Yes
Yes
1.270 7514
550
450
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
No
No
No
No
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
4.964
1.293
1.268
0.817
0.817
0.011
0.004
0.329
0.350
0.817
0.011
0.004
0.330
0.350
933
70
138
88
884
12
3
354
339
8847
115
23
3539
3389
250
100
100
100
225
100
-
150
150
600
100
-
400
400
1500
1200
1200
1200
450
450
100
450
450
450
450
100
450
450
*Combustor only
-------
Table 1-3 (Table E-3)
Onshore Sour Natural Gas Sulfur Recovery Study
End-of-Run Sulfur Emission as SO2 and Stack Height
Acid Gas H2S/C02 Ratio of 20/80
CASE
NO.
2
4
6
6B
8
8B
10
10B
12
14
16
18
21
24
27
30
33
SULFUR
INPUT
(LT/D)
5
5
10
10
10
10
100
100
100
100
100
100
555
555
555
555
555
SULFUR RECOVERY UNIT
NO.
STAGES
_
2
2
2
3
3
3
3
3
3
3
2
3
3
3
3
2
TYPE
No
Recycle Selectox
Glaus
Recycle Selectox
Glaus
Recycle Selectox
Glaus
Recycle Selectox
Glaus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
TAIL GAS
UNIT
No
No
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
WASTE
HEAT
RECOVERY
No
No
No
No
No
No
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
SULFUR
VOL Z
5.34
0.851
0.882
0.851
0.591
0.491
0.591
0.491
0.009
0.007
0.238
0.233
0.592
0.009
0.007
0.238
0.233
AS SO?
LB/HR
933
90
184
179
123
103
1230
1034
22
9
493
483
6835
121
51
2734
2678
STACK
HEIGHT
(FT)
250
100
125
125
100
100
275
250
100
-
175
175
550
100
—
350
350
'riiMP
<°F)
1500
1200
1200
1200
1200
1200
450
450
450
100
450
450
450
450
100
450
450
*Cotnbu6tor only
-------
Table 1-4 (Table E-4)
Onshore Sour Natural Gas Sulfur Recovery Study
End-of-Run Sulfur Emission as SO2 and Stack Height
Acid Gas H2S/C02 Ratio of 12.5/87.5
m
i
CASE
NO.
4A
6A
6C
8A
8C
10A
IOC
SULFUR
INPUT
(LT/D)
10
10
10
10
100
100
SULFUR RECOVERY UNIT
NO.
STAGES
2
2
3
3
3
3
TYPE
Recycle Selectox
Glaus
Recycle Selectox
Glaus
Recycle Selectox
Glaus
Recycle Selectox
THERMAL OXIDIZER
TAIL GAS
UNIT
No
No
No
No
No
No
No
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
WASTE
HEAT
RECOVERY
No
No
No
No
No
Yes
Yes
SULFUR
VOL %
0.654
0.633
0.654
0.483
0.424
0.483
0.424
AS SO?
LB/HR
101
194
201
148
130
1480
1300
STACK
HEIGHT
(FT)
100
125
125
100
100
300
275
TEMP
(°F)
1200
1200
1200
1200
1200
450
450
-------
SECTION 2 (SECTION E-2)
SUMMARY OF RESULTS
EMISSIONS AND INVESTMENT COSTS
The emissions for the various cases are provided as outlined below.
The sulfur emissions as S02 vol X and Ib/hr along with stack heights are
shown in Tables 1-2, 1-3, and 1-4. They are also given as ppmv and again as
Ib/hr compared with total investment costs in Tables 5-1, 5-2, and 5-3.
The compositions of the exit gases in Ib mols/hr are included in Tables 2-1,
2-2, and 2-3.
Separate investment costs for each sulfur recovery process, tail gas process,
and thermal oxidizer, waste heat boiler, and stack are provided in
Tables 5-4, 5-5, and 5-6.
E-12
-------
Table 2-1 (Table E-5)
Onshore Sour Natural Gas Sulfur Recovery Study
Composition of Exit Gases (Ib mols/hr) End-of-Run
Acid Gas H2S/C02 Ratios of 80/20 and 50/50
THERMAL OXIDIZE*
CASE
HO.
Acid
19
Acid
1
m
1 3
| I
co
s
7
f
11
1)
1)
17
20
23
26
29
32
SULFUR
INPUT
UT/D)
CM H}S/CO?
1,000
G« H,S/CO,
5
5
10
10
100
100
100
100
100
1,000
1,000
1,000
1,000
1.000
SULFUR RECOVERY UNIT
NO.
STAGES
Ratio
3
Ratio
-
2
2
3
3
3
3
3
2
3
3
3
3
2
TYPE
- 80/20
- 50/50
No
Recycle Selecto*
Clan*
Claiu
Claua
Claua
Claua
Clam
Claua
Claua
Claua
Claua
Claua
Claua
TAIL CAS
UNIT
No
No
No
No
No
No
BSR/HDEA
BSRP
Sul f recn
BSR/Selectoi
No
BSR/HDEA
BSRP
Sulfreen
BSR/SelectoK
INCLUDED
Yea
Yea
Tea
Yea
Yea
Yea
Yea
No*
Yea
Yea
Yea
Yea
Ho*
Yea
Yea
WASTE
HEAT
RECOVERY
Yea
No
No
No
No
Yea
Yea
No
Yea
Yea
Yea
Yea
No
Yea
Yea
TAIL CAS COMPOSITION (Ib a»la/hr)
SO?
117.30
14.56
1.10
2.15
1.3B
13.81
0.18
-
5.52
5.29
138.10
1.79
-
55.24
52.90
52
143.60
32.72
1.08
2.00
1.98
19.84
21.85
-
19.31
17.83
198.40
218.50
-
193.10
178.30
»2
7890.70
206.47
27.32
90.43
90.00
900.10
1134.00
626.90
890.90
989.40
9001.00
11.340.00
6269.00
8909.00
9894.00
COj
939.40
14.56
32.97
32.16
32.37
323.70
365.50
308.20
325.50
338.70
3237.00
3655.00
3082.00
3255.00
3387.00
Hj CO COS HjO
143.60
24.98
22.60
42. 7«
43.18
- 431.80
- 176.90
11.03 0.62 0.04 65.40
434.50
- 158.60
- 4318.00
- - - 1769.00
110.30 6.20 0.36 653.80
- - - 4345.00
1586.00
TOTAL
9234.60
293.29
85.07
169.52
168.91
1689.25
1698.43
1012.19
1675.73
1509.82
16892.50
16984.29
10121.66
16757.34
15098.20
•Coabuitor only
-------
Table 2-2 (Table E-6)
Onshore Sour Natural Gas Sulfur Recovery Study
Composition of Exit Gases (Ib mols/hr) End-of-Run
Acid Gas H2S/C02 Ratio of 20/80
THERMAL OXIDIZER
CASE
MO.
2
*
6
61
8
88
10
tot
12
U
It
It
21
24
27
30
33
SULFUR
INPUT
(LT/D)
5
5
10
10
10
10
100
100
too
100
100
100
3)1
Ml
555
555
55S
SULFUR RECOVERY UNIT
NO.
STAGES
2
2
2
3
3
3
3
3
3
3
2
3
3
3
3
2
TYPE
No
Recycle Selecto*
Cl*u*
Recycle Selecto*
Cl*u*
Recycle Selecto*
CUiu
Recycle Selecto*
CUiu
ClaiM
Cl*u*
Cl*u*
Cl*u*
Cl*u*
Clew
Cl*u*
Cliui
TAIL GAS
UNIT
No
Ha
No
No
No
No
No
No
RSR/MDEA
RSRP
Sulfreen
BSR/Selectox
No
BSR/HDEA
RSRP
Sulfreen
BSR/Selectox
INCLUDED
Yes
Yet
Ye*
Ye*
Ye*
Yei
Ye*
Ye*
Ye*
Ho*
Ye*
Ye*
Ye*
Ye*
No*
Ye*
Ye*
WASTE
HEAT
RECOVERY
No
No
No
No
No
No
Ye*
Ye*
Ye*
No
Ye*
Ye*
Ye*
Ye*
No
Ye*
Ye*
TAIL CAS COMPOSITION (Ib aoli/hr)
Spj
14.56
1.40
2.87
2.80
1.92
1.61
19.21
16. U
0.34
-
7.69
7.S4
106.70
1.89
-
42.68
41.85
22
18.58
2.19
4.29
4.38
4.26
4.34
42.64
43.41
51.62
-
41.96
4.35
236.70
286. 50
-
232.90
24.14
"2
155.00
68.04
134.70
136.10
134.20
136.30
1342.0
1363.00
1896.00
767.90
1330.00
1598.00
7448.00
10520.00
4262.00
7379.00
8869.00
CO? Hj
58.24
62.22
124.00
124.40
124.30
124.60
1243.00
1246.00
1366.00
1201.00 12.87
1245.00
1280.00
6899.00
7580.00
6667.00 71.43
6909.00
7104.00
CO COS H?0
26.46
30.70
59.57
61.40
60.08
60.81
600.80
608.10
400.30
2.14 0.14 137.00
603.80
347.80
3334.00
2222.00
11.86 0.80 760.40
3351.00
1930.00
TOTAL
272.84
164.55
325.43
329.08
324.76
327.66
3247.65
3276.65
3714.26
2121.05
3228.45
3237.69
18024.40
20610.39
11773.49
17914.58
17968.99
•CoBbu«ter only
-------
Table 2-3 (Table E-7)
Onshore Sour Natural Gas Sulfur Recovery Study
Composition of Exit Gases (Ib mols/hr) End-of-Run
Acid Gas H2S/C02 Ratio of 12.5/87.5
THERMAL OXIDIZE*
m
i — *
tn
CASE
HO.
4A
6A
6C
8*
1C
10*
toe
SULTim
INPUT
U3JS1
s
10
10
10
10
100
100
SULFIII UCOVHY UNIT
NO.
STAGES
2
2
i
3
3
3
3
nn
•ccyclc Solccto*
CUui
Recycle Sclcctox
Cliuc
Recycle Sclcctox
CUui
••cycle Sclcctox
TAIL CAI
UHtT
No
No
No
No
No
No
No
INCLUDED
TM
Yci
Tea
Te»
Te«
Ie«
Tei
WASTE
HEAT
HECOVEKT
No
No
No
No
No
T«|
TCI
TAIL CAS COHPOSIT10H (Ib Bolc/hr)
S02
1.57
3.03
3.1*
2.31
2.03
23.11
20.30
£2
3.2$
6.4*
6. SO
6.47
6.50
64.71
65.04
1!2
•8.41
177.00
176. M
176.60
177.00
1766.00
1770.00
COz Nj
108.00
215.80
215.90
216.00
216.20
2160.00
2162.00
CO COS NjO
38.80
76.2*
77.60
76.68
76.85
766.80
768.50
TOTAL
240.03
478.61
47*. »4
478.06
478.58
4780.62
4785.84
-------
SECTION 3 (SECTION E-3)
SULFUR RECOVERY PROCESSES
RECYCLE SELECTOX PROCESS DESCRIPTION
The Selectox catalyst enables H£S to be oxidized to sulfur with air at low
temperature, eliminating the need for high-temperature combustion as in the
Claus Sulfur Recovery Process .
When supplied with the proper amount of air, the oxidation of one-third of
the H2S to S02 and reaction with the remaining two-thirds of H2S occur
simultaneously in the presence of the Selectox catalyst to form elemental
sulfur:
H2S + 3/2 02 - *"S02 + H20
2H2S + S02 - *-3S + 2H20
The effective overall reaction is therefore:
3H2S + 3/2 02 - »~3S + 3H20
The process is called Selectox when the acid gas feed strength is 5% i^S or
less. The exothermic reaction with 5% gas results in a reasonable maximum
reactor outlet temperature. After the Selectox reactor, the gas is cooled in
a sulfur condenser, which produces steam and condenses sulfur.
When the acid gas feed contains more than 5% i^S, some of the cooled lean
gas from the sulfur condenser is reheated and recycled to the Selectox
reactor inlet to maintain approximately 5% t^S at the reactor inlet. This
process is called Recycle Selectox.
Gas from the sulfur condenser proceeds through one or two Claus stages , each
with a reheater, converter, and sulfur condenser.
The Recycle Selectox 2-Stage Process , shown in Figure 3-1 , has one Selectox
and one Claus stage. The Recycle Selectox 3-Stage Process, illustrated in
Figure 3-2, is identical but has a second Claus stage added.
The system for the Selectox and the Claus reactors is the same: heating gas
to the desired inlet temperature, reaction in a converter, and cooling the
gas and condensing sulfur in a condenser. The condensers produce low-pressure
steam.
The first industrial plant using Recycle Selectox is in an advanced state of
construction and is expected to start operation about November 1981. Selectox
catalyst has been proven in 3-1/2 years of operation in a relevant industrial
Plant' E-16
-------
AGIO GAS
KO DRUM
CONOENSATE
AIR
AIR BIOWER
REHEATER
NO. 1
CONVERTER
NO. 1
ISEIECTOX)
RECVCIE
BLOWER f ft J
IP STEAM
I CONDENSER
1 NO. I
BFW
CONVERTER
NO.l
(ClAUSI
IP STEAM TAll GAS ^
t I *
! CONDENSER |
I NO. 2 I
I I
BFW
IIOUID
SUIFUR
SUIFUR PIT
i I
I I
SUIFUR PUMP
Figure 3-1. Recycle Selectox 2-Stage Process
(Figure E-l)
-------
CONOENSATE
AIR
AIR BLOWER
CONVERTER
NO. I
(SEIECTOX)
1
CONVERTER
NO.!
(CLAUSI
CONVERTER
NO. 3
ICIAUS)
SULFUR PUMP
Figure 3-2. Recycle Selectox 3-Stage Process
(Figure E-2)
-------
GLAUS PROCESS DESCRIPTION
The Claus reaction consists of combining 2 mo Is of H2S with 1 mol of S02
to form elemental sulfur:
2H2S + S02 - *-3S + 2H20 (1)
Normally, for gases rich in H2S (50% to 80Z), in the so-called Claus
Process the acid gas is burned with the proper amount of air to oxidize
one-third of the H2S to make the required amount of S02 to combine the
remaining two-thirds to create the following reaction:
H2S + 3/2 Q2 - »-S02 + H20 (2)
This makes a high enough temperature to trigger the reaction thermally.
However, when acid gas is weak in H2S, such as in the cases with
H2S/C02ratios of 20/80 and 12.5/87.5, the C02 dilution makes the
temperature in the reaction furnace too low. A sulfur-burning modification is
therefore used to make the required S02 by burning recovered sulfur in the
reaction furnace:
S + 02 - »-S02 (3)
The preheated acid gas containing all of the H2S goes directly to the first
converter, where it reacts with the S02 made in the reaction furnace. The
first converter is followed by one or two additional converters.
The Claus 2-stage process is illustrated in Figure 3-3. The acid gas flows
through a knockout drum to trap entrained liquid or slugs. The gas enters the
reaction furnace along with air, which is ratio-controlled to burn one-third
of the H2S to form S02. The gases are cooled in the reaction cooler,
which produces high-pressure steam, and are further cooled in Condenser 1,
which produces low-pressure steam. Sulfur is condensed and flows through a
seal into the sulfur pit. 'The gas is heated in Reheater 1, flows through
Converter 1 and through Condenser 2. This constitutes the first catalytic
stage. The second catalytic stage is identical. The sulfur collected from all
three condensers flows into the sulfur pit.
The Claus 3-stage process, shown in Figure 3-4, is identical to the 2-stage
process in Figure 3-3 plus the addition of a reheater, a converter and a
condenser .
The Claus sulfur -burning 2-stage process, shown in Figure 3-5, is the same as
the 2- stage process in Figure 3-3, except that sulfur instead of acid gas is
burned in the reaction furnace, and the acid gas is preheated and goes to
Converter 1.
The Claus sulfur-burning 3-stage process, shown in Figure 3-6, is identical
to the 2- stage process in Figure 3-5 plus the addition of a reheater, a
converter and a condenser.
E-19
-------
The acid gas preheaters are usually heated by steam. The reheaters can be
either auxiliary burners, which heat the process gases with either acid gas
or fuel gas, or steam-heated she11-and-tube units.
E-20
-------
KODRUM
ACID GAS
l
ro
T
WATER
HP STEAM
REACTION I REACTION |
FURNACE I COOLER I
BFW
AIR BLOWER
REHEATER
NO.l
L
t
CONVERTER \
i
R
^m
NO.l
i
/
/
L
\
CONVI
NO
i
REHEATER
NO. 2
i
LP STEAM
>
1
1
k
1
1
| CONDENSER)
I NO 2
\
1
BFW
i
r
—
AIR
IP STEAM
TAIL GAS
| CONDENSED |
| N0.3 |
BFW
LIQUID SULFUR
SUIFUR PIT
SULFUR PUMP
Figure 3-3. Glaus 2-Stage Process
(Figure E-3)
-------
KO DRUM
ACIO GAS
ro
ro
WATER
HP STEAM
REACTION I REACTION
FURNACE I COOLER
I I
RFW
AIR BLOWER
•AIR
BFW
BFW
BFW
i
i
\
r
\
r
i
F
SULFUR PIT
i
r
\
r i
i— i Ll°
r wr
1 1
ti
1
W
r
OS
SULFUR PUMP
Figure 3-4. Glaus 3-Stage Process
(Figure E-4)
-------
ACID CAS
I
»
T
WATER
PREHEATER
KO DRUM
HP STEAM
I
REACTION j REACTION |
FURNACE I COOLER I
BFW
AIR
AIR BLOWER
REHEATER
NO. 1
BFW
I '
CONVERTER \
N0.1 1
\ /
ER
i
' \
CONVI
NO
L
REHEATER
NO. 2
t
LP STEAM
, t
I
^
1 CONDENSER 1
1 NOZ
1
t
BFW
r
r
LIQUID SULFUR
LP STEAM
TAIL CAS
" t
I CONDENSER I
I NO. 3 I
J I
BFW
LIQUID SULFUR
»
SULFUR PIT
-------
ACIO GAS
I
»
T
WATER
KOORUM
HP STEAM
REACTION I REACTION |
FURNACE I COOLER I
J I
AIR BLOWER
IP STEAM
1 t
; CONVERTER ]
NO. 1 J
/
i
\
CONV
NC
REHEATER
NO. 2
i
IP STEAM
. t
L
1
1 1
1 CONDENSER)
I NO.?
1 1
t
BFW
1 J
r
LIQUID SULFUR
CONVERTER
NO. 3
IP STEAM
I CONOENSER|
I NO 3 |
BFW
IP STEAM TAIl GAS
SULFUR PIT
SULFUR PUMP
SULFUR PUMP
Figure 3-6. Glaus Sulfur-Burning 3-Stage Process
(Figure E-6)
-------
SECTION 4 (SECTION E-4)
TAIL GAS PROCESSES
THERMAL OXIDIZERS, WASTE HEAT BOILERS, AND STACKS
The two types of arrangements for burning the combustibles in tail gases to
convert all sulfur compounds and sulfur vapor into S02 are shown in
Figure 4-1. The combustion takes place with 252 excess air and the addition
of the required amount of fuel gas to maintain a temperature of 1,200°F. This
temperature is considered necessary to ensure that the stack gases will
contain less than 10 ppm of l^S.
For Cases 1 and 2, which have no sulfur recovery, the acid gas is thermally
oxidized directly with no fuel gas required. It is necessary to use more than
25% excess air to limit the stack temperatures to 1,500°F.
For small plants, which have no waste heat recovery such as in Cases 1
through 8C, the thermal oxidizer is in the base of the stack. The stack
provides more than sufficient residence time for completion of reactions.
This is shown on the left side of Figure 4-1.
For all other cases, except BSRP Cases 13, 14, 26, and 27, which only require
an emergency combustor, the scheme shown on the right side of Figure 4-1 is
used. The thermal oxidizer must have sufficient residence time to ensure
achieving complete combustion before entering the waste heat boiler where the
gas is being cooled. Because the pressure drop through the waste heat boiler
imposes a slight pressure on the thermal oxidizer, an air blower is required.
E-25
-------
ro
TAIL GAS
FUEL GAS
AIR
1
1
STEAM
TAIL GAS
THERMAL
OXIDIZER
ft STACK
FUEL GAS
'
THERMAL
OXIDIZER
t
AIR BLOWER
BFW
WASTE HEAT
BOILER
STACK
Figure 4-1. Thermal Oxidizers, Waste Heat Boilers, and Stacks
(Figure E-7)
-------
-BSR/MDEA PROCESS DESCRIPTION
The flow diagram for the BSR/MDEA Process is provided in Figure 4-2. The BSR
or hydrogenation section is identical to the corresponding section in the BSR
Process, except that It is somewhat larger to handle the recycled gas.
In the BSR section the sulfur recovery unit tail gas is heated to reaction
temperature in the reducing gas generator by mixing it with the products of
combustion of fuel gas and air. Some hydrogen and carbon monoxide are formed
to supplement the hydrogen in the tail gas. The gas enters the hydrogenation
reactor, where all sulfur compounds (S(>2, &*, COS, C$2 ) are converted
to H2S, and is then cooled in the reactor effluent cooler, which produces
steam. The gas is further cooled in the contact condenser by evaporating
water in the lower section and condensing and cooling in the upper section.
The cooled gas enters the MDEA absorber, where essentially all of the
and some of the C02 are absorbed by cool MDEA solution, which enters at the
top. The gas, containing a small amount of ^S, goes to the thermal
oxidizer, waste heat boiler and stack.
The rich MDEA from the bottom of the absorber Is preheated by lean MDEA and
fed to the MDEA regenerator, where the I^S and CO 2 are stripped from the
MDEA solution. This acid gas is recycled to the Claus unit.
E-27
-------
OESUPERHEATER/
CONTACT CONDENSER
Alfl
FUEL HAS
CLAUS
TAIL GAS
Li
ro
CO
REDUCING
GAS
GENERATOR
COOLER/
,$H
a-
HYOROGENATION
REACTOR
4T-+
STEAM
MDEA
ABSORBER
MDEA REGENERATOR
LEAN SOLUTION
COOLER
LEAN/RICH
EXCHANGER
CLEAN TAIL GAS
TO THERMAL
OXIOIZER
ACID GAS
TO CLAUS
UNIT
REFLUX
COOLER
REBOILER
REACTOR
EFFLUENT
COOLER
BFW
Figure 4-2. BSR/MDEA Process
(Figure E-8)
-------
BEAVON SULFUR REMOVAL PROCESS (BSRP) DESCRIPTION
The flow diagram for the Beavon Sulfur Removal Process (BSRP) is shown in
Figure 4-3. The process consists of the BSR or hydrogenation section and the
Stretford section.
In the BSR section, the sulfur recovery unit tail gas is heated to reaction
temperature in the reducing gas generator by mixing it with the products of
combustion of fuel gas and air. Some hydrogen and carbon monoxide are formed
to supplement the hydrogen in the tail gas. The gas enters the hydrogenation
reactor, where essentially all sulfur compounds (SC>2, Sx, COS, C$2) are
converted to l^S, and is then cooled in the reactor effluent cooler, which
produces steam. The gas is further cooled in the contact condenser by
evaporating water in the lower section and condensing and cooling in the
upper section.
In the Stretford section the cooled hydrogenated gas is contacted in a
venturl scrubber and an absorber, where the H2S is absorbed in an oxidizing
alkaline solution. The H2S is converted to elemental sulfur by the
oxidizing agents in the solution. The solution is regenerated by contacting
with air in the oxidizer tank where sulfur is floated off as a slurry. After
separating the sulfur from the chemicals by filtering or centrifuging, with
water washing, it is reslurried with wash water and heated to melt the
sulfur. The molten sulfur flows from the decanter to the sulfur pit. The
chemicals are returned to the system and the wash water is discarded.
The offgas from the absorber typically contains less than 1 ppm of H2S
and, therefore, does not need to be thermally oxidized. A combustor and short
stack on top of the absorber are provided for rare occasions when the H2S
content exceeds 10 ppm.
E-29
-------
FUEl GAS
AIR
ClAUS
TAIl •
GAS
REDUCING
0*5
GENERATOR
GO
o
OESUFERHEATER/
CONTACT
CONDENSER
COOLER
HVOROGENATION
REACTOR
STEAM
REACTOR
EFFLUENT
COOLER
IFH
t
I
-*m
• FUEL GAS
VENTURI
CONTACTOR
SOLUTION
HEATED
AtSORIER
AIR
IIOWER
HATER
WASH
HATER
STEAM
SULFUR
DECANTER
OXIDIZER
TANK
8ALANCE
TANK
SLURRY
TANK
SULFUR
TO MT
Figure 4-3. Beavon Sulfur Removal Process (BSRP)
(Figure E-9)
-------
SULFREEN PROCESS DESCRIPTION
The Sulfreen Process, shown in Figure 4-4, takes advantage of furthering the
Glaus reaction by operating below the sulfur dewpolnt of the reaction gas
mixture:
2H2S + S02 *-3S + 2H20
Liquid sulfur is adsorbed on the catalyst which removes it from the gas,
thereby allowing the reaction to move further to the right and obtaining a
higher conversion than in the Claus process where the tail gas is above the
sulfur dewpoint.
The catalyst is alumina, usually the same type used in the Claus process.
After a period of operation when the catalyst has adsorbed its limit of
sulfur, the reactor enters a closed-cycle desorption operation, where recyle
gas is heated and passed through the reactor to strip sulfur from the
catalyst, then through a sulfur condenser. This condenser cools the gas and
generates low-pressure steam. Sulfur is condensed and drained to the sulfur
pit.
There are usually three reactors, two of which are in adsorption service
while one is being regenerated.
E-31
-------
TO THERMAL
OXIOIZER
CONVERTER
(ADSORPTION)
CLAUS TAIL GAS
CONVERTER
(ADSORPTION)
CONVERTER
(REGENERATION)
LPSTEAM
1 SULFUR I
'CONDENSER)
BFW
REGENERATION
REHEATER
REGENERATION
BLOWER
-»~ LIQUID SULFUR TO SULFUR PIT
Figure 4-4. Sulfreen Process
(Figure E-10)
-------
BSR/SELECTOX PROCESS DESCRIPTION
The flow diagram for the BSR/Selectox Process is provided in Figure 4-5. The
process consists of a BSR or hydrogenation section and a Selectox section.
In the BSR section the sulfur recovery unit tail gas is heated to reaction
temperature in the reducing gas generator by mixing it with the products of
combustion of fuel gas and air. Some hydrogen and carbon monoxide are formed
to supplement the hydrogen in the tail gas. The gas enters the hydrogenation
reactor, where all sulfur compounds (S(>2» Sx, COS, CS2) are converted
to H2S, and is then cooled in the reactor effluent, which produces steam.
The gas is further cooled in the condenser by circulating water
countercurrent to the gas. The purpose of cooling is to increase the
potential conversion by removing water, which is one of the products of
reaction.
The gas from the condenser is reheated to a moderate temperature and combined
with air, after which it enters the Selectox reactor where the H2S is
directly oxidized to elemental sulfur:
H2S + 1/2 02 »-S + H20
The gas is cooled by generating low-pressure steam, and the condensed sulfur
flows to the sulfur pit. The tail gas from the sulfur condenser goes to a
thermal oxidizer, waste heat boiler and stack.
E-33
-------
AIR-
FUEL GAS-
TAIL GAS FROM
2 STAGECLAUS
REHEATER
AIR
REDUCING
GAS
GENERATOR
HYDROGENATION
REACTOR
I
CO
-p.
)
STEAM
BFW
CONDENSER
REACTOR
EFFLUENT
COOLER
JO THERMAL
OXIDIZER
SULFUR
CONDENSER
LIQUID SULFUR TO PIT
Figure 4-5. BSR/SELECTOX Process
(Figure E-ll)
-------
SECTION 5 (SECTION E-5)
INVESTMENT COSTS
INVESTMENT COSTS VS. SULFUR EMISSIONS
The total investment costs are compared with sulfur emissions for each case
in Tables 5-1, 5-2, and 5-3. These investment costs are based on January 1981
Gulf Coast prices and include all design, engineering, purchasing of
equipment and materials, and construction costs and contractors1 fees, but do
not include the initial charge of catalysts and chemicals. The investment
costs were developed separately for each sulfur recovery process, tail gas
process, and thermal oxidizer, waste heat boiler, and stack. These separate
costs are provided in Tables 5-4, 5-5, and 5-6.
The costs for the initial charge of catalysts and chemicals are given in
Tables 5-7, 5-8, and 5-9.
E-35
-------
Table 5-1 (Table E-8)
Onshore Sour Natural Gas Sulfur Recovery Study
Investment Costs and Sulfur Emissions (End-of-Run)
Acid Gas H2S/C02 Ratios of 80/20 and 50/50
SULFUR
CASE INPUT
NO.
SULFUR RECOVERY UNIT
NO.
(LT/D) STAGES
TYPE
Acid Gas H?S/CO? Ratio - 80/20
19 1,000 3
Acid Gas H2S/C02 Ratio - 50/50
1 5 - No
3 52 Recycle Selectox
5 10 2 Claus
7 10 3 Claus
9 100 3 Claus
11 100 3 Claus
13 100 3 Claus
15 100 3 Claus
17 100 2 Claus
20 1,000 3 Claus
23 1,000 3 Claus
26 1,000 3 Claus
29 1,000 3 Claus
32 1,000 2 Claus
TAIL GAS
UNIT
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
THERMAL OXIDIZER
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
WASTE
HEAT
RECOVERY
Yes
No
No
No
No
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
INVESTMENT
COST
(MM$)
22.30
1.28
2.43
2.95
3.32
6.47
11.90
9.12
8.26
7.47
26.10
47.17
29.99
29.41
28.93
SULFUR
AS
EMISSION
SO?
VOL. PPM LB/HR
12,700
49,640
12,930
12,680
8,170
8,170
110
40
3,290
3,500
8,170
110
40
3,300
3,500
7,514
933
70
138
88
884
12
3
354
339
8,847
115
23
3,539
3,389
*Combustor only
-------
Table 5-2 (Table E-9)
Onshore Sour Natural Gas Sulfur Recovery Study
Investment Costs and Sulfur Emissions (End-of-Run)
Acid Gas H2S/C02 Ratio of 20/80
co
CASE
NO.
2
4
6
6B
8
8B
10
10B
12
14
16
18
21
24
27
30
33
SULFUR
INPUT
(LT/D)
5
5
10
10
10
10
100
100
100
100
100
100
555
555
555
555
555
SULFUR RECOVERY UNIT
NO.
STAGES
^
2
2
2
3
3
3
3
3
3
3
2
3
3
3
3
2
TYPE
No
Recycle
Claus
Recycle
Claus
Recycle
Claus
Recycle
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Selectox
Selectox
Selectox
Selectox
TAIL GAS
UNIT
No
No
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
THERMAL OXIDIZER
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
WASTE
HEAT
RECOVERY
No
No
No
No
No
No
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
INVESTMENT
COST
(MM$)
1.28
2.43
3.40
2.67
3.74
3.11
9.05
8.46
20.44
11.53
10.88
10.45
26.23
66.35
29.42
29.63
29.89
SULFUR EMISSION
AS SO?
VOL. PPM
53,400
8,510
8,820
8,510
5,910
4,910
5,910
4,910
90
70
2,380
2,330
5,920
90
70
2,380
2,330
LB/HR
933
90
184
179
123
103
1,203
1,034
22
9
493
483
6,835
121
51
2,734
2,678
*Combustor only
-------
Table 5-3 (Table E-10)
Onshore Sour Natural Gas Sulfur Recovery Study
Investment Costs and Sulfur Emissions (End-of-Run)
Acid Gas H2S/C02 Ratio of 12.5/87.5
SULFUR
CASE INPUT
NO.
SULFUR RECOVERY UNIT
NO.
(LT/D) STAGES
4A
6A
6C
8A
m 8C
i
CO
oo IDA
IOC
10
10
10
10
100
100
2
2
3
3
3
3
TYPE
Recycle Selectox
Glaus
Recycle Selectox
Claus
Recycle Selectox
Claus
Recycle Selectox
THERMAL OXIDIZER
TAIL GAS
UNIT
No
No
No
No
No
No
No
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
WASTE
HEAT
RECOVERY
No
No
No
No
No
Yes
Yes
INVESTMENT
COST
(MM$)
2.A5
3.53
2.69
3.79
3.16
11.21
9.91
SULFUR EMISSION
AS SO?
VOL. PPM
6,540
6,330
6,540
4,830
4,240
4,830
4,240
LB/HR
101
194
201
148
130
1,480
1,300
-------
Table 5-4 (Table E-ll)
Onshore Sour Natural Gas Sulfur Recovery Study
Summary of Investment Costs by Units (MM$)
co
10
ACID CAS HjS/CO, RATIO
CASE NO. 1 3 5
SULFiR INPUT (LT/D) S 5 10
SULFUR RECOVERY PROCESSES:
(•cycle Selects*, 2-St*|* 1.93
CUu«, 2-Stagc 2.45
CUiu. 3-Stag«
TAIL GAS PtOCESSES:
BSR
HDEA
Stretford
•SI (for Selectoi)
Select ox
Sultrcca
THERMAL OXIDIZERS, HASTE HEAT BOILERS AND STACKS:
Ther«l Oxldlter 0.23 0.23 0.23
U««te He.t Bollcr(l)
Stack 1.05 0.27 0.27
TOTAL INVESTMENT 1.28 2.43 2.95
7 9 II
10 100 100
2.82 4. S3 4.85
1.66
4.07
0.23 0.45 0.46
0.59 0.59
0.27 0.90 0.27
3.32 6.47 11.90
50/50
13 15
100 100
4.53 4.53
1.58
3.01
2.21
0.45
0.61
0.46
9.12 8.26
17
100
3.73
1.42
0.84
0.45
0.57
0.46
7.47
20
1.000
17.73
1.89
2.35
4.13
26.10
23 26
1,000 1,000
19.49 17.73
5.55 5.22
17.57
7.04
1.94
2.35
0.27
47.17 29.99
29
1,000
17.73
5.26
1.89
2.38
2.15
29.41
32
1,000
14.50
4.96
3.27
1.83
2.22
2.15
28.93
80/20
19
1.000
15.28
1.50
1.94
3.58
22.30
-------
Table 5-5 (Table E-12)
Onshore Sour Natural Gas Sulfur Recovery Study
Summary of Investment Costs by Units (MM$)
m
i
4^.
O
ACID CAS HiS/CO, RATIO
CASE NO. 2 * 6 68
SULFUR INPUT (LT/D) 5 J 10 10
SULFUR RECOVERY PROCESSES:
Recycle Selectoi, 2-Stag« 1.91 2.08
CUue. 2-Stege 2.81
Recycle Selecto*, 1-Scige
Cleu*, 3-St«g«
TAIL CAS PROCESSES:
RSR
HDEA
St ret ford
BSR (far Selectoi)
Selectox
Sulfreen
THERMAL OXIDIZERS. WASTE HEAT BOILERS AND STACKS:
The rail Oaldlier 0.21 0.21 0.21 0.21
U»t> Ueat Bolter(i)
St.ck 1.05 0.27 0.16 0.16
TOTAL INVESTMENT 1.28 2.41 1.40 2.67
20/80
8 88 10 108 12 14
10 10 100 100 100 100
2.61 5.78
1.24 6.21 7.11 6.21
2.2i 1.99
8.86
1.11
0.21 0.21 0.70 0.70 0.77
0.90 0.91 0.98
0.27 0.27 1.22 1.0) 0.27
1.74 1.11 9.05 8.46 20.44 11.51
16 18
100 100
S.07
6.21
1.80
1.11
2.42
0.70 0.72
0.92 0.92
0.61 0.61
10.88 10.4$
21 24 27
555 555 555
17.91 21.19 17.91
6.01 S.22
11.51
6.27
2.18 2.18
2.54 2.79
1.58 0.27
26.21 66.15 29.42
10
555
17.91
5.21
2.16
2.56
1.75
29.61
11
555
14.60
4.91
1.79
2.22
2.60
1.75
29.89
-------
Table 5-6 (Table E-13)
Onshore Sour Natural Gas Sulfur Recovery Study
Summary of Investment Costs by Units (MM$)
ACID GAS H2S/C02 RATIO 12.5/87.5
CASE NO. 4A 6A 6C 8A 8C 10A IOC
SULFUR INPUT (LT/D) 5 10 10 10 10 100 100
SULFUR RECOVERY PROCESSES;
Recycle Selectox, 2-Stage 1.95 2.10
Glaus, 2-Stage 2.94
Recycle Selectox, 3-Stage 2.66 6.60
Claus, 3-Stage 3.29 7.77
THERMAL OXIDIZERS, WASTE HEAT BOILERS, AND STACKS;
Thermal Oxldlzer „ 0.23 0.23 0.23 0.23 0.23 0.91 0.91
Waste Heat Boller(s) 1.15 1.18
Stack 0.27 0.36 0.36 0.27 0.27 1.38 1.22
TOTAL INVESTMENT 2.45 3.53 2.69 3.79 3.16 11.21 9.91
-------
COST OF INITIAL CHARGE OF CATALYSTS AND CHEMICALS
The costs for providing the required amount of catalyst and chemicals to fill
the plants for initial startup are provided in Tables 5-7, 5-8, and 5-9.
E-42
-------
Table 5-7 (Table E-14)
Onshore Sour Natural Gas Sulfur Recovery Study
Cost of Initial Charge of Catalysts and Chemicals
Acid Gas H2S/C02 Ratios of 80/20 and 50/50
CASE
NO.
Acid
19
Acid
71 i
£ 3
5
7
9
11
13
15
17
20
23
26
29
32
SULFUR
INPUT
(LT/D)
Gas H7S/CO?
1,000
Gas H7S/CO?
5
5
10
10
100
100
100
100
100
1,000
1,000
1,000
1,000
1,000
SULFUR
NO.
STAGES
Ratio -
3
Ratio -
«
2
2
3
3
3
3
3
2
3
3
3
3
2
RECOVERY
80/20
50/50
No
UNIT
TYPE
Recycle Selectox
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
Glaus
TAIL GAS
UNIT
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
THERMAL
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
OXIDIZER
WASTE
HEAT
RECOVERY
Yes
No
No
No
No
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
CAT. & CHEN.
COST
(MM$)
0.19
-0-
0.02
0.004
0.004
0.02
0.13
0.10
0.05
0.16
0.25
1.33
0.99
0.50
1.33
*Combustor only
-------
Table 5-8 (Table E-15)
Onshore Sour Natural Gas Sulfur Recovery Study
Cost of Initial Charge of Catalysts and Chemicals
Acid Gas H2S/C02 Ratio of 20/80
THERMAL OXIDIZER
CASE
NO.
2
4
6
6B
8
8B
10
10B
12
14
16
18
21
24
27
30
33
SULFUR
INPUT
(LT/D)
5
5
10
10
10
10
100
100
100
100
100
100
555
555
555
555
555
SULFUR RECOVERY UNIT
NO.
STAGES TYPE
2
2
3
3
3
3
3
3
3
2
3
3
3
3
2
No
Recycle Selectox
Claus
Recycle Selectox
Claus
Recycle Selectox
Claus
Recycle Selectox
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
TAIL GAS
UNIT
No
No
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
WASTE
HEAT
RECOVERY
No
No
No
No
No
No
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
CAT. & CHEM.
COST
-------
Table 5-9 (Table E-16)
Onshore Sour Natural Gas Sulfur Recovery Study
Cost of Initial Charge of Catalysts and Chemicals
Acid Gas H2S/C02 Ratio of 12.5/87.5
CASE
NO.
AA
6A
6C
8A
1 ' I
i 8C
en
10A
IOC
SULFUR
INPUT
(LT/D)
5
10
10
10
10
100
100
SULFUR
NO.
STAGES
2
2
2
3
3
3
3
RECOVERY UNIT
TYPE
Recycle Se:
Claus
Recycle Se
Claus
Recycle Se
Claus
Recycle Se:
No
No
No
No
No
No
No
THERMAL OXIDIZER
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
WASTE
HEAT
RECOVERY
No
No
No
No
No
Yes
Yes
CAT. & CHEM.
COST
(MM$)
0.01
0.004
0.03
0.01
0.03
0.06
0.31
-------
SECTION 6 (SECTION E-6)
DIRECT OPERATING COST DATA
UTILITIES, CATALYSTS, AND CHEMICALS
The utilities and the catalyst and chemical costs are provided in Tables 6-1
through 6-8 for all cases except No. 1 and No. 2, which do not require any.
The utilities for each case are in two groups, those to be supplied to
battery limits, which are costs, and those exported to battery limits, which
are credits.
The Glaus units produce 250-, 50-, and 15-psig steam. The 15-psig steam is
sometimes condensed with the energy being wasted but the condensate being
recovered. However, it is exported to battery limits in all cases as it can
be useful in preheating or deaerating boiler feedwater.
The waste heat boilers recovering heat by cooling hydrogenation reactor
effluent gas produce 50-psig steam for the 100-LT/D cases and both 450- and
50-psig steam for the 555- and 1,000-LT/D cases.
The thermal oxidizer waste heat boilers produce 250-psig steam for the
100-LT/D cases and both 600- and 250-psig steam for the 555- and 1,000-LT/D
cases.
Chemical costs for the Stretford process, in industrial experience, have
varied widely. Plant design has a major effect on such costs, especially the
design of the sulfur slurry separation section of the plant. Both investment
and chemical costs herein apply to advanced design incorporating very
complete separations, with relatively high investment costs but low chemical
costs. It will be noted that a relatively large error in estimating chemical
costs has but a minor effect on overall costs.
E-46
-------
Table 6-1 (Table E-17)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst Costs
Recycle Selectox 2-Stage Process
CASE NO. 3 4 4A 6B 6C
Sulfur Input, LT/D 55 5 10 10
H2S/C02 Ratio 50/50 20/80 12.5/87.5 20/80 12.5/87.5
REQUIRED FROM BATTERY LIMITS
600-psig Steam, Ib/hr 373 616 857 1,230 1,713
Treated B.F. Water, Ib/hr 1,566 1,652 1,740 3,304 3,379
Electric Power, kW 77 70 65 110 100
Fuel Gas, 106 Btu/hr 0.59 1.22 1.88 2.44 3.76
EXPORTED TO BATTERY LIMITS
50-psig Steam, Ib/hr 635 660 675 1,920 1,950
15-psig Steam, Ib/hr 76 144 214 288 429
Steam Condensate, Ib/hr 1,173 1,416 2,275 2,230 3,950
Catalyst Cost, $/day 4.73 4.70 4.97 9.40 9.93
E-47
-------
Table 6-2 (Table E-18)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst Costs
Claus Process - No Tail Gas or Waste Heat Recovery Units
CASE NO. 5 6 6A 7 8 8A
Claus - No. Stages 22 233 3
Sulfur Input, LT/D 10 10 10 10 10 10
H2S/C02 Ratio 50/50 20/80 12.5/87.5 50/50 20/80 12.5/87.5
REQUIRED FROM BATTERY LIMITS
600-psig Steam, Ib/hr 239 848 1,302 343 1,057 1,615
Treated B.F. Water, Ib/hr 2,560 2,894 3,095 2,636 3,044 3,308
Electric Power, kW 51 56 59 53 58 61
Fuel Gas, 106 x Btu/hr 0.95 2.34 3.72 1.01 2.43 3.78
EXPORTED TO BATTERY LIMITS
250-psig Steam, Ib/hr 1,409 1,277 1,239 1,409 1,277 1,239
50-psig Steam, Ib/hr 0 122 221 129 364 512
15-psig Steam, Ib/hr 217 411 545 162 314 461
Steam Condensate, Ib/hr 1,096 1,848 2,302 1,202 2,057 2,615
Catalyst Cost, $/day 2.27 4.12 5.86 3.40 6.18 8.78
E-48
-------
Table 6-3 (Table E-19)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst Costs
Claus Process - With Waste Heat Recovery - No Tail Gas Unit
CASE NO. 9 10 10A 19 20 21
Claus - No. Stages 33 3333
Sulfur Input, LT/D 100 100 100 1,000 1,000 555
H2S/C02 Ratio 50/50 20/80 12.5/87.5 80/20 50/50 20/80
REQUIRED FROM BATTERY LIMITS
Treated B.F. Water, Ib/hr 36,650 51,770 65,230 332,000 365,000 285,300
Electric Power, kW . 233 273 308 1,676 1,876 1,275
Fuel Gas, 106 x Btu/hr 10.11 24.30 37.84 83.13 124.6 159.3
EXPORTED TO BATTERY LIMITS
600-psig Steam, Ib/hr 5,490 7,930 11,710 65,305 89,200 44,036
250-psig Steam, Ib/hr 15,160 14,984 15,736 169,206 151,601 83,165
50-psig Steam, Ib/hr 7,880 11,640 12,120 79,751 104,211 82,280
15-psig Steam, Ib/hr 1,620 3,140 4,610 4,043 5,400 5,800
Steam Condensate, Ib/hr 5,430 12,570 19,150 4,000 4,000 61,664
Catalyst Cost, $/day 34.00 61.80 87.83 266.98 339.98 343.08
E-49
-------
Table 6-4 (Table E-20)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst and Chemical Costs
BSR/MDEA Tail Gas Cases
CASE NO.
Claus - No. Stages
Sulfur Input, LT/D
H2S/C02 Ratio
REQUIRED FROM BATTERY LIMITS
Cooling Water (25eF Rise), gpm
50-psig Steam Required, Ib/hr
Treated B.F. Water, Ib/hr
Electric Power, kW
Fuel Gas, 106 x Btu/hr
EXPORTED TO BATTERY LIMITS
600-psig Steam, Ib/hr
450-psig Steam, Ib/hr
250-psig Steam, Ib/hr
15-psig Steam, Ib/hr
Steam Condensate, Ib/hr
Catalyst and Chemical
Costs, $/day
11
12
23
3
100
50/50
1,638
13,277
44,430
565
20.5
5,213
-
15,406
1,950
33,547
3
100
20/80
6,021
77,523
70,950
1,020
48.0
7,747
-
15,865
4,202
117,663
3
1,000
50/50
16,380
133,904
442,500
4,513
205
89,600
28,590
154,056
6,498
281,800
3
555
20/80
33,420
436,073
391,500
5,318
266.5
72,542
8,824
88,051
7,770
644,976
292.40 645.00 2,923.90 3,578.60
E-50
-------
Table 6-5 (Table E-21)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst Costs
Recycle Selectox 3-Stage Process
CASE NO.
8B
8C
10B
Sulfur Input, LT/D
H2S/C02 Ratio
Waste Heat Recovery
REQUIRED FROM BATTERY LIMITS
Catalyst Cost, $/day
11.37
12.76
114.67
IOC
10
20/80
No
10
12.5/87.5
No
100
20/80
Yes
100
12.5/87.5
Yes
600-psig Steam, Ib/hr
Treated B.F. Water, Ib/hr
Electric Power, kW
Fuel Gas, 106 Btu/hr
EXPORTED TO BATTERY LIMITS
600-psig Steam, Ib/hr
250-psig Steam, Ib/hr
50-psig Steam, Ib/hr
15-psig Steam, Ib/hr
Steam Condensate, Ib/hr
1,538
3,551
114
2.54
2,160
288
2,538
2,141
3,782
104
3.82
2,240
429
3,243
57,038
827
25.37
3,275
2,232
36,100
2,880
16,880
70,148
727
38.18
6,610
3,365
30,930
4,290
32,910
128.04
E-51
-------
Table 6-6 (Table E-22)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst and Chemical Costs
Beavon Sulfur Removal Process (BSRP)
CASE NO. 13 14 26 27
Sulfur Input, LT/D 100 100 1,000 555
H2S/C02 Ratio 50/50 20/80 50/50 20/80
REQUIRED FROM BATTERY LIMITS
Treated B.F. Water, Ib/hr 31,240 39,920 310,400 219,500
Cooling Water (25°F Rise), gpm 1,320 2,136 13,200 11,850
Electric Power, kW 700 870 5,850 4,530
Fuel Gas, 106 x Btu/hr 7.34 17.65 73.36 97.97
EXPORTED TO BATTERY LIMITS
450-psig Steam, Ib/hr - - 24,030 27,420
250-psig Steam, Ib/hr 14,580 10,230 145,800 56,780
50-psig Steam, Ib/hr 11,770 20,020 118,460 101,490
15-psig Steam, Ib/hr 1,380 2,400 3,020 1,670
Steam Condensate, Ib/hr 2,360 5,364 7,650 21,645
Catalyst and Chemical
Costs, $/day 181.40 295.30 1,814.00 1,639.00
E-52
-------
Table 6-7 (Table E-23)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst Costs
BSR/Selectox Process
CASE NO. 17 18 32 33
Claus - No. Stages 2222
Sulfur Input, LT/D 100 100 1,000 555
H2S/C02 Ratio 50/50 20/80 50/50 20/80
REQUIRED FROM BATTERY LIMITS
Cooling Water (25°F Rise), gpm 186 388 1,860 2,153
Treated B.F. Water, Ib/hr 39,383 60,028 393,201 333,282
Electric Power, kW 343 419 2,575 1,913
Fuel Gas, 106 x Btu/hr 15.3 37.2 153 206
EXPORTED TO BATTERY LIMITS
600-psig Steam, Ib/hr 8,200 19,178 82,003 106,455
450-psig Steam, Ib/hr - - 23,890 27,300
250-psig Steam, Ib/hr 15,066 15,052 150,656 83,539
50-psig Steam, Ib/hr 12,800 19,940 119,800 100,481
15-psig Steam, Ib/hr 2,170 4,110 5,400 5,800
Steam Condensate, Ib/hr 7,227 17,007 32,370 86,288
Catalyst Cost, S/day 101.00 195.00 1,010.00 1,082.00
E-53
-------
Table 6-8 (Table E-24)
Onshore Sour Natural Gas Sulfur Recovery Study
Utilities and Catalyst Costs
Sulfreen Process
CASE NO.
Claus - No. Stages
Sulfur Input, LT/D
H2S/C02 Ratio
REQUIRED FROM BATTERY LIMITS
Treated B.F. Water, Ib/hr
Electric Power, kW
Fuel Gas, 106 x Btu/hr
EXPORTED TO BATTERY LIMITS
600-psig Steam, Ib/hr
250-psig Steam, Ib/hr
50-psig Steam, Ib/hr
15-psig Steam, Ib/hr
Steam Condensate, Ib/hr
Catalyst Cost, $/day
15
16
29
30
3
100
50/50
3
100
20/80
3
1,000
50/50
3
555
20/80
37,348
365
11.9
68.00
55,737
445
26.9
372,061
2,863
119.4
124.00
680.00
307,234
2,130
149.5
6,106
15,224
7,669
1,620
5,641
11,382
15,382
11,273
3,140
12,937
95,367
152,246
102,100
5,400
6,111
63,172
85,369
80,241
5,800
63,703
686.00
E-54
-------
SULFUR RECOVERED
The average sulfur recovered in LT/D for each of the cases is given in
Tables 6-9, 6-10, and 6-11. These figures are based on the average of
start-of-run and end-of-run recoveries, and are provided for applying credits
for sulfur sales in the calculation of operating costs.
E-55
-------
Table 6-9 (Table E-25)
Onshore Sour Natural Gas Sulfur Recovery Study
Sulfur Recovered (LT/D), Average During Run
Acid Gas H2S/C02 Ratios of 80/20 and 50/50
THERMAL OXIDIZER
i
en
CASE
NO.
Acid
19
Acid
1
3
5
7
9
11
13
15
17
20
23
26
29
32
SULFUR
INPUT
(LT/D)
Gas H?S/CO?
1,000
Gas H2S/C02
5
5
10
10
100
100
100
100
100
1,000
1,000
1,000
1,000
1,000
SULFUR
NO.
STAGES
Ratio -
3
Ratio -
^
2
2
3
3
3
3
3
2
3
3
3
3
2
RECOVERY
80/20
50/50
No
UNIT
TYPE
Recycle Selectox
Claus
Glaus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
TAIL GAS
UNIT
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
WASTE
HEAT
RECOVERY
Yes
No
No
No
No
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
SULFUR
RECOVERED
(LT/D)
966.40
-0-
4.69
9.38
9.61
96.05
99.95
99.99
98.42
98.49
960.50
999.50
999.90
984.20
984.90
*Combustor only
-------
en
Table 6-10 (Table E-26)
Onshore Sour Natural Gas Sulfur Recovery Study
Sulfur Recovered (LT/D), Average During Run
Acid Gas H2S/C02 Ratio of 20/80
THERMAL OXIDIZER
CASE
NO.
2
4
6
6B
8
8B
10
10B
12
14
16
18
21
24
27
30
33
SULFUR
INPUT
(LT/D)
5
5
10
10
10
10
100
100
100
100
100
100
555
555
555
555
555
SULFUR
NO.
STAGES
^
2
2
2
3
3
3
3
3
3
3
2
3
3
3
3
2
RECOVERY UNIT
TYPE
No
Recycle Selectox
Glaus
Recycle Selectox
Claus
Recycle Selectox
Claus
Recycle Selectox
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
Claus
TAIL GAS
UNIT
No
No
No
No
No
No
No
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
No
BSR/MDEA
BSRP
Sulfreen
BSR/Selectox
INCLUDED
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No*
Yes
Yes
Yes
Yes
No*
Yes
Yes
WASTE
HEAT
RECOVERY
No
No
No
No
No
No
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
No
Yes
Yes
SULFUR
RECOVERED
(LT/D)
-0-
4.60
9.18
9.20
9.45
9.54
94.50
95.39
99.90
99.99
97.80
97.84
524.50
554.40
554.90
542.80
543.00
*Combustor only
-------
I
en
CD
Table 6-11 (Table E-27)
Onshore Sour Natural Gas Sulfur Recovery Study
Sulfur Recovered (LT/D), Average During Run
Acid Gas H2S/C02 Ratio of 12.5/87.5
CASE
NO.
4A
6A
6C
8A
8C
10A
IOC
SULFUR
INPUT
(LT/D)
5
10
10
10
10
100
100
SULFUR
NO.
STAGES
2
2
2
3
3
3
3
RECOVERY UNIT
TYPE
Recycle Se:
Claus
Recycle Se:
Claus
Recycle Se
Claus
Recycle Se:
No
THERMAL OXIDIZER
Yes
No
A.55
No
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
Yes
Yea
9.13
9.10
9.34
9.42
93.39
94.19
-------
OTHER DIRECT OPERATING COST DATA
The required number of operators per shift are:
Case No. No. per Shift
1 and 2 Negligible
3, 4, 4A, 6B, 6C, 8B, 8C, 10B, IOC 0.75
5, 6, 6A, 7, 8, 8A, 9, 10, 10A, 19, 20, 21 1.25
All others 2.25
Add 0.25 to all cases except 1 and 2 for shift supervision.
For annual maintenance costs assume:
Labor 1-1/2% of investment
Materials 2% of investment
E-59
-------
APPENDIX F
Unit natural gas production cost, UPC, (Table 9-4) equals:
1-itc
n
- t I
y-l
Dep
(l+d)y
> + Ie-
+ (1-t) (
L
DIT £
°y-l
(l+qrate)y
(l+r)y
UPC
L (l+qrate)y
Qn (1-roy) (1-t + t depl) £
0 y-1 (1+r)
It was assumed that:
itc = investment tax credit rate, .1
t = corporate income tax rate on marginal income, .47
n = depreciation period, 10
Dep = ACRS depreciation rates, 10 year life
d = nominal discount factor, .10
I. = drilling cost, input $
I - equipment cost, input $
OC - annual operating and maintenance cost, input $
L - well life, 20
qrate = production (and operating cost) decline rate, -0.06
r = real discount factor, .019
Q = annual production, input mcfy.
roy = royalty payment rate, .2
depl s percentage depletion allowance, .15
F-l
------- |