xvEPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-90-016a
June 1990
Air
Reactor
Processes in
Synthetic Organic
Chemical
Manufacturing
Industry-
Background
Information for
Proposed
Standards
Draft
EIS
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EPA-450/3-90-0163
Reactor Processes in
Synthetic Organic Chemical
Manufacturing Industry —
Background Information
for Proposed Standards
Emissions Standards Division
U.S. Environmental Protection
Region 5. library (PH 2J)
77 West Jackson Boulevard, 12th Floor
Chicago, It 60604-3590
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
June 1990
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Environmental Impact Statement
for Volatile Organic Compound Emissions from
Reactor Processes in
Synthetic Organic Chemical Manufacturing
Prepared by:
R. Farmer "^~ ' /(Date)
Director, Emission Standards Division
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
1. The proposed standards of performance will limit emissions of volatile
organic compounds from new, modified, and reconstructed reactor
processes. Section 111 of the Clean Air Act (42 U. S. C. 7411), as
amended, directs the Administrator to establish standards of performance
for any category of new stationary source of air pollution that ". . .
causes or contributes significantly to air pollution which may
reasonably be anticipated to endanger public health or welfare."
2. Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transportation,
Agriculture, Commerce, Interior, and Energy; the National Science
Foundation; State and Territorial Air Pollution Program Administrators;
EPA Regional Administrators; Local Air Pollution Control Officials;
Office of Management and Budget; and other interested parties.
3. For additional information contact:
Mr. Doug Bell
Standards Development Branch (MD-13)
U. S. Environmental Protection Agency
Research Triangle Park, N. C. 27711
Telephone: (919) 541-5568
4. Copies of this document may be obtained from:
U. S. EPA Library (MD-35)
Research Triangle Park, N. C. 27711
Telephone: (919) 541-2777
National Technical Information Service
5285 Port Royal Road '
Springfield, VA 22161
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This report has been reviewed by the Emission Standards Division of the Office
of Air Quality Planning and Standards, EPA, and approved for publication.
Mention of trade names or commercial products is not intended to constitute
endorsement or recommendation for use. Copies of this report are available
through the Library Services Office (MD-35), U.S. Environmental Protection
Agency, Research Triangle Park, N.C. 27711, or from National Technical
Information Services, 5285 Port Royal Road, Springfield, Virginia 22161.
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TABLE OF CONTENTS
Chapter Page
LIST OF TABLES viii
LIST OF FIGURES xiii
1.' SUMMARY 1-1
1.1 REGULATORY ALTERNATIVES 1-1
1.2 ENVIRONMENTAL IMPACTS 1-3
1.3 ECONOMIC IMPACT 1-4
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 2-5 •
2.4 CONSIDERATION OF COSTS 2-7
2.5 CONSIDERATION OF ENVIRONMENTAL IMPACTS 2-7
2.6 IMPACT ON EXISTING SOURCES 2-8
2.7 REVISION OF STANDARDS OF PERFORMANCE 2-9
3. REACTOR PROCESSES AT SYNTHETIC ORGANIC CHEMICAL
MANUFACTURING PLANTS ; 3-1
3.1 DESCRIPTION OF REACTOR PROCESSES AT SYNTHETIC
ORGANIC CHEMICAL MANUFACTURING PLANTS 3-1
3.1.1 Introduction 3-1
3.1.2 Scope of Reactor Processes 3-2
3.2 CHEMICAL REACTIONS AND REACTOR VOC EMISSIONS 3-2
3.2.1 Classification of Chemicals by Reaction
Type 3-2
3.2.2 Reactor VOC Emissions 3-5
3.3 EMISSION DATA PROFILE 3-11
3.4 BASELINE EMISSIONS 3-15
3.4.1 Method of Calculating Baseline Emissions 3-17
3.4.2 State Regulations and Industrial
Practices Impacting Baseline Emissions 3-18
3.5 CHEMICAL REACTION DESCRIPTIONS 3-19
3.6 REFERENCES FOR CHAPTER 3 3-33
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TABLE OF CONTENTS (CONTINUED)
Chapter paqe
4. EMISSION CONTROL TECHNIQUES 4-1
4.1 NONCOMBUSTION CONTROL DEVICES 4-2
4.1.1 Condensation 4.3
4.1.1.1 Condensation Process Description 4-3
4.1.1.2 Condenser Control Efficiency 4-3
4.1.1.3 Applicability of Condensers 4-3
4.1.2 Absorption 4-5
4.1.2.1 Absorption Process Description 4-5
4.1.2.2 Absorption Control Efficiency 4-6
4.1.2.3 Applicability of Absorption 4-6
4.1.3 Adsorption 4-6
4.1.3.1 Adsorption Process Description 4-6
4.1.3.2 Adsorption Control Efficiency 4-10
4.1.3.3 Applicability of Adsorption 4-10
4.2 COMBUSTION CONTROL DEVICES 4-11
4.2.1 Flares 4-11
4.2.1.1 Flare Process Description 4-11
4.2.1.2 Flare Combustion Efficiency 4-14
4.2.1.3 Applicability of Flares 4-18
4.2.2 Thermal Incinerators . 4-18
4.2.2.1 Thermal Incinerator Process
Description 4-18
4.2.2.2 Thermal Incinerator Removal
Efficiency 4-22
4.2.2.3 Applicability of Thermal
Incinerators 4-23
4.2.3 Industrial Boilers and Process Heaters 4-23
4.2.3.1 Industrial Boiler Description 4-23
4.2.3.2 Process Heater Description 4-24
4.2.3.3 Industrial Boilers and Process
Heater Control Efficiency 4-24
4.2.3.4 Applicability of Industrial Boilers
and Process Heaters as Control
Devices 4-25
4.2.4 Catalytic Oxidizer 4-26
4.2.4.1 Catalytic Oxidizer Process
Description 4-26
4.2.4.2 Catalytic Oxidizer Control
Efficiency 4-28
4.2.4.3 Applicability of Catalytic
Oxidizers 4-28
4.3 SUMMARY 4-28
4.4 REFERENCES FOR CHAPTER 4 4-29
ii
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TABLE OF CONTENTS (CONTINUED)
Chapter Page
5. MODIFICATIONS AND RECONSTRUCTIONS 5-1
5.1 MODIFICATION 5-1
5.2 RECONSTRUCTION 5-2
5.3 EXAMPLES OF MODIFICATIONS AND RECONSTRUCTIONS AT
EXISTING REACTOR FACILITIES 5-2
5.3.1 General Examples 5-2
5.3.2 Specific Examples 5-3
5.4 REFERENCES FOR CHAPTER 5 5-4
6. REGULATORY ANALYSIS 6-1
6.1 OVERVIEW OF THE REGULATORY ANALYSIS 6-1
6.2 SELECTION OF THE COMBUSTION CONTROL TECHNIQUES USED
IN THE REGULATORY ANALYSIS 6-2
6.3 DEVELOPMENT OF REGULATORY ALTERNATIVES 6-3
6.3.1 Introduction and Summary 6-3
6.3.2 Characteristics of the New, Modified, and
Reconstructed Reactor Process Units
Included in'the Regulatory Analysis 6-4
6.3.2.1 General Process Unit Definition and
Description 6-4
6.3.2.2 Number, Type, and Capacity of Process
Units 6-5
6.3.2.3 Vent Stream Characteristics 6-8
6.3.3 Description of the Regulatory Alternatives 6-11
6.4 REFERENCES FOR CHAPTER 6 6-13
7. ENVIRONMENTAL AND ENERGY IMPACTS 7-1
7.1 INTRODUCTION 7-1
7.2 AIR POLLUTION IMPACTS 7-2
7.2.1 Method of Estimating VOC Emissions and
Emission Reductions 7-2
7.2.2 VOC Emissions Impacts 7-3
7.2.3 Other Effects on Air Quality 7-6
7.3 WATER POLLUTION IMPACTS 7-7
7.4 SOLID WASTE DISPOSAL IMPACTS 7-8
7.5 ENERGY IMPACTS 7-8
7.6 OTHER ENVIRONMENTAL IMPACTS 7-9
7.6.1 Considerations for Installing Control
Equipment 7-9
7.7 OTHER ENVIRONMENTAL CONCERNS 7-9
7.7.1 Irreversible and Irretrievable Commitment
of Resources 7-9
7.7.2 Environmental Impact of Delayed Standards 7-9
7.8 REFERENCES FOR CHAPTER 7 7-10
iii
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TABLE OF CONTENTS (CONTINUED)
Chapter
8. COSTS
8.1 CONTROL SYSTEM DESIGN ................... 8-1
8.1.1 Thermal Incinerator Design ............. 8-1
8.1.1.1 General Design Criteria .......... 8-1
8.1.1.2 Thermal Incinerator Design
Categories ............... 8-3
8.1.1.3 Incinerator Auxiliary Equipment ...... 8-8
8.1.2 Flare Design .................... 8-9
8.1.2.1 General Design Criteria .......... 8-9
8.1.2.2 Flare Auxiliary Equipment ......... 8-11
8.2 CAPITAL COSTS ....................... 8-13
8.2.1 Thermal Incinerator ................ 8-13
8.2.2 Flare ...................... 8-14
8.3 ANNUAL COSTS ....................... 8-16
8.3.1 Labor ...................... 8-18
8.3.2 Utilities ..................... 8-18
8.3.3 Fuel Requirements for Incinerators ......... 8-19
8.3.4 Fuel Requirements for Flares ............ 8-19
8.3.5 Natural Gas Price ................. 8-20
8.3.6 Other Annual Costs ................. 8-20
8.4 COMPARISON OF CONTROL SYSTEM COSTS ............ 8-20
8.5 NATIONAL COST IMPACTS ................... 8-25
8.5.1 Determination of National Cost Impacts ....... 8-25
8.5.2 Results of the Cost Analysis ............ 8-26
8.6 CONTROL COST ACCUMULATION FOR REACTOR PROCESS
CHEMICALS ........................ 8-28
8.6.1 Introduction .................... 8-28
8.6.2 Background - Industry, Standards, and
Methodology ................... 8-28
8.6.2.1 Reactor Process Industry ......... 8-28
8.6.2.2 Previous Standards ............ 8-30
8.6.2.3 Methodology ................ 8-31
8.6.3 Data and Assumptions for Accumulating
Costs ...................... 8-32
8.6.3.1 Benzene Fugitive Emissions NESHAP ..... 8-36
8.6.3.2 VOC Fugitive Emissions in SOCMI and
Petroleum Refining Fugitive
Emissions NSPS ............. 8-36
8.6.3.3 Volatile Organic Liquid Storage
Tanks NSPS ............... 8-37
8.6.3.4 Distillation NSPS ............. 8-37
8.6.3.5 Reactor Processes NSPS .......... 8-38
8.6.4 Cost Conversion .................. 8-38
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TABLE OF CONTENTS (CONTINUED)
Chapter Page
8.6.5 Presentation of the Cumulative Impact
of Seven Clean Air Act Standards on the
SOCMI Industry 8-39
8.7 REFERENCES FOR CHAPTER 8 8-42
9. ECONOMIC ANALYSIS 9-1
9.1 INDUSTRY PROFILE 9-1
9.1.1 Industry Overview 9-1
9.1.1.1 Definition of SOCMI 9-1
9.1.1.2 Description of the Reactor Processes
Chemical Group 9-2
9.1.2 Supply and Demand 9-8
9.1.2.1 Supply Conditions 9-8
9.1.2.2 Demand Conditions 9-12
9.1.3 Market Structure 9-19
9.1.3.1 Chemical Firms 9-19
9.1.3.2 Geographic Distribution, Number,
and Size of Plants 9-19
9.1.3.3 Firm Concentration 9-29
9.1.3.4 Vertical Integration and
Diversification 9-29
9.1.3.5 Returns to Scale 9-30
9.1.3.6 Industry Cost Structure 9-31
9.1.3.7 Entry Conditions 9-31
9.1.4 Pricing 9-31
9.1.4.1 Homogeneity of Product 9-31
9.1.4.2 Degree of Concentration and Barriers
to Entry 9-32
9.1.4.3 Observed Pricing Practices 9-33
9.1.5 Market Performance 9-33
9.1.5.1 Financial Profile of the Industry 9-35
9.1.5.2 Trends in the Chemical Industry 9-43
9.1.6 Five-Year Industry Growth Projections 9-44
9.1.6.1 Projection of Capacity
Requirements . 9-45
9.1.6.2 Process Unit Projections 9-55
9.2 ECONOMIC IMPACT 9-64
9.2.1 Control Cost Impacts 9-67
9.2.2 Price Impacts 9-69
9.2.2.1 Price Analysis Assumptions 9-69
9.2.2.2 Reasonable Worst Case Scenario 9-71
9.2.2.3 More Likely Case Scenario 9-76
9.2.3 Other Economic Impacts 9-78
9.2.3.1 Quantity Impacts 9-78
9.2.3.2 Distributional Impacts 9-80
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TABLE OF CONTENTS (CONTINUED)
Chapter
Page
9.3
9.2.3.3 Employment and Capital
Requirements 9-81
REGULATORY, INFLATIONARY, SOCIOECONOMIC, AND SMALL
BUSINESS IMPACTS 9-83
9.3.1 Executive Order 12291 9-83
9.3.2 Small Business Impacts 9-85
9.3.2.1 Regulatory Flexibility Act
Considerations 9-85
9.3.2.2 Burden of Cost Analysis 9-86
9.4 IMPACTS OF THE ACCUMULATION OF COSTS FROM THE REACTOR
PROCESS NSPS AND OTHER AIR QUALITY STANDARDS 9-86
9.4.1 Price Impacts of Cumulative Costs 9-87
9.4.2 Quantity Impacts of Cumulative Costs 9-87
9.5 REFERENCES FOR CHAPTER 9 9-93
APPENDIX A. EVOLUTION OF THE PROPOSED STANDARD A-l
APPENDIX B. INDEX TO ENVIRONMENTAL CONSIDERATIONS B-l
APPENDIX C. EMISSION DATA PROFILE C-l
APPENDIX D. EMISSION MEASUREMENT D-1
D.I INTRODUCTION D-1
D.I.I VOC Measurement D-2
D.I.2 Emission Measurement Tests D-2
D.2 PERFORMANCE TEST METHODS D-3
APPENDIX E. LIST OF 173 SYNTHETIC ORGANIC CHEMICALS
BEING CONSIDERED FOR REGULATION E-l
APPENDIX F. TRE EQUATION AND COEFFICIENT DEVELOPMENT
FOR THERMAL INCINERATORS AND FLARES F-l
F.I INTRODUCTION F-l
F.2 INCINERATOR SYSTEM TRE EQUATION F-l
F.2.1 Incinerator TRE Index Equation Development F-l
F.2.2 Example Calculation of an
Incinerator-based TRE Index
Value for a Facility F-4
F.3 FLARE SYSTEM TRE DEVELOPMENT F-6
F.3.1 Development of the Flare TRE Index Equation F-6
F.3.2 Flare TRE Coefficients Verification F-8
F.3.3 Example Calculation of a Flare-based TRE
Index Value for a Facility F-14
vi
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TABLE OF CONTENTS (CONCLUDED)
Chapter Page
APPENDIX G. FEDERAL REGISTER NOTICE OF ORGANIC COMPOUNDS
DETERMINED TO HAVE NEGLIGIBLE PHOTOCHEMICAL
REACTIVITY G-l
APPENDIX H. CHEMICAL SCREENING ANALYSIS DATA H-l
H.I CHEMICALS AFFECTED H-l
H.2 SCREENING ANALYSIS INPUT FILES H-15
H.3 SCREENING ANALYSIS PROGRAM H-24
H.4 SCREENING ANALYSIS RESULTS H-29
H.5 QUANTITY AND DISTRIBUTIONAL IMPACTS
DISCUSSION H-35
H.6 PROCESS ROUTES H-44
VI1
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LIST OF TABLES
Table
1-1 Matrix of Environmental and Economic Impacts for the
Extremes of Regulatory Alternatives Considered ... 1-5
3-1 Breakdown of VOC Emissions from the SOCMI 3-4
3-2 Ranking of Chemical Reaction Types 3-6
3-3 Overview of the Emission Data Profile 3-13
3-4 Summary of Reactor-Related VOC Emission
Factors, Vent Stream Heat Contents,
and Flowrate Prior to Combustion 3-14
3-5 Distribution of Recovery and Combustion
Devices for the 127 Process Units in the
Emission Data Profile 3-16
4-1 Flare Emission Studies Completed by October 1982 . . . 4-16
6-1 Summary of New, Modified, and Reconstructed Reactor
Process Unit Capacities 6-7
6-2 Summary of New, Modified, and Reconstructed
Reactor Process Unit Vent Stream
Characteristics 6-9
6-3 Number and Percentage of Process Units Expected to be
Controlled at Various TRE Levels 6-12
7-1 Environmental and Energy Impacts of the Regulatory
Alternatives (Metric Units) 7-4
7-2 Environmental and Energy Impacts of the Regulatory
Alternatives (English Units) 7-5
8-1 Incineration General Design Criteria 8-4
8-2 Design Category Boundary Values for Reactor Process
Vent Stream Flowrates and Ratio of Flue Gas
Flowrate to Offgas Flowrate 8-6
8-3 Flare General Design Criteria 8-10
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LIST OF TABLES (CONTINUED)
Table Page
8-4 Flare Installation Factors 8-15
8-5 Bases for Annual ized Control System Costs 8-17
8-6 Cost Comparisons for Control of Example Reactor
Process Vent Streams 8-22
8-7 Summary of Cost Impacts at Selected Regulatory
Alternatives 8-27
8-8 Projected Facility Size and Cost for
26 Reactor Process Chemicals ... 8-29
8-9 Facility-Specific Costs of the Benzene Fugitive
Emissions NESHAP for Benzene Consuming Reactor
Processes Chemicals with Projected Capacity
Additions 8-33
8-10 Annualized Control Costs in Fifth Year After
Proposal for Four Air Quality Standards Based
on Facility Projections for 26 Reactor Processes
Chemicals 8-34
8-11 Annualized Control Costs in Fifth Year After
Proposal for Seven Air Quality Standards Based
on Facility Projections for 26 Reactor Processes
Chemicals 8-40
9-1 Production, Foreign Trade, and Prices for 173 Reactor
Processes Chemicals, United States, 1982 9-3
9-2 Comparison of Price Indexes Between Crude Oil and the
Average Price of Five Oil-based Chemicals,
1970-1984 9-10
9-3 Comparison of Price Indexes Between Natural Gas and
the Average Price of Five Gas-based Chemicals,
1970-1984 9-11
9-4 Capital Expenditures in U.S. for Chemicals and Allied
Products Industry and All Manufacturing,
1973-1983 9-13
IX
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LIST OF TABLES (CONTINUED)
Table Page
9-5 Number of Companies, Establishments, and Employees
for Industrial Organic Chemicals, 1958-1981 9-14
9-6 Productivity and Unit Labor Costs in U.S. for Chemicals
and Allied Products Industry and All Manufacturing
1972-1982 9-14
9-7 Historical Production and Sales of Industrial
Organic Chemicals, 1955-1981 9-16
9-8 U.S. Foreign Trade for Industrial Organic
Chemicals, 1972-1982 9-17
9-9 Top 25 U.S. Chemical Producers, 1982 9-20
9-10 Number, Capacity, and Location of Plants Producing
the 173 Reactor Processes Chemicals in 1982 9-21
9-11 Price Indexes for U.S. Chemical and Other Industries
1972-1982 9-34
9-12 Median Financial Ratios for SIC Industries 2865
and 2869, 1980 9-36
9-13 Financial Data for Top 25 U.S. Chemical Producers,
1982 9-40
9-14 Cash Flow for Major Chemical Producers, 1978-1982 . . 9-41
9-15 Debt Ratios for the U.S. Chemical Industry and
Manufacturing, 1978-1982 9-42
9-16 Projected U.S. Production, Capacity, and Growth Rates
for Reactor Processes Chemicals for 1985 9-46
9-17 End-Use Group Average Growth Rates, Ratios of
Retired Capacity to 1990 Production, and Capacity
Utilization for Reactor Processes Chemicals in
the 1980's 9-53
9-18 U.S. Consumption and Capacity Projections and Required
Capacity for 110 Reactor Processes Chemicals
in 1990 9-56
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LIST OF TABLES (CONTINUED)
Table Page
9-19 Projected Required Capacity, Typical Plant Size,
Number of Process Units, and Capacity Utilization
for 26 Reactor Processes Chemicals in 1990 9-65
9-20 Control Costs for Regulatory Alternatives, 1982$ . . . 9-68
9-21 Chemical Coproducts and Byproducts of Principal
SOCMI Product Chemicals , 9-74
9-22 Chemicals with Price Increases Greater than
5 Percent: Reasonable Worst Case Screening 9-75
9-23 Price Increases Before and After Recalculation
of Annual Control Cost for Vinyl Trichloride .... 9-77
9-24 Quantity Impacts in 1990 Due to Control Costs
Required by the Regulation 9-79
9-25 Distributional Impacts in 1990 Due to Control
Costs Required by the Regulation 9-82
9-26 Price Impacts of Cumulated Costs from Seven
Air Quality Standards for 26 Reactor
Processes Chemicals . 9-88
9-27 Quantity Impacts of Cumulated Costs from Seven
Air Quality Standards for 26 Reactor
Processes Chemicals 9-90
F-l Reactor Processes NSPS TRE Coefficients for Vent
Streams Controlled by an Incinerator F-2
F-2 Reactor Processes NSPS TRE Coefficients for Vent
Streams Controlled by a Flare F-9
F-3 TRE Index Values Generated Using TRE Coefficients
and the Flare Cost Algorithm Net Heating Value
Greater Than or Equal to 300 Btu/scf F-ll
F-4 Percent Difference Between TRE Index Values
Generated Using TRE Equation and the.Flare
Cost Algorithm Net Heating Value Less Than
300 Btu/scf F-12
XI
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LIST OF TABLES (CONCLUDED)
Table Page
F-5 Percent Differences Between TRE Index Values
Generated by the Cost Algorithm and the TRE
Equation for Vent Streams with Heating Values
Less Than 40 Btu/scf F-13
H-l List of Chemicals by Chemical Number H-2
H-2 Reasonable Worst-Case Input File H-16
H-3 More Likely Case Input File H-21
H-4 Reasonable Worst-Case Price Impacts .... H-30
H-5 More Likely Case Price Impacts. ........... H-36
H-6 Quantity and Distributive Impacts
Input File 1 H-39
H-7 Quantity and Distributive Impacts
Input File 2 H-40
H-8 Quantity Impacts Output File H-42
H-9 Distributional Impacts Output File H-43
xii
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LIST OF FIGURES
Figure Page
3-1 Emissions Groups Within the SOCMI 3-3
3-2 General Examples of Reactor-Related Vent Streams . . . 3-7
3-3 Process Flow Diagram for the Manufacture of
Nitrobenzene ..... 3-8
3-4 Process Flow Diagram for the Manufacture of
Ethyl benzene 3-9
3-5 Process Flow Diagram for the Manufacture
of Acetone 3-10
4-1 Condensation System 4-4
4-2 Packed Tower for Gas Absorption 4-7
4-3 Two Stage Regenerative Adsorption System 4-9
4-4 Steam-Assisted Elevated Flare System 4-12
4-5 Discrete Burner, Thermal Incinerator 4-19
4-6 Distributed Burner, Thermal Incinerator 4-21
4-7 Catalytic Oxidizer 4-27
8-1 Annualized Control Cost Comparisons for
Example Reactor Process Vent Streams 8-24
9-1 U.S. Chemical Industry Annual Profit Margin:
After-Tax Earnings as a Percentage of Net
Sales, 1970-1980 9-37
9-2 U.S. Chemical Industry Annual Return on Stockholders'
Equity: After-Tax Earnings as a Percentage of
Stockholders' Equity, 1970-1980 9-38
xi 11
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LIST OF FIGURES (CONCLUDED)
Page
H-l Screening Analysis Program H-25
H-2 Production Process Routes H-45
xiv
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1. SUMMARY
New source performance standards (NSPS) are being developed for the
synthetic organic chemical manufacturing industry under authority of
Section 111 of the Clean Air Act, as amended 1977. Emissions of volatile
organic compounds (VOC) from various sources in this source category are
being considered under several standards development programs. This
background information document supports the development of NSPS for VOC
emissions from reactor processes used to manufacture synthetic organic
chemicals. The list of chemicals considered in this document is presented in
Appendix E.
1.1 REGULATORY ALTERNATIVES
Reactor VOC emissions include all VOC in process vent streams from
reactors and process product recovery systems. Not included in process
equipment are product purification devices involving distillation operations.
Two broad categories of reactor processes are liquid phase reactions and gas
phase reactions. Four potential atmospheric emission points include: direct
reactor process vents from liquid phase reactors, vents from product recovery
devices applied to vent streams from liquid phase reactors, vents from gas
phase reactors after either the primary or secondary product recovery device,
and exhaust gases from combustion devices applied to any of these streams.
Some chemical production processes may have no reactor process vent to the
atmosphere, while others may have one or more vent streams.
There are numerous control techniques applicable to the reduction of VOC
emissions from reactor processes. Some of these techniques are used
primarily for product recovery; these techniques include condensation, carbon
adsorption, and gas absorption. Product recovery device performance varies
with stream characteristics, and as a consequence, it is not possible with
available information to identify subcategories of reactor processes for
which these devices would always be applicable. As a result, product
recovery devices were not analyzed in the regulatory analysis.
Combustion control techniques have been demonstrated to be applicable to
all reactor process vent streams and universally achieve higher VOC
destruction efficiency than other demonstrated control technologies on
reactor process vent streams, generally for a reasonable cost. Therefore,
combustion control is selected as a candidate technology for the regulatory
analysis. Combustion can be achieved in thermal incinerators, catalytic
incinerators, boilers, process heaters, and flares. It is not possible to
identify subcategories of reactor process vent streams for which the use of
catalytic incinerators, process heaters, and boilers would always be
1-1
-------
applicable. Therefore, these devices were not considered in the regulatory
analysis. The remaining control technologies, thermal incinerators and
flares, were selected for the regulatory analysis. Both incinerators and
flares are capable of achieving at least 98-weight-percent VOC destruction.
Flares are applied to vent streams containing nonhalogenated VOC in the
regulatory analysis except when thermal incinerators are found to be less
expensive. Incinerators are applied to vent streams containing halogenated
VOC because flare tip corrosion may prohibit the use of flares and because
halogenated streams may create levels of secondary emissions that require
flue gas scrubbing (which is not possible from flared emissions). In the
regulatory analysis, when incinerators are applied to vent streams containing
halogenated VOC, the cost of a flue gas scrubber is included.
The regulatory analysis was based on the control of varying numbers of
new, modified, and reconstructed process units that are projected to come
on-line between 1985 and 1990 (the fifth year of the NSPS applicability). The
projections used in the analysis were prepared from data on reactor processes
tabulated in Chapter 9.
The concept of total resource effectiveness (TRE) is used to define
regulatory alternatives. TRE consists of an index of cost effectiveness,
where cost effectiveness is simply the annual cost of control divided by the
annual emissions reduction, expressed in dollars per megagram ($/Mg) of VOC
controlled. In analyzing the regulatory alternatives, flares and
incinerators were applied to the 56 reactor process units anticipated to be
candidates for the addition of VOC controls over the first 5 years of the
standards' applicability. The costs and TRE levels for each process unit are
then calculated and analyzed.
Each regulatory alternative is constituted by a chosen cost-effectiveness
cutoff level on the continuum of all possible values. Therefore, the propor-
tion of process units controlled under each alternative varies with the
cost-effectiveness cutoff level considered for the alternative. Because
fewer reactor process units are controlled at lower TRE cutoff values, the
range of alternatives examined results in increasing numbers of new, modi-
fied, and reconstructed reactor process units being controlled at higher
cutoff values. The baseline alternative is representative of no additional
combustion control applied to all of the 56 new, modified, and reconstructed
process units with uncombusted vent streams. The most stringent alternative
possible is representative of combustion controls applied to all 56 process
units. The range of TRE values which could be examined in the regulatory
analysis forms a continuum between these two extremes.
A particular TRE value can be selected to serve as a limit for requiring
VOC emissions control. When used in a standard, TRE values below the limit
would dictate use of.VOC emissions control. Values above the limit would
indicate that a higher level of control was already in place for purposes
such as product recovery or that the reactor process had inherently small VOC
emissions that proved extremely costly to control.
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1.2 ENVIRONMENTAL IMPACTS
When applied to a given reactor vent stream, flares and incinerators can
achieve 98-weight-percent destruction of VOC contained in the vent stream.
Thus, the control levels achieved in the regulatory analysis ranged from the
baseline control level of zero percent to the 98-weight-percent control level
assuming control of all process units; these control levels correspond to a
nationwide VOC emissions reduction attributable to the NSPS of zero megagram
per year (Mg/yr) (at baseline) to approximately 2,300 Mg/yr (at control of
all projected process units). In addition, other impacts of the regulatory
alternatives (water pollution, solid waste, energy) were examined. A matrix
describing the impacts of the extremes of the regulatory analysis (no control
over baseline, total control) is presented in Table 1-1.
The primary environmental impact of the regulatory alternatives is the
reduction of VOC emissions from reactor processes. The total VOC emissions
from all new, modified, and reconstructed process units under baseline is
estimated to be approximately 3,300 Mg/yr (3,600 tons/yr) in 1990. About
2,400 Mg/yr (2,600 tons/yr) of these VOC emissions are from process units
with vent streams where combustion is not projected to be used at baseline;
while about 910 Mg/yr (1,000 tons/yr) of these VOC emissions are emitted from
the outlets of combustion devices expected to use combustion devices in the
absence of an NSPS. Thus, 98 percent of 2,400 Mg/yr or approximately
2,300 Mg/yr (2,600 tons/yr) of VOC is available to be controlled under the
regulatory alternatives. The most stringent alternative at which this
emissions reduction would be achieved represents control of all projected
reactor process units. This maximum emissions reduction accounts for about
70 percent of all baseline VOC emissions and 98 percent of all VOC emissions
that are not currently controlled at the baseline control alternative.
Increases in other air pollutants as a result of the VOC emissions controls
examined are considered negligible. No direct solid wastes are expected to
result from implementation of any of the regulatory alternatives other than
negligible quantities of incinerator ash.
No increase in total facility VOC wastewater is projected due to
combustion or product recovery devices. There is no organic wastewater
associated with the combustion devices (flares and incinerators) considered
in the regulatory analysis. Product recovery may be chosen by the facility
owner or operator to reduce process vent stream emissions and, maintain a TRE
index at a desired level. Any product recovery device will - by definition -
recycle product, by-product, or reactant for process use, reuse, or sale.
Therefore, no significant amount of organic wastewater is anticipated to be
generated from these devices. Some facilities with halogenated VOC in the
vent stream may have to dispose of brine solutions from incinerator flue gas
scrubbers. However, few if any facilities with halogenated VOC are expected
to actually control as a result of a reactor process NSPS. Thus, little, if
any, salt disposal is expected to occur as a result of the standard.
Available data show that most plants with halogenated VOC are already using
combustion devices and many are disposing of the brine at a relatively low
cost in sewers, brackish water systems, and by other methods.
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The impact on the projected national energy usage depends upon the
regulatory alternative considered (degree of overall control) and the control
device used (flare, incinerator). For the most stringent alternative
(control of all reactor process units) the national energy usage in the fifth
year was estimated to be 520 terajoules per year (TJ/yr) (84,000 barrels of
fuel oil equivalent/year). For these estimates, an incinerator with flue gas
scrubbing was assumed to be used for halogenated vent streams, and the less
expensive of a flare and an incinerator was assumed to be used for non-
halogenated vent streams. Since process heaters, boilers, and product
recovery upgrading will be used, the energy impacts will be smaller than the
above estimates.
1.3 ECONOMIC IMPACT
The projected national costs of the regulatory alternatives depend upon
the degree of control considered and the control device used. For control of
all units, the projected national costs in the fifth year was estimated to be
$9.3 million/year.
A chemical price impact screening analysis (see Chapter 9 and Appendix H)
indicated that all of the chemicals considered under the scope of this
program would pass a 5 percent price increase criterion. Furthermore, the
vast majority could pass more stringent price increase criteria.
The economic analysis indicates that there would be no significant
impacts on industry structure, foreign trade, employment, growth, or capital
markets.
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TABLE 1-1. MATRIX OF ENVIRONMENTAL AND ECONOMIC IMPACTS FOR
THE EXTREMES OF REGULATORY ALTERNATIVES CONSIDERED
Solid
Air Water Waste Energy Economic
Administrative Action Impact Impact Impact Impact Impact
No NSPS
Control All Units
00 000
+2 -1 0 -1 to +1 -1
Key: 0 No Impact
1 Negligible Impact
2 Small Impact
3 Moderate Impact
4 Large Impact
+ Beneficial Impact
- Adverse Impact
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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
technologies and degrees of efficiency are examined. Each potential level
of control 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 able to
see 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.
The 1977 amendments to the Act altered or added numerous provisions
that apply to the process of establishing standards of performance.
1. The EPA is required to list the categories of major stationary
sources that have not already been listed and regulated under standards of
performance. 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.
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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
performance revised.
2. The EPA is required to review the standards of performance every
4 years, and, if appropriate, revise them.
3. The EPA is authorized to promulgate a standard based on design,
equipment, work practice, or operational procedures when a standard based on
emission levels is not feasible.
4. The term "standards of performance" is redefined, 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 nonpolluting 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 demon-
strated 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
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.
Congress does not intend that new source performance standards contribute to
these problems. Fifth, the standard-setting process should create incentives
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 ne.w 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
2-2
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significant 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 (BAT), 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,
environmental, and economic impacts and other costs, determines is
achievable for such facility through application of production
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 technology" result in emissions of any pollutants
which will exceed the emissions allowed by an applicable standard
established pursuant to Section 111 or 112 of this Act.
(Section 169(3))
Although standards of performance are normally structured in terms of
numerical emission limits where feasible, alternative approaches are
sometimes 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
standard 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(i) 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
Administrator must find: (1) a substantial likelihood that the technology
will produce greater emission reductions than the standards require or an
equivalent 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.
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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 of
sources in such list if in his judgment it causes, or contributes signifi-
cantly 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 1977, 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 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) estimated
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 an NSPS
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 endanger public
health or welfare; and (3) the mobility and competitive nature of each such
category of sources and the consequent need for nationally applicable NSPS.
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
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, inability to obtain emission data from
well-controlled sources in time to pursue the development process in a
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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
determined. A source category may have several facilities that cause air
pollution, 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
demonstrated 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
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.
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, and a
literature search is conducted. From the knowledge acquired about the
industry, EPA selects certain plants at which emission tests are conducted
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." (For the reactor processes
standard, there are a few deviations from this model plant and regulatory
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analysis approach, as described in Chapters 6 through 8.) These regulatory
alternatives are essentially different levels of emission control.
The EPA conducts studies to determine the impact of each regulatory
alternative on the economics of the industry and on the national economy, on
the environment, and on energy consumption. From several possible
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
representatives 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 standards, and a preamble
explaining the standards 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.
A "proposal package" is assembled and sent through the offices of the
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
regulation, the public is invited to participate in the standard-setting
process. The 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.
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The significant comments and the 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 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 assessment of economic impact 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 businesses 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. It should be noted
that the costs used in developing these standards were based on 1984 costs;
the year the technical analyses were performed. These base year costs,
however, would not significantly change the analysis or the requirements of
the standards.
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 captured
potential air pollutants may pose a solid waste disposal problem. The total
environmental impact of an emission source must, therefore, be analyzed 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
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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 decision making 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 Act.
Essentially, the Court of Appeals has determined that the best system of
emission reduction requires the Administrator to take into account counter-
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
human environment within the meaning of the National Environmental Policy
Act of 1979." (15 U.S.C. 793(c)(l)).
Nevertheless, the Agency has concluded that the preparation of
environmental 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
environmental 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
associated 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 lll(d) of the Act if the standard for new sources limits emissions
2-8
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of a designated pollutant (i.e., a pollutant for which air quality criteria
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.
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3. REACTOR PROCESSES AT SYNTHETIC ORGANIC
CHEMICAL MANUFACTURING PLANTS
This chapter presents a description of reactor processes at synthetic
organic chemical manufacturing plants. Section 3.1 briefly describes the
synthetic organic chemical manufacturing industry (SOCMI) and identifies the
segment of the industry that is represented by reactor processes. The
chemical reactions used in reactor processes are identified in Section 3.2
and further described in Section 3.5. Section 3.2 also identifies and
discusses volatile organic compound (VOC) emission characteristics asso-
ciated with reactor processes employing many different chemical reactions.
Section 3.3 discusses the emission data base that is used to develop projec-
tions of emissions from new, modified, and reconstructed reactors in
Chapter 6. An estimate of the baseline emissions level is presented in
Section 3.4. References are presented in Section 3.6.
3.1 DESCRIPTION OF REACTOR PROCESSES AT SYNTHETIC ORGANIC CHEMICAL
MANUFACTURING PLANTS
3.1.1 Introduction
The SOCMI is a large and diverse industry producing over 7,000
intermediate and end-product chemicals from about 15 basic chemicals.1
These basic chemicals are derived primarily from crude oil, natural gas, and
coal. Examples of basic chemicals include benzene, ethylene, propylene, and
propane. Basic chemicals are used to produce hundreds of intermediate
chemicals, which are subsequently used to manufacture end-product chemicals.
Generally, each process level contains more chemicals than the preceding
level, and process units manufacturing chemica-ls at the end of the production
system generally have smaller capacities (in terms of production volume)
than process units producing the basic materials. Also, the volatilities of
the end-product chemicals are typically less than those of basic materials.
A SOCMI process unit may use two broad categories of processes to
manufacture organic chemicals: conversion and separation. Conversion
processes involve chemical reactions that alter the molecular structure of
chemical compounds. Conversion processes comprise the reactor processes
segment of a SOCMI plant. Separation processes often follow conversion
processes and divide chemical mixtures into distinct fractions. Examples of
separation processes are distillation, filtration, crystallization, and
extraction.
The SOCMI emissions have been divided into a number of groups according
to emission mechanisms to make the development of NSPS more manageable.
These major emission groups are fugitives, storage, secondary, and process
vents. Sources within each SOCMI group are similar with respect to operating
3-1
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procedures, emission characteristics, and applicable emission control
techniques. Reactor processes are one of several groups constituting
process vent emissions. There are two subsets of chemical reactor processes.
The focus of this document is upon reactor processes other than air oxida-
tion, which is shown cross hatched in Figure 3-1. Air oxidation processes
are the subject of a separate regulatory action because they involve large
reactor vent streams and high potential VOC emissions.2 In this study, the
term "reactor processes" refers to means by which one or more substances, or
reactants, (other than air or oxygen-enriched air) are chemically altered
such that one or more new organic chemicals are formed.
An estimated six percent of the total VOC emissions from the SOCMI are
associated with reactor processes (excluding air oxidation processes).3 For
comparison, estimated percentages of the total SOCMI VOC emissions associated
with each of the emissions groups are presented in Table 3-1. At present,
NSPS have been promulgated for SOCMI fugitives, and standards are currently
being developed for distillation operations, air oxidation processes, and
volatile organic liquid (VOL) storage tanks.k
3.1.2 Scope of Reactor Processes
Over 7,000 chemicals are manufactured by the SOCMI, but only a small
percentage of the total number of these chemicals account for the majority
of the industry's total production. The development of meaningful and
enforceable standards that could be applied to the manufacture of all 7,000
synthetic organic chemicals would require inordinate amounts of time, data,
and resources. As a result, the scope of the standards development program
for various emission groups of the SOCMI was limited to those chemicals that
dominate industry output. These large-volume chemicals are defined as those
with annual national production exceeding 45,400 Mg/yr (100 million lb/yr).
Production of these large-volume chemicals accounts for approximately
90 percent of national VOC SOCMI emissions because, when emissions do occur
from reactor processes, they are generally proportional to production
rates.3
•
Based on 1981 production data, a^ total of 173 chemicals produced in
volumes over 100 million lb/yr are included in the scope of reactor
processes.5 The list of 173 chemicals, given in Appendix E, does not
include polymers or chemicals produced exclusively by biological synthesis.
Also excluded from the list is ethanol produced for human consumption.
Chemicals that are manufactured exclusively by air oxidation processes or
distillation operations are included on the list but are not analyzed here
since they are being considered in separate standards development programs.
3.2 CHEMICAL REACTIONS AND REACTOR VOC EMISSIONS
3.2.1 Classification of Chemicals by Reaction Type
Between 30 and 35 different types of chemical reactions are used to
produce the 173 high-volume chemicals.6 These chemical reactions are
discussed in Section 3.5. Some of these chemical reactions are involved in
the manufacture of only one or two of the 173 chemicals while others (such
3-2
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SOCMI
VOL
Storaga
Operation*
CO
u>
Procaaa Vanta
from
Dlatlllatlon
Oparatlona
Procaaa Vanta
from Chamlcal
Raactor
Procaaaaa
Air Oxidation
Procaaaaa
I
Fugltlvaa
Sacondary
Sourcaa
Othar Raactor
Procaaaaa
Flgura 3-1. Emlaalona Groups within tha SOCMI.
-------
TABLE 3-1. BREAKDOWN OF voc EMISSIONS FROM THE socMi3
Percent of Total VOC.
Emissions Group Emissions From SOCMr
Process Vents 52
Distillation Operations 26
Air Oxidation Processes 20
Reactor Processes 6
Fugitives 35
VOL Storage Operations 8
Secondary Sources 5
a(Reference 3)
Estimates from process emission sources using best available information
from SOCMI NSPS standards development program (October 25, 1982).
Secondary source emissions estimated as 5 percent of the total of the other
sources.
3-4
-------
as halogenation, alkylation, and hydrogenation) are used to make more than a
dozen chemicals. Table 3-2 identifies most of the chemical reaction types
and the number of chemicals produced by each type. The reactions are ranked
according to volume of production. In addition, some of the chemicals
produced by reactions listed in Table 3-2 do not produce process vent
streams. In this document, a process vent stream means any gas stream
ducted to the atmosphere directly from a reactor, or indirectly, through the
process product recovery system. For example, approximately half of the
23,850 Gg of production from pyrolysis is accounted for by the manufacture
of ethylene -- a process that, according to available data, does not produce
a process vent stream.
3.2.2 Reactor VOC Emissions
Reactor VOC emissions include all VOC in process vent streams from
reactors and product recovery systems. Process product recovery equipment
includes devices such as condensers, absorbers, and adsorbers, used to
recover product or by-product for use, reuse, or sale. Not included in
product recovery equipment are product purification devices involving
distillation operations. (Distillation operations are considered under a
separate standards development program.)
Reactor processes may be either liquid phase reactions or gas phase
reactions. Four potential atmospheric emissions points are shown in
Figure 3-2 and include:
(A) Direct reactor process vents from liquid phase reactors;
(B) Vents from recovery devices applied to vent streams from liquid
phase reactors (Raw materials, products, or by-products may be
recovered from vent streams for economic or environmental
reasons.);
(C) Process vents from gas phase reactors after either the primary or
secondary product recovery device (Gas phase reactors always have
primary product recovery devices.); and
(D) Exhaust gases from combustion devices applied to any of the above
streams.
Some chemical production processes may have no reactor process vent to the
atmosphere, while others may have one or more vent streams. Specific
examples of vent types A, B, and C are presented in Figures 3-3, 3-4, and
3-5. Each figure represents one of the 173 chemicals covered within the
scope of this document.
The production of nitrobenzene by a nitration process is shown in
Figure 3-3 and is an example of a liquid phase reaction with an uncontrolled
vent stream (Vent Type A). Benzene is nitrated at 55°C (130°F) under
atmospheric pressure by a mixture of concentrated nitric and sulfuric acids
in a series of continuous stirred-tank reactions. The crude reaction
mixture flows to a separator, where the organic phase is decanted from the
aqueous waste acid. Emission streams from the reactors and separator are
combined and emitted to the atmosphere without any control devices (Vent 1).
All available data in the Emission Data Profile (EDP) indicate that controls
are not typically applied to this process, and that reactor vents are the
3-5
-------
TABLE 3-2. RANKING OF CHEMICAL REACTION TYPES
RANK
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Chemical
Reaction Type
Pyrolysls
Alkylation
Hydrogenation
Dehydration
Carbonylation/
Hydroformylation
Halogenation
Hydrolysis/Hydration
Dehydrogenation
Esterification
Dehydrohalogenation
Ammonolysis
Reforming
Oxyhalogenation
Condensation
Cleavage
Oxidation
Hydrodealkylation
Isomerization
Oxyacetylation
Oligomerization
Nitration
Hydrohalogenation
Reduction
Sulfonation
Hydrocyanation
Neutralization
Hydrodimerization
Miscellaneous b
Non-reactor processes
Number of
Chemicals
Produced
7
13
13
5
6
23
8
4
12
1
7
4
1
12
2
4
2
3
1
7
3
2
1
4
2
2
1
6
26
1981 Annual
Production
Gg (10° Ib)
23,850*
6,396.
5,580*
5,569*
5,224a
*
4,991*
4,697.
4,401*
4,075*
3,175*
2,759
2,605
2,426a
2,201*
1,947
1,750
1,492
942
878a
786*
728*
533
333
310
208
129
28
480
"•
(52,587)
(14,100)
(12,300)
(12,277)
(11,516)
(11,003)
(10,356)
(9,702)
(8,983)
(7,000)
(6,083)
(5,744)
(5,349)
(4,852)
(4,293)
(3,859)
(3,289)
(2,076)
(1,936)
(1,696)
(1,606)
(1,174)
(734)
(683)
(458)
(284)
(61)
(1,058)
™
Production data not complete for all chemicals.
bChemicals produced solely by air oxidation, distillation, or other
non-reactor processes.
3-6
-------
fits
Liquid
Rtcovtred
product
Product/By-product
Rtcovtry Otvlct
Liquid
6«s Ph
-------
To Atmosphara
ot
CO
oo
Banzana »•
Nitric Acid—*
Sulturic Acid— •>
<
Nitration
Raactor
Nitration
Raactor
Nitration
Raactor
«
n^^.T^^^n^fTM-i^-tn^rn-''* •**
Separator
Nltrobanzana
Nautrallzatlon
and
Stripping
Product
*• to
Storaga
Flgura 3-3. Procaaa Flow Diagram for the Manufacture of
Nitrobenzene. (Reference 7.)
-------
OJ
i
To Atmoaphara
t
Watar
Scrubber
©
voc
Scrubber
Banzana
Ethylana
Banzana
Scrubbar
Alkylatlon
Raactor
To Atmoaphara
Cruda
Ethylbanzana
Product
Purification
(Distillation)
Ethylbanzana
Flgura 3-4. Procaaa Flow Diagram for tha Manufactura of Ethylbanzana.
-------
To Atmosphere
To Atmosphere
Isopropyl
Alcohol
Catalyst
Dehydrogenatioi
Reactor
VOC
Scrubber
I
Condenser
1
To Recovery
Crude ^
Acetone
£
tf
r
Acetone
Refining
Acetone
Product
Figure 3-5. Process Flow Diagram for the Hanufacture of Acetone.
-------
largest source of VOC in nitrobenzene plants. Recent comments from industry
indicate that a new process without vents may now be in use. (See
discussion in Section 3.5.)
The production of ethylbenzene is an example of a liquid phase reaction
where the vent stream is passed through a VOC recovery device before it is
discharged to the atmosphere (Type B). Figure 3-4 depicts an alkylation
unit process used to produce ethylbenzene. Ethylene and benzene are
combined in the alkylation reactor to form crude ethylbenzene. The process
vent stream from the reactor goes through three types of scrubbers before
discharging to the atmosphere. The first scrubber recovers the excess
benzene reactant from the vent stream and recycles it to the reactor. The
second scrubber removes any ethylbenzene product in the vent stream and
recycles it to the reactor. Finally, traces of acidic catalyst in the vent
stream are removed by a water scrubber before the vent stream is discharged
to the atmosphere. Vent 1 in the figure designates the only reactor vent
stream for this example. The crude ethylbenzene product stream from the
reactor'is purified by distillation. The vent stream from the product
purification operations (Vent 2) is associated with distillation operations
and, therefore, is not considered to be a reactor-related vent stream.
Figure 3-5 shows a dehydrogenation process used to produce acetone.
Although this is not the most widely used process to make acetone, it
provides a good example of a vapor phase reaction and its associated vent
streams (Type C). In this process, isopropyl alcohol is catalytically
dehydrogenated to acetone in a vapor-phase reaction at 400 to 500°C (750 to
930°F). The crude acetone then passes through a condenser or primary VOC
recovery device. The overheads or process vent stream from the primary
condenser then goes through a scrubber and is released to the atmosphere
(Vent 1). Acetone is further refined and emissions from the refining
process (Vent 2) are again not considered to be reactor-related. Informa-
tion in the EDP show that other processes used to manufacture acetone have
no reactor process vent streams to the atmosphere.
The characteristics of reactor vent streams (i.e., heat content,
flowrate, VOC control) vary widely among the numerous chemicals and chemical
reactions in the SOCMI. In addition, the numerous possible combinations of
product recovery devices and reactors introduce another source of
variability among various process units (as defined in Chapter 5) using the
same reaction type. The following section describes the emission
characteristics of reactor processes.
3.3 EMISSION DATA PROFILE
In order to develop the baseline emissions level, discussed in the next
section, an extensive data base for 127 process units at existing SOCMI
plants was developed. For the purposes of this discussion, a process unit
is any combination of one or more reactors and an associated product
recovery system that manufactures the same organic compound as product or
by-product at the same site. A plant is constituted by one or more process
3-11
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units. There are no factors identified in the collection of the data that
would introduce systematic bias into the database. It is believed that the
EDP is representative of SOCMI reactor processes. The EDP is presented in
Appendix C.
Table 3-3 presents an overview of the EDP. As indicated, the EDP
represents approximately 50 percent of the 173 chemicals and about
90 percent of the 35 chemical reactions included in the scope of the reactor
processes segment of the SOCMI. A total of 17 States are represented in the
data profile. Of the process units represented in the profile, about
69 percent are located in Texas and Louisiana.8
Emissions data included in the EDP have been grouped by chemical
reaction type. Table 3-4 summarizes the VOC emission characteristics of
reactor processes using 30 of the 35 chemical reactions considered here.
These data represent the process vent stream characteristics following the
final gas treatment device (condenser, absorber, or adsorber) but prior to
any combustion device.
There is a wide variability in the VOC emission characteristics
associated with the various chemical reactions. For example, VOC emission
factors range from 0 kg/Gg of product for pyrolysis reactions to
120,000 kg/Gg of product for hydroformylation reactions. Wide variability
also exists in the emission characteristics associated with process units
using the same chemical reaction. For example, process units using
chlorination reactions have VOC emission factors that range from 292 to
9,900 kg/Gg. The variability in process vent stream flowrates and heating
values is not as pronounced as the VOC emission factors. Flowrates range
from 0 to 537 scm/min and heating values range from 0 to 58.8 MJ/scm.8
Although process vent stream characteristics are variable, there are
some general observations evident in Table 3-4. First, process units using
11 of the 30 reaction types included in Table 3-4 were reported to have no
reactor process vents. These reactions include: ammination, ammonolysis,
cleavage, etherification, fluorination, hydration, neutralization,
oligomerization, phosgenation, pyrolysis, and sulfurization.
A second general observation evident in Table 3-4 is that process units
using 6 of the reaction types included in Table 3-4 were reported to have
the largest VOC emission factors in the EDP. The reactions include:
hydroformylation, chlorination, dehydrogenation, condensation,
oxychlorination, and hydrochlorination. The vent streams from process units
using these reactions also tend to have both high heating values and a high
percentage application of combustion devices.
3-12
-------
TABLE 3-3. OVERVIEW OF THE EMISSION DATA PROFILE3
1. Number of chemicals included in the profile 83
Percent of 173 chemicals represented 48
2. Number of chemical reactions represented in the profile _ 31
Total number of chemical reactions associated with
the 173 chemicals 35
Percent of chemical reactions represented 89
3. Percent of plants in the profile that are from
Texas and Louisiana 69
4. Other states represented in the profile:
Alabama
California
Delaware
Florida
Georgia
Kentucky
Maryland
Mississippi
Nevada
New Jersey
New York
Pennsylvania
Tennessee
Virginia
West Virginia
Reference 8
3-13
-------
TABLE 3-4. SUMMARY OF REACTOR-RELATED VOC EMISSION FACTORS, VENT STREAM
HEAT CONTENTS, AND FLOWRATE PRIOR TO COMBUSTION
Chemical
Reaction Type
Alkylation
Ammi nation
Ammo no lysis
Carbonylation
Catalytic Reforming
Chlorlnation
Cleavage
Condensation
Dehydration
Dehydrogenation
Dehydrochlorl nation
Esterification
Etherification
Fluorinatlon
Hydration
Hydrogenatlon
Hydrochlorinatlon
Hydroformylation
Hydrodimerizatlon
Hydrolysis
Neutralization
Nitration
Oligomerization
Oxidation
{Pure 02)
Oxyacetylation
Oxychlorination
(Pure 02)
Phosgenation
Pyro lysis
Sulfonatlon
Sulfurization
(Vapor Phase)
Range (or single
value) of Reactor
VOC Emission
Factors3 >0, Kg/Gg
5.95-78.1
Od
Od
443
DNAf
292-9,900
Od
8,900
DNAf
11,400-12,600
4,790
4.38-594
od
Od
Od
0-943
2,000-14,700
120,000
1,310
2.5
Od
9.95-1,350
Od
0-3,900
2.20
7,180
Od
Od
29.2
Od
Range (or single
value) of VentKStream
VOC Contentb>C
g/scm
3.07-252
Od
Od
1.06
1.72
0.209-118
Od
554
DNAf
36.5-75.0
1,097
5.34-21.8
Od
Od
Od
0-1,638
28.1-2,247
878
6.69
0.27
Od
0.03-390
Od
0-2.85
3.82
658
Od
Od
0.014
Od
Percent of
Process Units with
Vent Streams Using
Combustion Control
33.3
Od
Od
100
100
44.4
Od
100
0
85.7
100
14.3
Od
Od
Od
83.3
80.0
100.0
0
33.3
Od
33.3
Od
25.0
0
100
Od
Od
0.0
od
Range (or single b
value) of Flowrates
son/mi n
0.24-0.48
Od
Od
537
36.5
1.13-342
Od
4.16
DNAf
16.3-147
0.283
0.06-2.12
Od
Od
Od
0.09-36.9
0.566
20.6
30.6
2.80
Od
0.37-23.3
Od
24.0-345
0.198
8.61
Od
Od
52.7
oa
Kange (or single
value) of Vent
Stream Heat
Content MJ/scm
0.15-6.74
Od
Od
11.0
7.63
0-45.7
Od
39.8
DNAf
10.4-11.2
22.3
3.8
Od
Od
od
12.0-58.8
18.6-47.9
45.9
2.61
0
Od
0-16.2
Od
0-0.15
15.2
•26.6
Od
Od
0
od
Emission factors are expressed 1n terms of Kg of VOC emitted per Gg of chemical produced and represent emissions
to the atmosphere from the final gas treatment device (1f used), but before combustion (If used).
Ranges are due to (1) different chemicals produced by the chemical process and (2) different controls used at the
process units.
All values represent emission stream characteristics after the final product recovery device and before
combustion (if used).
No reactor vent streams are associated with chemicals manufactured by this chemical process.
Little or no flow reported for this vent stream.
DNA - data not available.
3-14
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A general observation concerning all the units in the EDP is that some
reactor vent streams contain potentially toxic air pollutants. An
examination of some of the units in the EDP shows that chlorobenzene,
ethylene dichloride, and vinylidene chloride are emitted from reactor
processes in varying amounts. All of these pollutants are currently under
assessment by EPA for potential regulation under Section 112 of the Clean
Air Act. The units at which these emissions occur are presented in
Appendix C and include plant numbers CHL-1, CHL-2, CHL-4, CHL-6, CHL-7,
CHL-9, CHL-10, DEHC-1, and OXYC-1.
Appendix C details the information collected for the process units
included in the EDP. For each process unit, information is provided on the
chemical produced, the chemical unit process used, and any product/by-
product recovery and VOC control equipment. Vent stream characteristics and
VOC emissions are also given for each process unit where data are available.
The key vent stream characteristics for each process unit are the process
vent stream flowrate, heat content, and VOC content downstream of the final
recovery devices, but upstream of combustion devices. In most cases, these
vent stream characteristics were calculated based on information supplied
for each process unit.
Table 3-5 summarizes the distribution of recovery and combustion
devices for the 127 units in the EDP. Fifty-two percent (or 66 units) of
the total 127 process units included in the EDP have reactor process vent
streams. Of these 66 units, combustion devices are used for 56 percent of
the vent streams and are estimated to control about 94 percent of VOC
emissions from all process units in the EDP for which emission data are
available.9 Plants using combustion devices tend to have vent streams with
relatively large flowrates and moderate to high heat contents. Twenty
percent of the vent streams in the profile have no VOC combustion control
device, while 24 percent use only noncombustion devices as the method of VOC
control. From examining the data in the profile, combustion is not usually
used on vent streams with heat contents less than 6 MJ/scm (163 Btu/scf).
Two types of vent streams do not have VOC combustion controls applied.
Process vent streams with small flowrates are often not controlled despite
moderate to high heat contents and VOC concentrations. Similarly, vent
streams with high flowrates but low heat contents, <3.0 MJ/scm (<80 Btu/scf),
are typically not controlled.
3.4 BASELINE EMISSIONS
The baseline emissions level is defined as the estimate of national VOC
emissions that will occur in the absence of an NSPS from new, modified, and
reconstructed reactor process units coming on-line over a 5-year period,
from July 1, 1985, to July 1, 1990. Assuming no reactor process NSPS were
to be proposed in 1985, the baseline emissions level is calculated for the
year 1990. Baseline emissions from reactor processes are estimated to be
3-15
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TABLE 3-5. DISTRIBUTION OF RECOVERY AND COMBUSTION
DEVICES FOR THE 127 PROCESS UNITS IN THE
EMISSION DATA PROFILE
Process Unit Description
Number of Process Units (Percentage)
Units with reactor vent streams
66 (52 percent)'
Units with unknown vent stream status
Units using combustion devices
37 (56 percent)1
Distribution of combustion devices
Incinerators 13 units
Flares 11 units
Boilers 7 units
Process heaters 5
Unspecified combustion device 1
Units with no VOC treatment0
13
Units using only noncombustion
devices for VOC control
16
aPercent of 127 process units in the Emission Data Profile.
Percent of the 66 process units with reactor vent streams.
clncludes units with acid gas removal or no devices at all.
Noncombustion devices include condensers and VOC scrubbers.
3-16
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3,300 Mg per year. The purpose of establishing a baseline emissions level
is to provide a benchmark from which to compare the environmental and energy
impacts and cost impacts of the regulatory alternatives presented in
Chapters 7 and 8, respectively.
The baseline emissions level estimate was derived from the EDP together
with projections for the number of new, modified, and reconstructed process
units projected to come on-line between 1985 and 1990. Projections of
demand and estimates of replacements for each of the 173 chemicals was used
to determine the number, size, and type .of new, modified, and reconstructed
reactor process units that would likely come on-line during 1985-1990. It
was assumed that each of these process units would have emission characteris-
tics similar to those in the EDP. Thus, the baseline emission level estimate
takes into account both (1) the variability in anticipated production rates
for various products and (2) the variation in emissions by reaction type. A
description of the method of determining the baseline VOC emissions level
follows. Chapter 9 reviews the projections for new, modified, and
reconstructed process units.
3.4.1 Method of Calculating Baseline Emissions
Baseline emissions are constituted by the emissions from all new,
modified, and reconstructed process units, including those emissions from
units with vent streams projected to be combusted in the absence of an NSPS
and those emissions from units projected to be uncombusted in the absence of
an NSPS. It is estimated that of the 133 new, modified, and reconstructed
process units that are projected to come on-line between 1985 and 1990, 56
process units will not use combustion devices in the absence of an NSPS.
Total uncontrolled emissions from these units are estimated to be 2,400 Mg/yr.
As discussed in Chapters 6 and 7 these emissions were calculated using the
process unit capacity and emission characteristics presented in Table 6-1.
Emissions are also estimated to come from all new, modified, and
reconstructed process units which are projected to use combustion devices in
the absence of an NSPS. Although combustion is projected to be used at
these units, complete VOC destruction will not occur and some VOC will be
emitted from the outlets of the combustion devices. Based on the projections
for new and replacement capacity and other data presented in Table 9-18, it
is estimated that 22 of the 173 chemicals considered here will have new and
replacement process units built which will use combustion devices in the
absence of an NSPS. It was assumed a process unit making a specific chemical
would apply combustion in the absence of an NSPS if: (1) the majority of
process units in the EDP making that chemical use combustion or (2) the
majority of process units using the same process units as that specific
chemical use combustion (this method used if: (1) could not be used).
Table 9-18 summarizes the combustion status of each chemical considered.
Emissions from these units are estimated by multiplying the estimated new
and replacement capacity of each chemical with the appropriate VOC emission
factor for each chemical then summing the emissions for all 22 chemicals.10
The capacity was multiplied by a 77 percent capacity factor to estimate the
total amount of chemicals produced in the fifth year of the NSPS.25 The
3-17
-------
development of the VOC emission factors used here is discussed in Chapter 6.
The total emissions are then multiplied by 0.02 to account for the emissions
removed by the combustion devices. (Assuming that the combustion devices
applied will achieve 98-weight-percent VOC destruction). It is estimated
that 910 Mg/yr of VOC will be emitted from new, modified, and reconstructed
process units where combustion devices are applied in the absence of an
NSPS.10 Therefore, total baseline emissions are estimated to be 3,300 Mg/yr
(910 Mg/yr from 77 process units with combustion devices and 2,400 Mg/yr
from the 56 process units without combustion devices).
3.4.2 State Regulations and Industrial Practices Impacting Baseline
Emissions
It is estimated from the EDP that over 90 percent of VOC emissions from
reactor processes are currently combusted. Baseline emissions are influenced
by the existing Federal and State regulations affecting VOC emissions from
SOCMI plants. The degree of VOC control required by applicable State
regulations varies in stringency from State to State. About 90 percent of
the process units in the EDP that currently combust their vent streams would
be required to combust under Louisiana law, and 82 percent would combust
under Texas law. The following discussion illustrates the variability of
State standards among Texas, Louisiana, and New Jersey. Approximately
50 percent of the existing SOCMI process units (of which reactor process
units are a single subgroup) are located in these three States.11
Texas regulations require facilities emitting more than 45 kg/day
(100 Ib/day) or 110 kg/hr (250 Ib/hr), depending on the true vapor pressure
of the VOC, to incinerate the waste gas stream at 704°C (1,300°F). This is
considered equivalent to approximately 95 percent VOC reduction.12
Louisiana requires incineration of VOC waste gas streams at a minimum
temperature of 704°C (1,300°F) for at least 0.3 second in a direct flame
afterburner or equally effective device. However, control requirements may
be waived if the offgas stream is less than 100 tons per year or if the
offgas will not support combustion without auxiliary fuel.13 New Jersey
uses a sliding scale, based on the degree of difficulty in controlling the
VOC emission source, to establish allowable emission rates for individual
sources. Depending on the vapor pressure, concentration, and amount of the
waste stream VOC, the New Jersey regulation requires from 0 to 99.7 percent
VOC reduction.1"
In addition to existing regulations, a variety of industrial practices
or site-specific vent stream control practices may be instituted that impact
the baseline control level for reactor processes. In some cases, these
industrial practices may result in VOC emissions reductions that go beyond
that required under existing regulations. These practices may be instituted
for safety or economic reasons. For instance, intermittent reactor vent
streams may be flared for safety reasons to prevent the accumulation of
explosive gases. For some chemical processes it may be economical to
operate high efficiency product/by-product recovery devices on reactor vent
streams or to utilize the heat content of reactor offgas through combustion
in boilers or process heaters. For example, as indicated in Appendix C,
3-18
-------
process heaters are typically used at methanol process units. An example of
other industrial practices that may have a slight impact on baseline emissions
is the scrubbing of process vent streams to remove acidic or caustic compounds,
Changing feedstocks in the chemical production process (e.g., use of cleaner
or dirtier feedstocks) and process modifications (e.g., catalyst changes,
reactor temperature, pressure changes, etc.) may also affect emissions.
3.5 CHEMICAL REACTION DESCRIPTIONS
This section presents a brief description of the major chemical reactions
represented in the SOCMI. Only descriptions of the larger volume chemicals
are included in this discussion. Each chemical reaction description contains
a discussion of the process chemistry that characterizes each chemical
reaction and the major products resulting from the chemical reaction. In
addition, process vent stream characteristics are presented for chemicals
where data are available.8 Descriptions of the major large-volume chemical
reactions are presented in alphabetical order in the remainder of this
section.6
Alkylation
Alkylation is the introduction of an alkyl radical into an organic
compound by substitution or addition. There are six general types of
alkylation, depending on the substitution or addition that occurs:
1. substitution for hydrogen bound to carbon;
2. substitution for hydrogen attached to nitrogen;
3. addition of metal to form a carbon-to-metal bond;
4. substitution for hydrogen in a hydroxyl group of an alcohol or
phenol;
5. addition of alkyl halide, alkyl sulfate, or alkyl sulfonate to a
tertiary amine to form a quaternary ammonium compound; and
6. miscellaneous processes such as addition of an alkyl group to
sulfur or silicon.
The major chemical products of alkylation reactions are ethylbenzene
and cumene. The single largest category of alkylation products are refinery
alkylates used in gasoline production. Other chemical products of alkylation
processes include linear alkylbenzene, tetramethyl lead, and tetraethyl
lead.
In general, based on data for production.of ethylbenzene, cumene, and
linear alkylbenzene, reactor VOC emissions from alkylation processes appear
to be small compared to other unit processes. The commercial synthesis of
ethylbenzene from ethylene and benzene is an example of the first type of
alkylation reaction described above. The reaction can be carried out in two
ways. One production process involves a low pressure liquid-phase reaction
method using an aluminum chloride catalyst, while the other process operates
in the vapor phase at high pressure with various solid catalysts. Data from
one plant that produces ethylbenzene by liquid-phase alkylstion indicate
that reactor VOC emissions are relatively small. (Although no emissions
data are available for the vapor-phase alkylation process, the associated
3-19
-------
VOC emissions are expected to be small due to the high operating pressure.)
Reactor offgas from the liquid-phase alkylator is vented to a VOC scrubber
where unreacted benzene is removed from the gas stream and recycled to the
reactor. According to data contained in the EDP, the scrubber vent stream
contains inerts and a small amount of VOC and is vented to the atmosphere at
a rate of approximately 0.5 scm/m (17 scfm). The estimated heat content of
the vent stream is 6.7 MJ/scm (181 Btu/scf). The VOC emissions to the
atmosphere from the gas scrubber are estimated to be 2.7 kg/hr (16 Ib/hr).
Cumene is produced by the vapor-phase catalytic alkylation of benzene
with propylene. The reaction takes place at 690 kPa (100 psia) in the
presence of a phosphoric acid catalyst. No reactor streams are vented, and
thus no reactor VOC emissions to the atmosphere are associated with this
process at the five cumene plants included in the EDP. Excess benzene
required for the alkylation reaction is recovered by distillation in the
cumene product purification process and recycled to the reactor.
Dodecylbenzenes, also referred to as linear alkylbenzenes (LAB), are
produced by alkylation of mono-olefins or chlorinated n-paraffins with
benzene. VOC emissions from both processes are small or nonexistent. In
the case of the mono-olefin production route, only high purity raw materials
can be used, thus eliminating the introduction of dissolved volatiles.
Furthermore, the HF catalyst used in the process is a hazardous chemical and
a potential source of acidic emissions that must be minimized. As a result,
operators of one mono-olefin production route for LAB indicate that process
vent streams have little or no flow associated with them.15 The alkylation
reaction producing LAB from chlorinated n-paraffins generates HC1 gas and
some VOC by-products. The potential to emit reactor VOC from this process
is greater than for the mono-olefin process due to formation of degradation
and other VOC by-products. Benzene and HC1 are removed from the process
vent stream before discharging to the atmosphere. Data from a plant producing
LAB from chlorinated n-paraffins indicate that the process vent stream
following the scrubber is intermittent and emits no VOC to the atmosphere.
Ammonolysis
Ammonolysis is the process of forming amines by using ammonia or primary
and secondary amines as aminating agents. Another type of ammonolytic
reaction is hydroammonolysis, in which amines are formed directly from
carbonyl compounds using an ammonia-hydrogen mixture and a hydrogenation
catalyst. Ammonolytic reactions may be divided into four groups:
1. Double decomposition - NH3 is split into -NH2 and -H; the -NH2
becomes part of the amine while the -H reacts with a radical like
-Cl that is being substituted;
2. Dehydration - NH3 serves as a hydrant, and water and amines result;
3. Simple addition - both fragments of the NH3 molecule (-NH and -H)
become part of the newly formed amine; and
4. Multiple activity - NH3 reacts with the«produced amines resulting
in formation of secondary and tertiary amines.
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The major chemical products of ammonolysis reactions are acrylonitrile
and carbamic acid. Reactor emissions from acrylonitrile production are
covered in the air oxidation processes NSPS, so they are not discussed here.
Two other categories of ammonolysis products are ethanolamines and
methyl amines.
Based on information on ethanolamine production, ammonolytic processes
appear to be a negligible source of reactor VOC emissions. Ethanolamines,
including mono-, di-, and triethanolamines, are produced by a simple
addition reaction between ethylene oxide and aqueous ammonia. According to
information on two process units producing ethanolamines, no reactor VOC are
emitted to the atmosphere from this process. The reactor product stream is
scrubbed to recover the excess ammonia required for the reaction before
proceeding to the product finishing unit.
The manufacture of methylamines involves a vapor-phase dehydration
reaction between methanol and ammonia. In addition to methylamines, di- and
trimethylamines are also formed by the reaction. Although no process unit
data for this process are included in the EDP, available information suggests
that reactor VOC emissions from the process are small or negligible. Staged
distillation immediately follows the reactor to separate the coproducts. As
a result, all potential VOC emissions to the atmosphere are associated with
distillation operations and are not reactor-related. (Any VOC emissions
from distillation vents would be considered under the standards development
program for distillation operations.)
Carbonylation/Hydroformylation
Carbonylation/hydroformy1 ation reactions are used to make aldehydes
and/or alcohols containing one additional carbon atom. Carbonylation is the
combination of an organic compound with carbon monoxide. Hydroformylation,
often referred to as the oxo process, is a variation of carbonylation in
which olefins are reacted with a mixture of carbon monoxide and hydrogen in
the presence of a catalyst. Major chemical products of carbonylation/hydro-
formylation reactions are acetic acid, n-butyraldehyde, and methanol.
Carbonylation/hydrogenation processes typically generate relatively
large process vent streams with high heat contents, compared to other unit
processes. Thus, process vent streams from these reactions are normally
combusted.
One carbonylation process for acetic acid manufacture reacts liquid
methanol with gaseous carbon monoxide at 20 to 70 MPa (2,900 to 10,200 psia)
in the presence of a catalyst. At one plant that produces acetic acid by
this high pressure process, the reactor products are passed through two gas
liquid separators. The vent from the first separator, consisting primarily
of carbon dioxide and carbon monoxide, is scrubbed and sent to carbon
monoxide recovery. The vent from the second separator is scrubbed to
recover excess reactant and then combined with other waste gas streams and
flared. No data are available on the VOC content of the two vent streams.
3-21
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However, the only point where reactor VOC are potentially emitted to the
atmosphere is the vent from the second separator, which is ultimately
discharged to a flare.
In the oxo process for producing n-butyraldehyde, propylene is reacted
with synthesis gas (CO and H2) in the liquid phase at 20 to 30 MPa (2,900 to
4,400 psia). An aromatic liquid such as toluene is used as the reaction
solvent. A relatively large amount of VOC is contained in the process vent
stream for this reaction. Industry comment from the Chemical Manufacturers
Association (CMA) suggests that this process has generally been replaced by
an unnamed, low VOC-emitting process. No data, however, are available for
this process. Information from one plant producing n-butyraldehyde by the
oxo process indicates that the reactor vent stream consists of hydrogen,
carbon monoxide, and VOC and is used as fuel in an industrial boiler. Prior
to combustion, the estimated vent stream flow rate at this plant is 21 scm/m
(730 scfm) and the heating value is 46 MJ/scm (1,233 Btu/scf). The VOC
flowrate prior to combustion is approximately 1,100 kg/hr (2,394 Ib/hr).
Cleavage
Acid cleavage is the process by which an organic chemical is split into
two or more compounds with the aid of an acid catalyst. This chemical
reaction is associated with production of two major chemicals, phenol and
acetone.
Production of phenol and acetone begins with oxidation of cumene to
cumene hydroperoxide. The cumene hydroperoxide is usually vacuum distilled
to remove impurities and then agitated in 5 to 25 percent sulfuric acid
until it cleaves to phenol and acetone. The mixture is neutralized to
remove excess sulfuric acid, phase separated, and distilled. One process
unit producing phenol and acetone from cumene hydroperoxide reports little
or no flow in the process vent stream at the cleavage reactor. High purity
of the cumene hydroperoxide intermediate is the major reason for this "no
flow" vent.
Condensation
Condensation is a chemical reaction in which two or more molecules
combine, usually with the formation of water or some other low-molecular
weight compound. Each of the reactants contributes a part of the separated
compound. Chemical products made by condensation include acetic anhydride,
bisphenol A, and ethoxylate nonylphenol.
The EDP includes data on four condensation processes. Reactor
emissions to the atmosphere from condensation processes are expected to be
small. Emissions from acetic anhydride production are minimized by
combustion of the process vent stream. There are no reactor VOC emissions
from bisphenol, or ethoxylated nonylphenol production. (Bisphenol A has
emissions from distillation operations only.)
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Acetic anhydride is produced by the condensation of acetic acid and
ketene. Ketene for the reaction is made by pyrolysis of acetic acid. After
water removal, the gaseous ketene is contacted with glacial acetic acid
liquid in absorption columns operated under reduced pressure. The process
vent stream from the absorber contains acetic acid, acetic anhydride, traces
of ketene, and any reaction by-product gases generated. The VOC content of
the vent stream is particularly dependent on impurities that may be
contained in the acetic acid feed, such as formic or propionic acid, that
cause side reactions to occur. Scrubbers are normally used to remove acetic
acid and acetic anhydride from the vent stream. At two process units
producing acetic anhydride the vent streams are burned as supplemental fuel
in pyrolysis furnaces. No data on the vent stream characteristics or VOC
content were provided for one of these process units; however, data from the
other source on acetic anhydride production identify the major components of
the process vent stream after scrubbing to be carbon monoxide, carbon
dioxide, and VOC. The typical VOC flowrate of the vent stream after
scrubbing was estimated to be 138 kg/hr (305 Ib/hr), based on assumptions
about the purity of the reactants.
Bisphenol A is produced by reacting phenol with acetone in the presence
of HC1 as the catalyst. Numerous by-products are formed in the reaction
that must be eliminated in order to generate high-purity bisphenol A.
Removal of these by-products requires distillation and extraction
procedures, and thus no reactor vents to the atmosphere are associated with
this process.
Dehydration
Dehydration reactions* are a type of decomposition reaction in which a
new compound and water are formed from a single molecule. Reactions in
which two molecules condense with the elimination of water and the formation
of a new compound are included in the process of condensation. The major
chemical product of dehydration is urea.
Commercial production of urea is based on the reaction of ammonia and
carbon dioxide to form ammonium carbamate, which in turn is dehydrated to
urea and water. The unreacted ammonium carbamate in the product stream is
decomposed to ammonia and carbon dioxide gas. A portion of the ammonia is
removed from the process vent stream leaving primarily carbon dioxide to be
vented to the atmosphere. No data are included in the EDP for VOC emissions
from urea, production, but one study indicates that VOC emissions from urea
synthesis are negligible. Urea is the only chemical of those that use
dehydration to be included in the EDP.
Mhis process refers to chemical dehydration and does not include physical
dehydration in which a compound is dried by heat. Stucco produced by
heating gypsum to remove water is an example of physical dehydration.
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Dehydrogenation
Dehydrogenation is the process by which a new chemical is formed by the
removal of hydrogen from the reactant. Aldehydes and ketones are prepared
by the dehydrogenation of alcohols. Chemicals produced by dehydrogenation
processes include acetone, bivinyl, cyclohexanone, methyl ethyl ketone
(MEK), and styrene.
In general, dehydrogenation processes produce relatively large,
hydrogen-rich process vent streams that are either used as a fuel in process
heaters or industrial boilers or as a hydrogen feed for other processes.
The two process units for which data are available have high heat content
process vent streams. These occur as a result of the hydrogen generated in
the dehydrogenation reaction. Although these process vent streams can be
quite large, there is generally little VOC contained in them.
Acetone and MEK are produced by similar processes involving the
catalytic dehydrogenation of alcohols. There are four process units in the
EDP that produce MEK via the dehydrogenation of sec-butanol. In all cases a
hydrogen-rich process vent stream is produced. One process unit uses a VOC
scrubber to remove MEK and sec-butanol from the process vent stream prior to
flaring. In all four process units, reactor VOC emissions are well
controlled or nonexistent. One acetone production process unit has an
additional reactor process vent stream on a degasser directly following the
reactor. This degasser reduces the pressure on the product stream to allow
storage of the product at atmospheric pressure. The pressure reduction step
causes dissolved hydrogen and low boiling point VOC to escape from the
liquid-phase product. This purge stream, which is relatively small, is
routed to a water scrubber to remove some VOC before it is released to the
atmosphere. This is the only acetone production process unit in the EDP
that stores the acetone as an intermediate product, and as a result, it is
the only plant with a degasser process vent stream.
Two process units in the EDP manufacture styrene via the hydrogenation
of ethylbenzene. One plant produces a hydrogen-rich (90 percent by volume)
process vent stream that is normally combusted to recover the heat
content. The other plant produces a process vent stream that is first
condensed and then combusted in a flare system. The vent stream flowrate is
relatively large (16 scm/m (574 scfm)); the stream contains 23 percent VOC
including toluene, benzene, ethylbenzene, and styrene. The heat content is
.estimated to be 11 MJ/scm (300 Btu/scf), which would support combustion
without the addition of supplemental fuel.
Dehydrohalogenation
In the dehydrohalogenation process, a hydrogen atom and a halogen atom,
usually chlorine, are removed from one or more reactants to obtain a new
chemical. This chemical reaction is used to produce vinyl chloride,
vinylidene chloride, and cyclohexene.
3-24
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Vinylidene chloride is made by dehydrochlorinating 1,1,2-trichloroethane
with lime or aqueous sodium hydroxide. The reactor product is separated and
purified by distillation. The process vent stream at one vinylidene chloride
process unit is incinerated and then scrubbed with caustic before discharging
to the atmosphere. Before incinerating, the vent stream flowrate is
estimated to be 0.28 scm/m (10 scfm) and the heat content is 22 MJ/scm
(600 Btu/scf). The VOC emission rate of the vent stream is approximately
19 kg/hr (41 Ib/hr). At a second plant producing vinylidene chloride, no
reactor vent streams are used. The process vent streams are associated with
distillation operations.
Esterification
Esterification is the process by which an ester is derived from an
organic acid and an alcohol by the exchange of the ionizable hydrogen atom
of the acid and an organic radical. The major chemical product of esterifi-
cation is dimethyl terephthalate. Other esterification products include
ethyl acrylate and ethyl acetate.
VOC emissions associated with esterification processes are small based
on information on the production of methyl methacrylate, ethyl acrylate, and
ethyl acetate.
Ethyl acrylate is produced by the catalytic reaction of acrylic acid
and ethanol. The vent stream flowrate from reactor equipment producing
ethyl acrylate in one process unit is reported to be 2.1 scm/m (75 scfm).
The heat content for this stream is estimated to be 3.8 MJ/scm
,1 ? ?^s?f'' The VOC em1ssi'on rate of the vent stream is 2.8 kq/hr
(o.l Ib/hr;.
Methyl methacrylate is produced by esterifying acetone and hydrogen
cyanide with methanol. Limited information is available on reactor VOC
emissions from this process. The EDP includes one plant producing methyl
Tnr?no^Jnte; 1?^°^ v?nt.stream ^ this plant is combusted in an
incinerator. Although the incinerator is used primarily to destroy VOC in
ottgases from another plant process, combustion of the methyl methacrylate
process vent stream in the incinerator allows the plant to use less supple-
mental fuel by recovering the heat content of the vent stream. No vent
ltretmrf1owra*e or heat content data are available for this plant; however,
the VOC emission rate is estimated to be very low (0.05 kg/hr (0.1 Ib/hr)).
Ethyl acetate production involves an esterification reaction between
acetic acid and ethanol. Two process units producing ethyl acetate are
included in the EDP. Following condensation of the process vent stream to
recover product, both process units discharge the vent stream to the
atmosphere. Vent stream data reported by one of the process units indicate
the VOC content of the vent stream to be low, i.e., 0.2 kg/hr (0.5 Ib/hr).
3-25
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Halogenation
Halogenation is the process whereby a halogen (chlorine, fluorine,
bromine, iodine) is used to introduce one or more halogen atoms into an
organic compound. (Reactions in which the halogenating agent is a halogen
acid, such as hydrochloric acid, are included in a separate unit process
called hydrohalogenation.) The chlorination process is the most widely used
halogenation process in industry; fluorination is used exclusively in the
manufacture of fluorocarbons. The major products of halogenation reactions
are ethylene dichloride, phosgene, and chlorinated methanes and ethanes.
Reactor VOC emissions from halogenation reactions vary from no
emissions to 51 kg/hr (113 Ib/hr). Most chlorination reactors vent to
scrubbers or condensers where HC1 generated in the chlorination reaction is
removed. Some VOC reduction occurs along with HC1 removal by these devices.
Also, some vent streams are combusted prior to discharge to the atmosphere.
Purity of the feed materials (including chlorine) is a major factor
affecting the amount of reactor VOC emissions vented to the atmosphere.
»
Ethylene dichloride can be produced by direct chlorination of ethylene
or by oxychlorination of ethylene. Most ethylene dichloride is currently
made by a "balanced" process that combines direct chlorination of ethylene
and oxychlorination of ethylene. The direct chlorination process reacts
acetylene-free ethylene and chlorine in the liquid phase. The oxyhalogena-
tion process using oxygen for the manufacture of ethylene dichloride is
included in the reaction description for oxyhalogenation. Reactor VOC
emissions from ethylene dichloride production by direct chlorination vary
according to process vent stream treatment. HC1 is generated by the
chlorination reaction and is typically removed from the process vent stream
by a caustic scrubber. The vent stream following the scrubber may be
discharged to the atmosphere, recycled to the reactor, or incinerated. The
EDP contains information on three ethylene dichloride plants which use the
direct chlorination process as part of the "balanced" process. The process
vent stream characteristics for the three plants indicate a range of gas
flowrates of 1.1 to 7.6 scm/m (40 to 267 scfm) and a range of heat contents
of 1.5 to 46 MJ/scm (40 to 1,228 Btu/scf). The process vent stream with the
highest heat content (i.e., 46 MJ/scm) is incinerated before venting to the
atmosphere.
The fluorination reactions producing dichlorodifluoromethane and
trichlorotrifluoroethane involve the replacement of a chlorine in carbon
tetrachloride with fluorine. At two plants surveyed, no reactor VOC
emissions are associated with these fluorination processes. The two plants
report no process vent stream discharges to the atmosphere. Instead,
process vent streams occur from distillation operations.
Hydrodealkylation
Hydrodealkylation is the process by which methyl groups, or larger
alkyl groups, are removed from hydrocarbon molecules and replaced by
hydrogen atoms. Hydrodealkylation is primarily used in petroleum refining
3-26
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to upgrade products of low value, such as heavy reformate fractions,
naphthalenic crudes or recycle stocks from catalytic cracking. In
particular, hydrodealkylation is used in the production of high-purity
benzene and naphthalene from alkyl aromatics such as toluene.
The EDP contains no information on emissions from hydrodealkylation
processes. In the case of benzene production, the process vent stream
containing unconverted toluene is recycled to the reactor, and no reactor
VOC emissions are vented.16
Hydrohalogenation
Hydrohalogenation is the process in which a halogen atom is added to an
organic compound using a halogen acid, such as hydrogen chloride. The major
chemical products of this reaction are methyl chloride and ethyl chloride.
Approximately 80 percent of methyl chloride is produced by the vapor-
phase reaction of methanol and hydrogen chloride.17 In three process units
the process vent stream is condensed to remove excess HC1; some VOC is also
removed by the condensers. Of the nine plants that manufacture methyl and
ethyl chloride included in the EDP, five have no reactor process vent
streams, one discharges the noncondensibles directly to the atmosphere, and
three route the noncondensible stream to combustion devices. The VOC
content of a methyl chloride vent stream is 76 kg/hr (168 Ib/hr).
Hydrolysis/Hydration
Hydrolysis is the process in which water reacts with another substance
to form two or more new substances. Hydration is the process in which water
reacts with a compound without decomposition of the compound. These processes
are a major route in the manufacture of alcohols and glycols, such as
ethanol, ethylene glycols, and propylene glycols. Another major product of
hydrolysis is propylene oxide.
Propylene oxide is produced by hydrolysis of propylene chlorohydrin
with an alkali (usually NaOH or Ca(OH)2). The product vent stream is
condensed to remove the propylene oxide product and the noncondensibles are
discharged to the atmosphere. Data from a process unit that produces
propylene oxide indicate the flowrate of the vent stream following the
condenser to be about 2.8 scm/m (99 scfm) and the estimated VOC emissions to
the atmosphere to be 0.05 kg/hr (0.1 Ib/hr).
Sec-butyl alcohol is produced by absorbing n-butenes in sulfuric acid
to form butyl hydrogen sulfate that is then hydrolyzed to sec-butyl alcohol
and dilute sulfuric acid. The reactor product is steam stripped from the
dilute acid solution and purified by distillation. Information on the
sec-butyl alcohol production at one process unit does not indicate any
specific process vents. All process vents at this process unit are reported
to be flared so that any reactor VOC emissions would be combusted.
3-27
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In general, production of chemicals by hydrolysis/hydration processes
generate little or no reactor VOC emissions. Based on production
information for ethylene glycol and propylene glycol, these hydration
reactors do not have process vent streams associated with them. Ethylene
glycol and propylene glycol are produced by hydrating ethylene oxide and
propylene oxide, respectively. The reactions for both chemicals result in
production of di- and tri- glycols as coproducts. Following the reactor,
the glycols are separated and purified by distillation. No reactor VOC
emissions are vented to the atmosphere from the glycol process units in the
EDP.
Hydrogenation
Hydrogenation is the process in which hydrogen is added to an organic
compound. The hydrogenation process can involve direct addition of hydrogen
to the double bond of an unsaturated molecule, replacement of oxygen in
nitro-containing organic compounds to form amines, and addition to aldehydes
and ketones to produce alcohols. The major chemical products of hydrogena-
tion reactions include cyclohexane, aniline, n-butyl alcohol, hexamethylene
diamine, 1,4-butanediol, cyclohexanone, and toluene diamine.
In general, reactor VOC emissions from hydrogenation reactions appear
to be small in comparison with other chemical reactions. However,
combustion devices are typically associated with the vent streams of
hydrogenation processes. Excess hydrogen in these vent streams makes them
suitable for combustion in most cases.
Hexamethylene diamine is made by hydrogenation of adiponitrile.
Reactor VOC emissions from hexamethylene diamine production are small
according to information on three process units in the EDP. Excess hydrogen
used in the reaction is recovered from the vent stream and recycled to the
reactor. At two of these process units, the process vent streams are used
as fuel in a plant boiler. The average vent stream flowrate following
hydrogen recovery at the three process units is 14.0 scm/m (496 scfm) and
the average heat content is 21 MJ/scm (562 Btu/scf). The VOC content of the
noncombusted vent stream at the process unit that does not use combustion is
approximately 3 kg/hr (6.6 lb/hr). The VOC content of the combusted streams
at the other two process unit is estimated to be negligible prior to
combustion.
Cyclohexane is produced by the liquid-phase hydrogenation of benzene.
In this process, both cyclohexane and hydrogen are recovered from the
process vent stream. Information from one cyclohexane plant indicates that
there is usually no flow in the vent stream following product and hydrogen
recovery. The process vent stream after these recovery systems is
discharged to the atmosphere only during emergencies, and the stream is
vented to the flare system for VOC destruction during such upset
conditions.
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Cyclohexanone, 1,4-butanediol, and toluene dianrine production involve
the hydrogenation of phenol, 2-butyne-l,4-diol, and 2,4-dinitrotoluene,
respectively. The process vent stream for these hydrogenation reactions are
ultimately combusted in incinerators, boilers, or flares. Precombustion
vent stream characteristic data are available for only one of these vent
streams - n-Butyl alcohol. For this process unit, the vent stream flowrate
is estimated to be .09 scm/m (3.2 scfm) and the heating value 59 MJ/scm
(1,578 Btu/scf). The VOC flowrate prior to combustion is approximately
9 kg/hr (19.6 Ib/hr).
Isomerization
During isomerization, organic compounds are converted by heat and a
catalytic reaction that changes the arrangement of atoms in a molecule, but
not the number of atoms. Catalysts include aluminum chloride, antimony
chloride, platinum, and other metals. Temperatures range from 400 to 480°C
(750 to 900°F), and pressures range from 7 to 50 atm.18
Isomerization is used in petroleum refining to convert straight-chain
hydrocarbons into branched-chain hydrocarbons. An example is the conversion
of n-butane to isobutane.18 Emissions from this process would be expected
to be small, as with other high-temperature and high-pressure reactor
processes in the EDP.
Neutralization
Neutralization is a process used to manufacture linear alky!benzene;
benzenesulfonic acid, sodium salt; dodecylbenzene sulfonic acid, sodium
salt; and oil-soluble petroleum sulfonate, calcium salt. Diagrams of all of
the production processes show no reactor process vent streams.8
Nitration
Nitration is the unit process in which nitric acid is used to introduce
one or more nitro groups (N02) into organic compounds. Aromatic nitrations
are usually performed with a mixture of nitric acid and concentrated
sulfuric acid. Nitrobenzene and dinitrotoluene are the major products of
nitration reactions.
Reactor VOC emissions to the atmosphere from nitration reactions appear
to be relatively low based on information on production of nitrobenzene and
dinitrotoluene. Nitrobenzene production involves the direct nitration of
benzene using a mixture of nitric acid and sulfuric acid. Only a small
quantity of by-products, primarily nitrated phenols, are produced by the
reaction. The reaction is normally blanketed with nitrogen gas to reduce
fire and explosion hazards. At one process unit producing nitrobenzene,
waste acid is removed from the reactor product stream by a separator
followed by recovery of excess benzene by distillation. Vent streams from
the reactor and separator are combined and discharged directly to the
atmosphere. Industry comment from CMA has stated that a new but unnamed
process without reactor process vents is now in operation. No data,
however, are available for this process. The main components of the
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combined vent streams are nitrogen and benzene. The EDP nitrobenzene
nitration process has a combined vent stream flowrate estimated to be 0.37
scm/m (13 scfm) and an approximate heat content of 16 MJ/scm (434 Btu/scf).
VOC emissions to the atmosphere from the vent streams are 8.6 kg/hr
(19 Ib/hr).
Dinitrotoluene is produced by nitration of toluene in two stages using
different acid mixtures. As in the case of nitrobenzene production, the
waste acid is separated and recycled. Two process units producing dinitro-
toluene operate scrubbers on the reactor vent streams to remove VOC.
Following scrubbing, one plant discharges the vent stream to the atmosphere
while the other incinerates the vent stream. No data is available on the
characteristics of the incinerated vent stream. The flowrate of the
nonincinerated vent stream following the scrubber is estimated to be
23 scm/m (822 scf.n). Heat content of the vent stream is negligible.
Estimated VOC emissions to the atmosphere are 0.05 kg/hr (0.1 Ib/hr).
Oligpmerization
In the oligomerization process, molecules of a single reactant are
linked together to form larger molecules consisting of from 2 to about 10 of
the original molecules. Oligomerization is used to make several chemicals
including alcohols, dodecene, heptene, nonene, and octene. Typically, it is
a high temperature, high pressure process.19'20 Diagrams for all of the
chemical production processes show no reactor process vent streams.21"23
Other chemical unit processes with similar high pressure characteristics,
such as pyrolysis, emit little or no VOC.
Oxidation
Oxidation of organic chemicals is the addition of one or more oxygen
atoms into the compound. The oxidation processes considered here include
pure oxygen oxidation and chemical oxidation. (Air oxidation processes are
a separate subcategory of reactor processes for standards development
purposes and includes oxygen-enriched air processes as discussed in
Section 3.1.) An example of pure oxygen oxidation is the production of
ethylene oxide using pure oxygen and ethylene. The production of adipic
acid from nitric acid is an example of chemical oxidation.
Ethylene oxide can be produced by oxidation using air or pure oxygen.
In the pure oxygen process, ethylene, oxygen and recycle gas are reacted
under pressures of 1 to 3 MPa (150 to 440 psia). Two reactor process vent
streams are reported by one process unit that produces ethylene oxide by
pure oxygen oxidation. At this plant, the reactor effluent is sent through
an ethylene oxide absorber. The offgas from this absorber is routed to the
carbon dioxide removal system. A portion of the vent stream from the carbon
dioxide absorber system is recycled to the reactor while the remainder is
used as fuel in industrial boilers. The carbon dioxide absorber liquid is
regenerated, and the removed carbon dioxide is vented to the atmosphere.
The portion of the vent stream from the C02 absorber that is sent to a
boiler has an approximate flowrate of 176 scm/m (6,200 scfm) and a heat
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content of 13 MJ/scm (340 Btu/scf). The estimated discharge rate to the
atmosphere from the C02 absorber liquid regenerator vent is 345 scm/m
(12,187 scfm), and the heat content is 0.15 MJ/scf (4 Btu/scf). Prior to
combustion in the boiler, the VOC flowrate of the first vent stream is
0.59 kg/hr (1.3 Ib/hr). For the uncontrolled vent stream, VOC emissions to
the atmosphere are estimated to be 59 kg/hr (130 Ib/hr).
In adipic acid production, an alcohol ketone mixture is oxidized using
nitric acid. Adipic acid from the reactor is stripped of nitrogen oxides
produced by the reaction and then refined. Of the three process units
producing adipic acid included in the EDP, two of the process unit discharge
the stripper'offgas to the atmosphere. Estimated vent stream flowrates at
the three process units range from 24 to 132 scm/m (848 to 4,653 scfm). The
heating values of all three vent streams are negligible and there are no VOC
emissions from any of these process units.
Qxyacetylation
Oxyacetylation is the process in which oxygen and an acetyl group are
added to an olefin to produce an unsaturated acetate ester. Oxyacetylation
is used in a new commercial process to make vinyl acetate.
Vinyl acetate is produced from ethylene, acetic acid, and oxygen.
Reactor VOC emissions from one vinyl acetate production process unit are
small. The estimated vent stream flowrate and heating value are 0.2 scm/m
(7 scfm) and 15 MJ/scm (407 Btu/scf), respectively. The VOC flowrate prior
to combustion is approximately 0.05 kg/hr (0.1 Ib/hr).
Oxyhalogenation
In the oxyhalogenation process, a halogen acid is catalytically oxidized
to the halogenated compound with air or oxygen. The main oxyhalogenation
process is oxychlorination, in which hydrogen chloride is catalytically
oxidized to chlorine with air or oxygen. (Oxychlorination processes using
air are included in the analyses for air oxidation processes.) The oxychlori-
nation process is used in the production of ethylene dichloride.
As described previously, most ethylene dichloride is produced by the
"balanced process" that combines oxychlorination and direct chlorination of
ethylene. In the oxychlorination reaction, ethylene, hydrogen chloride, and
oxygen or air are combined. Emissions from air oxychlorination reactions
used in ethylene dichloride production are included in the air oxidation
processes NSPS. Only emissions from oxygen oxychlorination reactions are
considered here. At one process unit producing ethylene dichloride by
oxychlorination using oxygen, the reactor effluent is condensed, and excess
ethylene is recycled to the reactor. A small portion of the recycle stream
is vented to prevent a buildup of impurities. The vent stream is incinerated
in order to comply with State implementation.plans (SIPs) and to reduce
vinyl chloride emissions that are regulated under a NESHAP. The vent stream
flowrate prior to incineration is approximately 8.5 scm/m (304 scfm) and the
estimated heat content is 27 MJ/scm (713 Btu/scf). The VOC flowrate in the
vent stream is estimated to be 340 kg/hr (748 Ib/hr). Following incineration,
the estimated VOC emissions to the atmosphere are 6.8 kg/hr (15 Ib/hr).
3-31
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Phosgenation
Phosgenation is the process in which phosgene (COC12) reacts with an
amine to form an isocyanate, or with an alcohol to form a carbonate.
Toluene diisocyanate is the major chemical -product of this chemical unit
process.
Toluene diisocyanate is produced by phosgenating toluene diamine. At
one process unit, the reactor vent is routed through distillation columns
for product/by-product recovery and purification. Thus, no reactor VOC
•emissions are vented to the atmosphere from the process.7
Pyrolysis
Pyrolysis is a chemical reaction in which the chemical change of a
substance occurs by heat alone. Pyrolysis includes thermal rearrangements
into isomers, thermal polymerizations, and thermal decompositions. The
major use of this process is in the production of ethylene by the steam
pyrolysis of hydrocarbons. Other pyrolysis products include ketene (a
captive intermediate for acetic anhydride manufacture) and by-products of
ethylene production such as propylene, bivinyl, ethylbenzene, and styrene.
Ethylene and other olefins can be produced from a variety of
hydrocarbon feeds, including natural gas liquors, naphtha, and gas-oil.
Maximum ethylene production is achieved by adjusting furnace temperature and
steam-to-hydrocarbon ratios. Pyrolysis gases from the furnace are cooled,
compressed, and separated into the desired products. As in refinery
operations, the economics of olefins production make recovery of gaseous
products desirable. Thus, process vent streams to the atmosphere are
minimized. The ethylene process unit included in the EDP reports no process
vent streams to the atmosphere.
The first step in the manufacture of acetic anhydride is production of
ketene. Ketene and water are produced by pyrolysis of acetic acid. At two
plants producing acetic anhydride, the pyrolysis products are cooled and
separated prior to acetic anhydride formation. No process vent streams are
associated with the pyrolysis reaction to produce ketene.
Sulfonation
Sulfonation is the process by which the sulfonic acid group (S02OH), or
the corresponding salt, or sulfonyl halide is attached to a carbon atom.
"Sulfonation" can also be used to mean treatment of any organic compound
with sulfuric acid, regardless of the nature of products formed.21*
Isopropyl alcohol is made by Sulfonation of propylene to isopropyl
hydrogen sulfate and subsequent hydrolysis to isopropyl alcohol and sulfuric
acid.18
Many detergents are made by the Sulfonation of mixed linear
alkylbenzenes. These include benzenesulfonic acid and dodecylbenzene
sulfonic acid. To manufacture these, the linear alkylbenzenes are
3-32
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sulfonated with SO^ or oleums of various strengths. One process uses
diluted S03 vapor in a continuous operation. The reaction and heat removal
occurs in a thin film on a cooled reactor surface. The process forms almost
entirely the p-sulfonic acid.18
The EDP contains emissions data on one sulfonation process unit
controlled only with a caustic scrubber. It has extremely low uncombusted
VOC emissions (0.05 kg/hr or 0.1 Ib/hr) even though the vent stream rate is
relatively large (52 scm/m or 1,863 scfm).
3.6 REFERENCES
1. U.S. Environmental Protection Agency. Distillation Operations in
Synthetic Organic Chemical Manufacturing - Background Information for
Proposed Standards. Research Triangle Park, N.C. Publication No.
EPA-450/3-83-005a. December 1983. p. 9-2.
2. U.S. Environmental Protection Agency. Air Oxidation Processes in
Synthetic Organic Chemical Manufacturing Industry - Background Informa-
tion for Proposed Standards. Research Triangle Park, N.C. Publication
No. EPA-450/3-82-001a. October 1983. p. 3-19.
3. Memo from Stelling, J. H. E., Radian Corporation, to SOCMI Fugitive VOC
NSPS File. November 1, 1982. Estimate of VOC emissions from SOCMI.
4. Memo from Mead, R. C., Radian Corporation, to File. November 15, 1983.
Status of standards of performance.
5. Memo from Lesh, S. A., and Piccot, S. D., Radian Corporation, to Evans,
L. B., EPA. June 22, 1984. Revised list of high-volume reactor
process chemicals.
6. Memo from Fidler, K., Radian Corporation, to L. B. Evans, EPA. July 6,
1983. Identification of chemical production routes and unit processes
expected to be used in the future to manufacture the 176 chemicals
considered in the Carrier Gas Project.
7. U.S. Environmental Protection Agency. Organic Chemical Manufacturing,
Volume 7: Selected Processes. Research Triangle Park, N.C. Publica-
tion No. EPA-450/3-80-028b. December 1980. Section 1-i, p. III-l to
III-4.
8. Memo from Read, B. S., Radian Corporation, to File. May 28, 1985.
Summary of the emission data profile.
9. Memo from Read, B. S., Radian Corporation, to Reactor Processes NSPS
File. May 29, 1985. Combustion controls used in the Emission Data
Profile.
10. Memo from Rimpo, T., and Pandullo, R. F., Radian Corporation, to File,
June 4, 1985. Emissions from new, modified, and reconstructed reactor
process units which use combustion controls at baseline.
3-33
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11. Reference 2, p. 3-26.
12. Crowder, S., Chief Chemical Engineer, Texas Air Control Board. Tele-
communication to S. D. Piccot, Radian Corporation. Texas Regulation of
VOC and Regulations V and VI. December 2, 1982.
13. Bureau of National Affairs, Inc. Environmental Reporter, State Air
Laws, Volume 2, Louisiana. Washington, D. C., August 10, 1984.
14. Personal Communication. M. Flowers, Energy and Environmental Analysis,
Inc., with Ivey, L., New Jersey Air Pollution Control Agency.
September 11, 1979.
15. U.S. Environmental Protection Agency. Urea Manufacturing Industry -
Technical Document. Research Triangle Park, N. C. EPA Publication
No. 450/3-81-001. January 1981. p. 3-8.
16. Faith, W., et. al. Industrial Chemicals 4th Edition. John Wiley &
Sons, New York. 1975. p. 129-130.
17. Chemical Products Synopsis. Mannsville Chemical Products. Cortland,
New York. April 1983.
18. Herrick, E. C., et. al. (Mitre Corporation). Unit Process Guide to
Organic Chemical Industries. Ann Arbor, Michigan, Ann Arbor Science
Publishers, Inc., 1979. p. 120-121,
19. Waddams, A. L. Chemicals from Petroleum, 4th Edition. Houston, Texas,
Gulf Publishing Company, 1978. p. 24, 145-146, 173-174, 221-222.
20. U.S. Environmental Protection Agency. Industrial Process Profiles for
Environmental Use: Chapter 6. Research Triangle Park, N. C. EPA
Publication No. 600/2-77-023f. February 1977. p. 667.
21. C6-C8 Olefins (Dimersol X). Hydrocarbon Processing. 60(11):192.
November 1981.
22. Alpha Olefins. Hydrocarbon Processing. 58(11):128. November 1979.
23. C6-C8 Olefins (Dimersol Process). Hydrocarbon Processing. 56(11):170.
November 1977.
24. Reference 18, p. 111.
25. Memorandum from Robson, J., EPA/Economics Analysis Branch, to file.
February 21, 1985. Capacity utilization rates used in the Synthetic
Organic Chemical Reactor Processes NSPS 83-12.
3-34
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4. EMISSION CONTROL TECHNIQUES
This chapter describes the control techniques and associated emission
reduction effectiveness for reactor process vents of the synthetic organic
chemical manufacturing industry (SOCMI). The effectiveness of combustion
systems is examined with respect to their principles of operation,
advantages, and disadvantages.
The SOCMI process vent streams show a great variety in volume flows,
chemical compositions, and volatile organic compound (VOC) concentrations.
This chapter concentrates on combustion control devices since it is a VOC
control method universally applicable to SOCMI reactor process vent streams,
although it is not necessarily the best for a given process.
Effectiveness and specificity of condensers, absorbers, adsorbers, and
catalytic oxidizers may be affected by changes in waste stream conditions.
These conditions include flowrate, VOC concentration, chemical and physical
properties of VOC, waste stream contaminants, and waste stream temperature.
Analysis of reactor process VOC emissions control by these methods would be
unwieldy. Also, control systems based on condensation or absorption are
generally used as recovery devices, and the removal efficiencies decrease as
the VOC concentrations decrease.
Combustion control, however, is much less dependent on process and vent
stream conditions than the other control techniques. Incinerators and
flares are the only demonstrated VOC combustion controls which are
applicable to all SOCMI reactor processes. Flares, however, can only be
used on nonhalogenated vent streams. Both incinerator and flare cost and
efficiency determinations require a limited amount of vent stream data
(volume flow, VOC emission rate, net heating value, and corrosion
properties). The choice of incinerator and flare combustion controls as the
control techniques for analysis yields conservative estimates of energy,
economic, and environmental impacts since combustion control is relatively
expensive and energy-intensive.
All new incinerators, if properly designed, adjusted, maintained, and
operated, can achieve at least a 98-weight-percent VOC reduction or 20 ppmv
exit concentration, whichever is less stringent. This control level can be
achieved by incinerator operation at conditions which include a maximum of
1,600°F and 0.75 second residence time. Flares can also achieve at least a
98-weight-percent VOC reduction or 20 ppmv exit concentration. However, to
meet such reduction levels, the flare must meet the specifications discussed
later in this chapter.
4-1
-------
Process modification, improvements in product recovery, and use of
additional control devices are possible routes to lower emission levels.
This chapter discusses the advantages and disadvantages of using recovery
devices such as absorbers, adsorbers, and condensers alone, or in
conjunction with VOC control devices such as flares, boilers and thermal and
catalytic oxidizers to achieve reduction of VOC emissions.
"*
Boilers can be useful as VOC control devices only when the vent stream
volume flow is not large enough to upset the combustion process.
Furthermore, the vent stream must either have sufficient oxygen to be used
as combustion air or have a sufficiently high heating value to be used as
part of the fuel input.
All SOCMI reactor processes use a combination of absorption devices,
condensers, or carbon adsorption units for product recovery (or for recovery
of unreacted raw material). These devices are usually designed to recover
only as much of the VOC as is economically feasible and therefore would not
be considered control devices. However, in some plants, these devices are
designed to remove more than that amount which is economically justified.
In this case, the devices operate both for product recovery and as control
devices for emission reduction or to reduce the pollutant load on some other
final control device.
4.1 NONCOMBUSTION CONTROL DEVICES
The noncombustion control devices discussed in this section include
adsorbers, absorbers, and condensers. While many devices may remove some
VOC from the process stream (e.g., gas conditioning devices such as some
water scrubbers) and may be broadly characterized as a noncombustion control
device, this discussion is limited to those devices used specifically and
primarily for VOC recovery. Because noncombustion control devices recover
products, by-products, and/or unused reactants, they may be essential to
process economics, providing a cost benefit. The following three sections
present a process description and identify the VOC removal efficiency and
applicability of each device to reactor process vent streams.
Noncombustion devices are generally applied to recover reactant,
product, or by-product VOC from process vent streams. The chemical
structure of the VOC removed is usually - although not always - unaltered.
Of the 66 units identified in Appendix C that have reactor process vent
streams, 13 apply absorbers to recover VOC, 19 apply condensers, and none
apply adsorbers. Thirteen units vent to the atmosphere from the reactor
without any VOC recovery or combustion. Although noncombustion devices are
widely applied in industry, no one device is universally applicable to all
reactor process vent streams because: (1) reactor processes produce a wide
variety of vent streams with very different characteristics, and (2) the
performance of noncombustion devices will vary depending upon the
characteristics of a particular stream. This is generally not the case for
combustion devices, where a consistent VOC emission destruction can be
achieved regardless of the amount and type of VOC present in the vent
4-2
-------
stream. The conditions under which the noncombustion systems may not be
applicable to reactor process vent streams are identified in the following
sections.
4.1.1 Condensation
4.1.1.1Condensation Process Description. Condensation is a process
of converting all or part of the condensible components of a vapor phase
into a liquid phase. This is achieved by the transfer of heat from the
vapor phase to a cooling medium. If only a part of the vapor phase is
condensed, the newly formed liquid phase and the remaining vapor phase will
be in equilibrium. In this case, equilibrium relationships at the operating
temperatures must be considered. The heat removed from the vapor phase
should be sufficient to lower the vapor phase temperature to at or below its
dewpoint temperature (i.e., the temperature at which the first drop of
liquid is formed).
Condensation devices are of two types: surface condensers and contact
condensers.1 Surface condensers are shell-and-tube type heat exchangers.
The coolant and the vapor phases are separated by the tube wall and they
never come in direct contact with each other. Surface condensers require
more auxiliary equipment for operation but can recover valuable VOC without
contamination by the coolant, minimizing waste disposal problems. Only
surface condensers are considered in the discussion of control efficiency
and applicability since they are used more frequently in industry.
The major equipment components used in a typical surface condenser
system for VOC removal are shown in Figure 4-1. This system includes:
(1) shell and tube dehumidification equipment, (2) shell-and-tube heat
exchanger, (3) refrigeration unit, and (4) VOC storage tanks and operating
pumps. Most surface condensers use a shell-and-tube type heat exchanger to
remove heat from the vapor.2 As the coolant passes through the tubes, the
VOC vapors condense outside the tubes and are recovered. The coolant used
depends upon the saturation temperature of the VOC stream. Chilled water
can be used down to 7°C (45°F), brines to -34°C (-30°F), and chlorofluoro-
carbons below -34°C (-30°F).3 Temperatures as low as -62°C (-80°F) may be
necessary to condense some VOC streams.1*
4.1.1.2 Condenser Control Efficiency. VOC removal efficiency of a
condenser is dependent upon the type of vapor stream entering the condenser,
and on condenser operating parameters (flowrate and temperature of the
cooling medium). High VOC removal efficiencies are achievable "for con-
densers, but the design and operation of condensers for large heat removals
from dilute VOC streams may be costly. Efficiencies of condensers in actual
operation usually vary from 50 to 95 percent.5
4.1.1.3 Applicability of Condensers. A primary condenser system is
used in 19 out of 66 units with vent streams (about 29 percent) in the EDP.
In some cases, additional (secondary) condensers are used to recover more
VOC from the vent stream exiting the primary condenser. Condensers are •»
sometimes present as accessories to vacuum generating devices (e.g.,
barometric condensers). Based on these data, condensers are the most widely
used product recovery device for reactor vent streams.6
4-3
-------
VOC LAOGI GAS •
OEHUMIOIRCATION
UNIT
To Rtaove *at«r
and
?rncnt Freezing
m ,uam Conoaaw
CtXJUMT
scrum*
REfHIGEHATIQN
PUMT"
(1)
(3)
CLEANED GAS OUT
To Primary Control r'aie.
MAIN CONDENSES
CSOLANT
Recovered
Organic
for Process
or Other Use.
Figure 4-1. Condensation system.
4-4
-------
Condenser systems are not well suited for vent streams containing VOC
with low boiling points.7 In addition, condensers are not well suited for
vent streams with low concentrations of VOC, such as streams containing
large quantities of inerts such as carbon dioxide, air, or nitrogen. Low
boiling point VOC and inerts contribute significantly to the heat load that
must be removed from the vent stream, resulting in costly design specifica-
tions and/or operating costs. In addition, some low boiling point VOC
cannot be condensed at normal operating temperatures.8 In the EDP, a number
of process units produce reactor vent streams containing low boiling point
VOC. For example, process units producing chlorinated methanes have vent
streams with substantial amounts of methane, methyl chloride, and methylene
chloride. These compounds are not readily condensed and, as a result, are
usually vented to the atmosphere or destroyed in a combustion device.
4.1.2 Absorption
4.1.2.1 AbTorption Process Description. The mechanism of absorption
consists of the selective transfer of one or more components of a gas
mixture into a solvent liquid. The transfer consists of solute diffusion
and dissolution into a solvent. For any given solvent, solute, and set of
operating conditions, there exists an equilibrium ratio of solute concen-
tration in the gas mixture to solute concentration in the solvent. The
driving force for mass transfer at a given point in an operating absorption
tower is related to the difference between the actual concentration ratio
and the equilibrium ratio.9 Absorption may only entail the dissolution of
the gas component into the solvent or may also involve chemical reaction of
the solute with constituents of the solution.10 The absorbing liquids
(solvents) used are chosen for high solute (VOC) solubility and include
liquids such as water, mineral oils, nonvolatile hydrocarbon oils, and
aqueous solutions of oxidizing agents like sodium carbonate and sodium
hydroxide.11
Devices based on absorption principles include spray towers, venturi
scrubbers, packed columns, and plate columns. Spray towers require high
atomization pressure to obtain droplets ranging in size from 500 to 1,000 ym
in order to present a sufficiently large surface contact area.12 Spray
towers generally have the least effective mass transfer capability of the
absorption techniques discussed above and, thus, are restricted to
particulate removal and control of high-solubility gases such as sulfur
dioxide and ammonia.13 Venturi scrubbers have a high degree of gas-liquid
mixing and high particulate removal efficiency but also require high-energy
input and have relatively short contact times. Therefore, their use is also
restricted to high-solubility gases.llf As a result, VOC control by gas
absorption is generally accomplished in packed or plate columns. Packed
columns are mostly used for handling corrosive materials, for liquids with
foaming or plugging tendencies, or where excessive pressure drops would
result from use of plate columns. They are less expensive than plate
columns for small-scale operations where the column diameter is less than
0.6 m (2 ft). Plate columns are preferred for large-scale operations, where
internal cooling is desired or where low liquid flowrates would inadequately
wet the packing.15
4-5
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A schematic of a packed tower is shown in Figure 4-2. The gas to be
absorbed is introduced at the bottom of the tower (1) and allowed to rise
through the packing material (2). Solvent flows from the top of the column,
countercurrent to the vapors (3), absorbing the solute from the gas phase
and carrying the dissolved solute out of the tower (4). Cleaned gas exits
at the top for release to the atmosphere or for further treatment as
necessary. The saturated liquid is generally sent to a stripping unit where
the absorbed VOC is recovered. Following the stripping operation the
absorbing solution is either recycled back to the absorber or sent to a
treatment facility for disposal.
The major tower design parameters to be determined for absorbing any
substance are column diameter and height, system pressure drop, and liquid
flowrate required. These parameters are derived from considering the total
surface area provided by the tower packing material, the solubility and
concentrations of the components, and the quantity of gases to be treated.
4.1.2.2 Absorption Control Efficiency. The VOC removal efficiency of
an absorption device is dependent on the solvent selected and on design and
operating conditions. For a given solvent and solute, an increase in
absorber size or a decrease in the operating temperature can increase the
VOC removal efficiency of the system. It may be possible in some cases to
increase VOC removal efficiency by a change in the absorbent.
Systems that utilize organic liquids as solvents usually include
stripping and recycle of the solvent to the absorber. In this case the VOC
removal efficiency of the absorber is also dependent on the solvent
stripping efficiency.
4.1.2.3 Applicability of Absorption. Absorption is attractive if a
significant amount of VOC can be recovered for reuse. As noted earlier, 13
out of 66 units with vent streams (about 20 percent) in the EDP use absorption
devices. These units produce ethylene oxide and monochlorobenzene and use
absorbers to recover reactant for reuse as a. feedstock material.
Absorption is not usually considered for use when the VOC concentration
in a process vent stream is below 200 to 300 ppmv.16 Furthermore, the use
of absorption is subject to the availability of an appropriate solvent for a
particular VOC.
A number of chemical processes use absorption systems as an integral
part of the production scheme. A typical acetic anhydride manufacturing
facility is an example of one such production scheme. Acetic anhydride is
produced via the pyrolysis of acetic acid to form ketene. The ketene
produced in the pyrolysis furnaces contains by-products and other
impurities. Ketene is separated from these by-products and impurities by
contacting the product stream with glacial acetic acid in a ketene absorber.
Ketene is absorbed from the product stream and routed to further processing
and eventual acetic anhydride purification.
4.1.3 Adsorption
4.1.3.1 Adsorption Process Description. Adsorption is a mass-transfer
operation involving interaction between gaseous and solid phase components.
4-6
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O£ANE3 GAS OUT
To ->nai Control Csvica
ABSORBING
UQUIO IN
(3)
'A3C WOE!
IN
(4)
ABSORBING UQUIO
im voc OUT
Ta Qisoosai » vOC'Soivtnt Recovery
Figure 4-2. Packed tower for gas absorption.
4-7
-------
The gas phase (adsorbate) is captured on the solid phase (adsorbent) surface
by physical or chemical adsorption mechanisms. Physical adsorption is a
mechanism that takes place when intermolecular (van der Waals) forces
attract and hold the gas molecules to the solid surface.17 Chemisorption
occurs when a chemical bond forms between the gas and solid phase molecules.
A physically adsorbed molecule can readily be removed from the adsorbent
(under suitable temperature and pressure conditions) while the removal of a
chemisorbed component is much more difficult.
The most commonly encountered industrial adsorption systems use
activated carbon as the adsorbent. Activated carbon is effective in
capturing certain organic vapors by the physical adsorption mechanism. In
addition, adsorbate may be vaporized for recovery by regeneration of the
adsorption bed with steam. Oxygenated adsorbents such as silica gels,
diatomaceous earth, alumina, or synthetic zeolites exhibit a greater
selectivity than activated carbon for capturing some compounds. These
adsorbents have a strong preferential affinity for water vapor over organic
gases and would be of little use for high moisture gas streams from some
reactor process vents.18
The design of a carbon adsorption system depends on the chemical
characteristics of the VOC being recovered, the physical properties of
the offgas stream (temperature, pressure, and volumetric flowrate), and the
physical properties of the adsorbent. The mass flowrate of VOC from the gas
phase to the surface of the adsorbent (the rate of capture) is directly
proportional to the difference in VOC concentration between the gas phase
and the solid surface. In addition, the mass flowrate of VOC is dependent
on the adsorbent bed volume, the surface area of adsorbent available to
capture VOC, and the rate of diffusion of VOC through the gas film at the
gas and solid phase interface. Physical adsorption is an exothermic
operation that is most efficient within a narrow range of temperature and
pressure. A schematic diagram of a typical fixed bed, regenerative carbon
adsorption system is given in Figure 4-3. The process offgases are filtered
and cooled (1) before entering the carbon bed. The inlet gases to an
adsorption unit are filtered to prevent bed contamination. The gas is
cooled to maintain the bed at the optimum operating temperature and to
prevent fires or polymerization of the VOC. Vapors entering the adsorber
stage of the system (2) are passed through the porous activated carbon bed.
Adsorption of inlet vapors occurs in the bed until the activated carbon
is saturated with VOC. The dynamics of the process may be illustrated by
viewing the carbon bed as a series of layers or mass-transfer zones, as
illustrated by (3a, b, c) in Figure 4-3. Gases entering the bed are highly
adsorbed first in zone (a). Because most of the VOC is adsorbed in zone
(a), very little adsorption takes place in zones (b) and (c). Adsorption in
zone (b) increases as zone (a) becomes saturated with organics, and
eventually adsorption occurs in zone (c). When the bed is completely
saturated (breakthrough) the fhcoming VOC-laden offgases are routed to an
alternate bed while the saturated carbon bed is regenerated.
4-8
-------
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Regeneration of the carbon bed is accomplished by heating the bed or
applying vacuum to draw off the adsorbed VOC. Heat (the heat of adsorption)
is given up on adsorption and required for desorption. Low pressure
steam (4) is frequently used as a heat source to strip the adsorbent of VOC.
The steam-laden vapors are then sent to a condenser (5) and subsequently to
some type of solvent separation system (6). The regenerated bed is put back
into active service while the saturated bed is purged of organics. The
regeneration process may be repeated numerous times, but eventually the
carbon must be replaced.
4.1.3.2 Adsorption Control Efficiency. Many modern, well-designed
systems achieve 95 percent efficiency for some chemicals.19 Higher
adsorption system efficiencies are achievable, but the addition of the
carbon beds necessary to reach these higher efficiencies will add to system
cost. The VOC removal efficiency of an adsorption system is dependent upon
the physical properties of the compounds present in the offgas, the gas
stream characteristics, and the physical properties of the adsorbent.
Gas temperature, pressure and velocity are important in determining
adsorption efficiency. The adsorption rate in the bed decreases sharply
when gas temperatures are above 38°C (100°F).20,21 High temperature
increases the kinetic energy of the gas molecules causing them to overcome
van der Waals forces. Under these conditions, the VOC are not retained on
the surface of the carbon. Increasing system pressure generally will
improve VOC capture efficiency; however, care must be taken to prevent
solvent condensation on the carbon surface that will decrease efficiency and
subsequently may cause a fire hazard. The gas velocity entering the carbon
bed must be low enough to allow time for adsorption to take place. The
required depth of the bed for a given compound, therefore, is directly
proportional to the carbon granule size and porosity and to the gas stream
velocity (i.e., bed depth must increase as the gas velocity increases for a
given carbon type).
4.1.3.3 Applicability of Adsorption. Although carbon adsorption is an
excellent method for recovering some valuable process chemicals, there are
no process units in the EDP where adsorbers are used. Adsorption systems
are rarely used on reactor process vent streams because process vent stream
conditions are not well-suited for the effective use of carbon adsorption.
Some characteristics of SOCMI reactor process vent streams that make them
unsuitable for effective use of carbon adsorption are: (1) high VOC
concentrations (which can "flood" carbon surfaces), (2) very high or very
low molecular weight compounds (which desorb or adsorb with difficulty,
respectively), and (3) mixtures of high and low boiling point VOC (which can
differentially desorb or adsorb). The range of organic concentration to
which carbon adsorption can be applied is from a few parts per million (by
volume) to concentrations of several percent.22 Process vent stream data in
the EDP indicate that most streams have either very low VOC contents (less
than 1 percent) or much higher VOC contents (15 to 60 percent and above).
Adsorbing VOC from process vent streams with high organic concentrations may
result in excessive temperature rise in the carbon bed due to the
4-10
-------
accumulated heat of adsorption of the VOC loading. However, a high organic
concentration can be diluted to a concentration low enough for the
application of a carbon adsorption system.
For effective adsorption, the molecular weight of the compounds to be
adsorbed should be in the range of 45 to 130 gm/gm-mole. Accordingly,
carbon adsorption may not be an effective control technique for compounds
with low molecular weights (below 45 gm/gm-mole) owing to their smaller
attractive forces or for high molecular weight compounds (^130 gm/gm-mole)
that adsorb so strongly to the carbon bed that they are not easily
removed.23 Properly operated adsorption systems can be very effective for
homogeneous offgas streams; but adsorption systems can experience operating
problems with a multicomponent system containing a mixture of light and
heavy hydrocarbons. The lighter organics tend to be displaced by the
heavier (higher boiling) components, resulting in greatly reduced system
efficiency.21* Vent stream data from the EDP indicate some reactor process
vent streams have mixtures of light and heavy organics.
4.2 COMBUSTION CONTROL DEVICES
Combustion control devices alter the chemical structure of the VOC.
Combustion is complete if all VOC are converted to carbon dioxide and water.
Incomplete combustion results in some of the VOC being unaltered or being
converted to other organic compounds such as aldehydes or acids.
The combustion control devices discussed in the following four sections
include flares, thermal incinerators, catalytic oxidizers, and boilers and
process heaters. Each device is discussed separately with respect to its
operation, destruction efficiency, and applicability to reactor process vent
streams. Many combustion devices are widely applied, especially where VOC
control of process vent streams is mandated by current regulations and where
substantial energy recovery potential exists for a particular process vent
stream. For the 66 units identified in the -EDP that have reactor process
vent streams, 13 use incinerators, 11 use flares, 7 use boilers, and 5 use
process heaters to control VOC prior to atmospheric discharge of the process
vent stream. None use catalytic oxidizers.
4.2.1 Flares
4.2.1.1 Flare Process Description. Flaring is an open combustion
process in which the oxygen required for combustion is provided by the air
around the flame. Good combustion in a flare is governed by flame
temperature, residence time of components in the combustion zone, turbulent
mixing of the components to complete the oxidation reaction, and the amount
of oxygen available for free radical formation.
Kalcevic presents a detailed discussion of different types of flares,
flare design and operating considerations, as well as a method for
estimating capital and operating costs for flares.25 The basic elements of
an* elevated flare system are shown in Figure 4-4. Process offgases are sent
to the flare through the collection header (1). The offgases entering the
4-11
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Now lea
(6)
Baine*
Helps prevent flash back
Flare Tip (8)
Pilot
3u
-------
header can vary widely in volumetric flow rate, moisture content, VOC'
concentration, and heat value. The knock-out drum (2) removes water or
hydrocarbon droplets that could extinguish the flame or cause irregular
combustion. Offgases are usually passed through a water seal (3) before
going to the flare. This prevents possible flame flashbacks, caused when
the offgas flow to the flare is too low and the flame front pulls down into
the stack.
Purge gas (N2, C02, or natural gas) (4) also helps to prevent flashback
in the flare stack (5) caused by low offgas flow. The total volumetric flow
to the flame must be carefully controlled to prevent low flow flashback
problems and to avoid flame instability. A gas barrier (6) or a stack seal
is sometimes used just below the flare head to impede the flow of air into
the flare gas network.
The VOC stream enters at the base of the flame where it is heated by
already burning fuel and pilot burners (7) at the flare tip (8). If the gas
has sufficient oxygen and residence time in the flame zone it can be
completely burned. A diffusion flame receives its combustion oxygen by
diffusion of air into the flame from the surrounding atmosphere. The high
volume of fuel flow in a flare requires more combustion air at a faster rate
than simple gas diffusion can supply so flare designers add steam injection
nozzles (9) to increase gas turbulence in the flame boundary zones, drawing
in more combustion air and improving combustion efficiency. This steam
injection promotes smokeless flare operation by minimizing the cracking
reactions that form carbon. Significant disadvantages of steam usage are
the increased noise and cost. The steam requirement depends on the
composition of the gas flared, the steam velocity from the injection nozzle,
and the tip diameter. Although some gases can be flared smokelessly without
any steam, typically 0.15 to 0.5 kg of steam per kg of flare gas is
required. Gases with heating values below about 8 MJ/scm (200 Btu/scf) may
be flared smokelessly without steam or air assist.
Steam injection is usually controlled manually with the operator
observing the flare (either directly or on a television monitor) and adding
steam as required to maintain smokeless operation. Several flare manufac-
turers offer devices such as infrared sensors that sense flare flame
characteristics and adjust the steam flow rate automatically to maintain
smokeless operation.
Some elevated flares use forced air instead of steam to provide the
combustion air and the mixing required for smokeless operation. These
flares consist of two coaxial flow channels. The combustible gases flow in
the center channel and the combustion air (provided by a fan in the bottom
of the flare stack) flows in the annulus. The principal advantage of
air-assisted flares is that expensive steam is not required. Air assist is
rarely used on large flares because air flow is difficult to control when
the gas flow is intermittent. About 0.8 hp of blower capacity is required
for each 100 Ib/hr of gas flared.26
4-13
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Ground flares are usually enclosed and have multiple burner heads that
are staged to operate based on the quantity of gas released to the flare.
The energy of the flared gas itself (because of the high nozzle pressure
drop) is usually adequate to provide the mixing necessary for smokeless
operation and air or steam assist is not required. A fence or other
enclosure reduces noise and light from the flare and provides some wind
protection. Ground flares are less numerous and have less capacity than
elevated flares. Typically they are used to burn gas "continuously" while
steam-assisted elevated flares are typically used to dispose of large
amounts of gas released in emergencies.27
4.2.1.2 Flare Combustion Efficiency.
4.2.1.2.1Factors affecting flare efficiency. The flammability limits
of the flared gases influence ignition stability and flame extinction.
(Gases must be within their flammability limits to burn.) When flammability
limits are narrow, the interior of the flame may have insufficient air for
the mixture to burn. Fuels with wide limits of flammability (for instance,
H2) are therefore usually easier to burn.
The auto-ignition temperature of a fuel affects combustion because gas
mixtures must be at a high enough temperature to burn. A gas with a low
auto-ignition temperature will ignite and burn more easily than a gas with a
high auto-ignition temperature.
The heating value of the fuel also affects the flame stability,
emissions, and flame structure. A lower heating value fuel produces a
cooler flame that does not favor combustion kinetics and also is more easily
extinguished. The lower flame temperature will also reduce buoyant forces,
which reduces mixing (especially for large flares on the verge of smoking).
While low Btu content streams can be efficiently combusted, they are more
likely to be inefficiently combusted because of the factors discussed above.
For these reasons, VOC emissions from flares burning gases with low Btu
content may be higher than those from flares that burn high Btu gases.
The density of the gas flared also affects the structure and stability
of the flame through the effect on buoyancy and mixing. The velocity in
many flares is very low, therefore, most of the flame structure is developed
through buoyant forces as a result of the burning gas. Lighter gases there-
fore tend to burn better. The density of the fuel also affects the minimum
purge gas required to prevent flashback and the design of the burner tip.
Poor mixing at the flare tip or poor flare maintenance can cause
smoking (particulate). Fuels with high carbon to hydrogen ratios (greater
than 0.35) have a greater tendency to smoke and require better mixing if
they are to be burned smokelessly.
Many flare systems: are currently operated in conjunction with baseload
gas recovery systems. Such systems are used to recover VOC from the flare
header system for reuse. Recovered VOC may be used as a feedstock in other
processes or as a fuel in process heaters, boilers or other combustion
4-14
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devices. When baseload gas recovery systems are applied, the flare is
generally used to combust process upset and emergency gas releases that the
baseload system is not designed to recover. In some cases, the operation of
a baseload gas recovery system may offer an economic advantage over
operation of a flare alone since sufficient quantity of useable VOC can be
recovered.
4.2.1.2.2 Flare efficiency test data. This section presents a review
of the flares and operating conditions used in five studies of flare combus-
tion efficiency. Each study summarized in Table 4-1 can be found in
complete form in the docket.28-33
Palmer experimented with a 1.3 cm (1/2-inch) ID flare head, the tip of
which was located 1.2 m (4 ft) from the ground. Ethylene was flared at 15
to 76 m/s (50 to 250 ft/sec) at the exit, 0.1 to 0.6 MW (0.4 x 106 to
2.1 x 106 Btu/hr). Helium was added to the ethylene as a tracer at 1 to
3 volume percent and the effect of steam injection was investigated in some
experiments. Destruction efficiency (the percent ethylene converted to some
other compound) was 97.8 percent.3k
Siegel made the first comprehensive study of a commercial flare system.
He studied burning of refinery gas on a commercial flare head manufactured
by Flaregas Company. The flare gases used consisted primarily of hydrogen
(45.4 to 69.3 percent by volume) and light paraffins (methane to butane).
Traces of H2S were also present in some runs. The flare was operated from
30 to 2,900 kilograms of fuel/hr (287 to 6,393 Ib/hr), and the maximum heat
release rate was approximately 68.96 MW (235 x 106 Btu/hr). Combustion
efficiencies (the percent VOC converted to C02) averaged over 99 percent.35
Lee and Whipple studied a bench-scale propane flare. The flare head
was 5.1 cm (2 inches) in diameter with one 13/16-inch center hole surrounded
by two rings of 16 1/8-inch holes, and two rings of 16 3/16-inch holes.
This configuration had an open area of 57.1 percent. The velocity through
the head was approximately 0.9 m/s (3 ft/sec) and the heating rate was
0.1 MW (0.3 x 106 Btu/hr). The effects of steam and crosswind were not
investigated in this study. Destruction efficiencies were 99.9 percent or
greater.36
Howes, et al. studied two commercial flare heads at John Zink's flare
test facility. The primary purpose of this test (which was sponsored by
EPA) was to develop a flare testing procedure. The commercial flare heads
were an air-assisted head and a Linear Relief Gas Oxidizer (LRGO) head
manufactured by John Zink Company. The air-assisted flare burned
1,043 kg/hr (2,300 Ib/hr) of commercial propane. The exit gas velocity
based on the pipe diameter was 8.2 m/s (27 ft/sec) and the firing rate was
13 MW (44 x 106 Btu/hr). The LRGO flare consisted of 3 burner heads located
0.9 m (3 ft) apart. The 3 burners combined fired 1,905 kg/hr (4,200 Ibs/hr)
of natural gas. This corresponds to a firing rate of 24.5 MW
(83.7 x 106 Btu/hr). Steam was not used for either flare, but the
air-assisted flare head was in some trials augmented by a forced draft fan.
Combustion efficiencies for both flares during normal operation were greater
than 99 percent.37
4-15
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TABLE 4-1. FLARE EMISSION STUDIES COMPLETED BY OCTOBER 1982
Investigator
Palmer (1972)
Lee & Uhlpple (1981)
Siege 1 (1980)
Sponsor
E.I. du Pont
Union Carbide
Ph.D. Dissertation
Flare Tip Design
1.3 cm (0.5 Inch)
diameter
Discrete holes In 5 cm
(2 Inch) diameter cap
References
28
29
Commercial design 70 cm 30
(27.7 Inch) diameter
steam assisted
Flared Gas
Ethylene
Propane
=50% H,
plus light
hydrocarbons
Throughput
megawatts
(10e Btu/hr)
0.12-0.62 (0.4-2.1)
0.1 (0.3)
14-52 (49-178)
Flare
Efficiency
X
97.8->99
>99.9
>99
Howes et al. (1981)
EPA
McDanlel et al. (1982) CHA-EPA
Commercial design 15 cm 31 Propane
(6 inch) diameter air
assisted
Commercial design H.P.
3 tips 0 10 cm (4 Inch)
diameter
Commercial design 10 cm 32 Propylene
(4 inch) diameter
13 (44)
Natural Gas 8.2 (28)
0.003-17 (0.01-57)
>99
>99
83-99.9
SOURCE: Reference 33
-------
A detailed review of all four studies was done by Joseph, et al. in
January 1982.38 A fifth study39 determined the influence on flare
performance of mixing, Btir content and gas flow velocity. A steam-assisted
flare was tested at the John Zink facility using the procedures developed by
Howes. The test was sponsored by the Chemical Manufacturers Association
(CMA) with the cooperation and support of EPA. All of the tests were with
an 80 percent propylene, 20 percent propane mixture diluted as required with
nitrogen to give different heat content values. This was the first work
which determined flare efficiencies at a variety of "nonideal" conditions
where lower efficiencies had been predicted. All previous tests were of
flares which burned gases which were very easily combustible and did not
tend to soot (i.e., they tended to burn smokelessly). This was also the
first test which used the sampling and chemical analysis methods developed
for EPA by Howes. The steam-assisted flare was tested with exit flow
velocities ranging up to about 18.3 m/s (60 ft/sec), with heat contents from
11 to 84 MJ/scm (300 to 2,200 Btu/scf) and with steam to gas (weight) ratios
varying from 0 (no steam) to 6.86. Air-assisted flares were tested with
fuel gas heat contents as low as 3 MJ/scm (83 Btu/scf). Flares without
assist were tested as low as 8 MJ/scm (200 Btu/scf). All of these tests,
except for those with very high steam to gas ratios, showed combustion
efficiencies of over 98 percent. Flares with high steam to gas ratios
(about 10 times more steam than that required for smokeless operation) had
lower efficiencies (69 to 82 percent) when combusting 84 MJ/scm
(2,200 Btu/scf) gas.
After considering the results of these five studies, EPA has concluded
that 98 percent combustion efficiency can be achieved by steam-assisted
flares with exit flow velocities less than 18.3 m/s (60 ft/sec) and
combustion gases with heat contents over 11 MJ/scm (300 Btu/scf) and by
flares operated without assist with exit flow velocities less than 18.3 m/s
(60 ft/sec) and burning gases with heat contents over 8 MJ/scm (200 Btu/scf).
Flares are not normally operated at the very high steam to gas ratios that
resulted in low efficiency in some tests because steam is expensive and
operators make every effort to keep steam consumption low. Flares with high
steam rates are also noisy and may be a neighborhood nuisance.
Another study was performed by the Energy and Environmental Research
Corporation for EPA in order to investigate the VOC destruction efficiency
of flares at gas exit velocities greater than 60 ft/sec and 300 Btu/scf
heating value. Based on this study, EPA concluded that steam-assisted and
nonassisted flares that are designed and operated with an exit velocity less
than 122 m/sec (400 ft/sec) can achieve and maintain a 98 percent destruction
efficiency if the heating value of the gas being combusted is greater than
37.3 MJ/scm (1,000 Btu/scf). A report of this study is included in the
docket.63
•n,« FDA has a program under way to determine more exactly the
efficiencies of flares used in the petroleum refining industry/SOCMI and a
flare test facility has been constructed. The combustion efficiency of four
4-17
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flares (1 1/2 inches to 12 inches ID) will be determined and the effect on
efficiency of flare operating parameters, weather factors, and fuel
composition will.be established.
4.2.1.3 Applicability of Flares. About 75 percent of the organic
chemical plants are estimated to have a flare.1*0 Flares are usually
designed to control the normal operating vents or emergency upsets, which
require release of large volumes of gases. Often, large diameter flares
designed to handle emergency releases are used to control continuous vent
streams from various process operations. Eleven of the 66 units (17 percent)
in the EDP that have reactor process vent streams use flares to destroy VOC
in those streams. Process vent stream heating values for these eleven units
range generally from 7.6 to 58.8 MJ/scm (205 to 1,578 Btu/scf). In refineries,
many process vents are usually combined in a common gas header that supplies
fuel to boilers and process heaters. However, excess gases, fluctuations in
flow in the gas line, and emergency releases are sometimes sent to a flare.
Flares have been found to be useful emission control devices. They can
be used for almost any VOC stream, and can handle fluctuations in VOC
concentration, flowrate, and inerts content. Some streams, such as those
containing high concentrations of halogenated or sulfur-containing
compounds, are not usually flared due to corrosion of the flare tip or
formation of secondary pollutants (such as S02).
4.2.2 Thermal Incinerators
4.2.2.1Thermal Incinerator Process Description. Any VOC heated to a
high enough temperature in the presence of enough oxygen will be oxidized to
carbon dioxide and water. This is the basic principle of operation of a
thermal incinerator. The theoretical temperature required for thermal
oxidation depends on the structure of the chemical involved. Some chemicals
are oxidized at temperatures much lower than others. However, a temperature
can be identified that will result in the efficient destruction of most VOC
from reactor processes. All practical thermal incineration processes are
influenced by residence time, mixing, and temperature. An efficient thermal
incinerator system must provide:
1. A chamber temperature high enough to enable the oxidation reaction
to proceed rapidly to completion;
2. Enough turbulence to obtain good mixing between the hot combustion
products from the burner, combustion air, and VOC; and
3. Sufficient residence time at the chosen temperature for the
oxidation reaction to reach completion.
A thermal incinerator is usually a refractory-lined chamber containing
a burner (or set of burners) at one end. As shown in Figure 4-5, discrete
dual fuel burners (1) and inlets for the offgas (2) and combustion air (3)
are arranged in a premixing chamber (4) to mix thoroughly the hot products
from the burners with the offgas air streams. The mixture of hot reacting
gases .then passes into the main combustion chamber (5). This section is
sized to allow the mixture enough time at the elevated temperature for the
oxidation reaction to reach completion (residence times of 0.3 to 1.0 second
4-18
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tfaste Gas
Auxiliary
Fuel 3unw
(discrete)
(1)
Air
(3)
Mixing
Section
(4)
Combustion
Section (5)
Stack
4
Gotionat
Heat
Recovery (o)
Fioure 4-5. Discrete burner, thermal incinerator.
4-19
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are common). Energy can then be recovered from the hot flue gases in a heat
recovery section (6). Preheating of combustion air or offgas is a common
mode of energy recovery; however, it is sometimes more economical to
generate steam. Insurance regulations require that if the waste stream is
preheated, the VOC concentration must be maintained below 25 percent of the
lower explosive limit (LEL) to prevent explosion hazards.
Thermal incinerators designed specifically for VOC incineration with
natural gas as the auxiliary fuel may also use a grid-type (distributed) gas
burner as shown in Figure 4-6.1+1 The tiny gas flame jets (1) on the grid
surface (2) ignite the vapors as they pass through the grid. The grid acts
as a baffle for mixing the gases entering the chamber (3). This arrangement
ensures burning of all vapors at lower chamber temperature and uses less
fuel. This system makes possible a shorter reaction chamber yet maintains
high efficiency.
Other parameters affecting incinerator performance are the vent stream
heating value, the water content in the stream, and the amount of excess
combustion air (the amount of air above the stoichiometric air needed for
reaction). The vent stream heating value is a measure of the heat available
from the combustion of the VOC in the vent stream. Combustion of vent
stream with a heating value less than 1.9 MJ/scm (50 Btu/scf) usually
requires burning auxiliary fuel to maintain the desired combustion
temperature. Auxiliary fuel requirements can be lessened or eliminated by
the use of recuperative heat exchangers to preheat combustion air. Vent
streams with a heating value above 1.9 MJ/scm (50 Btu/scf) may support
combustion but may need auxiliary fuel for flame stability.
A thermal incinerator handling vent streams with varying heating values
and moisture content requires careful adjustment to maintain the proper
chamber temperatures and operating efficiency. Since water requires a great
deal of heat to vaporize, entrained water droplets in an offgas stream can
increase auxiliary fuel requirements to provide the additional energy needed
to vaporize the water and raise it to the combustion chamber temperature.
Combustion devices are always operated with some quantity of excess air to
ensure a sufficient supply of oxygen. The amount of excess air used varies
with the fuel and burner type but should be kept as low as possible. Using
too much excess air wastes fuel because the additional air must be heated to
the combustion chamber temperature. Large amounts of excess air also
increases flue gas volume and may increase the size and cost of the system.
Packaged, single unit thermal incinerators can be built to control streams
with flowrates in the range ef 0.14 scm/sec (300 scfm) to about 24 scm/sec
(50,000 scfm).
Thermal oxidizers for halogenated VOC may require additional control
equipment to remove the corrosive combustion products. The flue gases are
quenched to lower their temperature and are then routed through absorption
equipment such as towers or liquid jet scrubbers to remove the corrosive
gases. The halogenated VOC streams are usually scrubbed to prevent
4-20
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(2)
8unwP!atB- Flame Jets-? (1)
Stack
(natuwi gas)
Auxiliary fvei
Figure 4-6. Distributed burner, thermal incinerator.
4-21
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corrosion due to contact with acid gases formed during the combustion of
these streams.
4.2.2.2 Thermal Incinerator Removal Efficiency. The VOC destruction
efficiency of a thermal oxidizer can be affected by variations in chamber
temperature, residence time, inlet VOC concentration, compound type, and
flow regime (mixing). Test results show that thermal oxidizers can achieve
98 percent destruction efficiency for most VOC compounds at combustion
chamber temperatures ranging from 700 to 1,300°C (1,300 to 2,370°F) and
residence times of 0.5 to 1.5 seconds.1*2 These data indicate that signifi-
cant variations in destruction efficiency occurred for Cl to C5 alkanes and
olefins, aromatics (benzene, toluene, and xylene), oxygenated compounds
(methyl ethyl ketone and isopropanol), chlorinated organics (vinyl
chloride), and nitrogen-containing species (acrylonitrile and ethylamines)
at chamber temperatures below 760°C (1,400°F). This information, used in
conjunction with kinetics calculations, indicates the combustion chamber
parameters for achieving at least a 98 percent VOC destruction efficiency
are a combustion temperature of 870°C (1,600°F) and a residence time of
0.75 seconds (based upon residence in the chamber volume at combustion
temperature). A thermal oxidizer designed to produce these conditions in
the combustion chamber should be capable of high destruction efficiency for
almost any nonhalogenated VOC.
At temperatures over 760°C (1,400°F), the oxidation reaction rates are
much faster than the rate of gas diffusion mixing. The destruction effi-
ciency of the VOC then becomes dependent upon the fluid mechanics within the
oxidation chamber. The flow regime must assure rapid, thorough mixing of
the VOC stream, combustion air, and hot combustion products from the burner.
This enables the VOC to attain the combustion temperature in the presence of
enough oxygen for a sufficient time period for the oxidation reaction to
reach completion.
Based upon studies of thermal oxidizer efficiency, it has been
concluded that 98-percent VOC destruction or a 20 ppmv compound exit
concentration is achievable by all new incinerators considering current
technology.1*3 Because of much slower combustion reaction rates at lower
inlet VOC concentrations, the maximum achievable VOC destruction efficiency
decreases as inlet concentration decreases. Therefore, a VOC weight
percentage reduction based on the mass rate of VOC exiting the control
device versus the mass rate of VOC entering the device, would be appropriate
for vent streams with VOC concentrations above approximately 2,000 ppmv
(corresponding to 1,000 ppmv VOC in the incinerator inlet stream since air
dilution is typically 1:1). For vent streams with VOC concentration below
approximately 2,000 ppmv, it has been determined that an incinerator outlet
concentration of 20 ppmv (by compound), or lower, is achievable by all new
thermal oxidizers.1*3 The 98 percent efficiency estimate is predicated upon
thermal incinerators operated at 870°C (1,600°F) with 0.75 seconds residence
time. Study results show that these conditions yield conservative estimates
of costs and energy use for these type units.
4-22
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4.2.2.3 Applicability of Thermal Incinerators. In terms of technical
feasibility, thermal incinerators are applicable as a control device for
most reactor process vent streams. They can be used for process vent
streams with any VOC concentration and any type of VOC, and they can be
designed to handle minor fluctuations in flows. However, excessive
fluctuations in flow (i.e., process upsets) might not allow the use of
incinerators and would require the use of a flare. Presence of elements
such as halogens or sulfur might require some additional equipment such as
scrubbers for acid gas removal. Thermal incinerators are currently used to
control VOC emissions from a number of process operations including reactors
and distillation operations. Thirteen of the 66 units in the EDP that have
reactor process vent streams use thermal incinerator systems to control VOC
in those streams. Heating values of the process vent stream for these
13 units range from 6 to 46 MJ/scm (163 to 1,228 Btu/scf).
4.2.3 Industrial Boilers and Process Heaters
Industrial boilers and process heaters can be designed to control VOC
by incorporating the reactor process vent stream with the inlet fuel or by
feeding the stream into the boiler or heater through a separate burner. The
major distinctions between industrial boilers and process heaters are that
the former produces steam usually at high temperatures while the latter
raises the temperature of process streams as well as superheating steam
usually at temperatures lower than an industrial boiler. The following is a
process description and discussion of the applicability and efficiency of
applying industrial boilers or process heaters to control VOC in process
vent streams. The process description for an industrial boiler and a
process heater are presented separately in the following two sections. The
process descriptions focus on those aspects that relate to the use of these
combustion devices as a VOC control method.
4.2.3.1 Industrial Boiler Description. Surveys of industrial boilers
show that the majority of industrial boilers used in the chemical industry
are of watertube design. Furthermore, over half of these boilers use
natural gas as a fuel.1*1* In a watertube boiler, hot combustion gases
contact the outside of heat transfer tubes, which contain hot water and
steam. These tubes are interconnected by a set of drums that collect and
store the heated water and steam. The water tubes are of relatively small
diameter, 5 cm (2.0 inches), providing rapid heat transfer, rapid response
to steam demands, and relatively high thermal efficiency.1*5 Energy transfer
from the hot flue gases to water in the furnace water tube and drum system
can be above 85 percent efficient. Additional energy can be recovered from
the flue gas by preheating combustion air in an air preheater or by
preheating incoming boiler feedwater in an economizer unit.
When firing natural gas, forced or natural draft burners are used to
mix thoroughly the incoming fuel and combustion air. If a process vent
stream is combusted in a boiler, it can be mixed with the incoming fuel or
fed to the furnace through a separate burner. In general, burner design
depends on the characteristics of the fuel mix (when the process vent stream
and fuel are combined) or of the characteristics of the vent stream alone
4-23
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(when a separate burner is used). A particular burner design, commonly
known as a high intensity or vortex burner, can be effective for vent
streams with low heating values (i.e., streams where a conventional burner
may not be applicable). Effective combustion of low heating value streams
is accomplished in a high intensity burner by passing the combustion air
through a series of spin vanes to generate a strong vortex.
Furnace residence time and temperature profiles vary for industrial
boilers depending on the furnace and burner configuration, fuel type, heat
input, and excess air level.l*6 A mathematical model has been developed that
estimates the furnace residence time and temperature profiles for a variety
of industrial boilers.1*7 This model predicts mean furnace residence times
of from 0.25 to 0.83 seconds for natural gas-fired watertube boilers in the
size range from 4.4 to 44 MW (15 to 150 x 106 Btu/hr). Boilers at or above
the 44 MW size have residence times and are generally operated at
temperatures that ensure a 98-percent VOC destruction efficiency. Furnace
exit temperatures for this range of boiler sizes are at or above 1,200°C
(2,200°F) with peak furnace temperatures occurring in excess of 1,540°C
(2,810°F). Residence times for oil-fired boilers are similar to the natural
gas-fired boilers described here.
4.2.3.2 Process Heater Description. A process heater is similar to an
industrial boiler in that heat liberated by the combustion of fuels is
transferred by radiation and convection to fluids contained in tubular
coils. Process heaters are used in many chemical manufacturing operations
discussed in Chapter 3 to drive endothermic reactions. They are also used
as feed preheaters and as reboilers for some distillation operations. The
fuels used in process heaters include natural gas, refinery offgases, and
various grades of fuel oil. Gaseous fuels account for about 90 percent of
the energy consumed by process heaters.1*8
There are many variations in the design of process heaters depending on
the application considered. In general, the radiant section consists of the
burner(s), the firebox, and a row of tubular coils containing the process
fluid. Most heaters also contain a convective section in which heat is
recovered from hot combustion gases by convective heat transfer to the
process fluid.
Process heater applications in the chemical industry can be broadly
classified with respect to firebox temperature: (1) low firebox temperature
applications such as feed preheaters and reboilers, (2) medium firebox
temperature applications such as steam superheaters, and (3) high firebox
temperature applications such as pyrolysis furnaces and steam-hydrocarbon
reformers. Firebox temperatures within the chemical industry can range from
about 400°C (750°F) for preheaters and reboilers to 1,260°C (2,300°F) for
pyrolysis furnaces.
4.2.3.3 Industrial Boilers and Process Heater Control Efficiency. A
boiler or process heater furnace can be compared to an incinerator where the
average furnace temperature and residence time determines the combustion
4-24
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efficiency. However, when a vent gas is injected as a fuel into the flame
zone of a boiler or process heater, the required residence time is reduced
due to the relatively high flame zone temperature. The following test data,
which document the destruction efficiencies for industrial boilers and
process heaters, are based on injecting the wastes identified into the flame
zone of each combustion control device.
An EPA sponsored test was conducted in an effort to determine the
destruction efficiency of an industrial boiler for polychlorinated biphenyls
(RGB's).1*9 The results of this test indicated that the PCB destruction
efficiency of an oil-fired industrial boiler firing PCB-spiked oil was
greater than 99 percent for a temperature range of 1,360 - 1,520°C and a
range of residence time of 2-6 seconds. This efficiency was determined
based on the PCB content measured by a gas chromatograph in the fuel feed
and flue gas.
As discussed in previous sections, firebox temperatures for process
heaters show relatively wide variations depending on the application (see
Section 4.2.3.2). Tests were conducted by EPA to determine the benzene
destruction efficiency of five process heaters firing a benzene offgas and
natural gas mixture.5°-52 The units tested are representative of process
heaters with low temperature fireboxes (reboilers) and medium temperature
fireboxes (superheaters). Sampling prob ;ms occurred while testing one of
these heaters, and as a result, the data for that test may not be reliable
and are not presented.53 The reboiler and superheater units tested showed
greater than a 98 percent overall destruction efficiency for Cj to C6
hydrocarbons.51* Additional tests conducted on a second superheater
and a hot oil heater showed that greater than 99 percent overall destruction
of Ci to C6 hydrocarbons occurred for both units.55
4.2.3.4 Applicability of Industrial Boilers and Process Heaters as
Control DevicesTIndustrial boilers and process heaters are currently used
by industry to combust process vent streams from distillation operations,
reactor operations, and general refinery operations. Twelve of the 66 units
(18 percent) in the EDP with process vent streams use boilers or process
heaters to combust reactor vent streams. Process vent stream heating values
for these 12 units range from 0 to 46 MJ/scm (0 to 1,233 Btu/scf). As the
profile shows, these devices are most applicable where high vent stream heat
recovery potential exists.
Both boilers and process heaters are essential to the operation of a
plant. As a result, only streams that are certain not to reduce the
device's performance or reliability warrant use of a boiler or process
heater as a combustion control device. Variations in vent stream flowrate
and/or heating value could affect the heat output or flame stability of a
boiler or process heater and should be considered when using these
combustion devices. Performance or reliability may be affected by the
presence of corrosive products in the vent stream. Since these compounds
could corrode boiler or process heater materials, vent streams with a
relatively high concentration of halogenated or sulfur containing compounds
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are usually not combusted in boilers or process heaters. When corrosive VOC
compounds are combusted, the flue gas temperature must be maintained above
the acid dewpoint to prevent acid deposition and subsequent corrosion from
occurring.
The introduction of a reactor process vent stream into the furnace of a
boiler or heater could alter the heat transfer characteristics of the
furnace. Heat transfer characteristics are dependent on the flowrate,
heating value, and elemental composition of the process vent stream, and the
size and type of heat generating unit being used. Often, there is no
significant alteration of the heat transfer, and the organic content of the
process vent stream can in some cases lead to a reduction in the amount of
fuel required to achieve the desired heat production. In other cases, the
change in heat transfer characteristics after introduction of a process vent
stream may affect the performance of the heat generating unit, and increase
fuel requirements. For some process vent streams there may be potential
safety problems associated with ducting reactor process vents to a boiler or
process heater. Variation in the flowrate and organic content of the vent
stream could, in some cases, lead to explosive mixtures within a boiler
furnace. Flame fluttering within the furnace could also result from
variations in the process vent stream characteristics. Precautionary
measures should be considered in these situations.
When a boiler or process heater is applicable and available, they are
excellent control devices since they can provide at least 98 percent
destruction of VOC. In addition, near complete recovery of the vent stream
heat content is possible. However, both devices must operate continuously
and concurrently with the pollution source unless an alternate control
strategy is available in the event that the heat generating capacity of
either unit is not required and is shut down.
4.2.4 Catalytic Oxidizer
4.2.4.1 CatalyticTxidizer Process Description. Catalytic oxidation
is the fourth major combustion technique examined for VOC emission control.
A catalyst increases the rate of chemical reaction without becoming
permanently altered itself. Catalysts for catalytic oxidation cause the
oxidizing reaction to proceed at a lower temperature than is required for
thermal oxidation. These units can also operate well at VOC concentrations
below the lower explosive limit, which is a distinct advantage for some
offgas streams. Combustion catalysts include platinum and platinum alloys,
copper oxide, chromium, and cobalt.56 These are deposited in thin layers on
inert substrates to provide for maximum surface area between the catalyst
and the VOC stream.
A schematic of a catalytic oxidation unit is shown in Figure 4-7. The
waste gas (1) is introduced into a mixing chamber (3) where it is heated to
about 316°C (600°F) by contact with the hot combustion products from
auxiliary burners (2). The heated mixture is then passed through the
catalyst bed (4). Oxygen and VOC migrate to the catalyst surface by gas
diffusion and are adsorbed in the pores of the catalyst. The oxidation
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Stacx
Auxiliary
Fuei Burners
(2)
Waste Gas
(1)
Catalyst Bed
Optional
Heat Recovery
(5)
Mixing Chamber (3)
Figure 4-7.
Catalytic oxidizer.
4-27
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reaction takes place at these active sites. Reaction products are desorbed
from the active sites and transferred by diffusion back into the waste
gas.57 The combusted gas may then be passed through a waste heat recovery
device (5) before exhausting into the atmosphere.
The operating temperature of combustion catalysts usually ranges from
316 to 650°C (600 to 1,200°F). Lower temperatures may result in slowing
down and possibly stopping the oxidation reaction. Higher temperatures may
result in shortened catalyst life and possibly evaporation of the catalyst
from the support substrate. Any accumulation of particulate matter,
condensed VOC, or polymerized hydrocarbons on the catalyst could block the
active sites and, therefore, reduce effectiveness. Catalysts can also be
deactivated by compounds containing sulfur, bismuth, phosphorous, arsenic,
antimony, mercury, lead, zinc, tin, or halogens.58 If these compounds exist
in the catalytic unit, VOC will pass through unreacted or be partially
oxidized to form compounds (aldehydes, ketones and organic acids) that are
highly reactive atmospheric pollutants and can corrode plant equipment.
4.2.4.2 Catalytic Oxidizer Control Efficiency. Catalytic oxidizer
destruction efficiency is dependent on the space velocity, (the catalyst
volume required per unit volume gas processed per hour), operating tempera-
ture, oxygen concentration, and waste gas VOC composition and concentration.
A catalytic unit operating at about 450°C (840°F) with a catalyst bed volume
of 0.014 to 0.057 m3 (0.5 to 2 ft3) per 0.47 scm/sec (1,000 scfm) of offgas
passing through the device can achieve 95 percent VOC destruction
efficiency.59 However, catalytic oxidizers have been reported to achieve
efficiencies of 98 percent or greater.60 These higher efficiencies are
usually obtained by increasing the catalyst bed volume to offgas flow ratio.
4.2.4.3 Applicability of Catalytic Oxidizers. The sensitivity of
catalytic oxidizer to VOC inlet stream flow conditions, and their inability
to handle high VOC concentration offgas streams, limit the applicability of
catalytic units for control of VOC from many processes. Some catalytic
units, however, have operated successfully on reactor process vent streams
from air oxidation processes.61
4.3 SUMMARY
The two general classifications of VOC control techniques discussed in
the preceding sections are noncombustion and combustion control devices.
This section summarizes the major points regarding control device
applicability and performance.
The noncombustion control devices discussed include adsorbers,
absorbers, and condensers. In general, although noncombustion devices are
widely applied in the industry, no one device is universally applicable to
reactor vent streams because many restrictions exist to applying these
devices across a broad category of reactor process vent streams. For
example, adsorbers may not always be applicable to vent streams with:
(1) high VOC concentrations, (2) low molecular weight, and (3) mixtures of
low and high molecular weight compounds. These conditions exist in many
4-28
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reactor process vent streams. Absorbers are generally not applied to streams
with VOC concentrations below 200 to 300 ppmv, while condensers are not well
suited for application to vent streams containing low boiling point VOC or to
vent streams with large inert concentrations. Information in the EDP shows
that 30 percent of the units with reactor process vent streams use condenser
and/or absorbers to recover VOC. No units in the EDP use adsorbers. Control
efficiencies for the noncombustion devices considered vary from 50 to 95
percent for condensers and absorbers and up to 95 percent for adsorbers.
The combustion control devices considered include flares, industrial
boilers, process heaters, thermal incinerators, and catalytic oxidizers. With
the exception of catalytic units, these devices are applicable to a wide
variety of process vent stream characteristics and can achieve at least
98 percent destruction efficiency. Combustion devices are generally capable
of adapting to moderate changes in process vent stream flow rate and VOC
concentration, while control efficiency is not greatly affected by the type of
VOC present. This is generally not the case with noncombustion control
devices. In general, combustion control devices may require additional fuel -
except in some cases where boilers or process heaters are applied and the
energy content of the vent stream is recovered. However, because boilers and
process heaters are important in the operation of a chemical plant, process
vent streams that will not reduce boiler or process heater performance and
reliability warrant use of these systems. Application of a scrubber prior to
atmospheric discharge may be required when process vent streams containing
high concentrations of halogenated or sulfonated compounds are combusted in an
enclosed combustion device. In addition, the presence of high concentrations
of corrosive halogenated or sulfonated compounds may preclude the use of
flares because of possible flare tip corrosion and may preclude the use of
boilers and process heaters because of potential internal boiler corrosion.62
In addition, the presence of a halogen acid, such as HC1, in the atmosphere
may cause adverse health effects and equipment corrosion.
The EDP shows that all of the combustion devices are applied to process
vent streams with heating values of greater than about 9.3 MJ/scm
(250 Btu/scf). This indicates that combustion is typically applied to streams
that do not require make-up fuel and/or that have a relatively high energy
recovery potential.
4.4 REFERENCES
1. Erikson, D.G. (IT Enviroscience.) Control Device Evaluation
Condensation. In: U.S. Environmental Protection Agency. Organic
Chemical Manufacturing, Volume 5: Adsorption, Condensation, and
Absorption Devices. Research triangle Park, N.C. Publication
No. EPA-450/3-80-027. December 1980. Report 2. p. II-l.
2. Reference 1, p II-l.
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3. Reference 1, p. IV-1.
4. Reference 1, pp. II-3, III-3.
5. Reference 1, p. III-5.
6. U.S. Environmental Protection Agency. Office of Air Quality Planning and
Standards. Distillation Operations in Synthetic Organic Chemical
Manufacturing - Background Information for Proposed Standards. (Draft
EIS) Research Triangle Park, N.C., Publication No. EPA-450/3-83-005a.
December 1983. p. 4-11.
7. Reference 1, p. II-3.
8. Reference 1, p. III-5.
9. Standifer, R.L. (IT Enviroscience.) Control Device Evaluation Gas
Absorption. In: U.S. Environmental Protection Agency. Organic Chemical
Manufacturing, Volume 5: Adsorption, Condensation, and Absorption
Devices. Research Triangle Park, N.C. Publication No. EPA-450-3-80-
027. December 1980. Report 3. p. III-l.
10. Perry R.H., Chilton, C.H. Eds. Chemical Engineers Handbook. 5th
Edition. McGraw-Hill. New York. 1973. p. 14-2.
11. U.S. Environmental Protection Agency. Office of Air and Waste Manage-
ment. Control Techniques for Volatile Organic Emissions from Stationary
Sources. Research Triangle Park, N.C. Publication No. EPA-450/2-78-
022. May 1978. p. 76.
12. Stern, A.C. Air Pollution, Volume IV, 3rd Edition. Academic Press.
New York. 1977. p. 24.
13. Reference 11, p. 72.
14. Reference 9, p. II-l.
15. Reference 10, p. 14-1.
16. Reference 9, p. III-5.
17. Reference 11, p. 53.
18. Reference 12, p. 336.
19. Reference 12, p. 355.
20. Reference 12, p. 356.
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21. Basdekis, H.S. (IT Enviroscience.) Control Device Evaluation Carbon
Adsorption. In: U.S. Environmental Protection Agency. Organic Chemical
Manufacturing, Volume 5: Adsorption, Condensation, and Absorption
Devices. Research Triangle Park, N.C. Publication No. EPA-450/3-80-
027. December 1980. Report 1. p. 11-15.
22. Reference 21, p. 11-15.
23. Reference 21, p. 1-3.
24. Staff of Research and Education Association. Modern Pollution Control
Technology. Volume I. Research and Education Association. New York.
1978. pp. 22-23.
25. Kalcevic, V. (IT Enviroscience.) Control Device Evaluation Flares and
the Use of Emissions as Fuels. In: U.S. Environmental Protection
Agency. Organic Chemical Manufacturing Volume 4: Combustion Control
Devices. Research Triangle Park, N.C. Publication No. EPA-450/3-80-
026. December 1980. Report 4.
26. Klett, M.G. and J.B. Glaseki. .(Locklead Missiles and Space Co., Inc.)
Flare Systems Study. (Prepared for U.S. Environmental Protection
Agency.) Huntsville, Alabama. Publication No. EPA-600/2-76-079.
march 1976.
27. Joseph D., et al. Evaluation of the Efficiency of Industrial Flares Used
to Destroy Waste Gases, Phase I Interim Report - Experimental Design,
DRAFT. (Prepared for U.S. Environmental Protection Agency.) Research
Triangle Park, N.C. Publication No. EPA-600/2-83-070, August 1983.
28. Palmer, P.A. A Tracer Technique for Determining Efficiency of an
Elevated Flare. E.I. duPont de Nemours and Company. Wilmington,
Delaware, 1972.
29. Lee. K.C., and Whipple, G.M. Waste Gaseous Hydrocarbon Combustion in a
Flare. Union Carbide Corp., presented at 74th APCA Annual Meeting, South
Charleston, West Virginia. June 1981.
30. Siegel, K.D. Degree of Conversion of Flare Gas in Refinery High Flares.
Ph.D. Dissertation. Frideridana University, Karlsruhe, FRG. 1980.
31. Howes, J.E., et al. (Battelle Columbus Laboratories.) Development of
Flare Emission Measurement Methodology. Draft Final Report. (Prepared
for U.S. Environmental Protection Agency.) Research Triangle Park, N.C.
EPA Contract No. 68-02-2682. August 1981.
32. McDaniel, et al. (Engineering-Science.) Flare Efficiency Study.
Publication No. EPA-600/2-83-052. (Prepared for U.S. Environmental
Protection Agency.) Research Triangle Park, N.C. July 1983.
4-31
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33. Memo and attachments from Fanner, J.R., EPA, to distribution.
August 22, 1980. 29 p. Thermal incinerator performance for NSPS.
34. Reference 28.
35. Reference 30.
36. Reference 29.
37. Reference 31.
38. Reference 27.
39. Reference 32.
40. Letter from Matey, J.S., Chemical Manufacturers Association, to Beck,
D., EPA. November 25, 1981.
41. Reed, R.J. North American Combustion Handbook. North American
Manufacturing Company, Cleveland, Ohio. 1979. p. 269.
42. Reference 33.
43. Reference 33.
44. Devitt, T., et al. Population and Characteristics of Industrial/
Commercial Boilers in the U. S., PEDCo Environmental, Inc. EPA
Publication No. 600/7-79-178a. August 1979.
45. U.S. Environmental Protection Agency. Fossil Fuel Fired Industrial
Boilers - Background Information Document, Volume 1: Chapters 1-9.
Research Triangle Park, North Carolina. Publication No. EPA-450/3-82-
006a. March 1982. p. 3-27.
46. U.S. Environmental Protection Agency. A Technical Overview of the
Concept of Disposing of Hazardous Wastes in Industrial Boilers (Draft).
Cincinnati, Ohio. EPA Contract No. 68-03-2567. October 1981. p. 44.
47. .Reference 46, p. 73.
48. Hunter, S.C. and S.C. Cherry. (KVB.) NO Emissions from Petroleum
Industry Operations. Washington, D.C. API Publication No. 4311.
October 1979. p. 83.
49. U.S. Environmental Protection Agency. Evaluation of PCB Destruction
Efficiency in an Industrial Boiler. Research Triangle Park, North
Carolina. Publication No. EPA-600/2-81-055a. - April 1981. pp. 4 - 10,
117 - 128.
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50. U.S. Environmental Protection Agency. Emission Test Report on
Ethylbenzene/Styrene. Amoco Chemicals Company (Texas City, Texas).
Research Triangle Park, N.C. EMB Report No. 79-OCM-13. August 1979.
51. U.S. Environmental Protection Agency. Emission Test Report. El Paso
Products Company (Houston, Texas). Research Triangle Park, N.C.
EMB Report No. 79-OCM-15. April 1981.
52. U.S. Environmental Protection Agency. Emission Test Report. USS
Chemicals (Houston, Texas). Research Triangle Park, N.C.
EMB Report No. 80-OCM-19. August 1980.
53. Reference 50.
54. Reference 51.
55. Reference 52.
56. Key, J.A. (IT Enviroscience.) Control Device Evaluation Catalytic
Oxidation. In: U.S. Environmental Protection Agency. Organic Chemical
Manufacturing, Volume 4: Combustion Control Devices. Research Triangle
Park, N.C. Publication No. EPA-450/3-80-026. December 1980. Report 3.
p. 1-1.
57. Reference 1, p. 32.
58. Kenson, R.E. Control of Volatile Organic Emissions. MetPro Corp.,
Systems Division. Bulletin 1015. Harleysville, Pennsylvania.
59. Reference 56.
60. Reference 56.
61. Phthalic Anhydride Emissions Incinerated Catalytically. Chemical
Processing. 45(14):94. December 1982.
62. Blackburn, J.W. (IT Enviroscience.) Control Device Evaluation Thermal
Oxidation. In: U.S. Environmental Protection Agency. Organic Chemical
Manufacturing, Volume 4: Combustion Control Devices. Research Triangle
Park, N.C. Publication No. EPA-450/3-80-026. December 1980. Reports 1
and 2. pp. IV-1, V-l.
63. Pohl, J.H. (Energy and Environmental Research Corporation). Evaluation
of the Efficiency of Industrial Flares: Test Results. (Prepared for the
U.S. Environmental Protection Agency.) Research Triangle Park, N.C.
Publication No. EPA-600/2-84-095. May 1984.
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5. MODIFICATIONS AND RECONSTRUCTIONS
The reactor processes NSPS affects new reactor process units and
existing reactor process units that have been modified or reconstructed (in
accordance with the Code of Federal Regulations Title 40, Sections 60.14 and
60.15; 40 CFR 60.14 and 60.15). An existing facility is defined in
40 CFR 60.2 as a facility of the type for which standards of performance have
been promulgated and the construction or modifications of which has begun
prior to the proposal date of the applicable NSPS standards. This chapter
identifies typical or possible changes to reactor processes in synthetic
organic chemical manufacturing plants that could be deemed modifications or
reconstructions.
5.1 MODIFICATION
"Modification" is defined in 40 CFR 60.14(a) as any physical or
operational change of an existing facility that increases the emission rate
of any pollutant to which a standard applies.1 Exceptions to this definition
are presented in paragraph (e) of Section 60.14. These exceptions are:
1. Routine maintenance, repair, and replacement;
2. An increase in the production rate not requiring a capital
expenditure as defined in Section 60.2(bb);
3. An increase in the hours of operation;
4. Use of an alternative fuel or raw material if prior to the standard
the existing facility was designed to accommodate that alternate
fuel or raw material;
5. The addition or use of any system or device whose primary function
is the reduction of air pollutants, except when a system is removed
or replaced by a system considered to be less efficient; and
6. Relocation or change in ownership.
If any modification is made to the operation of an existing facility
that results in an increased emission rate for each pollutant to which a
standard applies, the facility becomes an affected facility under the
provisions of Section 60.14.
The reactor process affected facility is defined as the recovery system
and all reactors that discharge their vent streams into that recovery system.
Such a recovery system could consist of an individual series or train of
reactor process recovery equipment along with all reactors feeding vent'
streams into this equipment train. Each reactor not feeding vent streams
into a recovery system would constitute a separate affected facility.2
5-1
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5.2 RECONSTRUCTION
Under the provisions of Section 60.15, an existing facility becomes an
affected facility upon reconstruction, regardless of changes in pollutant
emission rates.3 Reconstruction is considered to occur upon the replacement
of components in the facility if the fixed capital cost of the new component
exceeds 50 percent of the fixed capital cost that would be required to
construct a comparable entirely new facility to comply with the applicable
standards of performance. The final judgment on what replacement constitutes
reconstruction and when it is technologically and economically feasible to
comply with the applicable standards of performance is made by the
Administrator. The Administrator's determinations "are made on the following
bases:
1. Comparison of the fixed capital costs of the replacement components
and a newly constructed comparable facility;
2. Comparison of the estimated life of the facility after the
replacements and the life of a comparable entirely new facility;
3. The extent to which the components, being replaced cause or
contribute to the emissions from the facility; and
4. Any economic or technical limitations on compliance with applicable
standards of performance that are inherent in the proposed
replacements.
The purpose of this provision is to prevent an owner or operator from
perpetuating an existing facility by replacing all but vestigial components,
support structures, frames, housing, etc., rather than totally replacing the
facility in order to avoid applicability to an NSPS. In accordance with
Section 60.5, EPA will, upon request, determine if the action taken
constitutes construction (including reconstruction).
5.3 EXAMPLES OF MODIFICATIONS AND RECONSTRUCTIONS AT EXISTING
REACTOR FACILITIES
5.3.1 General Examples
Suppose a hypothetical chemical plant is producing chemical Y in an
existing reactor facility consisting of three reactors all with vent streams
routed to a common recovery system. To accommodate increased demand for
chemical Y, the owners decided to add a fourth reactor to the facility and
duct the additional vent stream to the existing recovery system. The VOC
emissions from the added reactor and the existing reactors (i.e., the total
discharge from the existing recovery system) would be subject to the
provisions of the standard if the existing facility emissions increased as a
result of the operation of the additional reactor (constituting a
modification). Likewise, if one of the three existing reactors was replaced
with a new larger reactor, the VOC emissions discharged from the common
recovery system would also be subject to the standards if emissions increased
(constituting a modification). If the capital cost of the replaced
components - in this case, one larger-sized reactor - was greater than
50 percent of the cost of a new facility (i.e., 50 percent of the cost of an
entirely new facility composed of three reactors and the recovery system),
5-2
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the larger reactor could constitute a reconstruction and all reactors would
become affected. If a company chooses to retire antiquated reactors at an
existing facility and replace them with entirely new reactors venting to the
existing recovery system at the same site, this change could constitute a
reconstruction if the capital cost of replacement exceeds 50 percent of a new
facility cost.
5.3.2 Specific Examples
The general types of modifications and reconstructions that are most
likely to occur at existing facilities are feedstock or reactant substitution
where the facility was not designed to use that feedstock or reactant,
reactor additions, process and/or equipment changes, and combinations of the
above. Individual reactor replacements at multiple reactor facilities are
not expected to occur since reactors are generally designed to last the
lifetime of the process unit. If reactors at multiple reactor facilities are
replaced it is expected that all will be replaced at the same time in order
to accommodate a process change or because of fires or explosions.
If any of these examples results in the VOC emissions increasing from
the existing facility, this would constitute a modification. However, if
components of an existing facility are replaced and the costs of the
replacement components exceed 50 percent of the cost of a new facility, it
could be considered a reconstruction even if an emissions increase did not
occur.
Feedstock and reactant substitution is dictated^by economics and by the
availability of a substitute feedstock or reactant. Over 50 percent of the
173 chemicals considered can be manufactured from two or more different
feedstocks.1* For example, cyclohexanone can be manufactured using either
phenol or cyclohexanol as the feedstock. Although use of cyclohexanol has
predominated in the industry in the past, at least one facility in the
EDP has changed from using cyclohexanol to phenol. This feedstock
substitution required the addition of a hydrogenation section to the existing
cyclohexanone reactor system. As this example illustrates, a feedstock or
reactant change may result in a significant alteration to process equipment.
If equipment is replaced to accommodate the new feedstock and .if substantial
capital investment is required (more than 50 percent of the cost of an
entirely new facility), this may be considered a reconstruction regardless of
any change in emissions.. Depending upon the specific process, if an
alteration of a reactor process to accommodate the new feedstock causes an
increase in emissions from the existing facility, the change constitutes a
modification. If, however, the existing facility was designed to accommodate
the substituted feedstock, even though emissions increase at the existing
facility, a modification has not occurred. (See Section 5.1, exception (4).)
Another type of feedstock substitution includes changing from a
relatively pure high grade feedstock (e.g., high purity ethylene) to a lower
grade feedstock (e.g., low purity ethylene). Lower grade feedstocks
generally have higher concentrations of dissolved gases that may volatilize
5-3
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within a reactor and become a source of increased VOC emissions from that
reactor. As in the above example, this type of feedstock substitution may be
considered a modification unless it could be shown that the existing facility
was designed for the lower grade feedstock. Because this type of feedstock
substitution is generally expected to require neither process equipment
replacements nor substantial capital expenditure, it is not generally
expected to be considered a reconstruction.
Process equipment changes may constitute a modification depending on
whether or not an emissions increase occurs. Process equipment changes may
constitute a reconstruction depending upon whether or not the cost exceeds
50 percent of the cost of an entirely new facility. Examples of process
equipment changes include increasing the process unit capacity by adding more
reactors or by alteration of an existing recovery system (e.g., replacing an
absorber or changing from an absorber to a condenser). Based on a survey of
chemical plant construction summaries for the last 5 years, a relatively
large number of capacity expansions are expected to occur.5 If a larger
reactor replaces an existing reactor for the capacity expansion, and if the
replacement reactor vent stream is ducted to the existing recovery system, it
is expected emissions will increase which will constitute a modification. On
the other hand, whether or not emissions increase, if the cost of the
replacement reactor exceeds 50 percent of the cost of a new facility, it
may be considered a reconstruction. Capacity expansions may also be made by
the construction of additional reactors whose vent streams may be ducted to
the existing recovery system. If existing facility's VOC emissions increase,
this constitutes a modification. In general, the addition of reactors is
expected to be the most widespread method used to expand the capacity of
existing reactor process facilities, and when this occurs an emissions
increase is expected to occur.6
5.4 REFERENCES
1. Code of Federal Regulations.
60.14.
2. Reference 1.
Title 40, Chapter I, Subpart A, Section
3. Code of Federal Regulations. Title 40, Chapter I, Subpart A, Section
60.15.
4. Memorandum from Fidler, K. K., Radian Corporation, to L. B. Evans, EPA.
July 6, 1983. Identification of chemical production routes and unit
processes expected to be used in the future to manufacture the
176 chemicals considered in the Carrier Gas (Reactor Process) Project.
5. CE Construction Alerts. Chemical Engineering. 90: 80-81. April, 1983.
89:128-129. May, 1982. 88:152-155. April, T381. 87:134-136. April,
1380. 86: 96-98. March, "1779. ~~
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6. Memorandum from Pandullo, R. F., Radian Corporation, to Reactor Processes
NSPS Files. May 21, 1985. Examination of reactor replacements at
reactor processes facilities.
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6. REGULATORY ANALYSIS
This chapter describes the regulatory alternatives developed for an
analysis of a potential NSPS for reactor processes. The method used to
select these alternatives and the procedures used to analyze them are
described in this chapter. The environmental and energy impacts, and the
cost impacts associated with each regulatory alternative are presented and
discussed in Chapters 7 and 8, respectively.
In general, the regulatory alternatives examine the use of combustion
devices to reduce VOC emissions from new, modified, and reconstructed
reactor process units projected to come on-line between 1985 and 1990.
Excluded from this analysis are all reactor process units considered under
the proposed air oxidation NSPS (48 FR 48932). The use of combustion
devices as control techniques is examined by considering the cost
effectiveness, or TRE of control, associated with the application of
combustion devices to individual process units. The TRE is a concept that
has been applied previously to analyze regulatory alternatives for air
oxidation processes and for distillation operations. In general, the same
approach is used here, and as described later in this chapter, a TRE (or
cost effectiveness) cutoff value constitutes a regulatory alternative.
Section 6.1 presents a discussion of the basic assumptions and general
framework associated with the regulatory analysis and Section 6.2 identifies
the VOC control techniques considered under each regulatory alternative.
Section 6.3 describes the individual reactor process units considered as
candidates for the addition of VOC controls and describes how VOC controls
are applied to these process units under the regulatory alternatives.
6.1 OVERVIEW OF THE REGULATORY ANALYSIS
The Clean Air Act (CAA) directs EPA to develop standards of performance
for categories of new stationary sources of air pollution. A priority list
of source categories has been prepared for which standards must be
considered.1,2 Typically, the listed source categories are limited to
single industries that utilize one or two processes to manufacture specific
products. For such a case, one or more model plants are generally designed
to illustrate the emissions and control device requirements of typical new
.sources within that industry. Projections of new emission sources for these
model plants are made and then used to analyze the economic, energy, and
environmental impacts of the regulatory alternatives. The regulatory
alternatives are generally based on the use of several applicable control
devices that may have different control efficiencies, costs, and energy
requirements. The results of such a regulatory analysis permit selection of
6-1
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a regulatory alternative that reflects the greatest emissions reduction
achievable (considering costs) through application of the BDT for continuous
emission reduction. The selection process also includes consideration of
any nonair quality health, environmental, and energy impacts.
The traditional model plant approach described above is not used here
because of the large number of different reactor processes involved in this
source category and the complexity and diversity of the SOCMI. The
development and analysis of individual regulatory alternatives requiring
different control technologies and emission levels for each of the chemicals
and reaction types considered would be unreasonably time-consuming and
resource-intensive.
The approach used here is to develop regulatory alternatives based on
applying controls that have the potential to provide the basis for selecting
BDT for new, modified, and reconstructed reactor process units. In
Essex Chemical v. Ruckleshaus,3 BDT was defined as follows: "An adequately
demonstrated system is one which has been shown to be reasonably reliable,
reasonably efficient and which can reasonably be expected to serve the
interests of pollution control without becoming exorbitantly costly in an
economic or environmental way." In this analysis, control systems are
selected that are "reasonably reliable" and "reasonably efficient" while the
"economic and environmental costs" are examined through the use of various
regulatory alternatives.
Control technologies used in the SOCMI are discussed in Chapter 4.
Combustion is the control technology chosen for the regulatory analysis
since it meets the criteria set forth by the court and is applicable to all
reactor process vents. Other types of controls, such as condensers,
absorbers, and adsorbers can be used on individual reactor process units,
but their application is so site-specific that they cannot be analyzed under
a generic standard approach (i.e., applied to broad categories of reactor
processes for analysis). Furthermore, combustion devices achieve higher VOC
control efficiency than all other currently demonstrated control
technologies at a reasonable cost. Boilers, process heaters, flares,
thermal incinerators, and catalytic oxidizers are the five major types of
combustion devices. As noted in Chapter 4, all are capable under certain
conditions of achieving at least 98-weight-percent reduction of VOC
emissions.
6.2. SELECTION OF TH£ COMBUSTION CONTROL TECHNIQUES USED IN THE
REGULATORY ANALYSIS
As mentioned in Chapter 3, reactor process vent streams may contain
halogenated or nonhalogenated VOC. The distinction between these two
classes of vent streams is important in the choice of a VOC control
technology. As indicated in the previous section and discussed in
Chapter 4, emission reductions of 98-weight-percent are possible with five
types of combustion controls (boilers, process heaters, catalytic oxidizers,
flares, and incinerators). For nonhalogenated streams, any of these
controls may be generally applicable, but for halogenated streams, only
incinerators are applicable.
. 6-2
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In this regulatory analysis, for each process unit in either class of
vent stream (halogenated or nonhalogenated), the control technology that is
least expensive, at least 98-weight-percent efficient, and applicable for
the process unit is selected, and the cumulative industry impacts are summed
over all process units. For halogenated vent streams, the least expensive,
98-weight-percent efficient, and applicable control technology is an
incinerator with flue gas scrubbing. For nonhalogenated streams, a flare
may achieve the same (98-weight-percent) efficiency as any other combustion
control. Furthermore, flares are usually less expensive than incinerators
although for some streams (high flow and low heating value) this is not
always the case. For this reason, both flares and thermal incinerators are
considered applicable to nonhalogenated vent streams, and the cost of both
is considered when analyzing the regulatory alternatives. Boilers, process
heaters, and catalytic oxidizers, are not applicable to many types of
reactor process vent streams; stream-specific characteristics could reduce
their VOC reduction efficiency or applicability. Therefore, these devices
are not included in the regulatory analyses because their use in industry is
not possible to predict consistently. In actual practice any device that
achieves a 98-weight-percent VOC emission reduction may be used. For this
regulatory analysis of the overall impact of VOC controls on the reactor
processes portion of the SOCMI flares and incinerators are selected because
they are 98-weight-percent efficient and most broadly applicable to reactor
processes.
Although flares and incinerators have been selected as the control
technology applicable to all reactor processes, they may not be the most
cost-effective application in all cases. Because process vent stream
characteristics vary widely, both the control cost per unit emissions
reduction and the environmental impacts of applying these controls may also
vary widely. Therefore, it is possible that for some process units the cost
of applying controls would be so.large and the emission reduction so small
that flares and incinerators may not be cost effective.1* The possibility of
not requiring combustion for some reactor process units is consistent with
Section 111 of the CAA, which permits distinction among classes, types, and
sizes within source categories when establishing control requirements with
an NSPS.5 In addition, such an analysis for the similar distillation and
air oxidation standards showed that some streams were not cost effective to
control.
6.3 DEVELOPMENT OF REGULATORY ALTERNATIVES
6.3.1 Introduction and Summary
Regulatory alternatives are selected to examine the environmental,
energy, and cost impacts associated with applying thermal incinerators and
flares to control VOC emissions from new, modified, and reconstructed
reactor process units. The reactor process units examined include:
(1) units that are projected to be newly constructed during the 5-year
period following proposal of the NSPS (1985-1990), and (2) existing units
that are projected to be modified or reconstructed during the same time
frame. In the regulatory analysis, TRE values are determined for each of
6-3
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these two types of process units. For an individual process unit, the TRE
value is the annual cost of combustion control divided by the annual
emission reduction. Because each process unit is likely to have a different
TRE value, a range of values exists for the set of new, modified, and recon-
structed process units examined. Regulatory alternatives are defined by
specific TRE cutoff values. An analysis of each alternative is accomplished
by adding the impacts associated with all process units having TRE values at
or below the TRE cutoff for that specific alternative.
The remainder of this chapter presents a detailed discussion of the
regulatory alternatives. First, a general process unit description is
presented and the projected number and capacity of new, modified, and
reconstructed reactor process units are identified and discussed briefly.
Second, the estimated process vent stream characteristics for each of these
units are presented and discussed in more detail. Finally, the assumptions
used in applying VOC controls to individual process units to form regulatory
alternatives are discussed.
6.3.2 Characteristics of the New, Modified, and Reconstructed Reactor
Process Units Included in the Regulatory Analysis
This section describes the reactor process units included in the
regulatory analysis. The number, type, and capacity of all new, modified,
and reconstructed process units included in the regulatory analysis are
identified and the process vent stream characteristics associated with each
are presented. A general description of a process unit is also presented as
discussed in the next section.
6.3.2.1 General Process Unit Definition and Description. As described
in Chapter 5, a process unit is defined as one or more combinations of
reactors and product recovery systems each manufacturing the same organic
compound at a common site. In the regulatory analysis, various regulatory
alternatives are examined by estimating the impacts of those alternatives on
individual reactor process units. It should be noted that a reactor process
unit is not necessarily the same as a reactor affected facility; and that
under an NSPS, it is the reactor facility that is subject to the provisions
of the standards and may be required to control VOC emissions. The
significance of the use of process units in this analysis is discussed
below.
Process units, not reactor facilities, are used in this regulatory
analysis because the information available to project the number and
capacity of units lends itself to the process unit projections and not to
individual reactor facility projections. Because it is possible that a
small number of process units may contain more than one reactor facility,
some simplifying assumptions were made for the purpose of conducting the
regulatory analysis. Where multiple reactor facilities may exist within a
single process unit, the vent streams from each facility within that unit
are assumed to be combined and routed to a common point. Therefore, when
combustion devices are applied to process units that may contain multiple
6-4
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reactor facilities, only one combustion device is assumed to be used to
control the combined vents from all facilities. In order to use realistic
estimates of the actual cost of VOC combustion controls, the TRE calculation
is based upon the less costly control (due to economies of scale) of the
combined vent streams from all reactor facilities within a process unit,
rather than control of each reactor facility by multiple combustion control
devices. The additional cost incurred for a duplication of reactor facility
control devices would be especially large for halogenated vent streams
requiring incineration and offgas scrubbing.
As indicated in Chapter 3, some reactor process units in the EDP have
no process vents to the atmosphere. In addition, some process units with
vents currently use combustion devices as a result of existing VOC
regulations or industrial practices. The regulatory analysis examines the
addition of controls only to those new, modified, and reconstructed reactor
process units projected to have process vents that are currently not
combusted. As discussed later, these projections are based on information
contained in the EDP. Process units manufacturing chemicals where reactor
vents are currently combusted are assumed to continue to apply combustion
devices in the absence of an NSPS (i.e., combustion control is also applied
to new, modified, and reconstructed units making these chemicals at the
baseline level). Emissions from process units that use combustion devices
at baseline will be included in the emission estimates presented in
Chapter 7 and are discussed in Chapter 3.
6.3.2.2 Number, Type, and Capacity of Process Units. This section
describes the estimated number and capacity of process units that are
projected to be built between 1985 and 1990 to accommodate industry growth
and replacement trends in the reactor processes industry. Also presented is
a description of the three types of process units that might be added to
existing industry capacity.
Process units are projected to be newly constructed, modified, or
reconstructed over the first 5 years of the standards' applicability
(1985-1990) for two reasons. First, new process units may be built, and
existing process units may be expanded - each in response to increased
demand for specific chemicals. Secondly, a number of existing process units
may be retired and then replaced, as they reach their estimated useful life
of .20 years.
New process units may be grassroots units while capacity expansions at
existing process units could be new or modified process units. Capacity
expansions are assumed to occur at existing process units primarily by:
(1) adding one or more reactors or increasing the size of existing reactors
at an existing facility or, (2) adding one or more completely new and
independent facilities in parallel to existing reactor facilities. The
second example of capacity expansions are considered to be new reactor
facilities. In the first example of capacity expansions, the addition of a
combustion device under a regulatory alternative would result in the control
of VOC emissions from both the new and existing reactors because they are
6-5
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part of the same affected facility (i.e., they are assumed to share a common
product recovery device). However, emission reductions from these existing
reactors are not included in the regulatory analysis. This is because of
the uncertainty associated with predicting specifically which existing
process units will be expanded and, subsequently, with predicting the total
amount of emissions that may be controlled from those existing sources. .
Therefore, emission reductions associated with modified process units may be
underestimated in Chapter 7.
The reconstructed (or replacement) process units may include:
(1) process units that have some of their components replaced such that the.
cost of each replacement at each reactor facility within the process unit
exceeds 50 percent of the cost of a new reactor facility or, (2) process
units that are completely replaced. As discussed in Chapter 5, where
multiple reactors constitute an affected facility, replacement of individual
reactors are not expected to occur very often such that the cost of
replacement does not exceed 50. percent of the cost of a new facility. For
those process units that have replaced components as described in (1)., it is
assumed that the addition of combustion controls under a regulatory
alternative will result in the control of emissions from all reactor
facilities within the process unit. Therefore, for process units that have
replaced components and that may contain more than one existing reactor
facility, it is assumed that all reactor facilities within that process unit
are replaced. The replacement process units discussed in (2) are
replacements of the antiquated existing process units, these replacements,
whether at the site of the previously existing process unit or elsewhere,
would be considered new facilities under an NSPS.
Based on market demand for specific chemicals and on process unit
lifetimes, 56 new, modified, and reconstructed reactor process units with
uncombusted vent streams are projected to come on-line over the first
5 years of the standards' applicability. These 56 process units are
considered as candidates for the addition of VOC controls in the regulatory
analysis. Estimates of the production capacity for each of these units are
presented in Table 6-1. The following describes the assumptions used in
developing the capacity projections.
Projections of production in 1985, the first year of the standards, are
made in Section 9.1.6 and are used along with projected growth rates to
predict production in 1990. This production figure and an assumed industry-
wide capacity utilization rate of 85 percent generate the amount of total
industry capacity needed in 1990 for each chemical potentially affected by
the standards. In order to determine if any additional capacity is needed
to accommodate this growth, estimates of existing capacity in 1985 and the
amount of capacity expected to be retired in the 1985 to 1990 period are
made. Capacity is required in 1990 when existing 1985 capacity, less the
amount of capacity retired, is less than the total industry capacity needed
in 1990 to accommodate projected 1990 production at the 85 percent
utilization rate. This calculation does not distinguish between capacity
6-6
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TABLE 6-1. SUMMARY OF NEW, MODIFIED, AND RECONSTRUCTED
REACTOR PROCESS UNIT CAPACITIES
Process Unit Capacity
Chemical Name
Adipic acid
Benzyl chloride
Butyl acrylate
n-Butyl acetate
t-Butyl alcohol
t-Butyl hydroperoxide
Chlorobenzene
p-Chl oroni trobenzene
Cyanuric chloride
Di ace tone alcohol
Di ethyl benzene
2,4-(and 2,6)-Dinitrotoluene
2,4-Dinitrotoluene
Ethyl acetate
Ethyl acrylate
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
Methyl methacrylate
Nitrobenzene
1-Phenyl ethyl hydroperoxide
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl trichloride
69
236
36
35
23
5
11
68
18
18
7
18
17
80
15
40
318
204
206
95
153
18
18
322
18
193
45
106 Ib
520.0
79.4
77.2
50.7
11.0
24.3
150.0
39.7
39.7
15.4
39.7
37.5
176.0
33.1
88.1
701.0
450.0
454.0
209.0
337.0
39.7
39.7
710.0
39.7
425.0
99.2
Number of
Process Units
2
1
1
1
8
1
1
1
1
3
1
1
1
4
2
8
3
1
4
1
1
1
2
1
4
1
-------
required due to growth in demand and that required due to retirement of old
process units, but rather sums these dual effects to generate one amount.
Once the total amount of required capacity in 1990 is calculated, a
single process unit size is projected to be built to satisfy the
requirement. A single size is preferred due to the simplicity it implies,
and because more precise choices of multiple sizes are not supported by the
existing database. The single size chosen is the current median size for
each chemical, (Table 9-8) and all regulatory and economic impacts are
scaled to this median process unit size. The median size is divided into
the total amount of required capacity for each chemical, and if a remainder
exists, another full median-sized process unit is projected to be built.
Since the amount of required capacity is estimated based on exact
utilization rate of 85 percent, adding more capacity than needed will have
the effect of lowering the final capacity utilization in 1990 from
85 percent. This 85 percent figure therefore represents not the projected
utilization rate for 1990, but the rate at which a firm will decide to add
new capacity. Once the new capacity is added, (i.e., when projected
production grows larger than 85 percent of post-retirement available
capacity) then capacity utilization is anticipated to settle back down below
the 85 percent level.
The singular technique for projecting the size and number of process
units does not attempt to classify the process units in terms of whether or
not they will be added to an existing facility or whether they will be
manifested in a modification or reconstruction of a currently operating
process unit. The level of precision of the existing database will not
support such exact calculations. However, by choosing the single size to be
the current median process unit size, a middle ground is reached on which to
calculate regulatory and economic impacts.
6.3.2.3 Vent Stream Characteristics. Costs of control for the 56 process
units are developed based on vent stream information (flow rates and heat
contents) contained in the EDP, described in Appendix C. The procedure used
here is as follows. Flow and VOC emission factors are first calculated for
each process unit in the EDP by dividing the vent stream flowrate and VOC
emission rate for each process unit by the process unit production capacity
associated with these rates. This allows vent stream characteristics to be
predicted for the 56 process units based on these "normalized" data from
the EDP. Flowrate factors (in standard cubic feet per million pounds of
production capacity), VOC emission factors (in pounds of VOC per million
pounds of production capacity) and heat content (in Btu per standard cubic
feet) from the EDP are used to calculate vent stream characteristics and
subsequently, VOC control costs for those plants included in the regulatory
analysis. This is done by multiplying the emission factor in Table 6-2
(derived from the EDP) by the process unit capacity in Table 6-1.
The data in Table 6-2 were taken from a more complete listing of vent
stream characteristics developed from the EDP for all chemicals projected to
have new, modified, or reconstructed process units built.6 Because data
6-8
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TABLE 6-2. SUMMARY OF NEW, MODIFIED, AND RECONSTRUCTED
REACTOR PROCESS UNIT VENT STREAM CHARACTERISICS
VO
Chemical Name
*
Adipic acid
Benzyl chloride
Butyl acrylate
n-Butyl acetate
t-Butyl alcohol
t-Butyl hydroperoxlde
Chlorobenzene
p-Chl oronitrobenzene
Cyanurlc chloride
Diacetone alcohol
01 ethyl benzene
2,4-(and 2,6)-Dinitrotoluene
2,4-Dinitrotoluene
Ethyl acetate
Ethyl acrylate
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
Methyl methacrylate
Nitrobenzene
1-Phenylethyl hydroperoxide
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl trichloride
Flow
(scf/10b Ib)
3,493,738
396,000
73,000
23,360
148,670
841,680
396,000
2,438,567
396,000
257,544
18,043
2,482,567
4,909,582
122,640
438,000
18,043
21,936,600
148,670
73,000
55,551
12,676,688
18,043
148,670
841 ,680
9,244
396,000
Heat Value
(Btu/scf)
0
40
102
102
0
217
0
217
40
1069
93
217
0
102
102
93
4
0
102
434
2
93
0
217
407
40
VOC Emissions
(lb/10B lb)
0
398
20
20
3
443
386
682
398
8906
42
682
10
146
594
42
3900
3
20
1353
1950
42
3
443
2
398
Halogenated
VOC
No
Yes
No
No
No
No
Yes
Yes
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
-------
are not available in the EDP for all the chemicals that may have new,
modified, or reconstructed process units built, different procedures are
used to choose representative emission factors when data are lacking in the
EDP. The three procedures used for all chemicals in the regulatory analysis
include: (1) the chemical specific method; (2) the chemical process method
(when chemical specific data are lacking); and (3) the median method (when
data for a specific chemical or its process are lacking).
As its name implies, the chemical specific method uses vent stream
information from actual process units in the EDP producing a particular
chemical. For example, in the case of-adipic acid, data are available from
three process units in the EDP. Therefore, chemical specific data from the
EDP can be used to estimate the vent stream characteristics of the adipic
acid process units included in the regulatory analysis. For many chemicals,
vent stream characteristics are available only from one unit in the EDP.
For these chemicals the one EDP unit data is used. If data are available
from two units in the EDP producing a particular chemical, the average vent
stream characteristics for these two are used. In cases where vent stream
information is available from three or more process units as in the case of
adipic acid, median values are used.
The chemical process method is used when the chemical process
associated with the production of a chemical is known, but chemical specific
information is not available in the EDP. For example, chloronitrobenzene is
a chemical produced by the chlorination process for which chemical specific
information is not available in the EDP. All of the information for chemicals
in the EDP produced by the same process is used to obtain representative
vent stream characteristics which are then applied to those process units
making chemicals where chemical-specific data are lacking in the EDP. As
with the chemical specific method, in cases where process specific data.is
available from only one process unit in the EDP, this data is used for the
process units using that process. Where data from two units is available,
the average of those vent stream characteristics is used. Finally, in cases
where information from three or more units is available, median values are
used.
The median method is used in cases where no information is available
for a specific chemical or its process in the EDP. This method incorporates
all data in the EDP and includes only one set of emission factors when
applied. The median method emission factors are simply the median of all
the chemical process method emission factors.
The same procedures discussed here for estimating vent stream
characteristics for the 56 process units are also used to estimate the
baseline emissions from process units making the 2.2 chemicals projected to
use combustion devices in the absence of an NSPS.7 These chemicals are
discussed in Chapter 3 (Section 3.4).
6-10
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6.3.3 Description of the Regulatory Alternatives
As previously mentioned, incinerators and flares have been selected as
candidates for determining BDT and, therefore, as the control techniques used
to analyze the regulatory alternatives. Although other combustion techniques
could be used on specific vent streams, flares and thermal incinerators are
chosen as BDT candidate for reactor process vent streams. Because facilities
required to control VOC emissions under this NSPS did not use VOC controls
previously, it is assumed for this regulatory analysis that all control
devices will be newly constructed. In the regulatory analysis, the least
expensive of an incinerator or a flare is applied to process units with vent
streams containing nonhalogenated VOC while incinerators with flue gas
scrubbing are applied to process units with vent streams containing halo-
genated VOC. This approach is consistent with their application in the
industry.8
In the regulatory analysis, VOC control costs are estimated for each
new, modified, and reconstructed process unit included in Table 6-1. Flare
or incinerator costs are based on the costing procedures described in
Chapter 8. TRE values are estimated for each process unit by dividing the
annual cost of control by the annual emission reduction achieved.
Incinerators and flares are assumed to achieve 98-weight-percent VOC
destruction. Once TRE values are estimated for each new, modified, and
reconstructed process unit, all process units are ranked by increasing TRE
values.
A regulatory alternative is defined by a specific TRE cutoff value.
Therefore, the proportion of all process units controlled under each
alternative varies with the TRE level considered. Because fewer reactor
process units would be controlled at lower TRE values, the range of
alternatives examined results in increasing numbers of new, modified, and
reconstructed reactor process units being controlled at higher TRE cutoff
values. Alternatives range from no additional, controls, i.e., the absence of
an NSPS (the baseline level described in Chapter 3), to the most stringent
alternative, which assumes combustion control is applied to all of the 56
new, modified, and reconstructed process units with uncombusted vent
streams. The range of TRE values between these two extremes are examined in
the regulatory analysis. Using results from the regulatory analysis, the
number and percent of process units controlled at selected TRE cutoff values
are presented in Table 6-3. These TRE levels span the range of regulatory
alternatives. The national environmental and energy impacts of each
alternative are presented and discussed in Chapter 7, and the national cost
impacts are presented and discussed in Chapter 8.
6-11
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TABLE 6-3. NUMBER AND PERCENTAGE OF PROCESS UNIT EXPECTED
TO BE CONTROLLED AT VARIOUS TRE LEVELS
Percentage of Process Number of Process
TRE, $/Mg Units Controlled Units Controlled
0 (Baseline) 0 0
1,200 7. 4
2,500 13. ' 7
5,500 16. 9
20,000 38. 21
50,000 59. 33
200,000 75. 42
500,000 82. 46
>500,000 100. 56
6-12
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6.4 REFERENCES
1. U.S. Environmental Protection Agency. Priority List and Additions to
the List of Stationary Sources. Final Rule. 44 FR 49222-49226,
August 21, 1979.
2. U.S. Environmental Protection Agency. Revisions to the Priority List of
Categories of Stationary Sources. 47 FR 950, January 8, 1982.
3. Essex Chemical v. Ruckleshaus. 486 F.2d 427 (D.C. Cir 1973).
Environment Reporter - Cases, Vol. 5, 1974.
4. U.S. Environmental Protection Agency. Office of Air Quality Planning
and Standards. Distillation Operations in Synthetic Organic Chemical
Manufacturing - Background Information for Proposed Standards. Research
Triangle Park, North Carolina. Publication Number EPA-450/3-83-005a.
December 1983. p. 6-5.
5. United States Congress, Clean Air Act, as amended August 1977.
42 U.S.C. et. seq. Washington, D.C. U.S. Government Printing Office.
November 1977.
6. Memorandum from Cassidy, M. A. and M. A. Baviello, Radian Corporation,
to Reactor Processes NSPS File. Emission Characteristics of the New,
Modified, and Reconstructed Reactor Processes Units Projected to Come
On-line Between 1985 - 1990. May 10, 1985.
7. Reference 6.
8. Memorandum from Read, B. S., Radian Corporation, to Reactor Processes
NSPS File. Combustion Controls Used in the Emission Data Profile.
May 29, 1985.
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7. ENVIRONMENTAL AND ENERGY IMPACTS
i
This chapter presents the impacts of the regulatory alternatives on
national VOC emissions and discusses other impacts on air quality, water
quality, solid wastes, and energy consumption. The analysis considers both
the impacts attributed directly to control devices (e.g., reduced VOC
emissions) and the indirect or secondary impacts (e.g., potential
aggravation of other pollutant problems through use of VOC control devices).
The emphasis of the assessment is on national incremental impacts of
successively more stringent regulatory alternatives.
Under the regulatory alternatives discussed in Chapter 6, combustion
controls are applied to varying proportions of new, modified, and recon-
structed reactor process units according to the TRE of control. TRE values
are a measure of the cost effectiveness of VOC control and are expressed as
the cost of control per unit of VOC emissions reduction. Incineration and
flaring are the combustion techniques used as the basis of the TRE
calculations.
7.1 INTRODUCTION
The analysis considers all process units projected to come on-line
during the 5-year period of July 1, 1985, to July 1, 1990. These
projections, which are discussed in Chapter 6 (see Table 6-1), include new
grassroots process units, capacity expansions at existing process units, and
all other process units that are modified or reconstructed. The circum-
stances that constitute new, modified, and reconstructed facilities are
discussed in Chapter 5.
VOC emissions from new, modified, and reconstructed reactor process
units may be generally divided into two categories for the purpose of this
regulatory analysis: (1) emissions from process units that are anticipated to
use combustion devices on their vent streams in the absence of an NSPS
and, (2) emissions from process units that are anticipated to use no combus-
tion devices on their vent streams in the absence of an NSPS. National
emissions for the first category of process unit emissions (from combusted
vent streams) will be the same as baseline under all regulatory alterna-
tives. The second category of process unit emissions (from uncombusted vent
streams) are uncontrolled at baseline and, therefore, have the potential to
be controlled by the application of combustion devices. Under a regulatory
alternative, combustion is applied to those uncombusted vent streams with
TRE values that fall within a range of value specified in the given
regulatory alternative. For example, an alternative may consist of the
control of all process units with TRE values between $0/Mg and $l,000/Mg.
7-1
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The VOC emissions reduction and other environmental and energy impacts
resulting from the control of these process units are calculated as
described below.
7.2 AIR POLLUTION IMPACTS
This section describes the methodology used to estimate VOC emissions
reductions and other air pollution impacts associated with the regulatory
alternatives. The pollution impacts presented in this section include the
estimated national VOC emissions under each regulatory alternative and the
emissions reduction compared to the baseline level. N0x emissions resulting
from the use of combustion control devices are also discussed.
7.2.1 Method of Estimating VOC Emissions and Emission Reductions
In this section, the methods of calculating emissions are discussed for
new, modified, and reconstructed process units with and without combustion
controls on the vent streams. Because the calculated TRE value for each
process unit is used to determine which process units will be controlled
under the various alternatives, this section also describes how the TRE is
calculated for an individual new, modified, or reconstructed process unit.
For the first group of process units (with combustion controls at
baseline), vent streams are assumed to be controlled with combustion devices
under all regulatory alternatives. Similar process units for these chemicals
are currently combusted under existing industry practice or as a result of
existing State or Prevention of Significant Deterioration regulations. It is
assumed that combustion of the vent streams from these chemical reactor
processes will not change in the future. Therefore, nationwide VOC emissions
for these chemicals under all regulatory alternatives are the same as
emissions under the baseline alternative. Uncontrolled emissions for each
process unit are calculated by multiplying the predicted volume of 1990
production for specific chemicals projected to use combustion in the absence
of an NSPS (Section 9.1.2.2), by an emission factor that is derived for each
chemical, expressed in terms of kilograms of VOC emitted per megagram of
chemical produced (pounds of VOC emitted per million pounds of chemical
produced).1,2 Assuming the combustion devices applied will achieve
98-weight-percent destruction, the uncontrolled emissions are multiplied by
0.02 to yield controlled emissions. Emissions for all chemicals are summed.
For the second group of process units (without combustion controls),
vent streams are not projected to be combusted under existing regulations and
industry practices. The following three-step approach is used to estimate
these VOC emissions under each regulatory alternative. (1) For a single
process unit, uncontrolled VOC emissions are calculated by multiplying the
estimated production at the this process unit by an uncontrolled
chemical-specific emission factor derived from the EDP. All emissions are
calculated assuming a 77 percent capacity utilization of the particular
process unit under examination. This is consistent with the capacity
utilization used to determine annualized control costs for each unit (see
Chapter 8). The sum of the emissions for each reactor process unit
7-2
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constitute the uncombusted vent stream contribution to the baseline
emissions. This portion of baseline emissions may be potentially reduced
under an NSPS. (2) A TRE value is calculated to determine whether this
process unit will be required to reduce emissions by 98-weight-percent under
a given regulatory alternative. For vent streams containing nonhalogenated
VOC, the TRE calculated is based on the less costly of a flare or an
incinerator. For vent streams containing halogenated VOC, the TRE is
incinerator is based. A scrubber is used on the incinerator flue gas to
remove corrosive by-products that result from the combustion of halogenated
VOC. If a process unit can apply incineration or flaring at a TRE value that
is within the range of values specified for that alternative, it is assumed
to combust the vent stream. (3) If combustion is applicable under a given
alternative as defined in step (2), a controlled emission factor is estimated
assuming 98 percent destruction of the VOC in the vent stream. Otherwise, an
uncontrolled emissions estimate, as defined in step (1), is used for that
alternative.
The following discussion reviews the method of calculating TRE values,
which are used to determine if individual process units are controlled under
the regulatory alternatives. A TRE is calculated for each of the 56 new,
modified, and reconstructed process units considered here. As discussed
earlier, the TRE is the ratio of the annualized VOC control cost to the
associated emissions reduction. The costs of applying incineration or
flaring to individual process units are estimated using both the incinerator
and flare cost algorithms discussed in Chapter 8 and the capacity and
process vent stream characteristics presented in Chapter 6. Uncontrolled
emissions for each new, modified, and reconstructed process unit are
estimated from the vent stream characteristics presented in Chapter 6, and
potential emissions reductions are determined assuming 98 percent destruc-
tion of this uncontrolled VOC.
7.2.2 VOC Emissions Impacts
The primary environmental impact of the regulatory alternatives is the
reduction of VOC emissions from reactor processes. The total VOC emissions
from all new, modified, and reconstructed process units under baseline is
estimated to be approximately 3,300 Mg/yr (3,600 tons/yr) in 1990. About
2,400 Mg/yr (2,600 tons/yr) of these VOC emissions are from process units
with vent streams where combustion is not projected to be used at baseline;
while about 910 Mg/yr (1,000 tons/yr) of these VOC emissions are emitted from
the outlets of combustion devices projected to be used at baseline. Thus, a
maximum of 98 percent of 2,400 Mg/yr or approximately 2,300 Mg/yr
(2,600 tons/yr) of VOC is available to be controlled under regulatory
alternatives more stringent than baseline.
Tables 7-1 and 7-2 present the total VOC emissions and the VOC emissions
reductions achieved at various regulatory alternatives. For a particular
regulatory alternative, the reduction over baseline is the the difference
between VOC emissions at the baseline level and VOC emissions under that
particular regulatory alternative. The numbers of new, modified, and
reconstructed process units controlled by combustion are also shown. The
7-3
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TABLE 7-1. ENVIRONMENTAL AND ENERGY IMPACTS OF THE
REGULATORY ALTERNATIVES (Metric Units)8
i
.£»
Average Boundary Number of National VQC
1 tentative TRE for . TRE Units Controlled Emissions0
Number Alternative" Values Over Baseline (Mg/yr)
($/Mg) ($/Mg)
National Emission Percent of
Reduction Over Controllable .
Baseline Emissions Reduced
(Mg/yr)
National Energy
Impacts
Over Baseline
(TJ/yr)
I Basel 1nef 0
II
III
IV
V
VI
VII
VIII
IX
500
1,700
1,800
2,100
2,900
3.200
3,500
4,000
0
1,200
2,500
5.500
20,000
50,000
200,000
500,000
>500,000
- .
4
7
9
21
33
42
46
56
3,300
3,000
1,150
1,100
990
960'
960
960
960
.
300
2,100
2,100
2,300
2,300
2,300
2,300
2.300
_
13
90
91
97
100
100
100
100
.
3
320
340
390
430
440
450
520
([Calculated for the fifth year of the NSPS, 1990, in 1982 dollars.
TRE, or total resource effectiveness, Is the cost ($) per megagram (Mg) of VOC emissions removed. Average TRE calculated as
Cnat1onal annual cost/national emissions reduction over baseline.
New, modified, or reconstructed (replacement) process units considered In the analysis of those estimated to come on-line
dbetween 1985 and 1990.
Controllable emissions are the 2,400 Mg/yr that would be controlled at 98 percent VOC destruction efficiency (I.e., at the most
estr1ngent possible alternative, Alternative IX).
fEnergy Impacts Include both fuel (natural gas) and electricity use and any heat recovery credits.
Baseline emissions Include emissions from process units with combusted (controlled) vent streams and those with uncombusted
(uncontrolled) vent streams.
-------
I
en
TABLE 7-2. ENVIRONMENTAL AND ENERGY IMPACTS OF THE
REGULATORY ALTERNATIVES (English Units)3
Average Boundary
Alternative TRE for . TRE
Number Alternative" Values
($/Ton) ($/Ton)
I Basel 1nef 0
II
III
IV
V
VI
VII
VIII
IX
450
1,600
1,600
1,900
2.600
2.900
3,200
5.700
0
1,100
2,300
4.500
18,000
45,000
180,000
450,000
> 4 50, 000
liniJrfnnf^ii A Nat onal V8° National Emission Percent of National Energy
Units Controlled Emissions0 Reduction Over Controllable . Impacts
Over Baseline0 (Ton/yr) Baseline* Emissions Reduced" Overlaseline8
]*cement} ^rocess units considered in this analysis are those estimated to come on-line
ft6*1"5 5'!S t0n!/yr ,that Wou1d te controlled if all 56 units were controlled at 98 percent VOC
r«w ™ i •?" 5* ?** "°st Str1n9ent possible alternative. Alternative IX).
frgy Impacts Include fuel and electricity use and any heat recovery credits.
fr°" Pr°CeSS U"US WUh combusted (controlled) vent streams and those with uncombusted
-------
most stringent alternative assumes combustion control is applied to all new,
modified, and reconstructed process units. Under this alternative a national
VOC emissions reduction of 80 percent over baseline, or approximately
2,300 Mg/yr (2,600 tons/yr), occurs.
7.2.3 Other Effects on Air Quality
Combustion processes may produce secondary emissions, particularly
nitrogen oxides (NO ). However, overall impacts of the regulatory alterna-
tives are expected to be relatively small because NO emission concentrations-
from incinerators and other combustion devices are generally low. Data
characterizing N0x emissions from incinerators are presented below.
The principal factors affecting the rate of NO formation during
combustion are the amount of excess air available, She peak flame
temperature, the length of time that the combustion gases are at peak
temperature, and the cooling rate of the combustion products.3 Test
data show that incinerator outlet concentrations of NO from a toluene
diisocyanate process unit in the EDP were about 84 ppmv.1* Testing at a
polymer and resin process unit using an incinerator for VOC control measured
N0x concentrations ranging from 20.2 to 38.6 ppmv.5 The fuels tested were
mixtures of natural gas, waste gas, and/or atactic waste; incineration
temperatures ranged from 980 to 1,100°C (1,600 to 2,000°F). In a series of
seven sets of tests conducted at three air oxidation process units,
incinerator outlet N0x concentrations ranged from 8 to 200 ppmv.6 These
values could increasexby several orders of magnitude in a poorly designed or
operated unit. Although there are conflicting data, some studies report
that incineration of vent streams containing high levels of nitrogeneous
compounds may also result in increased N0x emissions.7 In these studies, the
maximum outlet N0x concentration measuredxfrom a combustion device at a
acrylonitrile (air oxidation) process unit, with a vent stream containing
nitrogenous compounds, was 200 ppmv.8 The N0x concentrations measured at the
first four process units discussed above, where the vent streams do hot
contain nitrogeneous compounds, range from 8 to 84 ppmv.9
An alternative combustion technique used in the regulatory analysis is
flaring. N0x concentrations were measured at two flares used to control
hydrocarbon emissions from refinery and petrochemical processes. One flare
was steam-assisted and the other air-assisted, and the heat content of the
fuels ranged from 5.5 to 81 MJ/scm (146 to 2,183 Btu/scf). The measured N0x
concentrations were somewhat lower than those for incinerators, ranging from
0.4 to 8.2 ppmv. The ranges of relative NO emissions per unit of heat input
are 7.8 to 90 g/GJ (0.018 to 0.208 lbs/106 8tu) for flares.10
Although incinerators and flares were examined as combustion techniques
in the regulatory analysis, process heaters may be applicable in some cases
for combustion control. No N0x data were available for process heaters used
on reactor vent streams; however, most of these process heaters would use
natural gas as a primary or supplemental fuel. Data on N0x emissions from
gas-fired process heaters show an average NO concentration of about 76 to
138 ppmv. In general, mechanical draft heaters with preheating emitted more
7-6
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N0x than furnaces without preheating and natural draft furnaces. Also, NO
emissions were higher under typical excess air conditions (about 5.5 percent
oxygen) than under low excess air conditions (about 3 percent oxygen).11
In addition to N0x emissions, combustion of halogenated VOC emissions
may result in the release of halogenated combustion products to the environ-
ment. The EDP shows that most streams containing halogenated VOC would not
be controlled by a flare. Incinerators are generally more capable of
tolerating the corrosive effects of halogenated VOC and its combustion
by-products. In addition, scrubbing can be used to remove these halogenated
compounds from an incinerator's flue gas. Generally, incineration
temperatures greater than 870°C (1,600°F) are required to ensure 98 percent
destruction of halogenated VOC. For example, when incinerating chlorinated
VOC at temperatures of 980 to 1,100°C (1,800 to 2,000°F), almost all chlorine
present exists in the form of hydrogen chloride (HC1). The HC1 emissions
generated by thermal oxidation at these temperatures can be efficiently
removed by wet scrubbing.12 As noted earlier, the cost of the scrubber was
added to the overall thermal incinerator system cost that was included in the'
regulatory analysis.
7.3 WATER POLLUTION IMPACTS
Control of VOC emissions using combustion does not typically result in
any significant increase in wastewater discharge. That is, no water
effluents are generated by the combustion device. However, the use of an
incinerator/scrubber system for control of vent streams with halogenated VOC
does result in slightly increased water consumption. In this type of
control system, water is used to remove the acid gas contained in the
incinerator outlet stream. The makeup rate for water that is purged from
the system may be approximately 0.033 m3/kg (19.2 gal/lb) of halogen in the
waste gas if a waste heat boiler is used prior to the scrubber or higher if
no waste heat boiler is used. Vent streams smaller than 700 scfm generally
don't have waste heat boilers as discussed in Chapter 8. In most cases, any
increase in total process unit wastewater would be relatively small and in
any case would not affect plant waste treatment or sewer capacity. More
than half of the process units with vent streams containing halogenated VOC
are already combusted in an incinerator at baseline. The remaining process
units generally have very high TRE values and would likely not be required
to use an incinerator under an NSPS. The increase in scrubber wastewater
flow due to an NSPS is, therefore, projected to be quite small.
The water effluent guidelines for individual States may require that
industrial sources maintain the pH of water effluent within specified limits.
To meet these guidelines, the water used as a scrubbing agent may need to be
neutralized prior to discharge to the plant effluent system. The
scrubber effluent can be neutralized by adding caustic (NaOH) to the
scrubbing water. The amount of caustic needed depends on the amount of acid
qas in the incinerator flue gas. For example, approximately 1.09 kilograms
(2.4 pounds) of caustic (as NaOH) are needed to neutralize one kilogram
(2.2 pounds) of HC1. '
7-7
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The salt formed in the neutralization step must be purged from the
system for proper disposal. The methods of disposal include direct waste
water discharge into sewer systems, salt water bodies, brackish streams,
and, on occasion, freshwater streams, sewer systems, deep well injection,
and salt recovery. Use of the latter disposable method is not very
widespread, and data show that most plants currently incinerating
halogenated streams have state permits to dump the brine or use onsite wells
to dispose of salty wastewater at a relatively low cost.13 It is expected
that such permits would be issued to new plants as well. The increased water
consumption and caustic costs were included in the projected operating costs
for control of halogenated vent streams using an incinerator/scrubber system.
The costs associated with the disposal of the salty wastewater were judged
not to be significant in comparison to the control costs and, therefore, were
not included in the projected cost impacts presented in Chapter 8.11*
An alternative to brine disposal is to use the brine as feed to chlorine
production. Such a use would be site specific, where there was a need for
the chlorine in subsequent syntheses, and where quantities of brine'either
alone or in combination with other brine sources were adequate for economical
production.
The use of scrubbers to remove HC1 from the incinerator flue gas also
has the potential to result in small increases in the quantities of organic
compounds released into plant wastewater. However, only small amounts of
organics are released into the scrubber wastewater; and the flow of
wastewater from the scrubber is small in comparison to total plant
wastewater, especially in installations where there are multiple chemical
processing units using a central wastewater treatment facility. In
addition, as discussed above for scrubber brine wastewater, over half of the
halogenated streams in the EDP are already combusted at baseline.15 This
fact combined with the generally high TRE values for process units that are
projected to have uncombusted halogenated vent streams indicate that the
increased incinerator scrubber wastewater flows due to this NSPS will be
small. Therefore, the increase in the emission of organics in plant
wastewater is not likely to be significant.
7.4 SOLID WASTE DISPOSAL IMPACTS
There are no significant solid wastes generated as a result of control
by combustion. A small amount of solid waste for disposal could result if
catalytic oxidation, instead of flaring or thermal incineration, were used
by a facility to achieve an equivalent degree of VOC control. The solid
waste would consist of spent catalyst.
7.5 ENERGY IMPACTS
The use of incineration to control VOC from reactor process vent streams
can result in fuel and electricity usage. Supplemental fuel is frequently
required to support combustion. Electricity is required to operate the
pumps, fans, blowers and instrumentation that may be necessary to control VOC
7-8
-------
using an incinerator or flare. Fans and blowers are needed to transport vent
streams and combustion air. Pumps are necessary to circulate absorbent
through scrubbers that treat corrosive offgases from incinerators combusting
halogenated VOC. Fuel and energy usage requirements for incinerators and
flares are discussed in detail as part of the overall cost methodology in
Chapter 8.
Tables 7-1 and 7-2 present total estimated energy usage associated with
each regulatory alternative. These energy values-include both fuel and
electricity usage estimates assuming either incineration or flaring as the
combustion technique. Energy impacts under the regulatory alternatives
range from about 3 to 520 TJ/yr (3 to 490 billion Btu/yr). Electricity
generally accounts for less than about 2 percent of the total energy impacts,
while fuel use accounts for the remainder.
In reality, other combustion devices could also be used to control some
new reactor process vents. This would affect fuel usage requirements. If
boilers or process heaters are used, steam can be produced and sold. This
may result in net energy savings, depending on the heat recovery potential
associated with a particular vent stream.
7.6 OTHER ENVIRONMENTAL IMPACTS
7.6.1 Considerations for Installing Control Equipment
Depending on the volume of process vent gas to be controlled,
incinerators and flares may require a site as large as 300 feet by 300 feet
for installation. Because thermal incinerators and flares use combustion
with a flame to control VOC emissions, these devices must be located at a
safe distance from process equipment handling flammable chemicals; otherwise,
special precautions may be needed to minimize the risk of explosion or fire.
7.7 OTHER ENVIRONMENTAL CONCERNS
7.7.1 Irreversible and Irretrievable Commitment of Resources
The use of combustion devices to control VOC emissions from reactor
processes usually requires the use of supplemental energy in the form of
natural gas, The adverse effects of using these nonrenewable resources must
be considered when evaluating the benefits of controlling the release of
potentially harmful air pollutants.
The use of product recovery techniques or process modifications is
another alternative to reduce VOC emissions. Control of VOC emissions using
product recovery techniques might be a viable alternative to combustion
control for some reactor processes. Since the reactor process vent streams
containing VOC are also derived ultimately from petroleum, these product
recovery techniques would result in conservation of both chemicals and fuels
derived from petroleum.
7.7.2 Environmental Impact of Delayed Standards
Annual 1990 VOC emissions from reactor processes assuming current
(baseline) levels of control are estimated to be 3,300 Mg/yr (3,600 tons/yr).
7-9
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Under the most stringent alternative (vent streams from all 56 new, modified,
and reconstructed process units are controlled by 98 percent efficient
control devices) 1990 VOC emissions would be about 910 Mg/yr (1,000 tons/yr).
This is an emissions reduction of about 2,300 Mg/yr (2,600 tons/yr), as shown
in Tables 7-1 and 7-2. If the standard is delayed, these emission reductions
would not occur, given that the most stringent alternative is adopted as the
standard.
7.8 REFERENCES
1. Memo from Read, B. S., Radian Corporation, to Reactor Processes NSPS
file. May 28, 1985. 'Summary of the Emission Data Profile.
2. Memo from Cassidy, M. A. and Baviello, M. A., Radian Corporation, to
Reactor Processes NSPS file. Emission Characteristics of New, Modified,
and Reconstructed Process Units Projected to Come On-Line Between 1985
and 1990. May 10, 1985.
3. IT Enviroscience. Organic Chemical Manufacturing, Volume 4, Combustion
Control Devices. Prepared for U.S. Environmental Protection Agency.
Research Triangle Park, N.C. Publication No. EPA-450/3-80-026.
December 1980. p. V-43.
4. Reference 1.
5. Lee, K. W., et al., Radian Corporation. Polymers and Resins NSPS.
Volatile Organic Compound Emissions from Incineration. Emission Test
Report. ARCO Chemical Company, LaPorte Plant, Deer Park, Texas.
Volume I: Summary of Results. Prepared for U.S. Environmental Protec-
tion Agency. Research Triangle Park, N.C. EMB Report No. 81-PMR-l.
March 1982. p. 12-15.
6. U.S. Environmental Protection Agency. Air Oxidation Processes in
Synthetic Organic Chemical Manufacturing Industry - Background
Information for Proposed Standards. Research Triangle Park, N.C.
Publication No. EPA-450/3-82-001a. January 1982. p. C-22.
7. Reference 3. p.II-4, II-6.
8. Reference 6.
9. References 1, 5, 6.
10. McDaniel, M., Engineering Science. Flare Efficiency Study, Prepared
for U.S. Environmental Protection Agency. Washington, D.C.
Publication No. EPA-600/2-83-052. July 1983. 134 p.
11. Memo from Keller, L. E., Radian Corporation, to file. October 31, 1983.
2p. N0x Emissions from Gas-Fired Process Heaters.
7-10
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12. Reference 6, p 111-15.
13. Memo from Piccot, S. D., and Lesh, S. A., Radian Corporation, to Reactor
Processes NSPS file. May 29, 1985. Disposal of Brine Solutions from
Wet Scrubbers.
14. Memo from Stelling, J. H. E., Radian Corporation, to Distillation
Operations NSPS file. September 2, 1982. Caustic and salt disposal
requirements for incineration.
15. Reference 1.
7-11
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8. COSTS
This chapter presents cost estimates for controlling VOC emissions from
reactor process facilities in SOCMI. Although a significant amount of time
has elapsed since these cost analyses were performed, the Agency has decided
not to update the cost information because it is believed that updated costs
would not significantly change the impacts or the requirements of the
standards. The cost impacts of each of the regulatory alternatives presented
in Chapter 6 are analyzed. Two types of control systems are considered in the
cost analyses: flares and thermal incinerators.
Section 8.1 includes a discussion of the design criteria for both control
systems. Based on these design criteria, control costing procedures are
developed. Section 8.2 includes a discussion of the capital cost basis for
both systems while the annualized cost basis is discussed in Section 8.3. A
comparison of the control system costs is given in Section 8.4. Finally, the
national cost impacts of each of the regulatory alternatives are presented in
Section 8.5, while Section 8.6 presents a discussion of the accumulated
economic impacts on SOCMI due to all air pollution standards.
8.1 CONTROL SYSTEM DESIGN
This section discusses the design of thermal incinerators and flares for
controlling VOC emissions from reactor processes. For any reactor process.
vent, the design and applicability of either control system is based on the
vent stream flowrate, heating value, and halogen content. Equations are used
to calculate equipment size, operating parameters, caustic consumption, and
utility use (natural gas, electricity, steam and water) for combusting a given
vent stream.
The design of thermal incinerators is discussed in Section 8.1.1.
Included in the discussion is a section defining categories of thermal
incinerators that are developed for costing purposes. These categories are
defined according to the presence of halogenated compounds and heating value
of reactor process vent streams. A discussion of flare design is given in
Section 8.1.2.
8.1.1 Thermal Incinerator Design
8.1.1.1 General Design Criteria. A thermal incinerator control system
may consist of the following equipment: combustion chamber, recuperative heat
exchanger, waste heat boiler, quench/scrubber system, and auxiliary equipment
such as ducts, pipe rack, fans, and stack. Incinerator design equations are
used to estimate the combustion chamber volume, heat exchanger surface area
(for low heat content vent streams), waste heat boiler surface area (for
halogenated vent stream heat recovery), auxiliary equipment sizes, and various
system operating parameters. All of these estimated equipment sizes and
operating parameters are used to determine the total installed capital cost as
well as the annual operating and maintenance costs of the incinerator.
8-1
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The combustion chamber volume is a function of the incinerator residence
time, operating temperature, and flue gas flowrate. The flue gas flowrate
for a specific process vent stream is determined through mass and energy
balances based on the incinerator temperature, the primary and supplementary
natural gas requirements, and the excess air level assumed in the flue gas
stream. A design vent stream flowrate is used in designing incinerator
systems. The design flowrate is 5 percent greater than the vent stream
flowrate. The combustion chamber volume, incinerator temperature, furnace
residence time, and other general design criteria are presented in Table 8-1
and were developed from an EPA report which was based on data supplied by
vendors.1
The smallest incinerator used in the costing procedures has a combustion
chamber volume of 1.01 m3 (35.7 ft3).2 Under the incinerator design
criteria, an incinerator with a 1.01 m3 combustion chamber is applied to
reactor process vent streams with initial process flowrates of 14.2 scm/min
(500 scfm) or less. To compensate for the application of an oversized
combustion chamber to streams with flowrates less than 14.2 scm/min, natural
gas and air are added to maintain the desired combustion temperature and
residence time. The process vent stream flowrate then equals 14.2 scm/min
and the design flowrate is 5 percent greater at 14.9 scm/min (526 scfm).
Reactor processes facilities requiring an incinerator larger than 32 ft
x 16 ft are assumed to use multiple smaller incinerators because they would
cost less than one large incinerator. Control-costs are lower for the
smaller incinerators because field fabrication is not required. Incinerators
larger than 32 ft x 16 ft require field fabrication, which greatly increases
the costs.3
A recuperative heat exchanger is used to preheat combustion air and/or
the vent stream when the vent stream heating value is insufficient to
maintain the design incinerator temperature. The use of a heat exchanger
reduces the amount of supplemental natural gas needed to maintain proper
incinerator temperature. A heat exchanger is not applied to vent streams
with heating'values high enough to maintain or exceed the desired incinerator
temperature or to vent streams with heating values greater than 25 percent of
the typical VOC lower explosive limit (LEL) in air. This is due to the fact
that raising the vent stream temperature through heat exchange could result
in damage to the combustion chamber, increase NO production, or risk
precombustion in the heat exchanger. Further, tfie use of heat exchangers on
streams with high heating values would not provide any fuel savings. A
recuperative heat exchanger is included in incinerator systems for non-
halogenated vent streams with heat contents less than or equal to 0.48 MJ/scm.
Further discussion on the applicability of recuperative heat exchangers is
included in Section 8.1.1.2.
It is assumed that the thermal incinerator uses a quench/scrubber system
for all process vent streams containing halogenated compounds. Water is used
to cool the flue gases in a quench chamber before introduction to the scrubber
8-2
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where water is used for acid gas removal. The acidic water resulting from
waste gas scrubbing is neutralized with caustic. The quench and scrubber
water and caustic requirements are determined through mass and energy balances
and the general scrubber design criteria listed in Table 8-1.
For halogenated vent streams with process flowrates equal to or greater
than 19.8 scm/min (700 scfm) a waste heat boiler is added after the
incinerator but prior to the quench/scrubber system to obtain heat recovery
through steam generation. Flue gas exiting the incinerator at 2,000°F is
cooled down to 500°F upon passage through the waste heat boiler.** However,
waste heat boilers are not manufactured for streams with flowrates of less
than 19.8 scm/min.5 In order to compensate for the absence of a waste heat
boiler for streams with flowrates less than 19.8 scm/min, more quench water
is needed to cool the gas to 500°F before it enters the scrubber for acid gas
removal. Because more water is added to quench the hotter flue gas, the
amount of water vapor in the gas stream increases, thus causing the gas
stream volume to increase. The increased volume requires a larger scrubber
thafi would be required if a waste heat boiler were used.6
In designing the thermal incinerator control system, it is assumed that
. all process vent streams contain no oxygen. In order to increase the rate of
combustion and avoid incomplete combustion and pyrolysis, it is assumed that
enough excess combustion air is supplied to ensure 3 mole percent oxygen in
the flue gas.7
8.1.1.2 Thermal Incinerator Design Categories. For the purpose of
costing, thermal incinerators are assigned to one of five broad design
categories depending upon the presence of halogenated compounds in the
reactor process vent stream and the heat content of the vent stream. For
each category, the thermal incinerator design employed for a particular
reactor vent stream depends upon the vent stream heat content, the flowrate,
and the presence or absence of halogenated compounds. The basic fuel use
requirements associated with each category are given in Table 8-1. For vent
stream flowrates less than 14.2 scm/min, the heating value is calculated
after dilution air is added to the stream to attain a minimum flowrate of
14.2 scm/min. The design incinerator inlet vent stream flowrates and the
ratios used to predict flue gas flowrates for each design category are given
in Table 8-2. These design flowrates are important in calculating equipment
sizes and fuel costs. The design vent stream flowrates in Table 8-2
correspond to the maximum equipment sizes for each design category and they
are used to determine the number of incinerators for proper combustion. The
volume increase indicated by the flue gas to vent stream flow ratios is due
to the addition of air and natural gas to the vent stream flowing into the
incinerator.
Categories Al and A2. All reactor process vent streams that contain
halogenated compounds are included in design Categories Al and A2.
Categories Al and A2 do not differ in control system design but only in
supplementary fuel requirements. Category Al includes all streams with heat
contents less than or equal to 3.5 MJ/scm (95 Btu/scf); Category A2 includes
8-3
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TABLE 8-1. INCINERATOR GENERAL DESIGN CRITERIA1'16
Item
Criteria
Emission control efficiency
Minimum incinerator volume*
Incinerator temperature
- nonha.logenated vent stream Incineration
- halogenated vent stream Incineration
Furnace residence times
- nonhalogenated vent stream Incineration
- halogenated vent stream Incineration0
Primary fuel requirement determined according
to heating value of vent stream
Supplemental fuel requirement. Required for
flame stability calculated according to
design category:
Design Category0:
Al
A2
B,C
0
98 percent destruction of VOC
1.01 m3 (35.7 ft3)
870"C - 980°C (1,6008F - 1.800eF)
1,100'C (2,000°F)
0.75 sec
1.00 sec
Fuel required to maintain Incinerator temperature
with 3 mole percent excess air in flue gas
Add 0.33 MJ/scm of process vent stream flow (9 Btu/scf)
Add 0.33 MJ/scm of process vent stream flow (9 Btu/scf)
itp-
Recuperative heat exchanger
Design Category0:
Al, A2, D, E
B
Waste heat boiler
Design Categories Al, A2
Quench/Scrubber system
- type
- packing height
- liquid/gas ratio
- gas velocity
scrubber gas temperature
quench and scrubber water
None
Offgas and combustion air preheated
70 percent heat recovery.
Combustion air preheated. 34 percent
heat recovery.
« *"*" the P™:*" v*"t stream flowrate Is
equal to or greater than 19.8 scm/min (700 scfm) and
the vent stream contains corrosive compounds
PaSedhtSwerr'rrOSlV* compounds are
11.0 m (36.0 ft) ,
1337 1/m3 (10 gal/ft3)
0.9 m/s (3.0 ft/s)
100°C (212'F)
Varies according to flue gas flowrate
^ --
8-4
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TABLE 8-1 (CONCLUDED). FOOTNOTES '
*If calculated Incinerator combustion chamber volume 1s less than 1.01 m (35.7 ft ), natural gas and air are
added to maintain the design combustion temperature and residence time for a 1.01 n (35.7 ft ) incinerator
volume.
bNeeded to ensure complete combustion.
C0es1gn categories are based on the following vent stream characteristics:
(HV * heating value of reactor process vent stream megajoules/standard cubic meter at 20°C and 1 atm, MJ/scm)
Al halogenated. HV < 3.5 MJ/scm
A2 halogenated. HV > 3.5 MJ/scm
8 nonhalogenated. HV < 0.48 MJ/scm
C nonhalogenated. 0.48 MJ/scm < HV <. 1.9 MJ/scm
0 nonhalogenated. 1.9 MJ/scm < HV <_ 3.6 MJ/scm
E nonhalogenated. HV > 3.6 MJ/scm
^Category I streams are diluted prior to Incineration so that combustion temperatures would not exceed 980°C (l.SOO'F).
For determining the supplemental fuel requirement,the resultant net heating value after dilution Is assumed to be
3.4 MJ/scm (92 Btu/scf).
8-5
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TABLE 8-2. DESIGN CATEGORY BOUNDARY VALUE FOR REACTOR PROCESS
VENT STREAM FLOWRATES AND RATIO OF FLUE GAS
FLOWRATE TO OFFGAS FLOWRATE3
Category
Maximum
Design Vent Stream
Flowrate per Incinerator
(at Incinerator Inlet)
(103 son/min) (103 scfm)
Ratio of
Incinerator Flue Gas
Flow to Reactor Process
Design Vent Stream Flow0
Ald
A2d
B
C
D
E
0.74
0.74
1.42
1.42
1.25
1.25
(26.1)
(26.1)
(50.1)
(50.1)
(44.1)
(44.1)
2.9
2.9
1.9
2.3
2.5
2.5
References 1,2.
JDesign flowrate = vent stream flowrate x 1.05.
"Both at standard temperature (20°C or 68°F) and pressure
(1 atm or 14.7 psia).
Reactor process vent contains halogenated compounds.
NOTE: 35.314 scfm = 1 scm/min
8-6
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streams with heat contents greater than 3.5 MJ/scm (95 Btu/scf). Since the
heat contents of Category Al streams are lower, more supplementary fuel is
required to maintain the proper incinerator temperature. Due to the greater
difficulty of achieving complete combustion of vent streams containing
halogenated VOC, an incineration temperature of 1,100°C (2,000°F) and a
1-second residence time were chosen to ensure that all halogenated streams
will be controlled to a 98-weight-percent reduction efficiency or a 20 ppmv
offgas concentration. Combustion temperatures exceeding 870°C (1,600°F)
limit the use of recuperative heat exchangers due to limitations of materials
of construction and due to the risk of precombustion in the exchangers.
Therefore, recuperative heat exchangers are not used within these design
categories. However, a waste heat boiler can be used effectively with flue
gas temperatures up to 1,650°C (3,000°F).12 A waste heat boiler with steam
generation resulting in 60 percent heat recovery is included in the design
criteria for these categories.13 The amount of heat recovery is limited by a
minimum temperature of the outlet flue gas exiting the waste heat boiler
(about 260°C (500°F)). Below this temperature, condensation of corrosive
combustion products could occur.11* The design criteria for Categories Al and
A2 also include a quench/scrubber -system for the removal of corrosive
hydrogen halides formed in the incinerator. The resulting solution from the
quench/scrubber is neutralized with caustic soda.
As mentioned previously, waste heat boilers are not available for
streams with flowrates less than 19.8 scm/min (700 scfm). Where waste heat
boilers are not used, an increase in the flow rate of quench water is
required to cool the hotter flue gas, and a larger quench/scrubber chamber is
needed to accommodate the larger volumes of steam and flue gas. For streams
with flowrates below 19.8 scm/min, where no waste heat boiler is used,
scrubber capital costs increase by about $60,000 (1979 dollars) and the
quench water flowrate increases from 0.063 1/scm/min (0.47 gal/1,000 scfm) of
vent gas to a value of 1.1 1/scm/min (8.0 gal/1,000 scfm) of vent gas.
Category B. Design Category B incinerators are used for reactor process
vent streams that do not contain halogenated VOC's and that have a heat
content equal to or less than 0.48 MJ/scm (13 Btu/scf). This heat content
corresponds to 25 percent of a typical VOC LEL in air.15 Streams with heat
contents less than or equal to 25 percent of the LEL can be preheated without
violating insurance requirements.15 For Category B, recuperative heat
exchange resulting in 70 percent heat recovery is included in the design
criteria. In this heating value range, the amount of heat recovery that can
be obtained is limited by a ceiling of about 550-600°C (1,000-1,100°F) on the
combustion air preheat temperature due to burner design considerations.16
Category C. Because of insurance requirements, reactor process vent
streams with heat values greater than 0.48 MJ/scm (13 Btu/scf) and less than
or equal to 1.9 MJ/scm (52.0 Btu/scf) may not be preheated.17 This heat
value range corresponds to a range of 25-100 percent of the LEL in air for a
typical organic vapor. Category C incinerators are used for all reactor
8-7
-------
process vent streams within this heat content range that do not include
halogenated VOC's. Because the majority of reactor process vent streams
contain little or no oxygen, vent streams in this heat content range need not
be diluted.18 While the vent stream is not preheated, the incinerator design
criteria for Category C do include preheating the combustion air via
recuperative heat exchange with the flue gas, resulting in 34 percent heat
recovery.19
Category D. This design category applies to incinerators used, to
combust reactor process vent streams with heat contents greater than
1.9 MJ/scm (52.0 Btu/scf) and less than or equal to 3..6 MJ/scm
(98.0 Btu/scf). Vent streams in this range are not preheated and require
only a small amount of auxiliary fuel for flame stability. Because little
fuel is needed, the use of recuperative heat recovery would not save much
energy and thus is not economical to apply. The combustion temperature,
which usually exceeds 870°C (1,600°F) and can be as high as 980°C (1,800°F),
is dependent upon the heat content of the vent stream. A design temperature
at the upper end of the possible raage is used (980°C (1,800°F)) to avoid
underestimating chamber costs.
Category E. Design Category E includes incinerators for reactor vent
streams with heat contents above 3.6 MJ/scm (98.0 Btu/scf). Vent streams in
Category E need not be preheated and require only a small amount of auxiliary
fuel for flame stability. The vent stream composition again determines the
combustion temperature and it is estimated combustion will occur at
temperatures of approximately 980°C (1,800°F). High heating value reactor
process vent streams in Category E are diluted to 3.6 MJ/scm (98 Btu/scf) and
no heat recovery is employed. The dilution to 3.6 MJ/scm is required to
ensure that the incineration temperature does not exceed 98°C. Excessive
incineration temperatures may shorten the life of the combustion chamber.
The supplemental fuel requirement is based upon the stream heating value
after dilution.
8.1.1.3 Incinerator Auxiliary Equipment. Auxiliary equipment needed
for a thermal incinerator control system includes ducting, pipe racks, a
stack, and a fan for moving the vent stream from the source to the control
device. A combustion air fan is also needed but the cost of this fan is
included in the combustion chamber cost discussed in Section 8.2. In
estimating the length of ducting required, it is expected that incinerators
will be located as close to the process unit as possible, but far enough away
to provide safety. Both the National Fire Protection Association and-the Oil
Insurance Association (now the Industrial Risk Insurers) concur that for
petrochemical plants, a minimum safe distance of 200 feet should be used to
separate a "high hazard" process unit and an enclosed combustion source.°'y
Therefore, the incinerator design criteria include 61 m (200 feet) of ducting
between the thermal incinerator and the edge of a process unit. An additional
30 m (100 feet) of ducting is added to route the vent stream from within the
process unit to the edge of the process unit. Therefore, for the purposes of
calculating costs, a total of 91 m (300 feet) of ducting is included.
8-8
-------
In order to support the ducting, the costs of a pipe rack have been
included in the cost estimates. The pipe rack is designed to support only
the duct and pipe associated with a single reactor process unit. The size of
the pipe rack included in the cost estimates is large enough to handle the
ducting associated with the largest vent stream anticipated from a reactor
process unit. The pipe rack consists of individual "T" shaped frames that
are 16 feet tall to allow for passage of vehicular traffic. It is estimated
that 13 A-36 structural steel pipe racks, each spaced about 20 feet apart,
would be required to support the 91 m (300 feet) of ducting.11
Fans are designed according to the combustion gas flowrate (i.e., vent
stream, natural gas and air) and pressure drop across the incinerator system.
Fans are designed to overcome pressure drops ranging from 6 to 22 inches of
water which are the pressure drops for these incinerator systems.10 The
overall pressure drop varies with the equipment used (e.g., an incinerator/
boiler/scrubber system has a 22-inch pressure drop while an incinerator alone
has a 6-inch pressure drop). Therefore, the power rating of the fan would
vary depending on the incinerator system used.
8.1.2 Flare Design
8.1.2.1 General Design Criteria. The flare design consists of an
elevated, guy-supported, steam-assisted, smokeless flare. Published
correlations relating vent stream flowrate, heat content, and composition, to
the flare height and tip diameter are used in the flare design.20 The
general design criteria used in developing these correlations are discussed
Below and are presented in Table 8-3. Additional equipment such as ducting,
flare services, pipe racks, and a vent stream mover are also discussed in
i* 1 1 I o ocCulOn*
Flare height and tip diameter are the basic design parameters used to
determine the installed capital cost of a flare. The tip dlSetlr selected
IL .K-'T °f *he Comb1ned ven* stream and supplemental fuel flowrates
the combined gas temperature, mean molecular weight, and the qas exit
ve ocity assumed at the flare tip. Supplemental fuel requirements Ind tie
velocity values are shown in Table 8-3/ Determination of flarTheigK? iJP
based on worker safety requirements. The flare height is selected so the
' ' °
4oB/nft2H ?enSr rom >oth the arndsunl htd es not
funny day of 300 Bti/Arftllnth-S°1ar radia51on has an approximate value on a
liuid m "'9" Crfter1a are the ""Pon
liquid seal and sea na, "9" Crtera are the ""PonMts of a
" "
8-9
-------
TABLE 8-3. FLARE GENERAL DESIGN CRITERIA
20
Item
Criteria
Emission control efficiency
General flare design
- minimum flare tip diameter (D)
- minimum flare height
- maximum ground level flare heat intensity
- flare tip velocity
- flame emissivity
- number of pilots
- pilot gas requirement
- steam requirement
- purge gas requirement
Supplemental fuel requirement
98 percent destruction
Elevated, guy supported, steam
assisted smokeless flare
5.1 cm (2.0 inch)
9.0 m (30 ft)
440 W/m2 (140 Btu/hr ft2)
V = 14.6 m/s (48 ft/s)
0.13
1 for Da < 20
2 for 20 < D < 61
3 for 61 < D < 107
2.36 scm/hr (80 scf/hr) of
natural gas per pilot
0.4 kg steam/kg vent gas
Natural gas added to maintain a
minimum flare tip velocity of
0.01 m/s (0.04 ft/s)
Natural gas required to
maintain vent stream HV of
11.2 MJ/scm (300 Btu/scf)
D is the flare tip diameter in.centimeters.
8-10
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In designing a flare, first, flare tip diameter (D) and flare height (H)
are calculated from empirical design equations23 *24t using vent stream
flowrate, VOC content, and heat content. The natural gas required for pilots
and purge, and the mass flowrate of steam required are also calculated.
Pilot gas consumption is a function of the number of pilots which, in turn is
a function of the tip diameter as shown in Table 8-3. Based on the tip
diameter, the number of pilots is selected and the pilot gas flowrate is
calculated assuming a gas flow of 2.26 scm/hr (80 scf/hr) per pilot. The
purge gas requirement is a function of -the calculated flared gas velocity
compared to the minimum allowable gas velocity at the tip. If the flared gas
velocity is sufficient, no purge gas is required. A flare tip exit velocity
of 14.6 m/s (48 ft/s) is used for design purposes. Based on test data, an
exit velocity of 18.2 m/s (60 ft/s) ensures a VOC destruction of 98 percent
when the heating value of the combined stream is at least 11.2 MJ/scm
(300 Btu/scf). The exit velocity of 14.6 m/s (48 ft/s) used in this analysis
contains a margin of safety to accommodate most unexpected vent stream surges
and still maintain a 98 percent destruction efficiency. The steam
requirement is the flow of steam needed to maintain a steam to flare gas
ratio of 0.4 kg steam/kg vent gas.25 The steam requirement is the estimated
amount of steam needed to ensure smokeless flaring. Most reactor vent
streams would actually require less than the specified 0.4 kg steam per kg of
vent gas.
8.1.2.2 Flare Auxiliary Equipment. Auxiliary equipment needed for a
flare system includes pipe or duct; flare services such as steam, air, and
natural gas lines; pipe racks; and a vent stream mover. The design criteria
include 120 m (400 feet) of ducting between the reactor process unit and the
flare. Both the National Fire Protection Association and the Oil Insurance
Association recommend a minimum safe distance of 91 m (300 feet) between the
edge of a "high hazard" process unit and an open flame combustion device.26'27
An additional 30 m (100 feet) of duct is allowed to route the vent stream
from within a process unit to .the edge of a process unit. Therefore, 120 m
(400 feet) of ducting have been included in the design criteria for flares.
Either pipe or duct is used to transport the reactor process vent stream
to the flare base. For streams with flowrates less than 11.3 scm/min
(400 scfm), a pipe is included in the flare design criteria. The pipe can
have one of four possible diameters (i.e., 1, 2, 4, and 6 inches) depending
upon the vent stream flowrate. Diameters are based on a maximum vent stream
linear velocity of 610 m/min (2,000 ft/min). A 6-inch diameter pipeline has
a maximum vent stream flowrate of 11.3 scm/min. For flow rates greater than
11.3 scm/min, duct is used because it is more economical than pipe for
diameters over 6 inches. Since flares are not used to combust vent streams
that contain halogenated compounds, all pipe, duct, and fittings are
constructed with schedule 40 carbon steel.
Flare services include the natural gas, steam, and instrument air lines
needed to provide these utilities at the flare base. The design criteria
include 120 m (400 feet) of pipe for the natural gas, air, and steam lines.
8-11
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The size of these lines are 2-inch diameters for gas and steam lines and a
i-inch diameter for the air line. These lines would be mounted on the pipe
rack discussed later in this section.
The vent stream mover system included in the flare design criteria and
costing procedures is different from the vent stream mover used for
incinerators. When flares are used on nonhalogenated vent streams, the
system pressure drop is about 21 inches of water whereas if an incinerator
were used the pressure drop would be about 6 to 10 inches. Because of the
difference in pressure drop, different types of vent stream movers are
required for the two control systems.
The vent stream movers used to transport the vent stream from the
reactor process unit to the flare were selected based upon a total system
pressure drop and the economics of application. Based on a representative
value of vent stream flowrate (3.4 scm/min, or 121 scfm), determined from all
of the vent stream flowrate data contained in the reactor processes emission
data profile (EDP), system pressure drop calculations were performed on the
pipe or duct system, gas seal, water seal, flare stack, and tip.31 At the
representative value of flowrate, the pipe or duct (including fittings)
pressure drop is estimated to be 4.8 inches of water.30 The pressure drop
estimated for the gas and water seals as well as the flare stack and tip is
approximately 16 inches of water. Therefore, the total system pressure drop
is approximately 21 inches of water. Mover systems were selected to overcome
this pressure drop.
Three types of gas movers are considered for use with either pipe or
duct. The vent stream movers considered are: (1) a compressor, (2) a turbo-
blower, and (3) a fan. For vent stream flowrates less than 1.2 scm/min
(44 scfm), a compressor was used. Fans and turbo-blowers were not used
because they cannot overcome the flare system pressure drop at these
flowrates.2^ For vent stream flowrates between 1.2 and 244 scm/min (44 scfm
to 8,600 scfm), a turbo-blower is more economical than a compressor or fan.29
Either a pipe or duct is used with a turbo-blower depending on the flowrates
as discussed above. A fan is included-in the design criteria for streams
with flowrates greater than 244 scm/min (8,600 scfm) because it is more
economical than the other two mover devices for vent streams in this flowrate
range. Only a duct is used in conjunction with the fan.
.In order to support the 120 m (400 feet) of vent, stream pipe or duct
and flare services lines, a pipe rack is included in the design. The pipe
rack is similar to that used for incinerators and consists of 18 "T"-shaped
structures placed about 20 feet apart.28 These structures are constructed of
A-36 structural steel and are 16 feet tall to allow for the passage of
vehicles. The pipe rack is sized to support the vent stream pipe and flare
services pipes (natural gas, instrument air, and steam lines) associated with
a single reactor process unit.32
8-12
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8.2 CAPITAL COSTS
The capital cost for each combustion control system includes the
purchase and installation of all equipment, pipe or duct, vent stream movers,
flare services, and pipe support necessary to route a vent stream from a
reactor process unit to the control device. Equations used to estimate
installed capital costs of incinerators.and flares were generated by using a
linear regression analysis of cost curves presented in an EPA report.33'35
Pipe or duct and mover costs are a summation of many individual component
costs (i.e., ducts, fittings, valves, fans). Total installed capital cost
equations used to determine the installed costs of pipe or duct, movers,
flare services, and pipe support were based on design and cost information in
Richardson.35 Capital and installation costs for the turbo-blowers and fans
were provided by a vendor.36
The capital cost bases for incinerators, flares, pipe or duct, vent
stream movers, flare services, and pipe racks are discussed in the following
sections. All capital costs and cost equations are adjusted to third quarter
1982 dollars using Chemical Engineering plant cost indices for fabricated
equipment.37.38.33
8.2.1 Thermal Incinerators
Capital cost equations for thermal incinerator systems are based on cost
curves.*0*1*1 Individual cost equations for the incinerator combustion
chamber, recuperative heat exchanger, and quench/scrubber are based on a
linear regression analysis of these cost curves.
The incinerator cost equations provide a relationship between equipment
cost and combustion chamber volume for three incinerator temperatures. The
high temperature equation (1,100°C(2,000°F)) is used when the reactor process
vent stream contains halogenated components, the moderate temperature
equation (980°C(1,800°F)) is used for streams with relatively high heating
values and the low temperature equation (870°C(1,600°F)) is used when
corrosive components are absent and the vent stream heating value is less
than 1.9 MJ/scm (52 Btu/scf). In addition to the cost of the combustion
chamber itself, the cost equations also account for the cost of fans, ducts,
stack, and recuperative heat exchanger. An installation factor of 4.0 is
applied to the combustion chamber capital cost equation to account for such
installation cost factors as foundation, insulation, erection, instruments,
painting, electrical, fire protection, engineering, freight and taxes.1*2
When a recuperative heat exchanger is included in the capital cost equations
(see Section 8.1.1.2 for applicability) an installation factor of 2.6 is used
to estimate installation cost of the heat exchanger.1*3 The installation
components considered are the same as those identified for the combustion
chamber with the exception of fire protection.
Halogenated (corrosive) vent streams require the use of a quench/scrubber
after the incinerator to remove the corrosive products of combustion. The
capital cost of this system is determined as a function of the total
incinerator exit gas flowrate. The cost equation is based on a linear
8-13
-------
regression analysis of cost curves.*"* The total installed capital cost of
the incinerator system is the summation of the combustion chamber, heat
exchanger, and quench/scrubber costs and auxiliaries.
The capital costs for purchase and installation of ducting, a fan, and
pipe racks are also included in the thermal incinerator costing procedure.
As discussed in Section 8.1.1,.the costs of 91 m (300 feet) of ducting and a
fan are included in the costs of the control system.57 The costs of a pipe
rack to support the ducting are also included in the cost of the control
system.
8.2.2 Flares
The total installed capital cost of a flare system is the sum of the
costs of the flare itself, auxiliaries, and the pipe or duct and mover
system. The capital cost of the flare itself is based on an EPA report that
contains vendor supplied information. The EPA report provided data on the
capital cost of a flare as a function of flare height and tip diameter for
systems designed to burn propylene.1*5 The vendor data provided information
on capital costs for different flare height and tip diameters for flares
combusting eight different VOC-containing streams. An installation factor of
2.1 was applied (see Table 8-4)66, and a cost equation was developed from a
linear regression analysis of both costing sources.20 This equation yields
the total installed capital cost of a flare as a function of height and tip
diameter.
Other flare system costs include the capital costs for purchase and
installation of the vent stream pipe or duct, pipe racks, flare services, and
a vent stream mover. As discussed in Section 8.1.2, 120 m (400 feet) of pipe
or duct supported by pipe racks are needed for the flare system. Flare
services such as natural gas and steam line extensions are also provided.
The purchase costs for these items are included in the flare costing
procedures.1*6
For the flare services, three separate conveyance pipes are needed. It
is estimated that 2-inch diameter lines, each 400 feet in length, will be
needed for steam and natural gas. The costs of Schedule 40, type A-53
grade B seamless carbon steel pipe are used in the cost estimation. In
addition to the pipe costs, the costs of four 90° long radius ells, two globe
valves, and four valve flanges are included. Costs are also included for a
1-inch thickness of fibrous glass pipe covering with fire retardant foil and
a white kraft jacket to prevent significant amounts of steam condensation in
the 2-inch diameter steam line. An additional 400 feet of pipe, 0.5 inches
in diameter, is needed to provide instrument air. The costs of Schedule 40,
type 304L, welded stainless steel pipe are included in the cost estimation.
It is important that the instrument air line be clean and in particular be
free of any particles of rust. Piping generally lies in the field prior to
use in the process plant use. Therefore, stainless steel pipe was costed
because it is resistant to atmospheric oxidation.**7~'*y Finally, the costs of
pipe hangers for all three pipe lines are included in the capital costing
8-14
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TABLE 8-4. FLARE INSTALLATION FACTORS66
Purchased Equipment
Primary and Auxiliary3
Instruments and controls
Taxes
Freight
Subtotal
1.18
Installation
Foundations and supports
Handling and erection
Electrical
Piping
Insulation
Painting
Subtotal
0.57
Indirect Costs
Engineering and supervision
Construction and field
Construction fee
Startup
Performance test
Contingencies
Subtotal
0.35
TOTAL
2.1
Primary and auxiliary represent the cost of the following components:
flare stack, flare tip, pilots, ignition panel, knockout drum, fluidic
seal, and necessary piping at the flare.
8-15
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procedure. The pipe rack costed is described in Section 8.I.2.2.50 The
total installed capital costs for flare services and the pipe rack are
$13,300 (1982 dollars) and $12,000 (1982 dollars), respectively.
The total installed capital costs for the pipe mover systems, in 1982
dollars, ranges from $4,300 for the 1-inch pipe/compressor system to $18,900
for the 6-inch pipe/turbo-blower system. The total capital cost installation
factor is approximately equal to 1.3 for all of the pipe or duct and mover
systems.
For reactor process vent streams with flowrates larger than 11.3 scm/min
(400 scfm), a duct/turbo-blower or duct/fan system is used to transport the
vent stream to the flare base. At a flowrate of 424 scm/min (15,000 scfm),
the total installed ducting cost is estimated to be $33,000 (1982 dollars).
The total installed capital cost for turbo-blowers ranges from $4,400 (1982
dollars) for a vent stream flowrate of 1.2 scm/min (44 scfm) to $11,000
(1982 dollars) for a flowrate of 244 scm/min (8,600 scfm) (1982 dollars).
Total Installed capita! costs for fans range from $7,500 (1982 dollars) at
244 scm/min (8,600 scfm) to $20,000 (1982 dollars) at 679 scm/min (24,000 scfm)
8.3 ANNUAL COSTS
The annual costs of control for thermal incinerator and flare systems
are presented in this section. The basis for calculating the annual costs
for both systems are the same with a few exceptions.
The annual 1 zed costs include direct operating and maintenance costs, and
annualized capital charges. The assumptions used to determine annualized
costs are presented in Table 8-5, and are given in third quarter 1982
dollars. Direct operating and maintenance costs include operating,
supervisory and maintenance labor, replacement parts, utility use, fuel
consumption, and caustic use.51 Utility requirements include electricity
(for compressors, turbo-blowers, and fans), steam for flare operation, and
make-up water for quench system operation. Supplemental natural gas is
required to increase the heating value of vent streams, to maintain pilot
flames, and to purge flare systems. Caustic is required to neutralize acidic
scrubber water. Direct operating, supervisory, and maintenance labor costs
are determined from the design criteria developed for each control system and
the annual cost factors presented in Table 8-5.
Capital charges include annualized equipment costs and indirect costs
for overhead, taxes, insurance, administration and capital recovery.
Annualized equipment costs and capital recovery are based on a 10-year life
for incinerators and a 15-year life for flares.70 Incinerators have a
shorter life expectancy because combustion occurs within the incinerator
chamber and corrosive vent streams are combusted at high temperatures. Under
the design criteria, flares are not used to combust corrosive vent streams.
Also, for flares, combustion occurs outside of the device. Therefore, flares
have a longer life expectancy. A capital recovery is based on a 10 percent
capital charge taken over the 10 or 15-year life span of the equipment. The
assumptions used for capital charges are shown in Table 8-5.
8-16
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TABLE 8-5. BASES FOR ANNUAL I ZED CONTROL SYSTEM COSTS
Direct Operating Cost Factors
Hours of operation (hrs/yr)a 6,745
Total Laborb
(a) Operating laborc (1982 $/hr) 12 05
(b) Supervisory labor i5x of operating labor
fcl M«fn*en«nc« Taoor 3% of total Installed costs
(d) Overhead 80S of a + b + c
Operating Labor (manhours)6
Incinerator 1,200
Incinerator with heat exchanger 2*133
Incinerator with scrubber 2*400
Flare 'JJQ
Pipeline/compressor or duct/fan Q
"mover" system
Utilities and Reagents (1982 $)
Electricity" ($/l,000 kWh) 51 2o
Natural gas" ($/10° Btu, net heating value) 5*75
Quench and scrubbing water (S/1,000 gal)T n°292
Steam (S/1.000 lb}9 , «•«,
Caustic ($/l,000 lb)T 57,89
Maintenance Materials 3% Of total Installed costs
Capital Charges h
Equipment life" (years)
Flares 15
Thermal Incinerator in
Interest rate (percent)] in
Capital Recovery Factor1
(percent of total installed cost)
Flares 13 14
Thermal Incinerator ie]27
Taxes, Insurance, Administration
(percent of total Installed cost) 4
Reference 52.
Reference 56.
GReference 54.
Reference 53.
Reference 67.
Reference 76.
Reference 75.
hReference 56.
Wore tax Interest rate shown.
Capital recovery factor - 1 (1 * i)K - 0.1627 (thermal incinerators)
(1 + 1)n - 1
n - equipment life (10 yrs for Incinerators; 15 yrs for flare)
1 - Interest rate (0.1)
8-17
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To account for reduced production levels and downtime an annual capacity
utilization factor of 77 percent is used.32 This translates into an annual
operating level of 6,745 hrs/yr. Each of the operating cost parameters are
reviewed below.
8.3.1 Labor
A summary of the labor cost basis is presented in Table 8-5. Labor
costs are estimated by considering four categories of labor charges. These
categories are (1) operating labor, (2) supervisory labor, (3) maintenance
labor, and (4) overhead costs. The cost of operating labor was determined by
referring to information provided by the U.S. Bureau of Labor Statistics.51*
This information indicates that the basic labor rate for an industrial
organic chemical worker is $12.05/hour,"based on third quarter 1982 dollars.
Supervisory labor is estimated to be 15 percent of the operating labor cost.
Maintenance labor has been estimated to be equal to 3 percent of the total
installed capital costs of the control system. Finally, overhead charges are
estimated to be 80 percent of the sum of operating, supervisory, and
maintenance labor costs. The sum of all four of. these cost categories are
collectively referred to as the total labor cost. These costs are
representative of the SOCMI and are consistent with the labor costs found in
other references.55"57
The operating labor requirements vary for the different design
categories due to the specific system designs. Thermal incinerator
categories Al and A2 (halogenated streams) require 2,400 man-hours annually
to operate the incinerator, waste heat boiler, and associated scrubber.
Categories B and C (nonhalogenated, low heat content streams) require 2,133
man-hours per year since a scrubber is not part of the system design.
Categories D and E (nonhalogenated, high heat content streams) require the
least amount of labor (1,200 man-hours/yr) since no heat recovery equipment
or scrubber is part of the system. The flare is a much simpler control
device and requires an estimated 630 man-hours of operating labor per year
This includes the labor costs for operating flare services and all auxiliary
equipment.15*
8.3.2 Utilities
The incinerator utilities considered in the annual cost estimates
include natural gas and electricity. For incinerators where heat exchange is
included in the design, natural gas costs are reduced. The cost estimates
for incinerators used to control halogenated streams include a credit for
heat recovery by means of a waste heat boiler. The amount of credit is based
on the amount of energy recovered and the costs of natural gas. For Category
A systems, the utility requirements also include scrubber water, quench
makeup water, and caustic (as 50 percent solution). The caustic requirements
are based on an assumed 1.2 percent chloride by volume in the flue gas to be
treated. The cost associated with disposal of sodium salt from the
neutralized scrubbing water (Categories Al and A2) are not included in the
annualized costs. These disposal costs would vary from facility to facility
but are not expected to be a significant percentage of the total annualized
costs.58
8-18
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Flare utilities considered in the annual cost estimates include natural
gas (for supplemental fuel, purge gas, and pilot gas requirements),
electricity (for operation of compressors, turbo-blowers, and fans), and
steam for smokeless flare operation.
8.3.3 Fuel Requirements for Incinerators
Natural gas use.curves and tables developed from detailed heat and
material balances in an EPA report were used to determine fuel requirements
for incinerators.59'62 Reactor process vent streams belonging to Categories
D and E have a higher heat content and require only a small amount of fuel
for flame stability. The fuel requirement for these streams was assumed to
be equivalent to 0.18 MJ of natural gas heat per standard cubic meter of vent
gas independent of the vent stream heat content. This fuel requirement was
chosen because it is equivalent to that calculated according to the Category
C fuel use equation for vent streams with a heat content of 1.9 MJ/scm (which
is the cutoff heat content distinguishing Categories C and D).
For the halogenated streams in Categories Al and A2, heat and mass
balance calculations for the designated combustion temperature of 1,100°C are
not given in the report mentioned above. Therefore, the fuel requirements
were interpolated from the curves for 980°C and 1,200°C. A fuel use equation
was fit to this interpolated curve. This equation indicated that halogenated
process vent streams in Category A2 with heat contents greater than
3.5 MJ/scm (95 Btu/scf) require primarily auxiliary fuel for flame stability.
At this heat content, according to the fuel use equation, the amount of fuel
required, per standard cubic meter of vent gas is equivalent to 10 percent of
the vent stream heat content.63
Several assumptions are built into the fuel use equations. The most
important is the assumption of no oxygen in the reactor process vent stream
mis leads to combustion air requirements and a total incinerator inlet flow
that will ensure complete combustion and prevent pyrolysis. It also
increases fuel costs.
The design criteria of a maximum heat exchange efficiency of 70 percent
may be too low for some facilities. A thermal incinerator system employing
recuperative heat recovery could achieve a primary heat exchange efficiency
as high as 85 to 95 percent.6" Therefore, facilities able to employ such
technology would have lower fuel requirements than are predicted by these qas
use assumptions.
8.3.4. Fuel Requirements for Flares
Flares used to control reactor process vent streams with heat contents
less than 11.3 MJ/scm (300 Btu/scf) require supplemental fuel. Natural gas
i.s added in order to ensure a 98-percent destruction efficiency in the
combustion of nonhalogenated vent streams. Natural gas is also required for
purge gas and pilot gas requirements.
8-19
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8.3.5 Natural Gas Price
The unit price ($/106Btu) of natural gas was determined by considering
regional variations in natural gas prices and the long term affects of gas
deregulation and other factors which could affect gas prices. Natural gas
prices vary not only with time but also with location. To take this into
account, EPA developed "best estimates" of 1990 natural gas prices in each of
the ten Federal Regions based upon the gross heating value of the gas.65
These prices were than weighted according to the estimated percentage of the
SOCMI located within each region. For each Region, the local natural gas
price was multiplied by the Region's SOCMI production weighting factor.
These products were summed across all Regions to provide an overall natural
gas price (at the gross heating value).
The SOCMI production weighting factor for each region was calculated as
the fraction of chemical production in a region divided by the estimated
total production of SOCMI chemicals in all 10 Federal Regions. The total
chemical production and the chemical production in each region were
determined from 1982 production data in Chapter 9. The total production
capacity of each chemical for which there were available data (i.e., total
capacity data shown in Table 9-1 and predominant plant locations shown in
Table 9-8) were assigned to one of the 10 Federal Regions. The production
capacities of all chemicals assigned to a region were summed to. result in
estimates of chemical production in each region.
Finally, the price was adjusted to the net heating value of the gas.
Previous price estimates were based on the gross heating value. The gross
heating value includes the energy recovered in condensing water vapor formed
during combustion. This does not occur during incineration or flaring;
therefore, the net heating value more accurately reflects the energy
available.
Applying the price weighting method discussed above, the price of
natural gas for reactor processes was estimated" to be $5.20/10* Btu (gross
heating value) or $5.76/106 Btu (net heating value)67*68
8.3.6 Other Annual Costs
The costs for taxes, administration, and insurance are included in the
estimate of annual costs. These three items collectively are estimated to be
4 percent of the total installed capital cost.69
8.4 COMPARISON OF CONTROL SYSTEM COSTS
This section presents and discusses ths capital costs, annualized costs,
average cost effectiveness, and natural gas costs for the application of
incinerators or flares to representative process vent streams. These costs
are determined by applying the costing methodology, developed in the previous
sections, to individual reactor process vent streams contained in the EDP.
8-20
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For a specific combustion control system, capital and annualized costs
vary with varying process vent stream flowrate and heat content. Therefore,
five reactor process vent streams are used as examples to show how the costs
of control vary for vent streams with a wide range of vent stream characteris-
tics. These example cases are selected from the EDP, and represent the
ranges of vent stream characteristics found in the EDP. Stream
characteristics for the five example cases are as follows:
Case 1 - Low flowrate, high heat content;
Case 2 - Low flowrate, low heat content;
Case 3 - High flowrate, high heat content;
Case 4 - High flowrate, low heat content; and
Case 5 - Medium flowrate and medium heat content.
Table 8-6 presents the capital costs, annualized costs, average cost
effectiveness, natural gas cost, and vent stream characteristics for the five
cases selected. All process vent stream characteristics used are based on
data in the EDP. It-should be noted that vent streams free of corrosive
(halogenated) compounds are used so that both incinerators and flares are
applicable to each stream.
Table 8-6 shows that average cost effectiveness for each control system
varies with the reactor process vent stream characteristics. The lowest
cost-effectiveness value shown occurs for the process vent stream (Case 3)
with the highest vent stream energy flow (i.e., (flowrate) x (heat content),
in MJ/min). The cost effectiveness for Case 3 ranges from $53.8/Mg
($48.8/ton) for incinerators to $14.8/Mg ($13.4/ton) for flares. In general,
the low cost effectiveness values for high energy content vent streams are a
result of the large mass of VOC available to support combustion and,
subsequently, the low supplemental fuel costs. Also, relatively large VOC
emission reductions occur for these streams, which greatly decreases cost
effectiveness.
Table 8-6 also shows that the highest cost effectiveness occurs for vent
streams with low energy flow (Case 2). This occurs even though this type of
stream generally has low annualized costs. For Case 2, cost effectiveness
ranges from $150,000/Mg ($137,000/ton) for flares to $622,000/Mg
($565,000/ton) for incinerators. As discussed in the following sections,
application of controls to these low heat content streams results in
moderately low costs but very low emissions reductions. A relatively small
amount of VOC is controlled because of the low VOC content and/or low
flowrates associated with these vent streams.
A comparison of capital costs is not discussed here because to do so
without including the cost impacts for energy consumption would be
misleading. For example, flares have the lower capital costs for all cases
considered but have the lower annualized costs for only four of these example
cases. This is a direct result of the energy costs associated with the fuel
(natural gas) required for stable flare operation. Because of the effect of
8-21
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TABLE 8-6. COST COMPARISONS FOR CONTROL OF EXAMPLE REACTOR PROCESS VENT STREAMS
Item
Annual 1 zed Cost (1982 $/yr)
Flare
Incinerator
Capital Cost (1982 $)
Flare
Incinerator
Cost Effectiveness
($/Mg. ($/ton))
Flare
CO
^ Incinerator
Supplemental Natural Gas Cost
(1982 $/j?r)
Flare
Incinerator
Reactor Process Vent Stream
Characteristics
Flowrate scm/m (scfm)
Heat content MJ/scm
(Btu/scf)
VOC flowrate Kg/hr (Ib/hr)
Case 1
Low Flowrate
High Heat
Content
35,900
225,300
65,200
405.000
605
(550)
3.800
(3,450)
2,810
55.200
0.26
(9.2)
27.9
(747)
8.91
(19.8)
Case 'i
Low Flowrate
Low Heat
Content
45.100
186.500
65.200
386.000
•
150.000
(137.000)
622,000
(565,000)
11,900
22,000
0.25
(8.7)
0.15
(4.0)
0.045
(0.1)
Case 3
High Flowrate
High Heat
Content
106,000
386.000
127,000
• 842.000
14.80
(13.40)
53.80
(48.80)
5,620
105.000
20.6
(729)
45.9
(1.233)
1.086
(2,394)
Case 4
High Flowrate
Low Heat
Content
1.370,000
312.000
148.000
449.000
•
5.060
( 4,600)
1.160
(1.050)
1.210,000
128.000
34.0
(1.200)
0.55
(15)
40.8
. (90)
Case 5
Medium Flowrate
Medium Heat
Content
43.300
180.500
76.900
405,000
2,190
(2.000)
9.120
(8,280)
2,810
10.420
2.0
( 70)
12.0
(323)
3.0
(6.6)
-------
energy consumption on annualized costs, comparison of control system costs
are presented on an annualized basis only.
Figure 8-1 illustrates the total annualized control costs for the five
selected cases. The figure shows that flares are generally less expensive
than incinerators. Specifically, flares are less expensive when applied to
vent streams with low flowrates (Cases 1 and 2) and streams with high to
medium heat contents (Cases 3 and 5). Incinerators have lower annualized
costs when applied to vent streams with high flowrates and low heat contents
(Case 4). High flowrate/low heat content streams require the most
supplemental natural gas. Since the maximum heat content that may be used in
the incinerators considered in this costing analysis is about 100 Btu/scf, as
opposed to 300 Btu/scf for flares, much less gas is used for incinerators.
This explains why the annualized costs for incinerators are lower than the
annualized costs for flares when fuel requirements are high (as in Case 4).
The following is a case-by-case comparison and discussion of the
annualized control system costs. Those cases that have similar cost trends
are grouped together.
Cases 1 and 2. Both cases are characterized by vent streams with low
flowrates.Figure 8-1 shows that for both cases the application of flares
yields lower annualized costs tha-n the application of incinerators. The
relatively low annualized costs for flares is attributed to minimum flowrates
of supplemental fuel required as a result of the low overall flowrates for
these vent streams.
As shown in Figure 8-1, the incinerator system has the higher annualized
cost for Cases 1 and 2. In general, the cost difference is due to the
relatively high equipment costs for incinerators compared to flares. For
both of these low flowrate cases, the minimum size incinerator of
14.2 scm/min (500 scfm) inlet flowrate is applied. As described in
Section 8.1.1, additional dilution air is required to generate sufficient
flue gas for maintaining the design residence time of this minimum size
incinerator when a vent stream smaller than 14.2 scm/min is combusted. The
dilution air also results in additional supplementary fuel being required.
As shown in Table 8-6, the supplemental fuel costs required for incinerator
operation under Cases 1 and 2 range from $22,000 to $55,200/yr.
Case 3. Case 3 represents vent streams with a high energy content and
high rTowrate. Because of the high energy content, these streams require
little or no supplemental fuel for combustion with a flare. For flares, the
contribution of natural gas cost to the annualized cost is about 5 percent.
Annual steam costs are the single largest contributor to Case 3 flare
annualized costs. For thermal incinerators, Case 3 is a Category E stream
that is diluted with air to reduce the heat content to a value of 3.65 MJ/scm
(98 Btu/scf). Prior to combustion, the vent stream has a diluted flowrate
that is increased in volume to 280 scm/min (9,170 scfm). Although auxiliary
fuel is required only for flame stability, natural gas costs are large
8-23
-------
600-
600-
S 400-
CO
i
O s
o o
300-
M
3 2OO
100-
KEY
Caaa 4
High Flowrate
Low Heat Content
NF
1.370.00C
1,210,000
NEW FLARE - NF
NEW INCINERATOR - INC
NATURAL GAS COSTS - yTTTA c->< 3
High Flowrate
High Heat Content
INC
Caae 1
Low Flowrate
High Heat Content
INC
NF ^
rl
Caae 2
Low Flowrate
Low Heat Content
INC
NF
77772
NF
INC
Caae 5
Medium Flowrate
Medium Heat Content
INC
NF
Figure 8-1. Annualized control cost conraaHsons for example reactor process vent streams.
-------
because they are a function of the increased volume of the diluted flow.
Natural gas costs constitute about 30 percent of Case 3 annual i zed costs.
The annual ized capital charges associated with the cost of the incinerator
also contributes a significant portion of the total annual ized costs.
Case 4. Case 4 results in the highest annual ized costs for flares as
compared to the other four cases. In addition, flares are much more
expensive than incinerators because of the supplementary fuel necessary for
flare operation. Figure 8-1 shows that the high annual ized cost of flares is
a direct result of the high energy cost. A large amount of supplemental fuel
is required for both flares and incinerators because the vent stream flowrate
is high, and its corresponding heat content is low. Table 8-6 shows that the
natural gas costs for a flare are $l,210,000/yr, representing about 90 percent
of the total annual ized cost of control, as compared to gas costs of $128,000
for thermal incinerators, representing 40 percent of the annual ized cost.
It is the difference in fuel requirements that drives the annual ized
cost of flares much higher than the cost. of incinerators. The flare cost
procedures require that enough fuel be added to this vent stream to reach a
minimum heat content of 11.2 MJ/scm (300 Btu/scf) while the incinerator
equations add enough fuel to maintain a heat content of approximately
3.7 MJ/scm (100 Btu/scf).
Case 5. Incineration is more expensive than flaring in Case 5 because
of the relatively large capital cost contribution to the total annual ized
costs. For incinerators the capital cost is $405,000, whereas for flares the
capital cost is $76,900. The vent stream characteristics of Case 5 for
thermal incinerators represent a Category E stream. However, because the
flowrate 1s less than 14.2 scm/min (500 scfm) the heat content decreases to
1.7 MJ/scm (45 Btu/scf) after air is added to attain the minimum flowrate of
14.2 son/mi n (see Section 8.1.1.1). The adjusted heat content shifts the
vent stream from Category E to Category C. The natural gas costs represents
less than 6 percent of the total annual ized cost. Incinerator capital costs
are relatively large because a larger combustion volume is required to
incinerate the increased volume of the diluted vent stream.
8.5 NATIONAL COST IMPACTS
Section 8.5.1 describes the method used to calculate the costs of VOC
control associated with each of the regulatory alternatives described in
Chapter 6, and Section 8.5.2 summarizes the national cost impacts of each
regulatory alternative.
S-5-1 Determination of National Cost Impacts
romnc 1" Section 6.3.2.2, a total of 56 new, modified, and
reconstructed reactor process units with vent streams that are not combusted
at baseline are projected to come on-line during the first 5 years of the
£r%+* applicability. In order to calculate national costs of control,
the costs of contra! were first calculated for each of these 56 process
units. For projected process units with vent streams that are nonhalogenated,
8-25
-------
the cost of controlling VOC with either an incinerator or a flare were
calculated. The less expensive of the two control systems, in terms of
annualized cost, was chosen as the basis for the cost impacts analysis. For
process units with halogenated vent streams, only the costs of applying an
incinerator for VOC control were calculated. The costs of applying flares
were not calculated because the use of flares on halogenated vent streams
would result in uncontrolled hydrogen chloride emissions. This problem can
be avoided where incinerators are used by adding a scrubber after the
incinerator.
The costs of applying flares or incinerators to the .56 process units
were calculated based on predicted vent stream characteristics such as
flowrate, VOC content, and halogen content. The vent stream characteristics
for each of the 56 process units were developed as described in Section 6.3.2.3.
The incinerator and flare design criteria and costing procedures described in
Sections 8.1 through 8.3 were used to calculate the annual costs of control
for each of these process unit vent streams.
Once the annual costs of control were calculated, TRE values were
calculated for each of the 56 process units. As discussed in Section 6.3.3,
TRE values were calculated for each process unit by dividing the annualized
cost of combustion control for that process unit by the annual emissions
reduction achievable. (The achievable emissions reductions at each projected
process unit were based on 77 percent capacity utilization and 98-weight-
percent VOC reduction by the control device, as described in Sections 7.2.1
and 8.3).
Regulatory alternatives are defined by specific TRE cutoff values
presented in Section 6.3.3. Under the baseline regulatory alternative, it is
assumed that new, modified, and reconstructed reactor process units are
controlled at the same level as currently operating units producing the same
chemical. Under baseline (in the absence of an NSPS) combustion controls
would not be applied to any of the 56 projected new, modified, and recon-
structed process units. Under the other regulatory alternatives, Alterna-
tives II - IX on Table 8-7, controls are applied to those uncombusted vent
streams with TRE values that are less than a specified cutoff value. For
example, an alternative may consist of control of all new, modified, arid
reconstructed process units with TRE values less than $l,000/Mg of VOC
controlled.
For a given regulatory alternative, the national costs were determined
by summing the costs of applying combustion control to vent streams from each
projected new, modified, or reconstructed process unit which has a TRE value
less than or equal to the TRE cutoff value.
8.5.2 Results of the Cost Analysis
The national cost impacts of each regulatory alternative are shown in
Table 8-7. Costs are expressed in third quarter 1982 dollars. The national
annualized costs represent the cost of control of reactor process VOC
8-26
-------
TABLE 8-7. SUMMARY OF COST IMPACTS AT SELECTED REGULATORY ALTERNATIVES*
Number of
Alternative TRE Cutoff Process Units
Number ($/Mg)D Controlled
I
II
III
IV
V
VI
00
N VII
VIII
IX
0 Baseline
1.200
2.500
5.500
20.000
50.000
200.000
500.000
>500.000
0
4
7
9
21
33
42
46
56
Percent of
National Emissions "Controllable"
(Mg/yr) Emissions Reduced
3.000
2.700
900
800
690
620
610
610
610
0
13
90
91
97
100.
100.
100.
100.
National Annuallzed
Cost (1.000 $/yr)°
0
150
3.700
3.900
4.700
6.700
7.400
8.200
9.300
National Average
TRE ($/Mg) '
-
500
1.700
1.800
2.100
2.900
3.200
3.500
4.000
bCosts are expressed In third quarter 1982 dollars.
Controllable emissions are the 2.400 Mg/yr that would be controlled If all 56 units were controlled at 98-percent destruction
efficiency (I.e.. at the most stringent possible alternative. Alternative IX).
dAt each TRE Cutoff: Nationwide Average TRE ($/Mg) - (National Annuallzed CoSt)/(Basel1ne National Emissions [3.000 Mg/yr] -
National Emissions at given TRE cutoff [Mg/yr]).
-------
emissions attributable to the NSPS in the fifth year after proposal of the
NSPS. These values do not include the costs of reporting, recordkeeping, or
enforcement of the standard. The national annualized costs range from zero
dollars at baseline to $9.3 million under the most stringent regulatory
alternative (control of all 56 projected new, modified, and reconstructed
reactor process units).
The calculation of national VOC emissions and percent of emissions
controlled under each regulatory alternative, shown in Table 8-7, are
discussed in Chapter 7.
The national average TRE under a given regulatory alternative is the
national annualized cost of control divided by the national VOC emissions
reduction due to the given regulatory alternative. The national average TRE
ranges from $0/Mg at baseline to $4,000/Mg under the most stringent
regulatory alternative.
8.6 CONTROL COST ACCUMULATION FOR REACTOR PROCESSES CHEMICALS
8.6.1 Introduction
In 1977, Congress passed the Clean Air Act Amendments, authorizing EPA
to propose new source performance and hazardous air pollutant standards for
industries that pollute the Nation's air. Since 1977, EPA has initiated
action on ten such standards that would directly affect the chemicals that
would be affected by the-reactor processes NSPS. Three of these standards
have been promulgated, four have been formally proposed, and three have been
dropped from consideration. The background information documents (BIDs)
prepared in support of these ten standards examine their economic impacts,
but, with few exceptions, they consider only the costs associated with a
single standard—not the cumulative costs of all applicable standards. This
section aggregates the individual costs of these standards to find their
accumulated economic impact on chemicals that may be affected by the reactor
processes NSPS.
8.6.2 Background—Industry, Standards, and Methodology
8.6.2.1 Reactor Processes Industry. As defined here, the reactor
processes industry consists of facilities involved in the production of any
of 173 chemicals having a minimum national production level of 45.4 Gg/yr,
including both basic and intermediate chemicals used in the production of a
wide range of end products. According to the projections described in
Section 9.1.6, the consumption of only 110 of these chemicals will grow in
the near term. Of these 110 chemicals, only 26 will have vent stream
characteristics that will cause them to be impacted directly by the reactor
processes NSPS under the most stringent regulatory alternative. Table 8-8
lists these 26 chemicals, the estimated number-and size of the facilities
needed to meet projected capacity requirements, the cost of controlling
emissions at each of these facilities, and the total control cost of all the
8-28
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TABLE 8-8. PROJECTED FACILITY SIZE AND COST
FOR 26 REACTOR PROCESS CHEMICALS
Chemical
Adi pic acid
Benzyl chloride
Butyl aery late
n-Butyl acetate
t-Butyl alcohol
t-Butyl hydroperoxide
Chlorobenzene
p-Chl oroni trobenzene
Cyanuric chloride
Diacetone alcohol
Di ethyl benzene
2,4-(and 2,6)-
dinitrotoluene
2,4-Dinitrotoluene
Ethyl acetate
Ethyl acrylate
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
Methyl methacrylate
Nitrobenzene
1-Phenyl ethyl
hydroperoxide
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl trichloride
Number of
projected
facilities
2
1
1
1
8
1
1
1
1
3
1
1
1
4
2
8
3
1
4
1
1
1
2
1
4
1
Size of
projected
facilities,
Gg
236
36
35
23
5
11
68
18
18
7
18
17
80
15
40
318
204
206
95
153
18
18
322
18
193
45
Control
cost
for each
facility,
$ 1982
396,356
386,904
43,548
37,036
38,838
67,840
411,492
381,820
378,900
35,780
36,392
105,019
269,986
41,256
99,742
56,332
1,174,592
169,783
59,394
39,256
214,784
36,392
172,896
61,270
35,776
390,885
Total cost,3
$ 1982
792,712
386,904
43,548-
37,036
310,704
67,840
'411,492
381,820
378,900
107,340
36,392
105,019
269,986
165,024
199,484
450,656
3,523,776
169,783
237,576
39,256
214,784
36,392
345,792
61,270
143,104
390,885
Total cost is projected to the dollar based on the algorithms presented
earlier in Chapter 8. These are the best estimates of possible costs to
control emissions from each chemical. Thus, although these estimates have
not been rounded, the values given do not necessarily imply the precision
usually suggested by nonrounded values.
8-29
-------
facilities projected for each chemical. The number of facilities required
for each chemical is calculated using a specific facility size and the
amount of additional capacity required to meet projected growth in the
consumption of each chemical in the 5-year period following proposal of the
reactor process standard in the Federal Register. Control costs are scaled
according to the size of the specific facility selected for each chemical.
The 26 chemicals listed in Table 8-8 represent the projected set of
potentially impacted chemicals in the 5-year period following proposal of
the reactor processes standard in the Federal Register. The costs for all
26 chemicals at the number of process units projected are summed to yield
the national costs of this standard under the most stringent regulatory
alternative. Under different regulatory alternatives, some or all of the 26
chemicals will not require control because their cost-effectiveness (TRE)
value exceeds the associated cutoff. This cumulative impacts analysis will
examine the impacts of the reactor processes NSPS on the 26 chemicals as
well as the impact of previously proposed and promulgated standards. In
doing so, this analysis will yield worst-case impacts on SOCMI, since it is
likely that fewer chemicals ultimately will be impacted under the regulatory
alternatives finally selected for the reactor processes NSPS.
8.6.2.2 Previous Standards. Proposed and promulgated air pollutant
emissions standards that affect these 26 chemicals are:
NESHAP: Benzene Fugitive Emissions. Promulgated June 6,
1984, 48 FR 12387.
NSPS: VOC Fugitive Emissions in Synthetic Organic
Chemicals Manufacturing Industry. Promulgated
October 18, 1983, 48 FR 48328.
NSPS: VOC Fugitive Emissions in Petroleum Refining.
Promulgated May 30, 1984, 48 FR 22598.*
NSPS: VOC Emissions from Volatile Organic Liquid Storage
Tanks, Proposed July 23, 1984, 49 FR 29698.
NSPS: VOC Emissions from Distillation Process Vents in
the SOCMI industry. Proposed December 30, 1983,
48 FR 57538.
NSPS: VOC Emissions from Air Oxidation Process Vents in
the SOCMI Industry. Proposed October 21, 1983, 48
FR 48932.
*Due to similar control technologies, the SOCMI Fugitive Emissions
NSPS, and the Petroleum Refining Fugitive Emissions NSPS are treated jointly,
and their costs are lumped together.
8-30
-------
NSPS: VOC Emissions from Reactor Processes Vents in the
SOCMI Industry. Currently being proposed.
The first five standards require control technologies that, for the most
part, are independent of the processes used to produce the 26 chemicals.
However, the last two standards, those for air oxidation and the reactor
processes, are production process specific—i.e., defined by the particular
production process used to produce the chemicals. Thus, because some of the
chemicals can be produced by either of the processes, some of the 26 chemicals
are subject to regulation under either standard, depending on the process
used to produce them.
Although proposing both standards ensures the control of VOC emissions
during the production of the 26 chemicals irrespective of production process,
it nevertheless complicates the process of estimating the cumulative impacts
of all the standards affecting SOCMI.
Specifically, because each of the standards assumes that all future
capacity will produce each chemical with only one process, the aggregation
methodology must count the impacts of only one standard, not both, in
estimating the cumulative impact. Otherwise, there is double counting of
the actual control costs imposed, because each chemical will be subject only
to the controls specified for the process used to produce it.
Therefore, to estimate the cumulative costs of all standards affecting
the SOCMI industry, this analysis incorporates the costs associated with
only one of the two process-specific standards. Although, theoretically,
the costs of either standard would function equally well, those associated
with the reactor process standard are used here because, as shown in Section
9.1.6, they were derived using more specific information on all the 26
subject chemicals.
8.6.2.3 Methodology. The basic methodology employed to generate the
cumulative annualized control costs is summarized below:
o All control costs are standardized to mid-1982 dollars.
o Costs are annualized by a capital recovery factor and a 10 percent
real interest rate.
o All control costs are incremental and do not include the cost of
pollution control equipment already in place.
Control costs are cumulated for all reactor process chemicals that
have projected growth, have process vents, and are uncombusted at
baseline.
For the NESHAP regulation, control costs derived from model plants
are multiplied by the number of existing facilities affected.
8-31
-------
o Where future facilities are concerned, the fifth-year total
annualized control costs for model facilities are used for
accumulation. Fifth-year annualized costs refer to the control
costs expected to be incurred by society in the fifth year after
proposal of each standard in the Federal Register. The fifth year
will vary among potential regulations because the dates of pro-
posal in the Federal Register vary. This analysis standardizes
fifth-year costs by assuming that the fifth year is 1990, the
fifth year of the proposed reactor processes standard. This is
accomplished by multiplying the estimated per-facility cost of
each standard by the number of facilities projected to come
on-line between 1985 and 1990 for the 26 chemicals (see Table
8-8).
o Only the EPA Administrator's recommended regulatory alternative is
considered when accumulating costs for the previously proposed and
promulgated standards. If the most stringent regulatory alternative
were considered, the cumulative cost estimates would reflect
unreasonably extreme values for calculating the impacts on the 26
chemicals. By considering the potential impacts on all 26 reactor
processes chemicals, EPA has already established an extreme set of
chemicals to use for the analysis, but not an unreasonable one.
However, by employing the worst possible costs of each regulation
for the largest possible set of chemicals impacted under the
reactor processes standard, a grossly overexaggerated impact on
the 26 chemicals would occur. While it is'important to analyze
potential impacts under extreme conditions, it is impractical to
make those conditions unrealistic.
o The costs that are cumulated in this section are the direct costs
of the various SOCMI standards. In Section 9.3.3, both direct and
indirect costs are used to examine price impacts. The indirect
costs are those that are rolled-through from ope producer to
another.
8.6.3 Data and Assumptions for Accumulating Costs
This section presents the specific data and assumptions used for each
of the proposed and promulgated standards to estimate cumulative costs for
the 26 reactor processes chemicals. The discussion for each standard
includes information on sources of cost data and the per-facility costs
associated with the relevant regulatory alternatives. Control costs for the
benzene fugitives NESHAP are broken down into per-facility costs for existing
facilities and per-facility costs for future facilities and then are aggregated
in Table 8-9. Control costs for the other NSPS are simply per-facility
costs for future facilities, except those for the reactor processes NSPS,
which is-costed on a chemical-specific basis. The control costs of each
regulation are presented in Table 8-10 in the base-year dollars of the *
particular standard. Section 8.6.5 below presents the converted control
costs of each regulation in the common base year, mid-1982 dollars. The
costs in Table 8-10 are converted by a procedure described in Section 8.6.4.
8-32
-------
TABLE 8-9. FACILITY-SPECIFIC COSTS OF THE BENZENE FUGITIVE EMISSIONS
NESHAP FOR BENZENE-CONSUMING REACTOR PROCESSES CHEMICALS
WITH PROJECTED CAPACITY ADDITIONS
Chemical
Chlorobenzene
Existing
facilities9
3
Cost per
existing.
facility0
($)
8,700
New
facilities0
1
Cost per
new .
facility0
($)
18,200
Total cost
($)
44,300
Ethyl benzene
Nitrobenzene
14
6
8,700
8,700
8
1
18,200
18,200
267,400
70,400
Reference 71.
°Cost to existing facilities will be $8,700 based on the average of the model
facilities for Regulatory Alternative III in the benzene fugitive emissions
EIS. Cost to future facilities will be $18,200 based on the average of the
model facilities for Regulatory Alternative IV.
cSee second column in Table 8-8.
8-33
-------
TABLE 8-10. ANNUALIZED CONTROL COSTS IN FIFTH YEAR* AFTER PROPOSAL FOR FOUR AIR QUALITY
STANDARDS BASED ON FACILITY PROJECTIONS FOR 26 REACTOR PROCESSES CHEMICALS0
Benzene
Number of fugitive
projected NESHAP
Chemical facilities (1979 $)
Adipic acid
Benzyl chloride
Butyl aery late
n- Butyl acetate
t-Butyl alcohol
t-Butyl hydroperoxide
Chlorobenzene
p-Chloronitrobenzene
00
do Cyanuric chloride
Di acetone alcohol
Di ethyl benzene
2,4-(and 2,6)-Dinitrotoluene
2 ,4-Di ni trotol uene
Ethyl acetate
Ethyl aery late
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
Methyl methacrylate
2
1
1
1
8
1
1 44,300
T •• —
1
3
1
1
1
4
2
8 267,400
3
1
4
VOC
fugitive
NSPS .
(1978 $)a
26,800
13,400
13,400
13,400
107,200
13,400
13,400
13,400
13,400
40,200
13,400
13,400
13,400
53,600
26,800
107,200
40,200
13,400
53,600
VOL
storage
NSPS
(1982 $)e
4,962
2,481
2,481
2,481
19,848
2,481
2,481
2,481
2,481
7,443
2,481
2,481
2,481
9,924
4,962
19,848
7,443
2,481
9,924
Distillation
NSPST
(1978 $)
141,600
70,800
70,800
70,800
566,400
70,800
70,800
70,800
70,800
212,400
70,800
70,800
70,800
283,200
141,600
556,400
212,400
70,800
283,200
See footnotes at end of table.
(continued)
-------
TABLE 8-10 (continued)
Chemical
Nitrobenzene
Number of
projected
facilities
1
Benzene
fugitive
NESHAPC
(1979 $)
70,400
1-Phenyl ethyl hydroperoxide 1
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl trichloride
Fifth-year costs are
^ the other regulations
^ number of facilities
*** **C^ — *"1 ^ 4-.. «., *_ j."
1
2
1
4 •
1
—
—
—
—
—
voc
fugitive
NSPS '
(1978 $)a
13,400
13,400
13,400
26,800
13,400
53,600
13,400
VOL
storage
NSPS
(1982 $)e
2,481
2,481
2; 481
4,962
2,481
9,924
2,481
Distillation
NSPS
(1978 $)
70,800
* 70,800
70,800
141,600
70,800
283,200
70,800
assigned for reactor processes control period 1985-1990. The cost per chemical for
are 1990 fifth-year costs in that their per-facility costs are multiplied by the
projected in the reactor processes analysis to come on-line in the 5-year period.
Facflity projections for reactor processes chemicals assume that all capacity added to accommodate
chemical growth is capacity to produce that chemical by reactor processes only. See Table 9-17.
cSee Table 8-9.
Cost per facility is $13,400. Total cost equals 13,400 times the number of facilities in the
first number column and represents the costs for both NSPS's.
eCost per facility is $2,481. Total cost equals 2,481 times the number of facilities in the
first number column.
Cost per facility is $70,800. Total cost equals 70,800 times the number of facilities in
the first number column.
-------
8.6.3.1 Benzene Fugitive Emissions NESHAP. Cost data are from the
draft Environmental Impact Statement (EIS) entitled "Benzene Fugitive
Emissions—Background Information for Proposed Standards," November 1980
(EPA-450/3-80-032a).70 Cost data in the EIS are in May 1979 dollars. The
benzene NESHAP would affect only those chemicals in the list of 26 reactor
processes chemicals that are benzene consumers. Table 8-9 presents the
three chemicals that fall into this category, along with the cost to control
current and future facilities.
EPA promulgated Regulatory Alternative III for existing sources
(46 FR 1175). This alternative, which requires the installation of certain
equipment and monthly monitoring for detection of leaks, is expected to
reduce benzene fugitive emissions by about 70 percent. EPA promulgated
Regulatory Alternative IV for new sources (46 FR 1177) and estimates an
emissions reduction of about 80 percent for this alternative. The estimated
cost per existing facility is $8,700, which is the weighted average of the
cost to three model facilities chosen by EPA for the analysis. The annualized
cost of control for model facility A is $7,400, and it is estimated that
62 percent of existing benzene-related production units are represented by
model A. The annualized cost of control for model B is $9,700, and this
model is representative of an estimated 31 percent of existing production
units. Model C's annual cost of control is $15,200, and it represents
7 percent of existing units.
The estimated cost per facility for new facilities for Regulatory
Alternative IV is $18,200, which is also a weighted average of the same
three model facilities. Model A is estimated to incur control costs of
$12,000; model B, $25,700; and model C, $39,000. The analysis assumes that
new facilities will follow the same distribution as the current population.
Table 8-9 shows the number of plants currently producing each of the
affected chemicals artd the cost per facility of controlling those existing
plants, $8,700. The table also shows the number of reactor processes
facilities that are projected to be built between 1985 and 1990 for the
three chemicals. The per-facility cost of $18,200 for new facilities is
multiplied by this number and added to the total cost for existing facilities
to derive the total cost of the benzene emissions standard on this subset of
the 26 reactor processes chemicals. Table 8-10 presents these totals in the
context of the costs for all the standards affecting the 26 reactor processes
chemicals.
8.6.3.2 VOC Fugitive Emissions in SOCMI and Petroleum Refining
Fugitive Emissions NSPS.Cost data are from the draft EIS entitled "VOC
Fugitive Emissions in Synthetic Organic Chemicals Manufacturing Industry-
-Background Information for Proposed Standards," November 1980
(EPA-450/3-80-033a).72 Cost data in the EIS are in fourth-quarter 1978
dollars and are assumed to represent the costs of control from both NSPS.
The VOC fugitive emissions NSPS would affect all 26 reactor processes
chemicals.
8-36
-------
EPA promulgated Regulatory Alternative IV (46 FR 1136). The annualized
cost of this alternative is $13,400 per facility for installing equipment to
control VOC emissions. The figure of $13,400 is an average of three model
facilities weighted by the percentage of current facilities that most
resemble each model facility. The annualized cost of control for model
l*?\£y ATuS $7'900i for mode1 ^cility B, $13,300; and for model facility C,
$33,000. The VOC fugitive emissions EIS estimates that 52 percent of
existing facilities are similar to model A, while 33 percent resemble B, and
15 percent resemble C. It is assumed that future facilities will resemble
each model plant in the same proportions as current facilities.
To arrive at chemical-specific costs of control, the $13,400 per-facility
annualized control cost is multiplied by the number of new sources shown in
Table 8-8. The total cost for each chemical for the control of its fugitive
emissions of VOC is given in Table 8-10.
* !:6^-3^Vgl^t1le.°rg!n!c^1Su1d storaq.e Tanks NSPS. Cost data are
from the draft US entitled "VOC emissions from Volatile Organic Liquid
Storage Tanks—Background Information for Proposed Standards," June 1983
(EPA-450/3-81-003a).73 Control costs are in 1982 dollars in the EIS. The
Volatile Storage NSPS would affect all 26 chemicals.
EPA recommends Regulatory Alternative IV from the draft EIS. The total
annualized cost of control for the entire industry is assumed to be $1 68
million to be incurred by an estimated 677 expansion and replacement tanks
This figure comes from Tables 9-15 and 9-20 in the VOL storage draft EIS,
which gives the total number of projected storage tanks to be built in the
5-year period after proposal and the percentage of this number that will
require control technology. If total annualized cost to the industry is
split equally among these 677 sources, a cost of $2,481 per tank will be
incurred.
To arrive at chemical-specific costs, the $2,481 cost per tank is
multiplied by the projected number of new sources for each of the 26 chemicals
(see Table 8-10).
Iin. S;?'3:4 Distillation NSPS. Cost data are from the draft EIS entitled
Distillation uperations in Synthetic Organic Chemical Manufacturing-
-Background Information for Proposed Standards," December 1983
(EPA-450/3-83-005a).71* Cost data in the EIS are in fourth-quarter 1978
dollars. The Distillation NSPS would affect all 26 chemicals.
Control costs per facility are calculated under two separate sets of
control conditions. Worst-case conditions reflect extreme assumptions about
the number of columns, the flow rate for the vent streams, the energy
requirements and recovery during VOC combustion, and the number of
incinerators, all of which cause the per-facility cost to be an overstated
maximum value. Most-likely conditions reflect the control costs that are
most likely to prevail at affected plants in the industry. These conditions
8-37
-------
are based on a flare preference for VOC combustion, and a 98-percent VOC
emissions reduction alternative. The control costs associated with these
most likely conditions are used. The control cost per facility under these
conditions is $70,800.
To estimate chemical-specific annual fifth-year costs of control of
distillation columns for the fifth year of the reactor processes standard,
the annual cost of $70,800 is multiplied by the number of facilities projected
to come on-line in the 1985 to 1990 period for each of the 26 chemicals.
The total annual cost in the fifth year for each chemical for the control of
its distillation column is given in Table 8-10.
8.6.3.5 Reactor Processes NSPS. Cost data are obtained from the
emissions data profile (EDP) in Section 3.3 and from the sizes of projected
facilities in Section 9.1.6 of this document. Cost data are in 1982 dollars.
The cost data in the EDP are scaled to the specific projected facility sizes
for each chemical. Table 8-8 shows the cost for each projected facil-ity,
and these are the costs used in the cumulation procedure for this analysis.
Section 8.2 presents a more detailed description of the cost methodology.
8.6.4 Cost Conversion
To present a standardized figure for total accumulated cost for the 26
reactor processes chemicals, all cost figures for the various regulations
are converted by appropriate price indices to the 1982 dollars used in this
reactor processes NSPS.
Costs for the benzene fugitive emissions NESHAP are presented in
second-quarter 1979 dollars. The chemical equipment cost index for second
quarter 1979 is 592.0 (1926 = 100); for mid-1982, the index is 763.2.
Therefore, the costs in Table 8-9 for the three chemicals affected by the
benzene NESHAP are multiplied by 763.2/592.0 to update the costs to 1982
dollars.
Costs for the VOC fugitive emissions NSPS and for the distillation NSPS
are presented in fourth-quarter 1978 dollars. The chemical equipment cost
index for fourth quarter 1978 is 560.4 (1926 = 100). To update the costs
associated with this regulation to mid-1982 dollars, a scalar of 763.2/560.4
is multiplied by all costs in the respective totals column of these standards
in Table 8-10.
Costs for the VOL storage tanks NSPS are presented in mid-1982 dollars,
and therefore no conversion is necessary for these costs. As mentioned
above, costs for the reactor processes NSPS are also presented in 1982
dollars and no conversion is necessary for them either.
8-38
-------
8.6.5 Presentation of the Cumulative Impact of Seven Clean Air Act
Standards on the SOCMI IndusTry
The costs in the totals column for the seven standards in Table 8-10
are multiplied by the appropriate indices to give the converted costs by
chemical for each standard shown in Table 8-11. These standardized fifth-year
annualized costs are then aggregated to get the total cost of the proposed
and promulgated standards that affect each chemical potentially impacted by
the reactor, processes NSPS. The total cumulated costs for the 26 subject
chemicals in Table 8-11 is 16.3 million dollars, and the cumulated cost for
each chemical ranges from 88,000 to 3.9 million dollars. The impacts of
these costs for each chemical are examined in detail in Section 9.4.
8-39
-------
TABLE 8-11. ANNUALIZED CONTROL COSTS3 IN FIFTH YEARb AFTER PROPOSAL
FOR SEVEN AIR QUALITY STANDARDS BASED ON FACILITY PROJECTIONS
FOR 26 REACTOR PROCESSES CHEMICALS
(1982 $)
Annual 1 zed control
Benzene VOC
fugitive fugitive
Chemical NESHAPC NSPSQ»e
Adi pic acid
Benzyl chloride
Butyl aery late
n- Butyl acetate
t-Butyl alcohol
t-Butyl hydro-
peroxide
Chlorobenzene
p-Chloro-
nitrobenzene
Cyanuric
chloride
Di ace tone
alcohol
Di ethyl benzene
2,4-(and 2,6)-
Dinitrotoluene
2,4-Dinitro-
toluene
Ethyl acetate
Ethyl acrylate
Ethyl benzene
Ethyl ene oxide
See footnotes at
36,502
18,251
18,251
18,251
146,008
18,251
57,103 18,251
18,251
18,251
54,753
18,251
18,251
18,251
73,004
36,502
344,678 145,008
54,753
end of table.
VOL
storage
NSPS
4,962
2,481
2,481
2,481
19,848
2,481
2,481
2,481
2,481
7,443
2,481
2,481
2,481
9,924
4,962
19,848
7,443
costs
Distil-
lation
NSPSa
192,860
96,430
96,430
96,430
771,440
0
96,430
96,430
96,430
289,290
96,430
96,430
96,430
385,720
192,860
771,440
289,290
Reactor
processes
NSPST
792,712
386,904
43,548
37,036
310,704
67,840
411,492
381,820
378,900
107,340
36,392
105,019
269,986
165,024
199,484
450,656
3,523,776
Total
cumulated
cost
1,027,036
504,066
160,710
154,198
1,248,000
88,572
585,757
498,982
496,062
458,826
153,554
222,181
387,148
633,672
433,808
1,732,630
3,875,262
(continued)
8-40
-------
TABLE 8-11 (continued)
Annualized control costs
Benzene
VOC
Chemical
VOL Distil-
fugitiye fugitive storage lation
NF<;HAPC MCDCa»e NSPS ucncU
Reactor Total
)rocesses cumulated
NSPST cost
Isopropyl alcohol
Methyl metha-
crylate
Nitrobenzene
1-Phenylethyl
hydroperoxide
90,745
18,251 2,481 96,430 169,783 286,945
73,004 9,924 385,720 237,576 706,224
18,251 2,481 96,430 39,256 247,163
18,251 2,481 96,430 214,784 331,946
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl tri-
chloride
Total
18,251
36,502
18,251
73,004
18,251
2,481
4,962
2,481
9,924
2,481
96,430
192,860
96,430
385,720
96,430
36,392
345,792
61,270
143,104
390,885
153,554
580,116
178,432
611,752
508,047
16,264,643
All ** A«h ^ 4» A Lb A. ._ ._.„.._ * ^ f\4+ f\ 1 ^ ^ ^»
All costs shown are in 1982 dollars. These costs are projected to the last
dollar based on algorithms presented in the Draft EISs associated with each
standard and because of converting the costs to 1982 dollars. These cost
estimates are the best available but should not be taken literally as their
numerical precision suggests they should.
Fifth-year costs are assigned for reactor processes control period 1985-
1990. The costs per chemical for the six other regulations are 1990
fifth-year costs in that their per-facility cost is multiplied by the
number of facilities projected to come on-line in the 5-year period.
Cost index to convert original costs for this standard from second quarter
1979 dollars to mid-1982 dollars is 763.2/592 = 1.289.
Cost index to convert original costs for this standard from fourth-quarter
1978 dollars to mid-1982 dollars is 763.2/560.4 = 1.362.
Q
These costs represent both SOCMI Fugitives and Petroleum Refining Fugitives
M3rJ S•
These costs of control are associated with production by reactor processes
(which is mutually exclusive of production by air oxidation) and therefore
represents the costs of both standards.
8-41
-------
8.7 REFERENCES
1. U. S. Environmental Protection Agency. Organic Chemical Manufacturing
Volume 4: Combustion Control Devices. Research Triangle Park, N C
Publication No. EPA-450/3-80-026. December 1980. Report 2. pp. III-l
to 111-17.
2. Reference 1, Report 1, p. 1-2.
3. Reference 1, Report 1, p. 1-2.
4. Reference 1, Report 1, p. 111-19.
5. Telecon. Rentz, J. ABCO Industries, Inc. with McKenzie, I., Radian
Corporation. January 18, 1985. Conversation about minimum size of
waste heat boilers.
6. Letter and attachment from McKenzie, I., Radian Corporation, to R.
Rosensteel, EPA. February 6, 1985. Removal of a waste heat boiler for
flowrates less than 700 scfm.
7. Reference 1, Report 1, p. III-2.
8. National Fire Protection Association. Fire Protection Handbook.
Section 9/Chapter 12, Processing Equipment^pp. 9-57 to 9-58.
9. Baasel, W. D., Chemical Engineering Plant Design. Oil Insurance
Association. Elsevier Publishing (New York 19/2). pp. 143-145.
10. Reference 1, Report 2, pp. III-7 and III-ll.
11. Richardson Engineering Services, Inc. Process Plant Construction
Estimating Standards. V. 2. Section 5-12, pp. 1-5; Section 5-0, p. 1.
12. Reference 1, Report 2, p. II-6.
13. Reference 1, Report 1, pp. 111-19 to 21.
14. Reference 1, Report 2, p. 11-6.
15. Reference 1, Report 1, p. III-B.
16. Memo from Desai, T., EEA. to Air Oxidation File. April 2, 1981.
Preheat temperature for combustion air and VOC offgas stream using a
recuperator.
17. Reference 1, Report, 1, p. III-B.
8-42
-------
18. Reference 1, Report 2, p. 1-2.
19. Memo and attachment from Mulchandi, B., EEA. to J. Galloway, EEA.
October 29, 1980. Calculations for the cases where only combustion air
is preheated by outgoing flue gas.
20. Memo from Sarasua, A., EEA, to Polymers and Resins NSPS file. May 12
1982. Flare cost program (FLACOS) documentation.
21. Kent, G. R., "Practical Design of Flare Stacks," in Waste Treatment and
Flare Stack Design Handbook. Gulf Publishing Company"!(1968).
22. Reference 20.
23. Straitz, J. F., (National Oil Burner Company, Inc.) Nanogram for
determining proper flare-tip diameter, Part 1. (In-house brochure)
Philadelphia, PA. July 1979.
24. Straitz, J. F. (National Oil Burner Company, Inc.) Nanogram for
determining proper flare-tip diameter height, Part 2. (In-house
brochure). Philadelphia, PA. July 1979.
25. Reference 20.
26. Reference 8.
27. Reference 9.
28. Reference 11.
29. Telecon. McKenzie, I., Radian Corporation, with T. Bobbitt, Gulf Stream
Air Inc., February 15, 1985. Conversation about flowrate operating
ranges for turbo-blowers and fans.
30. Memo from McKenzie, I., Radian Corporation, to file. October 23 1984
Duct pressure drop calculation sheet.
31. Telecon. Beck, D.A., EPA/Chemicals and Petroleum Branch with D. Shore,
Flaregas Corporation. December 6, 1984. Conversation about flare
system pressure drop estimations.
32. Reference 11.
33. Reference 1, Report 2, pp. V-14 to V-15.
34. Reference 1, Report 4, p. V-5.
8-43
-------
35. Richardson Engineering Services, Inc. Process Plant Construction
Estimating Standards. V.3. Section 15-43, pp. 1, 9, 23, 29, 30;
Section 15-72, p. 1; Section 15-70, p.4; Section 15-42, pp. 1, 20, 25,
36. Letter from Bobbitt, T., Gulf Stream Air Inc., to I. McKenzie, Radian
Corporation. January 15, 1985. Technical and budgetary information.
37. Chemical Engineering. Volume 87, No. 5. March 10, 1980. p. 7.
38. Chemical Engineering. Volume 89, No. 21. October 18, 1982. p. 7.
39. Chemical Engineering. Volume 90, No. 1. January 10, 1983. p. 7.
40. Reference 1, Report 2, pp. III-l to 111-17.
41. Reference 1, Report 2, pp. II-2 to II-4.
42. Memo from Galloway, J., EEA, to air oxidation NSPS file. August 8,
1980. Retrofit costs for thermal incineration.
43. Reference 41.
44. Reference 1, Report 2, pp. III-l to 111-17.
45. Reference 1, p. IV-4.
46. Reference 35.
47. Reference 35.
48. Reference 35. Section 15-17, pp. 1, 7, 8, 10, 25, 26.
49. Reference 35. Section 15-80, p. 1.
50. Reference 35. Section 15-76, pp. 2, 37.
51. Reference 16.
52. Memo from Robson, J., EPA/Economics Analysis Branch, to file.
February 21, 1985. Capacity utilization rates used in the synthetic
organic chemical reactor processes NSPS 83-12.
53. Department of Energy. Monthly Energy Review. DOE/EIA-0035(83/04).
"Electricity Price, September 1982". p. 92.
8-44
-------
54. U.S. Bureau of Labor Statistics. DIALOG File 178. Average Hourly
Earnings of Production Workers. Industrial Organic Chemicals. Q3 1982.
55. Vatavuk, W.M. and R.B. Neveril. Part II: Factors for Estimating Capital
and Operating Cost. Chemical Engineering. November 3, 1980. p. 160.
56. Reference 55.
57. Neveril, R.B. (6ARD, Inc.) Capital and Operating Costs of Selected Air
Pollution Control Systems. Prepared for U.S. Environmental Protection
Agency. Research Triangle Park, N.C. EPA 450/5-80-002. December 1978.
58. Memo from Piccot, S. D. and S. A. Lesh, Radian Corporation, to file.
May 29, 1985. Disposal of brine solutions from wet scrubbers.
59. Reference 1, Report 1, p. II1-8.
60. Reference 1, Report 2, pp. III-l to 111-17.
61. Memo from Galloway, J., EEA, to SOCMI air oxidation NSPS file.
September 1, 1980.
62. Reference 16.
63. Reference 1, Report 1, p. 11-10.
64. Letter from Berres, J., REECO, to Don R. Goodwin, EPA. July 14, 1981.
Comments on draft Air Oxidation BID.
65. Memo from Short, R., EPA/Economics Analysis Branch to W. Harnett,
EPA/Standards Development Branch. January 28, 1985. Projected natural
gas prices.
66. Reference 55, p. 158.
67. Memo from Lesh, S. A., Radian Corporation to file. January 28, 1985
Natural gas prices weighted by SOCMI production capacities in the EPA
Regions. Calculation sheets.
68. Memo from McKenzie, I. M., Radian Corporation to file. October 11
1984. Natural gas net heating value calculation.
69. Reference 55.
70. U. S. Environmental Protection Agency, Office of Air Quality Planning
and Standards. Benzene Fugitive Emissions, Background Information for
Proposed-Standards. Draft EIS. Publication No. EPA-450/3-80-032a.
November 1980. pp. 8-36 - 8-39.
8-45
-------
71. Memo from Reinhardt, B., Research Triangle Institute, to Reactor
Processes File. February 22, 1985. Regulatory flexibility analysis.
72. U. S. Environmental Protection Agency, Office of Air Quality Planning
and Standards. VOC Fugitive Emissions in Synthetic Organic Chemicals
Manufacturing Industry, Background Information for Proposed Standards.
Draft EIS. Publication No. EPA-450/3-80-033a. November 1980.
pp. 8-14 - 8-16.
73. U. S. Environmental Protection Agency, Office of Air Quality Planning
and Standards. VOC Emissions from Volatile Organic Liquid Storage
Tanks, Background Information for Proposed Standards. Draft EIS.
Publication No. EPA-450/3-81-003a. June 1983. pp. 9-30 - 9-43.
74. U. S. Environmental Protection Agency, Office of Air Quality Planning
and Standards. Distillation Operation in Synthetic Organic Chemical
Manufacturing Industry, Background Information for Proposed Standards.
Draft EIS. Publication No. EPA-450/3-83-005a. March 1983.
pp. 1-1 - 1-30.
75. Devitt, T. P., Sparte, and L. Gibbs. Population and Characteristics of
Industrial/Commercial Boilers in the U. S. Prepared for the U. S.
Environmental Protection Agency, Research Triangle Park, NC.
Publication No. EPA-600/7-79-78a. August 1979.
76. Reference 74, p. 8-13.
8-46
-------
CHAPTER 9
ECONOMIC ANALYSIS
9.1 INDUSTRY PROFILE
This profile of the Synthetic Organic Chemical Industry (SOCMI) contains
a general description. of the industry and detailed industry statistics and
growth projections. Material is presented in six sections. The first
section describes the SOCMI as a whole and defines the reactor processes
segment of the industry. The next four sections describe supply and demand
market structure, prices, and market performance, respectively. The sixth
section contains growth projections through 1990. Most data used in the
profile are current through 1982.
9.1.1 Industry Overview
9-1-1-1 Definition of SOCMI. The chemicals of concern here largely
fall into Standard Industry Classification (SIC) category 286, Industrial
Organic Chemicals. SIC 286 is part of a broader classification, Chemicals
and Allied Products, which also includes industrial inorganic chemicals,
polymers, Pharmaceuticals, agricultural chemicals, and other products Where
data for organic chemicals are unavailable for this profile, information for
Sf!!iCJ *J rJ -edipV°iucts 1s often used' In other Places> The Kline
Guide to the Chemical Industry! is used. The Kline publication uses a
definition of the chemical industry that excludes allied chemical products
but includes petroleum refining, metal industries, and photographic equipment
with industrial chemicals, polymers, and agricultural products. Data presented
are generally for the area including the 50 States, the District of Columbia,
and Puerto Rico.
R^-ir^hf-0 ?hem1cals ma> be classified as basic, intermediate, or end-product.
Basic chemicals- are produced directly from petroleum, coal, natural gas, or
living matter. These chemicals are used in the production of intermediate
chemicals, which are subsequently used in the manufacture of a number of
end-product chemicals.
HW J??1 1S ? ^complex industry, currently producing more than 7,000
different chemicals.2 Organic chemicals are widely used in manufacturing and
other industries, for example, as inputs in polymer production, pharmaceu-
Zl* als',co" structlon, and automotive products. The bask-to-intermediate-to-
end-product classification has some limitations because of these disparate
9-1
-------
uses: a number of chemicals may be used for some purposes as intermediate
chemicals and for others as end-product chemicals. Also, since many chemicals
can be produced by several processes, it is often possible to substitute one
input for another as price changes dictate.
The interdependence of the chemicals and the variety of end uses to
which they can be put makes SOCMI, like the chemicals industry as a whole,
difficult to describe. This interdependence has influenced the structure of
the industry, encouraging vertical integration among chemical firms. These
firms have found it profitable to expand in the industry both forward from
industries such as petroleum and agriculture and backward from industries
such as Pharmaceuticals and paint goods. Expansion of chemical companies to
nonchemical areas is also common.
Total SOCMI production as reported by the U.S. International Trade
Commission (USITC) for 1982 was 135,683 Gg, of which 67,920 Gg were sold for
$54,270 million.3
9.1.1.2 Description of the Reactor Processes Chemical Group. SOCMI is
subdivided into sectors according to production process.Though the number
of chemicals produced by SOCMI is large, as noted in Chapter 3, a small
percentage of chemicals accounts for most of the industry's total production.
These few chemicals are primarily produced by reactor, or conversion,
processes, which alter the molecular structure of chemical compounds.
Because these few chemicals so dominate industry output, the scope of the
SOCMI standards development effort is designed to cover only these chemicals.
Thus, this study considers only those reactor processes chemicals with a
national production level of 45.4 Gg/yr or highei—173 synthetic organic
chemicals.
Table 9-1 summarizes 1982 data for the 173 chemicals,l+~10 including
national production and capacity, imports and exports, and prices. In
general, these data provide an overview of the chemicals and are used as
bases for some of the industry growth projections presented in Section 9.1.6.
Where specific data are unavailable, spaces in the table are left blank.
Most sources for the data in Table 9-1 provide 1982 information, although
some list only older data. These outdated data are included in the table but
are updated in the subsequent projections analysis to be consistent with the
other 1982 data.1*'10 Where 1982 import and export data are not_available,
they are estimated from the most recent preceding year's data.1*"5 Estimates
are made assuming that 1982 imports and exports maintained the same percentage
relationship to total consumption that they did in the year of the most
recent available data. Average 1982 list prices are tabulated if
available,1*'5 or an average of four spot prices reported in the 1982 Chemical
Marketing Reporter is used.5 For some chemicals, chemical-specific or
end-use group average 1978 prices from the distillation operations background
information document (BID) are used.11 These prices are updated to 1982
prices using equipment cost indices.12
9-2
-------
IABLE 9-1. PROUUCTION. FOREIGN IRAOE, AND PRICES* FOR 1/3 HIAC IOK PROCESSES
CHEM1CAI S UNITED STATES Iule& on last page of
End-
use
group
GN
PF
PF
GN
PE
PF
PF
SE
PF
SE
GN
GN
GN
GN
GN
GN
PF
BC
GA
OS
GA
PF
SE
PF
SE
PL
BC
GN
GN
SO
CO
CO
GN
SO
GN
GN
PI
DC
PF ,
I'F
table
Production,
Gg/yr
181
1248
499
797f
495
134
1289
926
680
51f
314
82f
261
3548
54
240
828
488f
455
780*
136f
1811
UB"
bl
314
f
I54f
255
Capacity,
Gg/yr
454
1905
698
1361
143
354h
1175
803
1361"
299
327fl
581
7761
236
82
374
2107
2144f
/I/'
163
3014
6H
53b
458"
3/0
bUb'1
I'Jll'
Wf}
/v1
Imports
Exports
Percentage of Percentage of ChemiraJ
Utilization domestic domestic - H!-i£*._ .
Average, X Gg/yr production Uy/yr production 4/ku, «/lb
40 0 0
66 05 0
71 9 2
58 52 6
94
79 0 0
85 5 1
45 0 0
45 447 13
61
64 0 0
39
23f
64 '
83 f
bO Ib 1
/bOO
b9 3 9
/•' o o
HI1
14"
0 0 /b
52 ' 4 b8
9 2 90
00 bb
121
lib
364 39 99
16 2 132
100
106
121
121
12b
00 84
121 3 46
112
104
92
19 8 134
61
100
b/
n
2'J
1/2
220 12 /3
I'.iU
IH 15 106
3'J 12 10
Ib'J
9'J
bb
IH
42
100
34
26
41
30
55
52
45
60
45
48
bb
bb
b/
38
21
5l"
4/1
42
61
4Jb'
30*'
35
13
/8
33
bU
48
\?
12
3b
45
30
I/'
I'll
45 '
-------
I ABU 9-1 (continued)
IO
I
Chemical
2-Butyne-l,4-diol
Butyric anhydride
Capro'lactam
Carbon disu(fide
Carbon tetrachloride
Chloroacetic acid
Chlorobeiuene
Chloroform
p-Chloronitrobenzene
Citric acid
dime ne
Ciwene hydroperoxide
Cyanuric chloride
Cyclohexane
Cyclohexane, oxidized
Cyclohexanol
Cyc lohexanone
Cyc 1 ohexanone oxime
Cyclohexene
Oi ace tone alcohol
1,4-Dichlorobutene
3,4-Dichloro-l-butene
Oielhanolamine
Die thy 1 benzene
Oielhylene glycol
Difsodecyl ph thai ate
Dime thy Idichlorosi lane
Dime thy Uerephthalate
2,4-(and 2,6-)
Oiiiilrotoluene
2,4-Dinilrotoluene
Oioctyl phthalate
Dodecene
Oodecy (benzene, linear
Oodecyl benzene, non-linear
Oodecy 1 benzenesu 1 f on 1 c
acid
Uodecylbenzenesul Tonic
acid, sodium salt
tpichlorohydrin
tlhanolamine
Illiyl acetate
tlliyl acrylale
Uhyl alcohol
Llhy (benzene
End-
use
group
GN
GN
PF
PF
GN
OS
GA
HI
DY
HI
GA
PF
PE
PF
GN
GN
GN
GN
GN
GN
SE
SE
OS
GA
PF
PL
PF
PL
PF
PF
PL
GN
OS
OS
OS
OS
UN
OS
SO
CO
SO
PI
Production,
Gg/yr
320
127
267
58
106
135
136h
1215
577
272
«
68
175
49
2828*
1
2291
110
209
na!
1131
281S
1/0
1116
12
463
302 /
Capac i ty ,
Gg/yr
o.nfl
249°
540
304
494
64
227
46
163h
2086
458^
iifl
73
1322
272h
11"
23
1089
imoS
249"
292
1860
386
232
465* lj
290
2'Jb
122
824
4/74
lmportsc txuorlsc
Percentage of Percentage of
Otilitalion domestic domestic
Average, X Gg/yr production Gg/yr production
42 2 2 11
54 1 0 15 6
91 16 29 00
47
57 9 6 15 11
84h 53 19 13
58 78 6 10 1
63 1 52 9
25
55 1 9
60 0 18 10
29
0 0 34
49
49 113 ' 100
b9 00 16 'J
t) U 5 0 t>4 J!)
SO .0 0 44 60
SI, 35 8 B'J 19
63 0 0 24 1
Chemical
price
(/kg (/lu
_ _ --;--
319
98
190
37
42
123
Hd
Ol
68
1/4
181
53
319
55
121
137
132
98
91
112
101
101
106
218
70
72
462
70
201
i in
1 lu
33
till
101
iU6
'JJ
181
•J'j
121
57
71
145
* ^ 1
45
86
19
56
38
31
79
82
24
1451
25
Bb'
62
60
4b
41
16 1
46 '
48
US
210*
32
91
MM'
'
1!,
48*
42*
50 '
43
5f>
26
32
l ,.,jln.ji-'js on last !>-«je ol l!e
-------
[ABU 9-1 (continued)
I
cn
Chemical
Ethyl chloride
Ethylene
Ethylene dibromide
Ethylene dichloride
Ethylene glycol
tthyl'ene glycol
monoelhyl ether
Ethylene glycol
monoelhyl ether
acetate
tlhylene oxide
2-Ethylhexyl alcohol
(2-Ethylhexyl) amine
6-£lhyl-l. 2.3.4-
tetrahydro-9,10-
anthracenedione
Fluorocarbon 113
Formaldehyde
Freon 11
Freon 12
Freon 21
Freon 22 '
Glycerin
Heptane
Heplenes (mixed)
Hexane
Hexamelhylene diamine
Hexamethylene diamine
ad i pate
Hexamethylene
telraamine
Isobutane
Isobutyl alcohol
1 sobuly 1 ene
1 sobulyra Idehyde
Isopentane
Isoprene
Isopropyl alcohol
Kelene
linear alcohols,
elhoxyldled (mixed)
I inear alcohols.
elhoxylated anil
sulfaled, sodium
salts (mixed)
Hdleic anhydride
Hesityl oxide
Melhyl alcohol
End-
use
group
GN
BC
GN
SO
HI
SO
SO
GN
PL
GN
OY
•
AP
PF
AP
AP
AP
AP
SO
FA
GN
GN
SE
SE
PF
BC
SO
PF
PI
BC
SE
GN
GN
n
OS
fl
so
GN
Production,
Gg/yr
154
11195,
77f
4529
1948
/9
2210
145
''
2128
66
136
95,
59f
58?
166f
476
480 1
64 '
213
137f
23fl'
594
226 '
62'
122
J295
Capacity,
Gg/yr
302
17917
8101
3014
3275
227
50<]
4128.
465k
465*
465*
70f
9759
689
109
335
177f
57463
280
1340
U, 1
M4I
Otilization
Average, X Gg/yr
51 0
62 102
15
56 72
65 15
67
64 29
52 0
63
63
63,
84f
0
629
64
78
82
44 0
/b Ob
62 120
lmportsc
Percentage of
domestic
production Gg/yi
. 0 12
1 0
2 340
1 220
20 19
0 5
0
0 tlb
0 1
4 44'J
Percentage ol
domestic
product ion
8
11
13
14
themif a!
S3
84
31
73
lib
4/11)
24
24
38
14
33
52
14
/U
88
111
139
194
20
141
163
251
176
42
34
40
92
181
112
22
66
71
95
n
51
n
149
U4
114
•J'J
101
24
J2
40
50'
6i'
BM
9
64
"i
114
80
19
15
III
42
82
b,
IU
HI
J21
41
.12
24'
3J
6«'
«'
i?'
4b
4b
II
^oolnoles on lasl |iayt> ul
-------
TABLE 9-1 (continued)-
VO
I
lmportsc
Chemical
HelhylMine
ar-Hethylbenzenediaaine
Helhyl chloride
Helhyl chloroform
Hethylene chloride
Helhyl elhyl kelone
Helhyl isobulyl ketone
Helhyl methacrylate
l-Hethyl-2-pyrrolidone
Melhyl-t-butyl ether (HIBE)
Naphthene
Nitrobenzene
Nonyl alcohol
Nony 1 phenol
t ,
Nunyl phenol, ethoxylated
Oclene
Oil-soluble petroleum
sulfonate, calcium, salt
3-Pentenenitrile
Pentaerythrilol
Penlenes (nixed)
Perchloroeihylene
Phenol
1-Phenylelhyl
hydroperoxide
Plieny Ipropane
Phosgene
Phthalic anhydride
Propanal
Propanp
Propyl alcohol
Propylene
Propylene glycol
Propylene oxide
Sorb Hoi
Sly rent
lerephlhalic acid
letraethyl lead/
letramethyl lead
letrahydrofuran
1 ft rd (methyl-ethyl) lead
End-
use
group
GN
PF
GN
SO
SO
SO
SO
GN
' GA
FA
BC
PF
PL
DS
OS
PL
DS
PF
PF
GN
SO
GA
PF
GA
GN
PL
GN
BL
SO
BC
n
GN
GN
PF
PI
IA
SO
IA
Production,
Gg/yr
102
135
268
238
204
7I1
386
771
f
64}
485'
64
92fl
»
538
45
74f
265
969
7*80
320
t
3568
65
5575
182.
816
79
2699
1944
.
125
<
t»
Capac i ly ,
Gg/yr
157
311
433
376
408
111
585
1361
f
318}
760'
173
84
460
1406
898
617
100
395
12521
205
4106
3012
f
1/0
78
Utilization
Average, X Gg/yr
65
43
62
63
50
64'
66
57
|
64 '
37
54
58
69
87
52
65
46
65 '
39
66
6b
/3
0
0
18
18
0
1
0
5
17
0.5
0.5
0
214
05
25f
18
U
U
Exports
Percentage of
domestic
production Gg/yr
0
0
8
9
0
0
0
10
4
0
0
0
4
23
0
U
8
32
28
32
7
45
0
7
20
50
5
15
41
34
60
499
1J4
...
Percentage of
domestic
production
b
12
15
10
12
0
15
43
6
2
23
1
19 1
8
9
18
'
. _
Chemical
price
«/ku 4/lb
lib
loo
44
1)
53
BH
108
137
40
din
so
75
OJ
of
112
114
97
108
IOU
156
46
79
100
79
II
•)•}
£.£
46
97
99
101
11
II
bud
t'tt
L£J
3b4
"l
45
20
24
49
62
18
??
££
51
44
49
4b'
71
21
36
4b
41 '
Jl>
jb
3d
V
44
4S
35
Jb
1112
Ibb'
(uolnoles on last page ol table
-------
TABLE 9-1 (continued)
Imports0
End-
use d
Chemical group
Toluene
loluene-2,4-diamine
loluene 2,4- (and 2,6)-
diisocyanate (80/20 mixture)
Trichloroethylene
(rietnanalamtne
Tiyethylene glyco)
Trimethylene
Iripropylene .
Vinyl acetate
Vinyl chloride, monomer
Vinyl idene chloride
Vinyl trichloride
Xylenes (mixed)
m-Xylene
o-Xylene
p-Xylene'
BC
BC
PF
SO
OS
GN
Ml
GN
CO
PF
PF
SO
BC
PF
PF
PF
Production,
Cg/yr
479
93
261
81.
58f
52f
851
2946.
91 1
92 '
2400
355
1449
Capac i ty ,
Gg/yr
318
154
82f
256
1089
4296.
3»Bj
326f
799
481
2433
Util l/atlon
Average, X
82
53
64f
78
68
539
74
60
Percentage of
domestic
Gg/yr production
58
1
6
0
3
23
137
,9
16
35
12
0
8
0
0
1
6
169
4
2
txports
Gg/yr
9
77
15
5f
317
418
282
0
176
394
Percentage of e
domestic — JiU«.._
production «/kq 4/11)
2
30
19
87f
37
14
12
0
49
21
269
165
205
68
1(18
9/
120
37
71
40
61
/5
46
77
51
64
122
75
93
I]
49
44
54 '
32
18
28
34
21
23
29
Sources of price data include Hansville Chemical Products, Chemical Marketing Reporter, O.S. International trade Commission Statistics,
The SRI Directory of Chemical Producers, and Toxic Substances Control Act Surveys.
Data are for the year 1982 unless otherwise footnoted.
Import and export values for 1982 are taken from the sources above, if available. Otherwise 1982 imports and exports are estimated
from the most recent preceding year for which they were recorded, by assuming that imports and exports remain a constant percentage
of domestic consumption.
End-use abbreviations are
BC Basic Chemicals
GA General Aromatics
GN General Nonaromatics
SE Synthetic Elastomers
PF Plastics and Fibers
PL Plasticizers
PE Pesticides
0V Dyes
SO Solvents
OS Detergents and Surfactants
FA Fuel Additives
AP Aerosol PropeHauls and Refrigerants
CO Coatings
Ml Miscellaneous
Prices are list prices from the sources in footnote a when available.
Marketing Reporter.
Some are an average of four spot prices lor the year 1982, from Chemical
Data are for 1981.
90ata are for 1977
''Data are for 1980.
1978 prices from the distillation operations BIO," i_onverted lo 1982 dollars using eiiuipwenl tost index lor iliemit.il-. from Cheijntdl Cmjuieri intj
JCapacity includes both linear and nonlinear dodecylbt-iuene
Capacity includes Freon II, Freon 12, and Fijeon 22
1978 end-use group average from distillation operation BID." tunvt-rlvd lo 1W dollars using t^mpnifnl cosl index lor clifmiuls Mow
Chemical Engineering.
Note: Situations where prodiitUnn il.il.) i-xi ted capacity ilala ale adjir.lo.l in Milisei|iivnl use i>l llu> data
-------
Total 1982 production of the 173 chemicals is approximately 86,041 Gg.
This figure is based on a variety of sources, including assumed minimum
production levels of 45 Gg/yr for those chemicals for which current chemical-
specific data are unavailable. Among the highest volume chemicals are
ethylene, ethylene dichloride, and propylene.
For 88 chemicals, sufficient data are available to calculate capacity
utilization. In general, capacity utilization in 1982 was 45 to 75 percent.
This was lower than in past years, due in part to the effects of the 1981 to
1983 recession. However, as the economy recovers, a steady increase in
demand should increase capacity utilization by about 4 percentage points per
year through the 80s from the average rate of 60 percent in 1982.13
About 70 chemicals are imported or exported in sufficient volume to show
up in foreign trade statistics. In general, imports are less than 15 percent
of domestic production of a particular chemical. Overall, exports represent
a greater volume than imports but are generally less than 20 percent of
domestic production.
Table 9-1 also gives 1982 prices for 144 of the chemicals. They range
from $0.20/kg to $6.06/kg. The highest priced chemicals are tetraethyl lead
and tetramethyl lead; most prices are between $0.40 and $2.00/kg.
9.1.2 Supply and Demand
The market conditions that determine the amount of production and
consumption of chemical products at a given time—i.e., the supply and demand
conditions of the industry—are discussed in this section.
9.1.2.1 Supply Conditions.
9.1.2.1.1 Product description. The 173 chemicals can be grouped into
14 end-use categories based on position in the manufacturing chain and
ultimate use.11* These chemical end-use groupings are as follows:
Basic chemicals
Intermediates: general aromatics
Intermediates: general nonaromatics
Intermediates: synthetic elastomers
Intermediates: plastics and fibers
Intermediates: plasticizers
Intermediates: pesticides
Intermediates: dyes
Solvents
Detergents and surfactants
Fuel additives
Aerosol propellents and refrigerants
Costings
Miscellaneous end-use chemicals.
9-8
-------
The end-use group for each chemical is included in Table 9-1. It is important
to note that these end-use groups are independent of the type of chemical
reaction used in the production process shown in Section 3.5. This end-use
grouping scheme is useful for identifying growth and other trends within the
industry. The groups are referred to throughout this industry profile.
In general, basic and intermediate chemicals are commodities, which are
chemicals produced in high volume at comparatively low prices. About 60 percent
(by weight) of all organic chemicals produced in recent years are basic and
intermediate compounds.15 The majority of these are basic or intermediate
petrochemicals and solvents; the remainder are gum- and wood-product
chemicals and fatty acids.15
In contrast to commodity chemicals, end-product chemicals are generally
produced in smaller volume and sold at higher prices. These chemicals are
used directly by consumers or by other industries and are more differentiated
than are the basic and intermediate chemicals.
9.1.2.1.2 Factors of production. The primary inputs for the industrial
chemicals sector, which includes both inorganic and organic chemicals, are
other chemicals, as might be expected due to the chain of production of
chemicals from basic to end-product chemicals.16 Other important inputs are
energy, maintenance, transportation and storage services, petroleum, and
miscellaneous products of petroleum and coal. Professional and business
services also are significant production factors in the industry.16 Some of
these inputs are discussed below.
Raw Materials. The organic chemical industry depends largely on petroleum
and petroleum products for raw material as inputs. The partial deregulation
of petroleum products and the Organization of Petroleum Exporting Countries
(OPEC) cartel production quotas during the 1970s contributed to rising prices
in the chemical industry. Table 9-2 shows a comparison between an average
price index of five oil-based chemicals and an-index of crude oil prices from
1970 to 1984.17~19 The percentage change in the chemicals index parallels
the percentage change in the crude oil index in both direction and magnitude
of change in each year since 1973. Table 9-3 shows a similar comparison of
indexes between natural gas prices and an average price of five gas-based
chemicals.17'18 Natural gas does not show the same direct price influence on
gas-based chemicals that crude oil does on its chemicals. In fact, rarely
does the percentage change in the two indexes shown in Table 9-3 move in the
same, direction in any given year. This is due apparently to the effects of
long-term contracts for the use of natural gas as a feedstock for chemical
production.
The chemical industry as a whole has comparatively low expenditures for
raw materials. The Kline Guide reports that 56.8 percent of the value of
chemical sales went toward raw materials, compared to 59.7 percent for all
manufacturing. This indicates a relatively higher level of processing costs
and value-added for the industry.20 The ratio of expenditure for raw
9-9
-------
TABLE 9-2. COMPARISON OF PRICE INDEXES BETWEEN CRUDE OIL AND THE
AVERAGE PRICE OF FIVE OIL-BASED CHEMICALS 1970-198417 18 l9
(Base year = 1973)
Year
1970
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
Five oi
Average
price,
t/kg
12.0
15.3
26.4
27.6
29.1
29.9
31.3
44.8
57.9
64.7
56.3
54.5
55.6
1 -based chemicals
Index
0.78
1.0
1.72
1.80
1.90
. 1.95
2.05
2.93
3.78
4.23
3.68
3.56
3.63
Percent
change
in index
28
72
5
6
3
5
43
29
12
-13
-3
2
Price, b
$/Barrel
4.13
9.63
10.93
10.89
11.96
12.46
17.72
28.07
35.24
31.87
28.99
28.94
Crude oil
Index
1.00
2.33
2.65
2.64
2.90
3.02
4.29
6.80
8.53
7.72
7.02
7.01
Percent
change
in index
__
133
14
0
10
4
42
58
25
-9
-9
0
The five oil-based chemicals are acetic anhydride, benzene, cyclohexane,
ethylene, and toluene.
The price per barrel for crude oil is a composite figure of crude oil
cost in the U.S. from both foreign and domestic prices.
9-10
-------
TABLE 9-3. COMPARISON OF PRICE INDEXES BETWEEN NATURAL GAS AND THE
AVERAGE PRICE OF FIVE GAS-BASED CHEMICALS3 1970-198417 18
(Base year = 1973)
Five gas-based chemicals
Year
1970
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
Average
price,
-------
materials to total sales is expected to increase in the future because
petroleum and agricultural input costs are rising at a percentage rate
greater than that of the overall rate of inflation.20
Capital Requirements of the Chemical Industry. The chemical industry is
very capital intensive.Due to the high rate of process innovation and
product development in the industry, plants become obsolete relatively
quickly. Maintenance and repair of buildings and facilities is also an
important input for the industry. Capital expenditures for the chemical
industry were $8.14 billion in 1977, or 5.2 percent of sales.21 (The return
on investment was $1.55 for every dollar invested in industrial chemicals and
synthetics in 1979, as compared to $1.60 for the manufacturing sector as a
whole.21) Table 9-4 shows that capital expenditures for the industry are
increasing over time. After a sharp drop in investment during the 1982
recession, spending for 1983 is expected to have increased.21
Employment. Historical employment figures for SIC 286 are presented in
Table"?-!)?"777 Employment rose during the period of increasing production
from 1958 to 1969 and then remained relatively stable from 1970 to 1975. For
the broader category Chemicals and Allied Products (SIC 28), employment
remained stable from 1980 to 1981, but fell 3 percent in 1982; employment in
all manufacturing fell 7 percent from 1981 to 1982.2(+
The number of employees in chemical production has decreased while the
unit costs for labor have increased in recent years. Unit labor costs
increased by nearly 13 percent from 1981 to 1982.2S Historically, although
unit labor costs increased, these increases were offset by corresponding
increases in productivity. However, since the late 1970s, productivity
increases have not kept up with unit labor costs. Table 9-6 provides indices
for productivity and unit labor costs for 10 years for chemicals and allied
products and for all manufacturing industries.25 Until 1982, the chemical
industry generally performed better than manufacturing as a whole in terms of
labor productivity; however, in 1982, chemicals' productivity slipped 3 percent
while manufacturing productivity gained 3 percent. Compared to the sharp
increase in unit labor costs for chemicals, manufacturing unit costs rose
only 3 percent.
• Since the chemical industry is relatively capital intensive, the value
of annual sales per employee is quite high. The Kline Guide reports that,
for chemicals as a whole, this value per employee was $143,000 in 1977,
compared to $73,000 for all manufacturing. For basic and intermediate
organic chemicals (including cyclic crudes and intermediates, gum and wood
chemicals, and other organics), this ratio was particularly high, with a
value of $197,000 per employee.20
9.1.2.2 Demand Conditions.
9.1.2.2.1 Markets for chemicals. A wide variety of markets require
chemical inputs.The largest market is the chemical industry itself;
9-12
-------
TABLE 9-4. CAPITAL EXPENDITURES IN U.S. FOR CHEMICALS AND ALLIED
PRODUCTS INDUSTRY AND ALL MANUFACTURING, 1973-1983 ($109)a 21
Year
1983
1982
1981
1980
1979
1978
1977
1976
1975
1974
1973
Capital
Chemicals and
allied products
13.69b
13.27
13.60
12.60
10.78
8.46
8.14
8.12
7.63
6.48
4.24
expenditures
All manufacturing
115. 90b
119.98
126.79
115.81
98.68
79.72
69.22
59.95
54.92
53.21
42.37
Current dollars.
'Preliminary estimate.
9-13
-------
TABLE 9-5. NUMBER OF COMPANIES, ESTABLISHMENTS, AND EMPLOYEES
FOR INDUSTRIAL ORGANIC CHEMICALS, 1958-198122 23
Year
1981
1977
1972
1967
1963
1962
1958
Companies3
623
690
626
629
Establishments
866
826
849
841
639
Employees, 103
147.5
152.8
135.8
131.0
120.0
115.3
113.9
a . . ...
more under common ownership or control.
DAn establishment is a place where a product is produced or distributed or a
service rendered. The principal product or service defines the establish-
ments type, i.e., SIC. One physical location may have several establish
ments, but typically each establishment has only one location.
TABLE 9-6. PRODUCTIVITY AND UNIT LABOR COSTS3 IN U.S. FOR CHEMICALS AND
ALLIED PRODUCTS INDUSTRY AND ALL MANUFACTURING, 1972-198225
Chemicals and allied products
Year
1982
1981
1980
1978
1976
1974
1972
Productivity
197.5
203.2
196.5
184.8
168.5
151.7
143.2
Unit labor
163.0
144.8
136.2
122.6
114.0 .
103.8
95.9
All manufacturing
Productivity
163.3
157.8
152.5
144.3
134.5
129.2
122.2
Unit labor
184.0
178.9
168.5
151.1
132.7
121.1
110.9 -
'Index, 1967 = 100
9-14
-------
other markets include those for plastics, synthetic rubber, organic fibers,
paints and allied products, and petroleum refining.16 Because the chemical
industry provides inputs for a wide variety of other industries, demand for
chemicals tends to follow that of the entire economy. During 1982, for
example, when housing and automobile markets were poor, chemical sales
dropped 8 percent. They began to recover in 1983 as key markets began to
rebound.25 Table 9-7 presents historical production and sales data for
several USITC categories of organic chemicals.27 These data illustrate the
relationship between chemical production and economic trends. Drops in
production and sales occurred between 1974 and 1976 and 1980 and 1981,
periods of recession"in the U.S. economy.28 Rapid production and sales
increases tend to follow recessionary periods.
The elasticity of demand is a measure of the percentage change in
quantity demanded in response to a change in price. A recent USITC document
cites an unpublished demand elasticity of -0.7 to -0.9 for chemicals and
allied products.29 Values in this range are reasonable from a theoretical
perspective because the largest sectors within the industry make producer
goods. Thus, because other industries need these chemicals to produce their
products, overall chemical industry price increases will not lead to propor-
tional decreases in consumption. Demand for individual chemicals, however,
may be more elastic if substitutes are readily available at comparable cost.
9.1.2.2.2 Foreign trade conditions. The foreign trade position of the
United States in chemicals has traditionally been strong. Table 9-8 presents
a time series of U.S. exports and imports for all chemicals and for the
subset of organic chemicals.30 To establish this time series, nominal dollar
values have been converted to real dollar values using a chemical and allied
products industry producer price index.31 The table shows that total
revenues for exports grew consistently through the 1970s, although imports
have grown more steadily in recent years. Although overall demand slowed in
1982, reflected in decreases in real revenues of both exports and imports,
the United States has maintained a favorable balance of trade in chemical
sales. In 1982, $19,891 million (in current dollars) in chemicals were
exported; only $9,494 million (in current dollars) were imported. Orqanic
chemicals show a similar pattern.
* irtI?euUnited states enjoyed a cost advantage in chemical production prior
to 1981 because of Federal price controls on petroleum products. Decontrol
of oil in 1981 and staged decontrol of natural gas have eroded this advantage,
however, and U.S. producers are now beginning to face increasing foreign
competition in chemicals trade. Industry .experts predict that export markets
will shrink as new plants are built in Canada, Mexico, and OPEC nations, all
of which have ready access to inexpensive raw materials.32 A recent USITC
study notes that nations with a manufacturing cost advantage in production of
crude petroleum and natural gas, such as Saudi Arabia, Indonesia, Kuwait,
Canada, and Mexico, might pose a significant threat to U.S. markets. These
nations have the necessary infrastructure, ample petroleum resources, and low
energy consumption. In addition, the price in some of these nations for
9-15
-------
TABLE 9-7. HISTORICAL PRODUCTION AND SALES OF INDUSTRIAL
ORGANIC CHEMICALS, 1955-198127*
Year
1981
1980
1979
1978
1977
1976
1975
1974
1973
1972
1971
1970
1969
1968
1967
1966
1965
1964
1963
1962
1961
1960
1959
1958
1957
1956
1955
Production,
Gg
77,500
77,800
82,100
64,600
61,200
60,200
61,000
71,800
69,900
65,600
57,700
57,800
56,800
51,400
45,700
44,300
40,100
36,300
32,500
30,100
27,600
27,100
25,000
24,900
26,700
27,800
23,500
Sales quantity,
Gg
33,800
34,900
36,300
30,000
29,100
27,900
29,000
34,900
36,200
33,300
28,600
28,100
27,400
24,700
21,700
20,800
19,000
17,500
15,100
14,200
13,400
12,900
12,300
11,900
12,700
12,600
11,900
Sales value,
$106B
30,995
29,057
26,007
19,397
17,945
16,557
15,355
15,245
10,049
8,558
7,592
7,381
7,277
7,047
6,359
5,762
5,182
4,697
4,210
4,082
4,040
3,672
3,498
3,039
3,097
3,008
2,811
*These figures are based on a summation of the following International
Trade Commission categories: tar, tar crudes, cyclic intermediates, dyes,
lakes and toners, flavor and perfume materials, rubber-processing chemicals,
plasticizers, pesticides, miscellaneous end-use chemicals, and miscellaneous
cyclic and acyclic chemicals. These groupings are not strictly comparable to
similar SIC groupings.
°Current dollars.
9-16
-------
ORGANIC CHEMICALS,
Ratio (exports/imports^
Real dollars, base year = 1972.
9-17
-------
natural gas, a feedstock and energy source for some primary petrochemicals,
may be only 10 to 20 percent of that in the United States. With feedstock
and energy costs for chemicals such as methyl alcohol and ethylene comprising
60 to 70 percent of production costs, the cost advantage for these nations is
tremendous.33
A key factor in the impact of the entry of these nations into the world
market is their method of entry. If thes.e energy-rich nations require their
crude oil customers to buy petrochemicals, or if they cut prices substantially,
they could reduce the market shares of.existing U.S. producers. If their
entry is linked to demand increases, however, the impact will not be as
large. Additionally, many U.S. producers now are finding it cheaper to
import basic and intermediate chemical inputs to produce end-product chemicals.
Although costs are held down by this practice, it worsens the overall U.S.
trade balance. Some U.S. firms are considering mergers and joint ventures
with foreign producers.33
As a potential result of the loss of key export markets, the USITC study
concludes that, by 1990, the United States could have a net chemical trade
imbalance with about 120,000 Mg of exports and 4.8 million Mg of imports
compared to current large net export surpluses.31* This shift might cause
substantial decreases in output in the chemical and allied products industry
of $190 million to $5.1 billion in 1990, with an accompanying loss of up to
24,396 jobs in the industry.35
However, several factors should allow U.S. producers to retain some
trade advantage over the energy-rich nations. First, decontrol of gas is a
phased process and will not be complete even in the mid-1980s.36 Second, the
U.S. chemical industry has an efficient interplant distribution network and
better marketing and research and development technology in some cases.
Therefore, many U.S. plants are currently being constructed with flexibility
in the use of raw materials and will therefore be able to select the least
expensive inputs at any particular time.37 Foreign producers may be more
restricted in their selection of raw materials, such as crude oil, naphtha,
and various basic chemicals.
The United States is protected from organic chemical imports by high
tariffs. This is true especially for the benzenoid imports category, which
contains many of the organic chemicals. The benzenoid group includes any
chemical whose molecular structure has one or more six- membered carbocyclic
or heterocyclic rings with conjugated double bonds (e.g., benzene or pyridine
rings). Until recently, tariff valuation for some benzenoid chemicals was
extremely protective under the American Selling Price (ASP) system. The ASP
customs valuation system in some cases led to a tariff representing approxi-
mately 20 percent or more of the selling price of imports, making it difficult
for foreign producers to sell to the United States at a profit.
Recent multilateral trade negotiations scrapped the ASP system and
replaced it with a new set of tariffs that became effective July 1, 1980.
9-18
-------
Tariff rates for all chemicals have now been set on the basis of "transaction
value," which is the foreign invoice price plus shipping and insurance. Many
benzenoid chemicals do not have large tariff reductions under the new tariff
system.38 These benzenoid chemicals represented a $226 million portion of
the $688 million in dutiable benzenoid imports during 1976. The average U.S.
duty rate for non-benzenoid chemical imports will be a little over 7 percent
by 1987 when the new rates are fully phased in.39
U.S.. producers do face occasional problems in competing with government-
subsidized non-U.S. producers or in exporting to regulated non-U.S. markets.
These factors in combination with the large cost advantage in the use of
feedstocks and petroleum-based inputs have the potential of reversing the
trend of consistent balance of trade surpluses that the U.S. experienced in
the world chemical markets throughout the 1970s. These problems, however,
should not prevent the continuation of a chemical balance of trade surplus
through the next 5 years, given the continuing favorable treatment of many
benzenoid products in the new tariff system, the relatively small decrease in
most tariff rates, and the flexibility in use of inputs that many U.S.
chemical producers have.
9.1.3 Market Structure
The structure of the chemical industry as a whole, and especially the
sector producing the large-volume chemicals, is the subject of this section.
The firms that produce the chemicals, as well as the number, size, and
distribution-of the plants at which they are produced, are discussed, and the
relationship between these firms and plants is analyzed.
9.1.3.1 Chemical Firms. There are about 1,500 firms that produce
chemicals and allied products. Among these is a wide range of firm types,
from those that produce only chemicals to others that produce a variety of
products. Major producers include Allied, Celanese, Dow Chemical, Du Pont,
Monsanto, Shell, and Union Carbide. These companies each produce many
different chemicals at several locations. In contrast, several companies
produce just one chemical at a single location. Table 9-9 lists the chemical
sales and the ratio of chemical sales to total sales for the 25 largest
chemical producers.1*0 A detailed list of the firms and plants currently
producing the reactor processes chemicals is given in a memorandum to the
Docket created and maintained as an official record of the reactor processes
standards development effort.1*1
9.1.3.2 Geographic Distribution. Number, and Size of Plants. Table 9-10
presents the number of plants, capacity ranges, and general locations for the
large-volume chemical plants.1*1 The manufacture of the organic chemicals is
concentrated in the States of Texas and Louisiana.
Plant capacities for the production of large-volume chemicals vary
widely, from under 500 kg/yr to more than 2,000 Gg/yr. Basic and intermediate
chemicals are generally produced at larger capacity plants.
9-19
-------
TABLE 9-9. TOP 25 U.S. CHEMICAL PRODUCERS, 198240
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17 •
18
19
20
21
22
23
24
25
Company
Du Pont
Dow Chemical
Exxon
Monsanto
Union Carbide
Shell Oil
Celanese
Standard Oil
(Indiana)
W. R. Grace
Allied
Phillips Petroleum
Atlantic Richfield
Eastman Kodak
Mobil
Hercules
Gulf Oil
Rohm & Haas
American Cyanamid
Stauffer Chemical
American Hoechst
Texaco
Ethyl
Air Products
FMC
Ciba-Geigy
Chemical
sales,
$106
10,841
8,252
7,259
5,737a
4,985
3,085
3,062
2,786
2,654
2,407
2,356
2,242
2,151
2,148
2,040
2,006.
1,727
l,698a
1,618
l,506a
1,497
1,411
1,359
1,319
1,285
Chemicals as
percentage
of total sales
32.5
77.7
7.1
90.7
55.0
15.4
100.0
9.4
43.2
39.0
15.0
8.3
19.9
3.3
82.6
6.6
94.5
49.2
100.0
100.0
3.2
87.4
36.6
37.7
68.0
Chemical sales include significant amounts of nonchemical products.
9-20
-------
ro
TABLE 9-10. NUMBER, CAPACITY, AND LOCATION OF PLANTS PRODUCING
THE 173 REACTOR PROCESSES CHEMICALS IN 198241
Chemical
Acetaldehyde
Acetic acid
Acetic anhydride
Acetone
Acetone cyanohydrin
Acetylene
Acrylic acid
Acrylonitrile
Adipic acid
Adiponitrile
Alcohols (C-ll or lower,
mixtures)
Alcohols (C-12 or higher,
mixtures)
Alcohols (C-12 or higher,
unmixed)
Allyl chloride
Amylene
Amylenes (mixed)
Aniline
Benzene
Benzenesulfonic acid
Benzenesulfonic acid,
mond-Cl0_16alkyl
derivatives, sodium salts
Number of
plants
2
10
5
14
NDA
7
4
6
4
6
NDA
5
NDA
3
6
NDA
6
55
7
29
Plant capacities. Gq/vra
Smallest
181
41
63
25
'
5
18
113
14
23
53
0.5
59
3
0.005
0.005
Largest
272
454
227
318
82
159
209
317
227
120
227
127
463
227
23
Median
227
181
113
100
9
88
181
236
227
53
14
120
99
5
23
Predominant
location
Texas
Texas
Texas
Texas
Texas,
Texas
Texas
Texas
Texas
Texas ,
Texas,
Texas
Alabama
Louisiana
Louisiana
Louisiana
Footnotes on last page of table.
(continued)
-------
ro
ro
TABLE 9-10 (continued)
Chemical
Benzyl chloride
Bisphenol A
Bivinyl
B route tone
Butadiene & butene fractions
Butanal
Butane
Butanes (mixed)
1,4-Butanediol
2-Butoxyethanol
Butyl aery late
n-Butyl acetate
t- Butyl alcohol
sec-Butyl alcohol
n- Butyl alcohol
Butylbenzyl phthalate
orButylene
p-Butylene
Butylenes (mixed)
t-Butyl hydroperoxide
2-Butyne-l,4-diol
Butyric anhydride
Caprolactam
Carbon disulfide
Carbon tetrachloride
Number of
plants
3
4
19
NDA
NOA
7
NOA
NDA
4
4
5
4
3
4
8
5
4
8
8
6
4
I
3
4
9
Plant capacities, Gg/yra
Smallest
9
45
20
36
27
' 9
0.5
.34
2
5
12
23
11
23
Largest
36
159
236
204
91
23
454
159
145
227
91
45
225
227
Median
36
85
91
95
45
23
5
87
68
227
44
34
86
102
Predominant
location
New Jersey, Illinois
--
Texas,
Texas,
Texas
Texas
Texas,
Texas ,
Texas
--
Texas
__
Texas
Texas,
—
—
Texas
Louisiana
Puerto Rico
Louisiana
Tennessee
Louisiana
Tennessee
159
5
4
218
159
136 .
163
70
41
--
--
—
Footnotes on last page of table.
(continued)
-------
TABLE 9-10 (continued)
t*»
Chemical
Chloroacetic acid
Chlorobenzene
Chloroform
p-Chloronitrobenzene
Citric acid
Cumene
Cumene hydroperoxide
Cyanuric chloride
Cyclohexane
Cyclohexane, oxidized
Cyclohexanol
Cyclohexanone
Cyclohexanone ox i roe
Cyclohexene
1 , 3-Cyc 1 opentadi ene
Diacetone alcohol
1,4-Dichlorobutene
3,4-Oichloro-l-butene
Diethanolamine
Diethylbenzene
Diethylene glycol
Diisodecyl phthalate
Oimethyldichlorosilane
Dimethylterephthalate
Number of
plants
5
3
7
2 '
5
11
5
4
10
2
7
6
4
5
NOA
4
4
NOA
NOA
2
14
6
2
5
Plant capacities, Gg/yra
Smallest
2
23
16
0.5
11
54
0.05
0.5
35
45
23
9
2
227
Largest
23
68
50
45
45
340
227
45
259
227
227
331
54
590
Median
14
68
34
39
181
5
14
121
227
181
20
249
Predominant
location
—
Illinois
—
—
Texas
—
—
Texas
Texas
Texas
Texas, Florida
—
--
—
Louisiana, Texas
Michigan, Louisiana
Texas, Louisiana
Michigan, West Virginia
North Carolina, Tennessee
Footnotes on last page of table.
(continued)
-------
V£>
I
ro
TABLE 9-10 (continued)
Chemical
2,4-(and 2,6-)Oinitrotoluene
2,4-Dinitrotoluene
Oioctyl phthalate
Dodecene
Oodecyl benzene, linear
Dodecylbenzene, nonlinear
Oodecyl benzenesul fonic acid
Oodecylbenzenesul fonic acid,
sodium salt
Epichlorohydrin
Ethanolamine
Ethyl acetate
Ethyl acrylate
Ethyl alcohol (synthetic)
Ethylbenzene
Ethyl chloride
Ethylene
Ethylene dibromide
Ethylene dichloride
Ethylene glycol
Ethylene glycol monoethyl
ether
Ethylene glycol monoethyl
ether acetate
Ethylene oxide
2-Ethylhexyl alcohol
Number of
plants
4
5
7
7
5
3
27
48
2
5
6
5
4
14
. 5
23
4
18
14
4
3
15
5
Plant capacities, Gg/yra
Smallest
14
8
18
-
100
11
• 7
75
16
34
45
68
23
23
50
25
Largest
113
120
102
102
191
109
36
359
846
95
2177
908
612
23
590
77
Median
45
18
73
-
57
15
188
318
54
544
454
181
23
204
32
Predominant
location
Texas, West Virginia
* ™
-* ~
— ~
""
California
Texas
Texas, Louisiana
Texas
Texas, Louisiana
Texas, Louisiana
Louisiana, Texas
.
Arkansas, Texas
Louisiana, Texas
— ™
_ —
Texas, Tennessee
Louisiana, Texas
Texas
Footnotes on last page of table.
(continued)
-------
TABLE 9-10 (continued)
Chemical
(2-Ethylhexyl) amine
6-Ethyl-l,2,3,4-tetrahydro-
9,10-anthracenedione
Fluorocarbon 113
Formaldehyde
Freon 11
Freon 12
Freon 21
Freon 22
Glycerin (synthetic)
f Heptane
[£ Heptenes (mixed)
Hexane
Hexamethylene diamine
Hexamethylene diamine adipate
Hexamethylene tetraamine
Isobutane
Isobutyl alcohol
Isobutylene
Isobutyraldehyde
Isopentane
Isoprene
Isopropyl alcohol
Number of
plants
4
NOA
5
15K
1 nO
1?
3
12b
2
11
3
4
8
2
6
NDA
8
4
7
44
8
6
Plant capacities, Gq/yra
Smallest
5
27
18
0.0005
14
0.0005
4
7
7
7
0.0005
23
23
Largest
45
925
52
227
27
227
14
25
127-
91
454
84
454
Median
25
t- *J
186
0 5
\J * *J
27
136
U-
13
101
14
23
27
206
Predominant
location
--
T
__
Delaware,
Louisiana
Texas
South Carolina,
Florida
Texas
Texas, Louisiana
Texas
Texas
Texas
Louisiana, Texas
Footnotes on last page of table
(continued)
-------
TABLE 9-10 (continued)
I
IV)
at
Chemical
Ketene
Linear alcohols, ethoxylated
(mixed)
Linear alcohols, ethoxylated
and sul fated, sodium salt
(mixjed)
Maleic anhydride
Methyl alcohol
Methyl amines
ar-Methylbenzenediamine
Methyl chloride
Methyl chloroform
Methyl ene chloride
Methyl ethyl ketone
Methyl isobutyl ketone
Methyl methacrylate
Mesityl oxide
2-Methylpentane
l-Methyl-2-pyrrolidone
Methyl t-butyl ether (MTBE)
Naphthene
Nitrobenzene
Nonyl alcohol
Number gf
plants
1
19
13
7
12
4
NDA
9
3
7
6
5
4
7
NDA
3
10
9
6
1
Plant capacities, Gg/yra
Smal lest
5
174
5
11
91
27
36
7
54
0.5
25
34
34
Largest
59
748
75
68
204
159
136
36
340
23
•
318
45
170
Median
27
434
39
29
159
50
45
18
95
3
98
41
153
Predominant
location
West Virginia
--
--
--
Texas, Louisiana
--
Louisiana, W. Virginia
Louisiana, Texas
— —
--
—
—
—
--
Texas
--
—
New Jersey
Footnotes on last page of table.
(continued)
-------
TABLE 9-10 (continued)
I
ro
Chemical
Nonyl phenol
Nonyl phenol, ethoxylated
Octene
Oil-soluble petroleum
sulfonate, calcium salt
3-Pentenenitrile
Pentaerythritol
Pentenes (mixed)
Perchloroethylene
Phenol
1-Phenylethyl hydroperoxide
Pheny] propane
Phosgene
Phthalic anhydride
cr-Pinene
Propanal
Propane
Propyl alcohol
Propylene
Propylene glycol
Propylene oxide
Sorbitol
Styrene
Terephthalic acid
Number of
plants
6
16
4
7
NOA
4
NOA
7
10
NOA
2
16
9
3
NOA
3
30
6
4
7
12
7
Plant capacities.
Smallest
5
11
23
34
0.0005
11
36
29
23
200
54
195
_____
Largest
27
14
109
236
227
122
106
38
113
590
680
907
Gg/yra
Median
14
1Q
68
196
57
77
32
57
322
Jo
324
454
Predominant
location
Texas
Louisiana, Texas
Texas
Florida
Texas
Texas
Texas, Louisiana
Texas, Louisiana
South Carolina,
Alabama
(continued)
-------
TABLE 9-10 (continued)
Chemical
Tetraethyl lead/tetramethyl
lead
Tetrahydrofuran
Tetra (methyl-ethyl ) lead
Toluene
Toluene-2,4-diamihe
Toluene- 2, 4- (and 2,6-)
diisocyanate (80/20 mixture)
Trichloroethylene
10 Triethanolamine
i\j Triethylene glycol
00 Trimethylene
Tripropylene
Vinyl acetate
Vinyl chloride, monomer
Vinyl idene chloride
Vinyl trichloride
Xylenes (mixed)
m-Xylene
o-Xylene
p-Xylene
Number of
plants
4
3
NDA
28
10
7
2
NDA
12
NDA
5
5
12
5
7
23
1
7
10
Plant
Smallest
36
•
23
18
54
1
11
181
136
0.5
5
11
27
capacities, Gg/yra
Largest
79
45
57
100
11
145
272
567
227
227
136
1,089
Median
54
34
50
7
38
193
361
45
45
79
59
204
Predominant
location
Texas, Louisiana
—
__
—
—
Texas, Louisiana
Texas, Louisiana
--
Texas
Louisiana, Texas
Louisiana, Texas
Louisiana, Texas
Texas
Texas
Sources of data are Mansville Chemical Synopsis, Chemical Marketing Reporter, Toxic Substances
Control Act Surveys, and SRI Directory of Chemical Producers.
Freon 11, 12, and/or 22 can be manufactured at these plants.
NDA = No data available for the chemical.
-------
End-product chemicals, which are produced in smaller quantities and at higher
prices, are more likely to be produced at smaller plants. Plants that
produce less than 1 Gg/yr do not add significantly to total national production
or to resulting VOC emissions. These plants do not contribute significantly
to national emissions levels because of a proportional relationship between
production and emissions levels. Because this standard is limited to chemicals
whose total annual production exceeds 45.4 Gg/yr, it is assumed that plants
producing less than 2.5 percent of that minimum (less than 1 Gg) do not add
significantly to total national emissions levels resulting from the production
of al-1 173 large-volume chemicals. Consequently, these small plants are
ignored in the economic analysis that follows in Sections 9.2 and 9.3,
although they are shown in Table 9-10. Furthermore, it is assumed here that
the projected new plants that will be affected by these proposed standards
will each produce at least 1 Gg/yr.
9.1.3.3 Firm Concentration. The chemical industry is dominated by a
few major producers.It is estimated that 23 percent of total industry sales
are attributable to the-top four companies and 40 percent to the top ten.1*2
While this concentration level is relatively high compared to manufacturing
industries, it is low compared to other capital-intensive industries, such as
motor-vehicle production and petroleum refining.1*3
Although the industry as a whole is rather concentrated, the sectors
within it have varying levels of concentration. For example, in gum and wood
chemicals (SIC 2861), the top four firms account for more than 70 percent of
shipments. In contrast, the top four companies account for less than 40 percent
of shipments in the detergent and surfactants sector.1*3
Concentration in the production of each of the reactor process chemicals
is difficult to assess. Production of some chemicals is quite unconcentrated;
benzene is produced by a large number of producers at different locations.
In contrast, 90 percent of benzyl chloride production is at two plants owned
by a single firm.
,9.1.3.4 Vertical Integration and Diversification. As indicated in
Section 9.1.1, vertical integration among industry firms has been encouraged
by the basic structure of the chemicals industry. Diversification into the
production of nonchemical goods or services by chemicals companies has also
been common. The Kline Guide reports that, prior to World War II, most
companies producing chemicals were engaged only in the production of chemical
products. Since that time, however, forward vertical integration by petroleum
and other companies seeking the higher profits associated with chemicals made
from their products has changed this. Currently, only 37 of the 100 largest
chemical producing companies have more than 50 percent of their sales in
chemical products. Of the top 25 companies listed in Table 9-9, for example,
8 are petroleum companies.1*0 Petroleum companies now account for over
25 percent of chemical production in the United States.1*0
9-29
-------
Diversification was first encouraged by the decline in profits that the
industry began experiencing following the boom period of the 1960s. This
trend is discussed in a later section of this profile. Many chemical companies
have branched out into technical nonchemical areas. This trend is expected
to continue as higher costs and decreasing profit margins continue in the
industry.^
9.1.3.5 Returns to Scale. The average cost of production may change as
a firm changes its production capacity. If average cost declines with
increases in a firm's capacity, production is said to exhibit increasing
returns to scale; if average costs increase with increases in a firm's
capacity, production is said to exhibit decreasing returns to scale. In
general, as a plant's capacity increases, the plant is expected to experience
first increasing, then constant, and, finally, decreasing returns to scale.
In a competitive business environment, firms prefer a plant capacity in the
constant-returns-to-scale size range since that size minimizes average costs
of production. With market demand sufficiently large relative to the constant-
returns-to- scale plant size, i.e., the cost-minimizing plant capacity—numerous
competitive firms will likely be able to operate, at optimal, cost- minimizing
conditions. With small market demand relative to a cost- minimizing capacity
size, however, there is a tendency for one or a few firms to take advantage
of the low cost of constant-returns-production and dominate the market. At
issue, then, is whether the markets for the affected chemicals are large
relative to the firm's cost-minimizing plant capacity. If market demand is
sufficiently large, then many firms experience constant returns to scale and
there is no impediment to the operation of perfectly competitive markets in
chemical production. The size Df optimum plant capacity compared to total
market size is the important consideration for assessing the role of returns
to scale in effecting market competition.
As discussed in Section 9.1.3.3, there is no clear pattern relating
plant capacity and market size in the SOCMI industry as a whole. Production
of many basic and intermediate chemicals appears to exhibit increasing
returns to scale because the chemicals are most often produced at large-scale
plants. The markets for some of these chemicals are large enough, however,
to support quite a few large-scale plants. On the other hand, some chemicals
are produced at relatively small plants. Since some of these plants serve a
relatively small market, however, only a very few may be able to produce at a
minimum average cost and survive, thus possibly reducing competition between
the firms operating the plants.
Table 9-8 shows that, for the 153 chemicals for which data on the number
of producing plants are available, 98 are produced at at least five locations.
These data suggest that, for a large number of affected chemicals, increasing
returns to scale have not resulted in very few plants. As to whether the
industry may have an imperfectly competitive structure for other reasons,
considerations such as the number of firms in the market, the barriers to
entry, and the availability of substitutes are the relevent measures to
consider. These issues are discussed in Section 9.1.4.
9-30
-------
9.1.3.6 Industry Cost Structure. The average cost of production for
firms in an industry may change as industry-wide output changes. These
changes in cost can occur because input prices may change when all the firms
in the industry act in concert to increase or decrease production. An
industry is said to be an increasing, decreasing, or constant- cost industry
if the expansion of industry output increases, decreases, or does not affect
average total costs of production. These distinctions are important because
they affect what proportion of the control costs of a regulation is passed
through to customers in the form of a price increase. The average costs of
control may be less than, greater than, or just equal to the change in price
caused by a regulatory alternative, depending on whether the industry is an
increasing, decreasing, or constant cost industry.
mn TWlth the data availab1e» it ^ very difficult to determine how changing
SOCMI industry output has affected chemical prices. In essence, there are
other changes that occur that can also account for price changes. For
example, between 1960 and 1979, physical output in the industry increased at
an average rate of 7.5 percent per year. Until 1973, prices for chemicals
decreased consistently. This suggests a decreasing cost structure for the
industry, but it could just as well reflect improved industry technology.
After 1973, price indices began to rise, apparently due to increasing input
costs that were not offset by productivity increases. However, this response
is also consistent with an increasing cost industry. Given this uncertainty,
and the ambiguous history of price changes associated with increasing output,
the SOCMI industry is treated in this analysis as a long-run constant cost
industry. This means that, in a competitive environment, the average cost of
control will be equal to the change in price due to the regulation.
9.1.3.7 Entry Conditions. Although ease of entry into the chemical
industry cannot be measured directly, some general comments can be made.
Firms now considering entering the industry face high initial capital costs
as well as barriers of technical expertise. However, because many firms have
historically diversified into chemicals and because the number of firms in
the industry is large, these barriers have not been insurmountable. Therefore,
barriers to entry are probably not a major threat to the competitive nature
of the chemical industry. An NSPS would increase the initial capital costs
of entering the industry, but control costs would not discourage entry
because they are a very small proportion of total capital costs.
9.T.4 Pricing
Market structure, particularly industrial concentration and barriers to
entry, and the homogeneity or heterogeneity of a chemical product influence
the competitiveness of firms producing that chemical and, therefore, the
pricing practices.of those firms. Pricing practices, in turn, indicate how
firms may try to pass control costs forward.
9-1-4-1 Homogeneity of Product. The more the output of an industry
is perceived by demanders to be homogeneous, the more likely a single
market price will be observed.
9-31
-------
No generalization can be made about the homogeneity of chemical products
as a whole. Some chemicals are commodities produced by a large number of
producers to standard specifications of general usage, such as basic chemicals,
which have an average of 25 producers each. (Economists use the term
"commodity" to describe any item that is produced by a large number of
producers to standard specifications.) Price increases on the part of a
single producer would render its products uncompetitive because little
product differentiation is evident. In contrast, most end-product chemicals
are produced to perform a specific function. Companies with a degree of
expertise in production would be in a much better position to raise their
prices without losing customers. The reactor process chemicals are produced
in large quantity, and most of them are commodity chemicals that can be
characterized by the more competitive environment described above.
9.1.4.2 Degree of Concentration and Barriers to Entry. The degree of
concentration of industrial output in the largest firms also determines
pricing behavior. Different types of chemicals are produced in very different
settings, making a characterization of the concentration of the industry
difficult.
As discussed in Section 9.1.3.3, some organic chemical groups are rather
unconcentrated. Thus, a more competitive environment may exist for these
chemicals than for chemicals produced by only a few producers. Of the
chemicals with specific production capacity data by firm, 66 percent have no
one firm with more than half the total output capacity.1*1 In contrast, 11
percent of the chemicals have one firm that dominates the production capacity
with more than 90 percent of total capacity. The other 23 percent have one
firm maintaining a majority of production capacity, though not monopolizing
the output for those chemicals.
In terms of firm concentration in the entire industry, the top ten firms
account for about 40 percent of total sales. Though this is a high concentra-
tion in comparison to other industries, it is rather low when compared to
other capital-intensive industries. For example, the top eight firms in the-
automobile industry make 99 percent of all vehicles. The top eight firms
account for 98 percent of copper shipments, 89 percent of aircraft, 65 percent
of primary steel, and 56 percent of petroleum refining.4*3
Since most chemical producers are primarily involved in other industries
(namely, the petroleum, natural gas, and steel industries), entry into the
chemicals industry can occur in a variety of ways. Throughout the mid-1960s,
the industry enjoyed premium profits, inciting a number of capital-intensive
firms to purchase other chemical companies or to diversify their own production.
As profits dropped through the 1970s, this practice reversed, so existing
chemical- companies began to diversify into other production practices—end-use
products, for example.1*'* Since the chemical interests of the top companies
vary in scope and dimension, the power these companies have on price control
is limited. The primary barrier to entry seems to be sufficient funds to
either build a new plant and buy new equipment or to buy into a chemical firm
9-32
-------
in an attempt to diversify. Most new entries into the industry in recent
years have been through acquisition or merger.k>4
9.1.4.3 Observed Pricing Practices. Chemical journals and periodicals
usually use list prices when reporting the cost of a chemical. Chemical
producers typically base their list prices on a full-cost or cost-plus
method. The full-cost method involves adding a desired profit margin to
estimated unit costs. Cost-plus pricing uses a percentage return on equity
.instead of a profit margin on sales to calculate product price. When demand
is more elastic, and the product can be easily substituted for, producers
settle for a lower profit margin. The market price is determined by supply
and demand at a particular time. Since these conditions change frequently,
producers offer discounts, add surcharges to list prices, or modify other
terms of sale to maintain their prices at market levels. Large-quantity
purchasers often enjoy lower prices than small-quantity purchasers, and
transportation costs may also affect pricing of chemicals.
As mentioned in Section 9.1.2, raw material inputs greatly influence the
prices for most chemicals. If an input is in short supply or is diverted to
other products with higher priorities, the selling price of the chemical is
apt to rise. For example, the OPEC embargo caused prices of oil-based
chemicals to rise. Alternatively, if a large amount of new capacity comes on
line for a product, the product's price is apt to decrease. When a large
share of plant capacity is idle, producers often offer discounts or reduce
prices to maintain plant utilization levels.
Another factor also influences pricing of chemicals. Some chemicals
experience seasonal variation in demand. Toluene, for example, and other
basic aromatics that can be used as octane enhancers in gasoline, experience
higher demand in the peak driving seasons of the year. Thus, capacity is
more highly utilized during this season, and supply tightens, allowing
chemicaV producers to raise their prices.1*5
Table 9-11 presents historical price index series for chemicals and
other manufacturing sectorso1*6 The dramatic rise in chemical prices due to
supply shocks is evident in the early 1970s, followed by steady increases in
both chemicals and allied products as a whole and in industrial chemicals
The annual real change over the period 1972 to 1982 for chemicals and allied
products is 11 percent, while industrial chemicals show a 13-percent annual
rise. Industrial commodities and all commodities show a more moderate
10-percent increase. While prices for the commodities and for the chemicals
and allied products group continued to rise from 1981 to 1982, prices for
industrial chemicals dropped by 3 percent. Record low capacity utilization
rates and soft markets due to the recession over the period contributed to
the price decline in this sector.
9.1.5 Market Performance
Emphasis in this section is on two aspects of market performance: the
finances of the organic chemical industry and recent trends in industry
variables.
9-33
-------
TABLE 9-11. PRICE INDEXES FOR U.S. CHEMICAL
AND OTHER INDUSTRIES, 1972-1982a 46
Year
1982
1981
1980
1979
1978
1977
1976
1975
1974
1973
1972
Chemicals and
allied products
292.4
287.6
260.3
222.3
198.8
192.8
187.2
181. 3
146.8
110.0
104.2
Industrial
chemicals
353.0
363.3
324.0
264.0
225.6
223.9
219.3
206.9
151.7
103.4
101.2
Industrial
commodities
312.3
304.1
274.8
236.5
209.4
195.1
182.4
171.5
153.8
125.9
117.9
All
commodities
299.3
293.4
268.8
235.6
209.3
194.2
183.0
174.9
160.1
134.7
119.1
Producer price index, 1967 = 100.
9-34
-------
9.1.5.1 Financial Profile of the Industry. Profitability and capital
structure are two of several measures that indicate the financial health of
an industry. Profitability is the measure of a firm's ability to maximize
its shareholder's wealth. Capital structure determines the ability of the
firm to raise funds for growth and to maintain stable earnings.
Profitability can be assessed in a number of ways. Table 9-12 presents
significant financial ratios for SIC categories 2865 and 2869, the two major
components of the organic chemicals group. Financial ratios are technical
terms that represent measures of an industry's financial health. ^ The four
measures presented provide a means of evaluating the profitability of the
organics sector. The first two values presented, which examine the revenue
and assets aspects of profitability, are the percentage of net profits to net
sales and the percentage of net profits to tangible net worth. The percent
of current debt to net worth and the percent of total debt to net worth
examine the debt and liability indicators of profitability. Figures 9-1 and
9-2, respectively, show historical trends in the percentage of net profits to
net sales and the percentage of net profit to net worth for the chemical
industry."8'1*9 Note that the data in the figures are from a different source
than the data presented in the tables; therefore the values cannot be
directly compared.
The percentage of net profits to net sales and net profits to tangible
net worth are primary indicators of profitability. Net profits to net sales
is the value of net earnings after taxes divided by net sales. This measure
is also referred to as the profit ratio and represents the ability of an
industry to produce goods and services at a profit. Figure 9-1 shows that
overall profitability increased over the early 1970s but decreased late in
the decade. After recovering between 1977 and 1979, the profit measure again
fell. Recent sources indicate that the fall in the profit measure has
?on?!H!ied 1nto the 1980s» slipping to 4 percent in 1982 from over 6 percent
in 1980, reducing the profitability of the industry.50
The percentage of net profits to tangible ne-t worth is the value of net
earnings after taxes divided by stockholders' equity. Stockholders' equity
is obtained by subtracting total liabilities from total assets and then
deducting intangibles. Intangibles are certain nonmaterial rights or benefits
of a firm and include patents, copyrights, trademarks, and goodwill.51 A
profit-to-equity measure of at least 10 percent is considered necessary to
ensure adequate funds for dividends and for future growth.52 Both SIC groups
have values in excess of 10 percent, although the value for SIC 2869 is
larger than that for SIC 2865. Figure 9-2 shows the profit to shareholders'
equity ratio for 1970 to 1980. This measure usually varies with the profit
ratio measure and is generally considered the key measure of profitability.
The remaining two financial ratios in Table 9-12, the percentages of
current debt to tangible net worth and total debt to tangible net worth, are
indicators of the debt status of the two SIC groups. The current debt to
tangible net worth figure should not surpass 80 percent for a financially
9-35
-------
TABLE 9-12. MEDIAN FINANCIAL RATIOS FOR SIC INDUSTRIES
2865 AND 2869, 198047
Median ratio
Net profits to
net sales
Net profits to
net worth
Current debt to
net worth
Total debt to
net worth
SIC 2865:
Cyclic crudes and
intermediates, %
4.57
17.06
94.7
150.9
SIC 2869:
Industrial organic
chemicals, NEC, %
4.99
17.28
41.7
58.8
NEC = Not elsewhere classified.
9-36
-------
I
OJ
s
I
I-
•t jm-
•^ 9
° •-
j -
1-
I-
Mil
1)12
isii
I
IWS
YEARS
1911 ISIS ISM
Nola: Nat talat aqual grou salai lati diicounls to custonnari. Salai ara maaiurad bafora axpanias and taxai.
Figure 9-1. U.S. Chemical industry annual profit margin: after-tax earnings
as a percentage of net sales, 1970-1960.48'49
-------
RETURN ON STOCKHOLDERS' EQUITY, %
c
CO
o
II
fs a.
I
o <
a-
Is
mT *+
£. »
"* M
l
ss-
B)
s
3,
i
-------
sound firm.53 For example, the cyclic crude and intermediates sector has
amassed a substantial amount of current debt compared to its stockholders'
equity. The total debt to tangible net worth figure is the percentage of
total current plus long-term debt to stockholders' equity. If this measure
were to exceed 100 percent, the equity of the firm's creditors would be
greater than that of the owners.51* Again, SIC 2865 shows less financial
stability and demonstrates an overall debt structure that threatens to damage
the long-term health of the industry, as this last ratio is more than 150
percent.
Profitability varies among the sectors of the organic chemical industry,
however. Commodities are generally more vulnerable to supply and demand
shifts than specialty chemicals, while specialty chemicals are generally more
profitable than other chemicals. For example, four of the five most profitable
chemical manufacturers in 1980 were specialty chemical producers.55 Because
reactor process chemicals are large-volume chemicals, the financial ratios
for the entire industry are most likely representative of the firms producing
them. Some financial data for 1982 on the 25 largest firms in the chemical
industry are presented in Table 9-13.56 (Note that net profit in Table 9-12
is the same measure as operating profit in Table 9-13. Therefore, the
operating profit margin.for these 25 producers can be compared to the net
profits to net sales figure for the whole industry shown in Table 9-12.)
Historically, the chemical industry has maintained its profits by
reducing costs while maintaining revenues. This allows firms to operate
above the "break-even" point, the point at which total costs and total
revenues meet.57 The break-even point is lowered when companies reduce fixed
costs enough to turn a profit at lower capacity utilization than before.
This is done by selling off assets, laying off employees or otherwise lowering
labor costs, and eliminating excess inventories.
In addition to profitability, capital structure is a major financial
consideration for the chemical industry. Table 9-14 lists the sources of
funds for 15-firms within the chemicals and allied products industry over a
period of several years.51* The industry traditionally has been heavily
internally financed. In 1982, 31.5 percent of funds came from depreciation.
Long-term debt has become increasingly important for the industry, however,
aLSeW> -a!?er Sca1e plants are retired- The low net income of the 1980 to
1982 period also contributed to high proportions of debt financing.
Table 9-15 presents debt ratios for the entire chemical industry compared
to all manufacturing.'*7 si The debt ratio is long-term debt as a percentage
of debt plus equity. Table 9-15 shows that the chemicals industry as a whole
historically has had debt ratios similar to those of all manufacturing but
that these ratios have increased relative to all manufacturing since the late-
1970s. Industrial chemicals have had higher debt ratios since the early
1970s. This indicates a trend in the industry toward raising capital externally
and, in the process, using up its available source of external funding
9-39
-------
TABLE 9-13. FINANCIAL DATA FOR TOP 25 U.S. CHEMICAL PRODUCERS. 1982
Chemical Change
operati ng from
profit, 1981,
Rank Company 10* 1982 $ X
1
2
3
4
5
6
7
3
9
10
11
12
13
14
15
16
17
18
19
20-
21
22
23
24
25
•Ou Pont
Dow Chemical
Exxon
Monsanto
Union Carbide
Shell Oil
Celanese
Standard •Oil
(Indiana)
W. R. Grace
Allied
Phillips
Petroleum
Atlantic
Richfield
Eastman Kodak
Mobil
Hercules
Gulf Oil
Rohm & Haas
American
Cyanamid
Stauffer
Chemical
American
Hoechst
Texaco
Ethyl
Air Products
FMC
Ciba-Geigy
417
226
47
497
294
-56
39
133
303
105
23
-96
205
6
75
-329
156
100
285
NA
-20
161
189
149
NA
-63.7
-63.1
-86.5
-26.0
-49.3
Oef
-82.3
-36.7
-23.5
-50.2
-83.6
Oef
-29.1
-95.1
-55.9
Oef
-16.6
-49.5
-7.3
NA
Oef
4.5
-4.2
-23.4
NA
Chemical
operati ng
profits as
X of total
operati ng
profits
10.6
63.5
0.6
99.2
44.7
Oef
100.0
3.7
50.2
13.4
1.0
Oef
11.0
0.1
65.3
Oef
98.7
43.4
100.0
NA
Def
84.5
93.7
81.7
NA
Operating Tangible
profit b chemical
margin, assets,
% 10« 1982 $
3.8
2.7
0.6
8.7
5.9
Oef
1.3
4.8
11.4
4.4
1.0
Oef
9.5
0.3
3.7
Oef
9.0
5.9
17.6
NA
Oef
11.4
13.9
11.3
NA
7445
3124
5047
5234
6027
3841
2862
2530
1608
1726
1563
2608
2001
2075
1468
1232
1008
1308
1756
NA
953
959
1596
1084
NA
Chemical
- assets,
X of
total
assets
36.6
68.3
8.1
86.1
57.3
18.0
100.0
10.6
34.5
27.5
14.9
12.1
19.3
5.8
90.4
6.6
90.7
56.5
100.0
NA
4.5
86.7
73.6
39.2
NA
Operating
return on
chemical
assets,
X
5.4
2.8
0.9
9.5
4.9
Oef
1.4
5.3
18.8
6.1
1.5
Oef
10.2
0.3
5.1
Oef
15.5
7.6
16.2
NA
Oef
16.8
11.8
13.7
NA
Def = Deficit.
NA = Not available.
*5ales less administrative expense and cost of selling.
Operating profit as a percentage of chemical sales.
Operating profit as a percentage of tangible chemical assets.
"Fiscal year ended September 30, 1982.
9-40
-------
TABLE 9:14. CASH FLOW FOR MAJOR CHEMICAL PRODUCERS.
1982
Source/application of funds
Sources of funds
Net income
Depreciation and depletion
Deferred taxes
Other internal sources
Long tem debt
Stock
Total
10* $
$2,692
5,073
694
2,167
3,466
1,834
16,126
X of
total
17.9%
31.5
4.3
13.4
21.5
11.4
100.0
1981
10« $
$4.358
4.267
1,012
1.833
7.493
4.931
23.894
X of
total
18.2%
17.9
4.2
7.7
31.4
20.6
100.0
us, i3/u-.i:
1980
10s $
$3,981
3.818
679
815
2,079
630
12,002
X of
total
33.2%
31.8
5.7
6.8
17.3
5.2
100.0
tot
1979 1Q7Q
10« $
$3.801
3.602
427
1.093
1,210
322
10,454
X of
total
36.3%
34.4
4.1
10.5
11.6
3.1
100.0
106 $
$3,085
3.197
353
930
1,545
84
9,194
total
33.6%
34.6
3.8
10.1
16.8
0 9
100.0
«3 Applications of funds
i
4*
Dividends
Capital expenditures
Additions to working
capital
Reduction of long-ter*
debt
Other applications
Total
Data are totals for 15 »ajor en
$2,003
6,506
-1,842
4.335
3.124
16.126
eaical coma
12.4%
52.7
-11.4
26.9
19.4
100.0
anioc
$1.845
8.344
3.759
1.483
8,453
23,894
7.7X
34.9
15.7
6.3
35.4
100.0
$1,603
7,027
1.057
1,119
1,196
12,002
13.4%
58.5
8.8
9.3
10.0
100.0
$1,474
5,633
1.075
1.042
1.230
10.454
1 ^ -- •
14. IX
53.9
10.3
10.0
11.7
100.0
==••••- - — • •
$1.317
5,080
863
879
1,054
9,194
14.3%
55.3
9 4
9 5
11.5
100.0
Current dollars.
-------
TABLE 9-15. DEBT RATIOS FOR THE U.S. CHEMICALS INDUSTRY AND FOR U.S. MANUFACTURING. 19/8-1982
10
l
ro
Industry group
Industrial chemicals and
synthetics
Long term debt3
Stockholders' equity
Debt ratio
Chemicals and allied
products
Long term debt
Stockholders' equity
Debt ratio
All Manufacturing
Long term debt'
Stockholders' equity
Debt ratio
1982
$21.0
$44.1
32. 2X
$37.2
$93.2
28. 5X
$292.9
$782. 3
27.2
1981
$21.4
$42.5
33. 5X
$36.9
$89.9
29. IX
$266. 5
$762. 3
25.9
1980
$16.8
$39.8
29. 6X
$28.3
$79.5
26.3%
$236.2
$699. 7
25.2
1979
$14.8
$32.3
31. 4X
$24.9
$67.4
27. OX
$204.8
$624.0
24.7
1978
$13.6
$29.3
31. 8X
$23.5
$60.8
27. 9X
$182.0
$560.8
24.5
1977
$12.3
$26.3
31. 9X
$21.1
$54.9
27. 8X
$167.3
$511.7
24.6
1976
$11.8
$25.0
32. OX
• $19.4
$50.8
27. 6X
$153.6
$475.3
24.4
1975
$10.2
$22.8
30. 8X
•
$16.8
$45.7
26.9%
$145.2
$435.5
25.0
1974
$7.8
$20.5
27.6%
$12.8
$40.9
23.8%
$130.1
$408.4
24.2
1973
$7.2
$18.7
27. 8X
$10.7
$36.7
22.6%
$112.9
$368. 0
23.5
19/2
$7.6
$18.5
29.2%
$11.5
$36.1
24.2%
$118.3
$353.1
25.1
aCurrent dollars.
bLong-teni debt as a percentage of long-ten* debt plus stockholders' equity.
-------
The change in capital structure from internal financing to debt financing
is related to a variety of factors. The industry has high fixed costs
because of the large capital costs of plants. Fixed costs do not depend on
the rate of production in any given period. When supply and demand conditions
are such that plants do not operate at full capacity, these high fixed costs
are distributed over lower production volumes, resulting in lower profit
margins and returns on stockholders' equity. Profitability and capital
utilization generally vary together. Capacity utilization was relatively
high in the early 1970s (above 80 percent), fell below 80 percent between
1975 and 1977, and rose again between 1977 and 1980. Since 1980, capacity
utilization has been very low, falling to 61 percent in 1982.58 Profitability
is expected to rebound as demand grows and capacity utilization increases.
9.1.5.2 Trends in the Chemical Industry. This section is a summary of
the movements in industry variables.Particular emphasis is given to some of
the trends within the various end-use groups identified for the 173 reactor
processes chemicals.
9.1.5.2.1 Overall industry trends. The chemicals industry has
traditionally been a growing and dynamic industry within the manufacturing
sector, usually growing at a faster rate than the economy as a whole because
of its generation of new products and rapidly changing technological
capability. Long-term growth in the physical output of the industry has
averaged 7.5 percent annually since 1960, as compared to 4 percent per year
for the manufacturing industries."2 The level of this output fluctuates with
conditions in the economy as a whole.
Until 1973, prices within the chemical industry demonstrated a steady
downward trend. In 1973, the oil supply shocks and subsequent rising feedstock
prices initiated increasing prices for most organics. Rising labor costs,
combined with lower productivity, have supplemented the price increases.
Profitability in the chemical industry is determined largely by the
capacity utilization of chemical plants. This utilization level is
determined in the short run by demand factors that depend on the overall
activity in the economy. Thus, the profitability of chemicals tends to be
nigher in periods of economic growth and lower in periods of recession.
A variety of factors may cause changes in the response of the chemical
industry to economic fluctuation in the future. Rising costs, foreign trade
competition, and a maturing industry have led some analysts to believe that
more and more chemical companies will enter into specialty chemical production
and leave commodity production.59 A reorganization of the industry is
expected in which unprofitable plants and operations are closed or go out of
business permanently to ensure the competitiveness of the firm as a whole.59
9.1.5.2.2 Description of end-use groups. The various end-use groups
into which the reactor process chemicals fall have experienced trends similar
to those of the whole industry, but have some characteristics peculiar to
each group. Some of these characteristics are discussed below.
9-43
-------
Basic chemicals are particularly tied to petroleum trends. Many olefin
plants are being built with flexibility in feedstock usage to allow for the
use of alternative feedstocks as those prices change.
Intermediates differ from other chemicals in that they are often consumed
captively by their producers. Therefore, reported production figures for
these chemicals based on sales generally underestimate actual production.
Total demand for intermediates, both external and internal, depends directly
on demand for their derivatives.
Plasticizers are used in the production of flexible polymers, such as
PVC, and are tied to the growth of the construction industry and related
industries. Pesticides are used primarily in the agricultural sector, so
their use is related to agricultural output. Growth in the production of
pesticides has traditionally been quite high.
Domestic consumption of aerosol propellants declined when they were
implicated in causing adverse upper-atmospheric environmental effects.
However, fluorocarbons with refrigerant and polymer end-uses now are expected
to experience some growth.
Fuel additives such as tetraethyl lead (TEL) and tetramethyl lead (TML)
are controlled by government regulation of gasoline, resulting in a reduction
in overall demand. Other fuel additives, such as methyl tertiary-butyl ether
(MTBE), have taken up the market traditionally supplied by TEL/TML and have
shown substantial growth.
9.1.6 Five-Year Industry Growth Projections
This section projects the number and capacity size of expansion and
replacement process units for the period July 1, 1985, through July 1, 1990,
for the production of the reactor processes chemicals. As defined in Chapter 5,
a process unit is one or more reactors feeding off-gas into a common product
recovery train. Process units affected by the regulatory alternatives are
built both to meet expanding demand and to replace capacity because of plant
retirement. For the purpose of these projections, the number of process
units added by 1990 is estimated based on the need for additional capacity
due both to outward shifts in demand (expansion capacity) and to plant
retirement (replacement capacity).
Technically, expansion capacity may take the form of new grassroots
process units or of small process units added at existing production sites.
Replacement capacity is defined as capacity built to accommodate retirement
of existing capacity because of age or technological change. Replacement
capacity generally oqcurs as onsite .reconstructions or as grassroots construc-
tion of process units. During the 5-year period beginning July 1, 1985, 56
process units are projected to be built to accommodate growth and plant
retirement in the reactor processes segment of the synthetic organic chemical
industry. Most of these process units will be built because of the retirement
of old process units. Approximately one-third will be built due to increases
in demand for chemicals.
9-44
-------
As discussed in Chapter 3, the projected process units are assumed to
/lno^emluS10n Characterist1'cs similar to those in the emissions data profile
(EDPj Many of the affected chemicals are currently produced in areas that
have Federal or State regulations affecting VOC emissions from SOCMI plants
In the projections, it is assumed that affected chemical capacity will be
located in states whose State Implementation Plans (SIPs) are similar to
those of states in which most of that chemical's current production is
located. If strict SIPs apply in those locations, that chemical is assumed
to be controlled at the baseline. Therefore, separate projections for SIP
and non-SIP process units are not made. Though the EDP does not exclude
batch process data from its calculations, the economic analysis assumes there
are no batch processes for the 173 large-volume chemicals. The projections
cover the area that includes the 50 States, the District of Columbia, and
Puerto Rico to the extent available data allow. The following sections
describe the methodologies used to arrive at these projections.
.9'1'?-1 Projection of Capacity Requirements. For each chemical, the
required increase in capacity due to increased demand and plant retirement
?oon tneS-year Projection interval is computed as a function of projected
1990 production, estimated 1985 capacity, an estimate of plant retirement
and an assumed projected capacity utilization at existing plants in 1990.
Projections of 1990 production and estimates of 1985 capacity are made
in two ways. Chemical-specific projections are made for those chemicals for
which data are available. For other chemicals, average growth trends and
capacity utilization factors for the general end-use groups identified in
Section 9.1.2 are used. The chemical-specific and end-use methodologies for
obtaining 1985 capacity and 1990 production projections are detailed below.
The data used in projecting 1990 production and potential required capacity
for the 173 large-volume chemicals are presented in Table 9-16.
9.1 6.1.1 Chemical-specific growth projection methodology. Of the 173
large-volume chemicals, lib have growth potential sufficient to project the
need for additional plant capacity by 1990. For 73 of the chemicals with -
potential for growth, complete data are available from a variety of sources
on historical domestic consumption, exports, imports, and capacity, along
with projections of future consumption, exports, and imports.*"6 These data,
along with estimates of 1985 production and capacity, are used to project
1990 production and capacity requirements.
For the most part, 1985 capacity and production are" estimated based on
data and forecasts from Mannsvilie Chemical Products Synopsis (MCP) and the
Chemical Marketing Reporter (CMR).1*'* For those chemicals for which no
estimates are available, 1985 capacity is assumed to be the same as the
latest actual or projected capacity figures available, and 1985 production is
°.s!7.!ote,s,J Projection fl>re times a yearly growth rate
nn7 0«che?o«e ***"?* 1985 MPac1^ 1S lfi" tha" estimated
J 5' i985 caPacft* ls increased to equal production in 1985
by an assumed average capacity utilization rate of 85 percent.58
9-45
-------
TABLE 9-16. PROJECTED U.S. PRODUCTION, CAPACITY, AND GROWTH RATES
FOR REACTOR PROCESSES CHEMICALS FOR 19854 s 6 7 s 9 10
Chemical
Acet aldehyde
Acetic acid
Acetic anhydride
Acetone
Acetone cyanohydrin
Acetyl ene
Acrylic acid
Acrylonitrile
Adipic acid
Adiponitrile
Alcohols, C-ll or lower,
mixed
Alcohols, C-12 or higher,
mixed
Alcohols, C-12 or higher,
unmixed
Allyl chloride
Amy 1 ene
Amylenes, mixed
Anil ine
Benzene
Benzenesulfonic acid
Benzenesulfonic acid, mono-
Cio is alky! derivatives,
sod4um salts
Benzyl chloride
Bisphenol A
Bi vinyl
Brometone
Butadiene and butene
fractions
Butanal
Butane
Butane, mixed
1,4-Butanediol
2-Butoxyethanol
1985
Produc-
tion,
Gg
91
1503
522
1017
513
166
229
853
701
187
55
352
91
*
79
45
372
5860
48
45
59
320
1388 -
45
511
434
844
45
164
2045
1985
.Capa-
city,
Gg
272
1905
653
1482
828
195
*
1052
803
366
95
608
156
*
137
78
581
7761
236
71
82
374
2107
69
*
717
2010
78
193
3205
Annual
growth
rate,
%
0
3
0
2
3
2.5
*
3
0.6
3
2
2
2
2
2
2
5
2.5
3
3
3
10
3
0
3
2
3
2
5
3.7
Sources
MCP 1/83, CMR 1/11/82
MCP 4/82, CMR 5/9/83
MCP 9/82, CMR 5/16/83
MCP 3/83, CMR 9/25/80
USITC 1981, EU
MCP 9/82
USITC
MCP 4/83
MCP 8/81, CMR 11/24780
TSCA, EU
USITC, EU
USITC, EU
USITC, EU
EU
TSCA, EU
EU
MCP 10/82, CMR 2/2/82
MCP 7/82, CMR 1/5/81
TSCA, EU
EU
•
MCP 7/78, CMR 8/31/81
MCP 1/82, CMR 5/26/80
USITC, SRI 1982, PTS, EU
PC
USITC, EU
USITC, SRI 1982, EU
USITC, EU
EU
MCP 4/81
MCP 12/82, CMR 6/6/81
Footnotes on last page of table.
(continued)
. 9-46
-------
TABLE 9-16 (continued)
Chemical
Butyl acrylate
n-8utyl acetate
t-Butyl alcohol
sec-Butyl alcohol
n-Butyl alcohol
Butyl benzyl phthalate
a + B-Butyleneq
Butyl enes, mixed
t-Butyl hydroperoxide
2-Butyne-l,4-diol
Butyric anhydride
Cap ro lac tarn
Carbon disulfide
Carbon tetrachloride
Chloroacetic acid
Chlorobenzene
Chloroform
p-Chloronitrobenzene
Citric acid
Cumene
Cumene hydroperoxide
Cyanuric chloride
Cyclohexane
Cyclohexane, oxidized
Cyclohexanol
Cyclohexanone
Cyclohexanone oxime
Cyclohexene
Di acetone alcohol
1 , 4-Di chl orobutene
3,4-Dichloro-l-butene
Diethanolamine
Di ethyl benzene
1985
Produc-
tion,
Gg
138
60
463
213
383
48
400
281
45
45
45
419
171
316
47
120
191
45
157
1558
45
45
842
68
45
340
45
45
19
45
45
73
45
1985
Capa-
city,
Gg
203
77
712
367
680
685
471
752
69
250
78
567
304
494
59
159
379
73
186
2134
69
73
1322
117
998
1089
78
78
27
250
89
114
68
Annual
growth
rate,
%
2
3
2
2
3
0
3
3
3
2
0
0.8
1
1
2
3.7
3.5
3
2.5
7.6
3
3
1.5
2
0
1.5
0
0
7.5
3
3
3
•3
. b
Sources
USITC, EU
MCP 3/83, CMR 10/26/81
TSCA, EU
SRI 1982, EU
MCP 12/81, CMR 12/7/81
TSCA, PC
PTS, SRI 1982, EU
SRI 1982, USITC, EU
EU
TSCA, EU
PC, EU
CMR 9/22/80
MCP 3/83, CMR 1/24/83
MCP 2/83, CMR 2/21/83
MCP 12/81, CMR 4/25/83
MCP 2/83, CMR 10/6/80
MCP 1/83, CMR 1/31/83
EU
MCP 8/81
MCP 4/83, CMR 5/11/81
EU
EU-
MCP 6/82
TSCA, EU
TSCA, PC
MCP 9/82
PC, EU
PC, EU
MCP 5/82
TSCA, EU
EU
USITC, EU
EU
Footnotes on last page of table.
(continued)
9-47
-------
TABLE 9-16 (continued)
Chemical
Diethylene glycol
Oiisodecyl phthalate
Dimethyldichlorosilane
Dimethylterephthalate
2,4-(and 2,6)-Dinitrotoluene
2,4-Oinitrotoluene
Dioctyl phthalate
Oodecene
Dodecyl benzene, linear
Dodecyl benzene, nonlinear
Dodecylbenzenesulfonic acid
Dodecylbenzenesulfonic acid,
sodium salt
Epichlorohydrin
Ethanolamine
Ethyl acetate
Ethyl acrylate
Ethyl alcohol
Ethyl benzene
Ethyl chloride
Ethyl ene
Ethyl ene di bromide
Ethyl ene di chloride
Ethyl ene glycol
Ethyl ene glycol monoethyl
ether
Ethyl ene glycol monoethyl
ether acetate
Ethyl ene oxide
2-Ethylhexyl alcohol
(2-Ethylhexyl) amine
6-Ethyl-l,2,3,4-tetrahydro-
9 , 10-anthracenedi one
1985
Produc-
tion,
Gg
199
100
45
2835
45
252
136
188
126
121
113
174
204
221
113
136
566
4154
88
• 14067
83
5383
2050
85
45
2404
177
45
45
1985
Capa-
city,
Gg
318
189
69
3335
69
381
386
232
465
188
177
272
290
295
133
199
824
4774
302
17736
142
8101
3205
130
70
3402
268
78
•V A
73
Annual
growth
rate,
%
3
*
2
3
3
2.5
2
1.5
1.5
1.5
1.5
3
3
2.3
2
2
3
-12
4.5
0
4
3.7
2.5
0
3.6
4
0
Sources
MCP 12/81
USITC, EU
d i
EU
USITC .
EU
USITC, EU
MCP 6/82
USITC, SRI 1982, EU
CMR, MCP 1/82
MCP 1/82
USITC, EU
USITC, EU
MCP 1/82
MCP 11/82, CMR 5/3/82,
MCP 1/81, CMR 1/17/83
USITC, EU
MCP 2/82, CMR 5/24/82
MCP 11/81, CMR 2/23/81
MCP 3/83
MCP 4/83, CMR 4/19/82
USITC, EU
MCP 6/81, CMR 6/13/83
MCP 12/82, CMR 6/15/81
USITC, EU
'PC, EU
MCP 12/82, CMR 6/8/81
MCP 6/82, CMR 3/8/82
PC, EU
ri i
CU
Footnotes on last page of table.
(continued)
9-48
-------
TABLE 9-16 (continued)
Chemical
Fluorocarbon 113
Formaldehyde
Freon 11
Freon 12
Freon 21
Freon 22
Glycerin
Heptane
Heptenes, mixed
Hexane
Hexamethylene diamine
Hexamethylene diamine adipate
Hexamethylene tetraamine
Isobutane
Isobutyl alcohol
Isobutylene
Isobutyraldehyde
Isopentane
Isoprene
Isopropyl alcohol
Ketene
Linear alcohols, ethoxylated,
1985
Produc-
tion,
Gg
45
2681
74
148
45
115
60
45
63
182
*
45
41
519
92
530
131
2515
241
920
45
215
1985
Capa-
city,
Gg
73
4128
119
239
73
185
70
80
75
314
979
89
68
1237
109
624
177
988
284
1340
78
406 -
Annual
growth
rate,
%
4
4
4
4
4
4
0.5
5
2
2
3
3
0
3
2
4.2
2
3
3
1.5
0
2
b
Sources
EU
MCP 12/81
MCP 8/82
MCP 8/82,
EU
MCP 8/82,
MCP 2/82
EU
USITC, SRI
USITC, EU
TSCA, EU
EU, TSCA
MCP 6/82
USITC, EU
USITC, SRI
PTS, SRI
USITC, SRI
TSCA, EU
USITC, SRI
CMR 3/7/83
CMR 3/7/83
, EU
, EU
> ww
, EU
j ~w
1982, EU
MCP 6/81, CMR 3/2/81
PC, EU
USITC, EU
Linear alcohols, ethoxylated
and sulfated, sodium salt,
mixed
Maleic anhydride
Methyl alcohol
Methyl amine
ar-Methy1benzenedi ami fie
Methyl chloride
66
147
6622
112
45
157
96
USITC, EU
222 4.5 MCP 9/82, CMR 8/1/83
7790 9 MCP 7/82
157 3 CMR 1/18/82
69 3 EU
282 0 MCP 4/82, CMR 3/21/83
Footnotes on last page of table.
(continued)
9-49
-------
TABLE 9-16 (continued)
Chemical
Methyl chloroform
Methylene chloride
Methyl ethyl ketone
Methyl isobutyl ketone
Methyl methacrylate
Mesityl oxide
2-Methylpentane
1-Methyl -2-pyrrol i done
Methyl -t-butyl ether (MTBE)
Naphthene
Nitrobenzene
Nonyl alcohol
Nonyl phenol
Nonylphenol, ethoxylated
Octene
Oil -soluble petroleum
sulfonate, calcium salt
3-Pentenenitrile
Pentaerythritol
Pentenes, mixed
Perchloroethylene
Phenol
1-Phenyl ethyl hydroperoxide
Phenyl propane
Phosgene
Phthalic anhydride
Propanal
Propane
Propyl alcohol
Propylene
Propyl ene glycol
Propylene oxide
Sorbitol
Styrene
Terephthalic acid
1985
Produc-
tion,
Gg
319
. 291
243
96
462
45
45
45
1814 '
69
522
45
70
117
45
119
45
49
80
274
1143
45
45
884
393
45
3862
66
6600
338
1045
99
3485
2373
1985
Capa-
city,
Gg
433
458
318
113
590
70
78
68
2134
318
760
86
173
184
86
185
69
84
138
411
1581
69
68
1040
712
78
9195
100
15714
398
1433
205
4184
3011
Annual
growth
rate,
%
3
3
3
8
4.5
2
2
3
10
3
3.5
0
3
*
2
3
0
1
2
-2
1.8
3
3
3.5
3
2
2
3.5
5.5
4.5
4.6
- 4.3
3.5
Sources
MCP 11/82, CMR 3/28/83
MCP 5/83
MCP 11/82, CMR 8/9/82
MCP 5/82, CMR 12/15/80
MCP 8/82, CMR 12/14/81
EU
EU
EU
MCP 7/82
USITC, SRI 1982, EU '
MCP 9/80, CMR 8/6/82
PC
MCP 9/82
USITC, EU
EU
USITC, EU
PC
MCP 1/83, CMR 4/4/83
USITC, EU
MCP 5/83, CMR 3/14/83
MCP 3/83, CMR 9/1/80
EU
EU
MCP 9/80
MCP 12/82, CMR 7/11/82
EU
USITC, EU
MCP 2/83
MCP 8/82
MCP 6/81
MCP 6/81, CMR 12/21/81
MCP 7/82, CMR 6/21/81
MCP 10/82, CMR 1/12/81
MCP 5/83
Footnotes on last page of table.
(continued)
9-50
-------
TABLE 9-16 (continued)
Chemical
Tetraethyl lead/tetramethyl
1 __ j
1985
Produc-
tion,
Gg
125
1985
Capa-
city,
Gg
170
Annual
growth
rate.
%
0
Sources
USITC, SRI
Tetrahydrofuran 53 78 2
Tetra (methyl-ethyl) lead 60 105 0
Toluene 414 986 5.7
Toluene-2,4-diamine 100 239 3
Toluene-2-4-(and 2,6)- 323 380 2
diisocyanate (80/20 mixture)
Trichloroethylene 92 154 -1
Triethanolamine 62 97 3
Triethylene glycol 57 82 1
Trimethylene 45 60 3
Tripropylene 148 256 2
Vinyl acetate 953 1089 4.5
Vinyl chloride, monomer 3287 4110 4
Vinylidene chloride * * 5.5
EU, SRI 1982
USITC, EU
MCP 9/82, EU
EU, USITC
MCP 4/82, CMR 11/15/82
MCP 3/83,
USITC, EU
MCP 11/81,
EU
EU, SRI 1982
MCP 4/83, CMR 5/23/83
MCP 1/83, CMR 6/20/83
EU
Vinyl trichloride
Xylenes, mixed
m-Xylene
o-Xylene
p-Xylene
98
3087
*
502
1929
151
7348
*
591
2434
2
2
3
2
4
USITC, EU
MCP 1/83
EU
MCP 1/83
MCP 1/83
aGrowth rate for consumption.
'Source abbreviations refer to the following publications and assumptions:
Mf*D ftlsM^tf* 11 *» /*!* AM 4 MAIA.^^^...^-** •_ r
MCP
CMR
SRI
USITC
Mansville Chemical Products Synopsis
Chemical Marketing Reporter
SRI Directory of Chemical Producers
USITC Synthetic Organic Chemicals: U.S. Production and Sales, various
years
Toxic Substances Control Act Survey
Predicasts, Inc. PTS U.S. Forecasts Data
Growth rate based on production chain analysis
End-use growth rate average and/or capacity utilization factor used.
Data for a- and 8-butylene are combined. Approximately 25 percent of total
production is B-butylene.
*These data are considered proprietary and are used in subsequent calculations.
TSCA
PTS
PC
EU
9-51
-------
For 1990 production, projections are made by applying a consumption
growth rate to 1985 production:
1990 Production = (1 + GR)5 x 1985 Production ,
where
Production = (consumption and exports) - imports
GR = forecast growth rate of consumption.
Specifically, production is considered a function of domestic consumption,
exports, and imports, with imports being subtracted from and exports added to
domestic consumption figures to account for all production. In extrapolating
1981 and 1982 import and export data to 1990, it is assumed that imports and
exports in 1990 will maintain the same percentage relationship to domestic
consumption as they did in the year of the most current data. It is also
assumed that no changes in inventory levels would occur.
9.1.6.1.2 End-Use projection methodology. Projections cannot be made
in the manner described above for a number of chemicals due to a lack of
chemical-specific data. These chemicals are arranged into 14 end-use groups
as described in Section 9.1.2. It is assumed that chemicals with similar end
uses will experience similar growth in domestic production and consumption
during the period 1985 through 1990.
For those chemicals for which current production and capacity are
available but for which no estimates of future growth rates are found, the
average annual growth rate for the end-use group is used to project 1990
production. The end-use growth rates averaged are those expected for the
individual chemicals or those inferred from published projections of future
production. Table 9-17 shows the average rounded growth rates for each
end-use group.
The growth rates for several chemicals are determined using production
chain analysis. If the chemicals used to manufacture the chemical of interest
and the chemicals made from the chemical of interest show no growth, then
that chemical is considered not to be growing.
For a number of chemicals, production information is available, but not
capacity estimates. In these cases, the capacity for the chemical is estimated
using production and a capacity utilization factor derived for each end-use
group. The capacity utilization factor is an average of the ratios of
production to capacity for those chemicals with complete data in each end-use
group. Table 9-17 also presents the average capacity utilization figures for
each -end-use group.
For several chemicals, no data on production or capacity are available.
In these cases, a 1985 production of 45.4 Gg, the minimum production level
9-52
-------
TABLE 9-17. END-USE GROUP AVERAGE GROWTH RATES, RATIOS OF RETIRED
CAPACITY TO 1990 PRODUCTION, AND CAPACITY UTILIZATION FOR
REACTOR PROCESSES CHEMICALS IN THE 1980s
Average end-use
annual growth
Group rates, %
Basic chemicals
General aromatics
General nonaromatics
Synthetic elastomers
Plastics and fibers
Plasticizers
Pesticides
Dyes
Solvents
Detergents and surfactants
Fuel additives
Aerosol propel lants and
refrigerants
Coatings
Miscellaneous end-use
3
3
2
3
3
2
3a
3a
2
3
5
4
2
3
Average ratio of
ret.i red
capacity
to 1990
production
0.24 .
0.26
0.45
0.35
0.29
0.34
0.28b
0.28b
0.39
0.12
0.28b
0.28b
0.34
0.20
Average end-use
capacity
utilization, %
42
67
58
51
66
53
62C
62C
65
64
57
62C
68
76
Note: Figures are rounded.
The growth rates for the groups pesticides and dyes are the average for
the entire group of 173 chemicals.
The figure is the overall group average ratio of retired capacity to 1990
production figures.
The capacity utilization figures for pesticides, dyes, and aerosol propel-
lents and refrigerants are the overall group average. Data are insuffi-
cient to determine end-use averages for thes.e groups.
9-53
-------
required for inclusion in the study, is used. This estimate of 1985 production
is used with the end-use growth rate to estimate 1990 production. The
minimum production figure is also used with the end-use capacity utilization
figure to estimate 1985 capacity.
No production information is available for allyl chloride, sec-butyl
alcohol, tetrahydrofuran, and tripropylene. However, capacity information is
used, along with the capacity utilization average for the respective end-use
groups, to estimate production in 1985. The end-use growth rate is then used
to determine growth over the 1985 to 1990 period.
In the case of a few chemicals, estimated 1985 production is slightly
larger than existing capacity figures that are used to approximate 1985
capacity. This is due to the assumption of constant capacity and constant
export and import proportions. In these cases, 1985 production is divided by
the historical capacity utilization rate of 85 percent58 to get the 1985
capacity figure.
9.1.6.1.3 Estimation of Retired Capacity. A 20-year lifetime for
chemical plants is used for the purposes of tnis analysis. With this assump-
tion in plant lifetime, the amount of capacity added over the period 1965 to
1970 is roughly the amount of capacity that might be retired during the 1985
to 1990 time period. Data on 1965 and 1970 capacity for 64 of the subject
chemicals are available in Mannsville Chemical Products Synopsis^and in
Chemical Engineering Construction Alerts.60"65 The additions to production
capacity made between 1965 and 1970 in the form of modifications, reconstruc-
tions, or grassroots process units are used as an estimate of the amount of
capacity that came online during the period.
For those chemicals without chemical-specific information, the amount of
retired capacity is estimated by using the average ratio of retired capacity
to the production projection for 1990 for the chemicals in its end-use group
with data. This average ratio yields a value that is more realistic than the
average retired capacity values for the end-use groups, which are larger than
the total 1990 production estimates for some of the chemicals. Table 9-17
presents the average ratio of retired capacity to 1990 production for those
chemicals with chemical- specific information for each end-use group.
Retired capacity for those chemicals without chemical-specific information is
thus estimated as its end-use group average ratio x 1990 production.
9.1.6.1.4 Calculation of additional capacity requirements in 1990. The
projection technique described below yields the production capacity needed in
1990 to meet the projected growth in consumption for each chemical between
1985 and 1990. Though the methodology actually compares projected 1990
consumption and 1990 available capacity, it estimates the total, amount of
production capacity that will be added at various times throughout the 5-year
period, 1985 to 1990.
9-54
-------
-h Tl!5-l"te9ral e1ement ?! this methodology is an assumption that defines
when additional process units will be constructed throughout the 5-year
period. Specifically, based on industry analysis, it is assumed that the
industry will not operate its existing capacity at a utilization rate greater
than 85 percent.58 Therefore, whenever production demand from growth in
consumption increases to 85 percent of the capacity available at that time,
the industry will decide to construct additional process units.
In the projection methodology, the projected 1990 consumption is compared
to 85 percent of the available 1990 .capacity to determine if additional
process units are needed. Though performed on projected fifth-year values,
this calculation gives a reasonable estimate of the capacity that should be
added throughout the first 5 years of the standard by employing the construc-
tion decision factor of 85 percent maximum capacity utilization.
K * TheioocUalJC?lo«1!t1on f1rst subtracts the estimate of capacity retired
between 1985 and 1990 from the amount of capacity existing in 1985 to determine
the capacity available in 1990. If projected consumption is greater than
85 percent of the capacity available in 1990, then additional production
capacity is needed. The minimum amount of capacity that must be added to
maintain an industry capacity utilization rate of no more than 85 percent is
equal to 1990 consumption divided by 0.85— total capacity needed-minus the
amount of available capacity.
An example demonstrates more clearly the required capacity projection
methodology used in this analysis. Acrylonitrile has a projected 1990
production of 981 Gg/yr based on a growth rate in consumption of 3 percent
per year. Capacity in 1985 is estimated to be 1,052 Gg/yr, and 279 Gq are
199° production is greater than ss pe?cent °f
>(0.85)(1,052 - 279), 981 >657
2tlSS51g keq38ledg/;
Qfll
735 - (1,052 - 279) * 381 Gg.
.-,! 9-1-?-2 Process Unit Projections. A total of 110 of the 173 chemicals
will require expansion or replacement capacity during the 1985 to 1990 period
(see Table 9-18). As shown in the table, 22 of the 110 chemicals have vent
streams that are combusted at baseline based on information in the EDP and,
thus, would not require additional controls under any regulatory alternatives
considered. 66 An additional 62 have no vent streams at baseline, so these
rh±>^ldr+ b?i ?1gn1ficantly affected *y the NSPS-68 The remaining 26
5«?r« K I 2 ^1 r^uire add1t1onal capacity have vent streams that are
not combusted at baseline. Projections of the number of process units needed
to accommodate the total amount of additional capacity are made for these
chemicals using a single process unit size for each chemical -the median
process unit size.
9-55
-------
TABLE 9-18 U S CONSUMPTION AND CAPACITY PROJECTIONS AND REQUIRED CAPACI1Y FOR
110 REACTOR PROCESSES CHEMICALS IN 1990 (Gg/yr)
Chemical name
Acetic acid
Acetone
Acetylene
Acrylonitrile
Adipic acid
Alcohols C-ll, or
*P lower mixed
en
°* Alcohols C-12, or
higher, mixed
Alcohols C-12 or
higher, unmixed
Ally! chloride
Amylene
Amylenes mixed
Aniline
Benzene
(1)
Estimated
capacity
in 1985
1905.1
1481.5
165.6
1052.4
802.8
94.6
607.7
156.4
289.9
136.9
78.2
580.6
7761.1
(2)
Capac i ty
to be
retired
(1985-1990)
544.3
410.5
0.0
279.0
215.5
28.0
171.7
48.5
86.4
39.7
22.6
65.7
1625.5
(3)
(5) a
Additional capacity
required to accommo-
Capacity (4) date consumption in Process
available Projected 1990 at 85 percent vent/
in 1990 consumption utilization babel ine
(1-2) in 1990 (4/0.85-3) combustion
1360.8
1071.0
165.6
773.4
587.3
66.6
436.0
107.9
212.5
97.2
55.6
514.9
6135.6
1745.5
1159.6
190.6
981.1
719.1
62.0
379.9
107.3
191*. 1
87.9
50.0
474.4
6682.6
692.7
293.3
58.7
380.9
258 7
6.3
10.9
18 4
12.3
6.3
3.2
43.3
1/26 J
yes/yes
no/—
no/--
no/--
yes/no
no/--
\m/-~
no/- -
no/--
no/--
no/--
no/--
„„/-
-------
TABLE 9-18 (continued)
01
Chemical name
Benzyl chloride
Bispneno) A
Biyiny)
Butana)
Butanes nixed
1,4-Butanediol
2-ButoxyethanoI
Butyl acrylate
n-Butyi acetate
t-Butyl alcohol
sec-Butyl alcohol
a.b-Butylene
t-Butyl hydroperoxide
Capro lac tarn
(1)
Estimated
capacity
in 1985
81.6
374.2
2107.0
716.7
78.2
195.5
3204. 7
173.4
77.1
711. B
367.4
258.6
68.7
567.0
/ 1 \
(2)
Capac i ty
to be
retired
(1985-1990)
18.1
54.4
607.4
164.6
22.6
70.4
419.6
40.1
0.0
185.8
166.2
60.7
15.4
77.1
(3)
Capacity
available
in 1990
(1-2)
63.5
319.8
1499.6
552.1
55.6
105.1
2785. 1
133.3
77.1
526.0
261.2
197.9
53.3
489.9
(5)
Additional capacity
required to accomno-
(4) date consumption in Process
Projected 1990 at 85 percent vent/
consumption utilization baseline
in 1990 (4/0.85-3)° combustion
68.7
504.9
1752.5
477.5
50.0
200.0
2496. 3
117.9
71.0
481.2
235.0
216.8
52.3
438.9
17.3
274.2
562.2
9.7
3.2
130.2
151.7
5.4
6.5
40.1
15.3
57.2
8.2
26.5
yes/no
no/--
no/--
yes/yes
no/--
yes/yes
yes/yes
yes/no
yes/no
yes/no
yes/yes
no/--
yes/no
no/--
(continued)
-------
TABLE 9-18 (continued)
Chemical name
Carbon tetrachloride
Chlorobenzene
p-Chloronitrobenzene
Citric acid
Cumene
Cumene hydroperoxide
Cyanuric chloride
Cyclohexane oxidized
Diacetone alcohol
Diethylbenzene
Diethylene glycol
Dimethyldichlorosi lane
Dimethy 1 terephthal ate
2.4-(and 2.6)-
Oinitrotoluene
2,4-Dinitrotoluene
(1)
Estimated
capacity
in 1985
494.4
158.8
73.2
186.0
2134.2
68.7
73.2
117.3
27.2
67.6
317.5
68.7
3375.7
68.7
381.4
(2)
Capac i ty
to be
retired
(1985-1990)
158.8
0.0
14.7
36.6
689.5
15.4
14.7
33.9
11.7
13.4
104.3
15.4
1146.9
15.4
88.7
(3)
Capacity
available
in 1990
(1-2)
335.6
158.8
58.5
149.4
1444.7
53.3
58.5
83.4
15.5
54.2
213.2
53.3
2228.8
53.3
292.7
(5)
Additional capacity
required to accommo-
(4) date consumption in Process
Projected 1990 at 85 percent vent/
consumption utilizatiog baseline
in 1990 (4/0.85-3)° combustion
367.4
143.5
52.3
180.4
1854.7
52.3
52.3
75.0
25.8
52.3
236.4
52.3
3326.6
52.3
302.3
96.6
10.0
3.0
62.9
737.3
8.2
3.0
4.8
14.9
7.2
64.9
8.2
1684.9
8.2
62.9
no/--
yes/no
yes/no
no/--
no/--
no/--
yes/no
no/--
yes/no
yes/no
no/--
no/--
no/--
yes/no
yes/no
(continued)
-------
TABLE 9-18 (continued)
10
Chemical name
Oodecene
Epichlorohydrin
Ethanolamine
Ethy] acetate
Ethyl acrylate
Ethyl alcohol
Ethy (benzene
Ethylene
Ethylene dichloride
Ethylene glycol
Ethylene glycol
monoethyl ether
Ethylene oxide
2-Ethylhexyl alcohol
6-Ethyl-l. 2.3,4-
tetrahydro-9.10
anthracenedione
(1)
Estimated
capacity
in 1985
293.9
290.3
294.8
122.5
199.4
823.7
4774.1
17735.8
8101.3
3204.7
130.5
3402.0
267.6
73.2
(2)
Capacity
to be
retired
(1985-1990)
141.9
22.7
22.7
20.4
56.6
337.0
1421.7
4263.8
. 2492.5
406.0
36.8
811.9
122.9
14.7
(3)
Capacity
available
in 1990
(1-2)
152.0
267.6
272.1
102.1
142.8
486.7
3352.4
13472.0
5608.8
2798.7
93.7
2590. 1
144.7
58.5
(4)
Projected
consumption
in 1990
313.9
243.4
257.0
126.7
166.6
624.1
4843. 1
17529.4
7397.9
2551.4
95.3
2661.7
224.1
52.3
(5)
Additional capacity
required to accommo-
date consumption in
1990 at 85 percent
utilization
(4/0.85-3)"
217.2
18.8
30.2
47.0
53.1
247.6
2345.3
7150.9
3094.6
202.9
18.4
541.3
118.9
3.0
—----—=
Process
vent/
baseline
combustion
no/--
yes/yes
no/--
yes/no
yes/no
no/--
yes/no
no/--
yes/yes
no/--
yes/yes
yes/no
no/--
yes/yes
(continued)
-------
TABLE 9-18 (continued)
id
i
Ot
o
Chemical name
Fluorocarbon 113
Formaldehyde
Freon 11
Freon 12
Freon 21
Freon 22
Glycerin
Heptane
Heptenes Mixed
Hexane
Isobutyl alcohol
Isobutylene
Isobutyraldehyda
Isopentane
Isoprene
(1)
Estimated
capacity
in 1985
73.2
4127.8
119.3
239.2
73.2
185.1
70.3
79.6
109.5
313.6
108.9
335.7
176.9
2514.8
286.7
(2)
Capacity
to be
retired
(1985-1990)
15.3
832.4
25.2
50.5
15.3
39.0
49.9
16.0
31.8
90.8
38.6
86.9
50.1
703.0
96.2
(3)
Capacity
available
in 1990
(1-2)
57.9
3295.4
94.1
188.7
57.9
146.1
20.4
63.6
77.7
222.8
70.3
248.8
126.8
1811.8
190.5
(5)
Additional capacity
required to accommo-
(4) date consumption in Process
Projected 1990 at 85 percent vent/
consumption utilization baseline
in 1990 (4/0.85-3)" combustion
54.7
3167.3
90.1
180.2
54.7
139.2
61.5
57.2
70.3
200.8
99.9
295.9
145.3
2890. 1
277.5
6.5
430.8
12.0
23.2
6.5
17.6
52.0
3.7
5.0
13.4
47.3
99.3
44.1
1588.4
136.0
no/--
no/--
no/--
no/--
no/--
no/--
no/--
no/--
no/--
no/--
yes/yes
no/--
yes/yes
no/--
yes/yes
(continued)
-------
TABLE 9-18 (continued)
to
Chemical name
Isopropyl alcohol
Maleic anhydride
Mesityl oxide
Methyl alcohol
Methyl ant ne
ar-Methylbenzenedia-
•ine
Methyl chloride
Methyl chloroform
Methylene chloride
Methyl ethyl ketone
Methyl isobutyl ketone
Methyl methacrylate
l-methyl-2-pyrrol idone
Methyl t-butyl ether
(MTBE)
(1)
Estimated
capac i ty
in 1985
1340.4
222.3
69.8
7883.6
157.4
68.7
282.1
433.2
458.1
317.5
114.3
589.6
67.7
2160.0
(2)
Capacity
to be
retired
(1985-1990)
258.6
33.1
19.3
5220. 3
58.5
15.4
99.8
136.1
113.4
40.8
27.2
199.6
13.4
978.0
(3)
Capacity
available
in 1990
(1-2)
1081.8
189.2
50.5
2663.3
98.9
53.3
182.3
297.1
344.7
276.7
87.1
390.0
54.3
1182.0
(4)
Projected
consumption
in 1990
987.6
183.9
50.0
11548.8
129.4
52.6
161.5
333.6
299.5
275.7
147.5
589.7
52.6
. 3492.7
<5> 1 a
Additional capacity
required to accommo-
date consumption in
1990 at 85 percent
utilization
(4/0.85-3)°
BO.O
27.2
8.3
10923.5
53.4
8.2
7.6
95.3
7.6
47.6
86.4
303.7
7.2
2927.0
Process
vent/
baseline
combustion
yes/no
no/--
yes/yes
yes/yes
no/--
yes/yes
yes/yes
no/--
no/--
no/--
yes/yes
yes/no
no/--
no/--
(continued)
-------
TABLE 9-18 (continued)
Additional capacity3
Chemical name
Nitrobenzene
Pentenes mixed
Perchloroethylene
Phenol
en 1-Phenyl ethyl hydro-
ro peroxide
Phenylpropane
Phosgene
Propanal
Propyl alcohol
Propylene glycol
Propylene oxide
Styreite
Terephthalic acid
Tetrahydrofuran
(1)
Estimated
capacity
in 1985
759.8
137.6
410.5
1580.8
. 68.7
67.6
1052.4
78.2
99.8
394.6
1433.4
4183.6
3011.9
77.6
(2)
Capacity
to be'
retired
(1985-1990)
172.4
40.0
147.4
178.7
15.4
13.4
158.8
22.6
22.7
97.5
421.9
771.1
657.7
22.7
(3)
Capacity
available
in 1990
(1-2)
587.4
97.6
263.1
1402.1
53.3
54.2
993.6
55.6
77.1
297.1
1011.5
3412.5
2354.2
54.9
required to accomo-
(4) date consumption in Process
Projected 1990 at 85 percent vent/
consumption utilization baseline
in 1990 (4/0.85-3)° combustion
600.5
88.4
244.9
1363.6
52.3
52.3
1049.8
50.0
76.3
412.5
1389.3
4081.5
3061.0
58.8
119.0
6.3
25.1
202.1
8.2
7.2
341.5
3.2
12.7
188.2
623.0
1452.3
1247.0
14.3
yes/no
no/--
no/--
nb/--
yes/no
yes/no
no/--
yes/yes
yes/yes
no/ —
yes/no
yes/yes
no/--
yes/yes
(continued)
-------
TABLE 9-18 (continued)
Chemical name
Toluene-2,4-(and 2,6)-
diisocyanaU (80/20
mixture)
Triethylene glycol
Trimethylene
Tripropylene
Vinyl acetate
Vinyl chloride
Vinyl idene chloride
Vinyl trichloride
m-Xylene
o-Xylene
p-Xylene
(1)
Estimated
capacity
in 1985
384.7
81.7
59.6
256.3
1088.6
4109.6
180.1
150.7
79.4
597.4
2433.6
(2)
Capacity
to be
retired
(1985-1990)
86.2
17.7
10.6
74.0
410.5
916.3
43.1
44.7
22.9
191.7
736.2
(3)
Capac i ty
available
in 1990
(1-2)
298.5
64.0
49.0
182.3
478.1
3193.3
137.0
106.0
56.5
405.7
1697.4
(4)
Projected
consumption
in 1990
343.8
60. 0
52.3
163.8
1208.7
4166.0
146.9
115.7
78.0
652.8
2507.8
(b) a
Additional capacity
required to accommo-
date consumption in
1990 at 85 percent
utilization
(4/0.85-3)°
106.0
6.6
12.5
10.4
743.9
1707.8
35.9
30.0
35.3
362.3
1253.0
Process
vent/
base) i ne
combustion
no/"
no/--
yes/no
no/--
yes/no
no/--
yes/yes
yes/no
no/--
no/--
no/--
Amounts of required capacity do not reflect the fact that some chemicals are always produced as a coproduct
byproduct of some principal product. A list of these chemicals produced by reactor processes is given in
Table 9-19. For those copr6duct chemicals it is likely that the required capacity in 1990 will more closely
approximate the required capacity of the principal product than the required capacity shown above
«Haon °f req"'red "Pac'tV *s 1990 production divided by O.B5. which is the total amount of capacity
needed in 1990. minus the amount of capacity available in 1990.
NOTE: Some of the 1990 production and 1985 capacity values of this table do no't natch the initial or corresponding
values of Table 9-14 These disparities are due to last minute revisions in the data and sources used to
compile Table 9-14. Reanalysis with the revised data shows little net change in economic impacts and
emission reductions under the regulatory alternatives.
-------
A single process unit size is selected for the economic and regulatory
analyses in Section 9.2 because it is straightforward and appropriate to the
level of detail in process unit cost, and because capacity and production
data are available from the data base.
By projecting single-sized process unit(s) to accommodate all required
capacity in 1990, it is possible and even likely that more capacity is
projected to come on line than would strictly be required based on the
capacity utilization rate of 85 percent.
Table 9-19 shows the median-sized facility, required capacity, and final
capacity utilization after the process units are added for the 26 chemicals
that require additional capacity in 1990, are uncombusted at baseline, and
have vent streams. None of the capacity utilization rates falls below a
level historically unobserved, though a few chemicals would have a rate lower
than 70 percent if the median-sized facilities were added. Thus, the current
median plant sizes may overestimate the actual process.units that will be
built in 1990,.since capacity utilization would be higher if smaller process
units were added.
While the projections are as accurate as data permit, changes in the
general state of the economy, technological advances, development of competitive
substitutes, discovery of new product uses, and changes in the stability of
markets may affect actual industry growth. These projections reflect the
most probable scenario and are the best possible given the data available.
Even if subsequent events prove the projections wrong, they remain valid
for their intended purpose: as a guide in exploring the future costs and
other impacts of the potential NSPS. Reasonable variations in the projection
of process units would have no effect on the need for, and selection of, a
standard.
9.2 ECONOMIC IMPACT
This section examines the economic impacts of the reactor processes NSPS
on the SOCMI industry in the first 5 years of implementation. Section 9.2.1
reviews the control costs associated with different regulatory alternatives
(cost/effectiveness cutoffs). For each regulatory alternative, the analysis
presents estimates of the capital costs required for control equipment,
annual operating cost, and the fifth-year (1990) annualized cost of control.
Because these control costs are assumed to be passed on to consumers,
Section 9.2.2 estimates chemical price increases of the subject SOCMI
chemicals under two sets of cost assumptions—reasonable worst-case (RWC)
control costs and more likely case (MLC) control costs. In Section 9.2.3,
the MLC costs are used as a basis for discussing other economic impacts,
including adjustments in the rate of SOCMI chemical production, and
distributive impacts from SOCMI chemical consumers to chemical producers.
9-64
-------
TABLE 9-19.
NUMBER
Chemical name
Adipic acid
Benzyl chloride
Butyl aery late
n-Butyl acetate
t-Butyl alcohol
t-Butyl hydroper-
oxi de
Chlorobenzene
p-Chloronitroben-
zene
Cyanuric chloride
Oi acetone alcohol
Diethyl benzene
2,4-(and 2,6)-
Dinitrotoluene
2,4-Dinitrotoluene
Ethyl acetate
Ethyl aery late
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
PROJECTED REQUIRED CAPACITY,
OF PROCESS UNITS, AND CAPACITY
26 REACTOR PROCESSES CHEMICALS
Total
required
capacity to
achieve
utilization
of 85%, Gg
258.7
17.3
5.4
6.5
40.0
8.2
10.0
3.0
3.0
14.9
7.2
8.2
62.3
47.0
53.1
2345.3
541.3
80.0
Capacity of
a typical
process
unit, Gg
236
36
35C
23
5
11C
68
18d
18d
7C
18d
17C
80C
15
40C
318
204
206
TYPICAL PLANT SIZE,
UTILIZATION FOR
IN 1990
Number of
typical
process
units built
in 1990
2
1
1
1
8
1
1
1
1
3
1
1
1
4
2
8
3
1
Projected
final
utilization
of total
capacity,
1990,
%
67.9
69.0
70.1
70.9
85.0
81.3
63.3
68.4
68.4
70.7
72.4
74.4
81.1
78.2
74.8
82.1
83.1
76.7
(continued)
9-65
-------
TABLE 9-19 (continued)
Chemical name
Methyl methacrylate
Nitrobenzene
1-Phenyl ethyl
Total
required
capacity to
achieve
utilization
of 85%, Gg
303.7
119.0
8.2
Capacity of
a typical
process
unit, Gg
95
153
18d
Number of
typical
process
units built
in 1990
' 4
1
1
Projected
final
utilization
of total
capacity,
1990,
%
76.5
81.1
72.6
hydroperoxide
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl trichloride
7.2
623.0
12.5
743.9
30.0
18°
322
18d
193
45
1
. 2
1
4
1
73.7
*
84.0
78.1
83.4
76.6
aTypical process unit size is most often the median process unit size as shown
in Table 9-10.
bFina1 capacity utilization is calculated as the percentage of total industry
capacity, after the new process units of the typical size are added, that is
used to produce each chemical to meet projected 1990 consumption. If the
total capacity requirements shown in column 1 were made into process units of
their respective size, all numbers in the capacity utilization column would
be 85 percent. Since we add process units of a typical size to cover the
capacity requirements, more capacity is added than is needed sometimes and
capacity utilization falls.
Srfhen specific process unit sizes are not available, the average process unit
size is used for these chemicals.
no median or average data are available for a chemical, a simple default
value of 18 Gg is used. 18 Gg is the overall median value of all process-
specific median values of observed process unit sizes.
9-66
-------
9.2.1 Control Cost Impacts
The regulatory alternatives, introduced in Section 8.2, are based on a
series of successively more stringent cost/effectiveness cutoffs known as
total resource effectiveness (TRE) values. These values measure the dollar
cost per megagram (Mg) of VOC controlled. When a process unit's calculated
TRE value is less than a particular cutoff prescribed by one of the regulatory
alternatives, that unit will have to control 98 percent of all VOC emissions.
?olc v^™s Ca1culated for all facilities that will come on line between
1985 and 1990, as a function of each facility's vent stream characteristics.
Thus, as the TRE cutoffs are raised, more facilities will have a cost/
effectiveness less than the TRE cutoff and will be required to control
emissions.
The control cost of a regulatory alternative is the cost of purchasing,
installing, and operating the required control devices over the life of the
plant equipment. The control costs presented here are based on the regulatory
analysis of Section 8;2. -In that analysis, the chemical- specific projections
T,n»nt10n 9-1 of affected facility capacities coming on line between 1985
and 1990 are matched with the process and vent stream data of the emission
data profile (EDP). Cost algorithms are then applied to each facility
characterization to estimate facility-specific control costs. The
cost/effectiveness (TRE) of each facility is computed by dividing cost by
emission reduction to determine at what regulatory alternative cutoff level
that facility would be required to install the control equipment The
estimated control costs for all affected facilities required to meet the
standard under each regulatory alternative are then summed to obtain the
aggregate control cost for that alternative.
Table 9-20 presents estimates of the nationwide control cost for each
J39d]JSrtJ1i!rKSJe ^T9^1990-. A,]1 COStS are exPress*i in 1982 dollars.
As described in Section 8.1, the control costs are computed with an assumed
10-year equipment life and a 10-percent real rate of discount. Table 9-20
expresses these costs in a variety of ways to provide perspective on their
composition and magnitude. The table gives the total capital costs and
annualized capital costs associated with control for each of the regulatory
alternatives. The operating costs and the fifth-year annualized control cost
are aiso presented.
Cost minimizing firms will have an incentive, of course, to reduce the
cost of complying with the regulation. The TRE cutoff offers several ways of
doing this. First, the firm might design additional product recovery into
the facility to reduce the amount of VOC emitted and raise the TRE to an
amount above the cutoff. Second, it might be able to build multiple facilities
of reduced size, thereby raising the TRE on individual facilities. Third
the firm might modify reactor process design or operating conditions, by
cnanging feedstocks, temperature, pressure or other conditions to increase
control costs, reduce emissions, and therefore raise the TRE. The method or
combination of methods chosen would have a cost less than the control cost
that otherwise would be incurred under the regulation.
9-67
-------
TABLE 9-20. CONTROL COSTS FOR REGULATORY ALTERNATIVES IN 1982 DOLLARS
Cost- Total Annualized Annual Fifth Year
Effectiveness Capital Capital Operating Annualized
Regulatory Cutoff Costs Costs Costs Control Costs
Alternative ($/Mg VOC) (Million $) (Million $) (Million $) (Million $)
Ia
II
III
IV
V '
VI
VII
VIII
IX
0
1,200
2,500
5,000
20,000
50,000
200,000
500,000
>500,000
0
.27
5.9
6.1
7.3
12.1
13.7
. 15.4
17.3
0
.036
.96
.98
1.2
1.9
2.2
2.4
2.7
0
.11
2.7
2.9
3.5
4.8
5.2
5.8
6.6
0
.15
3.7
3.9
4.7
6.7
7.4
8.2
9.3
aBaseline, or conditions that would exist in the absence of the standards.
9-68
-------
Other methods may also be available to reduce control costs.
Specifically, some firms may be able to route the reactor vent stream to an
already existing boiler, flare, process heater, or incinerator. This will
meet the requirements of the standards with little additional investment and
operating expense, and will also have potential for energy savings. The
producer may also have alternatives to building new capacity to produce more
of the regulated large-volume chemical. The producer may build capacity for
small-volume chemicals that are good substitutes, or switch to a large-volume
reactor chemical that has a .lean vent stream, or find means to produce the
chemical using a nonreactor process. If these options exist and are pursued
successfully, the control costs of each regulatory alternative might be
considerably less than those estimated in Table 9-20. While the economic
impacts for the proposed standard are somewhat overstated, the degree of
overstatement cannot be quantified.
If a firm is able to avoid compliance with the regulation by any of the
methods described above, it still must comply with the monitoring and record-
keeping requirements of the regulation. It must continually monitor and
prove that its TRE value is above the cutoff, or that 98 percent control is
being maintained.
9.2.2 Price Impacts
The purpose of the price analysis is to determine if any of the affected
chemicals might experience a major price increase as a result of NSPS. Price
impacts are primary indicators of impacts on profits, quantity supplied,
employment levels, industry growth, and other economic variables. However,
only when these price impacts are of a substantial magnitude should a full-scale
analysis be performed to determine the impacts on these other variables.
The primary tool in the price analysis is a computer model that computes
the percent price increase for each of the chemicals from the TRE cost of
control. A computer model is necessary because the number of chemicals in
the subject group (173) is large and because some of the affected chemicals
are inputs in the production of other affected chemicals. The model incor-
porates the process routes for each of the chemicals and can trace control
costs through the series of chemicals that are input along a process route.
Thus, the model can determine the resulting price impact of the regulation on
a final chemical in a process chain and can be modified to analyze price
impacts under different sets of assumptions. Section 9.2.2.1 summarizes the
assumptions and data used in the analysis, including the prices, plant
capacities, and control costs used, and describes the methodology employed in
the model. Section 9.2.2.2 provides a discussion of the model results under
reasonable worst-case (RWC) assumptions. Section 9.2.2.3 summarizes the
assumptions and results of a more likely case (MLC) analysis.
9.2.2.1 Price Analysis Assumptions.
9.2.2.1.1 General assumptions. A number of criteria might be used to
identify chemicals that would show significant price increases owing to the
9-69
-------
standard. For the purposes of this analysis, if the RWC annualized costs of
control for a chemical result in a price increase greater than 5 percent,
that chemical is thought to have a significant price.impact and is examined
further for economic impacts. The 5-percent level is used because it seems a
reasonable criterion, especially given the tendency to overstate costs when
the worst-case assumptions are used.
The specific input data used in the model are presented in Appendix H,
along with other model documentation. The 1982 prices are from Table 9-1,
and the capacities for the RWC are the small capacities shown in Table 9-10.
The current median process unit size, used to represent the size of process
units to be built in 1990 for each chemical and shown in Table 9-19, is used
for the MLC.1*1 The costs are based on the vent stream characteristics in the
EDP scaled to the particular capacities of each case as discussed in
Appendix H.
For some chemicals, price and/or Capacity data are not readily available.
For these chemicals, some of which are not sold widely and thus have no
market price, a default price of $0.46/kg is used. This figure is an average
price for SOCMI chemicals weighted by 1978 production and updated to 1982
dollars.67 For those chemicals for" which no current plant capacity data are
available, a value of 23 Gg is assumed. This figure is the median of the
smallest existing plant sizes for the chemicals for which plant capacity data
are available. The assumption of small plant size is conservative—i.e., it
leads to projections of price increases that are on the high side.
For the purposes of the price impact analysis, perfect competition in a
constant-cost industry is assumed. This means that the unit costs incurred
by the affected firms are passed through completely to the consumer. This
assumption is consistent with the discussion in Section 9.1, which indicates
that the affected chemicals in this analysis are largely commodity chemicals
produced in competitive markets by firms that are price-takers.
9.2.2.1.2 Model description. The price impact model incorporates the
capacity and price data to estimate the effects of the regulation on the
individual chemicals in the industry. Firms can incur costs not only from
their own direct costs of control but also from the control costs passed
through by suppliers of the input chemicals they use. As described in
Section 9.1, chemicals are produced in a series of processing steps from
basic to intermediate to end-product chemicals. Control costs at each stage
affected by the standard may be passed on (or "rolled through") so that costs
add up for chemicals produced from other affected chemicals.
The analysis takes into account potential rolled-through control costs
by charging control costs for input chemicals to derivatives in proportion to
the amounts used in the production of the derivatives. For example, if 1 kg
of chemical C is produced from 0.5 kg of chemical A and 0.75 kg of chemical B
(with 0.25 kg becoming by-products), one-half of the control costs (per
kilogram) for chemical A and three-fourths of the control costs (per kilogram)
9-70
-------
for chemical B are added to the direct cost impact for chemical C This
rolled- through cost methodology helps to ensure that the price increases
resulting from control costs are conservative in magnitude. Under no
circumstances can rolled-through costs be negative due to possible recovery
credits. A more detailed description of the model is contained in Appendix H.
9'2-2-2 Reasonable Worst-Case Scenario. While employing reasonable
J°9ic: the reasonable worst-case (RWC) scenario posits some extreme conditions
that tend to greatly exaggerate projected price increases. The assumptions
incorporated in the RWC are described below.
The costs used for the analysis are worst-case costs in that they are
estimates of the costs of control scaled to the smallest capacity plant
producing a chemical. If no chemical-specific data on plant capacity are
available, the costs of control are scaled to the smallest plant of the
chemicals produced by the same unit process.
C?st? of contro1 are developed based on vent stream information (flowrates,
nnmJSS70"/^tes' and heat contents) contained in the emission data profile
EDP) described in Appendix C. Flowrates (scfm) and VOC emission rates
llb/h) are normalized for each plant in the EDP by dividing these rates for
each plant by the plant production capacity (106 Ib/yr) associated with these
rates. Heat content is not normalized because the heat content is based on a
unit volume of vent stream. In determining VOC control costs for the RWC
vent stream characteristics were scaled to the smallest plant capacities by
multiplying the normalized emission rates from the EDP by the smallest
capacities shown in Table 9-10. *IWM«U
Because data are not available for all the chemicals included in the
screening analysis, three procedures are used to choose representative
a Chanical5 1ncluded '" ^screening'
""
infnJ5f JtS !ame 1mPl1es» the chemical-specific method uses vent stream
information from actual plants in the EDP producing a particular chemical
th«r±?J J! IK PHP' °TKheXf etnyl!na <"»"«.<"*! are avJnJbS Sil
three plants in the EDP. Therefore, chemical-specific data from the EDP can
be used to estimate the vent stream characteristics of the hexamethylene
diamine p ant included 'in the screening. For many chemicals? Jent stream
characteristics are available only for one plant in the EDP For thesl
™l uf E?P !la?tls data are used '" the screening. If are
available from two plants in the EDP producing a particular chemical averaae
vent stream characteristics for these two are used in the serein ng. In 9
cases where vent stream information is available from three or more plants,
median values are used in the screening. »" <"".*•
with Ih« oSr?!^r°feSS metl?od ^ u"d when the chemical process associated
with the production of a chemical is known, but chemical specific information
9-71
-------
is not available in the EDP. For example, chloroacetic acid is a chemical
for which chemical-specific information is not available. All of the chemical-
specific information for chemicals produced by the same process is used to
obtain representative vent stream characteristics for chemicals using that
process. These representative vent stream characteristics are then applied
to chemicals in the screening where chemical-specific data are absent in the
EDP. As with the chemical specific method, in cases where process specific
data are available from only one plant in the EDP, these data are used in the
screening for all chemicals using that process. Where data from two plants
are available, the average of those vent stream characteristics is used.
Finally, in cases where information from three or more plants is available,
median values are used.
The median method is used in cases where no information is available for
a specific chemical or its process. This method incorporates all data in the
EDP and includes only one set of vent stream characteristics when applied.
The median vent stream characteristics are simply the median of the chemical
process method vent stream characteristics.
The plant capacities included in the RWC analysis are based on information
contained in Table 9-10. In general, the smallest plant capacities that may
be affected by the standards are selected for the RWC analysis. This includes
small plants larger than 1 Gg/yr.in capacity (i.e., larger than the exempted
capacity). As with the vent stream characteristics, data do not exist for
all chemicals being screened, so three procedures are used to determine the
smallest plant capacities from available data in Table 9-10: (1) the chemical
specific method; (2) the chemical process method; and (3) the median method.
The chemical-specific method is the same as before and uses chemical -
specific data from Table 9-10 to determine the smallest plant capacity. This
method is always used for chemicals in the screening analysis that have
available chemical specific data listed in Table 9-10. The chemical process
method is invoked when the chemical process associated with the production of
a chemical is known, but chemical-specific capacity information is not
available from Table 9-10. All the smallest capacities for chemicals produced
by the same process are included to obtain a median smallest plant capacity
for that process. The median method is used in cases where no information is
available for a specific chemical or its process. This method incorporates
all data in Table 9-10. The smallest plant capacity is assumed to be the
median of the"chemical process capacities.
In addition to the control cost assumptions, the RWC scenario incorporates
several other conservative assumptions that tend to exaggerate projected
price increases. First, although many chemicals are coproducts produced
together in a single process or are byproducts of the production of another
chemical, these chemicals do not share the costs of control, and each is
assigned the full impact of control cost. If the coproducts and byproducts
were omitted from the price impact model, the primary product (or subject
chemical) would carry all the cost of control in its price, and the true cost
9-72
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impact of the regulation would result. By assigning full cost pass-through
to those coproducts and byproducts, another worst-case assumption is imple-
mented in the RWC analysis. Table 9-21 shows a list of chemicals produced in
a coproduct/byproduct reactor process.70 As a result of this assumption, the
price impacts for the chemical in the right column of Table 9-21, or the
secondary product in a reactor process, are slightly exaggerated.
In addition, chemicals are assumed to have costs even if no expansion or
replacement capacity is projected. Thus, a number of the 173 chemicals
discussed in Section 9.1.6 that are not projected to grow are nevertheless
costed. It is also assumed that firms producing chemicals thought to be
combusted at baseline will nevertheless incur costs of control. This assumption
implies that any process units producing these chemicals that are built to
accommodate new growth or the retirement of existing process units will be
built in areas in which regulations or other economic and/or safety considera-
tions currently do not require combustion. A recent article confirms that
this assumption fits an extreme worst-case scenario. The article predicts
that the majority of forthcoming construction in the chemical industry will
Jen6 £lace 1n areas where ?IPs re<1uire controls similar to those of the
NSPS.b9 If, in contrast, it had been assumed that all future process units
would be built in areas with such regulations, the cost of control for these
chemicals would be zero, and the rolled-through price impacts for the other
chemicals would be lessened.
Finally, the roll-through logic of the price impacts model described in
Section 9.2.2.1 also tends to reinforce the RWC assumptions. For some of the
chemicals, two or three process routes are available. The model chooses
among the various process routes possible for a given chemical and selects
the route that produces the highest price increase.
The majority of the chemicals had very small price increases under the
RWC assumptions. When the RWC costs were used, 36 percent of the 173 chemicals
screened experienced no price increase due to zero cost assigned to chemical
processes without vent streams. Of the 173, 61 percent experienced increases
of between 0 and 5 percent. Six of the chemicals or 3 percent had price
increases greater than 5 percent using the RWC costs. A complete list of the
price increases for each of the chemicals is provided in Appendix H.
a«,,»I5?«Cheni1!;al;! Witl? P"'Ce increases greater than 5 percent using the RWC
assumptions and the price increases associated with each are presented in
Table 9-22. Also presented is information about the degree to which the
chemical is likeiy to be affected by the regulation, including notes on the
TRE value under RWC conditions and the amount of required capacity projected.
Uf the chemicals with high price increases, two are not projected to require
any expansion or replacement capacity during the first 5 years of regulation,
and three have no vents or are combusted at baseline. The remaining chemical
has a vent stream assumed not combusted at baseline. This chemical, vinyl
;ricll2nd?' hfls a very high TRE value under the RWC conditions. The higher
the TRE value the less likely the chemical producer will be required to
control under an NSPS.
9-73
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TABLE 9-21. CHEMICAL COPRODUCTS AND BYPRODUCTS OF
PRINCIPAL SOCMI PRODUCT CHEMICALS70
Principal product
Coproduct/byproduct
Methyl chloride
Carbon tetrachloride
Ethylene glycol
Propylene
Oodecene
Benzene
Benzene
Benzene
Benzene
Perchioroethylene
Ethylene glycol
Chloroform
Chloroform
Diethylene glycol
Ethylene
Tripropylene
Toluene
Xylene (mixed)
o-Xylene
p-Xylene
Trichioroethylene
Triethylene glycol
9-74
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10
TABLE 9-22. CHEMICALS WITH PRICE INCREASES GREATER
THAN 5 PERCENT: REASONABLE WORST CASE SCREENING
Name
Percentage
price increase
Why the price increase
will not materialize
51 Methyl chloride
68 1,4-Dichlorobutene
73 Vinylidene chloride
203 Methyl chloroform
204 Vinyl trichloride
240 Chloroacetic acid
7.98
5.14
19.21
11.11
10.54
15.50
Combusted at baseline
No required capacity
projected
Combusted at baseline
No reactor-related vents
at baseline
Large TRE
No required capacity
projected
9-75
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It is possible to recalculate the annual costs and subsequent price
increases for vinyl trichloride assuming the plants producing it are required
to control under certain regulatory alternatives. Using a TRE cutoff of
$2,500, Regulatory Alternative III, the highest possible costs that would be
incurred if a chemical were to require controls are calculated. This would
occur when the continually monitored TRE value falls below the level of
$2,500 per megagram of VOC controlled. Since the TRE value is defined as
control cost per year divided by annual VOC emission rate, the maximum yearly
control cost would be equal to $2,500 times the annual VOC emission rate if
Regulatory Alternative III were imposed. For vinyl trichloride, the annual
costs of control are recalculated using the $2,500 TRE limit and the amount
of VOC controlled from the EDP. This annual cost represents the highest
possible cost to a producer if he is required to install control equipment
based on a TRE level below $2,500. The price increase that results from the
change in annual cost for vinyl trichloride drops substantially. Not only
does this chemical fall below the 5 percent level, but also two chemicals it
inputs into, vinylidene chloride, and methyl chloroform, fall below the 5
percent level. Therefore, although the prices of several chemicals appear to
be significantly impacted under the RWC assumptions, it is unlikely that
these effects would materialize.
Table 9-23 shows both the old and new price increases of these three
chemicals, along with the other three chemicals. As mentioned earlier,
however, these other three chemicals are either uncombusted at base.line or
have no new or replacement capacity required. Under this analysis, then, no
chemical new facilities built in the 1985 to 1990 period are expected to have
a price increase greater than 5 percent..
9.2.2.3 More Likely Case Scenario. In addition to the RWC screening, a
more likely case (MLC) scenario has also been developed. It provides a more
likely projection of the impacts that will result from the regulation, in
contrast to the exaggerated RWC impacts used for analysis of price increases
due to an NSPS.
Under the MLC assumptions, only those chemicals that have vents, are
uncombusted at baseline, and have projected need for additional capacity over
the first 5 years of implementation are assigned'control costs. Furthermore,
chemicals with projected need for new capacity but without vents and chemicals
with projected need for new capacity but with baseline combustion have zero
control costs. The control costs developed for the MLC, like the RWC, are
based on the vent streams in the EDP. The vent streams and control costs are
scaled to each chemicals median process unit size, however, rather than to
the smallest existing plant size. No TRE cutoff is applied, so that many
chemicals that will not be required to be controlled are still given price
increases.
A total of 43 chemicals experience some price increase under the MLC
assumptions. Twenty-six of these are chemicals with assigned control costs;
the remainder have those 26 chemicals as inputs. The results of the MLC
9-76
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TABLE 9-23. PRICE INCREASES BEFORE AND AFTER
RECALCULATION OF ANNUAL CONTROL COST
FOR VINYL TRICHLORIDE3
ID
51
68
73
203
204
240
Chemical name
Methyl chloride
1,4-Dichlorobutene
Vinylidene chloride
Methyl chloroform
Vinyl trichloride
Chloroacetic acid
Price
Before5
7.98
5.14
19.21
11.11
10.54
15.50
increase, %
After
7.98
5.14
2.56
1.48
0.72
15.50
Control costs for vinyl trichloride and only for vinyl
trichloride are assumed to be $2500/mg of VOC controlled.
These entries are from Table 9-22.
9=77
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analysis indicate that none of the chemicals has a price increase greater
than 5 percent. Most of the price increases are very small: 93 percent are
under 1 percent. These results are used to estimate quantity and distributional
impacts in subsequent sections of this chapter.
9.2.3 Other Economic Impacts
9.2.3.1 Quantity Impacts. The price increases estimated in the preceding
section may have further economic impacts. Price increases induce consumers
to reduce consumption, all other things being equal. This response is
important because actual quantities traded at the new price level will
decrease, and the production capacity actually installing controls will be
reduced relative to projections given in Table 9-16. This reduction in the
quantity of a chemical produced relative to the projection of production is
termed the quantity impact of the regulation.
The magnitude of the quantity impact depends upon the price elasticity
of demand, or the percentage change in quantity demanded in response to the
percentage change in price. In mathematical terms, the price elasticity is
defined in Equation (9-1):
n = -(AQ/AP) x (P/Q), (9-1)
where
n = price elasticity
AQ - change in quantity produced due to price increase
AP = change in price due to the NSPS (1982 $)
Q = projected 1990 quantity produced
P = price before the NSPS (1982 $).
The negative sign is a convention used to make the elasticity positive since
quantity and price are normally inversely related.
Given n, P, Q, and AP, the quantity impact, AQ, due to a price increase
can be estimated:
AQ = -n x Q x AP/P , (9-2)
where
AP/P = the proportionate change in price calculated in Section 9.2.2
Q = the value given in Table 9-18, column 1
n = 0.7, the lower bound on the range of price elasticity for the
chemical industry as a whole given in Section 9.1.
Table 9-24 shows the change in quantity produced due to the NSPS for the
chemicals that have projected need for new capacity. Included in this table
9-78
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TABLE 9-24. QUANTITY IMPACTS IN 1990 DUE TO
CONTROL COSTS REQUIRED BY THE REGULATION
Rolled- through
change In
1990 price from
production, regulation, Price,
Chemical name Gg
-------
are the original production projections for 1990, before any quantity impacts
were accounted for, and the change in price using more-likely-case assumptions.
The quantity impacts shown in Table 9-24 not only influence the employment
level and capital expenditures discussed later in Section 9.2.3.3, but also
influence the projections of future need for capacity and thus the potential •
emissions reduction of the standard. If quantity produced is diminished in
1990 from its value projected in Section 9.1.6, then it is possible that
fewer process units will be constructed, and that emissions reduction brought
about by the standard will fall. On the other hand, the quantity impact may
effect decreases in production from existing units only, or may simply lower
industry capacity utilization, and emissions reductions will stay the same.
Since the magnitude of the impacts are less than 1 Gg for most chemicals, it
is likely that all projected process units will be built, and the industry
will absorb the reduction in quantity produced.
As noted in Section 9.1, a single measure of price elasticity applied to
all chemicals does not take into account each chemical's particular response
to changes in the market price. The quantity impacts may vary from those
projected here if a different measure of price elasticity applies. For
example, the actual price impacts may induce producers to use substitutes,
either in the production process of the chemical or for the chemical itself.
If this is the case, the opportunity to use a close substitute would tend to
raise a chemical's price elasticity to a higher negative value closer to -1,
yielding a correspondingly larger quantity impact for each. The" avail ability
of good substitutes and whether the substitutes themselves will be regulated
are major factors in determining the price elasticity appropriate to a given
chemical. In this .analysis, however, the computation of chemical-specific
elasticities is ruled out because of the lack of publicly available elasticity
estimates for these chemicals and the analytical resources that would have
been required to estimate them independently.
9.2.3.2 Distributional Impacts. The proposed NSPS would require
controls only on selected expansion or replacement capacity additions.
Existing facilities will, however, be affected by the price impacts. In
particular, established facilities would derive extra revenue as chemical
prices increase while production costs remain level. The total of the output
from the unaffected firms times the change in price represents a transfer of
income (additional consumer expenditures; from chemical consumers to producers.
This transfer is a distributional impact of the standard. In this analysis,
it is assumed that no delay in plant retirement will occur because of the
standard.
The distributional impact is calculated as the change in price from the
regulation times the output (in 1990) provided by process units that are
built prior to 1985 and are therefore not affected by regulation. This
output is calculated from 1990 production projections by subtracting
85 percent of the projected additions to capacity in 1985-1990.
9-80
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For the distributional impacts, the change in price is calculated
differently from the roll-through price change used in the quantity impact
analysis. If a rolled-through price increase were used, the additional
consumer expenditures transferred to existing facilities would be double
counted for all intermediate chemical price effects. While it is true that
the selling price must increment through the roll-through process, the
aggregation of intra-industry expenditures must not be added to the end-product
consumer expenditure or they would be counted more than once in the final
amount. Therefore, the change in price is calculated directly from the
dollar cost of regulation for the median-sized capacity plant projected for
each chemical. The dollar cost per plant size is converted to
-------
TABLE 9-25. DISTRIBUTIONAL IMPACTS IN 1990 DUE TO CONTROL
COSTS REQUIRED BY THE REGULATION
Chemical name
Adipic acid
Benzyl chloride
Butyl acrylate
n-Butyl acetate
t-Butyl alcohol
tert-Butyl hydroperoxide
Chlorobenzene
p-Chloronitrobenzene
Cyanuric chloride
Diacetone alcohol
Di ethyl benzene
2,4-(and 2.6)-Dinitrotoluene
2 ,4-Qi ni trotol uene
Ethyl acetate
Ethyl acrylate
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
Methyl methacrylate
Nitrobenzene
1-Phenyl ethyl hydroperoxide
Phenyl propane
Propylene oxide
Tri methyl ene
Vinyl acetate
Vinyl trichloride
Total
Existing
producers
production
in 1990
317.8
38.4
88.3
51.5
404.5
42.7
85.2
36.7
36.7
8.2
36.7
37.5
256.0
76.0
133.0
. 2,680.6
2,140.8
811.9
267.0
469.9
36.7
36.7
841. 6 "
36.7
552.8
77.8
Direct
change
in price
1,679.47
10,747.33
1,244.23
1,610.26
7,766.40
6,167.27
6,051.35
21,212.22
21,050.00
5,111.43
2,021.78
6,177.59
3,374.82
2,750.40
2,493.55
177.14
5,757.80
824. 19
625.20
256.58
11,932.44
2,021.78
536.94
3,403.89
185.37
8,686.33
Distributional
impacts
533,737.0
412,697.6
109,803.2
82,847.9
3,471,580.8
263,034.2
515,575.3
778,488.6
772,535.0
41,658.1
74,199.2
231,968.4
863,955.2
209,030.4
246,861.4
474,854.0
12,326,306.6
669,159.3
166,928.4
120,577.5
437,920.7
74,199.2
451,892.2
124,922.7
102,471.4
675,362.4
24,232,566
9-82
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be felt in the construction industry if capacity expansions are not pursued
when demand decreases in response to price increases. Given the size of the
industry and the small level of output reduction relative to projected
increases, these employment effects are relatively small.
Capital requirements for reactor process NSPS also would be small The
debt ratio for the chemicals industry is estimated using long-term debt of
$37.2 million and stockholder's equity of $93.2 million, as shown in Table
9-13, and equals 28.5-percent. This value represents the debt ratio that is
incurred normally without expenditure for NSPS controls. An estimate of
capital cost of NSPS controls for a median-size plant is obtained from the
total capital cost of the recommended Regulatory Alternative III in Table 9-20
divided by the projected number of facilities required to control under that
alternative. A capital investment in control equipment of $0.84 million per
!CirS( re^lts from th1s emulation. This increase in capital investment
of $0.84 million to install VOC emission controls under median control
conditions would increase the overall industry debt ratio to 29 percent if
financed entirely from debt sources. This half a percentage point change in
debt ratio is modest and could be limited even further if part of the control
investments were not funded by debt.
9.3 REGULATORY, INFLATIONARY, SOCIOECONOMIC, AND SMALL BUSINESS IMPACTS
9.3.1 Executive Order 12291
Executive Order 12291 requires the conduct of a regulatory impact
analysis (RIA) of a proposed regulation if the regulation is likely to result
in
• An annual effect on the economy of $100 million or more;
• A major cost or price increase for consumers; individual industries;
Federal, State, or local government agencies; or geographic regions;
or
• Significant adverse effects on competition, employment, investment,
productivity, innovation, or ability of U.S.- based enterprises to
compete with foreign-based enterprises in domestic or foreign
markets.
An RIA is somewhat more comprehensive than the analysis described in
this document. Among other things, RIAs contain a full examination of the
air quality benefits—not just emission reductions—associated with NSPS
The c°st impacts calculated in Chapter 8 and discussed in Chapter 9 for the
;StS<»«, * ?2 w w re?u]atory alternatives indicate that the annual
S T.hff o%S°UJJ be*i!bstant1ally ess than $100 million per year. As shown
in Table 9-20, the fifth-year annualized cost requirements of the most
stringent regulatory alternative amount to only $9.3 million. For Regulatory
Alternative III, these costs are only $3.7 million.
9-83
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The price impacts presented in Section 9.2.2 indicate that under the
RWC, inflationary impacts may exceed 5 percent for three chemicals. However,
none of the chemicals with high price increases has both process units
projected and a low TRE value. Under the more likely case assumptions, no
chemicals experience a price increase greater than 5 percent.
Based on these results, the proposed standards do not qualify as major
regulatory action under the criteria enumerated above: the annual effect on
the eco.nomy is substantially less than $100 million, the price impacts are
small, and the standard will not have a significant effect on the operation
of the domestic economy or its international trade. Therefore, a regulatory
impact analysis and associated benefit/cost calculations are not given here.
While this is the case, it is still worthwhile to note, in a qualitative
fashion, the benefits against which the costs discussed above should be
balanced.
The standards will reduce the rate of emission of VOCs to the atmosphere.
These compounds are precursors of photochemical oxidants, particularly ozone.
The EPA publication Air Quality Criteria for Ozone and Other Photochemical
Oxidants71 explains the effects of exposure to elevated ambient concentra-
tions of oxidants. (The problem of ozone depletion of the upper atmosphere
and its relation to this standard are not addressed here.) These effects
include
• Human health effects. Ozone exposure has been shown to cause
increased rates of respiratory symptoms such as coughing, wheezing,
sneezing, and shortness of breath; increased rates of headache, eye
irritation, and throat irritation; and increases in the number of
red blood cells. One experiment links ozone exposure to damage to
human chromosomes.
• Vegetation effects; Reduced crop yields as a result of damage to
leaves and/or plants have been shown for several crops including
citrus, grapes, and cotton. The reduction in crop yields was shown
to be linked to the duration of ozone exposure.
• Materials effects. Ozone exposure has been shown to accelerate the
deterioration of organic materials such as plastics and rubber
(elastomers), textile dyes, fibers, and certain paints and coatings.
• Ecosystem effects. Continued ozone exposure has been shown to be
linked to the disappearance of trees such as Ponderosa and Jeffrey
Pines and the death of predominant vegetation. Hence continued
ozone exposure places a stress on the ecosystem.
In addition to reducing the severity of the physical and biological
effects enumerated above, the regulatory action is likely to improve the
aesthetic and economic value of the environment through, for example, beauti-
fication of natural and undeveloped land because of increased vegetation,
improved visibility, and reduced incidence of noxious odors.
9-84
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9.3.2 Small Business Impacts
The Regulatory Flexibility Act (Public Law 96-354, September 18, 1980)
requires that agencies give special consideration to the impacts on small
firms, organizations, and governments of all proposed regulations. Specific-
ally if a proposed regulation is likely to adversely effect small entities
then the agency must perform a Regulatory Flexibility Analysis. According to
EPA guidelines, an "adverse effect" on small entities is defined both in
terms of the percentage of small firms affected by the regulation and the
significance of the economic impact. A proposed regulation is considered to
have an adverse effect on small firms when the percentage of small firms
affected is substantial i.e., at least 20 percent), and the economic impact
on these firms is significant (i.e., price increases of at least 5 percent).72
To satisfy the specific requirements of the.Regulatory Flexibility Act,
this analysis shows that the number of small firms affected by the regulation
does not constitute a substantial percentage of small firms in the industry!
and therefore there is no adverse effect and no need for a Regulatory
Flexibility Analysis. Further, additional analyses of the number of small
and large firms in the industry affected by the standards show that the
larger firms will bear the majority of the burden of control cost, and that
the potential burden of cost on small firms is not disproportionate to their
contributions to emissions.
u *u9>3'2>1u tegu^^ry Flexibility Act Consideration's. In order to identify
whether a substantial number of small firms are affected, the set of small
firms in the industry is first defined. Then the number of small firms'
producing the chemicals with uncombusted vents and projected growth for the
5-year period of analysis are identified.
tho J!!?iSJandardS £!I.C]assify1n9,a bus1ness « small are those set forth by
the Small Business Administration (13 CFR Part 121), which determine that a
small business in the organic chemicals industry can have no more than 750
r-SC 285 and ltQ°° ^P10*665 f°r SIC 2869.^3 other characteris-
'
S?1°SS r-SiC 2855 and ltQ°° ^P10*665 f°r SIC 2869.^3 other characteris
tvoifv a smfir^K; T ovTrSh!P a!!d "orjdomi'na"« in its field of operation
typify a small firm. According to the Bureau of Census there are 347 small
' *hhe
t«o . 1nd"stry categories SIC 2865 and SIC 2869 based on
these classification standards.71* These SIC industries are assumed to
represent the organic chemical industry. «"umea to
rh^,vMc- t0 current sources, there are 55 firms that produce the 26
UteSl? thTt *mn™mb!!St.d rntS ?"d Pro^cted growth shown in Table 9-19.
(Recall that all 26 chemicals would be affected only under the most stringent
^Ino°ty altfrjatlve1- and that many fewer will be impacted under less 9
thpS? JIT9" 1atory alternatives). Employment data are available for 46 of
*™ ?L -7 5Urre??1£ Producin9 the 26 chemicals. Only 7 of the 46 firms
fnrp !h 6red $5" b"sinesses °ased on available employment data.*' There-
fhl ifndSsetfv°?r71?; ?I7Sma11 f!n"5 P°te"t7'ally impacted to small firms in
the industry is 7 to 347, or only 2.0 percent. Even if it is assumed that
9-85
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all 9 firms for which there are no employment data available are also small,
the percentage of potentially impacted small firms in the industry is only
4.6 percent. Both of these percentages are well below 20 percent.
Though the analysis in Section 9.2.2 shows that this regulation may have
significant impacts on a few small firms under worst case assumptions, the
number of these firms is far from substantial, and a Regulatory Flexibility
Analysis is not required.
9.3.2.2 Burden of Cost Analysis. There is another way to look at the
question of whether this NSPS will place an undue burden on small firms.
This is to compare the portion of small (or large) firms potentially impacted
by the NSPS with the proportion of small (or large) firms in the industry.
This comparison indicates that the NSPS may favor small firms vis-a-vis large
firms.
A total of 517 firms are included in SIC 2865 and SIC 2869. Thus, about
67 percent (347 divided by 517) of firms in the organic chemical industry are
considered small. Even if the 9 firms for which no data are available are
assumed to be small, only 16 out of 55, or 29 percent of the firms potentially
impacted by the regulation are small. If it is assumed that the distribution
of facility ownership by firm size will be the same for new facilities as for
existing facilities, only 29 percent of the firms potentially impacted under
the NSPS in the first 5 years will be small even though 67 percent of the
firms in the overall industry are small. On the other side of the coin,
there is a greater percentage of potentially impacted firms that are large
(71 percent) than the percentage of large firms in the industry (33 percent).
Though the large firms bear a burden of the total industry cost
disproportionate to their overall number, the cost they bear will be propor-
tional to their level of emissions, assuming that emissions levels are
proportional to production. Based on this evidence it is most likely that
the burden of the standard will fall predominately on those firms responsible
for most of the total emissions.
9.4 IMPACTS OF THE ACCUMULATION OF COSTS FROM THE REACTOR PROCESS NSPS AND
OTHER AIR QUALITY STANDARDS
This section describes the potential organic chemical product price
increases due to production cost increases resulting from the fifth-year cost
of seven air pollution control regulations developed since August 1977: the
benzene fugitive emissions NESHAP, VOC fugitive emissions NSPS, the VOC
fugitive emissions from petroleum refining, the volatile organic liquid
storage tanks NSPS, the distillation NSPS, the air oxidation NSPS, and the
reactor processes NSPS. This section also examines potential changes in
production of organic chemicals due to price increases from control costs.
Section 8.6 gives a full account of the methodology used to estimate these
cumulative costs, and Table 8-11 provides the total direct costs of the seven
potential emissions regulations for 26 reactor process chemicals that have
projected required capacity for the 5-year period beginning in 1985.
9-86
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9.4.1 Price Impacts of Cumulative Costs
The price increase analysis is conducted on a chemical-specific basis
assuming that total cumulative costs are passed through completely to consumers
of the chemicals. Total fifth-year annualized costs are based on the projec-
tions of the number and size of facilities for 26 reactor process chemicals
listed in Table 9-19. This analysis calculates the direct price increases
associated with control costs as the fifth- year 1990 cumulated cost for each
chemical divided by the total projected production increase of that chemical
in 1985-1990, as shown in Table 9-19. The. direct percentage price increase,
given in cents per kilogram after multiplying by the proper conversion
scalar, is shown in the third column of Table 9-26.
Also shown in Table 9-26 is the rolled-through price increase from the
accumulation of costs from the five potential standards. A rolled- through
price increase results from the aggregation of individual price increases of
input chemicals along a production chain. The computer model used in the
price analysis of Section 9.2.2 incorporates the process routes for each of
the 26 chemicals and traces cumulated control costs through the series of
chemicals that are input along a given process route. The results from this
rolled-through calculation are shown in the fourth column of Table 9-26.
The results of the price increase analysis show that none of the 26
chemicals is expected to have a price increase greater than 5 percent.
9.4.2 Quantity Impacts of Cumulative Costs
The rolled-through price increases estimated in the preceding section
may have economic impacts. Price increases induce consumers to reduce
consumption, all other things being equal. This response is important
because actual quantities traded at the new price level will decrease,
causing production decisions to be altered. This reduction in*the quantity
of the chemical produced is termed the quantity impact of a price increase
due to regulation.
The magnitude of the quantity impact depends on the price elasticity of
demand, or the percentage change in quantity demanded in response to the
percentage change in price. Equation 9-1 gives the price elasticity of
demand and provides the means with which to calculate the quantity impact
from the cumulated rolled-through price increases in Table 9-26. The quantity
impact is calculated as described in Section 9.2.3.1 using the figure of -0.7
for the price elasticity, the projection of production in 1990 for quantity,
the price in cents per kilogram before the regulation in 1982 dollars for the
price, and the rolled-through cumulated cost increase for the change in
price. Table 9-27 shows the results in reduction of quantity supplied and
the percentage change in quantity produced in 1990 due to the fifth-year
cumulated costs of control from the seven emission standards.
9-87
-------
TABLE 9-26. PRICE IMPACTS OF CUMULATED COSTS FROM SEVEN AIR QUALITY
STANDARDS FOR 26 REACTOR PROCESS CHEMICALS
Chemical
Adi pic acid
Benzyl chloride
Butyl aery late
n-Butyl acetate
t-Butyl alcohol
t-Butyl hydroperoxlde
Chlorobenzene
p-Chloronltrobenzene
Cyanuric chloride
Di acetone alcohol
01 ethyl benzene
2,4-(and 2,6)-Dinitrotoluene
2 , 4-Di ni trotol uene
Ethyl acetate
Ethyl acrylate
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
Methyl methacrylate
Price3
-------
TABLE 9-26 (continued)
Chemical
Nitrobenzene
1-Phenyl ethyl hydroperoxide
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl trichloride
Price3
-------
TABLE 9-27. QUANTITY IMPACTS OF CUMULATED COSTS FROM SEVEN AIR
QUALITY STANDARDS FOR 26 REACTOR PROCESS CHEMICALS
Chemical
Adipic acid
Benzyl chloride
Butyl aery late
n-Butyl acetate
t-Butyl alcohol
t-Butyl hydroperoxide
Chlorobenzene
p-Chloronitrobenzene
Cyanurjc chloride
Di acetone alcohol
Di ethyl benzene
2,4-(and 2,6)-Dinitrotoluene
2,4-Dinitrotoluene
Ethyl acetate
Ethyl aery late
Ethyl benzene
Ethyl ene oxide
Isopropyl alcohol
Methyl methacrylate
Nitrobenzene
1-Phenyl ethyl hydroperoxide
Quanti ty
impact,
Qg
0.84
0.73
0.25
0.31
6.61
1.22
1.02
0.72
0.31
0.35
0.15
0.24
0.56
0.99
. 0.48
2.86
16.76
1.33
0.57
0.90
0.70
1990
production,
Gg
719
69
118
71
481
52
143
52
52
26
52
52
324
127
167
4,843
2,661
987
590
600
52
Percent
change in
1990
production
0.12
1.07
0.21
0.44
1.37
2.34
0.72
1.39
0.61
1.36
0.30
0.46
0.17
0.78
0.28
0.06
- 0.63
0.13
0.10
0.13
1.34
See footnote at end of table.
(continued)
9-90
-------
TABLE 9-27. (continued)
Chemical
Phenyl propane
Propylene oxide
Trimethylene
Vinyl acetate
Vinyl trichloride
Quantity
impact,
Gg
0.34
0.88
0.30
0.95
1.22
1990
production,
Gg
52
1,389
52
1,209
116
Percent
change in
1990
production
0.65
0.06
0.30
0.08
1.05
Projected production in 1990 from Table 9-18.
9-91
-------
Column three of Table 9-27 shows that none of the changes in production
decisions due to the cumulated price increases detailed in Section 9.4.1
constitutes more than 1.37 percent of the total projected production of any
chemical and is less than 1 percent for most chemicals. The absolute change
in production (the quantity impact) is less than 2 Gg for all but two of the
chemicals. These chemicals, ethylene oxide, and butyl alcohol have a relatively
large amount of projected output in 1990.
9-92
-------
9.5 REFERENCES
1. The Kline Guide to the Chemical Industry. C. H. Kline and Company.
Fairfield, NJ. 1980. pp. 1-4.
2. Reference 1, p. 97.
3. U.S. International Trade Commission. Synthetic Organic Chemicals.
United States Production and Sales. 1981. Publication No. 1292.
Washington, DC. 1982. p. 3.
4. Mannsville Chemical Products. Chemical Products Synopsis. Cortland,
NY. 1983.
5. Chemical Profile and Current Prices of Chemicals and Related Materials.
Chemical Marketing Reporter. Various issues. 1982.
6. Memo from Cassidy, M. A., Radian Corporation, to Reactor Processes file.
May 6, 1985. PTS U.S. Forecasts Data, File 81, and PTS U.S. Time
Series, File 82.
7. SRI International. 1983 Directory of Chemical Producers: United States
of America. Menlo Park, CA. 1983.
8. U.S. International Trade-Commission. Synthetic Organic Chemicals.
United States Production and Sales. Various issues 1977 to 1982.
Washington, DC.
9. Reference 3. pp. 13-283.
10. Memo from Mead, R. C., Radian Corporation, to file. September 29, 1983.
1 p. Computer printouts of data from the 1977 production survey for the
Toxic Substances Control Act.
11. U.S. Environmental Protection Agency, Office of Air Quality Planning and
Standards. Distillation Operations in Synthetic Organic Chemical
Manufacturing, Background Information Document. Draft EIS. Publication
No. EPA-450/3-83-005a. Research Triangle Park, NC. December 1983.
p. 1-1 to 1-30.
12. Economic Indicators. Chemical Engineering. 90:7. February 1983.
86:7. February 1979. ~~
13. Petrochemical Industry Continues with Various Coping Strategies.
Hydrocarbon Processing. 62(1):19. January 1983.
14. Reference 11, p. 9-20 to 9-45.
15. Reference 1, p. 98.
9-93
-------
16. U.S. Department of Commerce, Bureau of Economic Analysis. The Detailed
Input-Output Structure of the U.S. Economy: 1972. Magnetic computer
tapes. Washington, DC. 1979.
17. Memo from Reinhardt, Brooke, Research Triangle Institute, to Reactor
Processes File. May 14, 1985. Presentation of the time series of
prices for 5 oil-based and 5 gas-based chemicals.
18. U.S. Department of Energy. Energy Information Administration. Petroleum
and Natural Gas Price Summary. Monthly Energy Review, November 1984.
Washington, D.C. pp. 89-98.
19. U.S. Department of Commerce. Bureau of Industrial Economics. 1984 U.S.
Industrial Outlook. Washington, D.C., p. 17-3.
20. Reference 1, p. 52.
21. Facts and Figures for the U.S. Chemicals Industry. Chemical and
Engineering News. June 13, 1983. p. 42.
22. U.S. Department of Commerce, U.S. Bureau of the Census. Annual Survey
of Manufacturers, Statistics for Industry Groups and Industries.
Washington, DC. 1978-1981. Table 2.
23. U.S. Department-of Commerce, U.S. Bureau of the Census. 1977 Census of
Manufacturers, Volume II, Industry Statistics, Part 2. SIC Major Groups
27-34. Washington, DC. August 1981.
24. Reference 21, p. 52.
25. Reference 21, p. 49.
26. Chemical Earnings Fell Again in Fourth Quarter. Chemical and Engineering
News. February 14, 1983. p. 15.
•27. U.S. International Trade Commission. Synthetic Organic Chemicals,
United States Production and Sales. Summary Table 1. Washington, DC.
1979, 1980, 1982, 1983.
28. Reference 1, p. 21.
29. U.S. Internationa1 Trade Commission. The Probable Impact on the U.S.
Petrochemical Industry of the Expanding Petrochemical Industries of the
Conventional Energy-Rich Nations. Washington, DC. April 1983. p. 178.
30. Reference 21, p. 55.
9-94 '
-------
31. U.S. Department of Commerce, U.S. Bureau of the Census Statistical
Abstract of the U.S. 1985. Washington, D.C. 1985 p. 470
' News'! 3^ eCl1ne' ^"^ and
33. Reference 29, pp. 1-5, 47.
34. Reference 29, p. 11.
35. Reference 29, p. 11-12.
36- 1 1 Gas- chemicai and
37 ' ?§Jnd Chanl$a1 Outlook. Chemical and Engineering News. December 22,
iyou. p. oo. . '
" 13, 1979.
39' I?hU°ni CfSUC?1111f,E- U- ?• Inter"atio.nal Trade Connission, with
- Viola, J.. EEA, Inc. January 20, 1983. Tariffs for organic chemicals
40. Reference 21, p. 36.
41. Memo from Reinhardt, Brooke, Research Triangle Institute, to Reactor
Processes File. February 22, 1985. Small Business Impacts?
42. Reference 1, p. 15.
43. Reference 1, p. 9.
44. Reference 1, p. 14.
46. Reference 21, p. 38.
47 ' " adrdtr Bus1"e« «•««• *» - Bradstreet Corp.
industry-
a"d E"9fneenng News.
9-95
-------
50. Reference 21, p. 35.
51. Greenwald, Douglas, ed. The McGraw-Hill Dictionary of Modern Economics.
New York, McGraw-Hill. 1983. p. 20.
52. Reference 47, p. 2.
53. Reference 47, p. 3.
54. Reference 21, p. 39.
55. Reference 49, p. 8.
56. Reference 21, p. 37.
57. Lower Break-Even Points Signal Higher Profits in 1983. Chemical and
Engineering News. March 28, 1983. p. 22. •
58. Memo from John Robson to Reactor Processes File. February 21, 1985.
Capacity Utilization Rates used in the Synthetic Organic Chemical
Reactor Processes NSPS.
59. New Chemical Business Recovery May Be Very Different. Chemical and
Engineering News. January 10, 1983. pp. 14-17.
60. CE New Plants and'Facilities. Chemical Engineering. 72:111-120.
April 1965. ~~
61. CE New Plants and Facilities. Chemical Engineering. 73:151-162.
April 1966. ~
62. CE New Plants and Facilities. Chemical Engineering. 75:187-196.
April 1967. ~
63. CE New Plants and Facilities. Chemical Engineering. 75:147-158.
April 1968. —
64. CE New Plants and Facilities. Chemical Engineering. 76:141-150.
April 1969. —
65. CE New Plants and Facilities. Chemical Engineering. 77:123-134.
April 1970. —
66. Memorandum from Rimpo, E. T., and Pandullo, R. F., Radian Corporation,
to File, June 4, 1985. Emissions from new, modified and reconstructed
reactor process units which use combustion controls at baseline.
67. U. S. Environmental Protection Agency. VOC Emissions from Volatile
Organic Liquid Storage Tanks. Background Information for Proposed
Standards. Draft EIS. EPA-450/3-81-003a. February 25, 1983. p. 9-36.
9-96
-------
68. Memorandum from Cassidy M. A., and Baviello, M. A., Radian Corporation,
to File, May 10, 1985. Emissions characteristics of the new, modified,
betweln°1985-1990 """"^ prOCeSS6S units P^cted to come online
" Slippl'ng' Chem1cal and
70. Memorandum from Lesh Steve A., Radian Corporation, to Robson, John,
Co r d J ' Reactor Processes Chemicals with Byproducts/
71" U^SAJnVloun1!enJal.Pr?t®ct1on A9ency- Air Quality Criteria for Ozone
and Other Photochemical Oxidants. EPA-600/8- 78-004. April 1978.
-
pp. 1-16.
72. Memorandum from Jenkins, R., EPA: EAB, to Bingham, T.9 RTI. June 9,
1982, EAB Interim Guidelines for Regulatory Flexibility Analysis.
73. U S. Small Business Administration. Small Business Size Standards,
Revision; Final Rule. February 9, 1984. 49 FR 5024-48.
74. Letter from Reinhardt, Brooke, Research Triangle Institute, to
1984 »ip??prernnS->e-t0r; J^*" °f CenSUS' Washin9ton, D.C. June 7,
figures " confirming telephone conversation regarding SIC employment
9-97
-------
APPENDIX A
EVOLUTION OF THE PROPOSED STANDARDS
-------
-------
APPENDIX A
EVOLUTION OF THE PROPOSED STANDARDS
The purpose of this study was to develop new source performance standards
for reactor processes In the synthetic organic chemicals' manufacturing
industry (SOCHI). Work on this study was begun on October 25, 1982, by
Radian Corporation under the direction of the Office of Air Quality Planning
and Standards (OAQPS), Emission Standards-and Engineering Division (ESED)
The decision to develop these standards was made on the recommendation of the
Environmental Protection Agency (EPA) 1n conformity with its policy to
develop generic standards for the SOCMI.
The chronology, which follows, lists important events that have occurred
in the development of background Information for new source performance
standards for reactor processes 1n the SOCMI.
A-l
-------
Date
October 25, 1982
December 8, 1982
January 28, 1983
February 28, 1983
Feburary 16, 1983
March 21, 1983
May 6, 1983
May 6, 1983
June 8, 1983
July 19, 1983
July 20, 1983
September 28, 1983
September 29, 1983
Activity
EPA project kickoff meeting.
Phase I workplan completed.
Source Category Survey Report (SCSR)
completed.
Completed final concurrence memorandum
recommending continuation of the reactor
processes NSPS development.
Held meeting with EPA to discuss direction
of project continuation.
Phases II and III workplan completed.
Developed updated comprehensive list of
chemicals produced in capacities greater
than 100 million Ibs per year.
Submitted SCSR to the Chemical
Manufacturers Association (CMA) and other
trade groups for their review and comment.
Submitted SCSR to environmental groups for
review and comment.
Visited Monsanto Fibers and Intermediates
Company at Houston, Texas.
Visited the Texas Air Control Board at
Houston, Texas
Completed the industry profile
(Section 9.1 of BID) containing growth
projections and general industry
statistics.
Meeting held with members of the CMA to
discuss SCSR and overall reactor processes
NSPS development.
A-2
-------
Date
October 5, 1983
October 6, 1983
October 11, 1983
November 1983
November 15, 1983
December 19, 1983
December 1983
January 10, 1984
January 11, 1984
February 3, 1984
February 28, 1984
March 12, 1984
Visited Witco Chemical Company at Houston,
lexas.
Visited Dow Chemical at Freeport, Texas.
Visited Tennessee Eastman Company at
Kingsport, Tennessee.
Received Office of Management and Budget
approval for Section 114 questionnaires;
completion of first-round regulatory
analyses.
Developed affected facility and other
definitions.
Meet with EPA Branch Chiefs on the
status of the reactor processes project.
Decision made to revise the growth
projections for reactor process facilities
and to include flares specifically in the
regulatory analysis.
Completed first draft list of potential
Section 114 letter contacts.
Meeting between EPA/CPB and SOB held to
resolve issues on the regulatory
alternatives.
Submitted 20 Section 114 letters to
respondents requesting information on 24
chemicals; identified production
capacities and vent stream
characteristics for chemicals covered by
standards.
Completed concurrence memorandum on the
regulatory alternatives.
Completed and sent BID Chapters 3-6 to
industry for comment.
A-3
-------
Date
March 20, 1984
March 30, 1984
April 24, 1984
April 27, 1984
May 17, 1984
May 25, 1984
June 1984
June 22, 1984
July 12, 1984
July 25, 1984
July 27, 1984
August 1, 1984
August 29, 1984
September 14, 1984
October 1984
Held meeting to discuss revisions to the
flare and incinerator costing procedures.
Completed draft preamble and regulation.
Meet with EPA/CPB to discuss industry
comments on flare costing algorithms.
Completed concurrence memorandum on the
basis of the standards.
Meeting held to resolve preamble and
regulation issues.
Completed a memorandum documenting changes
made to flare and incinerator algorithms.
Revisions made to regulatory analysis;
developed total resource effectiveness
(TRE) coefficients for the regulation.
Developed revised list of large volume
chemicals for the reactor processes
standards.
Sent NAPCTAC package to participants.
Sent Working Group package to group
members.
Docket opened.
Meet with Research Triangle Institute
to discuss the chemical price screening.
Meeting of NAPCTAC in Durham, N.C., at
which the Texas Chemical Council made a
presentation.
Completed NAPCTAC issues summary.
Started revisions of flare and incinerator
costing algorithms based on industry
comment received on costs used for other
SOCMI standards; completed development of
low flowrate and low production capacity
cutoffs.
A-4
-------
Date
October 24, 1984
November 1, 1984
December 26, 1984
January 1985
February 11, 1985
Activity
Meet with EPA to establish procedures for
the chemical price screening analyses.
Meet with EPA to discuss recommended
revisions to flare and incinerator costing
algorithm; discussed impact of revisions.
Sent Steering Committee package to
committee members.
Initiated work on the final Assistant
Administrator proposal package.
Completed work on the chemical price
screening analysis.
A-5
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
-------
APPENDIX B
INDEX TO ENVIRONMENTAL CONSIDERATIONS
This appendix consists of a reference system which is cross indexed with
the October 21, 1974 Federal Register (39 FR37419) containing EPA guidelines
for the preparation of Environmental Impact Statements. This index can be
used to identify sections of the document that contain data and information
germane to any portion of the Federal Register guidelines.
B-l
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background
Information Document (BID)"
1. Background and Description
of Proposed Action
Summary of Regulatory
Alternatives
Statutory Basis for the
Standard
Facilities Affected
Process Affected.
Availability of Control
Techno!ogy
Existing Regulations at
State or Local level
Alternatives to the Proposed
Action
Description of Range of
alternatives examined
A range of regulatory alternative
control levels is discussed in
Section 6.2.
The statutory basis for the
standard is given in Chapter 2.
A description of the facilities to
be affected is given in Chapter 6.
A description of the processes to
be affected is given in Chapter 3,
Sections 3.3 and 3.5.
Information on the availability
of control technology is given in
Chapter 4.
A discussion of existing
regulations on the industry to be
affected by the standards is
included in Chapter 3,
Section 3.4.2.
The definition of the available
range of control alternatives is
presented in Chapter 6,
Section 6.3.
B-2
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
(CONCLUDED)
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements(39 FR 37419)
Location Within the Background
Information Document (BID)
3. Environmental Impacts
Air Pollution
Water Pollution
Solid Waste Disposal
4. Energy
5. Other Impacts
6. Costs
The air pollution impact of the
control alternatives are considered
in Chapter 7, Section 7.2.
The impact of the control alterna-
tives on water pollution are consid-
ered in Chapter 7, Section 7.3.
The impact of the control alterna-
tives on solid waste disposal are
considered in Chapter 7,
Section 7.4.
The impact of the control alterna-
tives on energy use are considered
in Chapter 7, Section 7.5.
Other impacts associated with the
control alternatives are evaluated
in Chapter 7, Sections 7.6 and 7.7.
The national cost impact of the
control alternatives is considered
in Chapter 8, Section 8.5.
B-3
-------
APPENDIX C
EMISSION DATA PROFILE
-------
APPENDIX C. EMISSION DATA PROFILE
Plant
Unit Process • Production
I.D.* Chemical (10° lb/yr)
ALK-1
ALK-2
ALK-3
ALK-4
ALK-5
ALK-6
ALK-7
ALK-8
ALK-9
ALK-10
ALK-11
ALK-12
ALK-13
ALK-14
AMMI-1
AMM-1
AMM-2
CAR-1
CAR-2
CAR- 3
CAR-4
CLE-1
CHL-1
CHL-2
CHL-4
CHL-5
CHL-6
CHL-7
CHL-8
CHL-9
CHL-10
CHL-11
CHL-12
CHL-1 3
CHL-14
CHL-15
Linear Alkylbenzene
Linear Alkylbenzene
Ethylbenzene
Tetra Ethyl -
Tetra Methyl Lead
Ethylbenzene
Linear Alkylbenzene
Linear Alkylbenzene
Cumene
Cumene
Cumene
Cumene
Cumene
Dime thyldichlorosi lane
Nonyl phenol
Caprolactam
Ethanolamines
Ethanolamines
Acetic Acid
Methanol
Methanol
Methanol
Phenol /Acetone
Ethylene Dichloride
Chlorobenzene
Chlorobenzene
Ethylene Dichloride
Ethylene Dichloride
Ethylene Dichloride
Methylene Chloride
Ethylene Dichloride
Ethylene Dichloride
Methylene Chloride
1 ,4-D1chlorobutene
Methyl chloroform
Allyl Chloride
Mono Chloroacetic Acid
250
DNA
1.795
175
147
243
140
700
230
450
400
DNA
DNA
DNA
280
125
40
100
1,484
590
.1.070
500
550
60
73
500
700
847
DNA
100
100
42
DNA
DNA
250
DNA
Sequential Listing of All.
Vent Gas Treatment Devices
HCL/VOC Scrubbers
-
VOC Scrubber
Condenser/ 1 nc 1 ne ra tor
Condenser/VOC Scrubber
Acid Gas Scrubber/Flare
VOC/HCL Scrubbers
.
_
.
.
.
.
-
-
_
-
VOC Scrubber/Flare
Process Heater
Process Heater
Process Heater
. -
HCL Scrubber/Incinerator
Condenser/Scrubber
HCL Scrubber
.
. Incinerator
Condenser/ Inc 1 nera tor
-
HCL Scrubber
Condenser/ 1 nc 1 nera tor
-
Condenser/Scrubber
.
.
VOC Scrubber
Process Vent Stream Characteristics0
flow (scfm) Heat Value (Btu/scf)
DNAd
NO
17
DNA
8.7
REACTOR
•
DNA (low flow)
DNA
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
DNA a
( 18,950 )e
DNA
DNA
NO
(167)
DNA
55
NO
DNA
DNA
NO
40
(267)
NO
9.195
NO
NO
DNA
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
DNA
REACTOR
REACTOR
(1
REACTOR
REACTOR
REACTOR
DNA
PROCESS
181
DNA
4.0
DNA
DNA
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
DNA
(295)
DNA
DNA
PROCESS
(163)
DNA
(Assumed 0)
PROCESS
DNA
DNA
PROCESS
40
.228)
PROCESS
0
PROCESS
PROCESS
DNA
VOC (Ib/hr)
DNA
VENTS
16
DNA
0.1
DNA
DNA
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
DNA
(75)
DNA
DNA
VENTS
(74)
2
4
VENTS
DNA
DNA
VENTS ,
3.6
(113)
VENTS
7.2
VENTS
VENTS
DNA
-------
APPENDIX C. EMISSION DATA PROFILE (Continued)
o
i
ro
Plant
Unit Process ,P3d?l3iffl?
1.0. Chemical (10 \b/yr)
CON-1
CON- 2
CON- 3
CON-4
CRE-1
DEHY-1
OEH-1
DEH-2
DEH-3
DEH-4
DEH-S
DEH-6
DEH-7
DEH-8
DEH-9
OEH-10
DEH-11
DEH-12
DEHC-1
OEHC-2
DEHC-3
EST-1
EST-2
EST-3
EST-4
EST-5
EST-6
EST-7
EST-8
ETH-1
ETHY-1
FLU-1
FLU-2
FLU-3
Acetic Anhydride
Acetic Anhydride
Nonyl phenol, ethoxylated
Bisphenol - A
Benzene
Urea
Acetone
Methyl Ethyl Ketone
Styrene
Styrene
n-Parafflns
Acetone
Acetone
Acetone
Methyl Ethyl Ketone
Methyl Ethyl Ketone
Methyl Ethyl Ketone
Cyclohexanone
Vinyl idene Chloride
Vinyl Idene Chloride
Vinyl Idene Chloride
Ethyl Acrylate
Methyl Methacrylate
Ethyl Acetate
Dioctyl ph thai ate
Dimethyl Terephthalate
Ethyl Acetate
Butyl Acetate ,
Ethylene Glycol
Monoethyl ether acetate
MTBE
Butynediol
Freon - 12
Freon - 113
Freon 11.12,113,114.22
300
600
DNA
DNA
DNA
DNA
73
DNA
548
112
DNA
120
DNA
12
DNA
70
DNA
75
73
DNA
90
168
ONA
200
DNA
30
45
DNA
nu A
DNA
DNA
DNA
DNA
Sequential Listing of A1K
Vent Gas Treatment Devices
Boiler
Boiler
Condenser/Flare
NH3 Scrubber
VOC Scrubber
VOC Scrubber/Flare
Process Heater
Condenser/Flare
Process Heater
Hydrogen System/Flare
Boiler
Incinerator/HCL Scrubber
Condenser/ 1 nc 1 nera tor
No Controls
Incinerator
Condenser
Condenser
Condenser
Condenser
Condenser
Stripper
-
Prn«.« Vent Stream Characteristics0
flow (scfm)
(147)
DNA
NO
NO
(1.289)
DNA
DNA
DNA
(5,208)
(574)
DNA
NO
NO
NO
NO
NO
DNA
DNA
(10)
NO
DNA
75
DNA
DNA
5
NO
7
2
8
NO
9.2
NO
NO
NO
Heat Value (Btu/sct)
(1,069)
DNA
REACTOR PROCESS
REACTOR PROCESS
(205)
ONA
DNA
DNA
(280)
(300)
DNA
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
DNA
DNA
(600)
REACTOR PROCESS
ONA
102
DNA
DNA
DNA (Assume 102)
REACTOR PROCESS
DNA (Assume 102)
DNA (Assume 102)
DNA (Assume 102)
REACTOR PROCESS
.747
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
VOC lit>/nrj
(305)
DNA
VtNTS
VENTS
(8.3)
0
DNA
DNA
(711)
(161)
DNA
VENTS
VENTS
VENTS
VENTS
VENTS
DNA
DNA
(41)
VENTS
DNA •
6.1
0.1 •
ONA
0.1 .
VENTS
0.5
0.1
20f .
VENTS
19.8
VENTS
VENTS
VENTS
-------
APPENDIX C. EMISSION DATA PROFILE (Continued)
r>
i
to
Plant
Unit Process Production Sequential Listing of All.
l.D.° Chemical (10D Ib/yr) Vent Gas Treatment Devices"
HYD-1
HYD-2
HYD-3
HYD-5
HYD-6
HYD-7
HYD-8
HYO-9
HYD-10
HYD-11
HYDC-3
HYOC-4
HYDC-5
HYDC-6
HYDC-7
HYDC-8
HYDC-9
HYDC-10
HYDC-11
HYDC-12
HYDF-1
HYDF-2
HYDI-1
HYDO-1
HYDO-2
HYOO-3
HYDR-1
HYDR-2
HYDR-3
HYDR-4
NIT-1
NIT-2
NIT-3
NUT-1
NUT-2
NUT- 3
Hexamethylene dianine
Hexamethylene diamine
Cyclohexane
Aniline
Butanediol
Cyclohexanol
Toluene Diamine
n-Butyl Alcohol
Hexamethylene Diamine
6-Butylene
Methyl Chloride
Methyl Chloride
Ethyl Chloride
Methyl Chloride
Ethyl Chloride
Ethyl Chloride
Ethyl Chloride
Ethyl Chloride
Ethyl Chloride
Eplchlorohydrin
Oxo Alcohols
Butyraldehyde
Adiponitrile
Propylene Oxide
Sec Butyl Alcohol
Glycerin
Propylene Glycol
Ethylene Glycol
Ethylene Glycol
Ethylene Glycol
Nitrobenzene
Dinitrotoluene
01 nitro toluene
Linear Alkyl benzene
Linear Alkylbenzene
Dodecyl benzene sulfonic
180
190
1.6
ISO
DNA
DNA
DNA
DNA
DNA
DNA
DNA
80
DNA
100
16
DNA
DNA
DNA
DNA
250
500
175
180
350
270
DNA
DNA
183
DNA
DNA
123
88
DNA
250
DNA
No Controls
Boiler
•
.
Flare
Incinerator
Flare
Boiler
-
Scrubber/Condenser/Incinerator
Refrigerated Condenser
Flare
-
•
.
Condenser/ Incl nera tor
Combustion Device
Condenser/Flare
Boiler
NH3 Scrubber
Condenser
Flare
-
_
.
_
-
No Controls
VOC Scrubber
VOC Scrubber/ Incinerator
.
.
Process Vent Stream Characteristics0
flow (scfm)
70
(113)
NO
NO
DNA
NO
DNA
(3.2)
(1,304)
NO
DNA
20
NO
(20)
NO
NO
NO
NO
DNA
DNA
DNA
(729)
1.080
99
DNA
DNA
NO
NO
NO
NO
13
822
DNA
NO
NO
Heat Value (Btu/scf )
323
(900)
REACTOR PROCESS
REACTOR PROCESS
DNA
REACTOR PROCESS
DNA
(1,578)
(462)
REACTOR PROCESS
DNA
(Assume 500)
REACTOR PROCESS
(1,286)
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
DNA
DNA
DNA
(1.233)
70
0
DNA
DNA
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
REACTOR PROCESS
434
o
DNA
REACTOR PROCESS
REACTOR PROCESS
VOC (Ib/hr)
6.6
0
VENTS
VENTS
DNA
VENTS
DNA
(19.6)
(0)
VENTS
DNA
2.1
VENTS
(168)
VENTS
VENTS
VENTS
VENTS
DNA.
2,080T
DNA
(2.394)
27
0.1
DNA
DNA
VENTS
VENTS
VENTS
VENTS
19
0.1
DNA
VENTS
VENTS
acid. Sodium Salt
ONA
NO
REACTOR
PROCESS
VENTS
-------
APPENDIX C. EMISSION DATA PROFILE (Continued)
o
i
Plant
Unit Process Production
I.D.* Chemical (10° Ib/yr)
OLIG-1
OLIG-2
OLIG-3
OLIC-4
OLIG-5
0X1-1
OX I -2
OXI-3
OX I -4
OXYA-1
OXYC-1
PHO-1
PYR-1
PYR-2
PVR-3
PYR-4
PYR-5
PYR-6
PYR-7
SUL-1
SULP-1
Octene
Dodecene
o-Butylene
Trlpropylene
Dodecene
Adlplc Acid
Adlplc Acid
Adlplc Acid
Ethyl ene Oxide
Vinyl Acetate
Ethylene Dlchlorlde
Toluene Dlisocyanate
Ketene
Ethylene
Ketene
Propylene
Ethylene
Vinyl Chloride Monomer
Blvlnyl
Dodecyl benzene sulfonic
acid
Carbon Dlsulflde
DNA
DNA
DNA
DNA
DNA
640
100.
700
292
398
912
DNA
300
DNA
600
DNA
DNA
310
DNA
30
DNA
Sequential Listing of All
Vent Gas Treatment Devices
-
NH, Scrubber
No Controls
NH, Scrubber/Boiler
No Controls
No Controls
Incinerator
-
_
-
Acid Gas Scrubber
-
. Process Vent 'Stream Characteristics0
flow (scfm) Heat Value (Btu/scf)
NO
NO
NO
NO
NO
2,800
848
(4.653)
12,187
7
(304)
NO
NO
NO .
NO
NO
NO
NO
NO
1.863
NO
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
REACTOR
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
0
0
(0)
4
407
(713)
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
PROCESS
0
PROCESS
VOC (Ib/hr)
VENTS
VENTS
VENTS
VENTS
VENTS
0
0
(0)
130
0.1
(748)
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
VENTS
0.1
VENTS
-------
APPENDIX C (Concluded). FOOTNOTES
a. Process units are identified by the chemical reaction
ALK
MMI
AKH
CAR
CLE
CRE
CHL
CON
OEHY
OEII
DEHC
EST
ETH
ETHY
FLU
- Alkylation
- Amn1 nation
- Amnonylisis
- Carbonylation
- Clevage
- Catalytic Reforming
- Chlorination
- Condensation
- Dehydration
- Deny drogenat ion
- Dehydrochlorination
- Esterlflcatlon
- Etherlflcatlon
- Ethynylation
- Fluorination
HYD -
HYDC -
HYOF -
HYDI -
HYDO -
HYDR -
NIT -
NUT -
OLIG -
OXI -
OXYA -
OXYC -
PHO -
PYR -
SUL -
SULP -
associated with their manufacture. Reaction codes are as follows:
Hydrogenation
Hydrochlorination
Hydrof ormy 1 a t i on
Hydrodimerization '
Hydrolysis
Hydratlon
Nitration
Neutralization
Ollgomerlzation
Oxidation (Pure 0?)
Oxyacetylation •
Oxychlorination (Pure
Phosgenatlon
Pyrolysis
Sulfonation
Sulfurizatlon (Vapor
OJ
2
Phase)
o
I
en
II) «3« I"? *fntl es a11 Process vent stream treatment devices, including all combustion and noncombustion devices
Identified in the data base. Devices are not listed when (1) there Is no process vent stream or (2) there is a vent
i< » A Is ™cyc}ed within tj* Process or Is a feed to another process (e.g., a hydrogen feed steam). All devices are
listed In the sequence In which they occur.
c. For process units where combustion devices are used, the vent stream characteristics presented are In parentheses and
represent the vent stream characteristics just prior to the combustion device. For units without combustion devices,
the vent stream characteristics presented represent the vent at Its point at discharge to the atmosphere. These are
the characteristics upon which the TRE calculation Is based.
d. DNA - Data not available.
e. For all process units where combustion is currently used, i.e., baseline, all vent stream data are In parentheses.
f> Snra-eX?r!!SCd 1n Unlts of 1bs per 1()6 1bs of Producti°n because sufficient information was not available to express
VOC in Ib/hr.
-------
APPENDIX D
EMISSION MEASUREMENT
-------
APPENDIX D
EMISSION MEASUREMENT
0.1 INTRODUCTION
The proposed reactor processes new source performance standard (NSPS)
divides reactor process facilities into two groups. One group of facilities
is required under the proposed standard to reduce VOC emissions by combusting
them in an incinerator or a flare. Emissions must be reduced by 98 weight
percent for flares or by 98 weight percent or to 20 ppmv (total volume
concentration, by compound), whichever is less stringent, for incinerators.
Standard measurement methods should be used to determine the VOC reduction.
The second group of facilities is not required to reduce VOC emissions under
the proposed standard. As discussed in Chapter 6, the two groups of facili-
ties are distinguished by a cutoff level of total resource effectiveness
(TRE). An index value of TRE can be associated with each reactor process
vent stream for which the offgas characteristics of flowrate and individual
VOC emission concentrations are known. The proposed standard would require
that measurements be made to determine whether a source has a TRE index
value above or below the cutoff level. In this case, measurements are
needed to determine the flowrate and individual VOC emission concentrations.
The net heating value of the reactor process vent stream is then calculated.
The purpose of this appendix is to discuss and present measurement
methods acceptable for determination of VOC reduction efficiency and/or
individual VOC .emission concentrations.
0-1
-------
D.I.I VOC MEASUREMENT
Numerous methods exist for the measurement of organic emissions. Among
these methods are continuous flame ionization analyzers (FIA) and gas chroma-
tograph (GC) (EPA Reference Methods 25 and 18). Each method has advantages
and disadvantages. Of the two procedures, GC has the distinct advantage of
identifying and quantifying the individual compounds. However, GC systems
are expensive; and determination of the column required and analysis of
samples can be time consuming.
The FIA technique is the simplest procedure. However, the FIA responds
differently to various organic compounds and can yield highly biased results
depending upon the compounds involved. Another disadvantage of the FIA is
that a separate methane measurement is required to determine nonmethane
organics. Of course, the direct FIA procedure does not identify or quantify
individual compounds.
Method 25 sampling and analysis provides a single nonmethane organic
measurement on a carbon basis; this is convenient for establishing control
device efficiencies on a consistent basis. However, Method 25 does not
provide any qualitative or quantitative information on individual compounds
present. For these determinations, Method 18 must be used.
D.I.2 EMISSION MEASUREMENT TESTS
No emission measurement tests were performed during data gathering for
4
this proposed standard. All emission data were collected directly from
existing industry emission records.
D-2
-------
D.2 PERFORMANCE TEST METHODS
EPA Methods 18 and 25 are the recommended test procedures for
determining control device efficiencies for reactor processes. However,
Method 25 is likely to yield slightly lower calculated efficiencies than
actually obtained. Method 25 can be expected- to yield higher results than
the Method 18 at the emission outlet when the outlet concentration is less
than 100 ppm volume; therefore, at this time, Method 25 is particularly not
recommended for performance tests to measure compliance with the 98 percent
reduction provision of the proposed standard when the outlet emissions are
expected to be below 100 ppm. EPA Methods 1, 1A, 2, 2A, 2C, and 2D are
recommended for determination of stack flowrates.
In order to determine the stream net heating value for reactor process
sources, both identification and quantification of the substances being
emitted are necessary. Method 18 can be used to: (1) determine individual
VOC emissions from the control device outlet, (2) determine individual VOC
reduction efficiency of the control device, and (3) provide data required to
determine whether a source has a TRE index value above or below the cutoff
level specified in the proposed standard.
The costs associated with performing a control device efficiency test,
a total outlet VOC concentration test, or a test to gather data to compute a
TRE value will vary widely, depending on the resources available; but are
estimated to be $10,000 or $15,000 per test.
D-3
-------
APPENDIX E
LIST OF 173 SYNTHETIC ORGANIC CHEMICALS
BEING CONSIDERED FOR REGULATION
-------
LIST OF 173 SYNTHETIC ORGANIC CHEMICALS
BEING CONSIDERED FOR REGULATION
Common Name
Acetaldehyde
Acetic acid
(1) Acetic anhydride
1 1\ As** + 4r. x... .'J.
Chemical Name
Acetaldehyde
Acetic acid
Acetic acid, anhydride
CAS No.
75-07-0
64-19-7
108-24-7
(1) Acetone
(2) Dimethyl ketone
(1) Acetone cyanohydrin
(2) 2-Methyllactonitrile
(1) Acetylene
(2) Ethine
Acrylic acid
Acrylonitrile
Adi pic acid
(1) Adiponitrile
(2) 1,4-Dicyanobutane
Alcohols, C-ll or lower, mixtures
Alcohols, C-12 or higher, mixtures
Alcohols, C-12 or higher, unmixed
Alkylbenzene
(1) Ally! chloride
(2) 3-Chloropropene
Amylene
Amylenes, mixed
(1) Aniline
(2) Phenylamine
2-Propanone
67-64-1
2-Hydroxy-2-methylpropanenitrile 75-86-5
Ethyne
2-Propenoic acid
2-Propenenitrile
Hexanedioic acid
Hexanedinitrile
74-86-2
79-10-7
107-13-1
124-04-9
111-69-3
Alcohols, C-ll or lower, mixtures
Alcohols, C-12 or higher, mixtures
Alcohols, C-12 or higher, unmixed
Dodecylbenzene, linear 123-01-3
3-Chloro-l-propene 107-05-1
2-Methyl-2-butene
2-Methylbutenes, mixed
Benzenamine
513-35-9
62-53-3
E-l
-------
Common Name
Chemical Name
CAS No.
Benzenesulfonic acid
Benzenesulfonic acid
Cjg.g-alkyl derivatives,
sodium salts
Benzol
(1) Benzyl chloride
(2) a-Chlorotoluene
(1) Bisphenol A
(2) 4,4'-Isopropylidenediphenol
(1) Bivinyl
(2) Divinyl
(1) Brometone
(2) Tribromo-t-butyl alcohol
(3) Acetone-bromoform
Butadiene and butene fractions
n-Butane
1,4-Butanediol
Butanes, mixed
n-Butyl acetate
Butyl aerylate
n-Butyl alcohol
sec-Butyl alcohol
(1) tert-Butyl alcohol
(2) t-Butanol
Butyl benzyl phthalate
Butyl CellosolveR
Benzenesulfonic acid 98-11-3
Benzenesulfonic acid 68081-81-2
C1Q_lg-alkyl derivatives,
sodium salts
Benzene 71-43-2
(Chloromethyl) benzene 100-44-7
4,4'-(1-Methy1 ethylidene) 80-05-7
bisphenol
1,3-Butadiene 106-99-0
1,1,1-Tri bromo-2-methyl-2- 76-08-4
propanol
Butadiene and butene fractions
Butane 106-97-8
1,4-Butanediol 110-63-4
Butanes, mixed
Acetic acid, butyl ester 123-86-4
2-Propenoic acid, butyl ester 141-32-2
1-Butanol 71-36-3
2-Butanol 78-92-2
2-Methyl-2-propanol 75-65-0
1,2-Benzenedicarboxylic acid 85-58-7
butyl, phenylmethyl ester
2-Butoxyethanol 111-76-2
E-2
-------
Common Name
a-Butylene
(1) 6-Butylene
(2) pseudo-Butylene
Butylenes (mixed)
tert-Butyl hydroperoxide
2-Butyne-l,4-diol
Butyraldehyde
Butyric anhydride
Caprolactam
(1) Carbolic acid
(2) Hydroxybenzene
Carbon disulfide
Carbon tetrachloride
Chloroacetic acid
Chlorobenzene
Chloroform
(1) p-Chloronitrobenzene
(2) p-Nitrochlorobenzene
Citric acid
Cumene
Cumene hydroperoxide
(1) Cyanuric chloride
(2) 2,4,6-Trichloro-s-triazine
Chemical Name
1-Butene
2-Butene
Butenes, mixed
1,1-Dimethylethyl hydroperoxide
2-Butyne-l,4-diol
Butanal
Butanoic acid, anhydride
Hexahydro-2H-azepi n-2-one
Phenol
Carbon disulfide
Tetrachoromethane
Monochloroacetic acid
Chlorobenzene
Trichloromethane
1-Chloro-4-ni trobenzene
2-Hydroxy-1,2,3-
propanetricarboxylic acid
(1-Methylethyl) benzene
1-Methyl-1-phenylethyl
hydroperoxide
CAS No.
^^"^^^"^•^»™^»
106-98-9
25167-67-3
75-91-2
110-65-6
123-72-8
106-31-0
105-60-2
108-95-2
75-15-0
56-23-5
79-11-8
108-90-7
67-66-3
100-00-5
77-92-9
98-82-8
80-15-9
2,4,6-Trichloro-l,3,5-triazine 108-77-0
E-3
-------
Common Name
Chemical Name
CAS No.
Cyclohexane
Cyclohexane, oxidized
Cyclohexanol
Cyclohexanone
Cyclohexanone oxime
Diacetone alcohol
1,4-Dichlorobutene
3,4-Dichloro-l-butene
(1) Dieth
(2) 2,2'-
Diethanolamine
Aminodiethanol
Diethyl benzene
Diethylene glycol
Di-isodecyl phthalate
Dimethyldichlorosilane
1) Dimethyl terephthalate
2) Terephthalic acid, dimethyl
ester
(3) DMT
2,4-(and 2,6)-dinitrotoluene
(1) Dioctyl phthlate
(2) Bis (2-ethylhexyl) phthalate
(3) Di (2-ethyl hexyl) phthalate
Hexahydrobenzene 110-82-7
Cyclohexane, oxidized 68512-15-2
(1) Hexalin 108-93-0
(2) Hexahydrophenol
Pimelic ketone 108-94-1
Cyclohexanone oxime 100-64-1
4-Hydroxy-4-methyl-2-pentanone 123-42-2
l,4-Dichloro-2-butene 110-57-6
3,4-Dichloro-l-butene 64037-54-3
2,2'-Iminobisethanol 111-42-2
Diethylbenzene 25340-17-4
2,2'-Oxybisethanol 111-46-6
1,2-Benzenedicarboxylic acid 26761-40-0
diisodecyl ester
Dichlorodimethylsilane 75-78-5
1,4-Benzenedicarboxylic. acid 120-61-6
dimethyl ester
1-Methyl-2,4-dinitrobenzene 121-14-2
(and 2-Methyl-l,3-dinitrobenzene)
1,2-Benzenedicarboxylic acid
bis (2-ethylhexyl) ester
117-81-7
E-4
-------
Common Name
Chemical Name
CAS No.
(1) Dodecene
(2) Tetrapropylene
Dodecyl benzene, non linear
Dodecylbenzenesulfonic acid
Dodecylbenzenesulfonic acid,
sodium salt
Epichlorohydrin
Ethanolamine
Ethyl acetate
Ethyl- acrylate
Ethyl alcohol
Ethyl benzene
Ethyl chloride
(1 Ethylene
(2 Elayl
(3 Olefiant gas
1-Dodecene
Dodecyl benzene, non linear
Dodecylbenzenesulfonic acid
Dodecylbenzenesulfonic acid,
sodium salt
(Chloromethyl) oxirane
2-Aminoethanol
Acetic acid, ethyl ester
2-Propenoic acid, ethyl ester
Ethanol
Ethyl benzene
Chloroethane
Ethene
25378-22-7
123-01-2
1886-81-3
25155-30-0
106-89-8
141-43-5
141-78-6
140-88-5
64-17-5
100-41-4
75-00-3
74-85-1
(1) Ethylene dibromide
(2) Ethylene bromide
(1) Ethylene dichloride
(2) Ethylene chloride
Ethylene glycol
(1) Ethylene glycol monoethyl
w wi • w • *•>*>* t«M V^ |^
(2) Cellosolve acetate*
(1) Ethylene glycol monomethyl
ether
(2) Methyl Cellosolve*
1,2-Dibromoethane
1,2-Dichloroethane
1,2-Ethanediol
2-Ethoxyethyl acetate
2-Methoxyethanol
.106-93-4
107-06-2
107-21-1
111-15-9
109-86-4
E-5
-------
Common Name
Chemical Name
CAS No.
Ethylene oxide
2-Ethylhexyl alcohol
(2-Ethylhexyl) amine
6-Ethyl-l,2,3,4-tetrahydro
9,10-antracenedione
Formaldehyde
(1) Freon 11
(2) Fluorotrichloromethane
Freon 12
Freon 21
Freon 22
(3
Glycerol
Glyceryl
Glycerin
n-Heptane
Heptenes (mixed)
Hexamethy1ene diamine
(1) Hexamethylene diamine adipate
(2) Nylon salt
(1) Hexamine
(2) Hexamethylene tetramine
Hexane
Isobutane
Isobutyl alcohol
Oxirane
2-Ethyl-l-hexanol
(2-Ethylhexyl) amine
6-Ethyl-l,2,3,4-tetrahydro
9,10-antracenedione
(1) Formalin (solution)
(2) Methanal (gas)
Trichlorofluoromethane
Di chlorodi f1uoromethane
Dichloroflueoromethane
Chlorodi f1uoromethane
1,2,3-Propanetriol
Heptane
Heptenes (mixed)
1,6-Hexanediamine
1,6-Hexanediamine adipate
1,3,5,7-Tetraazatricyclo
(3.3.1.13.7)-decane
Hexane
2-Methylpropane
2-Methyl-l-propanol
75-21-8
104-76-7
104-75-6
15547-17-8
50-00-0
75-69-4
75-71-8
75-43-4
75-45-6 .
56-81-5
142-82-5
124-09-4
3323-53-3
100-97-0
110-54-3
75-28-5
78-83-1
E-6
-------
Common Name
Chemical Name
CAS No.
(1) Isobutylene
(2) 2-Methylpropene
Isobytyraldehyde
Isopentane
Isoprene
(1) Isopropyl acetone
(2) Methyl Isobutyl ketone
Isopropyl alcohol
Ketene
Linear alcohols, ethoxylated,
mixed
Linear alcohols, ethoxylated, and
sulfated, sodium salt, mixed
Maleic anhydride
Mesityl oxide
(1) Methyl alcohol
(2) Wood alcohol
Methyl amine
ar-Methylbenzenediamine
Methyl chloride
Methyl chloroform
Methylene chloride
Methyl ethyl ketone
(1) Methyl methacrylate
(2) Methacrylic acid methyl
ester
2-Methyl-l-propene
2-Methylpropanal
2-Methylbutane
2-Methyl-l,3-butadiene
4-Methyl-2-pentanone
2-Propanol
Ethenone
Linear alcohols, ethoxylated,
mixed
Linear alcohols, ethoxylated, and
sulfated, sodium salt, mixed
2,5-Furandione
4-Methyl-3-penten-2-one
Methanol
Methanamine
ar-Methylbenzenediamine
Chloromethane
1,1,1-Tri chloroethane
Dichloromethane
2-Butanone
2-Methyl-2-propenoic acid,
methyl ester
115-11-7
78-84-2
78-78-4
78-79-5
108-10-1
67-63-0
463-51-4
108-31-6
141-79-7
67-56-1
74-39-5
25376-45-8
74-87-3
71-55-6
75-09-2
78-93-3
80-62-6
E-7
-------
Common Name
Chemical Name
CAS No.
1-Methyl-2-pyrrolidone
MTBE
(1) Naphthene
(2) Naphtha!in
Nitrobenzol
(1) n-Nonanol
(2) Nonyl alcohol
Nonylphenol
Nonylphenol, ethoxylated
Octene
Oil-soluble petroleum sulfonate,
calcium salt
Pentaerythritol
3-Pentenenitrile
Pentenes, mixed
1-Phenylethyl hydroperoxide
Phenylpropane
Phosgene
Phthalic anhydride
Propane
Propionaldehyde
Propyl alcohol
Propylene
1-Methyl-2-pyrrolidinone 872-50-4
Methyl tert-butyl ether
Naphthalene 91-20-3
Nitrobenzene 98-95-3
1-Nonanol 143-08-8
Nonylphenol 25154-52-3
Nonylphenol, ethoxylated 9016-45-9
Octene 25377-83-7
Oil-soluble petroleum sulfonate,
calcium salt
2,2-Bis (Hydroxymethyl)- 115-77-5
1,3-propanediol
3-Pentenenitrile 4635-87-4
Pentenes, mixed 109-67-1
1-Phenylethyl hydroperoxide
Propylbenzene 103-65-1
Carbonic dichloride 75-44-5
1,3-Isobenzofurandione 85-44-9
Dimethyl methane 74-98-6
Propanal ' 123-38-6
1-Propanol 71-23-8
1-Propene 115-07-1
E-8
-------
Common Name
Chemical Name
CAS No.
Propylene glycol
Propylene oxide
Sorbitol
Styrene
Terephthalic acid
(1) Tetrachloroethylene
(2) Perch!oroethylene
Tetraethyl lead
1,2,3,4-Tetrahydrobenzene
Tetra (methyl-ethyl) lead
Tetramethyl lead
THF
Toluene
(1) Toluene-2,4-diamine
(2) 2,4-Diaminotoluene
(3) 2,4-Tolylenediamine
Toluene-2,4-(and, 2,6)-
diisocyanate (80/20 mixture)
Trichloroethylene
(1) Trichlorotrifluoroethane
(2) Fluorocarbon 113
(1) Triethanolamine
(2) Triethylolamine
Triethylene glycol
Trimethylene
1,2-Propanediol 57-55-6
Methyloxirane 75-56-9
D-Glucitol 50-70-4
Ethenylbenzene 100-42-5
1,4-Benzenedicarboxylic acid 100-21-0
Tetracholoroethene 127-18-4
Tetraethylplumbane 78-00-2
Cyclohexene 110-83-8
Tetra (methyl-ethyl) plumbane,
Tetramethylpiumbane 75-74-1
Tetrahydrofuran 109-99-9
MethyTbenzene 108-88-3
4-Methyl-l,3-benzenediamine 95-80-7
l,3-D1isocyanato-2-(and 4-) 26471-62-5
methyl benzene (80/20 mixture)
Trichloroethylene 79-01-6
l,l,2-Trichloro-l,2,2- 76-13-1
trifluoroethane
2,2',2"-Nitrilotrisethanol 102-71-6
2,2'-(l,2-Ethanediylbis (oxy)) 112-27-6
bisethanol
Cyclopropane
75-19-4
E-9
-------
Common Name
Chemical Name
CAS No.
Tripropylene
Vinyl acetate
Vinyl chloride
Vinylidene chloride
Vinyl trichloride
m-Xylene
o-Xylene
p-Xylene
Xylenes (mixed)
1-Nonene
Acetic acid, ethenyl ester
Chloroethene
1,1-Dichloroethene
1,1,2-Tri chloroethane
1,3-Dimethylbenzene
1,2-Dimethybenzene
1,4-Dimethyl benzene
Dimethyl benzenes (mixed)
27215-95-8
108-05-4
75-01-4
75-35-4
79-00-5
108-38-3
95-47-6
106-42-3
1330-20-7
E-10
-------
APPENDIX F
TRE EQUATION AND COEFFICIENT DEVELOPMENT
FOR THERMAL INCINERATORS AND FLARES
-------
-------
APPENDIX F: TRE EQUATION AND COEFFICIENT DEVELOPMENT
FOR THERMAL INCINERATORS AND FLARES
F.I INTRODUCTION
This appendix describes the development of the TRE index equations used
in the proposed standards for reactor processes. These equations can be
used to directly calculate the TRE index based on the vent stream flowrate
(scm/min), heating value (MJ/scm), and VOC emission rate (kg/hr).
F.2 INCINERATOR TRE INDEX EQUATION
This section presents the method used to develop the incinerator TRE
index equation and an example calculation of the incinerator TRE index.
F.2.1 Incinerator TRE Index Equation Development
The incinerator TRE index equation was developed in the following
manner. First, an equation for total annual ized cost was determined by
combining the equations for each component of the annual ized costs. The
equations- for each annual ized cost component are shown in Docket Item
No. II-B-62 and include annualized capital costs, supplemental gas costs,
labor costs, electricity costs, quench water costs, scrubber water costs,
neutralization costs, and heat recovery credits.
The equation for total annualized costs developed from the equations
for each annualized cost component (Docket Item No. II-B-62) was divided by
the amount of VOC removed and the reference cost effectiveness of $2,500/Mg
of VOC removed to generate the general TRE index equation. Collecting like
terms results in an equation with the following form:
TRE = ^TOC [• t M/*88 + c(Q ) + d(Qj(HT) + e«L °-88)(HT°-88) +
f (Ys)0'5] s.s T
where for a vent stream flowrate (scm/min) at a standard temperature of 20°C
is greater than or equal to 14.2 scm/min:
F-l
-------
TABLE F-l. REACTOR PROCESSES NSPS TRE COEFFICIENTS FOR VENT STREAMS CONTROLLED BY AN INCINERATOR
DESIGN CATEGORY Al. FOR HALOGENATED PROCESS VENT STREAMS, IF
Qs • Vent Stream Flowrate ( son/ml n)
14.2 < Q < 18.8
18.8 ~ q? < 699
699 < Of < 1400
1400 < q* < 2100
' 2100 < Q* < 2800
2800 < q| < 3500
a
19.65559
20.48848
40.83338
61.17828
81.52318
101.86808
DESIGN CATEGORY A2. FOR HALOGENATED PROCESS VENT STREAMS, IF
q « Vent Stream Flowrate (scm/m1n)
14.2 q. < 18.8
18.8 ~ 0s ~ 699
699 q* ~ 1400
1400 0* < 2100
2100 q* ~ 2800
2800 q| < 3500
DESIGN CATEGORY B. FOR NONHALOGENATED
Qs • Vent Stream Flowrate (scm/min)
14.2 < 0 < 1340
1340 < q* ~ 2690
2690 < Q| I 4040
DESIGN CATEGORY C. FOR NONHALOGENATEO
q » Vent Stream Flowrate (scm/min)
14.2 < q. < 1340
1340 < q! < 2690
2690 < q| < 4040
DESIGN CATEGORY D. FOR NONHALOGENATEO
Qs - Vent Stream Flowrate (scm/min)
14.2 < q < 1180
1180 < 0« < 2370
2370 < 0* i 3550
DESIGN CATEGORY E. FOR NONHALOGENATEO
,YS • Dilution Flowrate (scm/m1n) « (Qs
14.2 < Y. < 1180
1180 ~ Ys ~ 2370
2370 < Y| < 3550
»
19.31203
20.14491
40.14625
60.14759
80.14892
100.15026
PROCESS VENT STREAMS,
a
8.84812
17.55267
26.25721
PROCESS VENT STREAMS,
a
9.56783
18.99209
, 28.41635
PROCESS VENT STREAMS.
a
6.87612
13.60866
20.34120
PROCESS VENT STREAMS,
)(HT)/3.6 a
6.87612
13.60866
20.34120
0 < NET HEATING VALUE (MJ/scm) < 3.5:
b
0.27948
0.27948
0.30372
0.31887
0.33007
0.33902
NET HEATING
b
0.27099
0.27099
0.29449
0.30917
0.32003
0.32872
c
0.76683
0.30929
0.30929
0.30929
0.30929
0.30929
VALUE > 3.5
C
0.20500
-0.25255
-0.25255
-0.25255
-0.25255
-0.25255
IF 0 <. NET HEATING VALUE
b
0.10696
0.11623
0.12203
C
0.09188
0.09188
0.09188
d
-0.13173
-0.13173
-0.13173
-0.13173
-0.13173
-0.13173
MJ/scm:
d
0
0
0
0
0
0
(MJ/scm) < 0.48
d
-0.17252
-0.17252
-0.17252
IF 0.48 < NET HEATING VALUE (NJ/scm) < 1
b
0.06187
0.06723
0.07058
IF 1.9 < NET
b
0.07036
0.07648
0.08028
c
0.32303
0.32303
0.32303
d
-0.16316
-0.16316
-0.16316
HEATING VALUE (MJ/scm) < 3.
c
0.02669
0.02669
0.02669
IF NET HEATING VALUE > 3
b
0
0
0
C
0
0
0
d
0
0
0
.6 MJ/scm:
d
0.00730
0.00730
0.00730
e
0
0
0
0
0
0
e
0
0
0
0
0
0
:
e
0
0
0
.9:
e
0
0
0
6:
e
0
0
0
e
0.02249
0.02445
0.02566
f
0.01044
0.01044
0.01477
0.01809
0.02088
0.02335
f
0.01044
0.01044
0.01477
0.01809
0.02088
0.02335
f
0.01044
0.01477
0.01809
f
0.01044
0.01477
0.01809
f
• 0.01044
0.01477
0.01809
f
O.C1044
0.01477
0.01809
F-2
-------
TRE « Total resource effectiveness index value.
Qs = ,®or stream flowrate (scm/min), at a standard temperature of
C-\J U •
HT = Vent stream net heating value (MJ/scm), where the net enthalpy
per mole of vent stream is based on combustion at 25°C and
760 mm Hg, but the standard temperature for determining the
volume corresponding to one mole is 20°C, as. in the definition
of Q$.
ETOC ~ Hourl.y emissions of total organic compounds reported in kq/hr
measured at full operating flowrate.
Ys = QS for a11 vent st™am categories listed in Table F-l except for
Category E vent streams where Y = (Q )(HT)/3.6.
where for a vent stream flowrate (scm/min) at a standard temperature of 20°C
that is less than 14.2 scm/min:
TRE = Total resource effectiveness index value.
Qs - 14.2 scm/min
HT * (FLOW)(HVAL)/14.2
where:
FLOW = Vent stream flowrate (scm/min), at a temperature of 20°C.
HVAL = Vent stream net heating value (MJ/scm), where the net enthalpy
per mole of vent stream is based on combustion at 25°C and
760 mm Hg, but the standard temperature for determining the
volume corresponding to one mole is 20°C, as in the definition
of Qs.
ETOC = Hourly emissions of total organic compounds reported in Kq/hr
measured at full operating flowrate.
YS = Qs for all vent stream'categories listed in Table F-l except for
Category E vent streams where Y « (Q )(HT)/3.6.
5 SI
The coefficients a through f are functions of incinerator design
parameters, such as temperature, residence time, supplemental fuel
requirements, etc. As discussed in Chapter 8, there are six different
design categories of incinerators. The design parameters were previously
F-3
-------
presented in Table 8-1. Substituting the design values from Table 8-1 into
the general equation allows values for coefficients a through f to be
derived for each design category. This derivation is included in Docket
Item No. II-B-62.
The results of this derivation are summarized in Table F-l. As shown,
the coefficients are divided into six incinerator design categories.
Under each design category listed in Table F-l, there are several intervals
of vent stream flowrate. Each flowrate interval is associated with a
different set of coefficients. The first flowrate interval in each design
category applies to vent streams with a flowrate corresponding to the
smallest control equipment system easily available without special custom
design.
The remaining flowrate intervals in each design category apply to vent
streams which would be expected to use two, three, four, or five sets of
control equipment, respectively. These flowrate intervals are distinguished
from one another because of limits to prefabricated equipment sizes. The
flowrate intervals and maximum vent stream flowrate for each design category
are discussed in Chapter 8.
F.2.2 Example Calculation of an Incinerator-based TRE Index Value
for a Facility
This section presents an example of use of the TRE index equation. The
example reactor process vent stream has the following characteristics:
1. Q =284 scm/min
2. HT - 0.37 MJ/scm
3. ETQC =76.1 kg/hr.
4. Y =- 284 scm/min.
5. No halogenated compounds in the vent stream.
Based on the stream heating value of 0.37 MJ/scm, Category B is the
applicable incinerator design category for this stream. The flowrate is
284 scm/min, and therefore the coefficients for the second flowrate interval
under Category B are used. The coefficients for Category B, flow interval
#1 are:
F-4
-------
a = 8.85
b = 0.107
c = 0.092
d = -0.173
e = 0
f = 0,010
The TRE equation is:
1
TRE = ETQC [a + b(Qs)°'88 + C(QS) + d(Qs)(HT) + e(Qs 0-88)(HT°'88)
f (Qs)0'5]
TRE = (.013)[8.85 + 0.107 (284)0'88 -t- (0.092)(284)-0.173
(284)(.37) + 0 + 0.010)(284)°'5]
TRE = 0.116 + 0.203 + 0.343 - 0.239 + 0'+ 0.002
TRE = 0.425
Since the calculated TRE index value of 0.425 is less than the cutoff value
of 1.0, this facility would be required to reduce VOC emissions by 98 weight-
percent or to 20 ppmv because the cost of incineration is considered to be
reasonable. Because the TRE index is a ratio of two cost-effectiveness
values, it is possible to calculate cost effectiveness for controlling any
vent stream given its TRE index value. The TRE index value of the facilfty
is multiplied by the reference cost-effectiveness $2,500/Mg as follows:
TRE = 0.425
Reference cost effectiveness = $2,500/Mg
Cost effectiveness for example stream = (0.425)(2,500) = $l,063/Mg of
VOC removed
F-5
-------
If the TRE index value for this example were above 1.0, the flare-based TRE
equation (see Section F.3) would be used to calculate the flare-based TRE
index because flares can be applied to nonhalogenated vent streams. If the
flare-based TRE index were less than 1.0, this facility would have to reduce
VOC emissions by 98 weight-percent or to 20 ppmv, whichever is less
stringent. If the flare TRE index were also above 1.0, or if the stream
contained halogenated compounds so a flare could not be used, then no
further controls would be required.
F.3 FLARE SYSTEM TRE DEVELOPMENT
This section presents the development of the flare TRE index equation,
verification of the equation, and an example calculation of the flare TRE
i ndex.
F.3.1 Development of the Flare TRE Index Equation
The flare TRE index equation was developed by selecting a general form
for the equation which contained the stream characteristics of flowrate,
heating value, and VOC emission rate as the independent variables, and the
TRE index as the dependent variable, and fitting this equation to TRE index
values calculated from the annualized cost equations. The form of the TRE
index equation for flaring had to be selected so that an accurate prediction
of the TRE index could be obtained for a given set of vent stream
characteristics. The form of the flare TRE index equation selected was the
same as the form used in the proposed standards for Distillation Operations
(50 FR 20446). An identical form of the TRE index equation was adopted for
the reactor standards from the distillation standards because the VOC
control costing procedures for the two standards are similar. The TRE index
equation was a good predictor of the TRE index for the distillation
standards. Therefore, it was expected that the same equation would also be
applicable for the reactor standards.
The general form of the equation is as follows:
TRE = _1_ [a(Qs) + b(Qs)°'8 + c(Q$)(HT) + d(ETQC) + e]
ETOC
where:
F-6
-------
TRE = total resource effectiveness index value
Q = vent stream flowrate (scm/min) at a standard temperature of
20°C
H, = vent stream net heating value (MJ/scm) where the net enthalpy
per mole of vent stream is based on combustion at 25°C and
760 mm Hg, but the standard temperature for determining the
volume corresponding to one mole is 20°C as in the definition
of Qs.
ElOC = hourly emission rate of total organic compounds reported in
kg/hr measured at full operating flowrate.
a, b, c, d, and e are coefficients.
The coefficients for the flare TRE index equation were developed with
the same regression analysis procedure that was used to develop the flare
TRE coefficients in the distillation standards. The regression analysis
procedure used is the General Linear Model (GLM) procedure of the
Statistical Analysis System Institute, Inc., Raleigh, North Carolina. The
development of the coefficients involved three steps: (1) formation of an
appropriate data base for the regression; (2) calculating a TRE index value
for each set of vent stream characteristics in the data base with the flare
costing procedure described in Chapter 8; and (3) using the GLM procedure to
regress TRE index values against the vent stream characteristics.
It was infeasible to use only the reactor processes Emissions Data
Profile (EDP) as the data base for the regression analysis because the EDP
is too small for the analysis that had to be performed. Therefore, the
distillation NSPS National Emissions Profile (NEP) was used as the
supplement to the reactor processes EDP for the purposes of the analysis.
Adding the distillation NEP was judged to be appropriate because of two
significant similarities with the reactor processes EDP: (1) the vent stream
characteristics represented in the two data bases are similar; and
(2) identical or similar synthetic organic chemicals are produced by both
reactor processes and distillation .operations.
After the data base was formed, the cost of controlling VOC emissions
using flares was calculated from the annualized cost equations for each
F-7
-------
facility with nonhalogenated vent streams in the EDP and NEP. These costs
were divided by the amount of VOC emissions reduced by flaring (i.e.,
98 weight-percent) to obtain a value for cost of control per megagram of VOC
reduced. Next, these values were divided by a TRE cutoff of $2,500/Mg to
obtain a TRE index value for each facility. The TRE index value and vent
stream characteristics for each facility were then input to the GLM
regression program.
Coefficients were developed for each term in the TRE equation using the
TRE index value as the dependent variable and the vent stream
characteristics as independent variables. The flare TRE coefficients are
shown in Table F-2. A set of coefficients was developed for each of two
cases: (1) combustion with a flare for vent streams with heating values
below 11.2 MJ/scm (300 Btu/scf), and (2) combustion with a flare for vent
streams with heating values at or above 11.2 MJ/scm (300 Btu/scf). The
first set of coefficients include the natural gas cost incurred by
facilities with vent stream heating values below 11.2 MJ/scm (300 Btu/scf).
For this type of stream, enriching with natural gas to reach 11.2 MJ/scm
(300 Btu/scf) is necessary to ensure a 98 weight-percent reduction
efficiency of VOC. No enriching is necessary for facilities with vent
stream heating values at or above 11.2 MJ/scm (300 Btu/scf). Therefore a
second set of TRE coefficients was developed for streams with heating values
at or above 11.2 MJ/scm.
F.3.2 Flare TRE Coefficients Verification
The flare TRE equation and coefficients were examined to ensure their
capability of accurately predicting the TRE index value for a facility from
the vent stream characteristics. The verification procedure for the flare
TRE coefficients involved several steps: (1) calculation of a TRE index
value using the newly derived TRE equation for each facility in the data
base; (2) calculation of a TRE index value using the flare cost algorithm
described in Chapter 8 for each facility in the data base; and .(3) comparison
of the TRE index values fcom (1) and (2) through the calculation of percent
difference. The verification procedure focused on those cases where the TRE
index value is around 1.0 because it is important to have the most accurate
F-8
-------
TABLE F-2. REACTOR PROCESSES NSPS TRE COEFFICIENTS FOR VENT STREAMS
CONTROLLED BY A FLARE
Flare b C d
HT < 11.2 MJ/scm 2.25 0.288 -0.193 -0.0051
F-9
2.08
Flare
HT> 11.2 MJ/scm 0.309 0.0619 -0.0043 -0.0034 2.08
-------
predictive capabilities in this critical region. The results of the
verification procedure are discussed below.
For vent streams with heating values at or above 11.2 MJ/scm, the
percent difference in TRE index values near the cutoff range from -0.49 to
3.39. Thus, it was concluded that the coefficients for this category of
vent streams provide good agreement with .the actual TRE index values.
Table F-3 presents a comparison of TRE indexes near the cutoff for vent
streams with heating values at or above 11.2 MJ/scm. The comparison is
between TRE index values calculated with the TRE equation and those
calculated using the cost algorithm for the same facility as described
above.
For vent streams with heating values below 11.2 MJ/scm there was poor
agreement initially between the algorithm and TRE equation. Therefore,
those data points resulting in very high TRE indexes were removed after the
initial verification procedure was performed because they caused the poor
agreement at TRE index values near the cutoff. After removal of those data
points, the TRE coefficients for vent stream heating values less than
11.2 MJ/scm were recalculated and the verification procedure was undertaken
again. The percentage difference in the recalculated TRE index values near
the cutoff ranged from 2.38 to -7.39. Thus, it was concluded that the
recalculated TRE coefficients for vent streams with heating values below
11.2 MJ/scm provided good agreement with the actual TRE index values.
Table F-4 presents a comparison of TRE indexes near the cutoff for vent
streams with heating values below 11.2 MJ/scm.
As a final verification step for vent streams with heating values below
11.2 MJ/scm, the recalculated TRE coefficients were used to determine a TRE
index value for those data points which were removed after the initial
verification procedure was performed. The percentage difference between the
TRE index values determined using the recalculated coefficients and the TRE
index values determined using the flare cost algorithm ranged from 2.29 to
-6.24. Thus, it was concluded that the coefficients enable accurate
estimation of even those facilities with high TRE index values. Table F-5
presents a comparison of TRE index values for those vent streams with high
TRE index values.
F-10
-------
TABLE F-3. TRE INDEX VALUES GENERATED USING TRE COEFFICIENTS AND THE FLARE COST
ALGORITHM NET HEATING VALUE GREATER THAN OR EQUAL TO 300 Btu/scf
Flowrate
(scf/min)
70.00
1.45
1.20
2.04
1.39
.20
0.30
6.60
Heat Content
(Btu/scf)
323.00
903.00
1024.00
1024.00
966.00
2778.00
4978.00
1286.00
VOC
(Ib/hr)
6.60
1.60
3.81
6.47
6.04
2.00
4.90
3.00
TRE INDEX
VALUE
Algorithm Coefficients
0.88
2.90
1.22
0.72
0.77
2.31
0.95
1.57
0.91
2.91
1.22
0.72
0.77
2.31
0.94
1.57
Percent
Difference
3.39
0.43
0.03
-.08
-.06
-.01
-.49
0.08
-------
_— — — — -
Flowrate
(scf/mln)
17.00
75.00
50.40
4.40
22.60
11.30
68.70
7.57
27.30 .
4.20
88.00
7.50
2.40
17.90
15.00
80.00
_ — • ——
Heat Content
(Btu/scf)
181.00
102.00
70.00
190.00
92.00
168.00
72.00
18.00
47.00
18.00
47.00
47.00
260.00
69.00
149.00
9.00
VOC
Ob/hr)
— .„ i . i— —
16.00
6.10
16.90
4.00
10.50
5.23
26.30
5.00
8.50
28.50
2.50
4.00
4.00
8.00
6.60
19.60
TRE INDEX
Algorithm
0.38
2.12
0,65
1.22
0.73
1.16
0.50
1.14
1.02
1.04
0.57
2.23
1.17
0.92
0.96
0.87
VALUES
Coefficients
Recalculated
.37
2.12
0.65
1.24
0.69
1.07
0.50
1.16
0.99
1.06
.58
2.28
1.18
0.87
0.91
0.86
, -^— -^— —
Percent Differences
fnmpared to Algorithm
Coefficients
Recalculated0
-2.23
- .10
0.00
1.84
-5.16
-7.39
0.21
2.06
-3.63
1.29
0.68
2.38
1.05
-5.71
-5.29
-1.53
•m
*-
.u-.
• .«>«..9 "'<« •«•«"• *• '« """'" ""' "" """ 3M """*'•
-------
TABLE F-5. PERCENT DIFFERENCES BETWEEN TRE INDEX VALUES GENERATED BY THE COST
ALGORITHM AND THE TRE EQUATION FOR VENT STREAMS WITH HEATING
VALUES LESS THAN 40 Btu/scf
Flowrate
(scf/im'n)
99.00
822.00
16.67
0.05
39.20
6.60
2.00
6.25
12.40
13.53
Heat Content
(Btu/scf)
0.00
0.00
4.00
36.00
4.00
8.00
0.00
9.00
0.00
0.00
VOC
Ob/hr)
0.10
0.10
.37
0.10
0.18
.60
.003
.40
0.14
0.03
TRE INDEX
VALUE
Algorithm Coefficients"
203
1325
21
46
61
9
1640
14
51
242
202
1290
20
46
60
9
1658
14
48
228
Percent
Difference
-.91
-2.65
-5.16
0.19
-2.28
2.24
1.14
2.29
-6.24
-5.96
Equation coefficients were developed after excluding vent streams with heating values
less than 40 Btu/scf.
-------
In summary, the flare TRE equations developed for this NSPS allow for
the calculation of TRE index values that are highly correlated with the TRE
index values obtained from the costing algorithm. The TRE equations do not
necessarily result in the best statistical fit between TRE values and vent
stream characteristics. This is because the primary concern in developing
the.equation and coefficients is to ensure very good agreement between the
TRE equation and cost algorithm for TRE's at or around the cutoff.
F.3.3 Example Calculation of a Flare-Based TRE Index Value for a Facility
This section presents an example calculation for the same vent stream
used in Section F.2.2. The vent stream characteristics are as follows:
1. Q$ « 284 scm/min
2. HT * 0.37 MJ/scm
3. ETQC =76.1 kg/hr
4. No halogenated compounds in vent stream.
Based on the stream heating value of 0.37 MJ/scm, the coefficients for
this stream are as follows:
a = 2.25
b = 0.288
c = -0.193
d = -0.0051
e = 2.08
Substituting these values into the general TRE index equation gives the
following result:
TRE * 0.013[2.25(284)+0.288<284)°*8-0.193(284)(0.37)-0.0051(76.l)+2.08]
TRE = 8.41
This index is above the cutoff of 1.0.' However, as previously shown in
Section F.2.2, the TRE index for an incinerator applied to this stream was
below 1.0. Therefore, this facility would be required to reduce VOC
emissions by 98 weight-percent or below 20 ppmv.
F-14
-------
APPENDIX G
FEDERAL REGISTER NOTICES OF ORGANIC
COMPOUNDS DETERMINED TO HAVE NEGLIGIBLE
PHOTOCHEMICAL REACTIVITY
-------
APPENDIX G: FEDERAL REGISTER NOTICES OF ORGANIC
COMPOUNDS DETERMINED TO HAVE NEGLIGIBLE
PHOTOCHEMICAL REACTIVITY
INTRODUCTION
As indicated by Federal Register notices included in this appendix, the
following chemicals have been determined to be negligibly photochemically
reactive compounds: methane; ethane; 1,1,1-trichloroethane; methylene
chloride, trichlorofluoromethane; dichlorodifluoromethane; chlorodifluoro-
methane; trifluoromethane; trichlorotrifluoroethane; dichlorotetrfluoro-
ethane; and chloropentafluoroethane.
G-l
-------
35314
NOT1CIS
ENVIRONMENTAL PROTECTION
AGENCY
l«U. 729-41
AM QUALITY
Recommended Policy on Control of- Volatile
Organic Compounds
Puwoss
The purpose of this notice to to rec-
ommend a policy for States to follow on
the control of volatile organic rnmpoiuuH
(VOC). which are a constituent in the
formation of photochemical ffrtrtantj
(smog). This notice doea not place any
requirements on States: State Implemen-
tation Plan (SIP) provisions which offer
reasonable alternatives to this policy will
be approvable. However, this policy will
be followed by EPA whenever it is re-
quired to draft State Implementation
Plan* tar the control of photochemical
oxidants.
BAOCG1OTTH9 '~
Photochemical oxidants result from
sunlight acting on volatile organic com-
pounds (VOC) and oxides of nitrogen.
8ome VOC. by their nature, start to form
oxidant after only a short period of ir-
radiation in the atmosphere. Other VOC
may undergo Irradiation for a longer
period before they yield measurable
. .to its guidance to states for. the prep-.
Afatlon* adoption* ip4 submltta! of State
^ftp Plans published in 1971*
the Environmental Protection Agency
ernTttiastTtil reduction of 'total organic
compound emissions, rather than sub-
stitution. (See 40 CPU Part "31. Appendix
BJ However, in Appendix B. EPA stated
ttat substitution of one coin pound for
amrthtr might bc.useful where it would
result in a clearly evident decrease la
reactivity and thus tend to reduce photo-
chemical oxidant formation. Subse-
quently. many State Implementation
Plans were promulgated with solvent
substitution provisions similar to Rule
M of the Los Angeles County Air Pollu-
tion Control District. These regulations
allowed exemption! for many organic
solvents which have now been shown
to generate significant photochemical
oxidant.
On January 29. 197«. EPA published
its "Policy Statement on Use of the Cen-
eept of Photochemical Reactivity of Or-
ganic Compounds in State Xmplementa-
. tton Plans for Oxidant Control." The
notice of availability of this document
appeared in the PEDOUL Ruana on
February 5. 197« (41 PR 9390) .
The 1976 policy statement emphasised
that the reactivity concept was useful
as an interim measure only, and would
not be considered a reduction In organic
emissions for purposes of estimating at-
tainment of the ambient air quality
standard for oxidants. The document
also Included the following statement:
Although; tn« ratatttutlaa portions of Rut*
M *M •tauter nut* npriMut e, worlusbl*
tad aowptabU program M rat of mat (law.
bitter eabttituooa ragulattoas eaa be de-
ivlopod, tux pa ettmat kaawtadci of it-
activity sad tedtutjui eapabffit*. ETA m
sailsfcjtaBoa witt auto tad industry nprt-
teanuita will formulate la l»7S aa lac
provM nil* for aatMaal urn.
SUMMARY -
Analysis of available data and Infor-
mation show that very few volatile or-
ganic compounds are of such low photo-
chemical reactivity that they can be
ignored in oxidant control programs.
For this reason. EPA's recommended
policy reiterates the need for positive
reduction techniques (such as the reduc-
tion of volatile organic compounds in
surface coatings, process changes, and
the use of control equipment) rather
than the substitution of compounds of
low (slow) reactivity in the place of
more highly (fast) reactive compounds.
There are three reasons for **\f Pint.
man? of the VOC that previously have
been-designated as having low reactivity
are now known to be moderately or
highly reactive In urban atmospheres.
Second, even compounds that are pres-
ently known to have low reactivity «an
form appreciable amounts of oxidant
under multiday stagnation conditions
such as occur during summer In many
areas. Third, some compounds of low
or negligible reactivity may have other
deleterious effects.
Of the small number of VOC which
'have only negligible photochemical re-
activity, several flnniitiie. "•fa>nHrtlt -
chloroform, carbon tetrachlortde. ethyl-
ene dlehlortde. ethylene dlbromide. and
methrlene chloride) have been identified
or implicated as being carcinogenic, mu-
tagenic. or teratogenlc. An additional
compound, benzaldehyde. while produc-
ing no appreciable ozone, nevertheless.
forms a strong eye Irritant under Irradia-
tion. In view of these circumstances, it
would be Inappropriate for EPA to en-
courage or support increased utilization
of these compounds. Therefore, they are
not recommended for exclusion from
control Only the four compounds listed
in Table 1 are recommended for exclu-
sion from SIP regulations and. therefore.
It Is not necessary that they be inven-
toried or controlled, to determining re-
ductions required to meet oxidant
NAAQS. these VOC should not be in-
eluded in the .base line nor should reduc-
tions in their emission be credited toward
achievement of the NAAQS,
• It la T>t~»l that the two halo-'
genated compounds listed in Table 1
(methyl chloroform and Freon 113) may
cause deterioration of the earth's ultra-
violet radiation shield since they are
nearly unresctlve In the lower atmos-
phere and all contain appreciable frac-*
Uons of chlorine. The Agency has
reached conclusions on the effects of only
the fully halogenated chlorofluoroal-
kanes. The Agency on May 13. 1977 (49
PR 24S42). proposed rules under the
Toxic Substances Control Act (TSCA) to
prohibit the nonessentlal use of fully
halogenated chlorofluoroalkanes as aero*
sol propellents. The restrictions were ap-
plied to all members of this class. In-
cluding Freon 113. since they an poten-
tial substitutes for Freon 1U Freon 12.
Freon 114. and Freon US, which are cur.
rently osed as aerosol propellents. The
Agency is planning to investigate control
systems and substitutes for nonpropei-
last •uses under TSCA. as annormced as
May 13. Methyl chloroform is not a fuur
halogenated chlorofluoroalkane. Rather
If !• among the chlorine-containing com-
pounds for which the Agency has not
completed its analysis: EPA has not ret
concluded whether it is or is not a threat
to the stratospheric ozone. Therefore it
has been placed on this list as an accept-
able exempt compound. AS new informa-
tion becomes available on these com-
pounds. EPA will reconsider the recom-
mendation.
The volatile organic compounds listed
in Table 2. while more photoche-.;:^.
reactive than, those in Table 1. never-
theless do not contribute large quantities
of oxidant under many atmospheric coc-
draone.
TABU L—VoUMK Organic. Compound, at
MgMfAte fhataehtmtemt JUaetntcy nut
«t»«l* *• Cxmpt from. JUftilatlon Under
fla.ru
UJ-TMcalorottaaat. (Mttbrl Chloroforms
U3)>
«ompoua&i at.** b*ta
es taring •fftca
> tad. taentor*. m»r oo
to fa.
•—./
Tiatx «*—VoIMite Orftnie Compcuttft
Uothvl Ethvl K*toa«
Uotbiaol '-•
Inpropiaoi
Uetltyl
Ttrturr Alfcyl AleoboU
UttbvlAeetato ..
Fhcavl Aaotot*
"
Aottyltao
W. TT rttnwthjl formcoutf*
Only during multiday stagnations dc
Table 2 VOC yield significant oxidants,
Therefore, if resources are limited or if
the sources are located in areas when
prolonged atmospheric stagnations ire
•uncommon, priority should be given to
controlling more reactive VOC flnt snd
Table 2 organlcs later. Table 2 VOC are
to be included in base line emission in-
ventories and reductions in them wul be
credited toward achievement of the
NAAQS. Reasonably available control
technology should be applied to signifi-
cant sources of Table 2 VOC where neces-
sary to attain the NAAQS for oxldaati.
New sources of these compounds will also'
be subject to new source renew require-
ment!. • ~{
Perchloroethvlene. the principal soU
vent employed in the dry cleaning indus-
try. is also of low reactivity, comparable
to VOC listed in Table 2. It was not ta-
cluded in Table 2 because of reported ad-
verse health effects. Uses, environmental
distribution, and effects of percblorov
ethylene currently are being studied is*
tensively by occupational health author*
ethylene currently are being studied in-
vestigations nay have major impact. on
MOISTH. VOl. 42. NO. 13»—-MIOAT. JULY I. \977
6-2
3s XV- .
-------
industrial UMR. IB designing control reg-
ulations for perchloroethyiene sources.
particularly dry cleaners. consideration
should be iirtn to these *»«MT» as wtll
as industry rtqulmmnu tad the cost of
applying contrail. Available control tech-
noiocy u highly cost effective for large
perehloroethylene dry eleanlnr opere-
tioaa. However. for corn-operated sad
mull dry cleaners, the same equipment
would represent a heavy -economic
burden.
As part of Its continuing program. EPA .
will renew new information relative to
me photochemical reactivity. tozlcity..or
•Sects oa stratospheric ozone of volatile
organic compounds. Where appropriate.
additions or deletions will be made to the
Usts of VOC la Tabels 1 and 2.
Moit air pollution control regulations
applicable to stationary sources of VOC
to tbe United states are patterned after
Bole «* of the LOB Angela* County Air
Fonntton Control District (pHsesUr
Heffnlatlon 443 of 1be> Southern Calif or-
oia Air Pollution Control District) . Role
M and similar regulations incorporate
two basic strategies to reduce ambient
oxldaat levels. T.e, positive VOC reduc-
tion and sctactrvw solvent sobatitutloa
baeed on pbotoebendeal reactivity'. Poal-
ttvej cejdactlc& echcBMe such ae iacl&efa-
tton. absorption. and the use of tow-sol-
vent coatings are acknowledsed means of
reducing ambient oxidant levels;
abould be retained IB future VOC control
programs, in confrast. the utility of sol-
vent substitution strategies has been
questioned as more information on pho-
to chemical raaettvtty has emerged.
EPA acknowledged the chorteomlage
of solvent substltuUon based oa Rule M
reactivity criteria to a 1978 policy state-
ment (41 FR 5350). Findings were cited
which indicated that almost an VOC
eventually react in the atmosphere to
form some oxldaat Concurrently,. EPA
initiated an InveetigaUon to consider Im-
plications of revising the advent cubsti-
twton aspects of Rule 66. Three separate
forme were conducted with represent!
trvee of state and local air pollution
ouutrol agencies* university professors*
and industrial reprecentattvea with
knowledge and expertise to the fields of
wxenoapherte chemutry and industrial
ewlvent applications. In addition, nu-
were held vita
knowledged experts in the field. Toplee
of particular eoncem were:
Whotfcoc Mulo ee •ubttltuttea entorla
eauM be revised eoosuteat win available
rtmeumr date tad yet b» conptabU wttft
nx»u»trui precuies tad wttft product re-
euiremeau.
Whctiur com* compound* ue or tufl-
.' low reactivity taat taer-ii* aet osl-
•aa* precutwan aad eea b* exempted rrom
•oatroi uader State Zmplemeataaea Pltai.
^Vrhetav tft» '*>f/*-**tffn of teectlftty t%-
««eeon» m tddltioa to poem*e
-------
3S316
NOTICIS
•pread substitution of methyl chloroform
(1.1.1 trlchloroethane) for the photo*
rhemieaUy reactive degreaaing aolTaat
trlchloroethylene. Socb substitution un-
der Hula 68 generation regulation* baa
already influenced industrial degreasing
operations to the extent that methyl
chloroform production baa surpaaMd
that of trlchloroethylene in the United
States. Any regulation In the ana will
hare a marked effect on the production
and atmospheric emissions of both sol-
vents. Endorsing methyl chloroform sub-
stitution would Increase emissions, par-
ticularly In Industrial States that have
not. heretofore, implemented Rule M. On
the other hand, disallowing methyl chlo-
roform as a substitute or banning it alto-
gether would significantly Increase amis-'
dons of trlchloroethylene even If de-
greasers were controlled to the limits of
available technology. Presently, tech-
nology Is only able to reduce emissions by
approximately SO percent In "metropoli-
tan areas which have already Imple-
mented Rule 66. a return to trtchloro-
ethylane would have an advene effect
-^n ambient oxtdent levelc. ID addition to
.-being highly reactive, trtehloroethyleno
rhaa bean Implicated as a carcinogen.
, Alternatives to the above-cited choices
rwoold be (1)-development and appllca-
-tlon ot highly efficient digiesiir control
;jystems and (1) replacement with an
Intermediate solvent which Is neither re-
active nor detrimental, to the upper aw
mosphere. Major revisions would be
needed to degreaser designs to Improve
vapor capture above the current best
level. Anticipated design changes could
add materially to degreaser costs. No. al-
ternative solvent Is clearly acceptable
from the standpoints of photochemical
oxidant and stratospheric ozone deple-
tion. Neither methylene chloride nor
trichlorotrtfluoroethane are reactive, but.
like methyl chloroform, are suspected of
causing damage to the stratospheric
oaone layer. In addition, methylene chlo-
ride 4s a suspect mutagen. Perchloro-
etbylcne. the principal dry cleaning sol-
vent, does'not present a hazard to the
stratosphere but has been implicated as
being a carcinogen and also reacts slowly
m the atmosphere to form oxidant.
7.- Organic solvents of low or negligible
photochemical.- reactivity have only
limited use In many industries. Most are
chlorinated organic* that find principal
applications as cleaners for metals and
fabrics. A few nonhalogenated VOC such
aa acetone, methyl ethyl ketone. ead
isopropanol an of low reactivity but
these, can't possibly satisfy afl the myriad
needs of the paint, plastics, pharmaeeu-
ttcal. or many other industries.. While
users of reactive VOC usually can employ
• effective control equipment to recover or
destroy VOC emissions, they seldom have
the option of applying reactivity eon-
afderations In choosing solvents. Applying
reactivity restrictions to the surface coet--
tng industry would be especially disad-
vantageous since it would greatly Inhibit
the development of low-solvent coatmgs:
essentially all of the organic solvents
used to constitute high-solids coatings
and water-borne coatings are. in fact,
highly reactive.
8. It Is recognized that smog chamber
studies conducted to date are incomplete
because many organic compounds ha\e
not been examined and it has been im-
possible to duplicate all atmospheric sit-.
uattons. For example, there has bate.
only Umlted examination of oxidant for**'
mation under relatively high ratios of
VOC to NO, (30:1 and greater). compar-
able to rural conditions. Any policy on
.photochemical reactivity necessarily .-.is
to be open to revision as new information
la developed which may show specific
nrwanlft compounds to be more or less
pnotoehemlcally. reactive than indicated
by current data. •
Deted^ June ». 1*77.
'ABB F. TUBBK.
t Administrator
i
-------
32042
Federal RatUtet / Vol 44. No. 1M / Monday. June 4. 1979 I Notices
lUvitw under 42 U.S.C | 7l9(b) (1977
Supp.) from HI order of the Secretary of
Energy.
Copiee of the petition lor review have
been served on the Secretary.
Department of Energy, tad all
participants in prior proceedings before
the Secretary.
Any person desiring to be heard with
reference to such filing should on or
before }une 12.1979. file a petition to
intervene with the Federal Energy
Regulatory Commission. 825 North
Capitol Street N£_ Washington. D.C
20O8. in accordance with the
Commission's rules of practice and
procedure (18 CFR 1.8]. Any person
wishing to become a party or to
participate as a party must file a petition
to intervene. Such petition moat also be
served on the parties of record in this
proceeding and the Secretary of Energy
through Caynell C Methvia. Deputy
General Counsel for Enforcement and
Litigation. Department of Energy. 12th
and Pennsylvania Ave, N.W.
Washington. D.C 20461. Copie* of the-
petition for review are on file with the
Commission and are available for public
Inspection at Room lOOa 823 North '
. Capitol SUN.E, Washington, D.C
20428.
r.
[Deeket No. arrVM)
TrNon CM Corpu; PcMton for
and S98-A or show cause why such
refunds were not due. Triton's position
la that because sales under these rate
schedules were authorized by
permanent certificates of public
convenience and necessity which
contained no refund conditions, there is
no refund obligation. Triton
acknowledges that the Commission may
order refunds and reductions in rates
after August 1.1971—the effective date
of Opinion No. 598. However, it asserts
that the Commission is without
authority to order such adjustments
- prior to the effective date where races
were not collected subject to a
suspension order or under a temporary
certificate.
Any person desiring to be heard or to
make any protest with reference to said
petition should file a petition to
intervene or a protest with the Federal
Energy Regulatory Commission. 825
North Capitol Street. N.E. Washington.
D.C 20428. in accordance with
requirements of the Commiaaioa's rules
of practice and procedure (18 CPJL14
or 1.10). All such petitions or protests
should be filed on or before luneJO.
1879. AH protests filed with the
Commit*"?" will be considered by it la
determining the appropriate action to be
taken but will not serve to make the
protestants parties to the proceeding.
Any person wishing to become a party
to a proceeding, or to participate as a
party in any hearing therein, must file a
petition to intervene in accordance with
tfa Commission's rules.
MayJBitvm. -
Take notice that on April 5.1979. . •
TritosrOa and Gee Corporation (Triton).
One Energy Soaare. 492S Greenville
Avenue. Dallas. Texae 75208 filed m
Docket No. R»»-36 a petition for
declaratory eider pursuant to Section X7-
of th* Comaaaeioa's Raise of Practice,
•aad Praoedare»Tritoa i
thailthaei
Area Rate Opmtoa No. 599 far rates it.
oaUected for certain sake of gae. The
^ss»« 4W afc^Mhdlw^Mdl taMtJSH ffV^^M <|^t-I— |A aaV^
(•• IP praOUCBQ DOB UNaT DMaaW IB UM
Sootfaen Louisiana Area and sold to
Teaaeesee Gee Pipeline Company.
Southern Nataral Gas Compeay
Triton's Rat* Schedules Lead 8.8, aad 7
Oa f«ae 8.1978. the Commission
directed Triton, amonf other produ
a» diebune rereads for the period from
October 1888 to January 1971 pursuant
to the Commisstoi's Opinion Noa. 598
CDooketi»>a»7»4ai
Unrted Qaa Ptoa Una Co* Informal
140 PA. anv
that oa Juae 7.
I paraoae wiu be caavaaod far
the-purpose of continued settlement
dtacaeaioaa ia tUa prcceodiagvTaa
conference wiB be held in Room 3300 of
the Federal Energy Regulatory
Commission at 941 Norm Capttot Street
RE. Washington. D.C 20428.
Customers and other iatereelad
peraons wifl be permitted to attend, bat
if such persons have not previously been
permitted to Intervene by order of the
Commission, attendance wfll not be
deemed to authorize Intervention aa a
party In this proceeding.
All parties will be expected to come
fully prepared to discuss the merits of
the issues arising in this proceeding and
to make commitments with respect to
such issues and any offers of settlement
or stipulation discussed et the
conference.
Acting ^ternary.
Office of Energy Conservation and
SoUr AppUcattona
Meeting Regarding Emergency
Buildtna. Temperature Reetrtctiona
Program
Notice is hereby given thai the
Department of Energy (DOE) will hold s
meeting with the National Governon'
Association on Friday. June 8.1979 st it
a.m. in Room 285.444 North Capitol
Street. Washington. D.C
The purpose irf the meeting will be to
discuss the role of the States in
implementing the Emergency Building
Temperatin Restrictions Program. This
aroaraai ia eathorized by taa Presidents
"Standby Conservation Plea No. 2:
Emergency Building Temperature
Restrictions." which recently was
approved by taa Congress.
Issued la Washmgtea. D.C oa May n.
1979.
. Caauinutioa
iNVmONKENTAL PROTECTION
AGENCY
Air Oua§ry.Cs»ilHcallo«i of Agency
Mtay Caneanang Ozon* S»
liapuaaabadi
the anthortty of section 101(b) and
eacbom 101 of the dean Air. Act The
notice clarifies EPA's Itaoommeaded
Policy oa Control of Volatile Organic
" *• ' 42 FR 35314 Quly «. 198T).
The Jury 1977 Policy
Statement noted that only reectfve
volatile orgaak compounds participate
m the chemical reactions that form
photochemical ondaata. Currendy
available information suggests that
negligibly paotochemicaUy tnctive
volatile organic compounds aa defined
in that Statement. Including methyl
P.-5
-------
Federal Register / Vol. 44. No. 108 / Monday. June 4. 1979 / Notices
32043
chloroform and methylene chloride, do
not appreciably affect ambient otone
levels. Hence. EPA will not disapprove
any state implementation plan or plan
revision for its failure to contain
regulations restricting emissions of these
compounds.
Although these substances need not
be controlled under state
implementation plans for the purpose of
achieving ambient osone standards,
nothing in this memorandum is intended
to modify past EPA expressions of
concern shout the uncontrolled use of
methyl chloroform and methylene
chloridt. As noted in tht above
referenced policy and the clarification
presented in memoranda of August 24.
1978 and March 8.1979. there is
suggestive evidence that both
compounds are potentially carcinogenic
and methyl chloroform ia suspected of
contributing to depletion of
stratospheric osone. See. for example.
the following studies:
Simmon. V. F. Kauhanen. K. and
TardifL R. G. "Mutagenic Activity of
Chemicals Identified in Drinking Water"
m Prognu in Genetic Toxicology, ed. L
D.Scott a A. Bridges, and F.RSobels,
at 249-258 (Elsevier. 1977);
Price. P. G.. Hassett C M. and
Mansfield. O. L. "Transforming
Activities of Trichloroethylena and
Proposed Industrial Alternatives" ta
Vitro 144, at 290-293 (1978):
Theiss. I. C, Stoner. G. D. Shimldn. M.
B, at a/. Test tor Caidnogenicity of
Organic Contaminants of United States
Drinking Waters by Pulmonary Tumor
Response m Strain A Mice." Cancer
AeseareA, 37(8 Pt 1): 2717-20. (August
1077X
The EPA Caremogen Assessment
Croup's Preliminary Risk Assessment on
Methyl Chloroform. Type I—Air
Program, (January 17.1979):
Tbe EPA Caremogen Assessment -
Croup's Preliminary Risk A ssesamant on
Methyiene Chloride. Type Ir-Air ---,-
' nrir.1979): ""
i Methyl
these compounds under the Clean Air
Act
POM «mTM«H INFOMMATION CONTACT:
Joseph Padgett Director. Strategies and
Air Standards Division. Office of Air
Quality. Planning and Standards. MD-12
Research Triangle Park. North Carolina.
27711 (919) 541-5204.
Dated: May 23.1979.
OavU C. HawUoa.
Auiitant Administrator for Air. Noitt and
Radiation.
ftagton Ife Oroundwtttr Syattm of th«
Now Jortoy Coastal PlsjJns AquHar
On March 21. 1979. a notice was
published stating that a petition has
bean submitted by the Environmental
Defense Fund. Inc. and the Sierra Quo-
New Jersey Chapter, pursuant to Section
1424(t) of the Safe Drinking Water Act
Pub. L. 93-823. requesting the
Administrator of the Environmental
Protection Agency to make a
determination that the aquifer
underlying the Counties of Monmouth.
Burlington, Ocean. Camdtn. Gloucester.
Atlantic, SalasL Cumberland and Cape
May and portions of Mercer and
Middlesex Counties. Ntw feney is the
solt or principal drinking water source
far tba coastal plain area which, if
omitamtnatad. would create a
laboratory. U3. EPA, February 27-_
»».• Weatangton. D.C (procMdings) ta
both methyl chloroform tad
chloridt in pottntftOy
BPA recommends that that*
• •- not bt tobatftattd tor other
•oitwts ta aflbrta to reduce otnn* »
~ »ttont,EPAftBthtr
i that the states control
I unhem to section lie of the
i Air Act Moreover, there Is a
I possibility for future regulation of
d to, pvblic health.
Tbs-nottca) indicated that comments.
data aadrefarencas in response to the
petition ahtsdd bt submitted by May 21.
1979. Dw torn* complexity of issues
wUcnswrooodtfa* designation of the -
Coavtal PteiB Area at a sote source
•qtJfar. KPA ww reque«ted to extend
parted. In order to permit
_e for all interested ' :- .
to provide their input KPA :
--- . ., , iDasT OOBffiasVt paKiOtt QB tUft *
ptttllOBrtqBest&omMay21.1979to .
AisjHt A ISfftJL Comments, data and
nteaaett ta response to the Coastal
Plain Petition taoold be tubmitted in •
wrltinftoEdtardtCB«±.!UtJonal
Administrator. Region Ft Environmental
Protection Agtaey. 28 Federal Plaa.
Room 1009, Ntw York. N.Y. 10007.
Attention: Coastal Plain Aquifer. --
Information conctmlng tht Coastal
Plain Aquifer System wiH bt available
for inspection at tht above address.
Deled; May 21. 1979.
•ckairftCBeck.
Rtfional Adminiitrator.
SNJJM MH M*»>S1^
IPfU. 1239-3 OM-000951
Statt-PIFRA Issues Research and
Evaluation Group (SFIREG); Working
CommiRot on Enforcement Open
Hotting .
AOIMCYT Environmental Protection
Agency (EPA). Office of Pesticide
ACTioic Notice of Open Meeting. _
•UMMANV: There will bt a two-day
meeting of the Working Committee on
Enforcement of the Stete-FIFRA Issues
Research and Evaluation Group
(SFREC) on Tuesday and Wednesday.
June 5-8. 1979. beginning at 8:30 a.nv
each day. and concluding by 12 noon on
June 8th. Tat meeting will be held at the
Atlanta Town House. 100 Tenth Street
N.W, Atlanta. Georgia. Telephone: 404/
892-4800. and will be open to the public
MS) WKTMCH IMPCMMATIOM CONTACT:
Mr. William Buffalo*, North Carolina
Department of Agriculture. Raleigh.
North Carolina. Telephone: 919/733-
3558: or Mr. Anthony Deilavecdua,
Pesticide and Toxic Substances
Enforcement Division. EPA. 401 M
Street S.W, Washington. D.C.
telephone: 202/755-0914.
IIUM. This the
second meeting of the Working
Committee oa Enforcement. The meeting
wUl bt concerned with the following
1. Plan for forore recall and
suspension orderB
. 2. aerification of undefined terms ia
Section 28 and 27 of FIFRA;
•;*, Status of State-primacy use
*.Useof
ofrioaltaral
itionaof
publics not
by
•peatiddt sales representatives;
- 5. Discussion of definition of-^on
crop land:"
8. FffRA Section 7-oroducen of
active ingredienta; and
7. Other enforcement matters which
may arise. <• •
Dated; May a WB.
•MaLleeaeee. .
flaewjr yUurtont Admiaatrator foe fntieidt
G-6
-------
82*24
Fadaral KatUtat / VcV4S. No" V /Friday: May'ie. 1980 / Notices
Included within the definition of .,
nontarget sites an anas of permanent •
human habitation Indmting permanent
residences, schools, churches, aad anas
in which substantial commercial
activities an conducted (04. shopping
centers), domestic apiaries, and .
publicly-maintained roads, m addition.
aquatic habitats such aa critical
fisheries, municipal water supply - ••
Intakes and other waters (which Include
rivers, steams, ponds, lakes, and
ephemeral steams and ponds with
Sowing or standing water visible from
an aircraft flying at an altitude of 1.000
feet above the terrain at the time of
treatment}, an included within the
definition of a sensitive ana. The
nlease of any pesticide spray is not
permitted over a sensitive ana or in the
surrounding buffer zone. Buffer zones
an defined as anas intended to receive
only spray drift fallout from the
application sites.
The Agency recognizes the! some
seasonal dwellings, such ss hunting and
fishing camps, may be located in or
adjacent to the treatment ana. These
dwellings an not considered to be
permanent residences and thus will not
be buffered against direct application.
However, many of ness dwellings an
near aquatic sites listed in Table 0
which will be buffered.
To minimize operational errors.
overflights of the treatment ana prior to
the actual spray operation are
encouraged. The purpose of these
overflights is to locate visually all
sensitive areas and buffer zones
designated on the spray block maps.
Particular attention should be given to
identifying ephemeral steams and
ponds visible from an aircraft flying at
an altitude of 1000 feet or less above the
terrain at the time of treatment, which
may not be designated on the spray
block map due to their seasonably.
Authority
This Advisory Opinion governing the
use of certain insecticides for the
. suppression of the spruce budworm in
Maine through July. 19*0, Is issued
pursuant to the authority granted to the
Administrator by Section 2(ee) of
FIFRA. 7 U.S.C 136(ee) (Supp. 1979).
Section 12(a)(2)(C] of FIFRA makes it
unlawful for any person "to use any
registered pesticide in a manner
inconsistent with its labeling." Section
2(ee) defines this terminology as
prohibiting the use of registered
pesticide "la a mannentot permitted by
the labeling." However, section 2(ee)
also provides that this prohibition does
not apply with respect to "any use of a
pesticide la a manner that the
Administrator determines to be
consistent with the purposes of this
Act"
Effective Date: This Hottce I* effective
DetedtMaySiUBa
itevee, P. !•«••«•
Anutant Administrator for Pttticidw end
"
(FHL 14*3-7]
Air Quality; Clarification of Agency"
PoOcy Concemlno; Ozone SIP
Revtalona and Solvent Reactivities
•AcxanowNo: This notice Is published
under the authority of 1101(b) and 1103
of the Clean Air Act The notice
provides further clarification of a policy
announced in EPA's "Recommended
Policy on the Control of Volatile Organic
Compounds.- 42 FR 35314 (July e. 1977)
and "Clarification of Agency Policy
Concerning Ozone SIP Revisions and
Solvent Reactivities." 44 FR 32042 (June
4,1979).
otacuasJOK The previous policy
statements on the control of volatile
organic compounds (VOCs) noted that
methyl chloroform and methylene'
chloride an negligibly photochemicaHy
reactive and do not appreciably
contribute to the formation of ozone.
Consequently, controls on emissions of
these two compound would not
contribute to the attainment and
maintenance of the national ambient air
quality standards for ozone. In the June
1979 policy statement EPA explained
that it would not disapprove any state
implementation plan (SIP) or plan
revision for its failun to contain
regulations restricting emissions of
methyl chloroform end/or methylene
chloride.
Today's statement clarifies EPA
policy regarding state implementation
plan t^h"*IMslt which do contain
regulations restricting emissions of the
two compounds. Section 110(a)(l) of the
dean Air Act limits state
implementation plans to measuns
designed to achieve and maintain the
national ambient air quality standards
(NAAQS]. Because currant information
indicates that emissions of methyl
chloroform and methylene chloride do
not appreciably affect ambient ozone •
levela. EPA cannot approve measures
specifically controlling emissions of
• either orb
federally
a/o
lie os
i aa part of a
me SIP. EPA
EPA approval If a state chooses to
control emissions of these compounds.
such measons will be considered as
state regulations only and not as part of
an ozone SIP. EPA will not enforce
controls on emissions of either methyl
chloroform or methylene chloride
adopted by the state as part of an
Implementation plan for ozone.
Statea ntain authority to control
emissions of these compounds under the
authority nserved to them under
Section 116 of the Clean Air Act. For
further information nlevant to the
exercise of this authority see the July 8.
1977 and June 4.1979 policy statements.
This policy notice should not be read as
a statement of EPA's views on the
desirability of controls on these
substances.
Finally. EPA wishes to point out that
this policy notice addresses only the
Agency's lack of authority to include in
federally approved SFPs controls on
substances whose emissions do not
contribute, either directly or indirectly.
to concentration's of pollutants for which
NAAQS have been established under
section 109 of the Act This policy notice
does not address the question of SIP
measuns-which control substances
contributing to concentrations of
pollutants for which NAAQS have been
established, but which an contended to
be mon strict than absolutely necessary
to attain and maintain the NAAQS. EPA
has no authority to exclude such
measuns from SIP*.
•on niimtta INFORMATION CONTACT
C. T. Helms. Chief. Control Programs
Operations Branch (MD-1S). Research
Triangle Park. North Carolina 27711.
(919) 541-5228. FTS 629-5228.
DatediMaylltaa.
David G. HawUas.
AstittantAdoiinittrotorforAjr. Noitt and
Radiation.
(PR On. CKIIIM flM VIM* *tt Ml
will take no action on any
specifically controlling emissions of the
two compounds which are submitted by
the states aa ozone SIP measuns for
[HU.1491-7; fP M1M7/T239]
Extension of a Temporary Tolerance
AOINCY: Environmental Protection
Agency (EPA).
Acne»e Notice.
auMMAflv: EPA has extended the
temporary tolerance for residues of the
herbicide thidiazuran (AA.phenykV-l.i3-
thiadiazol-S-yhina) and its aniline-
containing metabolites in or on the raw
agricultural commodities cottonseed at
O2 part per million (ppm). milk 0.05 ppm.
eggs 0.1 ppm. meat fat and meat
byproducts of cattle, goats, hogs, horse*.
poultry, and sheep at OJ ppm.
G-7
-------
Federal Register / Vol. 45. No. 142 / Tuesday. July 22. 1980 / Notices
48941
Dcmpasco Service Sta. U.S. 1 and Hwy A1A.
Juno Beach. FL 33406—4-14-80
Par Mobd. 324 Par Avenue. Orlando. FL
32804—3-16-eO
)ohn Gibson. l-« and ICY 90, Cave City. KY
42127—3-18-80
Bellmcadt ShelL $313 S. Harding. Nashville.
TMITTM 1 H KB
Comer Stem. 1401 No. Main Street
Kissimme*. FL 32741—3-19-W
Kopper Kettle. Highway tOO * MS. Franklin.
KY 42134—4-7-80
Buechet Terrace Chevron. 4219 Bardstown
Rd- Louisville. KY 40218—1-10-80
UPort* Exxon. 1029 S. Federal Hwy.
Hollywood. FL 13020 I 24-80
Rimer's Chevron. 3420 Lebanon Road.
Hermit***. TN 37076—6-13-80
Douglas Amoco Service. S83 Donaldson Pike.
Nashville. TN 37214—<-14-«0
Town * River Texaco. 1024 CyprtM Lake*
Rd. Ft Meyer*. FL 33907—5-14-80
Trail Sunoco. «tt So. Tamuniami. Ft Meyer*.
a 33S07—4-14-80
VUlai Chervron, MM So. Tamamiami, Ft
Meyer*. FL 33907-4-14-80
Port Comfort Bm 106. Rt 24. Ft Meyer*. FL
CantniTa Exxon. 1910 Dickenon Rd.
NeabviUe. TN 37207—9-16-80
Barker Westgate Standard. 2S10 Pto Nono
Ave. Macon, CA 31206—6-19-60
Seminol* Exxon, 1949 W. Tean. Tallahassee.
FL 32304—4-19-80
ftedrtoaey'sO^vron. SOU RomeUar Road.
Macao. CA 31204—1-20-80
Winston Chevron. 62S Madiaon Street
HunttYille. AL 35501—4-22-80
H • A Fuel Service. P.O. Box 440. Hardevffl*.
Chancy* Standard. P.O. Box 1706. St Simon*
bland CASlS23-*-28-«
Norman'» Standard. 3304 Clynn Avenue,
Brunswick. CA 31520—3-28-80
Plaz* Standard. 198S Clynn Avenue.
Brunswick. CA 31320—4-28-80
Col«y'» Exxon, Rt 1 MS and SC 290. Duncan.
SC?B114 1 'fl HO
BinghanV* Texaco. Rl 1J-8S and SC 290.
Duncan. SC 29334 S 26 80
White's Exxon. Hwy M8 and SC-9.
£|l«ll»ilbui|, 3C IJTOl B TH 6H
Mauldin Chevron. 804 N. Main. MauWin.SC
Wade Hampton Mall Exxon. 1035 Wad*
Hampton Blvd. Greenville. SC 29609-5-
29-80
Ham* Standard. P.O. Box 406. Nahunta. CA
31533—5-29-80
Putman's Standard. 1-73 and Juliette Rd.
Forsyth. CA 31029-5-30-*)
Trout's Texaco. 106 N A1 A Hwy. SateUit*
Beach. FL 32937—5-30-60
Magnolia Plantation. P.O. Drawer. Tifton, CA
31794 5'30 60
M • M 76.1100 SR 5:4 Rt 1. Cocoa. FL
-5-JO-80
Issued in Atlanta. Georgia on the llth day
of July 1980.
lemwCEasterday,
Dittrict Manager.
Concurrence:
Leonard F. BittBW.
ChiifEnforctaitot Count*!.
in Ow SCHISM nM r-n-*> *:« ml
•UJMO coot in* ••>•*
ENVUIONMENTAI. PROTECTION
AGENCY
[PIU. 1946-7]
Air Quality; CtarfflcaUon of Agency
PoNey Concerning Oione SIP
Reviaiora and Solvent ReactivWe*
AOfNCr: Enviranmentai Protection
Agency (EPA).
ACTIOM: Notice.
•ACXONOUNO: This notice U published
under the authority of section I01(b) end
section 103 of the Cleen Air Act The
notice provides further clarification of a
policy announced in EPA's
"Recommended Policy on the Control of
Volatile Organic Compounds." 42 FR
35314 (July 8.1977) and "Clarification of
Agency Policy Concerning Ozone SIP
Revisions and Solvent Reactivities." 44
FR 32042 (June 4,1979) and 45 FR 32424
(May 16.1980).
DMCUMICHC The previous policy
statements on the control of volatile
organic compound* (VOCs) noted that
despite concerns about their potential
toxicity LLl-trichloroethane (methyl
chloroform) and methylene chloride are
negligibly photochemically reactive and
do not appreciably contribute to the
formation of ozone. Today's statement
expands the list (45 FR 32424) of organic
compounds (VOCs) of negligible
photochemical reactivity to include the
following chlorofluoracarbons (CFC) or
fluorocarbons (FC):
trichlorofluoromethane (CFC-11):
dicUorodifluoromethane (CFC-12):
chlorodifluoromathane (CFC-22);
trifluoromethane (FC-23):
trichlontrifluoroethane (CFC-113):
dichloratetrafluoroethane (CFC-U4);
and chloropcntafluoroethane (CFC-115).
EPA has determined that these
halogenated compounds are no more
photochemically reactive than methyl
chloroform and methylene chloride and
do not appreciably contribute to the
formation of ambient ozone.
Consequently, controls on emissions of
these compounds would not contribute
to the attainment and maintenance of
the national ambient air quality
standards for ozone. EPA cannot
approve or enforce controls on these
compounds as part of a Federally
enforceable ozone State Implementation
Plan (SIP). EPA will take no action on
any measures specifically controlling
emissions of these compounds which
are submitted by the States as ozone SIP
measures for EPA approval. (See 45 FR
32424.)
However. EPA would like to reiterate
its continuing concern over the possible
environmental effects from emissions of
these compounds. As such. EPA n not
precluding the possible future regulation
of these compounds.
It should be recognized that the two
halogenated compounds, methyl
chloroform and CFC-113. stated to be of
negligible photochemical reactivity in
the July 8,1977 Federal Register, have
been implicated in the depletion of the
stratospheric ozone layer. This layer is a
region of the upper atmosphere which
shields the earth from harmful
wavelengths of ultraviolet radiation that
increase the risk of skin cancer in
humans.
la response to this concern, the
Agency promulgated on March 17.1978
(43 FR 11318). rules under the Toxic
Substances Control Act (TSCA) to
prohibit the nonessential use of fully
halogenated chlorofluoroalkanes as
aerosol propellents. Restrictions were
applied to all member* of this class.
including CFC-113. since they are
potential nbstitutes for CFC-11. CFC-
12. CFC-114. end CFC-115. which are
currently usud as aerosol propellents.
The Agency •' investigating control
options and • bstitutes for
nonpropell*. -see.
EPA ha* pn ~3**d new source
performance '.andards under Section
111 for organic solvent cleaners (45 FR
39766. June 11.1980). These proposed
standards would limit emissions of the
reactive volatile organic compounds
trichloroethylene and perchloroethylene
as well as methyl chloroform, methylene
chloride, and trichlorotnfluoroethane
(CFC-113) from new. modified, or ,
reconstructed organic solvent
degreasers. If these standards are
promulgated. EPA will develop e
guideline document for States to us* in
developing regulations required under
Section.lll(d) for existing organic
solvent cleaners thet use eny of the
designated compounds.
Whether, and to what extent, methyl
chloroform and methylene chloride are
human carcinogen* or have other toxic
effects, and to what extent methyl
chloroform. CFC-113. and other CFCs
depletp the ozone layer, are issues of
considerable debate. Detailed health
assessments of methyl chloroform.
methylene chloride, and CFC-113 are
being prepared by EPA's Office of
G-8
-------
48942
Federal Register / Vol. 48. No. 142 / Tuesday, fuly 22. 1980 / Notices
Research and DtvtlopnunL This*
assessments will b« submitted for
external review, including • nyitw by
thi Scicnca Adviiory Board, prior to
promulgation of tht regulations and tha
propoaal of EPA guidanca to Slates for
davaloping existing sourca control
maaaurts. Tha axtant to which tha
pralinunary findings ara affirmed by tha
rtviaw pracata may affect tha final
rulamaking for naw aa wall as existing
sources.
Until these isauaa of environmental
impact ara fully resolved. EPA remains
concerned that if thasa chemical* are
exempted from regulation, the
substitution of exempt for nonexempt
solvents could result in large increases
of emissions of pollutants that may have
adverse health impacts.
The emissions of CFC-22 and FC-23.
also of relatively low photochemical
reactivity, are of continuing concern
with regard to possible environmental
effects. Consequently. EPA is not
precluding the possible future regulation
of these compounds aa well
Finally. EPA wishes to point oat that
this notice addresser only the Agency's
lack of authority to include in Federally
approved SIPs controls on substances
whose emissions do not contribute.
either directly or indirectly, to
concentrations of pollutants for which
N AAQS have been established under
Section 100 of the Act. This policy notice
does not address the question of SIP
measures which control substances
contributing to concentrations of
pollutants for which NAAQS have been
established, but which are contended to
be more strict than absolutely necessary
to attain and maintain the NAAQS. EPA
has no authority to exclude such
measures from SIPs.
FOR pusrrMSjii INFORMATION CONTACT*
C. T. Helms. Chief. Control Programs
Operations Branch (MEMS). Research
Triangle Park. North Carolina £711.
(919) 541-5228. FTS 829-4220.
Date* fitly IS. USA
David G.Hawtda*.
AttiitantAdaunnimorforAir. .Vo/o* oad
Radiation.
in a*.
California State Motor Vehicle)
Poflutton Control Standard*; Public
Aoancir: Environmental Protection
Agency (EPA).
ACTON: Notice of public hearing on
•requests for waivers of Federal
preemption.
SUMMARY: The California Air Resources
Board (CARB) notified EPA of two
recent amendments to California's
emission standards and test procedures
for motor vehicles produced by certain
small-volume manufacturers, and
requested a waiver of Federal
preemption for each amendment EPA
will consider these waiver requests.
among other issues, at a public hearing
already scheduled for July 24.1980 at
EPA s San Francisco office, as
announced in a Federal Register notice
of July 3.1980.
OATIS: Hearing July 24. and if necessary
July 25.1980.
AOORUSIS: EPA will consider the
waiver requests at a public hearing held
at: U.S. Environmental Protection
Agency Regional Office (Region IX],
Nevada Room. Sixth Floor. 215 Fremont
Street San Francisco. California. Copies
of all materials relevant to the hearing
are available for public inspection
during normal working hours (8:00 a.m.
to 4:30 p.m.) at: U.S. Environmental
Protection Agency. Public Information
Reference Unit Room 2922 (EPA
Library). 401M Street SW..
Washington. D.C 20480.
•en FURTHER INFORMATION CONTACT:
Glenn Unterberger. Chief. Waivers
Section. Manufacturers Operations
Division (EN-MO). U.S. Environmental
Protection Agency. Washington. D.C
20480. (202) 472*4421.
wmuMNTARv INFORMATION:
L Background and Discussion
Section 209(a) of the Clean Air Act as
amended. 42 U.S.C 7543(a) ("Act").
provides in part "No state or any
political subdivision thereof shall adopt
or attempt to enforce any standard
relating to control of emissions from
new motor vehicles or new motor
vehicle engines subject to this part * • •
(or) require certification, inspection, or
any other approval relating to the
control of emissions * * * aa condition
precedent to the initial retail sale, titling
(if any), or registration of such motor
vehicle, motor vehicle engine, or
equipment"
Section 209fb)(l) of the Act requires
the Administrator, after notice and
opportunity for public hearing, to waive
application of-the prohibitions of section
209 to any State which had adopted
standards (other than crankcase
emission standards) for the control of
emissions from new motor vehicles or
new motor vehicle engines prior to
March 30.1986. if the State determines
that the State standards will be. in the
aggregate, at least as protective of
public health and welfare as applicable
Federal standards. The Administrator
must grant a waiver unless he finds that:
(1) The determination of the State is
arbitrary and capricious. U) the State
does not need the State standards to
meet compelling and extraordinary
conditions, or (3) the State standards
and accompanying enforcement
procedures ara inconsistent with section
202(a) of the Act.
Pursuant to these provisions, the
Administrator of EPA grasred California
waivers of Federal preen-.;.:.on allowing
the State to enforce its exhaust emission
standards for 1979 and subsequent
model year passenger can ' and for 1979
and subsequent model year light-duty
trucks (LDTs) and medium-duty vehicles
(MDVs).' In American Motors Corp. v.
Blum '. the D.C Circuit held that section
202(b)(l)(B) of the Act entitled American
Motors Corporation (AMC) to two
•additional years of lead time to meet
certain California oxide of nitrogen
(NOJ emission standards for passenger
cars.
As a result in a Federal Register
notice issued July 3.1980, the
Administrator modified his passenger •
car waiver decision with respect to 1980
and 19at modal year AMC passenger
can. and announced a public hearing to
reconsider the earlier LDT/MDV w«iver
decisions in light of AMC v. Blum. T'.t
notice further provided that EPA w. Id
consider at the public hearing any < .•
waiver requests filed by California . or
before July 7.1980 to cover amendet,
NO, standards and enforcement
procedures for 1980 end later model
year passenger cars and 1981 and la-er
year passenger cars and 1981 and later
year model year LDTs and MDVs
manufactured by AMC
la a June 13.1980 letter to the
Administrator. CARS notified EPA that
it had taken several actions to revise
California's new motor vehicles
emissions control program in response
to AMC v. Blum. CARS requested e
waiver of Federal preemption for the
following items:
(i) Amendments to exhaust emission
standards and test procedures for 1980
and later model year passenger cars.
light-duty trucks and medium-duty
< u nt am (ha* M. ism
•41FK lia UMMMT* U1STSI (for Ciliforau i
ten-Haz ao4W rw urn «« MOV«C « nt IMS
(Apnltxitm(tarCahfotnuit lea) u*Utw
iytwLDTiM*MDVi|.
•eat f. u era iac en.
6-9
-------
APPENDIX H
CHEMICAL SCREENING ANALYSIS DATA
-------
APPENDIX H
CHEMICAL SCREENING ANALYSIS DATA
This appendix provides a detailed presentation and description of
the data and programs used to" derive the results discussed in Section
9.2. The appendix includes in Section H.I a description and a list of
the affected chemicals used in the screening analysis. Section H.2
describes all input data used in the analysis including relevant .
assumptions made. Section H.3 is a brief explanation of the logic of
the screening analysis program accompanied by a printout of the program
itself. The results of the screening analysis are described and
listed in Section H.4. A separate discussion follows in Section H.5
of the program and inputs used to determine the quantity and distribu-
tional impacts, along with the results. Finally, Section H.6 details
the production process routes that are used for each chemical in the
roll-through price increase calculation.
This appendix is intended to be a point of reference for questions
arising from the price impacts analysis of Section 9.2. A brief
discussion of the logic of the computer program and the specific data
used are provided here. Although some discussion of the approach and
of the basis for assumptions made in the screening analysis is presented,
Section 9.2 should be read for a more in-depth discussion.
H.I CHEMICALS AFFECTED
' Table H-l provides an alphabetical and numerical list of 240
chemicals which is used to define the members of the SOCMI industry.
Included in this list are the 173 chemicals defined as the large-volume
chemicals produced by reactor processes in Section 9.1.2, and 16
chemicals that are process route inputs to these 173 but are not
produced themselves by reactor processes. An additional 51 chemicals
are included in Table H-l but are not specifically used in production
by reactor processes. The chemicals are arranged alphabetically by
chemical name and numerically by number in the data sets. Also included
is each chemical's common name, if different from its chemical name.
Several characteristics of this list warrant special notice.
First, the chemicals are numbered 1 to 257, but 17 of the numbers
have no chemical assigned to them and do not appear in Table H-l or in
the screening analysis data sets. These 17 numbers are, 59, 100, 218,
219, 229, 231, 233, 241, 242, 243, 244, 245, 246, 247, 253, 255, 256.
Second, there are 51 other numbers that do not appear in the screening
analysis data sets, and they are represent the 51 chemicals in Table H-l
H-l
-------
TABLE H-l. LIST OF CHEMICALS BY CHEMICAL NUMBER
Chemical
number
Chemical name
Common name
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Acetaldehyde
Acetic acid
Acetic acid, anhydride
Acetic acid, butyl ester
Acetic acid, ethenyl ester
Acetic acid, ethyl ester
Acetic acid, magnesium salt
Alcohols, C-ll or lower, mixtures
Alcohols, C-12 or higher, mixtures
2-Aminoethanol
Benzenamine
Benzene
1,3-Benzenedicarboxylic acid3
1,4-Benzenedicarboxylic acid
1,2-Benzenedicarboxylic acid,
bis (2-ethylhexyl) ester
1,2-Benzenedicarboxylic acid,
butyl, phenylmethyl ester
l,2-Benzenedicarboxylic.acidB di-n-
heptyl-n-nonyl undcyl ester
1,2-Benzenedicarboxylic acid,
diisodecyl ester
(1) Acetic anhydride
(2) Acetic oxide
n-Butyl acetate
Vinyl acetate
Ethyl acetate
Magnesium acetate
Ethanolamine
(1) Aniline
(2) Phenylamine
Benzol
Isophthalic acid
Terephthalic acid
(1) Bis (2-ethylhexyl)
phthalate
(2) Dioctyl phthalate
(3) Di (2-ethylhexyl)
phthalate
Butyl benzyl phthalate
Oi-n-heptyl-n-nonyl undecyl
phthalate
Diisodecyl phthalate
(See footnotes at end of table).
(continued)
H-2
-------
TABLE H-l (continued)'
Chemical
number
Chemical name
Common name
19 1,2-Benzenedicarbgxylic acid,
diisononyl ester
20 1,4-Benzenedicarboxylic acid
dimethyl ester
21 Benzenesulfonic acid
22 Benzenesulfonic acid, mono-C,Q ..-•
alkyl derivatives, sodium salts
23 Benzoic acid, technical3
24 l,l'-Biphenyla
25 2,2-Bis(hydroxymethyl)-l,3-
propanediol
26 1,3-Butadiene
27 Butadiene and butene fractions
28 Butanal
29 Butane
30 Butanes, mixed
31 l,2-(and 1,3-) Butanediol3
32 1,4-Butanediol
33 Butanoic acid, anhydride
34 1-Butanol
35 2-Butanol
36 2-Butanone
37 1-Butene
Diisononyl phthalate
(1) Terephthalic acid,
dimethyl ester
(2) Dimethylterephthalate
(3) DMT
Oiphenyl
Pentaerythritol
(1) Bivinyl
(2) Divinyl
Butyraldehyde
n-Butane
Butylene glycol
Butyric anhydride
n-Butyl alcohol
sec-Butyl alcohol
Methyl ethyl ketone
a-Butylene
(See footnotes at end of table)
(continued)
H-3
-------
TABLE H-l (continued)
Chemical
number
Chemical name
Common name
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
2-Butene
Butenes, mixed
2-Butoxyethanol
2-Butyne-l,4-diol
Carbamic acid, monoammonium salt
Carbon disulfide
Carbonic dichloride
Chlorobenzene, mono-
2-Chloro-l,3-butadienea
Chiorodi f 1uoromethane
Chloroethane
Chloroethene
6-Chloro-N-ethyl-N'-(l-methylethyl)-
l,3,5-triazine-2,4-diamine
Chloromethane
(Chloromethyl) benzene
(Chloromethyl) oxirane
l-Chloro-4-nitrobenzene
2-Chloro-1-propanol
(1) p-Butylene
(2) pseudo-Butylene
Butylenes (mixed)
Butyl Cellosolve
Phosgene
Chloroprene
Freon 22
Ethyl chloride
Vinyl chloride
(1) 2-Chloro-4-(ethylamino)~
6-(isopropylamino)-s-
triazine
(2) Atrazine_
Methyl chloride
(1) Benzyl chloride
(2) crChlorotoluene
Epichlorohydrin
(1) p-Chloronitrobenzene
(2) p-Nitrochlorobenzene
(1) 2-Chloropropyl alcohol
(2) Propylene chlorohydrin
(See footnotes at end of table)
(continued)
H-4
-------
TABLE H-l (continued)
Chemical
number
Chemical name
Common name
56 3-Chloro-l-propene
57 Coconut oil acids, sodium salt3
58 Cyclohexane
60 Cyclohexane, oxidized
61 Cyclohexanol
62 Cyclohexanone
63 Cyclohexanone oxime
64 l,3-Cyclopentadienea
65 Cyclopropane
66 1,2-Dibromoethane
67 Dibutanized aromatic concentrate3
68 l,4-Dichloro-2-butene
69 3,4-Dichloro-l-butene
70 Oichlorodifluoromethane
71 Dichlorodimethylsilane
72 1,2-Dichloroethane
73 1,1-Dichloroethene
74 Dichlorof1uoromethane
75 Dichloromethane
76 l,3-Dichloro-2-propanola
(1) 3-Chloropropene
(2) Ally! chloride
Hexahydrobenzene
(1) Hexalin
(2) Hexahydrophenol
Pimelic ketone
Trimethylene
(1) Ethylene dibromide
(2) Ethylene bromide
1,4-Dichlorobutene
Freon 12
Dimethyldichlorosilane
(1) Ethylene chloride
(2) Ehtylene dichloride
Vinylidene chloride
Freon 21
Methylene chloride
Dichlorohydrin
(See footnotes at end of table)
(continued)
H-5
-------
TABLE H-l (continued)
Chemical
number
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
Chemical name
Di ethyl benzene
l,3-Diisocyanato-2-(and 4-)
methyl benzene (80/20 mixture)
Dimethyl benzenes (mixed)
1,2-Di methyl benzene
1,3-Dimethyl benzene
1,4-Di methyl benzene
1,1-Dimethyl ethyl hydroperoxide3
2, 6- Dimethyl phenol3
1-Dodecene
Dodecyl benzene, linear
Dodecyl benzene, nonlinear
Oodecylbenzenesulfonic acid
Oodecylbenzenesulfonic acid,
sodium salt
Ethane3
1,2-Ethanediol
2,2'-(l,2-Ethanediylbis (oxy))
bisethanol
Ethanol
Ethene
Common name
—
Toluene-2,4-(and 2,6-)
diisocyanate (80/20 mixture)
Xylenes (mixed)
o-Xylene
m-Xylene
p-Xylene
--
(1) m-Xylenol
(2) 2,6-Xylenol
(1) Dodecene
(2) Tetrapropylene
Alkyl benzene
—
--
--
(1) Bimethyl
(2) Dimethyl
Ethyl ene glycol
Triethylene glycol
Ethyl alcohol
(1) Ethyl ene
(2) Elayl
(3) Olefiant gas
(See footnotes at end of table)
(continued)
H-6
-------
TABLE H-l (continued)
Chemical
number
Chemical name
Common name
95
96
97
98
99
101
102
103
104
105
106
109
110
111
112
113
114
Ethenone
Ethenylbenzene
2-Ethoxyethanol
2-Ethoxyethyl acetate
Ethyl benzene
2-Ethylhexanala
2-Ethyl-l-hexanol
(2-Ethylhexyl) amine
Ethylmethylbenzene3
6-Ethyl-1,2,3,4-tetrahydro-9,10-
anthracenedione
Ethyne
107 Fatty acids, tall oil, sodium salt3
108 Formaldehyde
2,5-Furandione
D-Glucitol
Heptane
Heptenes (mixed)
Hexadecyl chloride3
Hexahydro-2H-azepin-2-one
Ketene
Styrene
(1) Ethylene glycol monoethyl
ether
(2) Cellosolve
(1) Ethylene glycol monoethyl
ether acetate
(2) Cellosolve acetate
2-Ethylhexyl alcohol
(1) Acetylene
(2) Ethine
(1) Formalin (solution)
(2) Methanal (gas)
Maleic anhydride
Sorbitol
n-Heptane
Caprolactam
(See footnotes at end of table)
(continued)
H-7
-------
TABLE H-l (continued)
Chemical
number
Chemical name
Common name
115 Hexane
116 1,6-Hexanediamine
117 1,6-Hexanediamine adipate
118 1,6-Hexanedinitrile
j
119 ' Hexanedioic acid
120 ' 2-Hexenedinitrilea
121 3-Hexenedinitrilea
122 Hydrocyanic acid .
123 4-hydroxy-4-methy1-2-pentanone
124 2-Hydroxy-2-methy1propaneni tri1e
125 2-Hydroxy-l,2,3-
propanetricarboxylic acid
126 2,2'-Iminobisethanol
127 1,3-Isobenzofurandione
128 Isodecanol
129 Linear alcohols, ethoxylated, mixed
130 Linear alcohols, ethoxylated and
sulfated, sodium salt, mixed
131- Linear alcohols, sulfated, sodium
salt, mixed
Hexamethylene diamine
(1) Hexamethylene diamine
adipate
(2) Nylon salt
(1) Adiponitrile
(2) 1,4-Dicyanobutane
Adipic acid
1,4-Oicyano-l-butene
(1) 1,4-dicyanobutene
(2) Dihydromucononitrile
(3) l,4-Dicyano-2-butene
Hydrogen cyanide
Diacetone alcohol
(1) Acetone cyanohydrin
(2) 2-Methyllactonitrile
Citric acid
(1) Diethanolamine
(2) 2,2'-Aminodiethanol
Phthalic anydride
Isodecyl alcohol
(See footnotes at end of table)
(continued)
H-8
-------
TABLE H-l (continued)
Chemical
number
Chemical name
Common name
132 Methane
133 Methanol
134 2-Methoxyethanola
135 Methyl benzene
136 4-Methyl-l,3-benzenediamine
137 ar-Methylbenzenediamine
138 2-Methyl-l,3-butadiene
139 2-Methylbutane
140 2-Methyl-2-butene
141 2-Methylbutenes, mixed
142 l-Methyl-2,4-dinitrobenzene
(and 2-Methyl-1,3-dinitrobenzene)
143 1-Methyl-2,4-di ni trobenzene
144 (1-Methylethyl) benzene
145 4,4'-(1-Methylethylidene)
bisphenol
(1) Methyl alcohol
(2) Wood alcohol
(1) Ethylene glycol mono-
methyl ether
(2) Methyl Cellosolve_
Toluene
(1) Toluene-2,4-diamine
<2) 2,4-Diaminotoluene
(3) 2,4-Tolylenediamine
Isoprene
Isopentane
Amylene
Amylenes, mixed
2,4- (and 2,6-) Dinitroto-
luene
2,4-Dinitrotoluene
Cumene
(1) 4,4'-Isopropy1idenedi-
phenol
(2) Bisphenol A
146
147
148
Methyl oxirane
2-Methyl pentane3
4-Methy 1 -2-pentanone
Propylene oxide
Isohexane
(1) Isopropyl acetone
(2) Methyl Isobutyl ketone
(See footnotes at end of table)
(continued)
H-9
-------
TABLE H-l (continued)
Chemical
number
Chemical name
Common name
149 1-Methy1-1-phenylethyl
hydroperoxide
150 2-MethyIpropanal
151 2-Methy1 propane
152 2-Methyl-l-propanol
153 2-Methyl-2-propanol
r
154 2-Methy1-1-propene
155 2-Methy1-2-propenenitrilea
156 2-Methyl-2-propenoic acid, methyl
ester
157 1-Methy1-2-pyrrolidinone
158 Naphthalene
159 2,2',2"-Nitrilotrisethanol
Cumene hydroperoxide
(1) Isobutyraldehyde
(2) Isobutylaldehyde
Isobutane
Isobutyl alcohol
(1) tert-Butyl alcohol
(2) t-Butanol
(1) Isobutylene
(2) 2-MethyIpropene
Methacryloni tri1e
(1) Methacrylic acid methyl
ester
(2) Methyl methacrylate
l-Methyl-2-pyrrolidone
(1) Naphthene
(2) Naphthalin
(1) Triethanolamine
(2) Triethylolamine
160
161
162
163
164
165
Nitrobenzene
1-Nonanol
1-Nonene
Nonyl phenol
Nonyl phenol, ethoxylated
Octene
Nitrobenzol
(1) n-Nonanol
(2) Nonyl alcohol
Tripropylene
--
--
--
(See footnotes at end of table)
(continued)
H-10
-------
TABLE H-l (continued)
—» •— -^^— fclt^—^-s.
Chemical
number
166
167
Chemical name
Oil-soluble petroleum sulfonate,
calcium salt
Oil -soluble. petroleum sulfonate.
Common name
„
sodium salt
168 Oxirane
169 2,2'-Oxybisethanol
170 Pentane3
171 3-Pentenenitrile
172 Pentenes, mixed
173 Phenol
174 1-Phenylethyl hydroperoxide
175 Propanal
176 Propane
177 1,2-Propanediol
178 Propanenitrile3
179 1,2,3-Propanetrlol
Ethylene oxide
Diethylene glycol
n-Pentane
(1) Carbolic acid
(2) Hydroxybenzene
Propionaldehyde
Dimethyl methane
Propylene glycol
(1) Propionitrile
(2) Ethyl cyanide
(1) Glycerol
(2) Glyceryl
(3) Glycerin
180
181
182
183
184
Propanoic acida
1-Propanol
2-Propanol
2-Propanone
1-Propene
Prop ionic acid
Propyl alcohol
Isopropyl alcohol
(1) Acetone
(2) Dimethyl ketone
Propylene
(See footnotes at end of table)
(continued)
H-ll
-------
TABLE H-l (continued)
Chemical
number
185
186
187
188
189
190
191
192
193
194
Chemical name
2-Propenenitrile
2-Propenoic acid
2-Propenoic acid, butyl ester
2-Propenoic acid, ethyl ester
Propyl benzene
Sodium cyanide
Tallow acids, potassium salt3
Tallow acids, sodium salt3
Tetrabromomethane3
Tetrachloroethene
Common name
Acrylonitrile
Acrylic acid
Butyl aery late
Ethyl aery late
Phenyl propane
Cyanogran
—
—
Carbontetrabromi de
(1) Tetrachloroethylene
195 Tetrachloromethane
196 Tetraethylplumbane
197. 1,2,3,4-Tetrahydrobenzene
198 Tetrahydrofuran
199 Tetra (methyl-ethyl) plumbane
200 Tetramethylplumbane3
201 l,3,5-Triazine-2,4,6-triaminea
?02 1,1,l-Tribromo-2-methy1-2-propanol
203 1,1,1-Trichloroethane
204 1,1,2-Trichloroethane
(2) Perchloroethylene
Carbon tetrachloride
Tetraetyhl lead
Cyclohexene
THF
Tetra (methyl-ethyl) lead
Tetramethyl lead
(1) Mel amine
(2) 2,4,6-Triamino-s-triazine
(1) Tribromo-t-butyl alcohol
(2) Acetone-bromoform
(3) Brometone
Methyl chloroform
Vinyl trichloride
(See footnotes at end of table)
(continued)
H-12
-------
TABLE H-l (continued)
Chemical
number
Chemical name
Common name
205 Trichloroethene
206 Trichlorofluoromethane
207 Trichloromethane
208 2,4,6-Trichloro-l,3,5-triazine
209 l,l,2-THch1oro-l,2,2-
trifluoroethane
210 2,6,6-Trimethylbicyclo-
[3.1.1]hept-2-ene
211 Ureaa
Tri chloroethy1ene
(1) Freon 11
(2) Fluorotrichloromethane
Chloroform •
(1) Cyanuric chloride
(2) 2,4,6-Trichloro-s-tria-
zine
(1) Trichlorotrifluoroethane
(2) Fluorocarbon 113
a-Pinene
(1) Carbamide
(2) Carbonyldiamide
212
213
214 •
215
216
217
220
221
222
223
Urea ammonium nitrate
3-Hydroxybutyral dehyde
2-Butanal
2-Butenoic acid
1,3,5, 7-Tetraazatri eye 1 o-
[3.3.1.13>7]decane
6-Methyl heptanol3
Methanami ne
N-Methy 1 methanami nea
4-Methy 1 -3-penten-2-one
Benzotrichloride
--
(1) Aldol
(2) Acetaldol
(1) Crotonal dehyde
(2) B-Methylacrolein
Crotonic acid
(1) Hexamine
(2) Hexamethylene tetraamine
(1) Isooctyl alcohol
(2) Isooctanol
Me thy! ami ne
Di methyl ami ne
Mesityl oxide
--
(See footnotes at end of table)
(continued)
H-13
-------
TABLE H-l (continued)
Chemical
number
224
225
226
227
228
230
232-
234
235
236
237
238
239
240
248
249
250
251
252
254
257
. Chemical name Common name
1-Bromobutane
2-Chloroethanola
Ethanamine3
Ethyl -A-nonylatea
Ethyl sulfate3
Isononanol
Propiol acetone3
Tri bromomethane3 Bromoform
1 , 1 , 2 , 2-Tetrachl oroethane3
lodomethane3 Methyl iodide
Methyl t-butyl ether MTBE
Alcohols, C-12 or higher, unmixed
Tert-Butyl hydroporoxide
Chloroacetic acid
Carbon dioxide
Carbon monoxide
b
1,3-Dichloropropane
Butyric acid
Synthesis gas
Diisobutene
Cyanogen chloride
3Non-reactor process chemicals not affected by the standards.
blntermediate chemicals used in roll-through price analysis.
H-14
-------
that are not used in production by reactor processes. These 51 numbers
?™' ^134,i9' 23) 24' 31' 42' 46> 57' 64' 67> 76' 83> 84> 90> 101.
104, 107, 113, 120, 121, 131, 134, 147, 155, 167, 170, 178, 180, 190,
iS' Hi* I?3' 200' 201* 210' 211' 212' 217> 221> 223> 224 225 226
227, 228, 230, 232, 234, 235, 236. Third, chemicals numbered above
212 are not in alphabetic order. These chemicals were added to the
original alphabetic list to more completely define the SOCMI industry.
H.2 SCREENING ANALYSIS INPUT FILES
The two input files used in the main screening analysis program
are presented in Tables H-2 and H-3. These two files are slightly
different in that the first represents the reasonable worst-case
scenario and the second represents the more likely case scenario.
Letter codes head each column in the tables, defining the data as
fo11ows:
Reasonable Worst-Case Input File (Table H-2)
A Chemical number. This is the identification number assigned
to each chemical in Table H-l. These numbers are used
throughout the computer programs described in this appendix.-
B Capacity in gigagrams. For the reasonable worst-case scenario
this figure is the smallest existing plant size producing
the chemical. When no. chemical-specific data is available,
the median value of all chemical's smallest existing size is
used as a default. That median value is 23 Gg.
C Priority code. This code is a mechanism by which the program
calculates rolled-through costs in an order that follows the
chain of production among chemicals. Each chemical is
assigned a priority code, 1 being the highest, then 2 and so
on. The program calculates control costs first for input
chemicals and then for derivative chemicals on the list
according to their priority number. This code does not
signify plant characteristics or-relative importance, but is
merely a tool for the program in timing its calculations.
D Number of processes. This is the number of alternative
major commercial processes available for the final step in
producing the chemical. Each chemical will have the same
number of data lines as this number indicates, and each line
represents a separate process.
E Number of inputs. For each process route, this number shows
the number of input chemicals used in finding the rolled-
through costs. The entries might differ for different processes
for the same chemical.
H-15
-------
Table H-2 Reasonable Worst-Case Input File
ABCDEFGFGFG H j
001 181.0 02 01 01 94 0.71 75.0 750.7
002 41.0 04 02 01 1 0.77 ' 58.0 148.1
002 41.0 04 02 01 133 0.56 . 58.0 143.1
003 63.0 06 01 02 2 1.40 95 0.79 ' 90.0 42.7
004 9-0 05 01 02 2 0.54 34 0.71 106.0 36.0
005 181.0 05 01 02 2 0.73 94 0.37 71.0 35.7
006 7.0 05 01 02 2 0.69 93 0.59 95.0 33.1
003 11.0 02 02 01 94 1.18 106.0 o.O
008 11.0 02 02 01 176 106.0 o.O
009 11.0 02 01.01 94 1.29 121.0 o.O
010 37.4 03 01 01 168 0.75 111.0 o.O
011 59.0 04 02 01 160 1.35 . 84.0 Q.Q
011 59-0 04 02 01 160 1.47 84.0 o.O
012 3.0 02 02 46.0 44.9
012 3-0 02 02 01 135 1.23 46.0 44.9
014 195.0 03 01 01 82 0.67 77.0 o.O
015 14.0 04 01 02 127 0.39 102 0.70 110.0 35.9
016 5.0 04 01 03 34 0.26 52 0.45 127 0.53 99-0 35.5
017 9-0 04 01 02 9 1.18 127 0.29 107.0 37.4
013 9.0 04 01 02 127 0.34 123 0.75 72.0 .37.4
020 227.0 04 01 02 82 0.61 133 0.40 70.0 o.O
021 5.0 03 01 01 12 0.49 112.0 1-95.7
022 5.0 04 01 01 21 1.00 104.0 o.O
025 11.0 05 01 02 1 0.40 108 1.22 156.0 37.7
026 20.0 02 03 01 29 1.93 . 67.0 0.0
026 20.0 02 03 01 39 1.35 ' 67.0 0.0
026 20.0 02 03 67.0 0.0
027 3.0 02 02 01 29 1-80 67.0 ' 44.9
027 3-0 02 02 67.0 44.9
028 36.0 02 01 01 184 0.75 77.0 65.0
029 23.0 01 01 ' 29.0 0.0
030 23-0 01 0.0
032 27.0 06 01 01 41 1.19 172.0 33.8
033 -25.0 04 02 01 215 1.21 ' 98.0 38.7
033 25.0 04 02 01 251 1.24 95 0.30 98.0 38.7
034 2.0 03 01 01 28 1.03 70.0 47-3
035 34.0 03 01 01 37 0.90 77.0 61.0
036 36.0 04 01 01 35 1.17 88.0 • 0.0
037 12.0 02 01 01 94 66.0 0.0
038 23-0 03 01 01 37 1.15 38.0 o.O
039 11.0 01 01 42.0 0.0
040 25.0 04 01 02 34 0.90 168 0.59 73.0 38.7
041 23.0 05 01 02 106 0.43 108 1.00 319-0 35.9
043 5.0 02 01 01 132 0.23 37.0 0.0
044 -11.0 03 01 01 249 79-0 0.0
H-16
-------
Table H-2 Continued.
ABCDEF-GFGFG H J
045 23.0 03 01 01 12 0.82 84.0 384.6
047 23.0 06 01 01 207 1.10 51.0 0.0
048 34.0 03 02 01 93 0.75 53-0 365-3
048 34.0 03 02 01 94 0.49 53-0 365.3
049 136.0 03 01 01 72 1.65 40.0 0.0
050 11.0 04 02 01 132 0.33 4U-0 0.0
051 11.0 04 02 01 133 0.68 ' 44.0 364.5
052 9.0 02 01 01 135 0.80 92.0 374.9
053 100.0 03 01 01 56 1.08 181.0 368.6
054 45.0 04 01 01 45 0.80 174.0 409-2
055 02 01 01 184 0.64 0.0
056 53-0 02 01 01 184 0.74 126.0 0.0
058 35.0 03 01 01 12 0.93 55.0 0.0
060 45.0 04 01 01 58 0.94 121.0 0.0
061 23.0 06 02 01 58 1.20 137.0 0.0
061 23.0 06 02 01 173 0-98 • -137.0 0.0
062 9.0 07 02 01 61 0.84 • 132.0 53-4
062 9.0 07 02 01 173 0.98 ' 132.0 53-4
063 37-4 08 01 01 62 1.24 98.0 0.0
065 23-0 03 01 01 250 120.0 67-8
066 23.0 02 01 01 94 0.17 84.0 381.1
068 23-0 04 01 01 69 1.52 101.0 615.1
069 23-0 03 01 01 26 0.94 101.0 . 381.1
070 23.0 04 01 01 195 1-33 163-0 0.0
071 23.0 05 01 01 50 1.12 462.0 0.0
072 68.0 02 01 01 94 0.31 31.0 369-6
073 45.0 04 02 01 49 0.68 61.0 365.2
073 45.0 04 02 01 204 1.38 61.0 365-2
074 23.0 06 01 01 207 1.45 157.0 0.0
075 27.0 05 02 01 50 0.61 53-0 0.0
077 27.0 04 01 02 94 0.30 99 1.12 218.0 37-0
078 18.0 04 01 02 44 1.43 137 0.88 205.0 0.0
079 23-0 01 01 46.0 0.0
080 11.0 02 01 01 79 4.55 51-0 0.0
081 79-0 02 01 01 79 2.50 77.0 0.0
082 27.0 02 01 01 79 5-56 64.0 0.0
085 8.0 02 01 01 184 1.27 33-0 0.0
086 18.0' 03 01 02 12 0.35 85 0-76 101.0' 36.4
087 102.0 03 01 02 12 0.35 85 0-76 101.0 41.5
088 14.0 04 01 01 86 0.75 106.0 285-5
089 23-0 05 01 01 88 0-70 93-0 0.0
091 23.0 03 01 01 168 0.75 73.0 0.0
092 1.0 03 01 01 168 0-90 97-0 0.0
093 75.0 02 01 01 94 0.61 57-0 0.0
094- 45-0 01 01 53-0 0.0
095 ' 32-5 05 01 01 2 1-59 149-0 • 0.0
096 54.0 04 01 01 99 1.13 77.0 176.1
097 23-0 03 01 02 93 0-57 168 0.54 93-0 38.5
H-17
-------
Table H-2 Continued.
ABCDE'FGFGFG H J
098 9-0 05 01 02 2 0.48 97 0.76 115.0 37-4
099 16.0 03 01 02 12 0.76 94 0.28 71.0 36.3
102 25.0 03 01 01 28 1.23 83.0 ' o.O
103 27.0 04 01 01 102 1.44 111.0 37.0
105 25.0 04 01 02 99 0.64 127 0.90 139-0 83-0
106 5.0 02 02 01 132 4.10 121.0 0.0
106 5.0 02 02 01 176 2.82 121.0 o.O
108 27.0 04 01 01 133 1.19 20.0 0.0
109 5.0 03 02 01 12 1.33 99.0 . o.O
109 5.0 03 02 01 39 2.12 99.0 o.O
110 5.0 01 01 101-0 38.1
111 5.0 01 42.0 0.0
112 14.0 02 02 01 39 0.79 « 34.0 0.0
112 14.0 02 02 01 184 1.70 34.0 0.0
114 159.0 08 01 01 62 0.92 190.0 0.0
115 27.0 01 - • ^0.0 0.0
116 23.0 07 01 01 118 0.93 " 92.0 38.8
117 9.0 08 01 02 116 0.63 120 0.80 181.0 37.4
118 23.0 06 03 01 27 0-.72 100.0 129-5
118 23.0 06 03 01 120 1.93 100.0 129-5
•118 23.0 06 03 01 185 1.09 100.0 129-5
119 14.0 07 02 01 58 0.78 132.0 173.1
119 14.0 07 02 01 61 0.65 .132.0 173.1
122 02 01 01 132 0.79 19.0 0.0
123 25.0 06 01 01 183 1.01 112.0 38.7
124 23.0 06 01 01 183 0.60 0.0
125 11.0 01 181.0 0.0
126 159.0 03 01 01 168 0.88 • 106.0 0,0
127 36.0 03 02 01 80 0.98 77.0 . 0.0
127 36.0 03 02 01 158 1.25 77-0 0.0
128 03 01 01 T62 1.25 83-0 o.O
129 23.0 03 01 02 9 .0.93 168 0.22 84.0 38.5
130 113.4 04 01 01 129 0.87 114.0 0.0
132 01 01 • 0.0
133 174.0 03 01 01 132 0.56 24.0 505.3
135 27.0 01 01 269.0 0.0
136 23-0 03 01 01 143 1.57 165.0 43-7
137 23.0 03 01 01 143 3-57 ' 100.0 43.7
138 23.0 02-02 01 139 53-0 79-7
138 23.0 02 02 01 141 1.30 53.0 79.7
139 5.0 01 01 71.0 0.0
140 2.3 01 • 0.0
141 23-0 01 01 0.0
142 17.0 02 01 01 135 0.53 201.0 105-0
143 34.0 02 01 01 135 0.53 196.0 201.6
144 54.0 03 01 02 12 0.72 184 1.17 53-0 0.0
145 45.0 06 01 02 173 0.88 183 0.28 134.0 0.0
146 200.0 03 02 01 55 1.47 99.0 169-6
H-18
-------
Table H-2 Continued.
ABCDEFGFGFG H J
146 200.0 03 02 02 151 2.60 184 0.78 99.0 169 6
148 7.0 08 01 01 183 1.29 108.0 38 5
149 2.3 04 01 01 144 0.80 0 0
150 7.0 02 01 01 184 0.75 95.0 42.5
151 23-0 02 01 01 29 1.15 22.0 0 0
152 7.0 03 01 01 28 1.03 66.0 38.5
153 2.3 02 01 01 154 0.92 159.0 - 36.9
•154 7.0 01 01 15.0 b.o
156 54.0 06 01 03 122 0.27 133 0.32 183 0.58 137.0 49.7
157 127.0 07 01 01 32 0.72 260.0 0 0
158 34.0 01 01 48.0 0.0
159 127.0 03 01 01 168 0.93 108.0 0.0
160 34.0 03 01 01 12 0.65 75.0 " 35 8
161 21.5 02 01 01 254 84.0 54 1
162 11.0 02 01 01 184 1.21 37.0 0*0
163 5.0 06 01 02 162 0.76 173 0.46 112.0 o'o
164 25.0 07 01 02 163 0-96 168 0.19 114.0 0 0
165 11.0 02 01 01 39 97.0 o'.O
166 23-0 01 01 1Q8.0 0.0
168 50.0 02 01 01 94 1.00 70.0 418 5
169 2.0 03 01 01 168 0.84 70.0 0*0
171 23.0 03 01 01 26 0.96 100.0 0*0
172 27.0 1 . O'o
173 34.0 05 01 01 149 1.79 79.0 o 0
174 18.0 04 01 01 99 1.28 100.0 214.8
175 21.5 02 01 01 94 0.60 79 0 54 1
176 23.0 01 01 • 22.0 0.0
177 23..0 04 01 01 146 0.77 97.0 0 0
179 18.0 04 02 01 53 1.15 176.0 0.0
179 18.0 04 02 176.0 0.0
131 29.0 03 01 01 175 1.40 92.0 45 2
182 23.0 02 01 01 184 0.85 73.0 53*2
133 25.0 05 02 01 144 2.30 66.0 0 0
184 32.5 01 01 " 46.0 0.0
185 113.0 02 01 01 184 1.25 99.0 o 0
186 18.0 02 01 01 184 0.83 115.0 o'o
187 9.0 04 01 02 34 0.58 186 0.57 ' 150.0 37.'4
188 9.0 03 02 02 93 0.48 106 0.32 ' 123.0 49.7
188 9-0 03 02 02 93 0,51 186 0.76 123.0 49 7
139 227.0 03 01 02 12 0.93 184 0.50 91.0 50 8
194 23.0 03 03 01 132 0.21 46.0 0.0
195 4.0 03 03 01 132 0.11 42.0 0.0
196 36.0 04 01 01 48 1.19 606.0 37.5
197 23.0 07 01 01 61 1.74 91 0 67 8
198 23.0 07 01 01 32 1.31 225.0 67^
199 27.0 04 01 01 48 0.73 364.0 37 0
202 23.0 06 01 01 183 0.27 100.0 381 1
203 91.0 05 01 01 73 0.73 77.0 o'o
H-19
-------
Table H-2 Continued.
ABCDEFGFGFG.H J
204 5.0 03 01 01 72 0.81 75.0 3.7
205 54.0 03 01 01 72 0.74 68.0 367-7
206 23-0 04 01 01 195 1.17 141.0 0.0
207 16.0 05 02 01 50 0.43 68.0 0.0
208 5.0 04 01 01 257 319.0 372.9
209 5.0 04 01 01 194 0.98 194.0 0.0
213 3 01 01 1 1.11 - 0.0
214 3 01 0.1 213 1 .40 0.0
215 3 01 01 214 0.90 0.0
216 4.0 05 01 01 108 1.32 112.0 35.6
220 37.4 04 01 01 133 1.05 115.0 0.0
222 5-0 07 01 01 183 1-32 - 101.0 45-7
237 25.0 04 01 02 133 0.36 154 0.64 40.0 0.0
238 11.5 02 01 01 9 1.00 - 121.0 0.0
239 23.0 03 01 01 153 0.95 100.0 67-8
240 2.0 05 01 01 2 0.69 123.0 371-8
248 02 01 01 132 0.0
249 02 01 01 132 0.0
250 02 01 01 176 0.0
251 3 01 01 28 0.91 0.0
252 02 01 01 132 0.0
254 01 01 0.0
257 03 01 01 122 0.0
H-20
-------
ooooooooooooooooo
ooooooooooooooooooo
o o
*?£ui_u! c£o>»ooot£££ So££J°° JUJ^
........ .... --""'
ooooo oooooooo ooo
o ooooooo oooooooooo o
o o o o o
.oo
OOOOOOOOOOOOOOOOOO
—'fOvO-^lOUlUl-^J
—» —» Ul —» O\ OO OOUl
o oooooooooooooooobbbbbbbbb
• • • * •
CD
ooooooooooooooooooooooooooo
fO •+= IV) -CrCO (\) -tr CO
OOOOOOOOOOOOOOOOOOOOOOOOOOO
2 2 2 ° ° °°, ^ °JR ° °° ° °° 00 ° ° ° °0 00 0
-- - IV) -CO-* _ _^ _
vo ^ cocooo o^ro i\> 2*!t 2 •fc:VOvo vj)~g w -» oa -t^uoco -*coco fu
oj oo ro -tr ui ui LO ro f\> 4r oo
r* P PPPPPP^P '-'Oo-' o-.oooooooo-»
vxi -» o ui ouiuiui--i o oooo -»u> oooco *r o o oorocooco
OOOO VO ^
U1U1 VO 2,
00 _ 0
* • •
-~) -^1 _» "
CT.O-* fV) Co
,
*
_»_»_* ro ^-..^^ _^
ooooooo
— ' fNJ -fcLO -tr _fr |\>
OOOOOOO
o o o o o o
-» -» -> ro ro -^
OO IV) -* »\J fOOJ
-t -» ro-j ^aui
O — » O O O — '
Ul O VO -pr VOCO
— ' — »
ro o
oo ro
0 0
* *
Ul O
ooooooooooo
ro-t.trcorouiuiui-tr.frro
ooooooooooo
oooooooooo
~* ~"^ ~^ ~^ ro ro ro -~^ > i
O\ O^ O"v VO CO VO
oooo*rrororoco-*^r
— » — 'O— 'OOOOOO
-fco—j ro ON— j ui ui --i— -j
VO VOCO
ooo
...
UICO ^J
VO — ) -»
•H
O 0)
or
o n>
a:
ml
1
CO
Tl
o
O (b
r-
^-'
'n n>
o
O DJ
01
ID
T) 3
TJ
c
o TH
H1-
H^
0>
fVJ
OJCO -p:
OO CX> — »
_.5; _
OOvO ^r
-» Ul
0 °o
oo oo oo ooooooo
oo o oo o oo ooooo o
o ooo o oo oo'o oo
-------
Table H-3 Continued.
ABCDEFGFGFG H K
097 23.0 03 01 02 93 0.57 168 0.54 93-0 0.0
099 318.0 03 01 02 12 0.76 94 0.28 7J-0 56332/°
105 04 01 02 99 0.64 127 0.90 39.0 0.0
106 5.0 02 02 01 132 4.10 | 1.0 0.0
106 5.0 02 02 01 176 2.82 21.0 -qfi-P?'°
119 236.0 07 02 01 58 0.78 32.0 39o356.0
119 236.0 07 02 01 61 0.65 - 132-0 39635*'°
122 02 01 01 132 0.79 9-0 ,,7oo*n
123 7.0 06 01 01 183 1*01 12.0 3578°°°
126 03 01 01 168 0.88 106.0 0.0
127 36.0 03 02 01 30 0.98 77-0 °'°
127 36.0 03 02 01 158 1.25 77'° g.O
111 Sj gj ol 1629 l:ll 168 0.22 S?:? ' ^
j|| 174.0 0-301 01 252 ' £* 0.0
36 03 01 01 143 1.57 1*5.0 0.0
77 03 01 01 143 3.57 1°°-° °-°
III 17.0 02 ol 0? 135 0.53 201.0 105019-0
143 80.0 02 01 01 135 0.53 196.0 269986.0
144 54.0 030102 12 0.72184 1.16 53-0 17 °-°
tiiA 79? n 03 02 01 55 1.47 99-0 17289&.0
03 02 01 55 .
U6 sio 03 ol 02 151 2.66184 0.78 99.0 1728960
149 5.0 04 01 01 144 0.80 £.0
iqi 02 01 01 29 1 . 15 22<0 °-°
153 5.0 02 01 01 154 0.92 159-0 38832.0
ICM 7 n 01 01 15.0 0.0
156 95-0 06 01 03 122 0.27.133 0.32 183 0-58 137.0 59394.0
158 34.0 01 01 ^8°° °'£
159 ' 03 01 01 168 0.93 108.0
160 153.0 03 01 01 12 0.65 75.0
162 11.0 02 01 01 184 1.21 37-0
163 5.0 06 01 02 162 0.76 173 0.46 2.0 0.0
164 070102163 0.96163 0.19 11J-0 °.0
168 204.0 02 01 01 94 1.00 70.0 1174592.0
169 2.0 03 01 01 168 0.84 . 70.0 . 0.0
T73 34.0 05 01 01 149 1.79 J9-0 ?1U7fl?'S
174 18.0 04 01 01 99 1.28 100.0 21473^°
176 01 01 22.0 o.o
177 23.0 04 01 01 146 0.77 97'° 0 .0
132 206.0 02 01 01 184 0.85 J3.0 169785'2
183 ' 25.0 05 02 01 144 2.30 66.0 0.0
184 01 01 ^-° "'"
186- 18.0 02 01 01 184 0.83 ]5-0 " •"
137 35.0 04 01 02 34 0.58 136 0.57' 50.0 43543.0
138 43.0 03 02 02 93 0.48 106 0.32 23-0
138 43.0 03 02 02 93 0.51 136 0.76 123-0
H-22
-------
Table H-3 Continued.
ABCDEFGFGFG H
189 13.0 03 01 02 12 0.93 134 0.50 91.0
194 43.0 03 03 01 132 1.00 46 0 nn
195 41.0 03 03 01 132 0.11 4? 0 n'n
204 45.0 03 01 01 72 0.81 75~.0 390885 0
206 04 01 01 195 1.17 lil.O 9 Q n
208 18.0 04 01 01 257 ' 319.0 378900 0
209 5.0 04 01 01 194 0.98 Tg4.0 on
239 23.0 03 01 01 153 0.95 100.0 67840 0
248 02 01 01 132 1.00 n'n
250 02 01 01 176 « n
252 02 01 01 132 "n
257 03 01 01 122 00
H-23
-------
F Input ID. The number in the first F column designates the
ID number of one input used in the particular process. If
none of the chemicals listed in Table H-l is an input, this
column is blank.
G Input ratio. This decimal number in the first G column
indicates the kilogram amount of the first F-column chemical
used per kilogram of produced chemical.
The program allows for up to three chemical inputs for a
process. Columns F and G therefore are repeated for processes
involving more than one chemical input. If no other inputs
are used this space is blank.
H Chemical price. The price is a recent market price given in
cents per kilogram (
-------
program maxcoat;
const max s 215;
RIcoat rO
var of
inpt_id: array[l..max,-1.;3] of integer- ^ayC t . .max] of real;
inpt rat: arrayCl. .«:!, ,.?jj af r^fV'
not jug: array[l..max] of boolean; '
infcat: arrayd..3J of integer;
P«rc«nt: arrayCl.,3] Of real;
category, nun hi, num la, h 1 1 > i
X, z, nine, h7c,'frc,-frcap f^o' maxx-'
maxcst: arrayCT.,3] of Pea[.' °p> naxx'
more: boolean;
infilel, outfile: text-
begin
reset ( 'a-vscharin' , infilel);
rewrite ( -a-deltapout • , outfiie) •
for i ;s 1 to aax do
begin
coat incCi] :» o.O;
infill] :» 0.0;
not_big[i] :» true;
end;
for i :s 1 to 6 do
begin
infcatCil :s 0;
end;
for i :s 1 to 3 do
begin
maxcatCi] :a 0.0;
'end ;
nine :a 1.0;
category :» j;
num hi :s 0;
num~la := 0;
hoi? :s 0;
hvo :s 0.0;
frc : s 0.0;
frcap :s o.Q;
frop :a 0.0;
aaxx :s 0.0;
nore := false;
f read and process input file I
lb«rin :* 1 6o (max - ') do
^'inptaT'Jnot^dfi1;^3^11' P'-lO'-Cl], num procCi]
L i'poM!Ii/S!££tt
Figure H-1. Screening analysis program.
H-25
-------
if castUi] > 0.0 then
tc[i]:» castUi] * Slcost
. else
6cCi]:» costlCi];
{ select plant-capacities }
B if capCU <- 0.0 then cap[i] :s 23-0;
_ ( select prices }
^ if apr[i]* maxestCk] then aaxcstCk] :s cosi_incCl];
end ~
else if pradCl] > inpt idCj,k] then more :* false;
( no more matches to tHis product may be nade }
end;
end;
end;
{ compute the effective cost inc for this product process }
cost_incCj] :=
E 3
end;
end;
me for c.ns proauct process
* maxcstCU * ispt_ratC j, 1 ] •
maxcst[2] * inpc~rac[j,2] •
maxcstCjl * inpt~rat:j,3];
Figure H-1 (continued)
H-26
-------
{ next the'inflation factors oust be calculated and
the worst case-cost processes written out }
writeln (outfile);
writeln (outfile);
writ.in (outm^);' hi3h8St C03t Production processes');
writeln (putfile);
writeln (outfile, ' chem proc 1932 mkt 3 •,
' eff cat ine inflation',
.. , . ' capacity annual cost ');
writeln(outfile); '
maxx :» cost incC 1];
hold :s prodfl];
h : s 1;
for i :» 1 to max do
begin { =°«P^«e3lnfla^onh* ^1^eia^inJ th« high.st cost product
lf("P>CVth.2'°J th'" iaflCi]':i Cc'oatjni?!]1/ »prU])"d,oo.O;
S!3hf2h *?• product b«in« held have been exhausted 4
r.2i5iK ?i.2°!S °n' "°W h'U nust b< "•'Itt.n out 4
replaced with the new record now comina in »
writeln (outfile, prod[h]:lO, «pr[hl:l2:2, }
'1=2, «p[hl:13:4,
^ :s false;
num hi :* num hi + 1 ;
hold" :» prodCT];
naxx :a coat
if inflCh] a~0.0 then infcatCl] :s infcatCU + 1;
< 5.0)
< 1Q-0)
^^^H^W.U,-., ., TH^.P, =,
if
hf.*n[*^ ^* ^-^ then'infcatCS] :, infcat[3]
end
else if coat^incCi] > aaxx then
h :a i*WltCh r°C b'ln8 held to the new hi3h*'- an« >
naxx :a cost incCi];
end; ~
end;
Figure H-1 (continued)
H-27
-------
end;
for i :s 1 to 8 do
begin
percent[i]:» (infoat[i]/nunj_hi)»100;
end; ~
( Inflation counts will be printed next.}
writeln (outfile);
writeln (outfile);
writeln (outfile);
writeln (outfile, '
1 no. percent');
writeln (outfile, 'chemicals having 05 inflation s
infcatd]: 10, percentC 1J: 10:2);
writeln (outfila, 'chaaicals having 0.1'.to 1.91 inflation =
infcat[2]:10, parcentC2]:10:2);
writeln (outfile, 'chemicals having 2.0 to 2.95 inflation s
infcatC3]:10, percentC33'•'0:2);
writeln (outfile, 'chemicals having 3.0 to 4.9* inflation a
infea*[4]:lO, percentCU]: 10:2) ;•
writteln (outfile, 'chemicals having 5-0 to 9-9S inflation s
infeat[5J:10, percentCS]:10:2);
writeln (outfile", 'chemicals having 10.0 to 14.9J inflation =
infcatC6]:10, percentCol:10:2);
writeln (outfile, 'chemicals having 15.0 to 19-9X inflation =
infcatCTl:10, percenttT]:10:2);
writeln (outfile, 'chemicals having 20X or more inflation a
infcat[8]:10, percentCS]:10:2);
{all those product-processes which are not the
highest costs will be printed out next }
writeln (outfile)
writeln (outfile)
writeln (outfile)
writeln (outfile,
processes not selected');
writeln (outfile)
writeln (outfile)
writela (outfile, ' chem proc 1932 ailct S
' eff cst inc inflation1,
' capacity annual cost ');
writeln (outfile);
wriweln (outfile);
^for h :s 1 to (max - 1) do
begin
if notJiigCh] then
begin ~
writeln (outfile, prod[h]:10, mpr[h]:12:2,
coat ine[h]:13:2, inflCh]: 11:2, cap[h]:13:4,
tc [hi: 1V.1);
num lo :a num lo * 1;
end;
end;
jsna.
Figure H-1 (continued)
H-28
-------
B As described'in Section 9.2.2, when no information for
smallest plant capacity exists, the value is set to 23 Gg,
or the median of smallest existing capacities for the chemi-
cals with available data.
C When no price information exists for a specific chemical,
the value is set to 46
-------
Table H-4 • Reasonable Worst-Case Price Impacts
M
75.00 0.41 0.55 181.0000 750.7
2 5800 0-68 1-17 41.0000 148.1
3 9000 1.88 2.08 63.0000 42.7
i 106 00 2.58 2.43 9.0000 36.0
= ?i no 052 0.73 181.0000 35-7
6 gs'.OO l'-01 1.07 7.0000 38.1
I in! 00 0.00 0.00 11.0000 0.0
o 21 00 0.00 0.00 11.0000 0.0
10 1 00 0.63 0.57 37.4000 0.0
i ' 84 00 1.58 1.89 59.0000 0-0
i 4600 1.50 3.25 3.0000 44.9
4 77 00 0.00 0.00 195.0000 0.0
5 110 00 0.41 0.37 14..0000 35.9
6 99.00 3-27 3-30 5.0000 36.5
'" -n7 nn 0 42 0.39 9.0000 37-4
8 7200 O'.SI 0.58 9-0000 37.4
20 70 00 0.12 0.17 227.0000 0.0
ll 11200 4.65 4-15 5.0000 195-7
II 04 00 4.65 4.47 5.0000. 0.0
ll 56*^0 093 0.60 11.0000 37-7
ll 67 00 O.-OO 0.00 20.0000 0.0
27 67*00 1.50 2.23 3.0000 44.9
S S:JS 8:8 i!:8888 ° :
, -88 '8:?8 8:8°, t?:8888 38:
S 2:SS §:«' 'IiSSSS 5?:73
« 7?'00 0 18 0.23 31.0000 61.0
ll lunn 0 21 0-2" 36.0000 0.0
? ' 1 ^ g:S85°o S:J
: ' °2-09°4 ^ iS:SSS°o
J? 319*S§ O'.SO 0.16 23.0000 35.9
5J 3? 00 0 00 0.00 5.0000 0.0
£4 79iSo OIOO 0.00 11.0000 0.0
4^ 84 00 2.90 3.45 23.0000 ' 384.6
1? ' 251.00 0.00 0.00 23.0000 0.0
4ft 53 00 1-07 2.03 34.0000 365-3
Jl ":SS 0.90 2.24 136.0000 0.0
1 "^ ^ ?:9°a U:8°o55 3s :§
52 92:00 4.17 M.53 9-0000 374.9
H-30
-------
Table H-4 Continued.
*»
L M N 0 P Q
53 181.00 0.37 0.20 100.0000 368.6
54 174.00 3-23 1.86 45.0000 409.2
55 46.00 ' 0.00 0.00 23.0000 0.0
56 126.00 0.00 0.00 53.0000 0.0
58 55.00 1.39 2.53 35.0000 0.0
60 121.00 1.31 1.Q8 45.0000 0.0
61 137.00 1.67 1.22 23-0000 0.0
62 132.00 " 2.11 1.60 9.0000 53.4
63 98.00 2.61 2.66 37.4000 0.0
65 120.00 0.29 0.25 23-0000 67.8
66 84.00 1.66 1.97 23.0000 381.1
68 101.00 5.19 5.14 23.0000 615.1
69 101.00 1.66 1.64 23.0000 381.1
70 163-00 . 0.00 0.00 23.0000 0 0
71 462.00 0.00 0.00 23.0000 0.0
72 31.00 0.54 1.75 68.0000 369.6
73 61.00 11.72 19.21 45.0000 365.2
74 157.00 0.00 0.00 23.0000 0.0
75 53-00 0.00 0.00 27.0000 0.0
77 218.00 1.67 0.76 27.0000 37.0
78 205-00 2.03 0.99 ' 18.0000 0.0
79 46.00 0.00 0.00 23-0000 0.0
80 51-00 0.00 ' 0.00 11.0000 0 0
81 77.00 0.00 0.00 79-0000 • -0.0
82 64.00 0.00 0.00 27.0000 0.0
85 33.00 0.00 0.00 8.0000 0.0
86 . 101.00 0.73 0.72 18.0000 36.4
87 -101.00 0.56 0.56 102.0000 41 5
88 106.00 2.58 2.44 14.0000 285.5
89 93-00 1.81 1.94 23.0000 0.0
91 73-00 0.63 0.86 23.0000 0.0
92 97-00 0.75 0.78 1.0000 0.0
93 57.00 0.00 0.00 75.0000 0 0
94 53-00 0.00 0.00 45.0000 0 0
95 149.00 1.08 0.73 32.5000 0.0
9$ 77-00 1.87 2.43 54.0000 176.1
9J 93.00 0.62 0.67 23.0000 38.5
98 115.00 1.21 1.05 9.0000 37.4
99 71.00 1.36 1.92 16.0000 36.3
°2 88.00 0.22 0.25 25.0000 0.0
1°3 111.00 0.46 0.41 27.0000 37 0
]°5 139.00 1.21 0.87 25-0000 83.0
06 121.00 0.00 0.00 5.0000 0.0
08 20.00 0.35 1.73 27.0000 0.0
1°9 99.00 1.99 2.01 • 5.0000 0.0
0 101.00 0.76 0.75 5.0000 38.1
111 42.00 0.00 0.00 5-0000 0.0
112 34.00 0.00 0.00 14.0000 0.0
H-31
-------
Table H-4 Continued.
L M N 0 P Q.
114 190.00 1.94 1.02 159-0000 0.0
115 40.00 0.00 0.00 27.0000 0.0
116 92.00 1.69 1-84 23-0000 38.8
117 181.00 1.48 0.82 9-0000 37-4
118 100.00 1.64 1.64 -23-0000 129-5
119 132.00 2.32 1.76 14.0000 173-1
122 19.00 ' 0.00 0.00 23-0000 . 0.0
123 112.00 2.66 2.37 25-0000 38.7
124 46.00 1.49 3-23 23-0000 0.0
125 181.00 0.00 0.00 11.0000 0.0
126 106.00 0.74 0.69 159-0000 0.0
127 77.00 .0.00 0.00 36.0000 0.0
128 83-00 0.00 0.00 23-0000 0.0
129 84.00 0.35 0.42 23-0000 38.5
130 114.00 0.31 0.27 113-4000 0.0
132 46.00 0.00 0.00 23-0000 0.0
133 24.00 0.29 1-21 174.0000 505-3
135 269-00 0.00 0.00 27-0000 0.0
136 165.00 1.12 0.68 23-0000 43-7-
137 100.00 2.31 2.31 23-0000 43-7
138 53.00 0.35 - ' 0.65 ' 23-0000 79-7
139 71.00 0.00 0.00 5.0000 0.0
140 46.00 0.00 0.00 2-3000 0.0
141 46.00 0.00 0.00 23.0000 • 0.0
142 201-00 0.62 0.31 17-0000 105-0
143 196.00 0.59 0.30 34.0000 201.6
144 53.00 1.08 2.03 54.0000 0.0
145 134.00 2.05 1.53 45.0000 0.0
146 99.00 0.08 0.09 200.0000 169-6
148 108.00 3°75 3-47 7.0000 38-5
149 46.00 0.86 1.87 2.3000 0.0
150 95.00 0.61 0.64' 7-0000 42.5
151 22.00 0.00 0.00 23-0000 0.0
152 66.00 0.74 1.12 7-0000 38-5
153 159.00 1.60 1.01 2.3000 36.9
154 15.00 0.00 0.00 7.0000 0.0
156 137.00 1.62 1.18 54.0000 49-7
157 260.00 0.53 0.21 127-0000 0.0
158 48.00 0.00 0.00 3^.0000 0.0
159 108.00 0.78 0.72 127-0000 0.0
160 75.00 1.08 1-44 34.0000 35.8
161 84.00 0.25 0-30 21.5000 54.1
162 37.00 0.00 0.00 11.0000 0.0
163 112.0.0 0.71 0.63 5.0000 0.0
164 114.00 0.84 0.74 25.0000 0.0
165 97.00 0.00 0.00 11.0000 0-0
166 108-00 0-00 0.00 23-0000 0.0
168 70.00 0.84 1.20 50.0000 418-5
H-32
-------
Table H-4 Continued.
L M N 0 P Q
169 70.00 0.70 1-00 2.0000 0.0
171 100.00 0.00 0.00 23-0000 0.0
172 46.00 O'.OO 0.00 27-0000 0.0
173 79.00 1.54 1.95 34.0000 0.0
174 100.00 2.94 2.94 18.0000 214.8
175 79.00 0.25 0.32 21.5000 54.1
176 22.00 - 0.00 0.00 23-0000 0.0
177 97.00 0.07 0.07 23-0000 0.0
179 176.00 0.42 0.24 18.0000 0.0
181 92.00 0.51 0.55 29.0000 45.2
182 73.00 0.23 0.32 23-0000 53-2
183 • 66.00 2.48 3.76 25.0000 0.0
184 46.00 0.00 0.00 32.5000 0.0
185 99.00 0.00 0.00 113.0000 0.0
186 .115.00 0.00 0.00 18.0000 0.0
187 150.00 1.90 1.26 9-0000 37.4
188 123.00 0.55 0.45 9-0000 49-7
189 91.00 1-41 1.55 227-0000 50.8
194 46.00 0.00 0.00 23-0000 ' 0.0
195 42.00 0.00 0.00 4.0000 0.0
196 606.00 1.38 0.23 36.0000 37-5
197 91.00 3.20 3-52 23-0000 67-8
198 225.00 1.27 • 0.56 23.0000 67.8
199 364.00 0.92 0.25 27-0000 37-0
202 100.00 2.33 2.33 23-0000 381.1
203 • 77-00 8.55 11.11 91.0000 0.0
204 75-00 • 7-90 10.54 5-0000 373-1
205 68.00 1.08 1-59 54.0000 367-7
206 141.00 0.00 0.00 23-0000 0.0
207 68.00 0.00 0.00 16.0000 0.0
208 319.00 7.46 2.34 5.0000 372.9
209 194.00 0.00 0.00 5.0000 0.0
213 46.00 0.46 0.00 23.0000 0.0
214 46.00 0.64 0;00 23.0000 0.0
215 46.00 0.58 0.00 23-0000 0.0
216 112.00 1.35 1.20 4.0000 35-6
'220 115-00 0.30 0.27 37.4000 0.0
222 101.00 4.19 4.14 5-0000 • 45-7
237 40.00 0.10 0.26 25.0000 0.0
238 121.00 0.00 0.00 11.5000 0.0
239 100.00 1.82 1.82 23-0000 67.8
240 123.00 19.06 15.50 2.0000 371-8
248 46.00 0.00 0.00 23-0000 0.0
249 46.00 0.00 0.00 23.0000 0.0
250 46.00 0.00 0.00 23-0000 0.0
251 46.00 0.16 0.00 23-0000 0.0
252 46.00 0.00 0.00 23-0000 0.0
254 46.00 0.00 0.00 23-0000 0.0
257 46.00 0.00 0.00 23-OCOO 0.0
H-33
-------
Table H-4 Continued.
no'. percent
chemicals having 0% inflation = 67 35.45
chemicals having 0.1 to 1.9% inflation = 87 46.03
chemicals having 2.0 to 2.9% inflation = 16 8.47
chemicals having 3.0 to 4.9% inflation = 13 ' 6.88
chemicals having 5.0 to 9.9%- inflation = . 2 1.06
chemicals having 10.0 to 14.9% inflation = 2 1.06
chemicals having 15^0 to 19-9% inflation = 2 1.06
chemicals having 20% or more inflation = 0 0.00
H-34
-------
N Effective cost increase in
-------
r\jroro-»->-»-i-»
Ooro—»OOOll\)—»OvOO\O14rfO
_»_»_» i\j -»-*-»-» _*_*_» _._.
o o OLO -» o»u> o\roLooi 4=^iu3 jrooco-^-j iv) .-4 o -»-g -» 4= oo -* rovo-i
r-><-»r->noooooooooooooooooooooooooooooooooooooooooooo a:
§00000000000000000000000000000000000000000000000 ^
o
n
ooooooooooooooooooo-^ooooooro-'oooooooooopppppppppp n>
§^ z
o
0000000000000000000-'000000-*-'OOOOOOOOpppppppppppp
bbbbo-»voooi\jooooi-»o-JOJroooooooooojoroo-'OO
OU)VOOOOOOO-~JOOC»OOOO-~1OI\JO—JOOOOOOOO4=v£)OvOU>OlOO
OOOGJOOOOlOlOOOOO-'VOOOIXJOOOOl-'O-lO-tOOOOOOOOOOJOfOO-'OO O
^.•.,i.i/^^^i.ii/^r^r^r->/--»r-»r->-jr-i<-inor-iC>C>ri-JOIV)O-JOOOOOOOO4=-vOOvOU>OlOO
T)
o
(D
_ ^
ro -»-»-» -» 4= cr> ro -* ro u> ro -* co -* a\ ro roco -» 01 -» ro -» <& ro -t cx>
ru
b b bbb o oo o o o o o o o o o ooo o oo o o o o o o o o o o
000000000000000000000000000000000000000000000000
• -I UOCO 4=
Uj VO 01 Ul ON CJOCO -
in o\ as cr»— »— «cn— » — ~
4r IU-JO
0, CAJ «£>--> ro o vo
OOOO\OOfOOOOOOOOOOOOrOOOOOOOOO4=OrOOOOOOOOOOOOOOO\ONONOO
bbbbbbbbbbbbbboooooooooooooooooooooooooooooooooo
oooooooooooooooooooooooooooooooooooooooooooooooo
-------
Table H-5 Continued.
L M N 0 P Q
127 77.00 0.00 0.00 36.00 0.00
128 83.00 0.00 0.00 23-00 0.00
129 84.00 0.13 0.15 23-00 0.00
132 46.00 0.00 0.00 23-00 0.00
133 24.00 0.00 0.00 174.00 0.00
135 269.00 0.00 0.00 23-00 0.00
136 165-00 0.53 0.32 23-00 0.00
137 100.00 1.20 1.20 23-00 0.00
142 201.00 0.62 0.31 17-00 105019-00
143 196.00 0-34 0.17 80.00 269986.00
144 53.00 0.00 0.00 54.00 0.00
146 99.00 0.05 0.05 322.00 172896.. 00
149 46.00 0.00 0.00 5--00 0.00
151 22.00 0.00 0.00 23-00 0.00
153 159-00 0.78 0.49 5-00 38832.00
154 15.00 0.00 0.00 7-00 0.00
156 137.00 0-06 0.05 95-00 59394.00
158 48.00 0.00 0.00 34.00 0.00
159 108.00 0.54 0.50 23-00 0.00
160 75-00 0.03 0.03 153-00 39256.00
162 37-00 0.00 0.00 11.00 0.00
163 112.00 0.00 0.00 5-00 0.00
164 114.00 0.11 0.10 23-00 0.00
168 70.00 0.58 0.82 204.00 1174592.00
169 70.00 0.48 0.69 2.00 0.00
173 79.00 0.00 0.00 34.00 0.00
174 100.00 1.22 1.22 18-00 214784.00
176 22.00 0.00 0.00 23-00 ' 0.00
177 97.00 0.04 0.04 23-00 0.00
182 73-00 0.08 0.11 206.00 169733-00
133 66.00 0.00 0.00 25.00 0.00
184 46.00 0.00 0.00 23-00 0.00
186 115.00 0.00 0.00 18.00 0.00
187 150.00 0.12 0.08 35.00 43548-00
188 123-00 0.23 0.19 43-00 99742.00
189 91-00 0.20 0.22 18.00 36392.00
194 46.00 0.00 0.00 48.00 0.00
195 42.00 O-.OO 0.00 41.00 0.00
204 75.00 0.87 1.16 45-00 390885-00
206 141.00 0.00 0.00 23-00 0.00
208 319.00 2.10 0.66 18.00 378900.00
209 194.00 ' 0.00 0.00 5.00 0.00
239 100.00 1.03 1-03 23.00 67840.00
248 46.00 0.00 0.00 23-00 0.00
250 46.00 0.00 0.00 23-00 0.00
252 46.00 0.00 0.00 23-00 0.00
257 46.00 0.00 0.00 23-00 0.00
H-37
-------
Table H-5 'More Likely Case Price Impacts
number
number
number
number
number
number
of
of
of
of
of
of
chemiclas having Q% inflation
chemicals having 0 to 0.9? inflation
chemicals having 1 to 1.9% inflation
chemicals having 2 to 2.9% inflation
chemicals having 3 to U.9% inflation
chemicals having 5% or more inflation
52
36
7
0
0
0
H.38
-------
Table H-6 Quantity and Distributive Impacts Input File 1
V
71 7 23 23
1?3 772
II 143 10 - 63 68
II 69 17 36 36
II 52 3 18 18
65 52 13 18 18
77 52 7 13 18
99 4843 2345 318 2544
119 719 259 236 472
123 26 15 7 21
142 52- 8 17 J7
;43 324 63 80 80
1« ' . 'Ig? 6§g ' 322 644
156 590 304 95 3ao
160 600 119 153 15?
168 266, 54, 2oj 6,
•is? ??? 3^ -^ ^
138 167 53 to |§
189 52 9 13 lg
204 116 30 45 45
239 If 1 ^ "8
239 52 8 ir 11
H-39
-------
Table H-7 Quantity and Distributive Impacts Input File 2
W X Y Z AA
ii 106.00 0.16 0.15 37036.0
5 71.00 0.02 0.03 35776.0
6 95.00 0.28 0-29 41256.0
45 84.00 0.61 0.72 411492.0
52 92.00 1-07 1-17 386904.0
54 174.00 2.61 1-50 381820.0
65 120..00 0.34 0.28 61270.0
77 218.00 ' 0.22 0.10 36392.0
qq 71.00 0.02 0.02 S&332.0
lie 132.00 0.17 0.13 396356.0
i2? 11-2.00 0.51 0.46 35780.0
142 201.00 0.62 0.31 105019-0
•HH 196.00 0.3-4 % 0.17 269986.0
145 99.00 0.05 0.05 172896.0
53 159.00 0.78 0.49 38832.0
56 137.00 0.06 0.05 59394.0
160 ' 75.00 0.03 0.03 39256.0
168 70.00 0.58 0.82 1174592.0
74 100.00 1-22 1.22 214784.0
182 • 73.00 0.08 0.11 169783.0
87 150.00 0.12 0.08 43548.0
188 123.00 0.23 0.19 9?I4?'2
iflQ 91.00 0.20 0.22 36392.0
204 75.00 0.87 1.16 390885.0
208 319.00 2.10 ' 0.66 378900.0
239 100.00 1.03 1-03 67840.0
H-40
-------
Quantity and Distributive Impacts Input File 2 (Table H-7)
W Chemical number.
X This number is the market price in cents per kilogram (
-------
000000 00 00 00 GO*- 00 ino 00 00 000
,
o t- o c\ =t vo in ir> in rr r- CM m rvi oo oo cr> o vo in oo «- MD in r- in in co
r; ^Jrj,::,- oo t- mm^-in^vo CT>'-«- «- 5:
_ r- ^ CM
CO
vo t-cr> ^-CM =r
-------
Table H-9 Distributive Impacts Output File
GG HH TT
J 51.5
5 552.8
° 76.0
54 36.7
65 ' 36.7
77 36.7
99 2680.6
119 317.8
123 8.2
1*2 37.5
143
-153
156 267.0
160 469.9
174 2136[?
182 811.9
187 88-3
183 • 99.0
189 36.7
H-43
May 22, 1985
JJ
1610.26
185.37
2750.40
6051.35
10747.33
21212.22
3403.89
2021.78
177.14
1679.47
5111.43
6177.59
3374 . 82
536.94
7766.40
625.20
256.58
5757.80
1 1 932 . 44
824.19
1244.23
2493-55
2021.78
8686.33
21050.00
82847.9
102471 .4
209030.4
515575.3
412697.6
778488:6
124922.7
74199.2
474854.0
533737.0
41658.1
231968.4
863955.2
451892.2
3471580.8
166928.4
120577.5
12326306.6
437920.7
669159-3
109803.2
246861.4
74199.2
675362.4
772535.0
. . .
239 42.7 6167.27 263034.2
-------
JJ This number is the distributional impact given in dollars.
It is calculated by multplying the direct change in price by
the production in 1990 from existing facilities.
H.6 PROCESS ROUTES
Figure H-2 describes the maximum cost production process routes
selected by the screening model for all 173 reactor processes chemicals
and for all intermediate chemicals.
.For each chemical, the figure shows the chemical ID number in the
middle of the page, and its common name on the right side (see Table H-l).
On the left side are the input or inputs that are used to make each
chemical. In two cases there are three inputs that combine to form a
chemical, but most often there are only one or two. An example of the
process route figure will illustrate what each of the elements represents.
Example 1 -
1.00 0.50 1.75
xx > yy > zz >
1.10 0.90 10 Name
x > y >
Chemicals zz and y are the direct inputs into chemical ID.
Chemicals xx and yy, and x, are upstream inputs in the production of
chemicals zz and y, respectively. The numbers above each input line
( >) represent the input ratio units of the preceding chemical into
the one that follows. The input ratio kilogram is the amount of input
chemical needed to produce 1 unit of the chemical produced. For
example, 1.75 units of chemical zz when combined with 0.90 units of
chemical y wi.ll form 1 unit of chemical ID.
In Figure H-2, as in this example, inputs are traced upstream for
up to three stages. For most chemicals the upstream process route has
no more than three stages. In a few cases there are further chemicals
upstream that feed into the initial chemical, which is xx in the
example route. Chemicals that have more than three process stages are
footnoted with an asterisk. To find the remaining upstream process
stages, locate the process route for the chemical next to the asterisk.
As in other listings, the chemicals are ordered by ID number
ranging from 1 to 257. There are several missing numbers. These
numbers have either not been assigned to a chemical or have been
assigned to a chemical that is not produced by reactor processes or is
not an intermediate in the production of a reactor process chemical.
H-44
-------
Process Route
Chemical ID Common Name
0.71
94 >
ACETALDEHYDE
0.71 0.77
> 1 >
ACETIC ACID
0.7-1' 0.77 1.40
94 > 1 > 2 >.
0.77 1.59 0.79
* 1—-> 2 > 95 >
ACETIC ANHYDRIDE
0.71 0.77 0.54
94 > 1 > 2 >
0-75 1.03 0.71
184 > 28 > 34 >-
N-BUTYL ACETATE
0.71 0.77. 0.73
94 > 1 > 2 >-
0.37
94 >'
VINYL ACETATE
0.71 0.77 0.69
94 > 1 > 2-—>.
0.61 0.59
. . 94 > 93 >'
ETHYL ACETATE
1.18
94 >
1.29
94——>
1.00 0.75
94 >168
10
ALCOHOLS, C-1-1 OR LOWER,
MIXTURES
ALCOHOLS, C-12 OR HIGHER,
MIXTURES
ETHANOLAMINE
0.65 1.47
12 >160
11
ANILINE
Figure H-2 Production Process Routes
H-45
-------
Process Route
Chemical ID Common Name
no inputs for chemical # 12
BENZENE
5.56 0.67
79 > 82 >
TEREPHTHALIC ACID
4.55 0.98 0.39
.79—-> 80 >127 >•
0.75 1-23 0.70
184 > 28 >102 >'
15
DIOCTYL PHTHALATE
0.75 1-03 0.26
184 >-28 > 34 >
0.80 0.45
135 > 52 > -16
4.55 0.98 0.53
79 > 80 >127 >'
BUTYLBENZYL PHTHALATE
1.29 1-18
94 > 9 ->•
4.55 0.98 0.29
79 > 80 >127 >'
DI-N-HEPTYL-N-NONYL
UNDECYL PHTHALATE
4.55 0.98 0.34
79 > 80 >127 >
1.21 1.25 0.75
84 >152 >128 X
18
DIISODECYL PHTHALATE
5.56" 0.61
79 > 82 >
0.56 0.40
132 >133
20
DIMETHYLTEREPHTHALATE
0.49
12 > 21
BENZENESULFONIC ACID
Figure H-2 Production Process Routes
H-46
-------
Process Route
Chemical ID Common Name
0.49 1.00
12 > 21 >
0.71 0.40
94 > i >.
0.56 1.19 1.22
132 > 133 > 108 >'
22
no inputs for chemical #
no inputs for chemical
1.19
41 •->
0.75 • 0.91 1.24
184 > 28 >251 >
0-77 1.59 0.30
*1 > 2 > 95 >•
25
1.93
29 > 26
1.35
39 > 26
1.80
29 > 27
0.75
184 > 28
29
30
32
33
BENZENESULFONIC ACID, MONO-
C10-16-ALKYL DERIVATIVES,
SODIUM SALTS
PENTAERYTHRITOL
BIVINYL
BIVINYL
BUTADIENE and BUTENE FRACTIONS
BUTYRALDEHYDE
N-BUTANE
BUTANES, MIXED
1,4-BUTANEDIOL
BUTYRIC ANHYDRIDE
0.75 1.03
184 > 28 > 34
N-BUTYL ALCOHOL
Figure H-2 Production Process Routes
H-47
-------
Process Route
Chemical PD Common Name
1.00 0.90
94 > 37 > . 35
SEC-BUTYL ALCOHOL
1.00 0.90 1.17
94 > 37 > 35 > 36
METHYL ETHYL KETONE
1.00
94——> 37
A-BUTYLENE
1.00- 1.15
94 > 37 > 38
no inputs for chemical # 39
B-BUTYLENE
BUTYLENES (MIXED)
0.75 1.03 0.90
184 > 28 > 34 >
1.00 0.59
94 >168 >
BUTYL CELLUSOLVE
2.82 0.43
175 >1Q6
0.56 1.19 1-00
>133 >108
2-BUTYNE-1,4-DIOL
1.00 1.00
132 ---- >248— ->
42
-CARBAMIC ACID MONOAMMONIUM SALT
0.23
132 ---- >
43
CARBON DISULFIDE
1.00 1.00
132 >249
44
PHOSGENE
0.82
12 > 45
CHLOROBENZENE, MONOMER
0.33 0.43 1.10
132 > 50 >207 >
FREON 22
Figure H-2 Production Process Routes
H-48
-------
Process Route Chemical ID Common Name
0.61 0.75
94 > 93—-_> 43
ETHYL CHLORIDE
0.31 1.65
94 > 72—--> 49
VINYL CHLORIDE
0.33
132 > 51
METHYL CHLORIDE
0.56 0.68
132 >133——> 51
METHYL CHLORIDE
0.80
135 > 52
BENZYL CHLORIDE
0.74 1.08
184——> 56 > 53
EPICHLOROHYDRIN
0.82 0.80
12 > 45 > 54
P-CHLRONITROBENZENE
0.64
184——> 55
PROPYLENE CHLOROHYDRIN
0.74
184 > 56
ALLYL CHLORIDE
0.93
12 > 58
CYCLOHEXANE
0.93 0.94
12 > 58 > .60
CYCLOHEXANE, OXIDIZED
0.93 1.20
12——> 58 > 61
CYCLOHEXANOL
0.93 1.20 0.84
12 > 58 > 61 > 62
CYCLOHEXANONE
Figure H-2 -Production Process Routes
H-49
-------
Process Route
Chemical ID . Common Name
1.20 0.84 '1.24
53 > 51 > '62 > 63
CYCLOHEXANONE OXIME
1.00 1.00
176 >250 > 65
TRIMETHYLENE
0.17
.94 > 66
ETHYLENE DIBROMIDE
1.93 0.94 1.52
29 > 26 > 69 > 68
1 ,4-DICHLOROBUTENE
1.93 0-94
29 > 26 > 69
3,4-DICHLORO-1-3l)TENE
0.11 1.33
132 >195 > TO
FREON 12
0.33 1.12
132 > 50 > 7-1
DIMETHYLDICHLOROSILANE
0.31
94 > 72
ETHYLENE DICHLORIDE
0.31 0.81 1-38
94 > 72 >204 > 73
VINYLIDENE CHLORIDE
0.33 0.43 1.45
132 > 50 >207 > 74
FREON 21
0.33 0.61
132 > 50 > 75
METHYLENE CHLORIDE
0.30
94 >
1.12
99 >'
77
DIETHYLBENZENE
Figure H-2 Production Process Routes
H-50
-------
Process Route
1.00 1.00 1.43
132 >249 > 44 >
0.53 3-57 0.88
135—-> 143 >137 >
Chemical ID Common Name
73
TOLUENE-2,4-(and 2,6)-
DIISOCYANATE (80/20 MIXTURE)
no inputs for chemical // 79
XYLENES (MIXED)
4.55
79 > 30
0--XYLENE
2.50
79 >
81
M-XYLENE
5-56
79 > 82
P-XYLENE
1.27
184 > 85
DODECENE
'0.35
12 >
1.27 0.76
184 > 85 >
86
DODECYLBENZENE, LINEAR
0.35
12 >
1.27 0.76
184 > 85 >
87
DODECYLBENZENE, NONLINEAR
0.75
86 >
DODECYLBENZENESULFONIC ACID
0.75 0.70
86 > 88 > 89
1.00 0.75
94 >168 > 91
DODECYLBENZENESULFONIC ACID
SODIUM SALT
ETHYLENE GLYCOL
Figure H-2 Production Process Routes
H-51
-------
Process Route
Chemical ID Common Name
1.00 0.90
94 >168 >> 92
TRIETHYLENE GLYCOL
0.61
94 > 93
ETHYL ALCOHOL
no inputs for chemical # 94
ETHYLENE
0.71 0.77 1.59
94 > 1 > 2 >
95
KETENE
1.13
99 >
96
STYRENE
0.61 0.57
94 _> 93 >^^
1.00 0.54 ./
94 >168 >
97
ETHYLENE GLYCOL MONOETHYL
ETHER
0.71 "0.77 0.48
94 > 1 > 2 >
0.76
97 >
98
ETHYLENE GLYCOL MONOETHYL
ETHER ACETATE
0.76
12 >
. 0.28
94 >
99
ETHYLBENZENE
0.75 1.23
184 > 28 > 102
2-ETHYLHEXYL ALCOHOL
0.75 '1.23 1.44
184 > 28 >102 > 103
(2-ETHYLHEXYL) AMINE
0.64
99 >
4.55 0.98 0.90
79 > 80 >127 >
105
6-ETHYL-1,2,3,4-TETRAHYDRO-
9-10-ANTHRACENEDIONE
Figure H-2 Production Process Routes
H-52
-------
Process Route
Chemical ID Common Name
2.82
176 > 106
ACETYLENE
4. 10
132 > 106
ACETYLENE
0.56 1.19
132 >133 > 108
FORMALDEHYDE
1-33
12 > 109
no inputs for chemical # 110
MALEIC ANHYDRIDE
SORBITOL
no inputs for chemical # 111
N-HEPTANE
0.79
39 > 112
HEPTENES (MIXED)
1.70
184 > 112
HEPTENES (MIXED)
1.20 0.84 0.92
*58 > 61 > 62 > 114
no inputs for chemical # 115
CAPROLACTAM
HEXANE
1.80 . 0.72 0.93
29 > 27 >118 > 116
1 ,6-HEXANEDIAMIN-E
0.72 0.93 0.63
* 27 >118 >116 >
0.80
120 >
:117
1,6-HEXANEDIAMINE ADIPATE
Figure H-2 Production Process Routes
H-53
-------
Process Route
Chemical ID Common Name
1.30 0.72
29 > 27 > 118
ADIPONITRILE
0.93 0.78
12 > 58 > 119
ADIPIC ACID
0.79
132 > 122
HYDROCYANIC ACID
2.30 1.01
144 >183 > 123
DIACETONE ALCOHOL
2.30 0.60
144 >183 > 124
ACETONE CYANOHYDRIN
no inputs for chemical # 125
CITRIC ACID
1.00 0.88
94 >168 > 126
DIETHANOLAMINE
4.55 0.98
79 > 80 > 127
PHTHALIC ANHYDRIDE
1.21 1.25
184 >162 > 128
ISODECYL ALCOHOL
1.29 0.93
94 > 9 >
1.00 0.22
94 >168 >
129
LINEAR ALCOHOLS, ETHOXYLATED,
MIXED
0.87
129 > 130
no inputs for- chemical # 132
0.56
132 > .133
LINEAR ALCOHOLS, ETHOXYLATED
and SULFATED, SODIUM SALT
MIXED
METHANE
METHANOL
Figure H-2 Production Process Routes
H-54
-------
Process ' Route
Chemical ID Common Name
no inputs for chemical # 135
TOLUENE
0.53 1.57
135 >1U3 > 136
TOLUENE-2.2-DIAMINE
0.53 3-57
135 >143 > 137
ar-METHYLBENZENEDIAMINE
1.30
141 > 138
no inputs for chemical # 139
no inputs for chemical # 140
ISOPRENE
ISOPENTANE
AMYLENE
no inputs for chemical # 141
AMYLENES, MIXED
0.53
135--—> 142
0.53
135 > 143
284-(and 2,6)-DINITROTOLUENE
2,4-DINITROTOLUENE
0.72
12 >
1.17
184 >
144
CUMENE
0.80 1.79 0.88
*144- >149 >173
2.30 0.28
144 >183—.-
145
BISPHENOL A
0.64 1.47
184 > 55——> . 146
PROPYLENE OXIDE
.Figure H-2 Production Process Routes
H-55
-------
process Route
Chemical ID Common Name •
2.30 1.29
144 >183 > 148
2-METHYLPENTANE
0.80
144 > 149
CUMENE HYDROPEROXIDE
0.75
"184 > 150
ISOBUTYRALDEHYDE
1.15
29 > 151
ISOBUTANE
0.75 1.03
.184 > 28 > 152
ISOBUTYL ALCOHOL
0.92
154 > 153
tert-BUTYL ALCOHOL
no inputs for chemical # 154
ISOBUTYLENE
0.79 0.27
132 >122
0.56 0.32
.132—~> 133 > 156
2.30 0.58
144 >183
METHYL METHACRYLATE
1.19 0.72
41 > 32 > 157
1-METHYL-2-P"YRROLIDONE
no inputs for chemical # 158
NAPTHENE
1.00 0.93
94 >168 > 159
TRIETHANOLAMINE
0.65
12 > 160
NITROBENZENE
Figure H-2 Production Process Routes
H-56
-------
Process Route
Chemical ID Common Name
1.00
254 > 161
NONYL ALCOHOL
1.21
134 > 162
TRIPROPYLENE
1.21 0.76
134 >162 > ^^
0.80 1.79- 0.46 .X
*144 >149 >173 >
153
NONYLPHENOL
0.96
163 >
1.00 0.19
94 >168—.—>
164
NONYLPHENOL, ETHOXYLATED
1.00
39 > 165
OCTENE
no inputs for chemical * 166
OIL SOLUBLE PETROLEUM SULFONATE
1.00
94 > 168
ETHYLENE OXIDE
1.00 0.84
94 >168 > 169
DIETHYLENE GLYCOL
1.93 0.96
29 > 26 > 171
3-PENTENENITRILE
no inputs for chemical # 172
PENTENES, MIXED
0.80 1.79
144 >149 > 173
PHENOL
1.28
99 -> 174
1-PHENYLETHYL HYDROPEROXIDE
Figure H-2 Production Process Routes
H-57
-------
Process Route
Chemical ID Common Name
no
0.60
94 > 175
inputs for chemical # 176
PROPAHAL
PROPANE
0.64 1.47 0.77
.184 > 55 >146 > 177
PROPYLENE GLYCOL
0.74 1.08 1.15
184 > 56 > 53 > 179
GLYCEROL
0.60 1.40
94 >175 > 181
PROPYL ALCOHOL
0.85
184 > 182
ISOPROPYL ALCOHOL
no
2.30
144 > 183
inputs for chemical # 184
ACETONE
PROPYLENE
1.25
184 > 185
ACRYLONITRILE
0.83
184 > 186
ACRYLIC ACID
. 0.75 1-03 0-58
184 > 28 > 34 >
0.83 0-57
184 >186 >
187
BUTYL ACRYLATE
0.61 0.48
94 > 93 >
2.82 0.32
176 >106 >
188
ETHYL ACRYLATE
Figure H-2 Production Process Routes
H-58
-------
Process Route
Chemical ID Common Name
0.93
12 >
0.50
184 >
189
PHENYLPROPANE
0.21
132 > 194
0. 11
132 > 195
0.61 0.75 1.19
( > 93—-> 48 > 196
0.93 1.20 1.74
12 > 58 > 61 > 197
1.19 1.31
41 > 32 > 198
0.61 0.75 0.73
94—•-> 93 > 43 > 199
0.33 1.14
132 > 50 > 200
2.30 0.27
144 >183 > 202
0.81 1.38 0.73
*72 >204 > 73 > 203
0.31 0.81
94 > 72 > 204
'.0.31 0.74
94 > 72 > 205
PERCHLOROETHYLENE
CARBON TETRACHLORIDE
TETRAETHYL LEAD-
CYCLAHEXANE
TETRAHYDROFURAN
TETRA (METHYL-ETHYL) LEAD
TETRAMETHYL LEAD
BROMETONE
METHYL CHLOROFORM
VINYL TRICHLORIDE
TRICHLOROETHYLENE
Figure H-2 Production Process Routes
H-59
-------
Process Route Chemical ID Common Name
0. 11 1-17
132 >195 > 206
FREON 11
0.33 0.43
132—-> 50 > 207
CHLOROFORM
0.79 1-00 1.00
132 >122 >257 > 208
CYANURIC CHLORIDE
0.21 0.98
' 132 >194 > 209
FLOUROCAR30N 113
0.71 1.11
94 > 1 > _ 213
ACETALDOL .
0.71 1.11 1^0
94 > 1 >213 > 214
CROTONALDEHYDE
1.11 1.UO 0.90
*1 >213 >214 > 215
CROTONIC ACID
0.56 1.19 1-32
132 >133 >108 > 216
HEXAMETHYLENE TETRAAMINE
0.56 1.05
132 >133 > 220
METHYLAMINE
2.30 1-32
144 >183 > 222
MESITYL OXIDE
0.56 0.36
132 >133 >
0.64
154 >
:237
METHYL tert-BUTYL ETHER
1.29 1.00
94 >• 9——> 238
ALCOHOLS, C-12 or higher, UNMIXED
Figure H-2 Production Process Routes
- H-60
-------
Process Route
Chemical ID Common Name
0.92 0.95
154 >153 > 239
0.71 0.77 0.69
94——> i > 2 > 240
1.00
132 > 248
1.00
132 > 249
1.00
. 176 > 250
0.75 0.91
184 > 28- > 251
1.00
132 > 252
no inputs for chemical # 254
0.79 1.00
132—.—>122 > 257
tert-BUTYL HYDROPEROXIDE
CHLOROACETIC ACID
CARBON DIOXIDE
CARBON MONOXIDE
1,3 DICHLOROPROPANE
BUTYRIC ACID
.SYNTHESIS GAS
DIISOBUTENE.
CYANOGEN CHLORIDE
Figure H-2 Production Process Routes
H-61
-------
1. MIPOftT NO.
EPA 450/3-90-Q16a
,„ TECHNICAL REPORT DATA
irtMM n»d titnncnotu OH tin rmnt I*fort eomfitttng
4. TtTU* ANO SU«TITU
Reactor Processes in Synthetic Organic Chemical
Manufacturing - Background Information for Proposed
Standards
3. MICimiNT-3 ACCUSION NO.
«. MHPOMMINO OHOANIZAT1ON HWOHT NO.
0. ftHFQKMINQ ORGANIZATION MAMI AND AQOMIM
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
ta. SFONSOHINO AGCNCY NAMC ANO AOO««S»
Oirector, office of Air Quality Planning and Standards
Office of Air and Radiation
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
•. MCPOftT OATI
June 1990
'INFORMING OHOAMIZATIONCOoT*
13. TYf»t O* MIPOHT ANO PtfllOO COVSHiO
4. SPON40MINO AQINCV COO«
EPA/200/04
impacts associated with the regulatory alternatives.
environmental
Standards of performance for the control of volatile organic compound fvoci em«-
from new, modified, and reconstructed reactor process units used in the manufacturp of
synthetic organic chemicals are being proposed under Sectiorv 111 of the 3S ^ Air let
This document contains background information on the industry and processes concerned
and environmental and economic impact assessments of the regulatory alternatives
considered i-n developing the proposed standards. egu.atory alternatives
*IV *0a0t MO OOCUMBNT ANALYSH
Air pollution
Pollution control
Standards of performance
Volatile organic compounds
Organic chemical industry
••«. OiSTHliUT.QN STAT«MtNT
Unlimited
S?* Pm IJ20.J (He,. 4.77}
Air pollution control
13B
-------
U.S. Environmental Protection Agency
Region 5, library (PI-12J)
77 West Jackson Boulevard, 12th Float
Chicago, !l 60604-3590
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