&EPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-84-015
December 1984
Air
Guideline Series
Control of Volatile
Organic Compound
Emissions from Air
Oxidation
Processes in
Synthetic Organic
Chemical
Manufacturing
Industry
-------
EPA-450/3-84-015
Guideline Series
Control of Volatile Organic Compound
Emissions from Air Oxidation Processes in
Synthetic Organic Chemical
Manufacturing Industry
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
December 1984
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GUIDELINE SERIES
The guideline series of reports is issued by the Office of Air Quality Planning and Standards (OAQPS) to provide
information to state and local air pollution control agencies; for example, to provide guidance on the acquisition and
processing of air quality data and on the planning and analysis requisite for the maintenance of air quality. Reports
published in this series will be available as supplies permit - from the Library Services Office (MD-35), U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina 27711, or for a nominal fee, from the National
Technical Information Service, 5285 Port Royal Road, Springfield, Virginia 22161.
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TABLE OF CONTENTS
Chapter Page
LIST OF TABLES x
LIST OF FIGURES xiii
CHAPTER 1 - INTRODUCTION 1-1
1.1 REFERENCES FOR CHAPTER 1 1-2
CHAPTER 2 - THE AIR OXIDATION INDUSTRY .2-1
2.1 GENERAL 2-1
2.2 INDUSTRY STRUCTURE 2-1
2.2.1 Air Oxidation Chemicals 2-1
2.2.2 Uses of Air Oxidation Chemicals 2-3
2.2.3 Companies and Production of Air Oxidation
Chemicals 2-3
2.2.4 Location of Air Oxidation Plants 2-3
2.3 AIR OXIDATION PRODUCTION PROCESSES 2-18
2.3.1 Reaction Types 2-18
2.3.2 Raw Materials 2-21
2.3.3 Reaction Characteristics 2-24
2.3.3.1 Reaction Stoichiometry 2-24
2.3.3.2 Reaction Phase 2-24
2.3.3.3 Explosion Hazard 2-28
2.4 STATISTICAL ANALYSIS OF AIR OXIDATION PROCESSES 2-28
2.4.1 National Emissions Profile 2-30
2.5 REFERENCES FOR CHAPTER 2 2-33
m
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TABLE OF CONTENTS (Continued)
Chapter Page
CHAPTER 3 - EMISSION CONTROL TECHNIQUES 3-1
3.1 INTRODUCTION 3-2
3.2 ADSORPTION 3-2
3.2.1 Carbon Adsorption Process 3-6
3.2.2 Carbon Adsorption Emissions Removal
Efficiency 3-6
3.2.3 Parameters Affecting VOC Removal
Efficiency 3-6
3.2.4 Factors Affecting Applicability and
Reliability 3-6
3.3 ABSORPTION 3-8
3.3.1 Absorption Process 3-8
3.3.2 Absorption VOC Removal Efficiencies 3-10
3.3.3 Factors Affecting Efficiency and
Reliability 3-10
3.4 CONDENSATION 3-10
3.4.1 Condensation Process 3-13
3.4.2 Condenser VOC Removal Efficiency 3-13
3.4.3 Parameters Affecting Reliability
and Efficiency 3-13
3.5 CONTROL BY COMBUSTION TECHNIQUES 3-13
3.5.1 General Combustion Principles 3-15
3.5.2 Combustion Control Devices 3-15
3.5.3 Thermal Oxidizers 3-15
3.5.3.1 Thermal Oxidation Process 3-15
3.5.3.2 Thermal Oxidizer Design 3-18
3.5.3.3 Thermal Oxidizer Emission
Destruction Effectiveness 3-20
3.5.4 Catalytic Oxidizers 3-21
3.5.4.1 Catalytic Oxidation Process 3-21
iv
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TABLE OF CONTENTS (Continued)
Chapter Page
3.5.4.2 Catalytic Oxidizer Emission
Reduction Effectiveness 3-21
3.5.4.3 Parameters Affecting VOC
Destruction Efficiency 3-21
3.5.5 Advantages and Disadvantages of
Control by Combustion 3-24
3.6 STATE REGULATIONS FOR VOC CONTROL 3-24
3.7 TECHNICAL FEASIBILITY OF RETROFITTING
CONTROL DEVICES 3-24
3.8 REFERENCES FOR CHAPTER 3 3-26
CHAPTER 4 - ENVIRONMENTAL ANALYSIS OF REASONABLY
AVAILABLE CONTROL TECHNOLOGY (RACT) 4-1
4.1 RACT RECOMMENDATION 4-1
4.2 AIR POLLUTION 4-3
4.3 WATER POLLUTION 4-6
4.4 SOLID WASTE DISPOSAL 4-7
4.5 ENERGY 4-7
4.6 REFERENCES FOR CHAPTER 4 4-8
CHAPTER 5 - CONTROL COST ANALYSIS OF RACT 5-1
5.1 INTRODUCTION 5-1
5.1.1 Substitution of National Profile for
Model Plant 5-1
5.1.2 Thermal Oxidation Design Categories 5-1
5.1.2.1 Categories Al and A2 5-1
5.1.2.2 Category B 5-3
5.1.2.3 Category C 5-3
5.1.2.4 Category D 5-3
5.1.2.5 Category E 5-3
5.1.2.6 Maximum Equipment Sizes 5-4
5..1.3 Offgas Composition Assumptions 5-4
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TABLE OF CONTENTS (Continued)
Chapter Page
5.2 BASIS FOR CAPITAL COSTS 5-4
5.2.1 Common Control Equipment 5-9
5.2.1.1 Thermal Oxidizer 5-9
5.2.1.2 Ductwork 5-9
5.2.1.3 Fans 5-12
5.2.1.4 Stack 5-12
5.2.2 Categories Al and A2 5-12
5.2.2.1 Waste Heat Boiler 5-12
5.2.2.2 Scrubber 5-12
5.2.2.3 Quench Chamber 5-12
5.2.3 Category B - 5-12
5.2.4 Category C 5-13
5.2.5 Category D 5-13
5.2.6 Category E 5-13
5.3 BASIS FOR ANNUALIZED COSTS 5-13
5.3.1 Fuel Requirements 5-17
5.4 EMISSION CONTROL COSTS 5-18
5.4.1 Major Contributing Factors to
Control Costs of Typical Streams 5-18
5.4.2 Variation of Control Costs with
Changes in Offgas Parameters 5-18
5.5 COST EFFECTIVENESS 5-20
5.5.1 Variation of Cost-Effectiveness with
Changes in Offgas Parameters 5-20
5.5.2 Total Resource-Effectiveness (TRE)
Index. 5-22
5.5.3 TRE Index Cutoff Value and Impacts
of the RACT Recommendation 5-24
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TABLE OF CONTENTS (Continued)
Chapter Page
5.6 REFERENCES FOR CHAPTER 5 5-26
APPENDIX A: EMISSIONS SOURCE TEST DATA A-l
A.I VOC EMISSIONS TEST DATA A-l
A.1.1 Chemical Company Test Data A-l
A. 1.1.1 Petro-Tex Test Data A-l
A.1.1.2 Koppers Test Data A-5
A. 1.1.3 Monsanto Test Data A-6
A.1.2 Environmental Protection Agency (EPA)
Test Data A-10
A.1.2.1 Denka Test Data A-10
A.1.2.2 Rohm & Haas Test Data A-12
A.1.2.3 Union Carbide (UCC) Test Data A-13
A. 1.3 Union Carbide Lab-Scale Test Data A-15
A.2 NITROGEN OXIDES (NO ) EMISSIONS A-15
A.3 COMPARISON OF TEST RESULTS AND THE TECHNICAL
BASIS OF THE SOCMI AIR OXIDATION EMISSIONS LIMIT . . . A-18
A.4 REFERENCES FOR APPENDIX A A-21
APPENDIX B: STATISTICAL ANALYSIS B-l
B.I INTRODUCTION B-l
B.2 STATISTICAL IMPACT ANALYSIS B-l
B.2.1 National Statistical Profile
Construction B-l
B.2.2 Data Reliability B-2
B.2.3 National Statistical Profile Use B-14
B.2.4 Calculation of Baseline Control Level B-14
B.3 REFERENCES FOR APPENDIX B B-15
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TABLE OF CONTENTS (Continued)
Chapter Page
APPENDIX C: EMISSION FACTORS . C-l
C.I VOC EMISSION FACTORS FOR EXISTING EQUIPMENT C-l
C.2 PRECAUTIONS TO BE CONSIDERED WHEN UTILIZING
EMISSION FACTORS C-l
C.2.1 Extreme Range of Some Emission Factors C-l
C.2.2 Cost-Effectiveness Cutoff with Respect
to -RACT Equipment C-l
C.3 VOC EMISSION FACTORS AS APPLIED TO EXAMPLE
PROCESSES C-4
C.3.1 Sample Calculation, Hydrogen Cyanide
Plant C-4
C.3.1.1 Existing Equipment. . C-4
C.3.1.2 RACT Equipment C-4
C.3.2 Plant VOC Emission Reduction Efficiency,
Hydrogen Cyanide Plant C-4
C.3.2.1 Total Annual Plant VOC Emission
Reduction C-4
C.3.2.2 Percent Reduction in Total Plant
VOC Emissions C-4
C.4 REFERENCES FOR APPENDIX C C-5
APPENDIX D: RACT CALCULATIONS D-l
DJ INTRODUCTION D-l
D.2 TOTAL RESOURCE EFFECTIVENESS D-l
D.2.1 Derivation of the TRE Coefficient D-3
D.2.2 Example Calculation of the TRE Index
Value for a Facility D-15
D.2.3 Calculation of Cost Effectiveness
for a Facility D-16
D.3 RACT IMPLEMENTATION D-17
vm
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TABLE OF CONTENTS (CONCLUDED)
Chapter Page
APPENDIX E: COST ANALYSIS SPECIAL TOPICS E-l
E.I INTRODUCTION E-l
E.2 CONTROL EQUIPMENT PURCHASE COSTS E-l
E.2.1 Thermal Oxidizer E-l
E.2.2 Recuperative Heat Exchanger E-l
E.2.3 Waste Heat Boiler E-2
E.2.4 Fans E-2
E.2.5 Stack E-2
E.2.6 Ducts E-2
E.3 INSTALLATION FACTORS E-2
E.4 INDIVIDUAL COMPONENT INSTALLED COSTS E-4
E.5 TOTAL CONTROL SYSTEM INSTALLED CAPITAL COSTS E-4
E.6 REFERENCES FOR APPENDIX E E-15
APPENDIX F: MAJOR COMMENTS RECEIVED ON THE DRAFT CTG F-l
APPENDIX G: PUBLIC COMMENT LETTERS ON THE DRAFT CTG G-l
APPENDIX H: REFERENCE METHODS AND PROCEDURES H-l
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LIST OF TABLES
TABLE
2-1 SOCMI CHEMICALS PRODUCED BY AIR OXIDATION 2-2
2-2 MAJOR END USE OF EACH IDENTIFIED SOCMI AIR
OXIDATION CHEMICAL 2-4
2-3 COMPANIES PRODUCING SYNTHETIC ORGANIC CHEMICALS
USING AIR OXIDATION PROCESSES 2-5
2-4 LARGEST PRODUCERS OF IDENTIFIED SOCMI AIR
OXIDATION CHEMICALS 2-9
2-5 ANNUAL PRODUCTION CAPACITY OF THE IDENTIFIED
SOCMI AIR OXIDATION CHEMICALS . 2-11
2-6 AIR OXIDATION PROCESS FACILITIES 2-12
2-7 PERCENTAGE PRODUCTION OF SOCMI CHEMICALS BY
AIR OXIDATION ' 2-19
2-8 AIR OXIDATION PROCESSES WITH CO-PRODUCT(S) AND
BY-PRODUCT(S) 2-22
2-9 BASIC RAW MATERIALS FOR AIR OXIDATION CHEMICALS 2-23
2-10 PHASE OF THE AIR OXIDATION REACTION STEP IN THE
PRODUCTION OF AIR OXIDATION CHEMICALS 2-25
2-11 CHEMICALS COVERED BY HOUDRY QUESTIONNAIRE 2-32
3-1 PRODUCT RECOVERY AND EMISSION CONTROLS CURRENTLY
USED IN ONE OR MORE PLANTS EMPLOYING MAJOR AIR
OXIDATION PROCESSES 3-3
3-2 SELECTED AIR OXIDATION PROCESSES KNOWN TO USE
CARBON ADSORPTION FOR PRODUCT/RAW MATERIAL
RECOVERY OR EMISSION REDUCTION 3-4
3-3 SELECTED AIR OXIDATION PROCESSES KNOWN TO USE
ABSORPTION FOR PRODUCT/RAW MATERIAL RECOVERY OR
EMISSIONS REDUCTION ' 3-9
3-4 SELECTED AIR OXIDATION PROCESSES KNOWN TO USE
CONDENSATION FOR PRODUCT/RAW MATERIAL RECOVERY
OR EMISSIONS REDUCTION 3-12
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LIST OF TABLES (Continued)
TABLE Page
3-5 PARTIAL LIST OF AIR OXIDATION CHEMICALS USING
THERMAL OXIDIZER FOR CONTROLLING VOC EMISSIONS
FROM OFFGAS STREAM 3-16
3-6 SELECTION AIR OXIDATION PROCESSES KNOWN TO USE
CATALYTIC OXIDATION FOR EMISSION CONTROL 3-22
4-1 ESTIMATED VOC EMISSIONS FROM PROCESS VENTS OF AIR
OXIDATION FACILITIES IN OZONE NONATTAINMENT AREAS 4-4
4-2 ESTIMATED VOC EMISSIONS FROM PROCESS VENTS FOR AN
AVERAGE AIR OXIDATION FACILITY 4-5
5-1 BASIC CHARACTERISTICS OF EACH DESIGN CATEGORY 5-2
5-2 MAXIMUM OFFGAS FLOWRATES FOR EACH DESIGN CATEGORY 5-5
5-3 RATIO OF FLUE GAS FLOWRATE TO OFFGAS FLOWRATE FOR
EACH DESIGN CATEGORY 5-6
5-4 INSTALLATION COMPONENTS 5-8
5-5 TOTAL INSTALLED CAPITAL COST EQUATIONS AS A FUNCTION
OF OFFGAS FLOWRATE 5-10
5-6 INSTALLED CAPITAL COSTS FOR A SELECTED HYPOTHETICAL
VENT STREAM IN EACH DESIGN CATEGORY 5-11
5-7 ANNUALIZED COST FACTORS 5-14
5-8 OPERATING FACTORS FOR EACH DESIGN CATEGORY 5-15
5-9 ANNUALIZED COST EQUATIONS 5-16
5-10 TYPICAL EMISSION CONTROL COSTS FOR EACH
DESIGN CATEGORY 5-19
5-11 COST EFFECTIVENESS FOR SELECTED STREAMS OF
EACH DESIGN CATEGORY 5-21
5-12 COEFFICIENTS OF THE TOTAL RESOURCE EFFECTIVENESS
(TRE) INDEX EQUATION 5-22
5-13 ESTIMATED IMPACTS OF RACT 5-25
A-l THERMAL INCINERATOR FIELD TEST DATA A-4
A-2 RESULTS OF DESTRUCTION EFFICIENCY UNDER STATED
CONDITIONS (UNION CARBIDE TESTS) A-16
A-3 SUMMARY OF RESULTS: N0x DATA A-17
A-4 RESULT-COMPARISONS OF LAB INCINERATOR VS.
ROHM & HAAS INCINERATOR A-20
XI
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LIST OF TABLES (Concluded)
TABLE
B-l LIST OF CHEMICALS FOR WHICH DATA HAVE BEEN OBTAINED .... B-3
B-2 ACTUAL DATA BASE USED TO CONSTRUCT NATIONAL
STATISTICAL PROFILE B-4
B-3 AIR OXIDATION OFFGAS COMPONENTS B-7
B-4 DISTRIBUTION OF NATIONAL STATISTICAL PROFILE
DATA VECTORS B-ll
B-5 JOINT DISTRIBUTION OF FLOW AND MASS EMISSIONS IN
NATIONAL STATISTICAL PROFILE B-l2
B-6 JOINT DISTRIBUTION OF DESIGN CATEGORIES AND MASS
EMISSIONS IN NATIONAL STATISTICAL PROFILE B-13
C-l VOC EMISSION FACTORS FOR SOCMI CHEMICALS
(AIR OXIDATION PROCESSES) C-2
C-2 TYPICAL ANNUAL VOC EMISSIONS FOR FOUR SELECTED
PROCESSES EMPLOYING EXISTING AND RACT EQUIPMENT C-3
D-l COEFFICIENTS OF THE TOTAL RESOURCE EFFECTIVENESS
(TRE) INDEX EQUATION D-4
D-2 MATHEMATICAL FORMULATION OF ANNUAL INCINERATOR
COST COMPONENTS D-5
E-l INSTALLATION COMPONENT FACTORS (% OF BUDGET
PRICE OF MAIN EQUIPMENT) E-3
F-l LIST OF COMMENTERS AND AFFILIATIONS F-2
XII
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LIST OF FIGURES
Figure Page
2-1 Schematic of a flowsheet for a liquid phase air
oxidation process 2-27
2-2 Schematic of a flowsheet for a vapor phase
air oxidation process 2-29
3-1 Two-stage regenerative adsorption system 3-5
3-2 Generalized form of the relationship of
effluent VOC concentration to steam usage 3-7
3-3 Packed tower for gas absorption .3-11
3-4 Condensation system 3-14
3-5 Discrete burner, thermal oxidizer 3-19
3-6 Distributed burner, thermal oxidizer 3-19
3-7 Catalytic oxidizer 3-23
A-l Petro-Tex oxo unit incinerator A-3
A-2 Off-gas incinerator (Monsanto Co., Chocolate
Bayou plant) A-8
A-3 Thermal incinerator stack sampling system A-9
A-4 Incinerator combustion chamber A-ll
B-l General-air oxidation process B-6
E-l Installed capital cost for the combustion chamber
with waste gas heat content = 10 Btu/scf, residence
time = 0.75 sec, and combustion temperature = 1600°F .... E-5
E-2 Installed capital cost for recuperative-type heat
exchangers with the waste gas heat content =
10 Btu/scf E-6
E-3 Installed capital costs for inlet ducts, waste gas,
and combustion air fans and stack with recuperative
heat recovery E-7
E-4 Installed capital costs for inlet ducts, waste gas,
and combustion air fans and stack for system with
no heat recovery E-8
xm
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LIST OF FIGURES (Concluded)
Figure
E-5 Installed capital cost of thermal oxidizer at 1800
and 2200°F including incinerator, two blowers,
ducts, and stack E-9
E-6 Installed capital cost for waste heat boilers
(250 psi) E-10
E-7 Installed capital cost of the scrubber including
quench chamber E-ll
E-8 Installed capital cost for inlet ducts, waste gas,
and combustion air fans and stack with waste heat
boilers E-12
E-9 Total installed capital cost for thermal oxidation
systems with waste gas heat content = 10 Btu/scf,
residence time = 0.75 sec, and combustion
temperature = 1600°F E-13
E-10 Total installed capital cost for thermal oxidation
systems with a scrubber at a residence time of 0.5
sec, a combustion temperature at 2200°F, and a waste
heat content of 1 Btu/scf E-14
xiv
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1. INTRODUCTION
The Clean Air Act Amendments of 1977 require each State in which there
are areas in which the national ambient air quality standards (NAAQS) are
exceeded to adopt and submit revised State Implementation Plans (SIP's) to
EPA. Revised SIP's were required to be submitted to EPA by January 1, 1979.
States which were unable to demonstrate attainment with the national ambient
air quality standards (NAAQS) for ozone by the statutory deadline of
December 31, 1982, could request extensions for attaining the standard.
States granted such an extension are required to submit a further revised
SIP by July 1, 1982.
Both the July 1, 1982, date for submittal of SIP revisions for "extension
areas" and the December 31, 1982, deadline for attainment for "nonextension
areas" have passed. Nevertheless, certain areas will still be required to
adopt reasonably available control technology (RACT) regulations after these
dates for volatile organic compound (VOC) source categories when EPA published
a control techniques guideline (CTG). Specifically, two types of nonattainment
areas are affected: (1) those granted an extension-up to 1987 for ozone
attainment since schedules for adopting these measures are incorporated in
the plan approvals, and (2) those failing to attain by 1982 (as originally
projected).
Section 172(a)(2) and (b)(3) of the Clean Air Act require that
nonattainment area SIP's include RACT requirements for stationary sources.
As explained in the "General Preamble for Proposed Rulemaking on Approval of
State Implementation Plan Revisions for Nonattainment Areas," (44 FR 20372,
April 4, 1979) for ozone SIP's, EPA permitted States to defer the adoption
of RACT regulations on a category of stationary sources of VOC until after
EPA published a CTG for that VOC source category. See also 44 FR 53761
(September 17, 1979) and 46 FR 7182 (January 22, 1981). This delay allowed
the States to make more technically sound decisions regarding the application
of RACT.
Although CTG documents review existing information and data concerning
the technology and cost of various control techniques to reduce emissions,
they are, of necessity, general in nature and do not fully account for
variations within a stationary source category. Consequently, the purpose
of CTG documents is to provide State and local air pollution control
agencies with an initial information base for proceeding with their own
assessment of RACT for specific stationary sources.
1-1
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1.1 REFERENCES FOR CHAPTER 1
1. "Guidance Document for Correction of Part D SIP's for Nonattainment
Areas," Office of Air Quality Planning and Standards, Research Triangle
Park, North Carolina, January 27, 1984.
1-2
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2. THE AIR OXIDATION INDUSTRY
2.1 GENERAL
The unit process of oxidation of organic compounds generally means the
chemical reaction with an oxidizing agent to introduce one or more oxygen
atoms into the compound, or to remove hydrogen or carbon atoms from the
compound, or a combination of the above. This analysis deals with the
subset of the oxidation industry in which air, or air enriched with oxygen,
is the oxidizing agent.
This chapter describes the air oxidation industry structure, its
production processes, and the associated emissions. The air oxidation
industry consists of those facilities that produce chemicals included in the
synthetic organic chemical manufacturing industry (SOCMI) by reacting one or
more chemicals with oxygen supplied as air. This industry also includes
chemicals produced using a combination of ammonia and air or of halogens and
air as reactants. Processes that use pure oxygen as the reactant or that
use an oxidizing agent other than oxygen are not considered in this study.
2.2 INDUSTRY STRUCTURE
It is difficult to separate the chemicals produced in air oxidation
processes from other SOCMI products since air oxidation is not the only
process to produce some of these chemicals. Several commercial routes
exist for many of these air oxidation chemicals including variations in
organic feed, oxygen oxidation, or chemical oxidation. Also, many air
oxidation chemicals are produced as intermediates for the manufacture of
other chemicals. This section discusses the identification of the air
oxidation chemicals, their uses and growth, and their domestic production.
2.2.1 Air Oxidation Chemicals
Table 2-1 lists these air oxidation chemicals; however, this list is
not exclusive.
Each air oxidation chemical belongs to one of the following general
chemical groups:
1. Acid anhydrides,
2. Alcohols,
3. Aldehydes,
4. Alkenes,
5. Carboxylic acids,
6. Esters,
7. Ketones,
8. Nitriles,
9. Oxides,
10. Peroxides, or
11. Halogenated alkanes.
Of the 36 air oxidation chemicals identified, 11 are carboxylic acids.
The remaining 25 chemicals include five ketones, five aldehydes, two
alcohols, two acid anhydrides, three alkenes, three nitriles, two oxides,
one ester, one peroxide, and one halogenated alkane.
2-1
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TABLE 2-1. SOCMI CHEMICALS PRODUCED BY AIR OXIDATION
1. Acetaldehyde
2. Acetic Acid
3. Acetone
4. Acetonitrile
5. Acetophenone
6. Acrolein
7. Acrylic Acid
8. Acrylonitrile
9. Anthraquinone
10. Benzaldehyde
11. Benzoic Acid
12. 1,3-Butadiene
13. p-t-Butyl Benzoic Acid
14. n-Butyric Acid
15. Crotonic Acid
16. Cumene Hydroperoxide
17. Cyclohexanol
18. Cyclohexanone
19. 1 ,2-Dichloroethane
20. Dimethyl Terephthalate
21. Ethylene Oxide
22. Formaldehyde
23. Formic Acid
24. Glyoxal
25. Hydrogen Cyanide
26. Isobutyric Acid
27. Isophthalic Acid
28. Maleic Anhydride
29. Methyl Ethyl Ketone
30. a-Methyl Styrene
31. Phenol
32. Phthalic Anhydride
33. Propionic Acid
34. Propylene Oxide (tert butyl
hydroperoxide)
35. Styrene
36. Terephthalic Acid
2-2
-------
Thirteen of the 36 chemicals contain an aromatic ring or rings. These
13 chemicals belong to each of the 11 groups listed above except the
nitriles, oxides, and halogenated alkanes.
Most of these chemicals are structurally simple. The acid anhydrides,
aldehydes, esters, and ketones, contain a carbonyl group. The alcohols,,,
nitriles, oxides, and peroxides also contain reactive functional groups.
The air oxidation chemicals have widely varying physical and chemical
characteristics. They exist as solids, liquids, or gases at ambient
condition, and most have characteristic odors.
2.2.2 Uses of Air Oxidation Chemicals
Air oxidation chemicals have many uses. They are used in production of
plastics, textile fibers, rubber, surface coatings, dyes, food additives,
fragrances, adhesives, drugs, and other substances.
There are two important characteristics of the air oxidation chemicals
in general. First, many air oxidation chemicals serve as intermediate
chemicals in the production of several other chemicals, which in turn have
numerous end uses and final products. Second, while the number of uses of
air oxidation chemicals is large, the major end uses are not very numerous.
Plastics and textile fibers account for the bulk of production of the air
oxidation chemicals studied here. . lable 2-2 lists the major use of each
identified air oxidation chemical. '
2.2.3 Companies and Production of Air Oxidation Chemicals
Fifty-nine companies produce one or more of the 36 air oxidation
chemicals. Table 2-3 gives7a listing of the companies and the chemicals
produced by each company. ' Of the 59 companies, 43 companies produce one
or two chemicals; 14 produce from three to nine chemicals; and two produce
10 or more. Celanese Corporation and Monsanto each produce the largest
number, 10.
A major share of the organic chemicals partially or fully produced by
air oxidation processes are controlled by large multi-line chemical
companies, chemical divisions, or subsidiaries of major oil companies, or
multi-industry companies with chemical process operations. Table 2-4 gives
the single, largest producer for each chemical andgthe percent of the
chemical's total capacity owned by that company. ' Other major producers
are listed if the largest producer does not control a major share of the
chemical's total production. Thirty-nine percent, or 14 out of 36
identified air oxidation chemicals, have an annual production greater than a
billion pounds per year. Table 2-5 lists,the,annual production capacities
of the identified air oxidation chemical. ' In general, the higher the
production volume of the air oxidation chemical, the less percent of total
capacity any one company will own. Those chemicals that are produced by
only one company are typically produced in small volumes.
2.2.4 Location of Air Oxidation Plants
There are currently 161 air oxidation process facilities operating in
the United States. Forty-seven of these are located in ozone national
ambient air quality standards (NAAQS) non-attainment areas. Table 2-6 gives
2-3
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TABLE 2-2. MAJOR END USE OF EACH IDENTIFIED SOCMI AIR OXIDATION CHEMICAL
1. Acetaldehyde
2. Acetic Acid
3. Acetone
4. Acetonitrile
5. Acetophenone
6. Acrolein
7. Acrylic Acid
8. Acrylonitrile
9. Anthraquinone
10. Benzaldehyde
11 . Benzoic Acid
12. 1,3-Butadiene
13. p-t-Butyl Benzoic Acid
14. n-Butyric Acid
15. Crotonic Acid
16. Cumene Hydroperoxide
17. Cyclohexanol
18. Cyclohexanone
19. 1,2-Dichloroethane
20. Dimethyl Terephthalate
21. Ethylene Oxide
22. Formaldehyde
23. Formic Acid
24. Glyoxal
25. Hydrogen Cyanide
26. Isobutyric Acid
27. Isophthalic Acid
28. Maleic Anhydride
29. Methyl Ethyl Ketone
30. a-Methyl Styrene
31. Phenol
32. Phthalic Anhydride
33. Propionic Acid
34. Propylene Oxide
35. Styrene
36. Terephthalic Acid
Intermediates - Drugs - Polymers - Paints
Intermediates - Polymers - Drugs - Solvents - Paints
Intermediates - Paints - Drugs - Solvent
Solvent - Intermediates
Solvent - Drugs - Polymers - Paints
Drugs - Intermediates
Polymers - Paints
Polymers - Drugs
Paints
Intermediates - Drugs - Paints
Drugs - Polymers - Paints
Intermediate - Polymers
Intermediate
Polymers - Drugs
Polymers - Drugs - Intermediates
Intermediate
Intermediate - Solvent
Intermediate - Solvent'
Intermediate - Solvent
Polymers
Drug - Intermediate
Intermediate - Polymers - Solvent
Intermediate
Intermediate - Polymers
Intermediate - Drugs
Solvent - Drugs
Polymers - Paints
Polymers - Intermediate
Solvent
Polymers
Polymers - Intermediate
Polymers - Drugs - Paints
Drug
Intermediate
Polymer - Intermediate
Polymers - Drugs - Paints
2-4
-------
TABLE 2-3. COMPANIES PRODUCING SYNTHETIC ORGANIC CHEMICALS USING
AIR OXIDATION PROCESSES
Company
Allied Chemical Co.
American Cyanamid Co,
Amoco
Amoco-Standard Oil
Ashland Oil, Inc.
BASF Wyandotte Corp.
Borden, Inc.
Celanese Corp.
Chembond
Chevron Chemical Co.
Ciba-Geigy Corp.
Clark Oil & Refining Corp.
Continental Oil Co.
Co-polymer Rubber and
Chemical Corp.
Crompton & Knowles Corp.
Degussa Corp.
Denka Chemical Co.
Diamond Shamrock
Dow Badische Co.
Chemicals
Acetone, Acetophenone, Cumene Hydroperoxide,
a-Methyl Styrene, Phenol, Phthalic Anhydride
Glyoxal
Terephthalic Acid
Isophthalic Acid, Maleic Anhydride
Maleic Anhydride
Phthalic Anhydride
Formaldehyde
Acetaldehyde, Acetic Acid, Acrylic Acid,
n-Butyric Acid, Cyclohexanol, Cyclohexanone,
Formaldehyde, Formic Acid, Methyl Ethyl
Ketone, Propionic Acid
Formaldehyde
Phthalic Anhydride
Hydrogen Cyanide
Acetone, a-Methyl Styrene, Phenol
1,2-Dichloroethane
1,3-Butadiene
Benzaldehyde
Hydrogen Cyanide
Maleic Anhydride
1,2-Dichloroethane
Cyclohexanol, Cyclohexanone
2-5
-------
TABLE 2-3 (Continued). COMPANIES PRODUCING SYNTHETIC ORGANIC CHEMICALS
USING AIR OXIDATION PROCESSES
Company
Dow Chemical, USA
DuPont
Eastman Kodak Co.
El Paso Natural Gas
Exxon Corp.
Firestone Tire & Rubber Co.
GAP Corp.
Georgia-Pacific Corp.
Getty Oil Co.
B.F. Goodrich Chemical
Gulf Oil Corp.
Hereofina
Hercules, Inc.
Hocker
ICI Americas Inc.
Inter'! Minerals & Chemical
Corp.
Kalama Chemical, Inc.
Koppers Co., Inc.
Chemicals
Acetone, Ethylene Oxide, Hydrogen Cyanide,
Phenol, 1,2-Dichloroethane
Acetonitrile, Acrylonitrile, Cyclohexanol,
Cyclohexanone, Formaldehyde, Hydrogen
Cyanide, Terephthalic Acid
Acetaldehyde, Acetic Acid, n-Butyric Acid,
Crotonic Acid, Isobutyric Acid,
Terephthalic Acid
1,3-Butadiene
Phthalic Anhydride
1,3 Butadiene
Formaldehyde
Acetone, Formaldehyde, a-Methyl Styrene, Phenol
Acetone, Acetophenone, a-Methyl Styrene, Phenol
1,2-Dichloroethane
Formaldehyde
Dimethyl Terephthalate, Terephthalic Acid
Formaldehyde, Hydrogen Cyanide
Formaldehyde
1,2-Dichloroethane
Formaldehyde
Benzoic Acid, Phenol
Phthalic Anhydride
2-6
-------
TABLE 2-3 (Continued). COMPANIES PRODUCING SYNTHETIC ORGANIC CHEMICALS
USING AIR OXIDATION PROCESSES
Company
Monsanto Co.
Nipro, Inc.
Northwest Indust., Inc.
01 in Corp.
Oxirane Corp.
Pacific RC
Pfizer, Inc.
PPG Indust., Inc.
Reichhold Chems., Inc.
Rohm and Haas Co.
Shell Chemical Co.
Standard Oil Co. (OH)
Stauffer Chemi. Co.
Stepan Chemical Co.
Tenneco, Inc.
Toms River Chemical Corp,
UOP, Inc.
Union Carbide Corp.
Chemicals
Acetone, Acrylonitrile, Benzoic Acid,
Cyclohexanol, Cyclohexanone, Formaldehyde,
Hydrogen Cyanide, Maleic Anhydride, Phenol,
Phthalic Anhydride
Cyclohexanol, Cyclohexanone
Benzoic Acid
Propylene Oxide
Propylene Oxide, Styrene
Formaldehyde
Benzoic Acid, Maleic Anhydride, Phenol
1,2-Dichloroethane
Formaldehyde, Maleic Anhydride
Hydrogen Cyanide, Acrylic Acid
Acetone, p-t-Butyl Benzoic Acid, Phenol,
1,2-Dichloroethane
Acetonitrile, Acrylonitrile, Hydrogen Cyanide
1,2-Dichloroethane
Phthalic Anhydride
Benzoic Acid, 1,3-Butadiene, Formaldehyde,
Maleic Anhydride
Anthraquinone
Benzaldehyde
Acetone, Acetophenone, Acrolein, Acrylic Acid,
Ethylene Oxide, Phenol, Propionic Acid,
a-Methyl Styrene
2-7
-------
TABLE 2-3 (Concluded). COMPANIES PRODUCING SYNTHETIC ORGANIC CHEMICALS
USING AIR OXIDATION PROCESSES
U.S. Steel Corp. Acetone, Cumene Hydroperoxide, Maleic
Anhydride, a-Methyl Styrene, Phenol,
Phthalic Anhydride
Vulcan Material Co. 1,2-Dichloroethane
Wright Chemical Corp. Formaldehyde
2-8
-------
TABLE 2-4. LARGEST PRODUCERS OF IDENTIFIED SOCMI AIR OXIDATION CHEMICALS
Chemicals
Acetaldehyde
Acetic Acid
Acetone
Acetonitrile
Acetophenone
Acrolein
Acrylic Acid
Acrylonitrile
Anthraquinone
Benzaldehyde
Benzoic Acid
1,3-Butadiene
p-t-Butyl Benzoic
Acid
n-Butyric Acid
Crotonic Acid
Cumene Hydroperoxide
Cyclohexanol/
Cyclohexanone
1,2-Dichloroethane
Dimethyl Terephtha-
late
Ethylene Oxide
Formaldehyde
Formic Acid
Glyoxal
Single Largest Producer
Celanese Corp.
Celanese Corp.
Allied Chemical Corp.
Percent of
Total Capacity
68
74
17
Other Major Producers
N/A N/A
N/A N/A
Union Carbide Corp. 100
Rohm & Haas Co. 42
Monsanto Corp. 49
Toms River Chemical Corp. 100
N/A - N/A
Kalama Chemical, Inc. 56
Tenneco 57
Shell Chemical Co. 100
Eastman Kodak Co. 100
Eastman Kodak Co. 100
N/A N/A
E.I. DuPont de Nemours &
Co., Inc. (E.I. DuPont) 40
•Dow Chemical Co. 35
Hereofina 75
Union Carbide Corp. 79
Celanese Corp. 20
Celanese Corp. 100
American Cyanamid 100
Union Carbide Corp.
Shell Chemical Co.
Monsanto Co.
Dow Chemical, USA
U.S. Steel Chemicals
N/A
N/A
Celanese Chemical
Union Carbide Corp.
E.I. DuPont
N/A
Northwest Indust., Inc.
El Paso Natural Gas
N/A
Monsanto Co.
Shell Chemical Co.,
PPG Industries, Inc.
Diamond Shamrock Corp.
Borden, Inc.
E.I. DuPont
Georgia-Pacific Corp.
2-9
-------
TABLE 2-4 (Continued). LARGEST PRODUCERS OF IDENTIFIED SOCMI AIR
OXIDATION CHEMICALS
Chemicals
Hydrogen Cyanide
Isobutyric Acid
Isophthalic Acid
Maleic Anhydride
Single Largest Producer
E.I. DuPont
Eastman Kodak Co.
Amoco-Standard Oil Co.
Monsanto Co.
Methyl Ethyl Ketone Celanese Corp.
a-Methyl Styrene Allied Chemical Corp.
Phenol Allied Chemical Corp.
Percent of
Total Capacity
53
100
100
24
100
45
18
Phthalic Anhydride Koppers Co., Inc.
Propionic Acid
Propylene Oxide
Styrene
Terephthalic Acid
Union Carbide Corp.
Oxirane Corp.
Oxirane Corp.
Amoco
26
100
100
100
58
Other Major Producers
Rohm and Haas Co.
Ashland Chemical Co.
U.S. Steel Chemicals
Amoco-Chemicals
U.S. Steel Chemicals
Monsanto Co.
Shell Chemical Co.
U.S. Steel Chemicals
Dow Chemical, USA
Union Carbide Corp.
Monsanto Co.
U.S. Steel Corp.
Stepan Chemical Co.
E.I. DuPont
N/A = Information not available.
2-10
-------
TABLE 2-5. ANNUAL PRODUCTION CAPACITY OF THE IDENTIFIED SOCMI AIR
OXIDATION CHEMICALS
Capacity in
Chemical Gigagrams Per Year
1. Acetaldehyde 630
2. Acetic Acid 770
3. Acetone 930
4. Acetonitrile N/A
5. Acetophenone N/A
6. Acrolein 27
7. Acrylic Acid 428
8. Acrylonitrile 880
9. Anthraquinone 2
10. Benzaldehyde N/A
11. Benzoic Acid 145
12. 1,3-Butadiene 410.
13. p-t-Butyl Benzoic Acid 3D'^
14. n-Butyric Acid 6c'a
15. Crotonic Acid 6
16. Cumene Hydroperoxide N/A
17. Cyclohexanol e
18. Cyclohexanone 925
19. 1,2-Dichloroethane 5452
20. Dimethyl Terephthalate 890
21. Ethylene Oxide 1430
22. Formaldehyde 3900
23. Formic Acid 7
24. Glyoxal N/A
25. Hydrogen Cyanide 620 ,
26. Isobutyric Acid 5 '
27. Isophthalic Acid 66
28. Maleic Anhydride 200
29. Methyl Ethyl Ketone 40
30. a-Methyl Styrene 24
31. Phenol 1472
32. Phthalic Anhydride 572
33. Propionic Acid 86
34. Propylene Oxide 181
35. Terephtnalic Acid 2235
36. Styrene 635
N/A = Data not available.
Letter from Bobsein, W.P., Toms River Chem. Corp., to Evans, L.B.,
EPA, February 11, 1980.
Estimated based on data given in letter from Haxby, L.P., Shell Oil
Co., to Evans, L.B., EPA, January 9, 1980.
cMemo from Galloway, J., EEA, to SOCMI Air Oxidation File. Estimation
of capacities for p-t-Butylbenzoic Acid, n-Butyric Acid, and Isobutyric
Acid from company data, April 9, 1981.
Estimated based on data given in letter and attachment from Edwards, J.C.,
Eastman Kodak Co., to Evans, L.B., EPA, February 6, 1980.
g
Production capacity of cyclohexanol and cyclohexanone have been reported
together.
2-11
-------
TABLE 2-6. AIR OXIDATION PROCESS FACILITIES
r\i
i—i
ro
Nonattainment
Area
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Primary Air-Oxidation Product(s)
(Manufacturing Process In Parentheses)
Acetaldehyde
Acetaldehyde
Acetaldehyde
Acetic Acid (Wacker)
Acetic Acid (Wacker)
Acetic Acid/Formic Acid/MEK/Butyric
Acid/Propionic Acid
Acetic Acid (Wacker)
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acetone/Phenol
Acrylic Acid
Acrylic Acid
Acrylic Acid
Acrylic Acid/Acrolein
Acrylonitri le
Acrylonitrile
Acrylonitrile
Acrylonitrile
Acrylonitrile
Anthraquinone
Company
Celanese Chemical
Celanese Chemical
Texas Eastman
Celanese Chemical
Celanese Chemical
Celanese Chemical
Tennessee Eastman
Allied Chemical
Clark Chemical
Dow Chemical
Georgia Pacific
Getty Refining
Monsanto Chemical
Shell Chemical
Amoco-Std. Oil
Union Carbide
Union Carbide
U.S. Steel Chemical
Celanese Chemical
Celanese Chemical
Rohm and Haas
Union Carbide
DuPont
DuPont
Monsanto Chemical
Monsanto Chemical
Vistron (SOHIO)
Toms River Chemical
Capacity (Gg/yr)
(Including All
Location By-Products)
Bay City, Texas
Clear Lake, Texas
Longview, Texas
Bay City, Texas
Clear Lake, Texas
Pampa, Texas
Kingsport, Tennessee
Frankford, Pennsylvania
Blue Island, Illinois
Oyster Creek, Texas
Plaquemine, Louisiana
El Dorado, Kansas
Chocolate Bayou, Texas
Deer Park, Texas
Richmond, California
Bound Brook, New Jersey
Penuelas, Puerto Rico
Haverhill, Ohio
Clear Lake, Texas
Pampa, Texas
Deer Park, Texas
Taft, Louisiana
Memphis, Tennessee
Beaumont, Texas
Alvin, Texas
Texas City, Texas
Lima, Ohio
Toms River, New Jersey
136
295
200
90
227
298
204
446
66
338
240
70
363
363
40
113
162
380
104
34
181
136
140
181
240
256
200
1.8a
-------
TABLE 2-6 (Continued). AIR OXIDATION PROCESS FACILITIES
ro
i—>
CO
Nonattainment Primary Air-Oxidation Product(s)
Area (Manufacturing Process In Parentheses)
Yes Ben/aldehyde
Benzoic Acid/Phenol
Benzoic Acid/Phenol
Benzoic Acio/Phenol
Benzoic Acid/Phenol
Yes Benzoic Acid/Phenol
Yes Benzoic Acid/Phenol
1 ,3-Butadiene
Yes 1 ,3-Butadiene
1 ,3-Butadiene
1 ,3-Butadiene
p-t-Butylbenzoic Acid
n-Butyric Acid
Crotonic Acid
Cyclohexanone/Cyclohexanol
Cyclohexanone/Cyclohexanol
Cyclohexanone/Cyclohexanol
Cyclohexanone/Cyclohexanol
Cyclohexanone/Cyclohexanol
Cyc 1 ohexanone/Cyc 1 ohexano 1
Company
Crompton and Knowles
Kalama Chemical
Northwest Indust.
Northwest Indust.
Pfizer Chemicals
Tenneco Chemicals
Monsanto Chemical
Firestone
Tenneco
Copolymer Rubber
El Paso Natural Gas
Shell Chemical
Tennessee Eastman
Tennessee Eastman
Badische
Celanese Chemical
DuPont
DuPont
Monsanto Chemical
Nipro
Capacity (Gg/yr)
(Including Al :
Location By-Products)
Fair Lawn, New Jersey
Kalama, Washington
Beaumont, Texas
Chattanooga, Tennessee
Terre Haute, Indiana
Garfield, New Jersey
St. Louis, Missouri
Orange, Texas
Houston, Texas
Baton Rouge, Louisiana
Odessa, Texas
Martinex, California
Kingsport, Tennessee
Kingsport, Tennessee
Freeport, Texas
Bay City, Texas
Orange, Texas
Victoria, Texas
Pensacola, Florida
Augusta, Georgia
Not Reported
81
18
23
15
7
1
54
236
27
93
Not Reported,
Estimated To Be
J •
Not Reported,
Estimated .To Be
6
140
45
142
231
227
139
-------
TABLE 2-6 (Continued). AIR OXIDATION PROCESS FACILITIES
ro
i
Nonattainment
Area
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Primary Air-Oxidation Product(s)
(Manufacturing Process In Parentheses)
Terephthalic Acid (TPA)
Terephthalic Acid (TPA)
Dimethyl Terephthalate (DMT)
TPA
DMT/TPA
DMT
TPA
TPA
Ethylene Oxide
Ethyl ene Oxide
Ethylene Oxide
Ethylene Oxide
Ethylene Oxide
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Mixed Metal)
Formaldehyde (Mixed Metal)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Capacity (Gg/yr)
(Including All
Company
DuPont
DuPont
Carolina Eastman
Tennessee Eastman
Hereof ina
Hereof ina
Amoco
Amoco
Dow Chemical
Dow Chemical
Union Carbide
Union Carbide
Union Carbide Caribe
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Borden, Inc.
Celanese Chemical
Celanese Chemical
Celanese Chemical
E.I. DuPont Denemours
E.I. DuPont Denemours
E.I. DuPont Denemours
E.I. DuPont Denemours
E.I. DuPont Denemours
Location By-Products)
Old Hickory, Tennessee
Wilmington, North Carolina
Columbia, South Carolina
Kingsport, Tennessee
Wilmington, North Carolina
Spartanburg, South Carolina
Charleston, South Carolina
Decatur, Alabama
Freeport, Texas
Plaquemine, Louisiana
Seadrift, Texas
Taft, Louisiana
Ponce, Puerto Rico
Demopolis, Alabama
Diboll , Texas
Fayetteville, North Carolina
Louisville, Kentucky
Sheboygan, Wisconsin
Fremont, California
Kent, Washington
La Grande, Oregon
Missoula, Montana
Springfield, Oregon
Geismar, Louisiana
Newark, New Jersey
Rock Hill, South Carolina
Bishop, Texas
Belle, West Virginia
Healing Springs, NC
LaPorte, Texas
Linden, New Jersey
Toledo, Ohio
213
485
227
227
703
75
454
743
91
204
385
500
250
45
36
107
36
59
102
36
30
40
30
13
53
53
80
227
100
145
73
122
-------
TABLE 2-6 (Continued). AIR OXIDATION PROCESS FACILITIES
Nonattainment
Area
Primary Air-Oxidation Product(s)
(Manufacturing Process In Parentheses)
Company
Location
Capacity (Gg/vr)
(Including All
By-Products)
no
t—'
en
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
(Mixed Metal)
(Mixed Metal)
(Mixed Metal)
(Mixed Metal)
(Silver)
(Silver)
(Mixed Metal)
(Mixed Metal)
(Mixed Metal)
(Silver)
(Mixed Metal)
(Mixed Metal)
(Silver)
(Mixed Metal)
(Mixed Metal)
(Silver)
Formaldehyde (Mixed Metal)
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
Formaldehyde
(Silver)
(Silver)
(Silver)
(Silver)
(Silver)
(Silver)
(Silver)
(Mixed Metal)
(Silver)
(Mixed Metal)
(Mixed Metal)
(Mixed Metal)
(Silver)
(Mixed Metal)
(Mixed Metal)
GAF Corporation
Georgia-Pacific
Georgia-Pacific
Georgia-Pacific
Georgia-Pacific
Georgia-Pacific
Georgia-Pacific
Georgia-Pacific
Georgia-Pacific
Georgia-Pacific
Chembond
Chembond
Chembond
Chembond
Gulf Oil
Hercules
International Minerals
Chemical
International Minerals
Chemical
Monsanto Chemical
Monsanto Chemical
Monsanto Chemical
Monsanto Chemical
Hooker
Reichhold Chemicals
Peichhold Chemicals
Reichhold Chemicals
Reichhold Chemicals
Reichhold Chemicals
Reichhold Chemicals
Reichhold Chemicals
Reichhold Chemicals
Tenneco
Calvert City, Kentucky 45
Albany, Oregon 45
Columbus, Ohio 77
Coos Bay, Oregon 35
Crossett, Arkansas 27
Crossett, Arkansas 45
Lufkin, Texas 45
Russelville, South Carolina 90
Taylorsville, Mississippi 55
Vienna, Georgia 45
Andalusia, Alabama 32
Springfield, Oregon 32
Springfield, Oregon 32
Winnfield, Alabama 32
Vicksburg, Mississippi 23
Louisiana, Missouri 77
Seiple, Pennsylvania 120
Seiple, Pennsylvania 30
Addyston, Ohio 55
Chocolate Bayou, Texas 88
Eugene, Oregon 45
Springfield, Massachusetts 134
North Tonawanda, New York 61
Hampton, South Carolina 23
Houston, Texas 45
Kansas City, Kansas 18
Malvern, Arkansas 50
Moncure, North Carolina 45
Tacoma, Washington 23
Tuscaloosa, Alabama 34
White City, Oregon 102
Fords, New Jersey 57
-------
TABLE 2-6 (Continued). AIR OXIDATION PROCESS FACILITIES
no
i
Nonattainment
Area
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Primary Air-Oxidation Product(s)
(Manufacturing Process In Parentheses)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Silver)
Formaldehyde (Mixed Metal )
Glyoxal
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Hydrogen Cyanide
Isobutyric Acid
Isophthalic Acid
Maleic Anhydride (Benzene)
Maleic Anhydride (Benzene)
Maleic Anhydride (Benzene)
Maleic Anhydride (Butane)
Maleic Anhydride (Benzene)
Maleic Anhydride (Butane)
Maleic Anhydride (Benzene)
Maleic Anhydride (Benzene)
Maleic Anhydride (Benzene)
Company
Tenneco
Tenneco
Pacific RC
Wright Chemical
American Cyanamid
Ciba-Geigy
Degussa
Dow Chemical
DuPont
DuPont
PuPont
Ciba-Geigy
Monsanto
Rohm and Haas
Tennessee Eastman
Amoco-Standard Oil
Ashland
Denka
Monsanto Chemical
Monsanto Chemical
Peichhold
Amoco-Standard Oil
Tenneco
U.S. Steel Chemicals
Pfizer
Capacity (Gg/yr)
(Including All
Location By-Products)
Fords, New Jersey 27
Garfield, New Jersey 45
Eugene, Oregon 43
Riegelwood, North Carolina 36
Charlotte, North Carolina Not Reported
St. Gabriel, Louisiana 40
Theodore, Alabama 24
Freeport, Texas 9
Memphis, Tennessee 66
Orange, Texas 95
Victoria, Texas 95
Glen Falls, New York 1
Texas City, Texas 63
Deer Park, Texas 90
Not Reported,
Estimate.djTo Be
Kingsport, Tennessee 5. '
Joliet, Illinois 65
Neal, West Virginia 27
Houston, Texas 23
St. Louis, Missouri 38
St. Louis, Missouri 10
Morris, Illinois 20
Joliet, Illinois 27
Fords, New Jersey 10
Neville Island, Pennsylvania 36
Terre Haute, Indiana 9
-------
TABLE 2-6 (Concluded). AIR OXIDATION PROCESS FACILITIES
ro
i
Nonattainment
Area
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Primary Air-Oxidation Product(s)
(Manufacturing Process In Parentheses)
Phathalic Anhydride (Xylene)
Phathalic Anhydride (Xylene)
Phathalic Anhydride (Xylene)
Phathalic Anhydride (Naphthalene)
Phathalic Anhydride (Xylene)
Phathalic Anhydride (Naphthalene)
Phathalic Anhydride (Xylene)
Phathalic Anhydride (Xylene)
Phathalic Anhydride (Xylene)
Phathalic Anhydride (Naphthalene)
Propionic Acid
Propylene Oxide/Styrene
1 ,2-Dichloroethane
1 ,2-Dichloroethane
1 ,2-Dichloroethane
1 ,2-Dichloroethane
1,2-Dichloroethane
l,2D1chloroethane
1 ,2-Dichloroethane
1 ,2-Dichloroethane
1 ,2-Dichloroethane
1 ,2-Dichloroethane
1 ,2-Dichloroethane
1,2-Dichloroethane
1 ,2-Dichloroethane
1,2-Dichloroethane
1 ,2-Dichloroethane
Capacity (Gg/yr)
(Including All
Company
Allied Chemical
Basf Wyandotte
Exxon
Koppers
Koppers
Monsanto Chemical
Monsanto Chemical
Chevron
Stepan
U.S. Steel
Union Carbide
Oxirane
Conoco Chemicals
Diamond Shamrock
Diamond Shamrock
Dow Chemical
Dow Chemical
Dow Chemical
Ethyl
Ethyl
B.F. Goodrich Chemical
ICI Americas
Petrochemicals
P.P.G. Industries
Chemicals-US
Shell Chemical
Shell Chemical
Stauffer Chemical
Vulcan Chemicals
Location By-Products)
El Segundo, California
Kearny, New Jersey
Baton Rouge, Louisiana
Bridgeville, Pennsylvania
Cicero, Illinois
Bridgeport, New Jersey
Texas City, Texas
Richmond, California
Millsdale, Illinois
Neville Island, Pennsylvania
Texas City, Texas
Channelview, Texas
Lake Charles, Louisiana
Deer Park, Texas
La Porte, Texas
Freeport, Texas
Oyster Creek, Texas
Plaquemine, Louisiana
Baton Rouge, Louisiana
Pasadena, Texas
Calvert City, Kentucky
Baton Rouge, Louisiana
Lake Charles, Louisiana
Deer Park, Texas
Norco, Louisiana
Long Beach, California
Geismar, Louisiana
16
68
60
40
107
40
60
23
76
82
86
816
266
145
454
726
500
816
318
118
454
234
703
635
318
45
159
aOp. cit., see Reference a for Table 2-5.
Op. cit., see Reference b for Table 2-5.
C0p. cit., see Reference c for Table 2-5.
Op. cit., see Reference d for Table 2-5.
-------
a listing of the air oxidation manufacturing processes and the facilities
employing each process. ' The plant location, capacity, and major
product(s) are given for each facility. Those facilities located in
nonattainment areas are so indicated.
Although air oxidation industries are scattered throughout several
states, many are located near refineries, which are located near domestic
sources of oil or points of entry for imported oil. Some of the petro-
chemical plants border refineries, thus permitting an easy exchange of
products. This results in a heavy concentration of chemical production
along the Gulf Coast (Texas and Louisiana) and the East Coast, particularly
in New Jersey and Pennsylvania.
Air oxidation plants are located in 27 states; over half of the
161 plants are located in the Gulf Coast and the East Coast. Twenty-eight
of the 36- air oxidation chemicals are produced in Texas. Louisiana and New
Jersey each produce 33 percent or more of the 36 air oxidation chemicals.
2.3 AIR OXIDATION PRODUCTION PROCESSES
The only determinant for classification as an air oxidation chemical is
the process by which the chemical is produced. Some chemicals identified as
air oxidation,chemicals in Section 2.2.1 can be made by non-air oxidation
processes. ~ Table 2-7-,shows the percentages of air oxidation production
of each of the chemicals.
Despite the large variation in reaction types used to produce air
oxidation chemicals, air oxidation processes can be grouped together because
they have one very important characteristic in common, the need to vent
large quantities of inert material containing VOC to the atmosphere. These
inerts, predominantly nitrogen, are present because air contains 20.9
percent oxygen and 78.1 percent nitrogen by volume on a dry basis. The
nitrogen in the air passes through the reaction unreacted. The exact
quantity of nitrogen and unreacted oxygen emitted is a function of the
amount of excess air used in the production process. The following sections
present a discussion of the reaction types used for the production of air
oxidation chemicals and the important factors which determine the amount of
excess air used.
2.3.1 Reaction Types
The principal types of oxidation reactions that take place in the
production of air oxidation chemicals are:
1. Dehydrogenation,
2. Introduction of an oxygen atom,
3. Destruction of carbon-carbon bonds,
4. Use of oxygen carrier,
5. Peroxidation,
6. Ammoxidation,
7. Oxidative condensation, and
8. Oxyhalogenation.
Dehydrogenation is illustrated in the transformation of a primary
alcohol to an aldehyde:
2-18
-------
TABLE 2-7. PERCENTAGE PRODUCTION OF SOCMI CHEMICALS BY AIR OXIDATION
% of Product Manufactured
Product by Air Oxidation
1. Acetaldehyde 99.7
2. Acetic Acid 40
3. Acetone 65
4. Acetonitrile No Data
5. Acetophenone No Data
6. Acrolein 52
7. Acrylic Acid 94
8. Acrylonitrile 100
9. Anthraquinone No Data
10. Benzaldehyde No Data
11. Benzoic Acid 100
12. 1,3-Butadiene 23
13. p-t-Butyl Benzoic Acid No Data
14. n-Butyric Acid No Data
15. Crotonic Acid No Data
16. Cumene Hydroperoxide No Data
17- Cyclohexanol 81
18. Cyclohexanone 81
19. 1,2-Dichloroethane 96
20. Dimethyl Terephthalate 100
21. Ethylene Oxide 51
22. Formaldehyde 100
23. Formic Acid 23
24. Glyoxal No Data
25. Hydrogen Cyanide 100
26. Isobutyric Acid No Data
27. Isophthalic Acid 100
28. Maleic Anhydride 80
29. Methyl Ethyl Ketone 11a
30. a-Methyl -Styrene 100a
31. Phenol 98
32. Phthalic Anhydride 100
33. Propionic Acid 62a
34. Propylene Oxide 20
35. Styrene 18
36. Terephthalic Acid 100
*Produced by air or oxygen oxidation.
aSRI International 1978 Directory of Chemical Producers,
United States of America.
2-19
-------
.OH + £00 = CH.CHO + H00
b L $ 2
or of a secondary alcohol to a ketone:
CH3CHOHCH3 + ±02 = CH3COCH3
or of an alkane to alkene:
= CH2CHCHCH2
An atom of oxygen may be introduced into a molecule, as is illustrated
by the oxidation of an aldehyde to an acid:
CH3CHO + |02 = CH3COOH
or of a hydrocarbon to an oxide:
A combination of the above may occur, as in the preparation of
aldehydes from hydrocarbons:
CH4 + 02 = CH20 + H20
or of benzoic acid from toluene:
C6H5CH3 + U02 = C6H5COOH + H2°
A combination of dehydrogenation, oxygen introduction, and destruction
of carbon-carbon bond may all occur in the same process of oxidation, e.g.,
in the oxidation of naphthalene to phthalic anhydride:
C10H8 + 4i°2 = C8H4°3 + 2H2° + 2C02
Oxidation may be accomplished indirectly through the use of
intermediate or oxygen carrier:
C2H4 + 2CuCl2 + H20 PdC12> CH3CHO + HC1 + 2CuCl
Peroxidation occurs readily under certain conditions. Thus, some
reactions occur directly with air when catalyzed by heavy metal salts:
Cumene + air = Cumene Hydroperoxide
Ammoxidation is a process for the formation of nitriles by the action
of ammonia in the presence of air or oxygen on olefins, organic acids, or
other alkyl group of alkylated aromatics:
2-20
-------
NH
= CH.CHCN
f.
3H90
c
Oxidative condensation occurs when two molecules combine with each
other with the introduction of oxygen atoms and removal of small molecules
like water:
2CH3CHO
= CH3COOOCCH3
Oxyhalogenation is a process in which oxygen and a halogen reacts with
an organic compound:
M/i + ±00 + 2HC1 = C1CH0CH,C1 + H00
L. <\ L L L
-------
TABLE 2-8. AIR OXIDATION PROCESSES WITH CO-PRODUCT(S) AND BY-PRODUCT(S)
Process
Co-Products
By-Products
Butane Oxidation II
Acetic Acid, Methyl Ethyl
Ketone
Cyclohexane Oxidation Cyclohexanol, Cyclohexane
Ethylbenzene Hydro-
peroxidation-
Cumene Hydroper-
oxidation
Toluene Oxidation
p-Xylene Oxidation
Propylene Oxidation
Propylene Ammoxidation
Styrene, Propylene Oxide
Acetone, Phenol
Phenol , Benzoic Acid
Dimethyl Terephthalate,
Terephthalic Acid
Acrylic Acid
Acrylonitrile, Hydrogen
Cyanide
Formic Acid, n-Butyric
Acid, Propionic Acid
Cumene Hydroperoxide,
Acetophenone, a-Methyl
Styrene
Acrolein
Acetonitrile
2-22 '
-------
TABLE 2-9. BASIC RAW MATERIALS FOR AIR OXIDATION CHEMICALS
ro
i
ro
_ .
Ethylene Based
Acetaldehyde
Acetic Acid
Ethylene Oxide
Glyoxal
Crotonic Acid
Propylene Based Butane Based
Acrolein Acetic Acid
Acrylic Acid 1 ,3-Butadiene
n-Butyric Acid
Formic Acid
Isobutyric Ac id
Maleic Anhydride
Methyl Ethyl Ketone
Propionic Acid
Aromatic Based
Acetone
Acetophenone
Benzaldehyde
Beruoic Acid
para-tert-Butyl Benzoic Acid
Cumene Hydroperoxide
Cyclohexanol
Cyclohexanone
Other
Formaldehyde (Methanol from Syngas)
Hydrogen Cyanide (Methane + Anwonia)
Hydrogen Cyanide (Ammonia * Propylene)
Acetonitrile (Ammonia + Propylene)
Acrylouilri le (Aimionia + Propylene)
Dimethyl Terephthalate
Isophthalic Acid
Methyl Styrene
Phenol
Phthalic Anhydride
Styrene
Terephthalic Acid
-------
natural gas-based petrochemicals. Alternative routes to these chemicals
utilizing oil-based feeds are being developed.
2.3.3 Reaction Characteristics
In spite of numerous reaction mechanisms, all air oxidation processes
vent large quantities of inert material containing predominantly nitrogen
from air and some VOC. Therefore, to quantify VOC emissions, and to select
the applicable control method, it is necessary to quantify offgas flow and
VOC concentrations. As discussed in Chapter 3, flow and VOC concentrations
are the major process parameters which determine the economics of
controlling VOC emissions by thermal or catalytic incineration. This
section discusses the reaction characteristics which affect the offgas flow
from air oxidation processes. Section 2.4 presents the results of the
statistical analysis from which the national VOC emission profile was
developed.
There are several reaction characteristics which determine the amount
of offgas vented to the atmosphere. They are as follows:
1. Reaction stoichiometry,
2. Reaction phase, and
3. Explosion hazard.
2.3.3.1 Reaction Stoichiometry. In air oxidation reactions, oxygen
from the air reacts with an organic reactant to produce the following:
(1) product air oxidation chemical, (2) some carbon dioxide and carbon
monoxide due to partial combustion of the feedstock, and (3) co-products and
by-products. The total oxygen required is dependent on the extent of each
reaction. The stoichiometry of the reaction and the catalyst selectivity of
a process determine the theoretical amount of oxygen required for a given
process. Catalyst selectivity is defined as the quotient of the amount of
reaction product to the amount of converted feedstock. For example, in
the ethylene oxide process, ethylene reacts with oxygen to produce ethylene
oxide (main reaction) and carbon dioxide according to the following
equations:
(75%) CH0CH0 + i00 = ChL CH9
L C C C- <-
0
(25%) CH2CH2 + 302 = 2C02 + 2H20
(100%) CH9CH? + | 0? = -T C?H.O + C0? + HLO
C£Ot."'£.*T C- f-
The molecular oxygen ratio (MOR), defined as moles of oxygen per mole of
product, is 0.5 for the main reaction. However, considering the oxygen
required foK the combustion reaction at an average catalyst selectivity of
75 percent , the MOR of the overall reaction becomes 1.5.
Generally, all air oxidation processes require greater than
stoichiometric amount of air to realize optimum conversion, favorable
reaction rates, and to prevent explosion hazard.
2.3.3.2 Reaction Phase. Generally, air oxidation reaction can be
carried out in either liquid or gas phase. Table 2-10 shows the division of
2-24
-------
TABLE 2-10.
PHASE OF THE AIR OXIDATION REACTION STEP IN THE
PRODUCTION OF AIR OXIDATION CHEMICALS
Liquid Phase
1. Acetaldehyde
2. Acetic Acid
3. Acetone
5. Acetophenone
6. Benzaldehyde
7. Benzoic Acid
8. p-t-Butyl Benzoic Acid
9. n-Butyric Acid
10. Cumene Hydroperoxide
11. Cyclohexanol
12. Cyclohexanone
13. Dimethyl Terephthalate
14. Formic Acid
15. Isobutyric Acid
16. Isophthalic Acid
17. Methyl Ethyl Ketone
18. a-Methyl Styrene
19. Phenol
20. Propionic Acid
21. Propylene Oxide (tert butyl
22. Styrene3
23. Terephthalic Acid
Vapor Phase
1. Acetaldehyde
2, Acetonitrile
3. Acrolein
4. Acrylic Acid
5. Acrylonitrile
6. Anthraquinone
7. 1,3-Butadiene
8. 1,2-Dichloroethane
9. Ethylene Oxide
10. Formaldehyde
11. Glyoxal
12. Hydrogen Cyanide
13. Maleic Anhydride
14. Phthalic Anhydride
hydroperoxide)'
The air oxidation step in styrene/propylene oxide manufacture is the
liquid phase hydroperoxidation of ethylbenzene.
2-25
-------
the various air oxidation processes between liquid and vapor phase. The
processes are categorized according to the phase of the air oxidation
reaction step, and not according to the phase of the step(s) in which the
final product(s) is/are formed.
Liquid phase reactions generally utilize high molecular weight
thermally unstable reactants. The reaction temperatures are low or moderate
and usually require high pressures for optimum reaction rates. The extent
of oxidation is controlled by limiting the duration of operation,
controlling the temperature and using low excess air. Large amounts of
excess air may cause branching of radical precursors with formation of a
multiplicity of radicals and, consequently, runaway reactions which could
ultimately result in explosion.
The catalyst used in liquid phase processes may be either dissolved or
suspended in finely divided form to ensure contact with the bubbles of gas-
containing oxygen which pass through the liquid undergoing oxidation. To
speed up the production, means must be provided for initially raising the
temperature and for later removing reaction heat. Heat may be removed and
temperature controlled by circulation of either the liquid being oxidized or
a special cooling fluid through the reaction zone and then through an
external heat exchanger. Where low temperatures and slow reaction rates are
indicated, natural processes of heat flow to the atmosphere may suffice for
temperature control.
In addition, liquid phase processes require adequate mixing and contact
of the two immiscible phases of gaseous oxidizing agent and the liquid being
oxidized. Mixing may be obtained by the use of special distributor inlets
for the air, designed to spread the air throughout the liquid. Mechanical
stirring or frothing of the liquid are the other methods of providing
thorough mixing.
Figure 2-1 represents a schematic flowsheet of a liquid phase air
oxidation process. Liquid feedstock and catalyst are fed into a reactor.
The reaction is carried out by passing air through this liquid mixture at a
controlled temperature and pressure. After completion of the reaction, two
streams come out of the reactor, liquid and gaseous. The liquid stream
usually contains the desired product, which is taken to a product recovery
system consisting of a series of different unit operations (e.g.,
distillation, crystallization, evaporation, etc). The gaseous stream
containing nitrogen, unreacted oxygen, CCL, and some VOC is condensed or
cooled and then fed into the gas separator to recover the condensable
compounds before venting it to the atmosphere.
In contrast to liquid phase reactions, vapor phase air oxidation
reactions can be effectively applied only to readily volatile substances
that are of sufficient thermal stability to resist dissociation at elevated
temperatures. The desired product must also be thermally stable to
continued oxidation and must be readily separable from gaseous product.
These various restrictions limit the material capable for economic
processing by vapor phase air^oxidation to the simpler aliphatic and
aromatic series of compounds.
In vapor phase air oxidation processes, a solid or vapor phase catalyst
may be employed. The temperatures are usually high. Control is affected by
2-26
-------
OFFGAS
ro
PRODUCT
HEcoviifw SYSTEM
FEED
STOCK
STORAGE
GAS
SEPARATOR
PRODUCT
PURIFICATION SECTION
Figure 2-1. Schematic of a flowsheet for a liquid phase air oxidation process.
-------
limiting the time of contact, temperature, proportion of oxygen, type of
catalyst, or by combinations of these factors.
By their very nature, the vapor phase oxidation processes result in the
concentration of reaction heat in the catalyst zone, from which it must be
removed in large quantities at high temperature levels. Removal of heat is
essential to prevent destruction of apparatus, catalyst, or raw material.
Maintenance of temperature at the proper level is necessary to ensure the
correct rate and degree of oxidation. Figure 2-2 represents a schematic
flowsheet of a vapor phase air oxidation process. The feedstock which is
either in vapor or liquid phase is first vaporized, if required, and then
mixed with air in a mixing chamber. The mixture is then fed at the required
temperature and pressure into a reaction chamber where it comes in contact
with a catalyst. After completion of the reaction, the mixture of gases
coming out of the reactor is passed through a product recovery system con-
sisting of different unit operations, which can include condensers,
scrubbers, or both. The exhaust gas coming from the product recovery system
containing predominantly nitrogen and some VOC, is vented to the atmosphere
or to a control device.
2.3.3.3 Explosion Hazard. Many organic reactants used in air
oxidation processes are inflammable and require adequate means to prevent
explosion hazard. When vapors of an inflammable organic compound are mixed
with air in the proper proportion, ignition can produce an explosion. An
increase in temperature of a mixture of organic vapors with air expands the
range of organics concentration capable of leading to an explosion. Because
of the explosion hazard, many insurance regulations limit the inflammable
organics concentration to 25 percent of the lower explosive limit in air.
In some cases to maintain reaction conditions below the explosive limit,
large quantities of excess air are used. Alternatively, low inlet
concentrations can be achieved by recycling a portion of the reactor offgas
back to the reactor system. Some processes, however, can operate above the
explosive limit. For example, in the manufacture of formaldehyde by silver
catalyst process, methanoKgoncentration in the gas stream is maintained
above the explosive limit. It is, however, possible that some processes,
by use of fluidized bed reactors, gas stream recycle, or utilizing
sophisticated heat transfer systems may operate within the apparent
explosive range.
The explosion hazard of an air oxidation process is also dependent on
the auto-ignition temperature of the reactants and the product. The
auto-ignition temperature is defined as that minimum temperature required to
initiate or cause self-sustained combustion independently of the heating or
heated element. Compounds having low auto-ignition temperature would
require better heat removal. The use of high excess air again provides a
method of realizing adequate heat removal.
2.4 STATISTICAL ANALYSIS OF AIR OXIDATION PROCESSES
In this section, results of statistical analysis of existing air
oxidation processes are presented. The purpose of the analysis is to
develop a nationwide VOC emission profile. The analysis was based on the
2-28
-------
nU)|Mir.T
IK COVE it Y
FEEDSTOCK
STORAGE
wo
AIR
OFFG*
PURIFICATION
SECTION
> PRODUCT
Figure 2-2. Schematic of a flowsheet for a vapor phase air oxidation process.
-------
data collected from 59 plants producing 14 SOCMI chemicals by air oxidation
processes. The details of the statistical procedure and the analysis of the
data are presented in Appendix B. The following are the conclusions of the
statistical analysis.
1. Of the 14 SOCMI chemicals included in the data base, one chemical
is produced in both liquid and vapor phase, while of the remaining 13
chemicals, eight are produced in the vapor phase and five in the liquid
phase.
2. The ratio of excess air to the stoichiometric air requirement for
vapor phase oxidation processes ranges from less than one to 13.
3. All liquid phase reactions examined have the ratio of excess air
to the stoichiometric air requirement of less than three.
4. Excess air requirement is influenced by reaction stoichiometry,
reaction temperature, auto-ignition temperatures, and explosive limits.
5. Of the 44 plants producing SOCMI chemicals in the vapor phase,
the distribution of flows, VOC, and heat content shows that 35 plants have
streams with less than 1.0 volume percent VOC; 38 plants have flows less
than 50,000 scfm and 19 plants have streams with less than 20 Btu/scf heat
content. The maximum VOC content is 2.2 volume percent, the maximum flow is
117,000 scfm, and the maximum heat content is 122.55 Btu/scf.
6. Of the 15 plants producing SOCMI chemicals in the liquid phase,
the distribution of flows, VOC, and heat content shows that nine plants have
streams with less than 0.1 volume percent VOC, seven plants have flow less
than 10,000 scfm, and 14 plants have streams with less than 20 Btu/scf heat
content. The maximum VOC content is 0.76 volume percent, the maximum flow
is 60,000 scfm, and the maximum heat content is 43.8 Btu/scf.
2.4.1 National Emission Profile
Air oxidation facilities use 36 types of oxidation processes (23
principal processes and 13 specialty processes) to manufacture 36 different
organic chemicals. Because of the number and diversity of facilities and
processes in the air oxidation industry, a chemical-by-chemical development
of CTG's would require large amounts of time, effort, and money. A unit
process approach, on the other hand, allows development of a CTG that
provides for regulatory development for VOC emissions from all SOCMI air
oxidation processes. This unit process approach allows the resource-
efficient statistical estimation of the RACT impacts for VOC emissions
control from all air oxidation processes.
In the unit process approach, no model plants are used for impact
analysis. Rather, the information concerning existing air oxidation
facilities is analyzed statistically and used to construct a national
profile. This national profile replaces the traditional model plant and can
be considered a statistical model of SOCMI air oxidation processes and
facilities. The national profile characterizes air oxidation processes
according to national distributions of key variables (e.g., vent gas stream
flowrate, net heating value, hourly VOC emissions, and whether the offgas
contains halogenated compounds) that can be used to determine VOC emissions
and the cost and energy impacts associated with RACT. RACT is therefore
examined as a percent VOC emission reduction based on thermal oxidation as
2-30
-------
the single control technique. The RACT impacts are evaluated as impacts
upon the entire population of affected facilities.
The actual use of the national statistical profile assumes that the
distribution of offgas flowrate, hourly emissions, net heating value, and
corrosion properties is chemical independent. Chemical identities are not
considered in the profile, nor is there claimed to be a one-to-one
correspondence between any one data vector and an existing offgas stream.
It is assumed, however, that the overall proportions and distributions of
the parameter values and data vectors be similar to those of the existing
population of air oxidation facilities. Thus, since the national
statistical profile contains 59 data vectors, each data vector and
associated impacts of population control represents 1/59 of the existing
population to be analyzed for control.
The national emissiongprofile was constructed using emissions data from
the Houdry questionnaire. The questionnaire covered 14 major air
oxidation chemicals. These chemicals are shown in Table 2-11. A total of
59 air oxidation plants are represented by the Houdry data, which is about
36 percent of the total air oxidation plants in existence today.
2-31
-------
TABLE 2-11. CHEMICALS COVERED BY HOUDRY QUESTIONNAIRE
Chemical
Acetaldehyde
Acetic Acid
Acrylonitrile
Cyclohexanone/Cyclohexanol
Dimethyl Terephthalate
Ethylene Dichloride
Ethylene Oxide
Formaldehyde
Formaldehyde
Hydrogen Cyanide
Maleic Anhydride
Phenol
Phthalic Anhydride
Terephthalic Acid
Process Number of
Hrocess Plants
Ethanol 1
Ethylene 1
Butane 1
Propylene 4
Cyclohexane 3
p-Xylene, Methanol 2
Oxychlorination 9
Ethylene 4
Methanol Silver Catalyst 9
Methanol Mixed Metal 4
Ammoxidation Methane 1
Benzene 7
Cumene 6
Naphthalene 2
o-Xylene • 3
p-Xylene 2
2-32
-------
REFERENCES FOR CHAPTER 2
1. Morrison, R.T. and R.N. Boyd. Organic Chemistry, Third Edition, Allen
and Bacon, Inc., Boston, January 1975.
2. Op. cit, Reference 1.
3. The Kline Guide to the Chemical Industry. Meegan, Mary K. and
Noble, Patricia, eds.C.H. Kline and Company. Fairfield, New Jersey.
1977, 299 pp.
4. Chemical Engineering, June 6, 1977, page 142.
5. Chemical and Engineering News, January 29, 1979, page 13.
6. 1979 Directory of Chemical Producers, United States of America.
Stanford Research Institute International, Menlo Park, California,
1979.
7. Darby, W.P. et. al., Regulation of Air Oxidation Processes Within the
Synthetic Organic Chemical Manufacturing Industry: Background Informa-
tion and Analysis. St. Louis, Washington University, 1981. pp. 36,
Appendix A.
8. Ibid.
9. Op. cit., see Reference 7.
10. Ibid.
11. Darby, op. cit.
12. Ibid.
13. Op. cit., see Reference 7.
14. Weissermel, K. and H.J. Arpe, Industrial Organic Chemistry, Verlag
Chemie, Weinheim, New York, 1978.
15. Lowenheim, F.A. and M.K. Moran, Faith, Keyes and Clark's Industrial
Chemicals, Fourth Edition. New York, A. Wiley-Interscience Publication,
16. Liepins, R., F. Mixon, C. Hudak, and T.B. Parsons. Industrial Process
Profiles for Environmental Use, Chapter 6, The Industrial Organic
Chemicals Industry. EPA-600/2-77-023f. U.S. Environmental Protection
Agency. Cincinnati, Ohio. February 1977.
17. Darby, op. cit.
2-33
-------
18. Bruce, W.D. and J.W. Blackburn. Emissions Control Options for the
Synthetic Organic Chemicals Manufacturing Industry, Cyclohexanol/
Cyclohexanone Product Report. Report 2. U.S. Environmental Protection
Agency. Research Triangle Park, NC. EPA-450/3-80-028a.
December 1980.
19. Hobbs, F.D. and J.A. Key. Emissions Control Options for the Synthetic
Organic Chemicals Manufacturing Industry, Acrylonitrile Product Report.
Report 2. U.S. Environmental Protection Agency, Research Triangle
Park, NC. EPA-450/3-80-028e. December 1980.
20. Lawson, J.F. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry, Maleic Anhydride - Product Report.
Report 4. U.S. Environmental Protection Agency, Research Triangle
Park, NC. EPA-450/3-80-028a. December 1980.
21. Op. cit., Reference 8.
22. Weissermel, K. and H.J. Arpe, Industrial Organic Chemistry. Weinheim -
New York, Verlag Chemie, 1978. p. 128-131.
23. Groggins, P.H., Unit Processes in Organic Synthesis. Fifth Edition, p.
486-556, 1958.
24. Ibid.
25. Ibid.
26. Lovell, R.J. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry, Formaldehyde Product Report.
Report 1. U.S. Environmental Protection Agency. Research Triangle
Park, NC. E'PA-450/3-80-028d. December 1980.
27. U.S. Environmental Protection Agency. Organic Chemical Manufacturing:
Program Report. Volume 1. EPA-450/3-80-023. Office of Air Quality
Planning and Standards, Research Triangle Park, NC. December 1980.
28. Guide for Safety in the Chemical Laboratory. Manufacturing Chemists
Association.Van Nostrand Reinhold Company, New York, 1972. 505 pp.
29. Survey Reports on Atmospheric Emissions from the Petrochemical
Industry, prepared by Houdry Division of Air Products and Chemical,
Inc. (data on file at EPA, ESED, Research Triangle Park, NC, 1972).
30. 1983 Directory of Chemical Producers, United States of America.
Stanford Research Institute International, Menlo Park, California,
1983.
2-34
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3. EMISSION CONTROL TECHNIQUES
3.1 INTRODUCTION
This chapter describes the control techniques and associated emission
reduction effectiveness for air oxidation unit 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 thermal oxidation since it is a VOC control
method universally applicable to SOCMI air oxidation 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 air oxidation VOC emissions control by these methods would be
unwieldy. Also, control systems based on condensation or absorption are
generally used as product recovery devices, and the removal efficiencies
decrease as the VOC concentrations decrease.
Thermal oxidation, however, is much less dependent on process and waste
stream conditions than the other control techniques. It is the only
demonstrated VOC control which is applicable to all SOCMI air oxidation
processes. Incinerator cost and efficiency determinations require a limited
amount of waste stream data (volume flow, hourly emissions, net heating
value, and corrosive properties). The choice of thermal oxidation as the
single control technique for analysis yields conservative estimates of
energy, economic, and environmental impacts since thermal oxidation is
relatively expensive and energy-intensive.
All new incinerators can achieve at least a 98 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 1600°F and 0.75 second residence time.
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 product
recovery devices such as absorbers, adsorbers, and condensers alone, or in
conjunction with VOC control devices such as boilers and thermal and
catalytic oxidizers to achieve reduction of VOC emissions. Detailed
descriptions and efficiency data are available in Appendix A and in the
references.
Boilers can be useful as VOC control devices only when the waste gas
stream volume flow is not large enough to upset the combustion process.
Furthermore, the waste gas 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. The only air oxidation process which currently
employs a boiler or process heater for VOC control is the Andrussow process
for manufacture of hydrogen cyanide.
3-1
-------
All air oxidation 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.
Table 3-1 shows some of the SOCMI air oxidation chemical processes and
the product recovery-VOC emission control methods used.
3.2 ADSORPTION
The main function of vapor-phase carbon adsorption is to contain and
concentrate dilute organic vapors from waste streams where condensers or
absorbers are ineffective or uneconomical. Carbon adsorption in most cases
is used for recovery of expensive, unreacted raw material and not for VOC
emission control. The major application of carbon adsorption in air
oxidation processes is for the recovery of aromatic feedstocks such as
benzene, xylene, and cumene. Selected air oxidation processes known to
employ carbon adsorption are listed in Table 3-2.
Adsorption devices work by capturing vapor-phase molecules upon the
surface of a solid. The molecules adhere primarily through two mechanisms:
(1) physical adsorption, in which Van der Waal '.s forces attract and hold the
gas molecules to the adsorbent surface, and (2) chemical adsorption
(chemisorption), in which the molecules are chemically bonded to the
adsorbent.
Oxygenated adsorbents such as silica gels, fullers, diatomaceous, and
other siliceous earths, synthetic zeolites, and metallic oxides exhibit
greater selectivity than activated carbon. However, due to their affinity
for polar molecules, they have a greater preference for water than organics
and are of little use on the moist air streams from SOCMI air oxidation
process vents. Vent stream dehumidification may be possible but will
necessitate more equipment and increase treatment cost.
3.2.1 Carbon Adsorption Process
Material recovery by carbon adsorption may be too difficult or
expensive^for some chemicals when their vapor concentrations are below
700 ppmv. Although carbon adsorption system configurations vary according
to the volume of gas handled and allowable pressure drop, a typical set-up
is shown in Figure 3-1. After filtering and cooling, the waste gas is
directed through a bed of carbon granules (Adsorber 1). In time, traces of
organic vapors appear in the exit air and the removal efficiency rapidly
decreases (breakthrough). At this point, the waste gas stream is routed
through a fresh bed, and the saturated bed is regenerated by passing a hot
gas through it to desorb (strip) the organics from the carbon. Low-pressure
steam is a common regeneration fluid providing a concentration gradient to
facilitate mass transfer of adsorbate from the carbon bed and supplying the
heat of desorption. The steam and organic vapors are then condensed and the
3-2
-------
TABLE 3-1. PRODUCT RECOVERY AND EMISSION CONTROLS CURRENTLY USED IN ONE OR MORE
PLANTS EMPLOYING MAJOR AIR OXIDATION PROCESSES
Chemical
Acetic Acid/Formic
Acid/Methyl Ethyl
Ketone
Acetone/Phenol
Acrylonitrile
Acrylic Acid
1,3-Butadiene
Cyclohexanol/
Cyclohexanone
Ethylene Dichloride
Ethylene Oxide
Formaldehyde
Formaldehyde
Hydrogen Cyanide
Maleic Anhydride
Maleic Anhydride
Phthalic Anhydride
Phthalic Anhydride
Propylene Oxide/
Styrene
Terephthalic Acid/Di-
Process
Product or Raw Material
Recovery Equipment
Emission
Control Equipment
Acetaldehyde
Acetic Acid
Wacker
Wacker
1, 2
1, 2
Butane
Cumene Peroxidation
Propene Ammoxidation
Propene
Butene Oxidative
Dehydrogenation
Cyclohexane
Ethylene Oxychlorination
Ethylene
Silver Catalyst
Mixed Metal Oxide
Catalyst
Andrussow
Benzene
Butane
Naphthalene
Xylene
Ethyl benzene Peroxidation
methyl Terephthalate Xylene
1, 2
1, 3
1, 2
1, 2
1, 2
U 2
1, 2
1, 2
1, 2
1, 2
2
1, 2, 3
1, 2
1, 2
1, 2
1, 2
1, 2, 3
5
4B
4B
4B, 5
5
6
4B, 5
4
4
4B
KEY:
1 Condenser
2 Absorber
3 Carbon Adsorber
4 Thermal Incineration
4B Thermal Incinerator - Waste Heat Boiler
5 Catalytic Incinerator
6 Process Heater or Boiler
3-3
-------
TABLE 3-2. SELECTED AIR OXIDATION PROCESSES KNOWN TO USE CARBON ADSORPTION
FOR PRODUCT/RAW MATERIAL RECOVERY OR EMISSION REDUCTION
Chemical Primary Compound Recovered
Acetone/Phenol Cumene
Maleic Anhydride Benzene
Terephthalic Acid/
Dimethyl Terephthalate Xylene
3-4
-------
VOC-LJftn
VntStntti
FILTERING
AND
COOUNG
FAN
OMO
Ciowd
ADSORBER I
< ADSORBING)
ADSORBER 2
'REGENERATING)
ClosM
QMfl
VENT TO
ATMOSPHERE
( CONDENSER J
OECANTQR
and/or
DISTILLING TOWER
Recovtred
Solvent
Water
Figure 3—1. Two stage regenerative adsorption system
3-5
-------
organics separated from the water by decantation and/or distillation. The
freshly-regenerated bed is cooled, dried, and prepared for another service
cycle.
3.2.2 Carbon Adsorption Emissions Removal Efficiency
State-of-the-art carbon adsorption systems for VOC recovery can have
outlet concentrations in the range of 50 to 100 ppmv.with concentrations as
low as 10 to 20 ppmv achievable with some compounds. For inlet concentra-
tions from 700 to 5000 ppmv, these numbers yield an expected VOC adsorption
removal efficiency range of 86 to 99 percent. Adsorption removal
efficiencies up to 95 percent can be achieved from some chemicals in
well designed systems.
3.2.3 Parameters Affecting VOC Removal Efficiency
The most important operating parameter affecting continuing VOC removal
efficiency is the amount of steam used for regeneration. The graph given as
Figure 3-2 shows' a generalized form of the relationship of effluent VOC
concentration to steam usage. The exact relationship depends on the type of
VOC being removed and on the operating characteristics of the system.
Figure 3-2 shows that reduced effluent concentration is obtained by
increasing the steam ratio and that very low effluent concentration levels
may be obtained with high steam ratio. Figure 3-2 shows that the position
of the effluent concentration curve for each particular compound is a
function of the adsorption temperature, regeneration temperature, and carbon
loading capacity. The effluent concentration curve is relatively independent
of inlet VOC concentrations. When the adsorption temperature increases, the
effluent concentration curve baseline may increase. Higher regeneration
temperatures may shift the effluent outlet concentration curve downward. A
different loading capacity may shift the curve laterally, since different
amounts of steam may be required to regenerate the carbon.
VOC with molecular weights below 45 do not adsorb well on carbon; high
(>130i molecular weight VOC are more difficult to remove during regenera-
tion. Also, during adsorption of multicomponent gas streams, the higher
boiling point components tend to displace the lower boiling point components
from the adsorption sites on the carbon.
Adsorption rates decrease sharply for gas streams with temperatures of
38°C (100°F) and above. ' Inlet VOC concentrations may be limited to
25 percent of LEL (.5000 ppmv) by insurance requirements. Although some
moisture is desirable in the waste gas to help dissipate the heat of
adsorption and provide more uniform bed temperatures, excessive humidity can
adversely affect the VOC removal efficiency of a carbon adsorption system.
Mist in the gas stream can rapidly saturate an adsorption bed, taking up
adsorption sites. Operating capacity^decreases become pronounced at
relative humidities over 50 percent.
3.2.4 Factors Affecting Applicability and Reliability
Although carbon adsorption can be used for product recovery and to help
control VOC emissions, it is not a control method generally applicable to
SOCMI air oxidation processes. The vent streams from some of these
3-6
-------
EFFLUENT VOC-
ti • adsorption temperature
-regeneration temperature
f (ti, tz, carbon loading capacity,
and type of compound)
STEAM RATIO
(Ibof steam/1b of carbon)
Figure 3-2. Generalized form of the relationship of effluent
VQC concentration to steam usage.
Due to the generalized nature of the relationship, the axis is not numPered. However, it is marked off m a logarithmic scale.
3-7
-------
processes are often saturated with moisture. This would result in serious
loss of adsorption capacity due to the water saturating the adsorbing medium
and taking up adsorption sites. Such process vent streams require
dehumidification to lower the water content. Process upsets which increase
vent stream VOC composition are not uncommon in air oxidation processes, and
may result in an excessive temperature rise due to the accumulated heat of
adsorption of the extra VOC loading.
3.3 ABSORPTION
Absorption is one of the two primary methods of product recovery used
in air oxidation processes. Absorbers are also commonly applied as
auxiliary control devices prior to combustion devices. An absorber can be
added to an existing process for the purpose of VOC control, or an existing
absorber could be modified, perhaps by an increase in the size or a decrease
in the operating temperature, for the purpose of VOC control. Some of the
air oxidation processes which employ absorption are listed in Table 3-3.
Gas absorption devices work by dissolving the soluble components of a
gaseous mixture in a liquid. Absorption may only entail the physical
phenomenon of solution or may also-,involve chemical reaction of the solute
with constituents of the solution. The absorbing liquids (solvents) used
are chosen for high solute (VOC) solubility and include liquids such as
water, mineral oils, non-volatile hydrocarbon oils, .and aqueous solutions of
oxidizing agents like sodium carbonate and sodium hydroxide. Devices
based on absorption principles include spray towers, venturi scrubbers,
packed columns, and plate columns. Spray towers require high pressure to
obtain droplets ranging in size from 500-,to 1000 mm in order to present a
sufficiently large surface contact area. They can remove particulate
matter without plugging, but have the least effective mass transfer
capability and thus, are restricted to particulate remova]5and control of
high-solubility gases such as sulfur dioxide and ammonia. Venturi
scrubbers have a high degree of gas-liquid mixing and high particulate
removal efficiency but require high pressure and have relatively short -jg
contact times, so their use is also restricted to high-solubility gases.
The choice for gas absorption is thus between packed and plate columns.
Packed columns are mostly used for handling corrosive materials and liquids
with foaming or plugging tendencies. They are less expensive than plate
columns for small-scale or pilot plant operations where the column diameter
is less than 0.6 m (2 ft). Plate columns are preferable for large-scale
operations, where internal cooling is desired and where low liquid flowrates
would inadequately wet the packing.
3.3.1 Absorption Process
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 diffusion to the solvent and dissolution into it. For any given
solvent, solute, and set of operating conditions, there exists an
equilibrium ratio of so]ute concentration in the gas mixture to concen-
tration in the solvent. The driving force for mass transfer at a given
point in the operating tower is related to the^ifference between the actual
concentration ratio and the equilibrium ratio.
3-8
-------
TABLE 3-3. SELECTED AIR OXIDATION PROCESSES KNOWN TO USE ABSORPTION FOR
PRODUCT RAW MATERIAL RECOVERY OR EMISSIONS REDUCTION
Chemical
Acetaldehyde
Acetic Acid/Formic Acid/MEK
Acrylonitrile
Acrylic Acid
1,3-Butadiene
Cyclohexanol/Cyclohexanone
Ethylene Dichloride
Ethylene Oxide
Formaldehyde
Hydrogen Cyanide
Maleic Anhydride
Phthalic Anhydride
Propylene Oxide/Styrene
Terephthalic Acid/Dimethyl Terephthalate
3-9
-------
A schematic of a packed, gas absorption tower is shown in Figure 3-3.
The waste gas of VOC concentration y.Q enters at the bottom and rises
through the packing, contacting the absorbing liquid on the surface of the
packing material. The VOC (solute) is dissolved in the absorbent liquid
(solvent) and is discharged at the bottom of the tower for recovery or
disposal. The cleaned gas exits at the top with reduced VOC concentration
y., , ready for release or final treatment such as incineration.
3.3.2 Absorption VOC Removal Efficiencies
Systems that utilize organic liquids as solvents usually include the
stripping and recycling of the solvent to the absorber. In this case the
VOC removal efficiency of the absorber is dependent on the solvent stripping
efficiency. If, for example, a system achieved a removal efficiency in
excess of 99 percent with once-through solvent usage, it would be expected
that the removal efficiency would drop to about 94 percent with solvent
recycling. Once-through solvent usage can create a liquid waste problem
and incur additional treatment costs.
For a given absorbent and absorbate, 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.
3.3.3 Factors Affecting Efficiency and.Reliability
The effectiveness of an absorption tower, which is the rate of mass
transfer between the two phases, is largely dependent upon the available
gas-liquid contact area. In packed towers, a reduction in the liquid-to-
gas ratio can lead to channeling where some of the packing is not wetted by
the liquid. Excessive gas flowrates can increase the liquid holdup until
the tower floods and liquid exists at the top with the gas.
VOC concentration can affect the operation of absorption equipment.
Excessive VOC loading can raise the temperature of the tower due to
increased rate of release of the heat of solution, resulting in a decreased
concentration gradient. Absorption is usually not considered when the VOC
concentration is below 200-300 ppmv.
3.4 CONDENSATION
Condensation is one of the two primary methods of product recovery used
in air oxidation processes. Condensers are also commonly applied as
auxiliary control?devices before thermal incinerators, adsorbers, and other
control devices. An existing condenser can be modified for improved VOC
emission control by lowering the operating temperature. The suitability of
condensation as an emissions control method depends on several parameters.
These include the VOC concentration at the inlet (usually >1 percent), the
VOC removal efficiency required, the VOC recovery value,^nd the size of the
condenser required for handling the gas volume flowrate. £|r oxidation
processes which employ condensation are listed in Table 3-4. ^5
Condensation devices are usually surface or contact condensers.
Contact condensers spray a cooled liquid directly into the gas ^ream, also
acting as scrubbers in removing normally noncondensable vapors. The
3-10
-------
CLEANED GAS OUT
^ To Final Control Device
ABSORBING
UQUIO IN
VOC LADEN
GAS IN
XAQ
ABSORBING LIQUID
WITH VOC OUT
To Oisoosai or VOC/Soivent Recovery
Figure 3—3. Packed tower for gas absorption.
3-11
-------
TABLE 3-4. SELECTED AIR OXIDATION PROCESSES KNOWN TO USE CONDENSATION FOR
PRODUCT/RAW MATERIAL RECOVERY OR EMISSIONS REDUCTION
Chemical
Acetaldehyde
Acetic Acid/Formic Acid/MEK
Acetone/Phenol
Acrylonitrile
Acrylic Acid
1,3-Butadiene
Cyclohexanol/Cyclohexanone
Ethylene Dichloride
Ethylene Oxide
Formaldehyde
Maleic Anhydride
Phthalic Anhydride
Propylene Oxide/Styrene
Terephthalic Acid/Dimethyl Terephthalate
3-12
-------
27
coolant is usually water or perhaps a process feed stream. Contact
condensers are generally cheaper, more flexible and efficient for VOC
removal. However, the spent coolant can2gresent a secondary emissions
source or waste water treatment problem. Surface condensers have more
auxiliary equipment but can recover valuable and marketable VOC. They do
not contaminate the coolant, therefore minimizing waste disposal problems.
Only surface condensers are discussed in this section.
3.4.1 Condensation Process
Condensation occurs when the partial pressure of a condensable
component equals its vapor pressure at that temperature. Most surface
condensers are of the shell*and-tube type and achieve condensation by
removing heat from vapors. As the coolant passes over the tubes, the VOC
vapors condense inside the tubes and are recovered. The coolant used
depends upon the saturation temperature (dewpoint) of the VOC. Chilled
water can be used down to 7°C (45°F)% brines to -34°C (-30°F), and freons
below -34°C (-30°F). u Temperatures as low as -62°C (-80°|] may be
necessary to obtain the required VOC removal efficiencies. A table of the
estimated operating temperature required to achieve a given VOC removal
efficiency is given in Reference 31. These temperatures were estimated for
aliphatic and halogenated aliphatic hydrocarbons as a function of inlet VOC
concentration.
The major pieces of equipment of a condenser system (as shown in
Figure 3-4) are the shell-and-tube heat exchanger (condenser), refrigeration
system (coolant supply), storage tanks, and pumps.
3.4.2 Condenser VOC Removal Efficiency
VOC removal efficiencies of 50 percent are typical of a condenser used
in conjunction with other control devices. The maximum efficiency reported
is close to 95 oercent with average efficiencies of 80 percent reported in
the literature.
3.4.3 Parameters Affecting Reliability and Efficiency
Condensers used for VOC control often operate at temperatures below the
freezing point of water. This requires that moist vent streams, such as
those found in air oxidation processes, be dehumidified before VOC removal
to prevent the formation of ice in the condenser. Particulate matter must
not be allowed to enter a surface condenser system since it may deposit on
the finned tubes and interfere with gas flows and heat transfer. Gas
flowrates from 100 to 2000 cfm are representative of the capacity range for
condensers as emission control devices. Vent streams containing less than
one-half percent VOC are generally not considered for control by
condensation.
3.5 CONTROL BY COMBUSTION TECHNIQUES
Combustion control techniques result in the destruction of the raw
material or product present in the offgas. Therefore, they are usually to
be considered add-on emission control techniques. Although the process
material can never be recovered, it is possible to recover much of the
3-13
-------
CLEANED GAS OUT
To Pniiaiy Coiiliol Plate,
Alleibuinei, Elc.
VOC LADEN GAS
DEHUMIOIFICATION
UNIT
To Remove Vfalei
and
Pievenl fieezmg
in Uaiii Condense!
CO
i
CONDENSER
4 4 J
COOLANT
RETURN
COOLANT
CONDENSED
VOC
REFRIGERATION
PLANT
STORAGE
TO PROCESS
Of Disposal
Figure 3-4. Condensation system.
-------
thermal energy released by combustion. In the case of offgas with a high
heating value, it may be economically attractive to combust the vent stream
in a boiler or process heater.
3.5.1 General Combustion Principles
Combustion is a rapid, exothermic oxidation process which results in
the complete or incomplete oxidation of VOC. Most fuels and VOC contain
carbon and hydrogen which, when burned to completion with oxygen, form
carbon dioxide and water.
Since air oxidation vent streams generally contain little oxygen,
additional combustion air must be provided. The total gas volume flow is
therefore relatively larger than that associated with other types of
control .
3.5.2 Combustion Control Devices
Control devices using combustion principles include furnaces, boilers,
and thermal and catalytic oxidizers. Combustion in thermal and catalytic
oxidizers are the usual control methods for air oxidation processes.
Furnaces and boilers are only occasionally used as control devices for
the larger air oxidation vent streams because the fuel requirements of their
firing cycles may not coincide with the availability or heating value of the
offgas. Waste streams with large flows and low heating values can adversely
affect the operation of these devices in two ways. By lowering furnace
temperatures, they cause incomplete combustion and diminished steam
production. Furthermore, an increased volume flow of gases can exceed the
handling capabilities of the exhaust system.
Catalytic oxidizers are not widely used because the catalysts can be
poisoned by sulfur- and halogen-containing compounds. Moreover, increases
of VOC concentration in poorly controlled streams can raise the catalyst bed
temperature excessively to the point of deactivating the catalyst.
3.5.3 Thermal Oxidizers
Thermal oxidation is the method of VOC emission control most widely
used for air oxidation processes because it is applicable to a variety of
chemicals and vent streams conditions. Incineration is the usual method of
pollution control for waste. streams with combustible concentration below the
°
LEL (about.,470 2J-&- ° 53 |^) such as those found in SOCMI air oxidation
processes. Taole 3-5 is a partial listing of chemical processes using
thermal oxidation for VOC control.
Thermal oxidizers can also control halogenated VOC. However, a higher
chamber temperature is required to properly oxidize chlorinated hydrocarbons
and convert the noxious combustion products to a form more readily removable
by flue gas scrubbing.
3.5.3.1 Thermal Oxidation Process. The combustion process is
influenced by time, mixing, and temperature. An efficient thermal oxidizer
must provide:
1. A chamber temperature high enough to enable the oxidation reaction
to proceed rapidly to completion »
3-15
-------
TABLE 3-5. PARTIAL LIST OF AIR OXIDATION CHEMICALS USING
THERMAL OXIDIZER FOR CONTROLLING VOC EMISSIONS
FROM OFFGAS STREAM
Chemical
Number of
Plants Reported
Reported
Operating
Temperature (°F)
Reported
Efficiency
Butadiene
Acrylic Acid
Acrylonitrile
Formaldehyde
Phthalic Anhydride
Maleic Anhydride
Maleic Anhydride
Not Reported
Not Reported
1800
2000
1200
1400
1600
Not Reported
Not Reported
>99%c ,
99.8-100%°
90-95%
93%
99%
Standifer, R.L. Butadiene Product Report. I.T. Enviroscience.
EPA-450/3-80-028e.
Blackburn, J.W. Acrylic Acid and Esters Report. I.T. Enviroscience.
EPA-450/3-80-028e.
cHobbs, F.D. and Key, J.A. Acrylonitrile Product Report. I.T. Enviroscience.
EPA-450/3-80-028e.
Lovell , R.J. Formaldehyde Product Report. I.T. Enviroscience.
EPA-450/3-80-028d.
eOffice of Air and Waste Management. U.S. Environmental Protection Agency.
Research Triangle Park, NC. Control Techniques for Volatile Organic
Emissions from Stationary Sources. Publication No. EPA-450/2-78-022.
May 1978.
^Lawson, J.F. Maleic Anhydride Product Report. I.T. Enviroscience.
EPA-450/3-80-028a.
3-16
-------
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.
Combustion chamber temperature is an important parameter in the design
of a thermal oxidizer since oxidation rates are highly temperature-dependent.
Incineration of low heating value offgas necessitates the burning of an
auxiliary fuel to achieve the desired chamber temperature. Destruction of
most VOC occurs rapidly at temperatures over 760°C (HOOT). However,
higher temperatures, on the order of 980°-1100°C (1800°-2000°F) , may be
required when incinerating halogenated VOC.
Mixing is crucial in achieving good thermal oxidizer performance. A
properly designed incinerator rapidly combines the offgas, combustion air,
and hot combustion products from the burner. This ensures that the VOC be
in contact with sufficient oxygen at a temperature high enough to start the
oxidation reaction. Improper mixing can permit packets of waste gas to pass
through the incinerator intact. Poor mixing can also lead to poor
temperature distributions so that not all the waste gas stream reaches or
remains at the design combustion temperature.
Residence time is the time available for the oxidation reaction to
occur within the combustion chamber. Residence times fronuas low as 0.3 to
several seconds have been used in thermal oxidizer design. Vendors
generally define residence times in one of two ways. Some count offgas
residence time in any of the available volume of the combustion chamber.
Others credit only residence time within that volume in which the flue gas
is at the combustion temperature. It is this volume which is theoretically
related to destruction efficiency. Therefore, incinerator efficiency data
which use the latter definition of residence time are more easily compared
in an analysis of the relationship of destruction efficiency to residence
time. Moreover, according to this definition, a larger combustion chamber
is required to achieve a given residence time. Therefore, this definition
yields more conservative estimates of the cost of control.
Other parameters affecting oxidizer performance are offgas heating
value, water content, and excess combustion air. The offgas heating value
is a measure of the heat available from the combustion of the VOC in the
offgas to C02 and HLO. The, heat OjTcombustion for specific organic com-
pounds can rangeRfr6m 950 -A (25 -^) for carbon tetrachloride (CC1/) to
35, 700 S- (960^) for meThane (CNl)-?5 Incineration of offgas with a low
heatingTalue (lesi than 1860 £±3- (50 |^)) may require the burning of an
auxiliary fuel to maintain the aesi red combustion temperature. Auxiliary
fuel requirements can be lessened or eliminated by the use,of recuperative
heat exchangers. Offgas with a heating value above 1860 |p3- (50 -^i-) may
support combustion but may need auxiliary fuel for
Combustion of an offgas with a heating value over 5200 p3- (140 -q) can
result in flame temperatures in excess of 1200°C (2200°^. Conventional
oxidation equipment can only be used for such streams if the temperature is
kept below 1200°C (2200°F) by addition of air, water vapor, or liquid water
or circulation of exhaust gas.
3-17
-------
A thermal oxidizer handling offgas streams with varying heating values
requires adjustment to maintain the proper chamber temperatures and
operating-efficiency. Water has a heat of vaporization ,of 41,390 (KJ/fkg mol)
(18'°°° TTTSoT> and a heat c*P*city of 'bout 27.5 kg J *c (11.8 1b ffi *F
kg
at 870°C (1600°F) and 101 kPa (14.7 psia). Entrained water droplets in an
offgas stream can substantially increase auxiliary fuel requirements due to
the additional energy needed to vaporize the water and raise it to the
combustion chamber temperature. 'Combustion devices are operated with some
quantity of excess air to ensure a sufficient supply of oxygen. Too much
excess air causes an increase in auxiliary fuel requirements since the extra
air is heated up to chamber temperature. Too much excess air also increases
the thermal oxidizer's flue gas volume flow rate and, thus, its size and
cost.
3.5.3.2 Thermal Oxidizer Design. A thermal oxidizer is usually a
refractory-lined chamber containing a burner at one end and generally
operated at3a temperature of 550°-850°C with a residence time of from 0.3 to
one second.
Discrete dual fuel burner(s) and inlets for the offgas and combustion
air are so arranged in the chamber to thoroughly mix the hot products from
the burners with the offgas and air streams. The mixture of hot reacting
gases then passes into the reaction section. This section is sized to allow
the mixture enough time at the elevated temperature 'for the oxidation
reaction to reach completion. Energy can then be recovered from the hot
flue gases in the heat recovery section. Preheating of combustion air by
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 be maintained below 40
percent of LEL to eliminate explosion hazards.
Thermal oxidizers designed specifically for VOC incineration with
natural gas as the auxiliary fuel may use a grid-type (distributed) gas
burner instead of the conventional dual fuel, forward flame, discrete
burners. The tiny gas flame jets on the grid surface ignite the vapors as
they pass through the grid and ensure burning of all the vapors at lower
chamber temperatures using less fuel and allowing for a shorter reaction
chamber. Typical configurations are shown in Figures 3-5 and 3-6.
Thermal oxidizers for halogenated VOC control require additional
control equipment. The flue gases are quenched to lower their temperature
and routed through absorption equipment such as towers or liquid jet
scrubbers to remove the halogenated combustion products.
Packaged, single unit thermal oxidizers can be built to control streams
with flowrates in the range of a few hundred scfm to about 50,000 scfm. A
typical thermal oxidizer built to handle a VOC waste stream of 850 Nm /nrin
(30,000 scfm) at a temperature of 870°C (1600°F) with 0.75 second residence
time probably would be a refractory-lined cylinder. Assuming the ratio of
flue gas to waste gas is about 2.2, the chamber volume necessary to grovide
the residence time at that temperature would be about 99 m (3500 ft ). If
the chamber length to diameter ratio is two to one, and allowing a 30.5 cm
(1 ft) wall thickness, the thermal oxidizer would measure 8.3 m (27 ft) long
by 4.6 m (15 ft) wide, exclusive of heat exchangers and exhaust equipment.
3-18
-------
Waste Gas
Auxiliary
Fuel Burner
(discrete)
Waste Gas
Stack
Mixing
Section
Combustion
Section
Optional
Heat
Recovery
Figure 3-5. Discrete burner, thermal oxidizer.
Burner Plate-. Flume Jets-
'natural gas)
Auxiliary Fuel
Optional
Heat
Recovery
Figure 3—6. Distributed burner, thermal oxidizer.
3-19
-------
3.5.3.3 Thermal Oxidizer Emission Destruction Effectiveness. Based on
a study of thermal oxidizer efficiency, cost and fuel use, it is concluded
that 98 percent VOC reduction, or 20 ppmv as compound exit concentration
(whichever is less stringent) is the highest reasonable control level
achievable by all new incinerators in all air oxidation processes,
considering current technology. An analysis assuming achievement of this
efficiency with incinerator operation at 870°C (1600°F) and 0.75 second
residence time yields conservative estimates of costs and energy use.
The VOC destruction efficiency of an incinerator can be affected by
variations in chamber temperature, residence time, inlet concentration,
compound type, and flow regime (mixing). A combustion chamber temperature
of 870°C (1600°F) was chosen for the analysis on the basis that higher
temperatures, with higher control efficiencies, are preferred. Test results
show that 98 percent destruction efficiency is achievable at various
temperatures (700°C (^00°F) to 800°C (1500°F)) and residence times
(0.5 to 1.5 seconds). Kinetics calculations comparing the test conditions
to 870°C (1600°F) temperature with 0.75 second residence time show that the
latter set of conditions is more conducive to complete VOC destruction.
Cost per pound of VOC controlled increases only 5 to 10 percent with an
increase in temperature from 760°C (1400°F) to 870°C (1600°F) with the use
of 70 percent recuperative heat recovery. Temperature higher than 870°C
(1600°F) are not desirable due to the materials limitations of metallic heat
exchangers. Higher temperatures would require heat exchange surfaces to be
made of more expensive materials.
Variations in inlet concentration can change a thermal oxidizer's VOC
destruction efficiency. Kinetics calculations describing the complex
combustion reaction mechanisms point to much slower reaction rates at very
low compound concentrations. Available data show that 20 ppmv as compound
minimum outlet concentration is a reasonable limit which allows for the drop
in achievable destruction efficiency with decreasing inlet concentration.
The data also show that the impact of compound variation on destruction
efficiency increases at temperatures lower than 760°C (1400°F), although
precise quantitative relations could not be determined. The types of
compounds in the data include C-, to Cr alkanes and olefins, aromatics such
as benzene, toluene, and xylene and oxygenated compounds such as MEK and
isopropanol. Nitrogen-containing species such as acrylonitrile and
ethylamines and chlorinated compounds such as vinyl chloride are also
included in the data.
At temperatures over 760°C (1400°F), the oxidation reaction rate is
much faster than the rate at which mixing takes place. Therefore, VOC
destruction becomes more dependent upon the fluid mechanics within the
oxidation chamber. The flow regime should be such that the mixing of the
VOC stream, combustion air, and hot combustion products from the burner be
rapid and thorough. This enables the VOC to attain the combustion tem-
perature in the presence of enough oxygen for a sufficient period of time
for the oxidation reaction to reach completion. Chamber design and burner
and baffle configurations provide for turbulent flow for improved mixing.
The most practical manner of achieving good mixing and efficiency is to
adjust the installed equipment to improve performance.
3-20
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3.5.4 Catalytic Oxidizers
Catalytic oxidation is the second major combustion technique for VOC
emissions control. Selected air oxidation processes known to use catalytic
oxidation for emission control are listed in Table 3-6.
A catalyst works by changing the rate of a chemical reaction without
becoming permanently altered itself. Catalysts for catalytic oxidation
cause a higher rate of reaction at a lower energy level (temperature),
allowing oxidation of VOC at lower temperatures than for thermal oxidation.
Combustion catalysts.include platinum and platinum alloys, copper oxide,
chromium and cobalt. These are deposited in thin layers on inert
substrates to provide for maximum surface contact area.
3.5.4.1 Catalytic Oxidation Process. In catalytic oxidation, a waste
stream and air are contacted with a catalyst at a temperature sufficiently
high to allow the oxidation reaction to occur. The waste gas is introduced
into a mixing chamber where it is heated to the proper temperature (about
316°C (600°F)) by contact with the hot combustion products of a burner. The
heated mixture is then passed through the catalyst bed as shown in Figure
3-7. VOC and oxygen are transferred to the catalyst surface by diffusion
from the waste gas and chemisorbed in the pores of the catalyst to the
active sites where the oxidation reaction takes place. The reaction
products are then desorbed from the.active sites and transferred by
diffusion back into the waste gas. The cleaned gas may then be passed
through a waste heat recovery device before exhausting into the atmosphere.
3.5.4.2 Catalytic Oxidizer Emission Reduction Effectiveness.
Catalytic oxidizers operating at 450°C (840°F) are able to oxidize waste
gases as effectively as thermal oxidizers operating at 750°C (1380°F).
Catalytic oxidizer VOC destruction efficiencies of 95 percent have been
reported in various cases and efficiencies of 97.9 to 98.5 percent are
attainable in some systems.
3.5.4.3 Parameters Affecting VOC Destruction Efficiency. Catalytic
oxidizer destruction efficiency is dependent on catalyst volume per unit
volume gas processed, operating temperature, and waste gas VOC composition-
and concentration. A typical catalyst bed contains about 0.014 to 0.057 m
of catalyst bed.uolume (0.5 to 2.0 ft ) for each 28 NirT m (1000 scfm) of
waste gas flow. Greater efficiencies can be attained by an increase in
the volume ratio; however, the cost of a larger catalyst bed can become
prohibitive.
The operating temperature range of combustion catalysts is usually from
316°C (600°F) to 650°C (1200°F). Lower temperatures may result in slowing
down and possibly stopping the oxidation reaction. Higher temperatures may
result in shortened catalyst life and possible evaporation of the catalyst
from the support substrate.
Accumulation of particulate matter or condensed polymerized material
can block the active sites and reduce effectiveness. Catalysts can also be
deactivated by compounds containing sulghur, bismuth, phosphorous, arsenic,
antimony, mercury, lead, zinc, or tin.
3-21
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TABLE 3-6. SELECTED AIR OXIDATION PROCESSES KNOWN TO USE CATALYTIC
OXIDATION FOR EMISSION CONTROL
Chemical
Acrylonitrile
Ethylene Dichloride
Ethylene Oxide
Maleic Anhydride
3-22
-------
Stack
GO
I
CO
Auxiliaiy
Fuel Buweis
Waste Gas
Optional
Heal Recovery
Figure 3-7. Catalytic oxidizer.
-------
Conditions such as those noted above can result in VOC passing through
or incomplete oxidation with the formation of aldehydes, ketones, and
organic acids.
Sensitivity to waste stream flow condition variations and inability to
handle moderate heating value streams limit the application of catalytic
oxidizers as SOCMI air oxidation process vent emission controls.
3.5.5 Advantages and Disadvantages of Control by Combustion
VOC control by combustion has several advantages:(1) a properly
designed and operated combustion device can provide destruction of nearly
all VOC; (2) most combustion units are capable of adapting to moderate
changes in effluent flowrate and concentrations; and (3) control efficiency
is insensitive to the specific VOC pollutant relative to product recovery
techniques.
There are also disadvantages associated with VOC control by combustion:
(1) high capital and operating costs result from thermal oxidation tech-
niques, which could require a plot of land as large as 300 ft by 300 ft
for installation; (2) since offgas must be collected and ducted to the
afterburner, long duct runs may lead to condensation of combustibles and
possibly to duct fires; and (3) since thermal oxidizers utilize combustion
with a flame for achieving VOC destruction, the unit must be located at a
safe distance from process equipment in which flammable chemicals are used.
Alternatively, special designs may be employed to minimize the risk of
explosion or fire.
There are several disadvantages particularly associated with control of
halogenated VOC by combustion: (1) halogen acids produced by the combustion
must be removed by flue gas scrubbing; (2) water and caustic are required at
the site for scrubbing the flue gas; and (3) proper waste disposal of the
salt formed during flue gas scrubbing is required.
3.6 STATE REGULATIONS FOR VOC CONTROL
Over 90 percent of the total SOCMI production capacity is located in
14 states, with over half of that percentage being in Texas and Louisiana.
Of the 14 states only Texas, Louisiana, New Jersey, and Illinois (jave VOC
emission regulations applicable to SOCMI air oxidation processes.
1. Texas facilities emitting more than 100 Ibs/day and at an
instantaneous rate greater than 250 Ibs/hr are required to "properly"
incinerate waste gases at 704°C (1300°F).
2. Louisiana requires incineration at 704°C (1300°F) with 0.3 seconds
residence time or control by other acceptable methods. The regulations can
be waived if the offgas will not support combustion.
3. New Jersey has based its SIP's on a sliding scale with allowable
emission rate based on difficulty of control.
4. Illinois limits all VOC emissions to 100 ppm equivalent methane
(CH4).
3.7 TECHNICAL FEASIBILITY OF RETROFITTING CONTROL DEVICES50"56
The difficulties encountered in retrofitting control devices are
similar.
3-24
-------
Retrofit construction can involve demolition, crowded construction
working conditions, scheduling construction activities with production
activities, and longer interconnecting piping. Utility distribution systems
and load capacities may not be adequate to accommodate the control
equipment, and extra circuit breakers may be required.
Retrofitted control devices are preferably located on the ground near
the process vents, but can be raised on platforms or mounted on the roof in
order to accommodate other processes. There must be sufficient room around
the units to allow for maintenance, and the exhausts must not present a
hazard to equipment or personnel. Each requires electricity to operate
fans, control and recording equipment. Valves and dampers may be pneumatically
operated, requiring compressed air lines. Adsorption devices may also need
steam for regeneration. Condensers probably need a refrigeration plant and
coolant lines.
Retrofits may require remodeling of existing structures and coordination
of the construction efforts with process operations.
Since thermal oxidizer systems require a relatively large land area and
the safety aspects of an open flame are an important factor, the longer
interconnecting piping probably is the most significant retrofit factor.
Because offgas containing halogenated VOC requires combustion temperatures
above those for which recuperative heat recovery is feasible, a waste heat
boiler must be used for heat recovery. Since it may be costly for some
companies to have excess steam on-site, it may not be practical for all
companies to utilize the heat recovery option. In a retrofit situation, it
may be difficult to locate the waste heat boiler close to the steam-consuming
site.
Data on retrofit requirements and costs for thermal oxidizers, recupera-
tive heat exchangers, and waste heat boilers are given in Reference 56.
3-25
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3.8 REFERENCES FOR CHAPTER 3
1. Office of Air and Waste Management. U.S. Environmental Protection
Agency. Research Triangle Park, N.C. Control Techniques for Volatile
Organic Emissions from Stationary Sources. Publication No.
EPA-450/2-78-022. May 1978. p. 53.
2. Stern. A.C. Air Pollution. Volume IV, 3rd Edition, New York, Academic
Press, 1977. p. 336.
3. Ibid., p. 352.
4. Basdekis, H.S. Emissions Control Options for the Synthetic Organic
Chemical Industry. Control Device Evaluation. Carbon Adsorption.
Report.1. EPA-450/3-80-027. December 1980. p. 11-15.
5. Stern, op. cit., p. 355.
6. Basdekis, op. cit., pp. 11-15 - 11-18.
7. Basdekis, op. cit., p. 1-4.
8. Staff of Research and Education Association. Modern Pollution Control
Technology. Volume I, New York Research and Education Association,
1978. pp. 22-23.
9. Stern, op. cit., p. 356.
10. Basdekis, op. cit.
11. Stern, op. city., p. 356.
/
12. Perry, R.H., Chilton, C.H. Eds. Chemical Engineers Handbook. 5th
Edition. New York. McGraw-Hill. 1973. p. 14-2.
13. Op. cit., see Reference 1, p. 76.
14. Op. cit., see Reference 9, p. 24.
15. Op. cit., see Reference 1, p. 72.
16. Standifer, R.L. Emissions Control Options for the Synthetic Organic
Chemical Industry. Control Device Evaluation. Gas Absorption.
Report 3. EPA-450/3-80-027. December 1980. p. II-l.
17. Perry, op. cit., p. 14-1.
18. Hesketh, H.E. Air Pollution Control. Ann Arbor. Ann Arbor Science,
1979. p. 143.
3-26
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19. Standifer, op. cit., p. III-5.
20. Ibid.
21. Ibid. p. II.
22. Op. cit., see Reference 1, p. 83.
23. Erikson, D.G, Emissions Control Options for the Synthetic Organic
Chemical Industry. Control Device Evaluation. Condensation.
Report 2. EPA-450/3-80-027. December 1980.
24. Op. cit., see Reference 11, pp. 23-37.
25. Erikson, op. cit., p. II-l.
26. Op. cit., see Reference 1, p. 84.
27. Erikson, op. cit., p. II-l.
28. Ibid., p. II-3.
29. Op. cit., see Reference 1, p. 83.
30. Erikson, op. cit., p. IV-1.
31. Ibid., pp. II-3, III-3.
32. Ibid., p. III-5.
33. Ibid., p. III-5.
34. Stern, op. cit., p. 368.
35. Blackburn, J.W. Emission Control Options for the Synthetic Organic
Chemical Industry. Control Device Evaluation. Thermal Oxidation.
Report 1. EPA-450/3-80-027. December 1980. p. II-l.
36. Weast, R.C. Ed., CRC Handbook of Chemistry and Physics. 60th Edition,
Boca Raton. 1980. p. D-174.
37. Ibid.
38. Stern, op. cit., p. 368.
39. Reed, R.J. North American Combustion Handbook. Cleveland, North
American Manufacturing Co., 1979. p. 269.
40. Memo and addendum from Mascone, D., EPA, to Farmer, J., EPA.
June 11, 1980. Thermal Incinerator Performance.
3-27
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41. Ibid.
42. Ibid.
43. Op. cit., see Reference 1, p. 32.
44. Key, J.A. Emissions Control Options for the Synthetic Organic Chemicals
Manufacturing Industry. Control Device Evaluation. Catalytic
Oxidation. Report 3. EPA-450/3-80-026. December 1980. p. 1-1.
45. Ibid.
46. Martin, N. Catalytic Incineration of Low Concentration Organic Vapors.
U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina. 1981. EPA-600/2-81-017.
47. Kent, R.W. A. Guide to Catalytic Oxidation. West Chester,
Pennsylvania. Oxy-Catalyst, Inc. Research Cotrell, Inc. (In-House
Brochure).
48. Key, op. cit., p. 1-3.
49. Op. cit., see Reference 1, p. 32.
50. Basdekis, op. cit., p. III-2.
51. Standifer, op. cit., p. V-l.
52. Erikson, op. cit., p. V-l.
53. Key, op. cit., p. III-l.
54. Blackburn, op. cit., pp. IV-1, V-l.
55. Basdekis, H.S. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry- Control Device Evaluation. Thermal
Oxidation Supplement (VOC-Containing Halogens or Sulfur). Report 2.
EPA-450/3-80-026. December 1980. pp. IV-1, V-l.
56. Memo from Galloway, J., EEA, to SOCMI Air Oxidation File. Retrofit
Costs for Thermal Incinerators. August 8, 1980.
3-28
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4. ENVIRONMENTAL ANALYSIS OF REASONABLY AVAILABLE
CONTROL TECHNOLOGY (RACT)
This chapter discusses the nature and environmental impact of reasonably
available control technology (RACT) for SOCMI air oxidation process reactors
and associated product recovery vents. The environmental analysis considers
both the effects attributed directly to the application of RACT, such as
reduced VOC emissions, and those that are indirect or induced, such as
aggravation of other pollutant problems. The beneficial and adverse effects
on air quality, water quality, solid waste disposal, and energy use are
analyzed.
4.1 RACT RECOMMENDATION
The recommended RACT (hereafter referred to as RACT) would be applicable
to air oxidation facilities within the SOCMI. This would include all
reactors in which air is used as an oxidizing agent to produce an organic
chemical. The air oxidation facility to which RACT would apply is a product
recovery system and all associated reactors discharging directly into that
system, or any reactor(s) discharging directly to the atmosphere. The
product recovery system refers to any equipment used to collect VOC for
beneficial use or reuse, such as for sale or recycling. Some examples of
product recovery systems are absorbers, adsorbers, and condensers as well as
certain devices that recover non-VOC's (such as ammonia and HC1 recovery
units). The RACT would require, for each air oxidation process vent stream,
either use of a combustion device which reduces total organic compound
emissions (minus methane and ethane) by 98 weight percent or to 20 ppm by
volume (ppmv), whichever is less stringent, or maintenance of a total
resource effectiveness (TRE) index value greater than 1.0. The meaning of
RACT is explained more fully in the following paragraphs.
Experience indicates that many types of control devices can be used to
reduce air oxidation process VOC emissions. However, thermal oxidation is
the only demonstrated VOC control technology universally applicable to all
SOCMI air oxidation processes. All new incinerators can achieve at least a
98 weight percent VOC reduction or 20 ppmv exit concentration (whichever is
less stringent). Although projection of the RACT impacts is based on the
use of thermal oxidation, the RACT itself would not specify thermal oxidation
as the only VOC control method. Other control devices such as flares,
boilers, process heaters, and catalytic oxidizers have been demonstrated to
achieve 98 percent destruction efficiency where applicable. The RACT would
permit the use of alternate devices as long as the 98 percent destruction or
20 ppmv emissions limits are met. It is recommended that air oxidation
facilities for which an existing combustion device is employed to control
process VOC emissions should not be required to meet the 98 percent emissions
limit until the combustion device is replaced for other reasons. In other
words, no facility would be required to upgrade or replace an existing
combustion device.
The RACT is based on incineration of certain process vent streams
discharged to the atmosphere. The streams for which RACT involves this VOC
reduction are those for which the associated total resource-effectiveness
4-1
-------
(TRE) index value is less than 1.0. An index value of TRE can be associated
with each air oxidation vent stream for which the offgas characteristics of
flowrate, hourly VOC emissions, corrosion properties, and net heating value
are known. For facilities having a TRE index value which exceeds the cutoff
level, a VOC emissions reduction of 98 percent or to 20 ppmv would not be
required under the recommended RACT.
The TRE index is a measure of the supplemental total resource
requirement per unit VOC reduction, associated with VOC control by thermal
oxidation. All resources which are expected to be used in VOC control by
thermal oxidation are taken into account in the TRE index. The primary
resources used are supplemental natural gas, capital, and (for offgas
containing halogenated compounds) caustic. Other resources used include
labor, electricity, and (for offgas containing halogenated compounds)
scrubbing and quench makeup water. TRE is further defined and discussed in
Chapter 5 and Appendix D.
The TRE index is a convenient, dimensionless measure of the total
resource burden associated with VOC control at a facility. Overall, the TRE
index is independent of the general inflation rate insofar as it assumes
fixed relative costs of the various resources, such as carbon steel and
electricity. However, the TRE index accounts for the fact that natural gas
costs are rising at a rate higher than the general inflation rate. The
natural gas cost used in the index was derived by taking the natural gas
price projected for the year 1990 weighted geographically. This 1990 gas
price was then deflated to 1980 dollars. The weighting scheme was derived
by taking individual gas price projections for the year 1990 for each of the
10 EPA regions. These projections were weighted according to the percentage
of total air oxidation plant capacity within each region. The 1990 natural
gas price used in the TRE index reflects the summation of the values for
each region.
The TRE index cutoff level associated with the RACT recommendation has
the value 1.0. Those facilities with a process vent stream or combination
of process vent streams having a TRE index value below 1.0 would reduce VOC
emissions by 98 percent under RACT. An equation for the calculation of the
TRE value of an individual facility as a function of the offgas flowrate,
hourly VOC emissions, corrosion properties, and heating value is derived and
presented in Appendix D.
The distinction in RACT, between facilities with a TRE index value
above the cutoff level of 1.0 and those with a value below it, encourages
the use of product recovery techniques or process modifications to reduce
emissions. As discussed in Appendix D, the values of offgas flowrate,
hourly VOC emissions, corrosion properties, and net heating value are used
to calculate the TRE value of a given facility. These values are measured
and/or determined for the vent stream at the outlet of the final product
recovery device. Use of additional product recovery is expected to decrease
VOC emissions and increase the total resource-effectiveness associated with
thermal incineration of a vent stream.
It is intended for RACT to cover air oxidation facilities that emit VOC
(i.e., compounds which participate in atmospheric photochemical reactions to
produce ozone.) Since compounds with negligible photochemical reactivity do
4-2
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not participate in the production of ozone, it is recommended that they be
excluded when determining a TRE index. Therefore, in determining hourly
emissions rate for input into the TRE equation, a facility should measure
total organic compounds and subtract those compounds which have been
identified to have negligible photochemical reactivity. Those compounds
which the Administrator has concluded have a negligible photochemical
reactivity are identified in EPA statements on ozone abatement policy for
SIP revisions (42 FR 35314; 44 FR 32042; 45 FR 32424; 45 FR 4894).
The environmental analysis used a national statistical profile,
representing the air oxidation segment of SOCMI, to estimate the cost and
energy impacts of RACT. Appendix B describes the statistical profile and
the specific method of projecting the RACT impacts.
4.2 AIR POLLUTION
The principal impact of RACT on air pollution would be beneficial and
would consist of a reduction in national VOC emissions. The hourly and
annual quantities of VOC released overall, before and after control by RACT,
are presented in Table 4-1. The overall emissions represent the total
amount of VOC released from the 47 air oxidation plants in ozone nonattain-
ment areas requesting extension. Table 4-2 shows hourly and annual VOC
emissions, before and after control by RACT, from an average air oxidation
plant. The average plant emissions represent the amount of VOC released
from one of the estimated 14 air oxidation plants that would control VOC
under RACT. However, because of the diversity of air oxidation vent streams,
actual VOC emissions differ at individual facilities. Under current control
levels, the national VOC emissions from the affected air oxidation facilities
are 40,390 Mg/yr (44,430 tons/yr). The application of RACT would reduce
these emissions by 53 percent to 19,015 Mg/yr (20,915 tons/yr).
Pollutants generated by the combustion process, particularly nitrogen
oxides (NO ), have the potential to affect the ambient air quality. The
principal factors affecting the rate of NO formation are the amount of
excess air available, the peak flame temperature, the period of time that
the combustion gases,are at peak temperature, and the rate of cooling of the
combustion products. Because of the relatively low combustion temperatures
and relatively short residence times associated with control of VOC using
thermal oxidation, the rate of NO formation is expected to be low.
Thermal oxidizer outlet concentrations of NO were measured in seven
sets of thermal oxidizer tests conducted at threexair oxidation plants. The
test results indicate that NO outlet concentrations range from 8 to
200 ppmv (0.015 to 0.37 g/m ). These values could increase by several
orders of magnitude in a poorly-designed or operated unit. The tests are
described and documented in Appendix A.
Although there are conflicting data, some studies report that
incineration of vent streams containing high leuels of nitrogen-containing
compounds may cause increases in NO emissions. The maximum outlet NO
concentration of 200 ppmv was measured at an acrylonitrile plant. The v*ent
stream of this plant does contain nitrogenous compounds. The NO outlet
concentrations measured at the other two plants, whose vent streims do not
contain nitrogenous compounds, range from 8 to 30 ppm (0.015 to 0.056 g/m ).
4-3
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TABLE 4-1. ESTIMATED VOC EMISSIONS FROM PROCESS VENTS OF AIR OXIDATION
FACILITIES IN OZONE NONATTAINMENT AREAS
VOC Emissions at
Uncontrolled Levels
kg/hr Mg/yr
VOC Emissions at .
Current SIP Levels
kg/hr Mg/yr
VOC Emissions After
Control by RACT
kg/hr Mg/yr
Air oxidation process vent emissions
from estimated 14 facilities required
to control VOC 5,920
51,860
2,490
21,810
50
4351
Air oxidation process vent emissions
from estimated 33 facilities not
required to control VOC
Estimated overall emissions9
5,050
10,970
44,240
96,100
2,120
4,610
18,580
40,390
2,120
2,170
18,580
19,015d
aOverall emissions represent the amount of VOC released from the process vents of 47 air oxidation facilities
in ozone nonattainment areas requesting extension.
Equivalent to 58 percent VOC reduction from uncontrolled levels. The 58 percent value for baseline control
is presented in Appendix B.
Equivalent to 98 percent reduction from current SIP levels.
Equivalent to 53 percent VOC reduction from current SIP levels.
-------
TABLE 4-2. ESTIMATED VOC EMISSIONS FROM PROCESS VENTS FOR AN
AVERAGE AIR OXIDATION FACILITY
VOC Emissions at
Uncontrolled Levels
kg/hr Mg/yr
VOC Emissions at
Current SIP Levels
kg/hr Mg/yr
VOC Emissions After
Control by RACT
kg/hr Mg/yr
Average plant emissions (for
estimated 14 facilities required
to control VOC)
423
3,705
178
1,560
3.56
31.
I
cn
Average plant emissions (for
estimated 33 facilities not
required to control VOC)
153
1,340
64
560
64
560
Equivalent to 58 percent VOC reduction from uncontrolled levels. The 58 percent value for baseline
control is presented in Chapter 2.
Equivalent to 98 percent VOC reduction from current SIP levels.
*•*
Average amount of VOC released (assuming 77 percent capacity utilization) from the process vent of
one of the estimated 14 air oxidation plants that would be estimated to control VOC under RACT.
Because of the-diversity of air oxidation vent streams, actual VOC emissions will differ at
individual plants.
Average amount of VOC released (assuming 77 percent capacity utilization) from the process vent of
one of the estimated 33 air oxidation plants that would not be estimated to control VOC under RACT.
Because of the diversity of the air oxidation vent streams, actual VOC emissions will differ at
individual plants.
-------
Control of VOC emissions from oxychlorination vent streams by thermal
oxidation may result in the release of chlorinated combustion products to
the environment. Flue gas scrubbing can be used to remove these compounds
from the incinerator outlet stream. However, incineration temperatures
greater than 871°C (1600°F) are required for destruction of halogenated VOC.
At temperatures of 980° to 1205°C (1800° to 2200°F), almost all chlorine
present exists in the form of hydrogen chloride (HC1), a form easily removed
by scrubbing. The HC1 emissions generated by thermal oxidation at these
temperatures can be removed efficiently by scrubbing with water. The
equation used to determine the TRE index for a halogenated vent stream
includes the costs associated with using such a scrubber. *
4.3 WATER POLLUTION
The impact of RACT on water pollution is minimal. Control of VOC
emissions using thermal oxidation does not result in any significant
increase >n wastewater discharge by air oxidation unit processes. Small
quantities of hazardous waste are generated as a result of thermal oxidizer
operation. Such waste would be covered under the Resource Conservation and
Recovery Act (RCRA).
Use of an incinerator/scrubber system for control of VOC emissions from
oxychlorination vent streams results in increased water consumption. In
this type of control system, water is used to remove the HC1 contained in
the thermal oxidizer outlet stream. The increase in total plant wastewater
would be relatively small and would not overload plant waste treatment or
sewer capacity. However, the absorbed HC1 may cause the water leaving the
scrubber to have a low pH. This acidic effluent could lower the pH of the
total plant effluent if it is released into the plant wastewater system.
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 must
be neutralized prior to discharge to the plant effluent system. The
scrubber effluent can be neutralized by adding sodium hydroxide (NaOH) to
the scrubbing water. The amount of NaOH needed depends on the amount of HC1
in the incinerator outlet stream. Approximately 1.09 kg (2.4 Ib) of NaOH
are needed to neutralize 1 kg (2.2 Ib) of HC1. The salt formed must be
purged from the system and properly disposed of. Acceptable methods of
disposal include direct waste water discharge or recovery of the NaCl.
The increased water consumption and NaOH costs were included in the
projected operating costs for those facilities with halogenated vent
streams. Costs associated with disposal of NaCl were judged to be
insignificant because all facilities can directly discharge the brine at
little or no cost into the ocean, a brackish stream, or a sewer system. The
makeup rate for water purged from the system, based on one percent dissolved
solids in the water recycle, is 0.333 m /kg (19.2 gal/lb) of chlorine in the
waste gas.
The use of scrubbers to remove HC1 from the incinerator offgas also
could result in small increases in the quantities of organic compounds, such
as 1,2-dichloroethane, released into plant wastewater. Organic compound
emissions into the water and, subsequently, into the air, can be prevented
by using a water stripper.
4-6
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4.4 SOLID WASTE DISPOSAL
There are no significant solid wastes generated or disposed of as a
result of control by RACT. A small amount of solid waste disposal would
result if catalytic oxidation were used by a facility, instead of thermal
oxidation, to achieve an equivalent degree of VOC control. The solid waste
would consist of spent catalyst. If a facility were to use an additional
absorption column for improved product recovery in order to become exempt
from a VOC reduction requirement, a small amount of solid waste would be
generated by cleaning the column.
4.5 ENERGY
The energy impacts of control by RACT are based on using thermal
oxidation to control VOC emissions. Maintenance of the required thermal
oxidizer operating conditions requires supplemental fuel, commonly in the
form of natural gas. The amount of supplemental fuel needed depends on
offgas temperature, flow and heating value, incineration temperature, and
type of heat recovery used. Due to the use of heat recovery techniques,
combustion of some air oxidation vent streams results in a net production of
energy even though supplemental fuel is necessary for flame stability. Up
to 70 percent heat recovery can be achieved at any facility by using
techniques currently employed in the air oxidation industry-
In addition to supplemental fuel, electricity requirements contribute
to the total energy use for VOC control. Electricity is required to operate
equipment such as the pumps, fans, blowers, and instrumentation that may be
necessary to control VOC using a thermal oxidizer or a thermal oxidizer/
scrubber system. Total electrical needs are relatively small compared to
energy requirements in the form of supplemental fuel for thermal oxidation.
The total additional national energy requirements after application of
RACT are estimated to be 5,000 TJ/yr (4.89 x 10iz Btu/yr). The overall
energy requirements represent the total amount of supplemental fuel, in the
form of natural gas, estimated to be used by the 14 air oxidation facilities
that would control VOC emissions under RACT.
4-7
-------
4.6 REFERENCES FOR CHAPTER 4
1.
2.
3.
Perkins, H.C. Air Pollution.
1974. pp. 302-308.
McGraw-Hill Book Company. New York.
Blackburn, J.W. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry. Control Device Evaluation. Thermal
-Oxidation. Report 1. EPA-450/3-80-026. December 1980.
Basdekis, H.S. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry. Control Device Evaluation. Thermal
Oxidation Supplement (VOC Containing Halogens or Sulfur). Report 2.
EPA-450/3-80-026.December 1980.
4.
Standard Support and Environmental Impact Statement: Emission Standard
for Vinyl Chloride. U.S. Environmental Protection Agency. Publication
No. EPA-450/2-75-009. Research Triangle Park, North Carolina.
October 1975.
5. Basdekis, op. cit.
4-8
-------
5. CONTROL COST ANALYSIS OF RACT
5.1 INTRODUCTION
The costs of implementing RACT for control of volatile organic compound
(VOC) emissions from SOCMI air oxidation process vents are presented in this
chapter. Capital costs, annualized costs, and the cost-effectiveness of
RACT are presented.
5.1.1 Substitution of National Profile for Model Plant
The RACT cost impacts were estimated based on natural gas-fired thermal
oxidation as the single control technique. For offgas that contains haloge-
nated compounds, a design temperature of 1100°C (2000°F) and a residence
time of 1.0 second were used. For offgas lacking halogenated compounds, a
design temperature of 870°C (1600°F) and residence time of 0.75 second were
used. These design parameters represent the worst-case conditions under
which a VOC destruction efficiency of 98 percent would be attained.
The RACT impacts were not based on the traditional model plant approach.
Because of the number and diversity of facilities and manufacturing processes
in the air oxidation industry, a large number of model plants would have
been required in order to accurately determine the cost impacts associated
with RACT. However, only a limited amount of waste stream data is required
to determine incinerator costs and efficiency. The required data include
offgas flowrate, net heating value, and VOC emission rate. It must also be
known whether the offgas contains halogenated compounds. Therefore,
although data from many types of processes are still required in order to
adequately represent the air oxidation industry, the data need not consist
of fully designed model plants. Rather, a national statistical profile of
air oxidation processes was constructed. The national profile characterizes
air oxidation processes according to national distributions of the three
critical offgas parameters for halogenated and nonhalogenated waste streams.
The RACT cost impacts are therefore evaluated as impacts upon the entire
population of affected facilities, as represented by the national profile.
The development and statistical basis for the national profile are described
in detail in Appendix B.
5.1.2 Thermal Oxidation Design Categories
The thermal oxidizer system design employed for a particular vent
stream depends upon the offgas net heating value, the flowrate, and the
presence or absence of halogenated compounds. Sufficient fuel must be added
to permit incineration at 870°C (1600°F). Fuel requirements can be reduced
by the use of recuperative heat recovery to preheat the offgas and/or
combustion air. Secondary heat recovery in addition to the heat exchanger
is, in general, neither technically nor economically feasible. The basic
design characteristics of each category are given in Table 5-1.
5.1.2.1 Categories Al and A2. All vent streams which contain
halogenated compounds are included in Categories Al and A2. Due to the
greater difficulty of achieving complete combustion of chlorinated VOC, an
incineration temperature of 1100°C (2000°F) and a one second residence time
5-1
-------
TABLE 5-1. BASIC CHARACTERISTICS OF EACH DESIGN CATEGORY
1-7
Category
Ala
A2a
B
C
D
E
Minimum
Net
Heating
Value
(MJ/scm)
0
3.5
0
0.48
1.9
3.6
Maximum
Net
Heating
Value
(MJ/scm)
3.5
..
0.48
1.9
3.6
-
Incineration
Temperature
C
1100
1100
870
870
980
980
Residence
Time
(Sec)
1.0
1.0
0.75
0.75
0.75
0.75
Type of
Heat Recovery
Waste-Heat
Boiler
Waste-Heat
Boiler
Recuperative
Heat Exchanger
Recuperative
Exchanger
None
None
Stream(s)
Preheated
None
None
Offgas and
Combustion Air
Combustion Air
Only
None
None
Percent
Heat
Recovery
60%
60%
70%
34%
-
-
Additional
Control Equipment
Flue Gas Scrubber
Flue Gas Scrubber
None
None
None
None
ro
aOffgas contains halogenated compounds.
-------
were assumed. Combustion temperatures exceeding 870°C (1600°F) rule out the
use of recuperative heat exchangers because of problems with materials of
construction and with associated problems such as possible precombustion
occurring in the exchangers. However, a waste heat boiler can be used
effectively with temperatures up to and above 1650°C (3000°F). The only air
oxidation process which has chlorinated offgas is ethylene dichloride
manufacture, which is known to employ waste heat boilers for heat recovery.
Therefore, heat recovery in a waste heat boiler with steam generation was
assumed. The amount of heat recovery was limited by a minimum outlet flue
gas temperature of about 260°C (500°F), belowgwhich, excessive condensation
of corrosive combustion products could occur. The corrosive hydrogen
chloride is then removed by flue gas quenching and scrubbing, and the
resulting solution neutralized with caustic soda. Categories Al and A2 do
not differ in control system design, but only in supplementary fuel
requirements.
5.1.2.2 Category B. Design Category B includes offgas with a heating
value below 0.48 MJ/scm (13 Btu/scf), whichgcorresponds to 25 percent of a
typical lower explosive limit (LEL) in air. For Category B, 70 percent
heat recovery was assumed. In this heating value range, the amount of heat
recovery which could be used is only limited by a ceiling of about
550-600°C (1000-1100°F) on theQcombustion air preheat temperature due to
burner design considerations.
5.1.2.3 Category C. Because of insurance requirements, offgas with a
heating value between 0.48 MJ/scm (13 Btu/scf) and 1.9 MJ/scm (52 Btu/scf),
which constitutes Category C, may not be preheated. This heating value
range corresponds to a range of 25-100 percent of LEL in air for a typical
organic vapor. Because air oxidation vent streams generally contain little
or no oxygen, which is essentially depleted by .tbe process reaction, offgas
in this heating value range need not be diluted. It was assumed that the
combustion air would be preheated, with 34 percent of the flue gas heat
content recovered.
5.1.2.4 Category D. Offgas with a heating value in the range
1.9 MJ/scm (52 Btu/scf) to 3.6 MJ/scm (98 Btu/scf), which constitutes
Category D, need not be preheated and requires only a small amount of
auxiliary fuel, for flame stability. The offgas determines its own
combustion temperature, which in general, exceeds 870°C (1600°F) and can be
as high as 980°C (1800°F). A design temperature of 980°C (1800°F) was
assumed, because of the larger chamber volume per mole of offgas and greater
amount of refractory required at that temperature.
5.1.2.5 Category E. Design Category E includes offgas with a heating
value above 3.6 MJ/scm (98 Btu/scf). Offgas in Category E need not be
preheated and requires only a small amount of auxiliary fuel, for flame
stability. The offgas, which determines its own combustion temperature,
will burn at temperatures of 980°C (1800°F) or greater. Some processes and
facilities with offgas this rich are able to use the steam which would be
5-3
-------
generated by employing a waste heat boiler after the thermal incinerator or
by combusting VOC in an existing boiler or process heater. Other facilities,
however, will not be able to use steam and will not employ heat recovery. A
few facilities might choose to dilute the offgas so that the flue gas
temperature does not exceed 980°C (1800°F). In order to give a conservative
estimate of costs, it was assumed that streams in Category E were diluted to
3.6 MJ/scm (98 Btu/scf), and that no heat recovery was employed.
5.1.2.6 Maximum Equipment Sizes. Because of shipping size restric-
tions, single thermal oxidizer units larger than about 32 feet by 16 feet
would require field fabrication, which would greatly increase the cost.
Therefore, it is assumed that vent streams which would require larger
incinerators would instead employ multiple sets of control equipment
systems. The design standard temperature vent stream (incinerator inlet)
flowrates, for each design category, wbicbgcorrespond to the maximum
equipment size are given in Table 5-2. '
5.1.3 Offgas Composition Assumptions
Facilities with a flowrate less than 500 scfm are assumed to have a
flowrate of 500 scfm for the purpose of calculating capital costs. In order
to avoid underestimation of the required equipment sizes, all vent streams
were assumed to contain no oxygen. Therefore, combustion air requirements
were maximal. In order to increase the rate of combustion and avoid
incomplete combustion and pyrolysis, it was assumed that enough excess
combustion air was supplied to assure three mole percent oxygen in the flue
gas.
An average VOC molecular weight was calculated for the national
profile. Based on additional calculations by Enviroscience, all non-
halogenated VOC were assumed to consist of a typical model compound with the
empirical formula C? RH. ?0n g?.y All halogenated VOC were assumed to 2Q
consist of a typical"Boffipound with the empirical formula C, ,H2 ,C1Q 05-
Based on an inspection of the national profile, it was further assumed that
each stream contained four moles of methane per mole of VOC. From these
offgas compositions, a typical ratio of flue gas flow to offgas flow was
calculated for each design category aad?used to size the control equipment.
These ratios are given in Table 5-3. ' An offgas temperature of 38°C
(100°F) was assumed. The model nonhalogenated VOC were assumed to have a
net heating value of 76 MJ/scm, while a net heating value of 29 MJ/scm was
assumed for the model halogenated VOC. These values corresp^jjd^o net
heating values of acetone and methyl chloride, respectively. ' These
offgas composition assumptions were also used to determine the minimum and
maximum net heating values for each design category. However, actual vent
stream parameters were used in all other parts of the analysis. Actual
offgas parameters were used in calculations for typical vent streams in each
design category, RACT impacts, and total resource-effectiveness projections.
5.2 BASIS FOR CAPITAL COSTS
The capital costs for the implementation of RACT include purchase costs
and retrofit installation costs for thermal incinerators, recuperative heat
5-4
-------
TABLE 5-2. MAXIMUM OFFGAS FLOWRATES
EACH DESIGN CATEGORY15'16
Category
Al
A2
B
C
D
E
Incineration
Temperature
\ ^ /
1100
1100
870
870
980
980
Residence
Time
(Sec)
1.0
1.0
0.75
0.75
0.75
0.75
Maximum
Design
Vent
Stream
(Incinerator
Inlet)
Flowrate
(Thousand
s cm/mi n)
0.74
0.74
1.42
1.42
1.25
1.25
5-5
-------
TABLE 5-3. RATIO OF FLUE GAS FLOWRATE TO OFFGAS
FLOWRATE FOR EACH DESIGN CATEGORY21'22
Category
Alb
A2b
B •
C
D
E
Maximum
Net
Heating
Value
(MJ/scm)
3.5
-
0.48
1.9
3.6
-
Incineration
Temperature
(bc)
1100
1100
870
870
980
980
Ratio of
Flue Gas
Flow to Off gas
Flowa
2.9
2.9
1.9
2.3
2.5
2.5
aBoth at standard temperature.
Offgas contains halogenated compounds.
5-6
-------
exchangers, ducts, fans, and stacks and supporting structures for the
ductwork. For halogenated streams, the purchase and retrofit installation
costs of waste heat boilers and flue gas scrubbers are also included.
The basic capital cost data were provided by the IT Enviroscience
thermalfioxidizer evaluation documents and were derived from vendor quota-
tions. The IT Enviroscience documents were specifically designed for
air oxidation processes, which have vent streams containing little or no
oxygen. Therefore, they take into account the maximum combustion air
requirements for incineration of such streams. Furthermore, the Enviro-
science documents present costs for a range of offgas heating values and
incineration temperatures. Total installed costs are presented for two
types and several levels of heat recovery. It was necessary to use a cost
source possessing this flexibility to cover the variety of air oxidation
vent stream characteristics. The Enviroscience costs were based on December
1979. In order to transform these to June 1980 costs, an escalation factor
of 1.056 was used. This factor is the ratio of the Chemical Engineering M&S
chemical industry equipment cost indexpvalue for the second quarter, 1980,
to that for the fourth quarter, 1979.
The relation of the Enviroscience purchase cost estimates to the
original vendor quotations is discussed in Appendix E. Graphs relating
purchase costs to offgas flowrates are also given in Appendix E for each
piece of control equipment. As discussed in that appendix, purchase cost
estimates obtained from two additional vendors agreed well with the
Enviroscience estimates.
Enviroscience estimates equipment installed costs from equipment
purchase costs by adding factors for each of 10 aspects of installation.
These factors are expressed as percentages of the equipment purchase cost.
Enviroscience also estimates an overall control system installed cost for
each design category. Because the Enviroscience installation factors are
for new sources, EPA used this method^and some additional data to estimate a
set of retrofit installation factors. The most important factors are
those for piping and erection. A list of the installation components for
which factors were developed is given in Table 5-4. A detailed discussion
of the derivation and use of the installation factors is given in
Appendix E. In order to reflect the retrofit installation costs, a retrofit
correction factor of 1.625, derived in Appendix E as the ratio of retrofit
to new source installation factors, was employed. This factor was
multiplied by the new source overall installed cost estimated for each
control system by Enviroscience.
The total installed capital costs represent the total investment,
including all indirect costs such as engineering and contractors' fees and
overhead, required for purchase and installation of all equipment and
material to provide a facility as described. These are battery-limit costs
and do not include the provisions for bringing utilities, services, or roads
to the site, the backup facilities, the land, the research and development
required, or the process piping and instrumentation interconnections that
may be required within the process generating the waste gas feed to the
thermal oxidizer.
5-7
-------
TABLE 5-4. INSTALLATION COMPONENTS
Installation Component
t-oundation
Insulation
Structures
Erection
Piping
Painting
Instruments
Electrical
Fire Protection
Engineering, Freight and Taxes
5-8
-------
The basis for the capital costs is further discussed below for each
design category. Total installed capital cost equations as a function of
operating offgas flowrate were developed and are described in Table 5-5 for
each design category.
It was assumed that at typical operating offgas flowrate would be 95
percent of the design maximum. Therefore, a design vent size factor of 0.95
was assumed to avoid an underestimate of control equipment size and capital
cost. These capital cost equations were obtained by fitting an analytical
function of capital cost versus design offgas flowrate to the data in the
Enviroscience tables and graphs. A different cost curve was fitted for each
design category.
All three coefficients were estimated for the Category B equation. The
exponent was estimated to be 0.88. This exponent was assumed for the other
design categories, and only the remaining two coefficients were fitted for
them. These equations are judged to be reasonably close fits, and no claim
is made that they are the best ones that could have been statistically
determined. Capital cost estimates for a hypothetical vent stream with
characteristics which are average for each design category are presented in
Table 5-6. It was estimated that retrofit total installed costs would
approximately equal the product of the retrofit correction factor of 1.625
multiplied by the new source total installed cost of a control system as
estimated by Enviroscience, escalated to June 1980 dollars.
5.2.1 Common Control Equipment
Several pieces of control equipment are common to each design category.
These include the thermal oxidizer, ductwork and supports, fans, and stack.
5.2.1.1 Thermal Oxidizer. The thermal oxidizer consists of a
refractory-lined carbon steel mixing chamber and combustion chamber.
Discrete burners are assumed. Enviroscience assumed a 10 percent heat loss
from the combustion chamber for all combustion temperatures and design
categories.
5.2.1.2 Ductwork ' . The ductwork used in the Envi
roscience
estimates consists of 150 ft of round-steel inlet with four ells, one
expansion joint, and one damper with control. Enviroscience indicated that
considerably more ductwork may be required in some cases. This analysis
incorporates an additional 150 feet of ductwork, along with 250 feet of pipe
rack support for the ductwork. The adjusted ductwork length of 300 feet was
based on specifications provided by The Industrial Risk Insurers (IRI), a
group which presents recommended distances for safely locating combustion
sources from process units. The IRI safety recommendation for processes
such as those found within the SOCMI is 200 feet. An additional 100 feet
was added to the IRI safety recommendation to account for routing the stream
around equipment before routing it away from the process unit.
The pipe rack costs are based on June 1982. In order to convert to
June 1980 costs, a deescalation factor of 0.928 was used. This factor is
the ratio of the Chemical Engineering M&S equipment cost index for the
second quarter, 1982, to that for the second quarter, 1980. The additional
5-9
-------
TABLE 5-5. TOTAL INSTALLED CAPITAL COST EQUATIONS
AS A FUNCTION OF OFFGAS FLOWRATE30'31
Category
Al
A2
B
C
D
Eb
Maximum
Flowrate
Per Unit
(Thousand)
(scm/min)
0.70
0.70
1.35
1.35
1.19
1.19
Fabricated
Equipment
Cost
Escalation
Factor
1.056
1.056
1.056
1.056
1.056
1.056
Retrofit
Correction
Factor
1.625
1.625
1.625
1.625
1.625
1.625
Cl
803.11
786.61
259.88
297.99
236.35
236.35
C2
12.83a
12.44a
4.91
2.84
3.23'
3.23
C3
0.88
0.88
0.88
0.88
0.88
0.88
Total Installed Capital Cost ($1000) = (# of Units) x (Escalation Factor) x
(Retrofit Facioc) x (Cl + C2 x (Flowrate per equipment unit in,scm/min * Design Vent
Size Factor) ) + pipe rack cost + additional ductwork cost.
a 0 88
Flowrate correction factor of 1.12 = (1.14) ' incorporated into Coefficient C2.
Dilution flowrate is used in capital cost equation.
Dilution flowrate = (design flowrate) x (original heating value) T (3.6 MJ/scm).
cPipe rack cost ($1,000) = (pipe rack length) x (cost per unit length) x
(installation factorKx (pipe rack deescalation factor) x (retrofit correction
factor) * 1,000 ($/103$) = 250[ft.] x 32.045[$/ft.] x 1.0873 x 0.928 x 1.625
*1,000($/103).
Additional ductwork cost = (ductwork length) x (cost per unit length) x (ductwork
escalation factor) x (retrofit correction factor) x (installation factor) = 150(ft.
x r(Flowrate x 35.314 x 4)Q>5 x 12 x 1.37-176, ($/ft.) x 1.364 x 1.625 x 1.087
L .95 x 2000 x 3.42
* 1000 ($/103$).
5-10
-------
TABLE 5-6. INSTALLED CAPITAL COSTS FOR A SELECTED HYPOTHETICAL
VENT STREAM IN EACH DESIGN CATEGORY
30,31
Category
Al
A2
B
C
D
E
B, Two Equipment Units
Offgas
Heating
Value
(MJ/scm)
0.74
4.52
0.12
1.19
2.75
4.8
0.12
Vent
Stream
Design
Flowrate
(scm/min)
344
344
344
344
344
344
2,400
Number of
Equipment
Units
1
1
1
1
1
1
2
Dilution-
Corrected
Flowrate
Through
Each
Equipment
Unit
(scm/min)
344
344
344
344
344
452
1,200
Overall
System
Installed
Capital
Cost5
($1000)
5,169
5,025
1,914
1,373
1,382
1,992
9,988
Including all auxiliary equipment.
-------
ductwork costs are based on June 1977. Similarly, an escalation factor of
1.364 was used to transform these costs to June 1980. This escalation
represents the Chemical Engineering M&S equipment cost index for the second
quarter, 1977, to that for the second quarter, 1980.
34
5.2.1.3 Fans . Fans are included for both offgas and combustion air.
Costs for motors and starters are included. The offgas flowrate, combustion
air flowrate (calculated from the flue gas to offgas flow ratio) and
pressure drop of the thermal oxidizer are used to calculate fan sizes. For
vent streams in Category A, which require flue gas scrubbing, the pressure
drop across the scrubber is also considered.
5.2.1.4 Stack . The stack design height is 80 ft. A linear gas
velocity of 15 m/sec (3000 ft/min) is assumed in calculation of the
cross-sectional area.
5.2.2 Categories Al and A2
Streams in Categories Al and A2 require flue gas quenching and
scrubbing to remove corrosive hydrogen chloride. A waste heat boiler is
employed for heat recovery prior to quenching.
oc
5.2.2.1 Kaste Heat Boiler . ?An overall heat .transfer coefficient of
0.16 MJ/(hr • m . °C) (8 Btu/(hr • ft • °F)) is assumed foe the boiler. Steam
is generated at 120°C (250°F) and a pressure of 1.7 MN/m (250 psi). For
60 percent heat recovery, the ratio of heat exchange surface area to flue
gas flowrate is 0.89 m /son (0.27 ft /scfm).
5.2.2.2 Scrubber . The scrubber column design is,based on 36 ft of
packing. The liquid-to-gas ratio is assumed to be 10. A superficial vapor
velocity of three ft/sec was used for determining the column diameter.
OQ
5.2.2.3 Quench Chamber . The quench chamber design location is the
lower part of the scrubber column. It has the same diameter as the scrubber
column. A one second flue gas retention was assumed. In reducing the flue
gas temperature to the adiabatic saturation temperature of the scrubbing
agent, considerable water is vaporized, increasing the gas flow through the
scrubber. The ratio of quenched to unquenched flue gas flowrate (both
standard) is 1.67 at 1100°C (2000°F).
39
5.2.3 Category BJ*
Vent streams in Category B employ 70 percent recuperative heat recovery.
The heat exchanger tubes are constructed of carbon steel, except for the
first few passes. It is necessary to construct the tube regions which
experience a flue gas temperature between 820 and 870°C (1500 and 1600°F) of
heat-resistant nickel alloy. An overall heat transfer coefficient of
0.08 MJ/hr • m - sec) (4 Btu/(hr • ft • °F) is assumed for the heat exchanger.
This assumption is deliberately low, and hence the heat exchanger is
deliberately over-designed to some degree. For 70 percent heat recovery,
the ratio of heat exchange surface area to flue gas flowrate is 2.7 m /scm
5-12
-------
f\
(0.83 ft /scfm). Recuperative heat recovery reduces both the natural gas
and combustion air requirements of the thermal oxidizer. Therefore the
required combustion chamber volume is reduced. For 70 percent heat recovery,
the combustion chamber size reduction factor is 0.667 (corresponding to a
33 percent reduction in system size relative to no heat recovery).
5.2.4 Category C40
Vent streams in Category C are assumed to preheat the combustion air
only, due to insurance requirements for safe handling of offgas with VOC
concentrations above 25 percent of LEL in air. Thirty-four percent heat
recovery is assumed. Materials of construction and overall heat transfer
coefficient are the same as in Category B. For 34 percent heat recovery,
the ratio of heat exchanger surface area to flue gas flowrate is 1.2 m /son
(0.36 ft /scfm). The combustion chamber size adjustment factor is 0.81
(corresponding to a 19 percent reduction in system size relative to no heat
recovery).
5.2.5 Category D
Due to their high heating value, vent streams in Category D determine
their own combustion temperature. A temperature as high as 980°C (1800°F)
may be reached. Therefore, preheating of the offgas is not economically
advantageous, nor is it technically feasible at temperatures above 870°C
(1600°F). It was not assumed that any process with offgas in Category D
could use generated steam, and therefore no waste heat boiler was included
in the design. The combustion chamber design takes into account the extra
refractory and internal volume required by the higher incineration
temperature.
5.2.6 Category E
Vent streams in Category E are assumed to be sufficiently diluted prior
to combustion that the resultant offgas heating value is 3.6 MJ/scm
(98 Btu/scf), so that the flue gas temperature will not exceed 980°C
(1800°F). The correction equations are:
1. New flowrate = (old flowrate) x (old heating value) T
(3.6 MJ/scm),
2. New % VOC = (old % VOC) x (old flowrate) ^ (new flowrate), and
3. New heating value = 3.6 MJ/scm.
The same incinerator design is assumed as in Category D.
5.3 BASIS FOR ANNUALIZED COSTS41"43
The typical annualized costs consist of the direct expenses for
operating labor, utilities, and maintenance materials and labor plus the
indirect costs for overhead, supervisory labor, taxes, insurances, general
administration, and the capital recovery charges. The utilities include
natural gas and electricity. For Category A, scrubbing water, quench makeup
water, and caustic are also included. Return on investment for the control
equipment is not included. All the data required in the estimation of these
cost factors and costs were obtained from References 41, 42, and 43. The
annualized cost factors are given in Table 5-7. Those operating factors
which vary with design category are given in Table 5-8. The equations used
to calculate annualized costs are given in Table 5-9.
5-13
-------
TABLE 5-7. ANNUAL I ZED COST FACTORS
41-43
Direct
Operating Labor: $9.79/hr (Includes Overhead)
Operating Labor Factor: 2400 Man-hr/yr (Categories
All Factors are Based on June 1980
Indirect ("Capital Charges")
Interest Rate = i = 10%
A1-A2)
2133 Man-hr/yr (Categories B-C)
1200 Man-hr/yr (Categories 0-E)
Supervisory Labor: $9.79/hr x (0.15)
Total Labor: [($9.79/hr x 1.15) + (0.03 of Total
Installed Capital)]
Overhead Labor: 0.80 of Total Labor
Electricity: $0.0362 /kWh
Natural Gas: $4.16/GJ = $4.03/1O3 scf
Heat Recovery Credit: $4.16/GJ = $4.03/103 scf
Quench Water Price: $0.26/Thousand Gallons
Scrubbing Water Price: $0.26/Thousand Gallons
Caustic Price: $0.05145/lba
Maintenance Labor Plus Materials Factor = 0.06
of Total Installed Capital
Incinerator Lifetime = 10 Years ='
i (1 + i
Capital Recovery Factor =
(1
= 0.163 of Total Installed Capital
Taxes, Insurance and Administrative Charges Factor = 0.04 of Total Installed Capital
Overall Capital Charges Factor = 0.203 of Total Installed Capital
Overall Taxes and Maintenance Factor = 0.10 of Total Installed Capital
Annual Operation = 8760 hr/yr
Average Capacity Utilization Factor for Air Oxidation Industry = 0.77
(Multiplied by Design Flowrate to Give Operating Flowrate)
aFifty percent liquid solution of caustic soda.
Memo to Hurley, E., EEA, from Galloway, J., EEA.
January 13, 1981. Average capacity utilization for the air oxidation industry.
-------
TABLE 5-8. OPERATING FACTORS FOR EACH DESIGN CATEGORY
41-43
en
Category
Alb
K2b
B
C
D
E
Minimum Maximum
Net Net
Heating Heating
Value Value
(MJ/scm) (MJ/scm)
0 3.5
3.5
0. 0.48
0.48 1.9
1.9 3.6
3.6
Ratio of
Flue Gas
Flow to ,
Offgas Flow8
2.9
2.9
1.9
2.3
2.5
2.5
Heat
Recovery
Factor
(MJ/scm)
3.38
3.38
0
0
6
0
Pressure
Drop
(Inche$4>45
22C
22C
10d
10d
6e
6e
Operating
Labor
Cost
($1,000/YR)
23.50
23.50
20.88
20.88
11.75
11.75
Natural Gas Use Coefficients
G0 Gl 62 G3
0
0
0.425
0
0
0
4.56
0.329
0.666
2.39
0.183
0.183
-0.985
0
-1.29
-1.22
0
0
0
0
0.015
0
0
0
aBoth at standard conditions.
Offgas contains halogenated compounds.
clncludes 6 inches across the combustion chamber, 4 inches across the waste heat boiler, and 12 inches across the scrubber.
Includes 6 inches across the combustion chamber and 4 inches across the recuperative heat exchanger.
6Across the combustion chamber.
-------
TABLE 5-9. ANNUALIZED COST EQUATIONS41"43
Operating flowrate (scm/min) = (Design flowrate (scm/min) x Capacity Utilization Factor) * 95
In the following Operating Cost and emissions equations, "flowrate" means the operating flowrate per equipment unit (dilution flowrate for Category E)
Natural Gas Used (TJ/yr) = 0.5256 Mi11ion Hin x G0 + Flowrate x (Gl + (G2 x H^ing) + (G3 x Heating2))
yr Value Value
Natural Gas Cost ($l,000/yr) = Natural Gas Price ($/GJ) x Natural Gas Used (TJ/yr)
Operating Labor Cost ($l,000/yr) = Labor wage ($/man-hr) x Operating labor factor (man-hr/yr) * 1,000
Supervisory Labor Cost ($1,000) = Operating Labor Cost ($1,000) x 0.15
Maintenance Labor Cost ($1,000) = Installed Capital ($1,000) x 0.03
Total Labor Cost ($1,000) = (Operating Labor Cost ($1,000) + Supervisory Labor Cost ($1,000) + Maintenance Labor Cost ($1,000))
Overhead Cost ($1,000) = Total Labor Cost ($1,000) x 0.80
Electricity Cost ($l,000/yr) = 0.0604 x Electricity Price ($/kWh) x Pressure Drop (inches H?0) x flowrate (scm/min) x flue-gas/offgas
ratio
Quench water cost ($l,000/yr) = Quench water price ($/thousand gal) x flowrate (scm/min) x 0.00886 x flue-gas/offgas ratio
Scrubbing water cost ($l,000/yr) = Scrubbing water price ($/thousand gal) x flowrate (scm/min) x 0.289 x flue-gas/offgas ratio
Caustic cost ($l,000/yr) = Caustic Price ($/lb) x flowrate (scm/min) x 17.17 x flue-gas/offgas ratio
Heat recovery credit ($l,000/yr) = Natural Gas Price ($/GJ) x Heat Recovery Factor (MJ/scm) x flowrate (scm/min) x 0.5256 (Million min/yr)
Taxes, Insurance and Maintenance Cost ($l,000/yr) = Installed Capital ($1,000) x Taxes and Maintenance Factor
Operating Cost ($l,000/yr) = Taxes, Insurance and Maintenance Cost ($l,000/yr) + Number of equipment units x [Gas Cost + Labor Cost + Electricity
Cost + Quench Cost + Scrub Cost + Caustic Cost -
Heat Recovery Credit]
Annualized Cost ($l,000/yr) = Operating Cost + Capital Recovery Factor x Capital Cost ($1,000)
Annual Emissions (Gg/yr) = Hourly Emissions (kg/hr) x 365 days/year x 24 hours/day x 1 Gg/10 kg x Capacity Utilization Factor
Annual Emission reduction (Gg/yr) = Annual Emission (Gg/yr) x 0.98
Cost Effectiveness ($/Mg) = Annualized Cost ($l,000/yr) * Annual Emission Reduction (Gg/yr)
-------
44 45
5.3.1 Fuel Requirements '
IT Enviroscience developed natural gas use curves and tables from a
detailed heat and material balance. The Enviroscience work was checked for
vent streams with heating values at the cutoff points distinguishing design
Categories B, C, D, and E, as well as for chlorinated streams (Categories Al
and A2). For these cutoff cases, the heat and material balance wa^
completely redone, using a slightly different set of assumptions. These
different assumptions included that of no preheating of the offgas for
Category C streams. In addition, it was assumed that offgas with a VOC
content of X mole percent would have a methane content of 4X mole percent.
The common assumptions are presented above in Section 5.1.3.
The results of the recalculations for the critical cases were
essentially in agreement with the Enviroscience work. Because of the
necessity of calculating fuel requirements and costs for the entire national
statistical profile of 59 vent streams (discussed in Appendix B), detailed
heat and mass balances were not done for each stream. Instead, equations
were fitted to the Enviroscience tables and graphs of natural gas use. The
coefficients of the fuel-use equation are given in Table 5-8.
Streams in Categories D and E have sufficient heating value that they
require only a small amount of fuel, for flame stability. The fuel
requirement for these streams was assumed to be equivalent to 0.19 MJ of
natural gas heat per normal cubic meter of offgas, independent of offgas
heating value. This fuel requirement was chosen because it is equivalent to
that calculated according to the Category C fuel use equation for offgas
with a heating value of 1.9 MJ/scm (which is the cutoff heating value
distinguishing Categories C and D). Therefore, a composite graph of the
fuel use equations for Categories C and D versus offgas heating value would
not be discontinuous at the cutoff heating value.
For the chlorinated streams in Categories Al and A2, Enviroscience did
not develop heat and mass balance calculations for the designated combustion
temperature of 1100°C, but only for higher temperatures. Therefore, the
fuel requirements were interpolated from the curves for 980°C and 1200°C. A
fuel use equation was fitted to this interpolated curve. This equation
indicates that chlorinated offgas with a heating value greater than
3.5 MJ/scm requires primarily auxiliary fuel, for flame stability. At this
critical heating value, according to the fuel use equation, the amount of
fuel required per normal cubic meter of offgas is equivalent to 10 percent »7
of the offgas heating value, which is a typical auxiliary fuel requirement.
This heating value constitutes the cutoff between design Categories Al and
A2. For Category Al, the fuel-use equation discussed above was employed.
For Category A2, the fuel requirement was assumed to be equivalent to
0.35 MJ of natural gas heat per normal cubic meter of offgas, independent of
offgas heating value.
The assumption of a maximum heat exchange efficiency of 70 percent may
be conservative for some facilities. A thermal oxidation system employing
regenerative heat recovery could achieve a primary heat exchange efficiency
as high as 85 to 95 percent. Therefore, facilities able to employ such
technology may have lower fuel requirements.
5-17
-------
Several additional conservative assumptions are built into the fuel use
equations. The most important is the assumption of no oxygen in the offgas.
This leads to maximum combustion air requirements and a higher total
incinerator inlet flow to be heated to the combustion temperature.
The natural gas price used in the cost equations was derived by taking
the natural gas price projected for the year 1990 weighted geographically.
This 1990 gas price was then deflated to 1980 dollars. The weighting scheme
was developed by taking individual gas price projections for the year 1990
for each of the 10 EPA regions. These projections were weighted according
to the percentage of the total air oxidation plant capacity located within
each region. The 1990 natural gas price reflects the summation of the
values for each region.
5.4 EMISSION CONTROL COSTS
This section discusses the estimated emission control costs associated
with control by RACT of a typical vent stream for each design category.
These emission .control costs are given in Table 5-10. The control costs are
broken down into detailed components, including all types of operating
expenses, capital charges, and heat recovery credits.
5.4.1 Major Contributing Factors to Control Costs of Typical Streams
The primary contributors to the annualized costs for the typical
chlorinated, dilute Category Al stream shown in Table 5-10 are capital
charges and caustic costs. These account for about 45 percent and
28 percent, respectively, of the total annualized costs. For the
chlorinated, concentrated Category A2 stream shown in Table 5-10, capital
charges and caustic costs account for about 214 percent and 135 percent,
respectively, of the total annualized costs. The sum of the other
contributors is negative due to the very large heat recovery credit. For
the dilute Category B streams which employ 70 percent heat recovery to
reduce fuel requirements, capital charges account for about 43 percent of
the total annualized cost. The moderately dilute streams of Category C,
which cannot employ preheating of the offgas because of safety
considerations, have the highest energy requirements of any category. For
the typical Category C stream shown in Table 5-10, gas costs account for
about 55 percent of the total annualized cost, while capital charges account
for about 28-percent. The VOC-rich streams in Category D require little
fuel, and capital charges account for about 52 percent of the total
annualized cost of the typical stream shown in Table 5-10. The very rich
streams of Category E, which are conservatively assumed to be diluted to
avoid exceeding a 980°C combustion temperature, consequently require a
larger incinerator volume per standard cubic meter of offgas. For this
reason and because of the greater gas expansion at the higher combustion
temperature, capital charges account for about 50 percent of the total
annualized cost of the typical stream shown in Table 5-10.
5.4.2 Variation of Control Costs with Changes in Offgas Parameters
The percentage of the total annualized cost due to capital charges
increases as offgas flowrate decreases due to economics of scale. In
5-18
-------
TABLE 5-10. TYPICAL EMISSION CONTROL COSTS FOR EACH DESIGN CATEGORY
Category
Al
A2
B
C
0
E
Typical
Heating
Value
(MJ/scm)
0.74
4.52
0.12
1.19
2.75
4.8
Typical
Flowrate
( s cm/mi n)
327
327
327
327
327
327
Installed
Capital
($1,000)
5,169
5,025
1,914
1,373
1,382
1,992
Capital
Charges
($l,000/yr)
1,049
1,020
389
278
281
404
Maintenance
($l,000/yr)
155
151
57
41
41
60
Heat
Recovery
Credit
($l,000/yr)
1,938
1,939
0
0
0
0
Natural
Gas
Costs
($1,000)
2,179
189
294
537
105
184
Caustic
Costs
($l,000/yr)
646
646
0
0
0
0
Operating
Costs
($l,000/yr)
1 ,668*
-341a
585
763
314
480
Annual ized
Costs
(1,000/yr)
2,509
477
897
987
539
804
alncludes $646,000 of caustic costs.
-------
contrast, utilities and operating labor are generally linear functions of
flowrate. For a given chemical manufacturing process, flowrate is expected
to be roughly proportional to capacity. Therefore, the percentage of total
annualized costs due to capital charges is also expected to increase as
capacity decreases.
Total annualized costs, as well as each contributing factor to them,
are expected to be essentially equal for any two given streams with the same
flowrate and heating value, but differing VOC contents. (Such streams would
have counterbalancing differences in non-VOC combustibles content.)
Total annualized cost (for nonchlorinated streams) is expected to
decrease as heating value increases through Categories B and C, reaching a
minimum at the low-heating value end of Category D. Total annualized cost
is expected to increase with increasing heating value through Categories D
and E, due to greater combustion air and dilution air requirements and gas
expansion at higher combustion temperatures. This increase is attributable
to increased capital charges. For chlorinated Category Al streams, total
annualized cost decreases with increasing offgas heating value. Annualized
costs of Category A2 streams are not expected to be particularly sensitive
to variation in offgas heating value. Due to higher capital costs
attributable largely to the scrubber, chlorinated streams are in general
more costly to control than nonchlorinated ones.
5.5 COST EFFECTIVENESS
The cost-effectiveness values are defined as total annualized costs per
annual Mg of VOC emissions controlled. The cost effectiveness is calculated
with respect to baseline emissions. Uncontrolled emissions were defined as
emissions from the primary absorber vent. The estimate baseline control
fraction of 58 percent is derived in Appendix B. The cost effectiveness for
selected vent streams of all design categories and with various offgas
characteristics are given in Table 5-11.
5.5.1 Variation of Cost Effectiveness with Changes in Offgas Parameters
That portion of cost effectiveness attributable to utilities and
operating labor is generally insensitive to variations in offgas flowrate or
capacity. In contrast, that portion of cost effectiveness attributable to
capital charges is expected to decrease with increasing flowrate. This
effect is illustrated by the three Category B streams in Table 5-11 which
vary only in offgas flowrate. However, vent streams with flowrates just
large enough to require an additional control system unit will have a
correspondingly higher cost effectiveness. The cost effectiveness of a
Category B stream with a flowrate of 1,350 scm/min (the assumed maximum
value) is expected to increase about 76 percent if two equipment units are
employed.
Increases in VOC content decrease cost effectiveness in two ways. If
non-VOC combustible content remains constant, heating value will increase
with increasing VOC content, and that portion of cost effectiveness attribut-
able to fuel requirements will in general decrease. Emission reduction is
proportional to VOC content. Therefore, cost effectiveness is inversely
proportional to VOC content (apart from the relation of heating value to VOC
content). This effect is illustrated in Table 5-11 by the pairs of streams
which differ from each other only in VOC content.
5-20
-------
TABLE 5-11. COST EFFECTIVENESS FOR SELECTED STREAMS OF EACH DESIGN CATEGORY
01
Category
Al
A2
B
B
B
B
C
C
D
E
Characteristics
Typical
Typical
Typical
Low Emissions Rate
Low Flowrate
High Flowrate
Typical
High Emissions Rate
Typical
Typical
Net
Heating
Value
(MJ/scm)
0.74
4.52
0.12
0.12
0.12
0.12
1.19
1.19
2.75
4.8
Hourly
Emissions
Rate
(kg/hr)
130
650
130
18
26
960
130
440
220
220
Non-VOC Combustible
Content
(Volume
Percent)
1.5
9.7
0
0.4
0
0
2.7
1.2
6.8
12.6
Operating
Flowrate
( s cm/mi n)
327
327
327
327
65
2,400
327
327
327
436
Annual ized
Costs
($l,000/yr)
2,509
477
897
897
338
5,294
987
987
539
804
Annual
Emissions
(Gg/yr)
0.88
4.41
0.88
0.121
0.175
6.48
0.88
2.97
1.48
1.48
Annual
Emission
Reduction
(Gg/yr)
0.86
4.33
0.86
0.119
0.174
6.35
0.86
2.91
1.45
1.45
Cost
Effectiveness
($/Mg)
2,917
110
1,043
7,534
1,966
817
1,148
339
370
553
Requires three equipment units.
-------
Cost effectiveness has a significant dependence on non-VOC combustible
content, although the relation is weaker than that between cost effectiveness
and VOC content. Streams which differ in non-VOC combustible content but
not in VOC content must have different heating values. Among vent streams
in the statistical profile (discussed in Appendix B), variations in non-VOC
combustible content are quite pronounced. Cost effectiveness generally
decreases with an increase in heating value, if the VOC content is constant.
However, cost effectiveness is expected to increase with increased heating
values within the boundaries of design Categories B and C, due to the loss
of potential heat recovery from the offgas. A cost-effectiveness increase
is also expected with increased heating value through the range of Category E,
due to the increasing dilution air requirements.
5.5.2 Total Resource Effectiveness (TRE) Index
The total resource effectiveness (TRE) index of a vent stream is
defined as the cost effectiveness of the stream divided by $l,600/Mg. The
TRE index is a convenient, dimension!ess measure of the total resource
burden associated with VOC control at a facility. It is independent of the
general inflation rate. However, it does assume fixed relative costs of the
various resources, except for natural gas (as discussed in Chapter 4).
The TRE index of a process vent stream can be estimated according to
the following equation:
TRE = | [a + b(FLOW)0'88 + c(FLOW) + d(FLOW)(HT) + e(FLOW0'88)(HT°-88)
+ f (FLOW)0'5]
where:
TRE = Total resource effectiveness index value.
FLOW = Vent stream flowrate (scm/min), at a standard temperature
of 20°C.*,**
E = Hourly measured emissions in Kg/hr.*
HT = Vent stream net heating value (MJ/scm), where the net enthalpy
per mole of offgas 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
FLOW.*
a, b, c, d, e, and f are coefficients. The set of coefficients which
apply to a process vent stream can be obtained from Table 5-12. These
coefficients were obtained by substituting the numeric values for all
variables, except offgas flowrate, heating value,'and VOC content, in the
cost and emissions equations given in Tables 5-5 and 5-9. The resulting
equations were substituted into the cost-effectiveness equation given in
Table 5-9, which was then indexed to a constant cost-effectiveness value as
described above. The TRE index equation simplifies to the six terms shown
*See Appendix H for reference methods and procedures.
**For a Category E stream, Flow should be replaced by "Flow x HT/3.6" when
associated with the f coefficient.
5-22
-------
TABLE 5-12. COEFFICIENTS OF THE TOTAL RESOURCE-EFFECTIVENESS (TRE) INDEX EQUATION
Al. FOR CHLORINATED PROCESS VENT STREAMS, IF 0 < NET HEATING VALUE (MJ/scm) < 3.5:
W Vent Stream Flowrate (scm/min) a b c d e f
W < 13.5
13.5 < W < 700
700 < tf < 1400
1400 < W < 2100
2100 < W < 2800
2800 < W < 3500
48.73
42.35
84.38
126.41
168.44
210.47
0
0.624
0.678
0.712
0.747
0.758
0.404
0.404
0.404
0.404
0.404
0.404
-0.1632
-0.1632
-0.1632
-0.1632
-0.1632
-0.1632
0
0
0
0
0
0
0
0.0245
0.0346
0.0424
0.0490
0.0548
A2. FOR CHLORINATED PROCESS VENT STREAMS, IF 3.5 - NET HEATING VALUE (Mj/scm):
W - Vent Stream Flowrate (son/mln) a b c
W < 13.5
13.5 < W < 700
700 < W < 1400
1400 < W < 2100
2100 < W < 2800
2800 < W < 3500
47.76
41.58
82.84
123.10
165.36
206.62
0
0.605
0.658
0.691
0.715
0.734
-0.292
-0.292
-0.292
-0.292
-0.292
-0.292
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0245
0.0346
0.0424
0.0490
0.0548
6. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 0 < NET HEATING VALUE (MJ/scm) < 0.48:
W = Vent Stream Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1350
1350 ' W < 2700
2700 < W < 4050
19.05
16.61
32.91
49.21
0
0.239
0.260
0.273
0.113
0.113
0.113
0.113
-0.214
-0.214
-0.214
-0.214
0
0
0
0
0
0.0245
0.0346
0.0424
C. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 0.48 < NET HEATING VALUE (MJ/scm) < 1.9:
W ' Vent Stream Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1350
1350 < W < 2700
2700 < W < 4050
19.74
18.30
36.28
54.26
0
0.138
0.150
0.158
0.400
0.400
0.400
0.400
-0.202
-0.202
-0.202
-0.202
0
0
0
0
0
0.0245
0.0346
0.0424
D. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 1.9 < NET HEATING VALUE (MJ/scm) < 3.6:
w = Vent Stream Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1190
1190 < U < 2380
2380 < W < 3570
15.24
13.63
26.95
40.27
0
0.157
0.171
0.179
0.033
0.033
0.033
0.033
0
0
0
0
0
0
0
0
0
0.0245
0.0346
0.0424
E. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 3.6 < NET HEATING VALUE (MJ/scm):
w = Dilution Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1190
1190 < W ? 2380
2380 < W < 3570
15.24
13.63
26.95
40.27
0
0
0
0
0
0
0
0
0.0090
0.0090
0.0090
0.0090
0
0.0503
0.0546
0.0573
0
0.0245
0.0346
0.0424
5-23
-------
above. At least two of the equation terms equal zero for vent streams in
any design category. The term of the gas use equation proportional to
squared heating value is sufficiently insignificant that it was ignored in
constructing the simplified equation and table of coefficients.
Table 5-12 is divided into the six design categories for control
equipment. Under each design category listed in the table, there are
several intervals of offgas flowrate. Each flowrate interval is associated
with a different set of TRE equation coefficients. The first flowrate
interval in each design category applies to vent streams with a flowrate
smaller than that 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 one, two, three, four, or five sets of control equipment,
respectively.
5.5.3 TRE Index Cutoff Value and Impacts of the RACT Recommendation
The RACT recommendation is based on incineration of those process vent
streams with an associated TRE index value of less than 1.0. This TRE index
cutoff value corresponds to a cost effectiveness of $1600 per Mg of VOC
destroyed. Under this RACT recommendation, three of the selected streams
presented in Table 5-11 would not reduce VOC emissions. These are the
chlorinated, dilute Category Al stream and the Category B stream with a very
low VOC content and the Category B stream with a low flowrate. Streams with
very low flowrates would tend to exceed the TRE index cutoff value, even if
their fuel requirements were small. Appendix D gives the procedure
necessary for converting the TRE index value of a facility to facility
cost effectiveness in $/Mg.
The estimated overall impacts of RACT are presented in Table 5-13. The
RACT involves a 98 percent VOC reduction for the estimated 14 facilities
which would control VOC emissions. An estimated 33 facilities would not
control VOC emissions under RACT. These impacts were projected assuming the
applicability of the statistical profile of offgas parameters (discussed in
Appendix B) to the 47 existing air oxidation facilities located in ozone
nonattainment areas. Any facilities in the profile that now use combustion
control or have changed processes were automatically considered not subject
to additional VOC emissions controls under RACT. The estimated overall
annualized cost associated with RACT is $30 million/yr and the estimated
overall capital cost is $30 million.
5-24
-------
TABLE 5-13. ESTIMATED IMPACTS OF RACTa
en
i
no
en
Cutoff Total
Resource
Effectiveness
Index
1.0
Cutoff Cost
Effectiveness
(S/Mg)B>C
1,600
Number of
Sources .
Affected0
14
National
Emissions
After Control
By RACTe
(Gg/yr)
19
Percent
Emission
Reduction
Over Baseline
53
National
Energy Impact
(TJ/yr)°
5,000
Overall
Annual ized Cost.
(Million $/yr)c*a
30
Overall Installed
Capital Cost.
(Million $)c>a
30
aAssuming applicability of the statistical profile of offgas parameters to the 47 existing air oxidation facilities located in ozone nonattainment
areas.
Highest cost effectiveness for any plant which would control VOC under RACT. Plants with a higher cost effectiveness would not control VOC under
RACT.
GJune, 1980 dollars.
RACT involves 98 percent VOC reduction from baseline levels for those facilities which would control VOC emissions. However only an estimated 14 of
the 47 plants would control VOC emissions under RACT.
eRACT would reduce national emissions over baseline by 21 Gg/yr (from 40 Gg/yr to 19 Gg/yr).
-------
5.6 REFERENCES FOR CHAPTER 5
1. Basdekis, H.S. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry. Control Device Evaluation. Thermal
Oxidation Supplement (VOC Containing Halogens or Sulfur). Report 2.
EPA-450/3-80-026. December 1980. p. III-ll.
2. Blackburn, J.W. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry. Air Oxidation Generic Standard
Support. EPA Contract No. 68-02-2577. May 1979. p. III-3.
3. Memo from Desai, T., EEA, to Galloway, J., EEA. April 2, 1981.
Preheat temperature for combustion air and VOC offgas stream.
4. Blackburn, op. cit., p. III-3.
5. Letter and attachment from McClure, H.H., Texas Chemical Council, to
Patrick, D., EPA. December 13, 1979. p. 7.
6. Memo and attachment from Mulchandani, B., EEA, to Galloway, J., EEA.
October 29, 1980. Calculations involving combustion air preheating.
7. Blackburn, J.W. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry. Control Device Evaluation. Thermal
Oxidation. Report 1. EPA-450/3-80-026. December 1980. pp. 1-1, 1-2.
8. Basdekis, op. cit., p. III-ll.
9. Blackburn, Generic Standard Support, op. cit., p. III-3.
10. Desai, op. cit.
11. Blackburn, Generic Standard Support, op. cit., p. III-3.
12. McClure, op. cit., p. 7.
13. Mulchandani, op. cit.
14. Blackburn, Thermal Oxidation, op. cit., pp. 1-1, 1-2.
15. Ibid.
16. Memo from Galloway, J., EEA, to SOCMI Air Oxidation File.
December 31, 1980. Maximum flowrate per incinerator unit.
17. Blackburn, Thermal Oxidation, op. cit.
18. Memo from Derway, D., EEA, to Galloway, J., EEA. August 15, 1980.
5-26
-------
19. Blackburn, Thermal Oxidation, op. cit., p. 111-13.
20. Basdekis, op. cit., p. 111-12.
21. Ibid., p. III-8.
22. Blackburn, Thermal Oxidation, op.cit., p III-9.
23. Ibid., p. III-l.
24. Ibid., p. III-4.
25. Basdekis, op. cit., p. III-4.
26. Ibid., p. III-7.
27. Ibid.
28. Blackburn, Thermal Oxidation, op. cit.
29. Chemical Engineering. July 14, 1980.
30. Memo from Galloway, J., EEA, to SOCMI Air Oxidation File.
August 8, 1980. Retrofit costs for thermal incinerators.
31. Ibid.
32. Blackburn, Thermal Oxidation, op. cit., p. V-l.
33. Ibid., pp. V-3, V-15.
34. Ibid., p. V-15.
35. Ibid., p. V-22.
36. Ibid., pp. 111-19, 111-22.
37. Basdekis, op. cit., p. 111-14.
38. Ibid., p. 111-15.
39. Ibid., pp. III-ll, 111-15, 111-16.
40. Blackburn, Thermal Oxidation, op. cit., p. 11-12.
41. Mulchandani, op. cit.
42. Blackburn, Thermal Oxidation, op. cit., p. V-22.
5-27
-------
43. Basdekis, op. cit., p. V-16.
44. Memo from Vatavuk, W., and Chasko, B., EPA, to Porter, F., EPA.
"Guidance for Developing CTGD Cost Chapters", September 17, 1980.
45. Blackburn, Thermal Oxidation, op. cit., p. III-8.
46. Baskdekis, op. cit., p. III-6.
47. Memo from Galloway, J., EEA, to SOCMI Air Oxidation File.
September 1, 1980.
48. Baasel, W.D., Chemical Engineering Plant Design. Oil Insurance
Association. Elsevier Publishing (New York, 1972). pp. 143-145,
5-28
-------
APPENDIX A. EMISSION SOURCE TEST DATA
-------
APPENDIX A: EMISSION SOURCE TEST DATA
The purpose of this appendix is to describe results of tests of
volatile organic compound (VOC) emissions reduction by thermal incineration.
These test results were used in the development of the control techniques
guideline (CTG) document for air oxidation processes of the synthetic
organic chemicals manufacturing industry (SOCMI). Background data and
detailed information which support the emission levels achievable are
included.
Section A.I of this appendix presents the VOC emissions test data
including individual test descriptions. Section A.2 provides a summary of
NO emissions from some of the tests. Section A.3 consists of comparisons
of various test results and a discussion exploring and evaluating the
similarities and differences of these results.
A.I VOC EMISSIONS TEST DATA
The tests were aimed at evaluating the performance of thermal
incinerators when used under varied conditions on the air oxidation process
waste streams. The results of this study indicate that 98 percent VOC'
reduction or 20 ppmv by compound exit concentration, whichever is less
stringent, is the highest control level currently achievable by all new
incinerators, considering available technology, cost, and energy use. This
level is expressed in both percent reduction and ppmv to account for the
leveling off of exit concentrations as inlet concentrations drop. This
level can be achieved by incinerator operation at conditions which include a
maximum of 1600°F and 0.75 second residence time. The 98 percent level can
frequently be achieved at lower combustion temperatures.
Three sets of test data are available. These sets consist of field
unit data from tests conducted by EPA and by chemical companies and of
lab-scale incinerator data from tests by Union Carbide.
A.1.1 Chemical Company Test Data
These data are from tests performed by chemical companies on
incinerators at three air oxidation units: the Petro-tex oxidative
butadiene unit at Houston, Texas, the Koppers maleic anhydride unit at
Bridgeville, Pennsylvania, and the Monsanto acrylonitrile unit at Alvin,
Texas.
A. 1.1.1 Petro-Tex Test Data2
1. Facility and Control Device - The Petro-tex incinerator for the
"Oxo" butadiene process is designed to treat 48,000 scfm waste gas
containing about 4000 ppm hydrocarbon and 7000 ppm carbon dioxide. The use
of the term hydrocarbon in this discussion indicates that besides VOC, it
may include non-VOC such as methane. The waste gas treated in this system
results from air used to oxidize butene to butadiene. The waste gas, after
butadiene has been recovered in an oil absorption system, is combined with
other process waste gas and fed to the incinerator. The waste gas enters
the incinerator between seven vertical Coen duct burner assemblies. The
incinerator design incorporates flue gas recirculation and a waste heat
A-l
-------
boiler. The benefit achieved by recirculating flue gas is to incorporate
the ability to generate a constant 100,000 Ibs/hr of 750 psi steam with
variable waste gas flow. The waste gas flow can range from 10 percent to
100 percent of design production rate.
The incinerator measures 72 feet by 20 feet by 8 feet, with an average
firebox cross-sectional area of 111 square feet. The installed capital cost
was $2.5 million.
The waste gas stream contains essentially no oxygen; therefore,
significant combustion air must be supplied. This incinerator is fired with
natural gas which supplies 84 percent of the firing energy. The additional
required energy is supplied by the hydrocarbon contamination of the waste
gas stream. Figure A-l gives a rough sketch of this unit.
2. Sampling and Analytical Techniques waste Gas
The waste gas sampling was performed with integrated bags. The
analysis was done on a Carle analytical gas chromatograph having the
following columns: D
1. 6-ft OPN/PORASILK (80/100).
2. 40-ft 20 percent SEBACONITRILEK on gas chrom. RA 42/60.
3. 4-ft PORAPAK N 80/100.
4. 6-ft molecular sieve bx 80/100.
Stack Gas
The stack gas samples are collected via a tee on a long stainless steel
probe which can be inserted into the stack at nine different locations.
These gas samples are collected in 30-50 cc syringes.
The gas samples are then transferred to a smaller 1 cc syringe via a
small glass coupling device sealed at both ends with a rubber grommet. The
1-cc samples can then be injected into a chromatograph for hydrocarbon
analysis. A Varian 1700 chromatograph is used, having a 1/8-in. x 6-ft
column packed with 5A molecular sieves and a 1/4-in. x 4-ft column packed
with glass beads connected in series with a bypass before and after the
molecular sieve column, controlled by a needle valve to split the sample.
The data are reported as ppm total HC, ppm methane, and ppm non-methane
hydrocarbons (NMHC). The CO content in the stack is determined by using a
Kitagawa sampling probe. The 02 content in the stack is determined via a
Teledyne O^/combustible analyzer.
3. Test Results - Petro-tex has been involved in a modification plan
for its "Oxo" incinerator unit after startup. The facility was tested by
the company after each major modification was made to determine the impact
of these changes on the VOC destruction efficiency. The incinerator showed
improved performance after each modification and the destruction efficiency
increased from 70 percent to well above 98 percent. Table A-l provides a
summary of these test results. The type of modifications made in the
incinerator were as follows:
November 1977
Test data prior to these changes showed the incinerator was not
destroying hydrocarbons as well as it should (VOC destruction efficiency as
low as 70 percent), so the following changes were made:
A-2
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Aupentint
(Supplemental)
AirOuct
Redrcuiation
Air Duct
RECIRCUUT10N
AIR FAN
Figure A—1. Petro-Tex oxo unit incinerator.
A-3
-------
TABLE A-l. THERMAL INCINERATOR FIELD TEST DATA
Company 1 location Type of Process
Pelro-tex Chewical Butadiene
Corp. , Houston,
TX
Koppers Co., Inc. Haleic Anhydride
fir idgev tile. PA
Monsanto Chemical Acrylonitrile
Intermediates Co. .
Alvin, TX
Denka. Houston, TX Haleic Anhydride
fiohw i Haas. Acrylic Acid i
Deer Park. TX Esters
Union Carbide Acrylic Acid &
Corp., Taft. IA Acrylate Esters
Production Rate
During Test
Waste Gas Flow
(Inlet) scfia
7.250
15,617
20,750
15.867
12.500
Avg. Combustion
Air: 49,333
33.200
Air: 8000
24.200
Air: 2000
75.000 (Avg.)
33,000
(701 of total
capacity)
Each 52.500
(12.500 tank
farm vent
(TVF))
(40.000 oxidl-
zer vent (OXV))
20.600
Number
of Tests
or Sets
Set 1
Set 2
Set 3
Set 4
Set 5
Set 1
Set 2
Unit 1
Unit 2
3
Set 1
3
Set 2
4
Set 3
1
Set 1
6
Sot 2
3
Test Date
5/25/77
9/09/77
12/01/77
4/19/78
9/27/78
11/02/77
11/16/77
12/16/77
12/16/77
3/21/78
3/22/78
3/23/78
3/78
3/78
3/78
12/78
12/78
Supplemental
fuel Residence Incineration Inlet
i Awount live Temperature VOC
Used (scfw) (Seconds) ( r) (ppuv)
Natural
Gas
1400
1467
900
1175
1176
Natupal
G4.S
Natural
Gas
1060 (gas)
1060
1060
900 (gas)
900
900
Natural
Gas
0.6
0.6
0.6
0.6
0.6
0.6
0.6
N/A
N/A
0.6
0.6
0.6
1.0
1.0
1.0
2-3
2-3
1400
1400
1400
1400
1400
"Below
2000"
Conf iden-
dential
1400
1400
1400
1425 TVF
OXV
1510 TVF
OXV
1545 1VF
OXV
1160
1475
10,300
10.650
10.650
10.300
10.300
834
834
VOC
Outlet Destruction
VOC Efficiency
(pp«v) by Weight
1000
215
215
10
10
7
8
Confiden- 25
dential
950
950
950
2.580
11.600
2.600
12,800
2.4)0
12.200
11.900
11.900
.47
13
13
13
1330
150
25
243
10
70.3
94.1
94.1
99.6
99.6
98.96
98.96
-99
'99
9fl.5
98.5
98.5
82.6
98.3
99.7
96.1
99.9
-------
1. Moved the duct burner baffles from back of the burner to the
front.
2. Installed spacers to create a continuous slot for supplemental air
to reduce the air flow through the burner pods.
3. Installed plates upstream of the burners so that ductwork matches
burner dimensions.
4. Cut slots in recycle duct to reduce exit velocities and improve
mixing with Oxo waste gas.
5. Installed balancing dampers in augmenting (supplemental) air
plenums, top and bottom.
6. Installed balancing dampers in three of the five sections of the
recycle duct transition.
7. Cut opening in the recirculation duct to reduce the outlet
velocities.
March 1978
After the November changes were made, a field test was made in December
1977, which revealed that the incinerator VOC destruction efficiency
increased from 70.3 percent to 94.1 percent. However, it still needed
improvement. After much discussion and study the following changes were
made in March 1978:
1. Took the recirculation fan out of service and diverted the excess
forced draft air into the recirculation duct.
2. Sealed off the 5-1/2-in. wide slots adjacent to the burner pods
and removed the 1/2-in. spacers which were installed in
November 1977.
3. Installed vertical baffles between the bottom row of burner pads
to improve mixing.
4. Installed perforated plates between the five recirculation qlucts
for better Oxo waste gas distribution.
5. Cut seven 3-in. wide slots in the recycle duct for better
secondary air distribution.
July 1978
After the March 1978 changes, a survey in April 1978 showed the Oxo
incinerator to be performing very well (VOC destruction efficiency of 99.6
percent) but with a high superheat temperature of 850°F. So, in July 1978,
some stainless steel shields were installed over the superheater elements to
help lower the superheat temperature. A subsequent survey in September
1978, showed the incinerator to still be destructing 99.6 percent VOC and
with a lower superheat temperature (750°F).
This study pointed out that mixing is a critical factor in efficiency
and that incinerator adjustment after startup is the most feasible and
efficient means of improving mixing and thus, the destruction efficiency.
A.1.1.2 Koppers Test Data
1. Facility and Control Device - The Koppers incinerator is actually
a boiler adapted to burn gaseous wastes from maleic anhydride unit. The
boiler is designed to operate at a temperature of 2000°F and a residence
A-5
-------
time of 0.6 second. Current operating parameters have not been measured,
but it is the company's judgment that the boiler now operates somewhat below
2000°F. The flowrate of waste gas to the boiler is usually 32,000 scfm and
contains 350 Ibs/hr benzene, 2850 Ibs/hr carbon monoxide, 22,100 Ibs/hr
oxygen, 6434 Ibs/hr water, and 105,104 Ibs/hr nitrogen. While these values
are typical for the system, they vary throughout the production cycle. The
boiler is fired with natural gas.
2. Sampling and Analytical Techniques - Different methods were used
for inlet and outlet sampling.Although integrated samples were used for
the outlet, gas bottle samples were used for the inlet. Such a sampling
technique would likely give a low bias to the measured inlet VOC
concentration.
The inlet concentration was taken to be the average of all maleic
reactor offgas measurements made. There were four samples taken, and the
results were 600 ppmv, 1172 ppmv, 600 ppmv, and 964 ppmv for an average of
834 ppmv benzene. (These values are not boiler inlet values since they were
collected prior to the introduction of the additional combustion air.) This
wide range of benzene values indicates the great deal of variability
inherent in efficiency calculations employing such a sampling technique.
For the June 1978 tests, samples of stack gas were taken in glass
bottles by plant chemists and analyzed at Koppers1 Monroeville Research
Center by direct injection to a gas chromatograph with flame ionization
detector. The November 1977 method used specially-designed charcoal
adsorption tubes, instead of impingers, in a United States Environmental
Protection Agency-type sampling train. The charcoal was eluted with CS? and
the eluent analyzed by gas chromatography.
3. Test Results - One test run of the Koppers data indicates 97.2
percent efficiency at 1800°F. However, the entire Koppers test is
disregarded as not demonstrably accurate because of the poor sampling
technique. Grab samples employed in obtaining inlet gas could give a low
bias to the measured inlet VOC concentration. Therefore, the calculated VOC
destruction efficiency would be artificially low. Table A-l provides a
summary of these test results.
A.1.1.3 Monsanto Test Data5
1. Facility and Control Device - The Monsanto incinerator burns both
liquid and gaseous wastes from the acrylonitrile unit and is termed an
absorber vent thermal oxidizer. Two identical oxidizers are employed. The
primary purpose of the absorber vent thermal oxidizers is hydrocarbon
emission abatement.
Acrylonitrile is produced by feeding propylene, ammonia, and excess air
through a fluidized, catalytic bed reactor. In the process, acrylonitrile,
acetonitrile, hydrogen cyanide, carbon dioxide, carbon monoxide, water, and
other miscellaneous organic compounds are produced in the reactor. The
columns in the recovery section separate water and crude acetonitrile as
liquids. Propane, unreacted propylene, unreacted air components, some
unabsorbed organic products, and water are emitted as a vapor from the
absorber column overhead. The crude acrylonitrile product is further
refined in the purification section to remove hydrogen cyanide and the
remaining hydrocarbon impurities.
A-fi
-------
The organic waste streams from this process are incinerated in the
absorber vent thermal oxidfzer at a temperature and residence time
sufficient to reduce stack emissions below the required levels. The
incinerated streams include (1) the absorber vent vapor (propane, propylene,
CO, unreacted air components, unabsorbed hydrocarbons), (2) liquid waste
acetonitrile (acetonitrile, hydrogen cyanide, acrylonitrile), (3) liquid
waste hydrogen cyanide, and (4) product column bottoms purge (acrylonitrile,
some organic heavies). The two separate acrylonitrile plants at Chocolate
Bayou employ identical thermal oxidizers.
Each thermal oxidizer is a horizontal, cylindrical, saddle-supported,
end-fired unit consisting of a primary burner vestibule attached to the main
incinerator shell. Each oxidizer measures 18 feet in diameter by 36 feet in
length.
The thermal oxidizer is provided with special burners and burner guns.
Each burner is a combination fuel-waste liquid unit. The absorber vent
stream is introduced separately into the top of the burner vestibule. The
flows of all waste streams are metered and sufficient air is added for
complete combustion. Supplemental natural gas is used to maintain the
operating temperature required to combust the organics and to maintain a
stable flame on the burners during minimum gas usage. Figure A-2 gives a
plan view of the incinerator.
2. Sampling and Analytical Techniques
Feed Stream and Effluent
The vapor feed streams (absorber vent) to the thermal oxidizer and the
effluent gas stream are sampled and analyzed using a modified analytical
reactor recovery run method. The primary recovery run methods are Sohio
Analytical Laboratory Procedures.
The modified method involves passing a measured amount of sample gas
through three scrubber flasks containing water and catching the scrubbed gas
in a gas sampling bomb. The samples are then analyzed with a gas
chromatograph and the weight percent of the components is determined.
Stack Gas
Figure A-3 shows the apparatus and configuration used to sample the
stack gas. It consists of a line of the sample valve to the small
water-cooled heat exchanger. The exchanger is then connected to a
250 ml sample bomb used to collect the unscrubbed sample. The bomb is then
connected to a pair of 250 ml bubblers, each with 165 ml of water in it.
The scrubbers, in turn, are connected to another 250 ml sample bomb used to
collect the scrubbed gas sample which is connected to a portable compressor.
The compressor discharge then is connected to a wet test meter that vents to
the atmosphere.
After assembling the apparatus, the compressor is turned on and it
draws gas from the stack and through-the system at a rate of 0.2 ft /min.
Sample is dcawn until at least 10 ft have passed through the scrubbers.
After 10 ft has been scrubbed, the compressor is shutdown and the
unscrubbed bomb is analyzed for CH., CJs, C-Hg, and C-HL, the scrubbed bomb
is analyzed for Np, air, 0~, COp, and CO, ana the bubbler liquid is analyzed
for acrylonitrile, acetonitrile, hydrogen cyanide, and total organic carbon.
The gas samples are analyzed by gas chromatography. For the liquid samples,
A-7
-------
I
00
PLAN VIEW
Figure A-2. Off gas incinerator, Monsanto Co., Chocolate Bayou Plant.
-------
TWO 2MML BUBBLERS
Will) I6&UL Distilled Walei in Each.
Bucket Contains Wet Ice Slush
2MML
SAMPLE BOMB
(Unsciubbed Sample)
PORTABLE
COMPRESSOR
2MML
SAMPLE BOMB
(Sciubbed Sample)
vt;:T TO
ATMOSPHERE
10 peel Above Giade
WET TEST
METER
NOTE: FIM Eidunga Piocess Outlet, AH Lines aie VauiM Tubing.
Figure A-3. Thermal incinerator stack sampling system.
-------
acrylonitrile and acetonitrile are analyzed by gas chromatography; hydrogen
cyanide (HCN) is by titration; and total organic carbon (TOC) is by a carbon
analysis instrument.
3. Test Results - Monsanto's test results show efficiencies well
above 98 percent; however, the parameters at which it is achieved are
confidential. All other known conditions are presented in Table A-l.
A.1.2 Environmental Protection Agency (EPA) Test Data
The EPA test study represents the most in-depth work available. These
data show the combustion efficiencies for full-scale incinerators on air
oxidation vents at three chemical plants. Data include inlet/outlet tests
on large incinerators, two at acrylic acid plants, and one at a maleic
anhydride plant. The tests measured inlet and outlet VOC by compound at
different temperatures, and the reports include complete test results,
process rates, and test method descriptions. The three plants tested are
the Denka, Houston, Texas, maleic anhydride unit and the Rohm and Haas, Deer
Park, Texas, -and Union Carbide, Taft, Louisiana, acrylic acid units. The
data from Union Carbide include test results based on two different
incinerator temperatures. The data from Rohm and Haas include results' for
three temperatures. In all tests, bags were used for collecting integrated
samples and a GC/FID was used for organic analysis.
A.1.2.1 Denka Test Data6
1. Facility and Control Device - The Denka maleic anhydride facility
has a nameplate capacity of 23,000 Mg/yr (50 million Ibs/yr). The plant was
operating at about 70 percent of capacity when the sampling was conducted.
The plant personnel did not think that the lower production rate would
seriously affect the validity of the results.
Maleic anhydride is produced by vapor-phase catalytic oxidation of
benzene. The liquid effluent from the absorber, after undergoing recovery
operations, is about 40 weight percent aqueous solution of maleic acid. The
absorber vent is directed to the incinerator. The thermal incinerator uses
a heat recovery system to generate process steam and uses natural?gas as
supplemental fuel. The size of the combustion chamber is 2195 ft . There
are three thermocouples used to sense the flame temperature, and these are
averaged to give the temperature recorded in the control room. A rough
sketch of the combustion chamber is provided in Figure A-4.
2. Sampling and Analytical Techniques
THC, Benzene, Methane, and Ethane
The gas samples were obtained according to the September 27, 1977, EPA
draft benzene method. Seventy-liter aluminized Mylar bags were used with
sample times of two to three hours. The sample box and bag were heated to
approximately 66°C (150°F) using an electric drum heater and insulation.
During Run 1-Inlet, the variac used to control the temperature malfunctioned
so the box was not heated for this run. A stainless steel probe was
inserted into the single port at the inlet and connected to the gas bag
through a tee. The other leg of the tee went to the total organic acid
(TOA) train. A Teflon line connected the bag and the tee. A stainless
steel probe was connected directly to the bag at the outlet. The lines were
A-10
-------
lSR-t«-
FUJI
SIDE VIEI
(Inlet)
(Outlet)
There are Three Thermocouples Spaced Evenly Across trie Top of trie Firebox.
The Width of the Firebox is 6ft-6in.
Figure A—4. Incinerator combustion chamber.
A-ll
-------
kept as short as possible and not heated. The boxes were transported to the
field lab immediately upon completion of sampling. They were heated until
the GC analyses were completed.
A Varian model 2440 gas chromatograph with a Carle gas sampling valve,
equipped with two cm matched loops, was used for the integrated bag
analysis. The SP-1200/Bentone 34 column was operated at 80°C. The
instrument has a switching circuit which allows a bypass around the column
through a capillary tube for THC response. The response curve was measured
daily for benzene (5, 10, and 50 ppm standards) with the column and in the
bypass (THC) mode. The THC mode was also calibrated daily with propane (20,
100, and 2000 ppm standards). The calibration plots showed moderate
nonlinearity. For sample readings which fell within the range of the
calibration standards, an interpolated response factor was used from a
smooth curve drawn through the calibration points. For samples above or
below the standards, the response factor of the nearest standard was
assumed. THC readings used peak height and column readings used area
integration measured with an electronic disc integrator.
CO
Analysis for these constituents was done on samples drawn from the
integrated gas bag used in THC, benzene, methane, and ethane. Carbon
monoxide analysis was done following the GC analyses using EPA Reference
Method 10 (Federal Register, Vol. 39, No. 47, March .8, 1974). A Beckman
Model 215 NDIR analyzer was used to analyze both the inlet and outlet
samples.
Duct Temperature, Pressure, and Velocity
Duct temperature and pressure values were obtained from the existing
inlet port. A thermocouple was inserted into the gas sample probe for the
temperature while a water manometer was used for the pressure readings.
These values were obtained at the conclusion of the sampling period.
Temperature, pressure, and velocity values were obtained for the outlet
stack. Temperature values were obtained by thermocouple during the gas
sampling. Pressure and velocity measurements were taken according to EPA
Reference Method 2 (Federal Register, Vol. 42, No. 160, August 18, 1977).
These values also were obtained at the conclusion of the sampling period.
2. Test Results - The Denka incinerator achieves greater than 98
percent reduction at 1400°F and 0.6 second residence time. These results
suggest that the recommended 98 percent control level is achievable by
properly maintained and operated new incinerators, for which the operating
conditions are less stringent than 1600°F and 0.75 second. Table A-l
provides a summary of these test results.
A.1.2.2 Rohm and Haas Test Data7
1. Facility and Control Device - The Rohm and Haas plant in Deer
Park, Texas, produces acrylic acid and ester. The capacity of this facility
has been listed at 400 million Ibs/yr of acrylic monomers. Acrylic esters
are produced using propylene, air, and alcohols, with acrylic acid produced
as an intermediate. Acrylic acid is produced directly from propylene by a
vapor-phase catalytic air oxidation process. The reaction product is
purified in subsequent refining operations. Excess alcohol is recovered and
A-12
-------
heavy end by-products are incinerated. This waste incinerator is designed
to burn offgas from the two absorbers. In addition, all process vents (from
extractors, vent condensers, and tanks) which might be a potential source of
gaseous emissions are collected in a suction vent system and normally sent
to the incinerator. An organic liquid stream generated in the process is
also burned, thereby providing part of the fuel requirement. The remainder
is provided by natural gas. Combustion air is added in an amount to produce
six percent oxygen in the effluent. Waste gases are flared during
maintenance shutdowns and severe process upsets. The incinerator unit was
tested because it operates at relatively shorter residence times (0.75-1.0
seconds) and higher combustion temperatures (1200°-1560°F) than most
existing incinerators.
The total installed capital cost of the incinerator was $4.7 million.
The estimated operating cost due to supplemental natural gas use is $0.9
million per year.
2. Sampling and Analytical Techniques - Samples were taken
simultaneously at a time when propylene oxidations, separations, and
esterifications were operating smoothly and the combustion temperature was
at a steady state. Adequate time was allowed between the tests conducted at
different temperatures for the incinerator to achieve steady state. Bags
were used to collect integrated samples and a GC/FID was used for organic
analysis.
3. Test Results - VOC destruction efficiency was determined at three
different temperatures: 1425°F, 1510°F, and 1545°F. Efficiency is found to
increase with temperature and, except for 1425°F, it is above 98 percent.
Test results are summarized in Table A-l. These tests were for residence
times greater than 0.75 second. However, theoretical calculations show that
greater efficiency would be achieved at 1600°F and 0.75 second than at the
longer residence times, but lower temperatures represented in these tests.
A.1.2.3 Union Carbide (UCC) Test Data8
1. Facility and Control Device - The capacities for the UCC acrylates
facilities are about 200 million Ibs/yr of acrolein, acrylic acid, and
esters. Acrylic acid comprises 130 million Ibs/yr of this total. Ethyl
acrylate capacity is 90 million Ibs/yr. Total heavy ester capacities (such
as 2-ethyl-hexyl acrylate) are 110 million Ibs/yr. UCC considers butyl
acrylate a heavy ester.
The facility was originally built in 1969 and utilized British
Petroleum technology for acrylic acid production. In 1976 the plant was
converted to a technology obtained under license from Sohio.
The thermal incinerator is one of the two major control devices used in
acrylic acid and acrylate ester manufacture. The UCC incinerator was
installed in 1975 to destroy acrylic acid and acrolein vapors. This unit
was constructed by John Zink Company for an installed cost of $3 million and
incorporates a heat recovery unit to produce process steam at 600 psig. The
unit operates at a relatively constant feed input and supplements the
varying flow and fuel value of the streams fed to it with inversely varying
amounts of fuel gas. Energy consumption averages 52.8 million Btu/hr
instead of the designed level of 36-51 million Btu/hr. The operating cost
A-13
-------
in 1976, excluding capital depreciation, was $287,000. The unit is run with
nine percent excess oxygen instead of the designed three to five percent
excess oxygen. The combustor is designed to handle a maximum of four
percent propane in the oxidation feed.
Materials of construction of a non-return block valve in the
600 psig steam line from the boiler section requires that the incinerator be
operated at 1200°F instead of the designed 1800°F. The residence time is
three to four seconds.
2. Sampling and Analytical Procedures - The integrated gas samples
were obtained according to the September 27, 1977, EPA draft benzene method.
Each integrated gas sample was analyzed on a Varian Model 2400 gas
chcomatograph with FID, and a heated Carle gas sampling valve with matched 2
cm sample loops. A valved capillary bypass is used for total hydrocarbon
(THC) analyses and a 2 m, 1/8-in., OD nickel column with PORAPAK P-S,
80-100 mesh packing is used for component analyses.
Peak area measurements were used for the individual component analyses.
A Tandy TRS-80, 48K floppy disc computer interfaced via the integrator pulse
output of a Linear Instruments Model 252A recorder acquired, stored, and
analyzed the chromatograms.
The integrated gas samples were analyzed for oxygen and carbon dioxide
by duplicate Fyrite readings. Carbon monoxide concentrations were obtained
using a Beckman Model 215A nondispersive infrared (IR) analyzer using the
integrated samples. A three-point calibration (1000, 3000, and 10,000 ppm
CO standards) was used with a linear-log curve fit.
Stack traverses for outlet flowrate were made using EPA Methods 1
through 4 (midget impingers) and NO was sampled at the outlet using EPA
Method 7. x
3. Test Results - VOC destruction efficiency was determined at two
different temperatures. Table A-l provides a summary of these test results.
Efficiency was found to increase with temperature. At 1475°F, the
efficiency was well above 99 percent. These tests were, again, for
residence times greater than 0.75 second. However, theoretical calculations
show that greater efficiency would be achieved at 1600°F and 0.75 second
than at the longer residence times but lower temperatures represented in
these tests.
All actual measurements were made as parts per million (ppm) of propane
with the other units reported derived from the equivalent values. The
values were measured by digital integration.
The incinerator combustion temperature for the first six runs was about
1160°F. Runs 7 through 9 were made at an incinerator temperature of about
1475°F. Only during Run 3 was the acrolein process operating. The higher
temperature caused most of the compounds heavier than propane to drop below
the detection limit due to the wide range of attenuations used, nearby
obscuring peaks, and baseline noise variations. The detection limit ranges
from about 10 ppb to 10 ppm, generally increasing during the chromatogram,
and especially near large peaks. Several of the minor peaks were difficult
to measure. However, the compounds of interest, methane, ethane, ethylene,
propane, propylene, acetaldehyde, acetone, acrolein, and acrylic acid,
dominate the chromatograms. Only acetic acid was never detected in any
sample.
A-14
-------
The probable reason for negative destruction efficiencies for several
light components is generation by pyrolysis from other components. For
instance, the primary pyrolysis products of acrolein are carbon monoxide and
ethylene. Except for methane and, to a much lesser extent, ethane and
propane, the fuel gas cannot contribute hydrocarbons to the outlet samples.
A sample taken from the inlet line knockout trap showed 6 mg/g of
acetaldehyde, 25 mg/g of butenes, and 100 mg/g of acetone when analyzed by
gas chromatography/flame ionization detection (GC/FID).
A.1.3 Union Carbide Lab-Scale Test Data9
Union Carbide test data show the combustion efficiencies achieved on 15
organic compounds in a lab-scale incinerator operating between 800° and
1500°F and .1 to 2 seconds residence time. The incinerator consisted of a
130 cm, thin bore tube, in a bench-size tube furnace. Outlet analyzers were
done by direct routing of the incinerator outlet to a FID and GC. All inlet
gases were set at 1000 ppmv.
In order to study the impact of incinerator variables on efficiency,
mixing must first be separated from the other parameters. Mixing cannot be
measured and, thus, its impact on efficiency cannot be readily separated
when studying the impact of other variables. The Union Carbide lab work was
chosen since its small size and careful design best assured consistent and
proper mixing.
The results of this study are shown in Table A-2. These results show
moderate increases in efficiency with temperature, residence time, and type
of compound. The results also show the impact of flow regime on efficiency.
Flow regime is important in interpreting the Union Carbide lab unit
results. These results are significant since the lab unit was designed for
optimum mixing and, thus, the results represent the upper limit of
incinerator efficiency. As seen in Table A-2, the Union Carbide results
vary by flow regime. Though some large-scale incinerators may achieve good
mixing and plug flow, the worst cases will likely require flow patterns
similar to complete backmixing. Thus, the results of complete backmixing
would be, relatively, more comparable to those obtained from large-scale
units.
A.2 NITROGEN OXIDES (NO ) EMISSIONS
Nitrogen oxides are derived mainly from two sources: (1) from nitrogen
contained in the combustion air called thermal NO and (2) from nitrogen
chemically combined in the fuel, called fuel NO . In addition, combustion
of waste gas containing high levels of nitrogen-containing compounds also
may cause increases in NO emissions. For fuels containing low amounts of
nitrogen, such as natural gas and light distillate oils, thermal NO is by
far the larger component of total NO emissions. By contrast, fuel NO
can account for a significant percentage in the combustion of heavy oiis,
coal, and other high-nitrogen fuels such as coal-derived fuels and shale
oils.
Thermal oxidizer outlet concentrations of NO were measured in seven
sets of thermal oxidizer tests conducted at threexair oxidation plants.
Table A-3.provides a summary of the test results. The test results indicate
A-15
-------
TABLE A-2. RESULTS OF DESTRUCTION EFFICIENCY UNDER STATED
CONDITIONS (UNION CARBIDE TESTSd)
Residence Time/Compound
0.75 second
Flow , Temperature
Regime0 (°F)
Two-stage
Backmixing
Complete
Backmixing
Plug Flow
1300
1400
1500
1600
1300
1400
1500
1600
1300
1400
1500
1600
Ethyl
Acrylate
99.9
99.9
99.9
99.9
98.9
99.7
99.9
99.9
99.9
99.9
99.9
99.9
Ethanol
94.6
99.6
99.9
99.9
86.8
96.8
99.0
99.7
99.9
99.9
99.9
99.9
Ethyl ere
92.6
99.3
99.9
99.9
84.4
95.6
98.7
99.6
99.5
99.9
99.9
99.9
Vinyl
Chloride
78.6
99.0
99.9
99.9
69.9
93.1
98.4
99.6
90.2
99.9
99.9
99.9
.5 & 1.5 sec
Ethyl ene
87.2/27.6
98.6/99.3
99.9/99.9
99.9/99.9
78.2/91.5
93.7/97.8
98.0/99.0
99.4/99.8
97.3/99.9
99.9/99.9
99.9/99.9
99.9/99.9
The results of the Union Carbide work are presented as a series of equations. These
equations relate destruction efficiency to temperature, residence time, and flow
regime for each of 15 compounds. The efficiencies in this table were calculated
from these equations.
3Three flow regimes are presented: two-stage backmixing, complete backrrixing, and
plug flow. Two-stage backmixing is considered a reasonable approximation of actual
field units, with complete backmixing and plug flow representing the extremes.
A-16
-------
TABLE A-3. SUMMARY OF RESULTS: N0¥ DATA
/\
Company
Union Carbide
Oenka
Monsanto
Number of Sets
and/or
Number of Runs
Set 1
(6)
Set 2
(3)
Set 1
Set 2
Set 3
Unit 1
Unit 2
Outlet NO
in Flue GSs
(ppmv)
27
30
9.3
10.2
8.0
200
8
A-17
-------
that NO -outlet concentrations range from eight to 200 ppmv (0.015 to
0.37 g/m ). These values could increase by several orders of magnitude in a
poorly designed or operated unit. NO samples were obtained according to
EPA Reference Method 7. x
The maximum outlet NO concentration of 200 ppmv was measured at an
acrylonitrile plant. The $ent stream of this plant contains nitrogeneous
compounds. The NO concentrations measured at the other two plants, whose
vent streams do not contain.,nitrogeneous compounds, range from eight to
30 ppmv (0.015 to 0.056 g/mj).
A.3 COMPARISON OF TEST RESULTS AND THE TECHNICAL BASIS OF THE SOCMI
AIR OXIDATION EMISSIONS LIMIT
This section compares various test results, discusses data and findings
on incinerator efficiency, and presents the logic and the technical basis
behind the choice of the above control level.
A consideration of VOC combustion kinetics leads to the conclusion that
at 1600°F and 0.75 second residence time, mixing is the crucial design
parameter. Published literature indicates that any VOC can be oxidized to
carbon dioxide and water if held at sufficiently high temperatures in the
presence of oxygen for a sufficient time. However, the temperature at which
a given level of VOC reduction is achieved is unique for each VOC compound.
Kinetic studies indicate that there are two slow or rate-determining steps
in the oxidation of a compound. The first is the initial reaction in which
the original compound disappears. It has been determined that the initial
reaction of methane (CH.) is slower than that of any other nonhalogenated
organic compound. Kinetic calculations show that, at 1600°F, 98 percent of
the original methane will react in 0.3 seconds. Therefore, any nonhalogenated
VOC will undergo an initial reaction step within this time. After the
initial step, extremely rapid free radical reactions occur. Finally, each
carbon atom will exist as carbon monoxide (CO) before oxidation is complete.
The oxidation of CO is the second slow step. Calculations show that, at
1600°F, 98 percent of an original concentration of CO will react in
0.05 second. Therefore, 98 percent of any VOC would be expected to undergo
the initial and final slow reaction steps at 1600°F in about 0.35 second.
It is very unlikely that the intermediate free radical reactions would take
nearly as long as 0.4 seconds to convert 98 percent of the organic molecules
to CO. Therefore, from a theoretical viewpoint, any VOC should undergo
complete combustion at 1600°F in 0.75 second. The calculations on which
this conclusion is based have taken into account the low mole fractions of
VOC and oxygen which would be found in the actual system. They have also
provided for the great decrease in concentration per unit volume due to the
elevated temperature. But the calculations assume perfect mixing of the
offgas and combustion air. Mixing is therefore identified from a
theoretical viewpoint as the crucial design parameter.
The test results both indicate an achievable control level of 98 percent
at or below 1600°F and illustrate the importance of mixing. Union Carbide
results on lab-scale incinerators indicated a minimum of 98.6 percent
efficiency at 1400°F. Since lab-scale incinerators primarily differ from
field units in their excellent mixing, these results verified the theoretical
A-18
-------
calculations. The tests cited in Table A-l are documented as being conducted
on full-scale incinerators controlling offgas from air oxidation process
vents of a variety of types of plants. To focus on mixing, industrial units
were selected where all variables except mixing were held constant or
accounted for in other ways. It was then assumed any changes in efficiency
would be due to changes in mixing.
The case most directly showing the effect of mixing is that of
Petro-tex incinerator. The Petro-tex data show the efficiency changes due
to modifications on the incinerator at two times after startup. These
modifications included (1) repositioning baffles, (2) adjusting duct slots
and openings in the mixing zone to improve exit velocity, (3) installing new
dampers, baffles and perforated plates, and (4) rerouting inlet combustion
air. These modifications increased efficiency from 70 percent to over
99 percent, with no significant change in temperature.
A comparison indirectly showing the effect of mixing is that of the
Rohm and Haas test versus the Union Carbide lab test as presented in Table
A-4. These data compare the efficiency of the Rohm and Haas incinerator in
combusting four specific compounds with that of the Union Carbide lab unit.
The lab unit clearly outperforms the R&H unit. The data from both units are
based on the same temperature, residence time, and inlet stream conditions.
The more complete mixing of the lab unit is judged the cause of the
differing efficiencies. The six tests of in-place incinerators do not, of
course, cover every feedstock. However, the theoretical discussion given
above indicates that any VOC compound should be sufficiently destroyed at
1600°F. More critical than the type of VOC is the VOC concentration in the
offgas. This is true because the kinetics of combustion are not exactly
first-order at low VOC concentrations. The Petro-tex results are for a
butadiene plant, and butadiene offgas tends to be lean in VOC. Therefore,
test results support the validity of the standard for lean streams.
The EPA, Union Carbide, and Rohm and Haas tests were for residence
times greater than 0.75 second. However, theoretical calculations show that
greater efficiency would be achieved at 1600°F and 0.75 second than at the
longer residence times but lower temperatures represented in these two
tests. The data on which the standard is based are test data for similar
control systems: thermal incineration at various residence times and
temperatures. If 98 percent VOC reduction can be achieved at a lower
temperature, then according to kinetic theory it can certainly be achieved
at 1600°F, other conditions being equal.
Four tests at temperatures less than 1600°F are relied upon to support
the 98 percent reduction requirement.
A-19
-------
TABLE A-4. RESULT COMPARISONS OF LAB INCINERATOR vs. ROHM & HAAS
INCINERATOR3
Rohm & Haas Incinerator Union Carbide Lab Incinerator
Compound
Propane
Propylene
Ethane
Ethyl ene
TOTAL
Inlet
(Ibs/hr)
900
1800b
10
30
2740
Outlet
(Ibs/hr)
150
150b
375
190
865
Inlet
(Ibs/hr)
71.4
142.9
0.8
2.4
217.5
Outlet
(Ibs/hr)
0.64
5.6
3.9
3.4
13.54
% VOC Destruction: 68.4% 93.8%
aTable shows the destruction efficiency of the four listed compounds for the
Rohm & Haas (R&H) field and Union Carbide (UC) lab incinerators. The R&H
results are measured'; the UC results are calculated. Both sets of results
are based on 1425 F combustion temperature and one second residence time.
In addition, the UC results are based on complete backmixing and a four-step
combustion sequence consisting of propane to propylene to ethane to ethylene
to CO- and H^O. These last two items are worst case assumptions.
Are not actual values. Actual values are confidential. Calculations with
actual values give similar results.
A-20
-------
A.4 REFERENCES FOR APPENDIX A
1. Mascone, D.C., EPA, Draft memorandum concerning incinerator efficiency,
April 25, 1980.
2. Letter from Towe, R., Petro-Tex Chemical Corporation, to Farmer, J.,
EPA, August 15, 1979.
3. Broz, L.D. and Pruessner, R.D., "Hydrocarbon Emission Reduction Systems
Utilized By Petro-Tex," paper presented at 83rd National Meeting of
AIChE, 9th Petrochemical and Refining Exposition, Houston, Texas,
March 1977.
4. Letter from Lawrence, A., (Coppers Company, Inc., to Goodwin, D., EPA,
January 17, 1979.
5. Letter from Weishaar, M., Monsanto Chemical Intermediates Co., to
Farmer, J., EPA, November 8, 1979.
6. Maxwell, W., and Scheil, G., "Stationary Source Testing Of A Maleic
Anhydride Plant At The Denka Chemical Corporation, Houston, Texas," EPA
Contract No. 68-02-2814, March, 1978.
7. Blackburn, J., Emission Control Options For The Synthetic Organic
Chemicals Manufacturing Industry, Trip Report,
EPA Contract No. 68-02-2577, November 1977.
8. Scheil, G., Emission Control Options for The Synthetic Organic Chemicals
Manufacturing Idustry, Trip report, EPA Contract No. 68-02-2577,
November 1977.
9. Lee, K., Hansen, J., and Macauley, D.," Thermal Oxidation Kinetics Of
Selected Organic Compounds," paper presented at the 71st Annual Meeting
of the APCA, Houston, Texas, June 1978.
A-21
-------
APPENDIX B: STATISTICAL ANALYSIS
-------
APPENDIX B: STATISTICAL ANALYSIS
B.I INTRODUCTION
The purpose of this appendix is to describe the methods of statistical
analysis used in the development of the control techniques guideline (CTG)
document for the air oxidation unit process segment of SOCMI. The method of
regulatory analysis developed for this CTG uses a national statistical pro-
file, representing the air oxidation segment of SOCMI to project the energy,
cost, and environmental impacts associated with VOC control using reasonably
available control technology (RACT).
B.2 STATISTICAL IMPACT ANALYSIS
Typically, a CTG would be developed on a chemical-by-chemical basis.
Because the processes used by a single chemical-producing industry to manu-
facture a specific product do not differ greatly, it is possible to design a
model plant that can be used to represent the emissions and control device
requirements of typical existing sources covered in the CTG. This model,
along with knowledge of the existing population of sources, would be used to
determine the environmental, energy, and cost impacts associated with RACT.
Air oxidation facilities, however, use 36 types of oxidation processes
(23 principal processes and 13 specialty processes) to manufacture 36
different organic chemicals. Because of the number and diversity of
facilities and processes in the air oxidation industry, a chemical-by-
chemical development of CTG's would require large amounts of time, effort,
and money. The unit process approach, on the other hand, allows development
of a CTG that provides for RACT development for VOC emissions from all SOCMI
air oxidation processes. This unit process approach allows the resource-
efficient statistical estimation of the RACT impacts for VOC emissions
control from all air oxidation processes.
In the unit process approach, no model plants are used for impact
analysis. Rather, the information concerning existing air oxidation
facilities is analyzed statistically and used to construct a national
profile. This national profile replaces the traditional model plant and can
be considered a statistical model of SOCMI air oxidation processes and
facilities. The national profile characterizes air oxidation processes
according to national distributions of key variables (e.g., waste gas stream
flow, heating value, and VOC content) that can be used to determine VOC
emissions and the cost and energy impacts associated with RACT. RACT is
therefore recommended as a percent VOC emission reduction based on thermal
oxidation as the single control technique. The RACT impacts are evaluated
as impacts upon the entire population of affected facilities.
B.2.1 National Statistical Profile Construction
The overall success of the statistical analysis depends on the
availability of an adequate sample size and dependable data. Thirty-six
chemicals are produced by air oxidation processes nationwide. The results
of the EPA Houdry Questionnaires contain data on 13 chemicals. These data
consist of emission and production factors for 59 chemical plants,
representing .36 percent of the total population. These results, alcng with
B-l
-------
the physical properties of the chemicals involved, form the basis of the
analysis. Table B-l lists the chemicals that are included in the data base.
As noted, the data base for CTG analysis has been derived from EPA
Houdry Questionnaires. The Houdry Division of Air Products and Chemicals,
Inc., conducted an extensive survey of the petrochemical industry to provide
data for EPA to use in their fulfillment of their obligations under the
terms of the Clean Air Amendments of 1970. The scope of that study included
most petrochemicals which fell into one or more of the classifications of
(1) large production, (2) high growth rate, and (3) significant air pollu-
tion. The information sought included industry descriptions, air emission
control problems, sources of air emissions, statistics on quantities and
types of emissions, and descriptions of emission control devices then in
use. The principal source for that data was the industry questionnaire
current as of 1972. The data base was updated in 1979.
Table B-2 shows the actual data base used to construct the national
statistical profile. Twenty-three different processes are represented in
the data set. Due to the wide variation in processes used and in the types
of control devices present across the air oxidation industry, only
uncontrolled emission factors and vent stream characteristics are included
in the data set. Since uncontrolled emissions are subject to the greatest
uncertainty because of the difficulty in defining what is a pollution
control device, all stream data represent the process stream exiting the
primary product recovery device. Figure B-l shows the reference point for
data collection within the air oxidation process. Since many air oxidation
facilities may have additional control equipment in place, these data are
overstated estimates of the current emission factors. Table B-3 shows the
air oxidation offgas components specific to each chemical represented in the
data base. Table B-4 shows the data vectors contained in the national
statistical profile. Tables B-5 and B-6 show tabular representations of the
vector distribution.
B.2.2 Data Reliability
From the Houdry data, two assumptions must be made regarding the Houdry
data reliability for this CTG analysis. First, the data contain a bias
toward large-volume chemicals or those chemicals with significant air pollu-
tion. This is not considered to be a serious drawback to the CTG analysis.
Second, because the chemical industry as a whole is dynamic, the age of the
Houdry data presented a second source of bias. In a study prepared for the
Chemical Manufacturers Association (CMA), the 1972 Houdry data (updated in
1979) were compared to a 1980 data base developed from recent industry
contacts. Twenty-two plants are represented in both the CMA data base and
the data base used for this CTG analysis. Emission factors were calculated
for each data vector representing a plant for which data exist in both data
bases. Two sets of 22 emission factors each, one set for each data base,
were thereby obtained. These two sets were statistically compared using the
Wilcoxon signed-rank procedure. The results of the Wilcoxon signed-rank
procedure to test the significance of the differences between the overlapping
portions of the two data bases show that the differences are not significant
at the 0.05 level.
B-2
-------
TABLE B-l. LIST OF CHEMICALS FOR WHICH DATA HAVE BEEN OBTAINED
Ethylene Oxide
Hydrogen Cyanide
Acetic Acid
Acetaldehyde
Phthalic Anhydride
Dimethyl Terephthalate
Phenol
Ethylene Dichloride
Acrylonitrile
Cyclohexanone
Terephthalic Acid
Maleic Anhydride
Formaldehyde
B-3
-------
TABLE B-2. ACTUAL DATA BASE USED TO CONSTRUCT NATIONAL STATISTICAL PROFILE
Company
Location
Process
Rohm & Haas
Badische
Badische
Nipro
Clark
Dow
Georgia Pacific
Monsanto
Shell
USS
DuPont
DuPont
Eastman
Amoco/Standard
Exxon
Monsanto
Stepan
Conoco
Diamond Shamrock
Dow
Ethyl
Goodrich
ICI
Shell
Stauffer
Vulcan
Dow
Koch
ucc
PPG
Eastman
American Cyanamid
DuPont
Monsanto
Vistron
Denka
Monsanto
Koppers
Reichhold
Reichhold
Deer Park, TX
Freeport, TX
Freeport, TX
Augusta, GA
Blue Island, IL
Oyster Creek, TX
Plaquemine, LA
Choc. Bayou, TX
Deer Park, TX
Haverhill, OH
Wilmington, NC
Old Hickory, TN
Kingsport, TN
Decatur, AL
Baton Rouge, LA
Texas City, TX
Millsdale, IL
Covenant, LA
Deer Park, TX
Freeport, TX
Baton Rouge, LA
Calvert City, KY
Baton Rouge, LA
Deer Park, TX
Long Beach, CA
Grismar, LA
Freeport, TX
Orange, TX
Seadrift, TX
Beaumont, TX
Longview, TX
New Orleans, LA
Beaumont, TX
Alvin, TX
Lima, OH
Houston, TX
St. Louis, MO
Bridgeville, PA
Morris, IL
Elizabeth, NJ
Methane/Ammonia Oxidation
Cyclohexane Oxidation
Cyclohexane Oxidation
Cyclohexane Oxidation
Cumene Hydroperoxidation
Cumene Hydroperoxidation
Cumene Hydroperoxidation
Cumene Hydroperoxidation
Cumene Hydroperoxidation
Cumene Hydroperoxidation
DMT p-Xylene Oxidation
DMT p-Xylene Oxidation
TPA p-Xylene Oxidation
TPA p-Xylene Oxidation
o-Xylene Oxidation
o-Xylene Oxidation
o-Xylene Oxidation
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
Oxychlori
Oxychlori
Oxychlori
Oxychlori
Oxychlori
Oxychlori
Oxychlori
Oxychlori
Oxychlori
nation
nation
nation
nation
nation
nation
nation
nation
nation
Ethylene Oxidation I
Ethylene Oxidation I
Ethylene Oxidation I
Ethylene Oxidation I
Ethylene Oxidation II
Propylene Ammoxidation
Propylene Ammoxidation
Propylene Ammoxidation
Propylene Ammoxidation
Benzene Oxidation
Benzene Oxidation
Benzene Oxidation
Benzene Oxidation
Benzene Oxidation
B-4
-------
TABLE B-2 (Concluded). ACTUAL DATA BASE USED TO CONSTRUCT
NATIONAL STATISTICAL PROFILE
Company
Location
Process
Tenneco
USS
USS
UCC
Gulf
Reichhold
GAP
Reichhold
Borden
Celanese
DuPont
Georgia Pacific
Monsanto
Georgia Pacific
Hercules
Reichhold
Tenneco
Eastman
Fords, NJ
Neville Island, PA
Neville Island, PA
Charleston, WV
Vicksburg, MS
Houston, TX
Calvert City, KY
Moncure, NC
Fayetteville, NC
Bishop, TX
Belle, WV
Vienna, GA
Choc. Bayou, TX
Crossett, AR
Wilmington, NC
Kansas City, KS
Garfield, NJ
Kingsport, TN
Benzene Oxidation
Benzene Oxidation
Naphthalene Oxidation
Naphthalene Oxidation
Methanol Oxidation I
Methanol Oxidation I
Methanol Oxidation I
Methanol Oxidation I
Methanol Oxidation II
Methanol Oxidation II
Methanol Oxidation II
Methanol Oxidation II
Methanol Oxidation II
Methanol Oxidation II
Methanol Oxidation II
Methanol Oxidation II
Methanol Oxidation II
Acetaldehyde Oxidation
B-5
-------
D3
I
CTl
Riaclaals,
Catalysis
A
B-
1 Ail Oxidation Process
REACTOR
T«
T
Ealssioii Pobl
~1
fRIMAHV
PAGDUCT
necovcav
Cradc Pie&cl
Spent Calalytlt
Pioducli
I
J
T*
Figure B-l. General Air-Oxidation Process.
-------
TABLE B-3. AIR OXIDATION OFFGAS COMPONENTS
ACRYLONITRILE
CYCLOHEXANONE
Nitrogen
Oxygen
Carbon Dioxide
Carbon Monoxide
Water (vapor)
Ammonia*
Methane
Ethane
Ethylene
Propane
Propylene*
Acetaldehyde
Acetone (vapor)
Acrolein (propenal) (vapor)
Hydrogen Cyanide
Acrylonitrile (vapor)*
Acetonitrile (vapor)
HYDROGEN CYANIDE
"Air"
Hydrogen Cyanide*
Nitrogen
Carbon Monoxide
Cyclohexane (vapor)*
Cyclohexanol (vapor)
Cyclohexanone (vapor)*
"Unknown Organics (C2+)"
ACETALDEHYDE
Nitrogen
Oxygen
Carbon Dioxide
Carbon Monoxide
Water (vapor)
Hydrogen
Methane
Methyl Chloride
Ethyl Chloride
Ethanol (vapor)*
Acetic Acid (vapor)
Acetaldehyde (vapor)*
Argon
ACETIC ACID
ACETIC ANHYDRIDE
Nitrogen
Oxygen
Carbon Dioxide
Water (vapor)
Carbon Monoxide*
Nitrogen
Oxygen
Carbon Dioxide
Carbon Monoxide
Hydrogen
B-7
-------
TABLE B-3 (Continued). AIR OXIDATION OFFGAS COMPONENTS
Argon
Hydrogen
Methane
Ethane
Butane*
"C2+ Hydrocarbons"
Methyl Iodide
Ethanol*
Acetaldehyde*
Methyl Acetate
Ethyl Acetate
Methane
Ethane
Ethylene
Propane
Propadiene
Acetic Acid (vapor)*
Diketene (vapor) "(CH2=C=0)2"
Acetic Anhydride (vapor)*
MALEIC ANHYDRIDE
Nitrogen
Oxygen
Carbon Dioxide
Water (vapor)
Carbon Monoxide
Formaldehyde
Formic Acid (vapor)
Maleic Acid (vapor)
Maleic Anhydride (vapor*)
Benzene (vapor)*
Xylene (vapor)
"Other Organics (Est. Mol. Wt. 50)"
PHTHALIC ANHYDRIDE
PHENOL
Nitrogen
Oxygen
Water (vapor)
Carbon Monoxide
Nitrogen
Oxygen
Water (vapor)
Carbon Dioxide
B-8
-------
TABLE B-3 (Continued). AIR OXIDATION OFFGAS COMPONENTS
PHTHALIC ANHYDRIDE PHENOL
Carbon Dioxide Sodium Carbonate (particulate)
Argon Formaldehyde
Sulfur Dioxide* Acetaldehyde
Inorganic Salts (Magnesium and Calcium Acetone (vapor)
Carbonates) (particulate) AcetQne (yapor)
"Hydrocarbons" Mesityl Qxide
Maleic Acid (vapor) (4-Methyl-3-Penten-2-One)
Maleic Anhydride (vapor) (vapor)
Benzoic Acid (vapor) Benzene (vapor)
Phthalic Anhydride* Phenol (vapor)*
1,2-Naphthoquinone (particulate, vapor) Cumene (vapor)*
Cumene Hydroperoxide (vapor)
a-Methyl Styrene (vapor)
a,a-Dimethyl Benzyl Alcohol
(2»Phenyl-2-Propanol) (vapor)
Acetophenone
Other Organics", "Oxidized
Organics (various)" (vapor)
TEREPHTHALIC ACID & DIMETHYL TEREPHTHALATE
Nitrogen
Oxygen
Water (vapor)
Carbon Dioxide ETHYLENE OXIDE
Carbon Monoxide
Methane Nitrogen
Methanol* Oxygen
Dimethyl Ether Carbon Dioxide
Methyl Ethyl Ketone (vapor)* "Oxides of Nitrogen"
B-9
-------
TABLE B-3 (Concluded). AIR OXIDATION OFFGAS COMPONENTS
TEREPHTHALIC ACID & DIMETHYL TEREPHTHALATE ETHYLENE OXIDE
Methyl Acetate (vapor)
Acetic Acid (vapor)*
Acetaldehyde*
p-Xylene (vapor)*
Argon
Methane
Ethane
Ethylene*
Ethylene Oxide*
"Particulate (Primarily
Carbon, small amounts of
Iron, Chlorine)
*Product or Feedstock
B-10
-------
TABLE B-4. DISTRIBUTION OF NATIONAL STATISTICAL PROFILE DATA VECTORS
Plant 10 Number
1303
1305
1306
1307
1601
205
2301
2302
2303
2305
2308
5101
5102
5103
5104
102
1004
1007
2203
2204
2205
2206
2207
2208
902
903
904
1001
1005
1801
1802
1803
1804
1805
1806
1807
1403
1404
1407
1408
1409
1410
1411
1418
1416
1421
1423
1422
1420
1601
5202
5203
5204
5205
5206
5207
5208
5209
5201
Hourly Emissions (kg/hr)
326
666
115
2.12
55.0
75.0
117
203
617
340
219
1370
2150
895
1210
13.7
323
223
155
26.4
27.9
36.0
13.7
14.6
30.2
103
407
78.7
188
529
211
205
136
14.1
135
355
15.1
20.3
33.7
14.6
0.0250
15.8
357
0.0205
39.6
16.0
19.5
23.3
31.4
0.217
30.2
433
348
228
125
464
371
78.9
616
Net Nesting Value (MJ/Nm3)
0.635
1.13
0.535
0.001
3.55
0.251
0.150
0.154
0.099
0.097
0.157
1.12
1.71
0.781
0.725
0.010
0.289
0.165
0.233
0.067
0.070
0.093
0.070
0.117
0.472
0.465
1.63
0.393
0.153
0.419
0.360
0.415
0.483
0.220
0.359
0.808
2.32
2.63
2.82
2.72
2.95
2.71
3.05
2.56
0.114
0.148
0.148
0.321
2.76
1.83
0.807
2.13
2.84
2.15
0.775
0.825
0.825
0.825
B-ll 4'56
Offgas Flowrate (Nmj/min)
430
493
181
2830
1520
142
736
1130
3310
2150
1230
1330
1280
1420
1950
340
1420
527
481
425
289
215
142
90.6
170
170
235
1530
912
2110
1250
1190
481
1220
850
566
22.7
67.9
56.6
70.8
31.1
161
510
25.5
164
110
110
93.4
56.6
184
170
113
201
603
133
283
226
48.1
269
-------
TABLE B-5. JOINT DISTRIBUTION OF FLOW AND MASS EMISSIONS IN NATIONAL STATISTICAL PROFILE
Hourly Emissions (E) kg/hr
Offgas^Flow (W)
Nnr/min
14
-------
TABLE B-6. JOINT DISTRIBUTION OF DESIGN CATEGORIES AND MASS EMISSIONS IN NATIONAL STATISTICAL PROFILE
Category
Net
Heating
Value
MJ/ifcn3
Hourly Emissions (E) kg/hr
E<5 5
-------
B.2.3 National Statistical Profile Use
The actual use of the national statistical profile assumes that the
distribution of offgas flow, mass emissions, and stream heating value is
chemical independent. Chemical identities are not considered in the
profile, nor is there claimed to be a one-to-one correspondence between any.
one data vector and an existing offgas stream. It is assumed, however, that
the overall proportions and distributions of the parameter values and data
vectors are similar to those of the existing population of air oxidation
facilities. Thus, since the national statistical profile contains 59 data
vectors, each data vector and associated impacts of pollution control
represents 1/59 of the existing population to be analyzed for control.
B.2.4 Calculation of Baseline Control Level1
As mentioned earlier, the data base was constructed from uncontrolled
emission sources. ' However, some control is currently being applied to the
sources as required by current State Implementation Plans (SIP's) or other
regulations. In order to modify the collection of data vectors to account
for existing control, an analysis of the SIP requirements and an adjustment
of the profile is required.
A weighted average of current control requirements appears to provide
the closest approximation of current VOC control levels. The baseline
analysis assumes that the statistical profile of data vectors adequately
represents the population of existing air oxidation processes within each
State. An annual emission value was calculated for each data vector from
its hourly emission value. These values were summed to give a total annual
emission value for the profile. Each data vector was analyzed in order to
estimate whether a plant with such offgas characteristics would be required
to reduce VOC emissions by a given SIP. For each data vector determined to
be subject to SIP control, the annual emission reduction under SIP was
calculated. The total annual emission reduction associated with the given
SIP was calculated as the sum of these individual vector values. This
emission reduction value was divided by the total emission value for the
profile. The result was an estimated percent reduction of emissions for a
given State. The national baseline was then calculated as a weighted
average of the baselines for each State. In calculating the national
weighted average, each individual State baseline control value was weighted
by the estimated percent of nationwide nonattainment area emissions from
nonattainment areas located within the respective State. For each existing
facility located in a nonattainment area, the plant capacity was multiplied
by the appropriate emission factor from Appendix D. The resulting plant
emission estimates were summed according to State, and percentages
calculated for each State to give the weighting factors. Analysis shows
that the estimated baseline control level attributable to the existing SIP's
is 58 percent. Consequently, a 58 percent VOC reduction from the uncon-
trolled level is used as the baseline level for analysis of the RACT impacts,
B-14
-------
B.3 REFERENCES FOR APPENDIX B
1. Memo from Galloway, J., EEA, to SOCMI Air Oxidation File.
July 29, 1981. Calculation of baseline emissions.
B-15
-------
APPENDIX C: EMISSION FACTORS
-------
APPENDIX C: EMISSION FACTORS
The following emission factors and sample calculations are included to
form a basis for the verification of VOC emission inventories developed from
emission source tests, plant site visits, permit applications, etc. These
factors and procedures should not be applied in cases where site-specific
data are available, but rather in instances where specific plant information
is lacking or highly suspect.
C.I VOC EMISSION FACTORS FOR EXISTING EQUIPMENT
Table C-l contains selected emission factors for each SOCMI air oxidation
chemical process being considered. To provide uniformity across the
various processes and to account for the differences in vent streams inherent
among the processes, a general emission point common to all processes was
selected.
Several criteria were used when selecting the point or points in any
given process at which VOC emissions data would be gathered and incorporated
into development of the emission factor. The data were generated primarily
from the point at which the bulk of the N? from the air used in the reaction
was vented to the atmosphere. The relevant point was prior to any combustion
device and downstream from any other product recovery or emission control
device.
Typical annual VOC emissions for four selected processes employing
existing and reasonably available control technology (RACT) equipment are
given in Table C-2.
C.2 PRECAUTIONS TO BE CONSIDERED WHEN UTILIZING EMISSION FACTORS
C.2.1 Extreme Range of Some Emission Factors
In some cases, plants using a given process reported widely differing
emission factors. Such extreme ranges indicate emission variability inherent
to a process and/or inaccurate data. Emission estimations derived from an
average of such a range of emission factors may differ significantly from
the actual emissions of any given plant.
C.2.2 Cost-Effectiveness Cutoff with Respect to RACT Equipment
RACT would not involve reduction of the vent stream VOC concentration
by 98 percent or to 20 ppm if the total resource effectiveness (TRE) index
value (described in Appendix E) of the process vent stream is above 1.0.
The selection of this level was based on the overall resource use required
to destroy a unit amount of process vent stream VOC using thermal oxidation.
All resources which are expected to be used in VOC control by thermal
oxidation are taken into account. The primary resources used are capital
and supplementary energy. The total resource effectiveness index is derived
and specifically defined in Chapter 5, "Cost Analysis." The TRE index value
of a facility is based on the characteristics of the offgas from the final
piece of product recovery equipment. Therefore, the use of a cutoff TRE
index level is meant to encourage the use of product recovery techniques or
process modifications to reduce emissions. A plant could add product
C-l
-------
TABLE C-l. VOC EMISSION FACTORS FOR SOCMI CHEMICALS (AIR OXIDATION PROCESSES)
Chemical (Process)
Acetaldehyde (Wacker)
Acetaldahyde (ethanol)
Acetic Acid (Wacker)
Acetic Acid (butane)
Acetone (Hercules cumene)
Acetone (Allied cumene)
Acryl 1c Acid
Acrylonitrile (Propene ammoxidation)
Anthraquinone
Benzaidahyde
Benzoic Acid
1 ,3-8utadiene
p-t-Butyl Benzole Acid
n-Butyric Acid
Crotonic Acid
Cyclohexanol
Dimethyl Terephthalate/Terephthalic
Acid
Ethylene Dlchloride
Ethyl ene Oxide
Formaldehyde (metal oxide)
Formaldehyde (silver catalyst)
Glyoxal
Hydrogen Cyanide
Isobutyric Acid
Isophthalic Acid
Maleic Anhydride (benzene)
Maleic Anhydride (butane)
Phthalic Anhydride (xylene)
Phthalic Anhydride (naphthalene)
Propionic Acid (propionaldehyde)
Propylene Oxide (ethyl benzene)
Number of
Data Points
Considered
2
1
4
1
3
5
3
6
0
0
1
2
0
1
0
5
6
n
6
6
11
0
2
1
2
9
1
3
2
1
3
... _ , kg VOC Emitted\
Mg Product
Selected
Range Value
0.6 to 2.3 1.4
Only one reported value .02
7 to 16 11
Only one reported value 7.0
2 to 6 3.7
3 to 20 10
90 to 200 120
98 to 210 110
Insufficient information available
Insufficient information available
Only one reported value 2.0
1.7 to 5 3.3
Insufficient information available
Only one reported value .5
Insufficient information available
10 to 52 38
2.4 to 15 10
6 to 36 12
33 to 79a 48
3 to 34 3
3 to 22b 6.5
Insufficient information available
6 to 8 7
Only one reported value 55
2 to 19 11
12 to 230 93
Only one reported value 19
76 to 92 35
25 to 34 30
Only one reported value 6
.2 to .7 .5
aOne stream with reported VOC precent below detection limits not incorporated 1n range.
bTwo streams with reported VOC percent below detection limits not incorporated 1n range.
C-2
-------
TABLE C-2. TYPICAL ANNUAL VOC EMISSIONS FOR FOUR SELECTED PROCESSES EMPLOYING EXISTING
AND RACT EQUIPMENT
F
Type of Plant (
Small Formaldehyde
Large Formaldehyde
o
co Small Ethyl ene
Dichloride
Large Ethyl ene
Dichloride
P1 . Emission Factor In kg VOC Average VOC Emissions
'rnrfurtinn Emitted/Mg Product in Gg/yr (Ib/yr)
lUUUUllull
Gg/yr Existing
mm Ib/yr) Equipment
16 6.5
(36)
144 6.5
(318)
45.4 12
(100)
300 12
(660)
RACT Existing
Equipment Equipment
0.13 0
(2
0.13 0
(2
0.24 0
(1
-
0.24 3
(7
.10
.3 x 105)
.95
.1 x 106)
.54
.2 x 106)
.6
.9 x 106)
RACT
Equipmen
2.
(4.
1.
(4.
1.
(2.
7.
(1.
1 x
6 x
9 x
1 x
1 x
4 x
3 x
6 x
10
10
10
10
10
/
F
i
t 1
-3
3>
-2
4)
104)
10
10
0
-£.
6)
Uinual VOC Emission
(eductions Resulting
From RACT Implementa-
tion in Gg/yr (Ib/yr)
0.
(2.
0.
(2.
0.
(1.
3.
(7.
10
3 x
95
1 x
54
2 x
5
7 x
105)
106)
106)
106)
-------
recovery equipment, and thereby be transferred to the RACT category of no
further control, by exceeding the TRE cutoff. It is therefore erroneous to
assume that RACT equipment will reduce by 98 percent VOC emissions in all
plants affected by the CTG.
C.3 VOC EMISSION FACTORS AS APPLIED TO EXAMPLE PROCESSES
C.3.1 Sample Calculation, Hydrogen Cyanide Plant
C.3.1.1 Existing Equipment
Existing Equipment Gg Product _ Mg VOC Emitted/yr by
Emission Factor (kg/Mg) x Produced/yr Existing Equipment
(7) x (52.6 Gg/yr) = 368 Mg VOC Emitted by Existing Equipment/yr
C.3.1.2 RACT Equipment
(Existing Equipment Emission Factor (kg/Mg)) x Weight % VOC Emissions
Expected to Remain After RACT Equipment = RACT Equipment Emission
Factor (kg/Mg)
(7) x (.02) = .14
RACT Equipment Emission Factor (kg/Mg) x Gg Product Produced/yr
= Mg VOC Emitted/yr by RACT Equipment
(.14) x (52.6 Gg/yr) = 7.36 Mg VOC Emitted/yr by RACT Equipment
C.3.2 Plant VOC Emission Reduction Efficiency, Hydrogen Cyanide Plant
C.3.2.1 Total Annual Plant VOC Emission Reduction
Total Annual Emissions _ Total Annual Emissions _ Total Annual Emission
from Existing Equipment from RACT Equipment Reduction
368 Mg VOC/yr - 7.36 Mg VOC/yr = 361 Mg VOC/yr
C.3.2.2 Percent Reduction in Total Plant VOC Emissions
Total Annual Emission * Total Annual Emissions _ % Reduction in Total
Reduction from Existing Equipment Plant VOC Emissions
(361 Mg VOC/yr) v (368 Mg VOC/yr) = 98% Reduction in Total Plant VOC
Emissions
C-4
-------
C.4 REFERENCES FOR APPENDIX C
1. Memo from Galloway, J., EEA, to SOCMI Air Oxidation File,
July 29, 1981. Calculation of baseline emissions level.
C-5
-------
APPENDIX D: RACT CALCULATIONS
-------
APPENDIX D: RACT CALCULATIONS
D.I INTRODUCTION
This appendix presents calculations and derivations related to the
definition and implementation of the recommended RACT (from this point on
the recommended RACT is simply referred to as RACT).
D.2 TOTAL RESOURCE EFFECTIVENESS
RACT is based on incineration of certain process vent streams
discharged to the atmosphere. The streams for which RACT involves this VOC
reduction are those for which the associated total resource effectiveness
(TRE) index value is less than 1.0. Thermal oxidation can reduce VOC
emissions by 98 weight percent or to 20 ppm (volume, by compound), whichever
is less stringent. An index value of TRE can be associated with each air
oxidation vent stream for which the offgas characteristics of flowrate,
hourly emissions and net heating value are known. For facilities with a
process vent stream or combination of process vent streams having a TRE
index value which exceeds the cutoff level of 1.0, the removal of VOC using
thermal incineration is not required.
TRE is a measure of the supplemental total resource requirement per
unit VOC reduction, associated with VOC control by thermal oxidation. All
resources which are expected to be used in VOC control by thermal oxidation
are taken into account in the TRE index. The primary resources used are
supplemental natural gas, capital, and (for offgas containing halogenated
compounds) caustic. Other resources used include labor, electricity, and
(for offgas containing halogenated compounds) scrubbing and quench makeup
water.
The TRE index is derived from the cost effectiveness associated with
VOC control by thermal oxidation. The calculation of cost effectiveness and
derivation of the TRE index are given in detail in Chapter 5. The TRE index
of a vent stream is defined as the cost-effectiveness value of the stream,
divided by a cost-effectiveness value of $l,600/Mg. The TRE index is a
convenient, dimensionless measure of the total resource burden associated
D-l
-------
with VOC control at a facility. It is independent of the general irrlation
rate. However, it does assume fixed relative costs of the various resources,
such as carbon steel and electricity.
States may choose to establish a cost-effectiveness cutoff different
from the $l,600/Mg cutoff recommended in this CTG. Even if a State were to
establish a different cost-effectiveness cutoff, the existing TRE equation
and coefficients could still be used provided that a correction factor is
applied. The correction factor would be equal to the existing TRE index
multiplied by $l,600/Mg and divided by the desired cost-effectiveness
cutoff.
The distinction.in RACT, between facilities with a TRE index value
above the cutoff level and those with a value below it, encourages the use
of product recovery techniques or process modifications to reduce emissions.
The values of offgas flowrate, hourly emissions, and net heating value used
to calculate the TRE value for a given facility are measured at the outlet
of the final product recovery device. Use of -additional product recovery is
expected to decrease VOC emissions and increase the total resource effective-
ness associated with thermal incineration of a vent stream.
The TRE index cutoff level associated with RACT has the value 1.0. The
TRE index of a process vent stream is calculated according to the following
equation:
TRE = 77 [a + b(FLOW)0'88 + c(FLOW) + d(FLOW)(HT) + e(FLOW°'88)(HT0-88) +
n.t. n r I
f (FLOW)U'b]
where:
TRE = Total resource effectiveness index value.
FLOW = Vent stream flowrate (scm/min), at a standard temperature of
20°C.*,**
HT = Vent stream net heating value (MJ/scm), where the net enthalpy
of per mole of offgas is based on combustion at 25°C and
760 mm Hg, but the standard temperature for determining the
*See Appendix H for reference methods and procedures.
**For a Category E stream, Flow should be replaced by "Flow x HT/3.6" when
•associated with the f coefficient.
D-2
-------
volume corresponding to one mole is 20°C, as in the definition
of FLOW.*
H.E. = Hourly emissions reported in kg/hr measured at full
operating flowrate.*
a.» Ib, £, <^, e_, and i_ are coefficients. The set of coefficients which
apply to a process vent stream can be obtained from Table D-l.
Table D-l is divided into the six design categories for control
equipment. These design categories differ in the amount of heat recovery
achieved, in the type of heat recovery equipment used, and in the use of
flue gas scrubbing for offgas containing chlorinated compounds. The amount
and type of heat recovery used depends upon the offgas heating value. These
design categories are defined and discussed in detail in Chapter 5. Under
each design category listed in Table D-l, there are several intervals of
offgas 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 smaller than that 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 one, 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 offgas flowrate for
each design category are presented and discussed in Chapter 5.
D.2.1 Derivation of the TRE Coefficients
The Total Resource Effectiveness (TRE) of an offgas stream is defined
as the cost effectiveness of incinerating the VOC stream under consideration
divided by the reference cost effectiveness ($l,600/Mg). The cost effective-
ness of treating an offgas stream is determined by developing equations for
the various annual cost components of the incineration system. These
components include annualized capital costs, supplemental gas costs, labor
costs, electricity costs, quench water costs, scrub water costs, neutraliza-
tion costs, and heat recovery credit. The development of each of the cost
component equations is summarized in Table D-2.
*See Appendix H for reference methods and procedures.
D-3
-------
TABLE D-l. COEFFICIENTS OF THE TOTAL RESOURCE-EFFECTIVENESS (TRE) INDEX EQUATION
Al. FOR CHLORINATED PROCESS VENT STREAMS, IF 0 < NET HEATING VALUE (MJ/scm) < 3.5:
W = Vent Stream Flowrate (scm/min) a b c d e f
W < 13.5
13.5 < W < 700
700 < W < 1400
1400 < W < 2100
2100 < W < 2800
2800 < W < 3500
48.73
42.35
84.38
126.41
168.44
210.47
0
0.624
0.678
0.712
0.747
0.758
0.404
0.404.
0.404
0.404
0.404
0.404
-0.1632
-0.1632
-0.1632
-0.1632
-0.1632
-0.1632
0
0
0
0
0
0
0
0.0245
0.0346
0.0424
0.0490
0.0548
A2. FOR CHLORINATED PROCESS VENT STREAMS, IF 3.5 < NET HEATING VALUE (MJ/scm):
W - Vent Strean Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 700
700 < W < 1400
1400 < W < 2100
2100 < W < 2800
2800 < W < 3500
47.76
41.58
82.84
123.10
165.36
206.62
0
0.605
0.658
0.691
0.715
0.734
-0.292
-0.292
-0.292
-0.292
-0.292
-0.292
0
0
0
0
0
0
0
0
0
0
0
0
0
0.0245
0.0346
0.0424
0.0490
0.0548
B. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 0 <. NET HEATING VALUE (MJ/scm) < 0.48:
W Vent Stream Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1350
1350 < W < 2700
2700 < W < 4050
19.05
16.61
32.91
49.21
0
0.239
0.260
0.273
0.113
0.113
0.113
0.113
-0.214
-0.214
-0.214
-0.214
0
0
0
0
0
0.0245
0.0346
0.0424
C. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 0.48 < NET HEATING VALUE (MJ/scm) < 1.9:
W Vent Stream Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1350
1350 < W < 2700
2700 < W < 4050
19.74
18.30
36.28
54.26
0
0.138
0.150
0.158
0.400
0.400
0.400
0.400
-0.202
-0.202
-0.202
-0.202
0
0
0
0
0
0.0245
0.0346
0.0424
D. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 1.9 < NET HEATING VALUE (MJ/scm) < 3.6:
w = Vent Stream Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1190
1190 < W < 2380
2380 < W < 3570
15.24
13.63
26.95
40.27
0
0.157
0.171
0.179
0.033
0.033
0.033
0.033
0
0
0
0
0
0
0
0
0
0.0245
0.0346
0.0424
E. FOR NONCHLORINATED PROCESS VENT STREAMS, IF 3.6 < NET HEATING VALUE (MJ/scm):
W = Dilution Flowrate (scm/min) a b c
W < 13.5
13.5 < W < 1190
1190 < W < 2380
2380 < W < 3570
15.24
13.63
26.95
40.27
0
0
0
0
0
0
0
0
0.0090
0.0090
0.0090
0.0090
0
0.0503
0.0546
0.0573
0
0.0245
0.0346
0.0424
D-4
-------
TABLE D-2. MATHEMATICAL FORMULATION OF ANNUAL INCINERATOR COST COMPONENTS
Component
Annualized Cost (10J$/yr)
la. Annualized Capital (number of equipment units) x (escalation factor)
Cost, Taxes, Insurance, x (capital recovery factor + taxes, insurance, and
and Maintenance
Ib. Pipe Rack
Ic. Additional Ductwork
2. Supplemental Natural
Gas
maintenance factor) x (capital cost per unit)
= [N x 1.056 x 1.625flx (0.163 + 0.10) x (C, +
C2(Flow/N/0.95)°-88)] l
[(pipe rack length) x (cost per unit length) x
(installation factor) x (escalation factor) x (retrofit
correction factor) x (capital recovery factor + taxes,
insurance and maintenance factor)]
= 250 [ft.] x 32.045 [$/ft.] x 1.0873 x 0.928 x 1-.625
0.263 v 1000 $/103$
= 13.14 x 0.263
= 3.46
[(ductwork length) x (diameter of ductwork) x (conversion
factor) x (cost per unit length) x (escalation factor) x
(retrofit correction factor) x (capital recovery
factor + taxes, insurance and maintenance factor)]
= 150 [ft.] x [/Flow x 35.314 x 4)°'5 x 12
1 2000 x 3.42
x 1.37-1.76] [$/ft.] x 1.364 x 1.625 x 1.087 x 0.263
v 1000 $/103
(gas price) x (supplemental gas required per
minute, per unit) x (number of minutes per year)
x (number of equipment units)
= 4.33[$/109J] x (GQ + (0.77 x Flow/N) x
(G1 + G2 x HT))[106J/min] x
0.5256[106min/yr] x N
D-5
-------
TABLE D-2 (Continued). MATHEMATICAL FORMULATION OF ANNUAL INCINERATOR COST COMPONENTS
Component
Annualized Cost (10J$/yr)
3. Operating Labor,
Supervisory Labor,
and Overhead Labor
Operating Labor = (labor wage)(labor hours per equipment
unit) (number of equipment units)
= 9.79/1,000 [103$/man-hr] x labor
[man-hr/yr] x N
Supervisory Labor = 0.15 x (operating labor)
Overhead Labor = 0.80 (operating labor + supervisory labor
+ maintenance labor)
where Maintenance Labor = 0.03 (total installed capital cost)
= 0.03 x N x [1.056 x 1.625 x (C + C
4. Electricity Cost
5. Quench Water Cost
(flow/N/0.95)
0.88
1 + 13.14
0.5
+ 150 x [(Flow x 35.314 x 4)
2000 x 3.42
x 12 x 1.37-1.76] [$/ft.] x 1.364 x
1.625 x 1.087
(electricity price) x (pressure drop) x (average
offgas flow rate) x (flue gas:offgas ratio)
x (fan equation conversion factor) x (number of
hours per year) * (fan efficiency)
= 0.0362/1000[103$/kW-hr] x AP[in H20] x
0.77 x Flow[scm/min] x f/o[-] x
0.004136[kW/scm-in H20] x 8760[hr/yr] * 0.6
= (0.0604) x ($.0362) x AP x (0.77 x Flow) x f/o
(water cost) x (average offgas flow rate)
x (flue gas:offgas ratio) x (water required
per unit flue gas flow rate) x (number of
minutes per year)
= [$0.26 $/103gal] x 0.77 x Flow[scm/min] x
f/o[-] x 1.68 x 10"5[103gal/scm] x 0.5256
D-6
-------
TABLE D-2 (Continued). MATHEMATICAL FORMULATION OF ANNUAL INCINERATOR COST COMPONENTS
Component
Annualized Cost (10 $/yr)
6. Scrub Water Cost
7. Neutralization Cost
x 106[min/yr] x l/1000[103$/$]
= $0.26 x.(0.77 x Flow) x f/o x 0.00883
(water cost) x (average offgas flow rate) x
(flue gas:offgas ratio) x (chlorine content
of flue gas) x (water required per unit
chlorine) x (number of hours per year)
= [0.26 $/103gal] x 0.77 x Flow[scm/min]
x 35.314scf/scm x f/o[-] x
n Q487F
u'U4tt/L
Ch°r1ne
scfmin flue gas
x 0.0192[103gal/lb chlorine] -
x 8760 hr/yr x l/1000[103£/$]
= ($0.26) x (0.77 x Flow) x f/o x (0.289)
(caustic cost) x (average offgas flow rate)
x (flue gas: offgas ratio) x (chlorine
content of flue gas) x (caustic requirement
per unit chlorine) x (number of hours per
year)
= [$0.0515 $/lb NaOH] x 0.77 x Flow[scm/min]
x 35.314 scf/scm x f/o[-]
v n fufl?r lb/hr chlorine -,
x °-0487[scf/min flue gas]
x 1.14[lb NaOH/lb chlorine] x 8760[hr/yr]
x l/1000[103$/$]
= ($0.0515) x (0.77 x Flow) x f/o x (17.17)
D-7
-------
TABLE D-2 (Concluded). MATHEMATICAL FORMULATION OF ANNUAL INCINERATOR COST COMPONENTS
Component Annualized Cost (10 $/yr)
8. Heat Recovery Credit (gas price) x (average offgas flow rate) x
(energy recovery per unit offgas flow rate)
x (number of minutes per year)
= $4.33[$/109J] x 0.77 x Flow[scmmin]
x HRF[106J/scm] x 0.5256[106min/yr]
= ($4.33) x (0.77 x Flow) x (0.5256) x HRF
D-8
-------
The parameters that are used in Table D-2 or are required in the
derivation of the TRE equation are defined as follows:
E = uncontrolled VOC emission rate, [kg/hr]
N = number of incinerator units, [-]
Flow = total design offgas flow rate, [scm/min]
f/o = flue gas to offgas ratio, [-]
HT = heating value of offgas stream [10 J/scm]
i g
HRF = heat recovery factor of offgas stream, [10 J/scm]
AP = scrubber pressure drop, [inches hLO]
GO, G«, G£ = coefficients in the supplemental natural gas
equation with units as follows:
GQ [106J/min]
Gj. [106J/scm]
G2 [-]
Substituting the cost expressions of Table D-2 into the TRE equation
definition yields the following derivation:
TRE EQUATION DERIVATION
Equation 1:
TRE = Total Resource = cost effectiveness of stream
Effectiveness reference cost effectiveness
•5
= annualized cost of stream [10 $/yr] * emissions reduction [Mg/yr]
$l,600/Mg
Equation 2:
annualized cost of control [10 $/yr] = (annualized capital cost, taxes
maintenance) + (annualized pipe rack and additional ductwork cost) +
(annual supplemental gas cost) +
(annual operating (annual
Tabor, supervisory + electricity
labor, overhead labor) cost)
+ /annual quench\ + /annual scrubx
* water cost ' * water cost '
+ /annual neutralization^ / annual heat ^
( cost ' ~ ^recovery credit'
D-9
-------
= [N x 1.056 x 1.625 x (0.163 + 0.10) ]
x [(C + C (_now_)0.88)]
N x 0.95
+ 13.14 x 0.263
+ 150 xr(F1ow x 35.314 x 4)°'5 x 12 x 1.37-1. 76-, x 1.364
L 2000 x 3.42 J
x 1.087 x 0.263 * 1000
-i- $4.33 x (GQ + 0.77 x Flow x (GI + GZ x HT))
x 0.5256
+ $9.79/1000 x 1.15 x (labor factor) x 1.80 + .024 x
(1.056 x 1.625 x (C, + C9 (Flow/N/0.95)0'88) + .024 x
13.14 i i
+ .024 x 150 xr(F1ow x 35.314 x 4)°'5 x 12 x 1.37-1. 76-,
L 2000 x 3.42 J
x '1.364 x 1.087 T 1000
+ $0.0362 x (0.0604) x AP x (0.77 x Flow)
+ $0.26 x (0.77 x Flow) x f/o x (0.00883) Category A only
+ $0.26 x (0.77 x Flow) x f/o x (0.289) Category A only
+ $0.515 x (0.77 x Flow) x f/o x (17.17) Category A only
- $4.33 x (0.77 x Flow) x 0.5256 x HRF Category A only
Equation 3:
emission reduction _ /hourly uncontrolled^ /number of days\
[Mg/yr] ^ emissions ' ^ per year '
/ number of hoursx / capacity \
x ( per day ; ^utilization'
x (VOC destruction efficiency)
= E [kg/hr] x 10"3[Mg/kg] x 365 [days/year]
x 24 [hours/day] x 0.77 x 0.98
D-10
-------
Equation 4:
2
TRE = (annualized cost of stream) [10 $/yr]
(1,600) [$/Mg] x E [kg/hr] x 6.610 [$£
= 0.0946 x (annualized cost of stream)[10 $/yr]
E Lkg/hrJ
= (0.0946/E) x {N x 1.056 x 1.625 x (0.163 + 0.10) x [(Cj_ +
C2(Flow/N/0.95)°'88] +
13.14 x 0.263 + 150 x .-(Flow x 35.314 x 4)°'5 x 12 x 1.37-1.76-,
L 2000 x 3.42 J
x 1.364 x 1.087 x 0.263 v 1000
+ N x 4.33 x (GQ + 0.77 x Flow/N x (Gj + G2 x HT))
x 0.5256) + N x 9.79/1000 x (labor factor) x 1.80 + .024 x 1.056 x 1.625
x [(Cj + C2 (Flow/N/0.95)0'88] + .024 x 13.14 + .024 x 150 x
r(F1ow x 35.314 x 4)°'5 x 12 x 1.37-1.76-, x 1.364 x 1.087 v 1000
L 2000 x 3.42J
+ 0.0362 x (0.0604) x AP x (0.77 x flow x f/o)
+ [0.26 x (0.77 x Flow) x f/o x (0.00883)
+ 0.26 x (0.77 x Flow) x f/o (0.289) + 0.0515 x f/o
x (0.77 x Flow) x (17.17)
- 4.33 x (0.77 x Flow) x 0.5256 x HRF]}
Note: The terms contained in brackets [ ] apply to category A only.
Next, the TRE equation is rearranged in the form:
Equation 5:
TRE = - ( a + b(flow)0'88 + c(flow) + d (flow)(HT)
E '
+ e(flow)0'88 (HT)0'88 + f (FLOW)0'5
D-ll
-------
Coefficients a_ through f_ are derived by substituting numeric values for
all quantities except flow, H,., and E, and then collecting like algebraic
terms. Design categories B, C, and D always have the same expressions for
the coefficients, while design categories A and E must be considered
individually for some of the coefficients. Category A has costs associated
with chlorine removal that are unique among the design categories. Category
E is unique because the offgas flow is diluted prior to incineration such
that the variable "flow" is replaced everywhere in Equations 2, 3, and 4 by
"flow x H,/3.65." These special features of categories A and E lead to
variations in the expressions for coefficients a^ through jf.
The term in the TRE equation involving coefficient a^ is independent of
flow. The expression for coefficient a^ is identical for all design
categories, and it consists of terms involving Cl, G , and a labor factor.
If the operating flow rate is less than 13.5 scm/min, then the expression
also includes a term involving C2 because in this case the fixed value flow
= 13.5 scm/min is used in the annualized capital cost expression.
- For design categories A, B, C, D, and E:
- when flow <13.5 scm/min
a = 0.0946 x 1.056 x 1.625 x 0.263 x N x Cl + 0.0946 x 13.14 x 0.263
- 1.76 x 150 x 1.364 x 1.087 x 0.263 x 0.0946 * 1000 + 0.0946 x
4.33 x 0.5256 x G x N + N x 0.0946 x 0.00979 x 1.15 x (labor
factor) x 1.80 + 0.0946 x .024 x 1.056 x 1.625 x Cl + 0.0946 x
N x 1.056 x 1.625 x 0.263 x C2nxft114/0.95)u'°° + 0.0946 x .024
x 1.056 x 1.625 x C2 (14/0.95)u'b8
= 0.0427 x N x Cl + .317 + 0.2153 x G x Np+ 0.00192 x N x (labor
factor) +n00Q427 x N x C2 x (14/0.95)u' + .003896 x C2 x
(14/0.95)°'85
- when flow >13.5 scm/min
a = 0.0946 x 1.056 x 1.625 x 0.263 x fl x Cl + 0.0946 x 13.14 x 0.263
- 1.76 x 150 x 1.364 x 1.087 x 0.263 x'0.0946 * 1000 + 0.0946 x
4.33 x 0.5256 x G x N + N x 0.0946 x 0.00979 x 1.15 x (labor
factor) x 1.80 + 8.0946 x .024 x 1.056 x 1.625.x Cl
= 0.0427 x N x Cl + 0.317 + (0.2153 x G x N) + (0.00192 x N
x (labor factor)) + 0.003896 x Cl °
D-12
-------
The term in the TRE equation involving coefficient Jj depends on
n ftft
(flow) . For design categories A, B, C, and D, the expression for
coefficient JD includes just one term that depends on C2, and therefore,
coefficient b^ is non-zero only when coefficient _a_ does not include the C2
term (i.e., coefficient b^ is non-zero only when flow >13.5 scm/min).
Coefficient b^ equals zero regardless of the value of flow for category E.
- For design categories A, B, C, and D:
- when flow <13.5 scm/min
b = 0
- when flow >13.5 scm/min
b = 0.0946 x N x 1.056 x 1.625 x 0.263 x C2 x 0.95~°'88 x N~°'88
+ 0.0946 x .024 x 1.056 x 1.625 x C2 x 0.95~°'88 x N"0'88
= N°'12 x 0.0487 x C2
- For design category E:
b = '0 (all flow values)
The term in the TRE equation involving coefficient £ depends on (flow).
For design category A, the expression for coefficient £ includes terms that
depend on GI§ AP, f/o, (f/o) x (AP), and HRF. For design categories B, C,
and D, HRF = 0 and the corresponding term does not appear in the expression
for £. Coefficient £ is zero for design category E.
- For design category A:
c = 0.77[0.0946 x 4.33 x 0.5256(G.-HRF) + 0.0946 x .0604 x .0362
x AP x f/o + 0.0946(.26 x .00883 + .26 x .289 + .0515
x 17.17) f/o]
= 0.77[0.2153(G1-HRF) +[0.000207(AP)f/o] +[0.091 x f/o]]
- For design categories B, C, and D:
c = 0.77[0.0946 x 4.33 x 0.5256 x G, + 0.0946 x 0.0604
x 0.0362 x AP x f/o] L
= 0.77[0.2153 x G, + 0.000207(AP)f/o]
D-13
-------
- For design category E:
c = 0
The term in the TRE equation involving coefficient d^ depends on the
(flow) x (H-j.) product. For design categories A, B, C, and D, the
expression for coefficient d^ consists of just one term that depends on Gp,
For design category E, the expression for coefficient d^ consists of terms
depending on G,, and the (AP) x (f/o) product.
- For design categories A, B, C, and D:
d = 0.77 x 0.0946 x 4.33 x 0.5256 x G2
= 0.77 x 0.2153 x G2
- For design category E:
d = 0.77/3.6 x 0.0946[4.33 x 0.5256 x G, + 0.0362 x 0.0604
x AP x f/o]
1
= 0.77/3.65[0.2153 x Gj +(0.000207 x AP x f/o)]
The term in the TRE equation involving coefficient e_ depends on the
(flow)0'88 x (HT)0'88 product. This product arises only in the TRE
expression for category E.
- For design categories A, B, C, and D:
e = 0 (all values of flow)
- For design category E:
o when flow <13.5 scm/min
e = 0
o when flow >13.5 scm/min
e = 0.0946 x N x 1.056 x 1.625 x 0.263 x C2 x 3.65~°'88
x 0.95"0'88 x N"°-88 + .0946 x .024 x 1.056 x 1.625 x C2 x
3.65-0'88 x 0.95-0'88 x N-°'88
D-14
-------
= N°'12 x 0.0391 x C2 x 0.320 x 1.0462 + 0.003896 x 0.320 x 1.0462
x N°'12
The term in the TRE equation involving coefficient f_ depends on
(Flow). Coefficient f_ is zero for design categories A, B, C, D, and E
when flow <13.5 scm/min. The value of coefficient _f is non-zero for all
design categories only if flow >13.5 scm/min.
- For design categories A, B, C, and D:
f = 0 when flow <13.5 scm/min.
- For design categories A, B, C, D, and E:
o when flow >14 scm/min
f = .0946 x 150 x 0.263 x 2000~°'5 x 3.142"0'5 x 4°'5 x 1.37 x 1.348
x 12 x 1.625 x 1.087 x 35.3140'5 x 0.95~°'5 T 1000 +
.024 x 0.0946 x 150 x 2000~°'5 x 3.142"0'5 x 4°'5 x 1.37 x 1.348
x 12 x 1.625 x 1.087 x 35.3140'5 x 0.95~°'5 rlOOO
D.2.2 Example Calculation of the TRE Index Value for a Facility
This section presents an example of use of the TRE index equation for
determination of the RACT category applicable to an individual air oxidation
facility. It has been determined that the air oxidation process vent stream
has the following characteristics:
1. FLOW = 284 scm/min (10,000 scfm).
2. HT = 0.37 MJ/scm (10 Btu/scf).
3. Hourly Emissions (E) = 76.1 kg/hr.
4. No chlorinated compounds in the offgas.
Because there are no chlorinated compounds in the offgas, design Category A
is not the applicable one. Categories B, C, D, and E all correspond to
nonchlorinated vent streams. Because the offgas net heating value is
0.37 scm/min, Category B is the applicable one. The offgas flowrate is 284
scm/min, and therefore the second flowrate interval under Category B is the
applicable one. The coefficients for Category B, flow interval #2 are:
D-15
-------
I.1 a = 16.61
2. b = 0.239
3. c = 0.113
4. d = -0.214
5. e = 0
6. f = 0
The TRE equation is:
1
TRE = H [a + b(FLOW)0'88 + c(FLOW) + d(FLOW)(HT) + e(FLOW0-88)(HT°'88) +
f (FLOW)0'5]
TRE = (.01314)(16.61 + 0.239 (284)0'88 + (0.113)(284)-0.214
(284)(.37) +0+0)
TRE = 0.218 + 0.453 + 0.422 - 0.95 +0+0
TRE = 0.798
Since the calculated total resource effectiveness (TRE) index value of 0.742
is less than the cutoff value of 1.0, the applicable RACT for this facility
would be 98 percent VOC reduction or reduction to 20 ppm. If process
modifications or increased product recovery were introduced, the product
recovery vent offgas percent VOC and heating value might be sufficiently
decreased that the resulting TRE value would exceed the 1.0 cutoff.
D.2.3 Calculation of Cost Effectiveness for a Facility
Because the TRE index is a cost effectiveness ratio, it is possible to
calculate cost effectiveness for any vent stream given its TRE index value.
The TRE index value of the facility is multiplied by the indexing constant
$l,600/Mg. For the stream used in the example above, the cost effectiveness
is found as follows:
D-16
-------
TRE = 0.798
Indexing constant = $l,600/Mg
Cost effectiveness = (0.798)(1,600) = $l,277/Mg
D.3 RACT IMPLEMENTATION
For RACT implementation, two types of measurements are required.
First, measurements must be made to evaluate the TRE index value for a given
plant. Offgas flowrate, hourly emissions, and stream net heating value must
be determined. Second, if a source must meet a 98 percent reduction or
20 ppmv emission requirement, then measurements of VOC reduction efficiency
must be made. Appendix H identifies the recommended reference methods and
procedures for implementing RACT.
D-17
-------
APPENDIX E: COST ANALYSIS SPECIAL TOPICS
-------
APPENDIX E: COST ANALYSIS SPECIAL TOPICS
E.I INTRODUCTION1'2
The purchase cost estimates for individual pieces of control equipment
are discussed in this appendix in relation to the raw vendor data on which
the estimates are based. Independent vendor estimates are also compared
with the purchase costs. The method of estimating installed costs from
component installation factors is discussed. Graphs of the installed costs
for several types of control equipment, as a function of flowrate, are
presented. Graphs are also presented for total installed capital costs for
the control systems, and the derivations of capital cost equations from
these graphs are discussed.
E.2 CONTROL EQUIPMENT PURCHASE COSTS
E.2.1 Thermal Oxidizer
Energy and Environmental Analysis, Inc., (EEA) obtained data from the
three vendors which provided combustion chamber cost data to Enviroscience.
The three sets of vendor quotations agreed with each other well. The
Enviroscience purchase cost curve represents a conservative "envelope" that
is higher than the vendor data for all equipment sizes.
Vendor A quoted costs for four equipment sizes for each of six
different incineration temperatures. Vendor B quoted costs for 14 equipment
sizes for each of four different temperatures. Vendor C quoted costs for
six equipment sizes for each of two different temperatures. These data
constitute an abundance of observations for derivation of reasonably
accurate equations for the relation of capital cost to offgas flowrate.
EEA independently obtained data from two additional vendors. Each of
these quoted costs for two equipment sizes at one temperature. Their
quotations essentially agreed with those of the vendors contacted by
Enviroscience.
E.2.2 Recuperative Heat Exchanger
EEA obtained data from the two vendors which provided heat exchanger
costs to Enviroscience. The two sets of vendor quotations agreed with each
other well. The Enviroscience purchase cost curve represents an average
that is roughly equivalent to the vendor curves.
Vendor A quoted costs for four offgas flowrates for each of two levels
of heat recovery. Vendor C quoted costs for three offgas flowrates for each
of two levels of heat recovery. .Because heat exchanger costs were quoted as
functions of heat exchange surface area, these data actually represent eight
and six different equipment sizes, respectively. These data constitute an
adequate number of observations for derivation of reasonably accurate
equations for the relation of capital cost to offgas flowrate.
EEA independently obtained data from two additional vendors. One
quoted costs for two offgas flowrates. The other quoted costs for two
offgas flowrates for each of two temperatures. Their quotations essentially
agreed with those of the vendors contacted by Enviroscience.
E-l
-------
E.2.3 Waste Heat Boiler
EEA obtained data from one vendor which provided waste heat boiler
costs to Enviroscience. The Enviroscience purchase cost curve represents
this data well.
The vendor quoted costs for 10 offgas flowrates for each of three
different temperatures. These data actually represent 30 different
equipment sizes, and therefore constitute an abundance of observations for
derivation of reasonably accurate equations for the relation of capital cost
to offgas flowrate.
E.2.4 Fans
One vendor quoted costs for 13 sizes of fans. These data constitute an
abundant number of observations for derivation of reasonably accurate
capital cost equations.
E.2.5 Stack
One vendor quoted costs for four sizes of stacks. While these data
constitute a minimal number of observations for accurate interpolation
between given stack sizes, the relatively low cost of stacks compared to the
rest of the control system makes extra accuracy unnecessary.
E.2.6 Ducts
Enviroscience used EPA 450/5-80-002 (The "GARD" Manual) as its source
for duct costs. The source for the additional duct and the pipe support
costs was a manual published by Richardson Engineering Services, Incorporated.
E.3 INSTALLATION FACTORS
The Enviroscience method of estimating installed costs of combustion
chamber, recuperative heat exchanger, and waste heat boiler from the original
vendor cost quotations is discussed below and summarized in Table E-l. The
component purchase costs represent interpolations of vendor quotations and
are graphed as continuous functions of offgas flowrate. A factor of
20 percent for "unspecified equipment" was added to the budget prices of the
combustion chamber and waste heat boiler. This factor was omitted for the
heat exchanger. Factors were then added for 10 aspects of installation,
such as insulation and piping. These factors were expressed as percentages
of the budget price of the equipment in question. The overall sum of these
factors plus the factor of one for the original equipment and, in two cases,
the factor of 0.2 for unspecified equipment was multiplied by a factor of
1.35, which represented the impact of contingencies, fees, site development,
and vendor assistance. Because the original costs seemed low, several cases
were vigorously recosted. It was decided by Enviroscience that the overall
installation factor would be multiplied by 1.33 to achieve a better estimate.
However, Enviroscience assumed that this factor of 1.33 was due entirely to
underestimates of the factors for the 10 aspects of installation. An
alternative correction factor was therefore calculated which, when multiplied
by the sum of the 10 installation component factors, would result in the
values of the same overall installation factor as given by the 1.33
estimate. The values of this correction factor were 1.7 for the combustion
chamber, 2.1 for the heat exchanger, and 1.9 for the boiler. The values of
E-2
-------
TABLE E-l. INSTALLATION COMPONENT FACTORS (% OF BUDGET PRICE OF MAIN EQUIPMENT)
LO
Combustion Chamber Recuperative Heat Exchange
Installation Component
Foundation
Insulation
Structures
Erection
Piping
Painting
Instruments
Electrical
Fire Protection
Engineering. Freight and Taxes
TOTAL
Factors
Budget Price
Unspecified Equipment
Total installation Component: New Source
Retrofit
Contingencies, Fees. Site Development
Overall Correction Factor
Total Installation Component Correction
Factor
Overall Installation Factor: New Source
Retrofit
New Retrofit
Source Labor
6
6
2
15
20
5
15
5
1
29
104
Combustion
1
0.2
1.04
2.09
1.35
1.33
1.7
4.0
6.5
9
9
3
22
30
8
22
8
2
29
142
Chamber
Retrofit Retrofit
Special New Retrofit Special
Expenses Source Labor Expenses
9 699
9 233
"10 1 2 10
45 10 15 30
60 ...
8 236
22 ...
15 ...
2 ...
29 21 21 21
209 42 53 79
Heat Exchanger Waste Heat Boiler
1 1
0 0.2
0.42 0.74
0.79 1.42
1.35 1.35
1.33 1.33
2.1 1.9
2.5 3.5
3.5 5.3
Haste Heat Boiler
Retrofit
New Retrofit Special
Source Labor Expenses
8 12 12
2 3 3
.
20 30 60
10 15 30
.
466
.
1 2 2
29 29 29
74 97 142
•
Formulas: (1) Overall New Source Installation Factor = (Budget Price Factor + Unspecified Equipment Factor + Total New Source Installation
Component Factor) x Contingencies Factor x Overall Correction Factor
Example (Combustion Chamber): 4.0 = (1 + 0.2 + 1.04) x 1.35 x 1.33
(2) Total Installation Component Correction Factor = ((Overall New Source Installation Factor '• Contingencies Factor) -
Budget Price Factor - Unspecified Equipment Factor) i Total New Source Installation Component Factor
Example (Combustion Chanter): 1.7 = ((4.0 » 1.35) - 1 - 0.2) i 1.04
(3) Overall Retrofit Installation Factor = (Budget Price Factor + Unspecified Equipment Factor + (Total Retrofit Installation
Component Factor x Total Installation Component Correction Factor)) x Contingencies Factor
Example (Combustion Chamber): 6.5 = (1 + 0.2 t (2.09 x 1.7)) x 1.35
-------
the final overall new source installation factor were 4.0, 2.5, and J.5 for
the combustion chamber, heat exchanger, and waste heat boiler, respectively.
Retrofit installation factors were then developed from the new source
factors. Because cramped plant conditions will make a longer time of
installation necessary, the installation labor cost will increase. For each
of the nine aspects of installation other than engineering, freight, and
taxes, it is assumed that 50 percent of the component installation factor
represents labor costs. These labor costs were assumed to double in each
case. Therefore, each of the nine component factors was assumed to increase
by 50 percent due to labor. Added expense was expected for four of the
factors: structures, piping, erection, and electrical. Such expense might
be due to a steel or concrete deck for the equipment, extra circuit breakers,
and about 500 feet of extra ducting, piping, and electrical, after inclusion
of the labor increase, were doubled. The factor for structures for the
combustion chamber and heat exchanger was assumed to increase to 10 percent.
The overall retrofit installation factors, calculated as above, for the
combustion chamber, heat exchanger, and boiler were 6.5, 3.5, and 5.3,
respectively.
In order that the Enviroscience total installed cost curves could be
used directly, one overall retrofit-to-new source correction factor was
developed. The individual correction factors for the combustion chamber,
heat exchanger, and boiler were 1.625, 1.4, and 1.514, respectively. In
order to give a conservative estimate of total installed costs, the value of
1.625 was used for the retrofit-to-new source correction factor.
E.4 INDIVIDUAL COMPONENT INSTALLED COSTS
Installed capital costs for a thermal oxidizer designed for a 870°C
(1600°F) combustion temperature and 0.75 second residence time are given in
Figure E-l. Recuperative heat exchanger installed capital costs are given
in Figure E-2. Installed capital costs for inlet ducts, fans, and stack,
for systems with and without heat recovery, are given in Figures E-3 and
E-4, respectively- The above equipment units constitute the components of a
control system for nonchlorinated vent streams.
Figures E-5 and E-6 give the installed capital costs for a thermal
oxidizer at 1200°C (2200°F) and 0.75 second residence time and for a waste
heat boiler, respectively. The installed capital costs of a scrubber
including quench chamber are given in Figure E-7. Figure E-8 gives installed
capital costs for ducts, fans, and stack for a system employing a waste heat
boiler.
E.5 TOTAL CONTROL SYSTEM INSTALLED CAPITAL COSTS
Total installed capital costs of a thermal oxidation system for control
of nonchlorinated vent streams are given in Figure E-9. The design condi-
tions are 870°C (1600°F) and a 0.75 second residence time. Figure E-10
gives the total installed capital costs of a thermal oxidation system for
control of chlorinated vent streams at 1200°C (2200°F). These conditions
were corrected to 1090°C (2000°F) and a one second residence time. The
combustion chamber volume correction factor of 1.14 represents the product
of a temperature correctioo, combustion air flowrate correction, and
residence time correction.
E-4
-------
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Figure E-l Installed capital cost for the combustion chamber with waste gas heat
content = 10 Btu/scf, residence time = 0.75 sec, and combustion
temperature = 1600 F.
-------
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RECUPERATIVE-TYPE HEAT EXCHANGER INSTALLED CAPITAL .-
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3. 70% Recup. Heat Recovery
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Figure E-2. Installed capital cost for recuperative-type heat exchangers
with the waste gas heat content = 10 Btu/scf.
E-6
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2. 50% Recup. Heal Recovery
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Figure E-3. Installed capital costs for inlet ducts, waste gas, and combustion air fans and
stack with recuperative heat recovery.
-------
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Figure E-4. Installed capital costs for inlet ducts, waste gas, and combustion air fans
and stack for system with no heat recovery.
-------
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Wasle-Gas Flow
Figure E-5. Installed capital cost of thermal oxidizer at 1800 and 2200 F including
incinerator, two blowers, ducts, and stack.
-------
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2. 10 atu/scf, 0.5 or 0.75 sec, 1600 °F
3. 100 Stu/scf, 0.5 or 0.75 sec, 1875 °F
4. 200 atu/scf, 0.5 or 0,75 sec, 2200 °F
i i
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WASTE GAS FLOW (1,000 SCrM)
Figure E-6. Installed capital cost for waste heat boilers (250 psi).
E-10
-------
3000
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Figure E-7. Installed capital cost of the scrubber including quench chamber.
-------
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Figure E-8. Installed capital for inlet ducts, waste gas, and combustion air fans and
stack with waste heat boilers.
-------
UAiUAiiON bYblfcMb IUIAL INSIALLtD CAPITAL j-
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Total installed capital cost for thermal oxidation systems with waste gas heat
content = 10 Btu/scf, residence time = 0.75 sec, and combustion temperature =
1000
1600°F.
-------
10,000
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-------
E.6 REFERENCES FOR APPENDIX E
1. Basdekis, H.S. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry. Control Device Evaluation. Thermal
Oxidation Supplement (VOC Containing Halogens or Sulfur). EPA Contract
No. 68-02-2577, November 1980. p. III-ll.
2. Blackburn, J.W. Emissions Control Options for the Synthetic Organic
Chemicals Manufacturing Industry. Air Oxidation Generic Standard
Support. EPA Contract No. 68-02-2577. May 1979. p. III-3.
3. Richardson Engineering Services, Incorporated. Process Plant
Construction Estimating Standards. 1982. San Marcos, California.
4. Memo from Galloway, J., EEA, to SOCMI Air Oxidation File. April 17,
1981.
E-15
-------
APPENDIX F: MAJOR COMMENTS RECEIVED ON THE DRAFT CTG
-------
APPENDIX F
MAJOR COMMENTS RECEIVED ON THE DRAFT CTG
Six letters were received as a result of an EPA request for comments on
the draft CTG. Table F-l gives a list of the commenters and their affiliations,
Specific comments from these letters were grouped into the following subject
areas:
(1) Applicability of the CTG;
(2) Recommendation of RACT;
(3) Cost estimation and cost effectiveness; and
(4) General.
The following sections summarize all comments received by their subject
areas. The EPA response to each comment follows each comment summary.
Copies of each of the comment letters are given in Appendix G.
1. APPLICABILITY OF THE CTG
1.1 Comment: Two commenters (#1, #4) raised questions concerning which
chemical manufacturing processes are addressed by this CTG. Both commenters
stated that the ambiguity of the list of chemicals in the CTG made it
uncertain which chemicals are covered. It was their concern that because
the list is given as "not exclusive," it does not properly define which of
these chemicals are covered or may eventually be covered by the CTG. One
commenter (#1) stated that EPA should present an all-inclusive list of
chemicals in the CTG to help producers know if their processes are covered.
Response: The CTG is a guideline document for use by State agencies
in establishing RACT. The final determination of RACT is left to the
discretion of the State agency. However, it must be noted that the RACT
recommendation and background information presented in the CTG pertain to
synthetic organic chemicals produced via air oxidation processes.
The thirty-six (36) chemicals listed in Table 2-1 represent the air
oxidation chemicals which the Agency has identified. It is possible that
chemicals not included in the list could be produced by newly developed air
oxidation processes in the future or complete information on all chemicals
produced by air oxidation was not available to the Agency. Thus, it is
recommended that any air oxidation chemicals not identified by the Agency be
covered by the recommended RACT. The supporting information and equations
for RACT are applicable to all air oxidation processes used in manufacturing
synthetic organic chemicals.
1.2 Comment: One commenter (#2) stated that oxyhydrochlorination/ethylene
dichloride plants should not be included in the scope of this CTG. The
commenter based this view on the unique vent stream control problems present
in the chlorinated solvent industry, as well as the location of the existing
EDC plants. All but two affected EDC plants are located in Texas and
Louisiana, where vent incineration is already required. One of the
remaining two is located in California and is already subject to strict
regulation. The last plant is located in Kentucky and the commenter felt
that it could be adequately addressed through the Kentucky State
Implementation Plan.
F-l
-------
TABLE F-l. LIST OF COMMENTERS AND AFFILIATIONS
Comment no. Commenter and affiliation
Dr. Robert A. Romano, Manager
Air Programs
Chemical Manufacturers Association
2501 M Street, Northwest
Washington, D.C. 20037
Mr. M. M. Skaggs, Jr., P.E.
Senior Environmental Engineer
Diamond Shamrock Chemicals Company
1149 Ellsworth Drive
Pasadena, Texas 77501
Mr. D. E. Park, Director
Corporate Environmental Affairs
Ethyl Corporation
Post Office Box. 341
Baton Rouge, Louisiana 70821
Mr. J. D. Reed, General Manager
Environmental Affairs and Safety
Standard Oil Company (Indiana)
200 East Randolph Drive
Chicago, Illinois 60601
Mr. A. H. Nickolaus, Chairman
CTG Subcommittee
Texas Chemical Council
1000 Brazos, Suite 200
Austin, Texas 78701-2476
Mr. D. C. Macauley, Manager
Environmental Affairs
Union Carbide Corporation
Ethylene Oxide/Glycol Division
Post Office Box 8361
South Charleston, West Virginia 25303
F-2
-------
Response: The Agency acknowledges that unique vent stream control
problems exist for ethylene dichloride plants because of the presence of
halogenated compounds in their process vent streams. However, the Agency
has accounted for this in the cost analysis for RACT. The analysis incor-
porates in the TRE equation the cost associated with scrubbing incinerator
flue gases containing halogenated compounds. This scrubbing cost includes
the cost of a scrubber and auxiliaries, a quench chamber, makeup water, and
caustic. Thus, the TRE index for a halogenated vent stream will accurately
represent the cost of scrubbing incinerator flue gases.
The cost associated with disposal of sodium chloride from the neutra-
lized scrubbing water of halogenated vent streams is based on direct
discharge which results in a negligible expense. Thus, the Agency considers
the cost associated with the disposal of sodium chloride to be negligible.
All but one existing air oxidation facility with halogenated vent streams
are located near the coast where the brine can be discharged either directly
or indirectly to salt water at relatively low costs. The remaining facility
will either sell the HC1 solution, or, if no market exists, will neutralize
the wastewater with caustic and dispose of the brine solution in a nearby
freshwater river. Thus, brine disposal costs are expected to be insignificant
for all facilities.
Finally, it is important to note that the Agency considers it proper to
include EDC plants in the scope of this CTG even if only one (1) plant were
to be affected. As stated in Chapter 1, EPA has permitted States to defer
the adoption of. RACT regulations on a category of sources of volatile
organic compounds (VOC) until after the EPA published a control techniques
guideline (CTG) for that VOC source category. Although presently the only
EDC plant which may potentially be affected by the CTG is located within an
attainment area in Kentucky, there is a possibility that the area could
experience a change in status to nonattainment. Thus, the CTG may be used
to develop RACT that would affect this EDC plant. Also, the list of
chemicals in Table 2-1 is intended to identify all known air oxidation
chemicals without regard to control status. Plants already subject to
control would not be affected by the RACT recommendation in this CTG and
would incur no costs.
1.3 Comment: Two commenters (#1, #4) stated that the draft CTG does not
clearly indicate which process vents are to be controlled. One commenter
(#1) said that the CTG should be revised to specify that it is not intended
to cover vents resulting from a reactor bottoms stream in cases where the
stream (which consists of liquids or solids with entrained air) is ultimately
passed through product purification operations. Another commenter (#4) said
that even though discussions with EPA pointed out that vents from product
purification are not covered under the CTG, the CTG itself does not make
this clear.
Response: Process vents that result from the product purification of a
reactor bottoms stream will not be covered by this CTG. For example, liquid
phase air oxidation reactors have two process streams, one liquid and one
gaseous. The liquid stream usually contains the desired product and is
taken to product purification. The gaseous stream containing nitrogen,
F-3
-------
unreacted oxygen, CCL, and some VOC is sent to product recovery to collect
reactants or additional product before being vented to the atmosphere. The
TRE calculations should be applied to this offgas stream after the final
product recovery device.
1.4 Comment: Two commenters (#1, #4) raised questions concerning the
calculation of the total resource effectiveness (TRE) index on processes
with multiple vent streams or where the stream is split after leaving the
process. For example, one case was given where a portion of the vent stream
(i.e., side stream) is taken for use as a transport gas and another case was
where the stream is vented separately to the atmosphere from each of two
scrubbers in series. Both commenters requested these cases be clarified as
to whether the TRE should be applied to the separate streams or to the
combined stream.
Response: If a side stream has a process use (such as a transport gas
or d gas blanket) the TRE should be calculated for it separately. This
calculation is done separately because there is a possibility that the side
stream will pick up additional VOC contamination when used in process
operations. For example, a side stream used as a gas blanket in a storage
facility containing an organic liquid may collect additional VOC from the
evaporation of stored organics.
If the side stream has no process use the TRE should be calculated on
the combined stream. The measurement of parameters for the TRE equation is
made at the outlet of the final product recovery device where VOC is reclaimed
for beneficial reuse. For the VOC recovery to be considered beneficial
reuse, the material must be recycled, sold, or used in another part of the
process. For example, consider a case where two scrubbers in series are
both used to recover VOC for beneficial reuse and part of the total stream
is vented to the atmosphere separately from each scrubber. The measurement
of flow rate, heat content, and VOC emissions should be made at both vents.
These measured parameters should then be combined for use in the TRE
equation. The measured flow rates and VOC emission rates would be added to
yield the aggregate flow and emission rate. The aggregate heating value can
be obtained by calculating a weighted average for the separate vent streams.
In cases where VOC from one of the two scrubbers in series is wasted,
the measurement of parameters for the TRE equation for that part of the
stream is made at the inlet to the scrubber from which the VOC is wasted.
These are added to the other measured parameters as previously described.
In cases where the VOC from both scrubbers in series is wasted, the
measurement of parameters for the TRE equation is made prior to the inlet of
the first scrubber. If this were not required, the owner or operator of an
affected facility could choose to use a scrubber to reduce VOC emissions,
comply with the standards by attaining a TRE index value above the 1.0
cutoff, but cause a negative environmental impact through the disposal of
the recovered VOC to land or water. If the TRE value were to be calculated
after a scrubber from which all VOC was wasted, then EPA would be neglecting
the need to limit the pollution of land and water. To provide a means of
compliance with the standards by the collection and disposal of VOC
emissions would impede the improvement of environmental quality.
F-4
-------
2. RECOMMENDATION OF RACT
2.1 Comnent: Two commenters (#4, #5) said that the CTG does not fulfill
its purpose of providing State and local air pollution control agencies with
the information they need to make their own assessment of RACT. The
commenter also said that RACT requirements are dictated in Chapter 4 of the
CTG without explanation of the basis for RACT or the alternatives
considered. Several commenters (#1, #2, #5, #6) voiced concern over the
lack of alternatives available for RACT. They said that the draft CTG does
not adequately address alternative control technologies which may be as
effective as thermal incineration. Other control methods identified by the
commenters for consideration as RACT are flares and catalytic incinerators.
Response: The Agency believes that there is ample flexibility within
the RACT recommendation described in the CTG document. The RACT recommenda-
tion outlined in Chapter 4 of the CTG does not mandate that a specific
control technique be used for an air oxidation facility. Rather, the RACT
recommendation sets percent reduction requirements and/or emission limits
which have been demonstrated to be achievable by available technology. The
RACT recommendation permits the use of alternative control techniques such
as flares and catalytic incinerators, as long as the emission reduction
requirements and/or limits are achieved. Available data show that these
devices are capable of achieving the emission reduction requirements
outlined in the RACT recommendation.
In order to analyze the impacts of RACT, a technology or technologies
had to be identified that would be available to all potentially affected
SOCMI air oxidation facilities and would achieve the largest feasible
emission reductions at a reasonable cost. Thermal oxidation was the only
technique that met both of these qualifications for the industry as a whole,
and thus it was selected for the impact analysis. The RACT recommendation
would allow the use of any alternative to thermal oxidation if the owner or
operator of an air oxidation facility were to determine that another technique
would be more appropriate. However, if an alternate technique is used the
98 percent reduction or 20 ppmv emission limit specified in the RACT recommenda
tion must be met.
The RACT recommendation has additional flexibility in that the emission
reduction requirements or emission limits do not have to be met if a facility
can maintain a TRE index greater than 1.0. The operator of a facility
having a TRE index less than 1.0 may upgrade product recovery or modify the
process to reduce emissions and raise the TRE index above 1.0. This would
enable the facility to avoid the specific emission reduction requirements
specified in the RACT recommendation. The benefits from compliance with
RACT in this manner are: (1) lower control costs; (2) recovered products,
by-products, and feedstocks; and (3) lower energy consumption.
The Agency also believes that there is sufficient information within
the CTG to enable State and local air pollution agencies to make their own
assessments of RACT. As stated in Chapter 1 of the CTG, the purpose of the
document is to review existing information and data concerning the cost of
various control techniques to reduce emissions. Since the document is
general in nature, it may not fully account for variations within the source
F-5
-------
category. However, this CTG provides a substantial information ba?t for the
State and local agencies to proceed with their own assessments of RACT.
2.2 Comment: A observation was made by a commenter (#6) that even though
the CTG includes a statement that RACT is not specifically to be met through
the use of thermal oxidation (page 4-1), it is the commenter's belief that
the criteria of 98 percent emission reduction or a VOC concentration of
20 ppmv can only be met by thermal oxidation. Thus, the criteria do not
allow industry a choice of alternative control technologies.
Response: The Agency has determined that 98 percent emission reduction
can be met by several control techniques on streams for which these
techniques apply. Available data show that efficiencies of 98 percent and
above can be achieved by catalytic oxidation (Martin, N., Catalytic
Incineration of Low Concentration Organic Vapors. U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina. 1981.
EPA-600/2-81-017). In addition, tests have also shown that flares can
achieve at least 98 percent destruction efficiency, (McDaniel, M., Flare
Efficiency Study. U. S. Environmental Protection Agency, Research Triangle
Park, North Carolina. September 1982. EPA-600/2-83-052). Finally, the
Agency believes that most steam generating units (e.g. boilers and process
heaters) can achieve a VOC destruction efficiency of at least 98 percent or
reduction to 20 ppmv provided that the vent stream .is introduced into the
flame zone. These units are generally operated at temperatures higher than
and residence times longer than those conditions necessary to achieve
98 percent destruction efficiency. Also, it is to the economic advantage of
the owners of facilities using steam generating units to operate these units
with stable flowrates and adequate mixing so that maximum combustion
efficiency is achieved. Therefore, there are many devices that can achieve
a 98 percent destruction efficiency on streams for which they apply. The
applicability of these devices depends upon stream characteristics and can
only be determined on a case-by-case basis.
2.3 Comment: One commenter (#1) stated that while thermal oxidation is the
only method analyzed in the CTG as a candidate for RACT, it is not true that
the control efficiency of thermal oxidation is much less dependent on
process and waste stream characteristics than other control techniques, nor
is thermal oxidation economically applicable to all air oxidation processes.
The commenter said that destruction efficiency of thermal oxidizers is
dependent on flame stability, which in turn depends on the composition,
heating value, and flowrate of the waste gas. In addition, some process
conditions will not lend themselves to efficient operation of thermal
oxidation and, therefore, other control techniques may be applicable and
their use should be encouraged.
Response: Available data show that the control efficiency of thermal
oxidation is much less dependent upon process and waste characteristics than
are other control techniques such as catalytic oxidizers and various product
recovery devices. The applicability and effectiveness of product recovery
devices such as condensers, absorbers, and adsorbers may be greatly affected
by the vent stream flowrate, water content, temperature, VOC concentration,
and VOC properties such as solubility, molecular weight, and liquid/vapor
F-6
-------
equilibrium. In general, where catalytic oxidizers are applicable, infor-
mation shows that 98 weight percent destruction can be achieved. However,
some air oxidation vent streams may have characteristics which would limit
the applicability of catalytic oxidizers. For example, vent streams with
high heating value or vent streams with compounds that may deactivate the
catalyst may not be suitable for applying catalytic oxidizers. Catalysts
can be deactivated by compounds sometimes present in the waste stream, such
as sulfur, bismuth, phosphorus, arsenic, antimony, mercury, lead, zinc, or
tin. Deactivation of the catalyst may also occur at high temperatures.
Thermal oxidation, on the other hand, is much less dependent on process
and vent stream characteristics as described above, and it is the only VOC
control technique that can achieve 98 percent emission reduction or 20 ppmv
outlet concentrations for all SOCMI air oxidation processes. However, the
RACT recommendation does not discourage the use of other control techniques.
The RACT recommendation would allow the use of any alternative to thermal
oxidation provided that the 98 percent reduction or 20 ppmv emission limit
specified in the RACT recommendation is met. Also, the use of product
recovery devices is allowed insofar as the owner or operator of an affected
facility may upgrade recovery equipment to raise the TRE value above 1.0 and
thus, avoid having to reduce VOC emissions by 98 percent or to 20 ppmv.
Although thermal oxidizer efficiency is dependent on flame stability,
it is relatively easy to maintain flame stability so that 98 percent destruc-
tion efficiency is ensured. The required efficiency can be attained when
mixing of the VOC stream, combustion air, and hot combustion products from
the burner is rapid and thorough. This enables the VOC to reach the desired
combustion temperature in the presence of enough oxygen for a sufficient
period of time for the oxidation reaction to reach completion. Chamber
design and burner/baffle configurations provide the turbulent flow necessary
for good mixing.
The commenter's concern that thermal oxidation may not be economically
applicable to all air oxidation processes is addressed by the inclusion of a
TRE cutoff in the RACT recommendation.
2.4 Comment: Two commenters (#2, #6) suggested that the criteria adopted
as RACT be relaxed. It was the belief of one commenter (#2) that a 95 percent
control efficiency should be adopted. As a result of the 95 percent control
efficiency, the commenter felt that greater nationwide emission reductions
would occur and gave two reasons to support this opinion. First, because
the lower control efficiency would allow the use of catalytic oxidation and
flares for RACT in addition to thermal incinerators, more process streams
would require incineration using the $l,600/Mg cost-effectiveness criterion.
Secondly, because today's higher costs for natural gas would encourage
design of many new thermal incinerators to use a.more polluting fuel such as
oil or coal, the use of catalytic oxidation or flares would avoid additional
S02, NO , and particulate emissions resulting from the fuel. This commenter
said that the additional cost of achieving 98 percent control, as opposed to
95 percent, is not justified by the additional emission reductions achieved
at 98 percent control. The commenter also said that in order to correctly
examine cost effectiveness, one must compare the incremental cost to remove
the last ton of a pollutant, as well as average cost effectiveness.
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Both commenters said that catalytic oxidation has not been properly
addressed as a RACT alternative. One of these commenters (#2) felt that the
text of the CTG makes it appear that the 98 percent emission reduction
criterion was selected specifically to exclude catalytic oxidation.
Response: Catalytic oxidation and flaring have not been excluded by
the RACT recommendation. As indicated in the response to Comment 2.1, the
RACT recommendation does not mandate that a specific control technique be
used for an air oxidation facility. The RACT recommendation permits the use
of alternative control techniques, as long as the emission reduction
requirements and/or limits are achieved. Thermal incineration is not
specifically required by the RACT recommendation. It is merely the control
technique upon which the RACT recommendation and the impacts of RACT are
based. The Agency expects that in some cases other control techniques, such
as catalytic oxidation and flaring, will be used. As stated in the response
to Comment 2.2, where catalytic oxidizers and flares are applicable,
information shows that these techniques can achieve 98 percent destruction
efficiency.
In determining the level of control which represents RACT, the Agency
examined emission data from incinerators already operating within the
industry as well as incinerator tests conducted by the Agency and by
chemical companies. The data show that all the new, well-operated
incinerators were achieving 98 percent destruction'efficiency. Also, at the
lower temperature and shorter residence time associated with lower
efficiencies, some VOC may not come into contact with sufficient oxygen at a
high enough temperature to enable the oxidation of VOC to proceed to
completion. As a result, there is greater chance that partially oxidized
organic compounds (e.g., aldehydes) and carbon monoxide may be generated.
Thus, the Administrator determined that 98 percent destruction efficiency
represents RACT.
One commenter (#6) stated that by lowering the percent reduction
requirement and, consequently, allowing other less expensive control devices
to be used, more process streams would require combustion using the
$l,600/Mg cost effectiveness criterion and more emission reductions would
occur. This assumption is incorrect because the RACT recommendation
specifies that all facilities calculate cost effectiveness using an equation
based on thermal incineration, which is the only control technique
universally applicable to the industry. Thus, even though a .facility using
a less expensive device would have a lower projected cost effectiveness than
that projected using the equation based on thermal incineration, the higher
value would be used to determine whether the costs of combustion are
reasonable and a combustion device should be installed.
The commenter also indicated that the use of catalytic oxidation or
flares would avoid additional S0?, NO , and particulate emissions resulting
from thermal incinerators using oil or" coal. However, the Agency believes
that at least in the foreseeable future, virtually all incinerators will use
natural gas for supplemental fuel. Most existing incinerators currently use
natural gas and are expected to continue to use it because the price and
availability have not changed so dramatically that this trend will not
continue.
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3. COST ESTIMATION AND COST EFFECTIVENESS
3.1 Comment: Four commenters (#1, #2, #5, #6) questioned the basis for the
cost estimates developed for the CTG. All four commenters stated that the
CTG ignores substantial costs associated with the purchase, construction,
and operation of a thermal incinerator. Two commenters (#1, #5) mentioned
that the disposal cost of NaCl from scrubbers is not insignificant as stated
in the CTG. One commenter (#1) mentioned that energy recovery (as steam) is
not feasible in many processes, especially where halogenated compounds are
present. Two of the commenters (#2, #5) stated that the costs associated
with the addition of a thermal incinerator to an existing process are
underestimated due to the omission of costs for siting, bringing utilities
and services to the site, and piping and instrumentation connections.
One commenter (#5) also noted that the 150 feet estimated by the EPA for
ductwork to the thermal incinerator is too short. He felt that due to
explosion hazard, many plant owners would not feel comfortable locating an
ignition source so close to a process, and suggested that 300 to 500 feet
would be a more representative figure.
Three commenters (#2, #5, #6) stated that the TRE index formula should
be revised to consider the omissions described above and other costs such
as: wastewater treatment expenses, variability in the cost of building
materials (carbon steel cannot be used for construction in EDC plants), down
time for heat recovery units on thermal incinerators, maintenance costs,
operating supplies, and other capital and annualized costs. Estimates for
additional costs given by one commenter (#5) are: operating supplies
(9-33 percent of operating labor), laboratory expense (10-20 percent of
operating labor), technical oversight (over 25 percent of operating labor),
and general plant overhead (50-70 percent of operating labor). The commenter
recommended that a factor of 40 percent of operating and maintenance labor
be added to account for these administrative and implementation costs.
Another commenter (#2) gave the following additional cost factors:
heat recovery unit down time, maintenance costs, operating supplies
(20 percent of operating labor), and laboratory expenses (15 percent of
operating labor). This commenter (#2) also stated that the TRE formula
should be revised to allow a company to use its true costs and thus take
regional cost differences into consideration.
One commenter (#5) stated that the estimates for annualized costs noted
in the CTG are too low. This commenter gave a comparison between his
organization s estimates and the CTG estimates. By their estimation (in
June 1980 dollars), total annualized costs will be $803,140, as compared to
the EPA estimate of $519,550. These costs are for a vent stream with a flow
rate of 284 SCM/min, heat content of 0.37 MJ/SCM, VOC emissions of
76.1 Kg/hr, and no chlorinated compounds in the offgas.
Response: The procedure used in this cost analysis was developed using
input from many sources, including the Chemical Manufacturers Association
(CMA) and the Texas Chemical Council (TCC). The procedure is sufficiently
detailed for the purpose of this cost analysis, which is to develop cost
estimates that adequately represent control costs anticipated to be incurred
by the majority of plants in the industry. The cost estimates developed for
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this standard, while not "worst case," are intended to be representative for
the industry as a whole, and, therefore, should not significantly under-
estimate or overestimate the costs for any individual facility. The Agency
believes that in some cases both minor underestimates and minor
overestimates may occur due to the site-specific nature of the costs
associated with installing incinerators at existing facilities. However,
the cost algorithms should not result in any significant inaccuracies.
Although several commenters mentioned that some items were omitted in the
cost algorithms, many of these items are actually not omissions at all.
The cost associated with disposal of sodium chloride from the
neutralized scrubbing water of halogenated vent streams is based on direct
discharge which results in a negligible expense. This is believed to be
representative of the situation that all air oxidation facilities will face.
All but one existing air oxidation facility with halogenated vent streams
are located near the coast where the brine can be discharged at a relatively
low cost either directly or indirectly into the ocean or into a brackish
stream. The remaining facility will either sell the HC1 solution directly,
or if no market exists, will neutralize the wastewater with caustic and dump
the brine solution into a nearby freshwater river. Thus, brine disposal
costs are expected to be insignificant for all existing air oxidation
facilities and no change in the costing procedures will be made.
Two commenters stated that the algorithms have omitted significant
costs that will be incurred when adding control devices to existing
facilities. The costs identified as being omitted were for siting, bringing
utilities to the site, and piping and instrumentation connections. This
statement, however, is inaccurate. Siting and piping/instrumentation costs
are actually included in the capital cost installation factor. Furthermore,
the Agency believes that the cost associated with adding a control device at
an existing facility is not underestimated. To account for difficulties
associated with adding a control device to an existing process, a retrofit
correction factor of 1.625 was used in estimating total installed capital
costs. This increases the total installed capital costs by about
63 percent. The costs for bringing utilities to the site are not included
because the control device (i.e., thermal incinerator) will most likely be
located in the proximity of the process unit where utilities are readily
accessible.
Two commenters recommended the inclusion of a factor of 35-40 percent
of operating and maintenance labor to account for heat recovery unit down
time, operating supplies, laboratory expenses, technical oversight, and
general plant overhead. Some of these items have been incorporated in the
maintenance labor and materials factor; the taxes, insurance, and
administrative charges factor; and the operating labor rate which includes
overhead. Also, even if the commenter's factor were incorporated in the
cost algorithms, total annualized costs would increase only by about
2 percent.
Other factors and assumptions were included in the algorithms to avoid
underestimating costs incurred by facilities using combustion to control
VOC. These assumptions were made to ensure that control equipment sizes and
supplemental gas requirements were not underestimated. First, vent streams
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were assumed to contain no oxygen to maximize estimated combustion air
requirements. Most streams, while not containing 21 percent oxygen, have
some smaller percentage of oxygen present. Therefore, the assumption of no
oxygen ensures that no underestimate will occur for the equipment size, the
combustion air flow rate, and the amount of supplemental natural gas needed.
Second, actual offgas flow rate was inflated by 5 percent in calculating
costs, which inflated gas consumption and equipment size by 5 percent.
Third, the temperatures and residence times assumed for cost estimation
purposes (l,600°F/.75 sec for nonhalogenated streams, 2,000°F/1 sec for
halogenated streams) were higher than those conditions generally necessary
to achieve a 98 percent VOC destruction efficiency, as discussed in
Appendix A of the CTG document. These higher temperatures and residence
times would result in a larger equipment size and higher gas consumption.
Fourth, the overall installation factors assumed for new sources were 4.0,
2.5, and 3.5 for the combustion chamber, heat exchanger, and waste heat
boiler, respectively. These factors were all higher than the EPA CARD
Manual factor of 2.17 (EPA-450/5-80-002).
Upon evaluating all the public comments, several changes were made in
the cost algorithms. The ductwork length used in the cost analysis was
changed from 150 feet to 300 feet and 250 feet of pipebridge supports for
the ductwork was added. The ductwork length increase was based on
specifications provided by The Industrial Risk Insurers (IRI) and the
National Fire Protection Association (NFPA). These are groups which present
recommended distances for safely locating combustion sources from process
units in chemical plants. An additional 100 feet was added to the IRI and
NFPA recommendation to account for routing the stream around equipment and
to the perimeter of the process unit before routing it away from the process
unit. The 300-foot figure is believed to be more representative of industry
conditions, and is within the range recommended by the one industry
commenter on this item.
The gas price used in the cost algorithms was revised to reflect the
upward trend of national gas prices. Since gas prices are projected to rise
more rapidly than inflation, the Agency believes it is important to use a
1980 base-year gas price that will reflect these rising prices. As
explained in Chapter 5, the gas price was projected for the year 1990
weighted geographically and then was deflated to 1980 dollars (the base year
for all costs used in the CTG document). This was done to obtain a
representative gas price on a national basis that would be incurred by
facilities.
The labor price and utility prices such as electricity, water, and
caustic were also revised. These prices were revised to be more
representative of 1980 costs, which the TRE equation is based on. Although
these prices were originally based on 1980 prices, further examination
showed that more representative prices could be used. These prices have the
same basis as the labor and utility prices for NSPS's using the TRE concept.
3.2 Comment: One commenter (#5) stated that the absence of design algorithms
in the CTG prevented his organization from properly comparing EPA capital
cost estimates with actual thermal incinerator costs. He suggested that EPA
have a construction firm perform a cost estimation on the example case given
in Appendix E of the CTG.
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Response: The incinerator cost algorithms presented in Appendix E are
derived from cost equations outlined in Chapter 5. The underlying
assumptions used in developing these cost equations are explained in this
chapter and the referenced documents. The cost data in this CTG were based
on the two IT Enviroscience thermal oxidizer evaluation documents that
specifically apply to air oxidation processes [(a) Basdekis, H. S.,
Emissions Control Options for the Synthetic Organic Chemicals Manufacturing
Industry. Control Device Evaluation. Thermal Oxidation Supplement (VOC
Containing Halogens or Sulfur). EPA-450/3-80-028d , November 1980.
(b) Blackburn, J. W. Emissions Control Options for the Synthetic Organic
Manufacturing Industry. Control Device Evaluation. Thermal Oxidation.
EPA-450/3-80-028d, July 1980]. Enviroscience has been involved in designing
these types of emission control devices for industry and was determined to
be qualified to develop costs estimates for this CTG. Furthermore, these
procedures have been extensively reviewed by industry and vendor
representatives and revisions have been made where appropriate.
3.3 Comment: A commenter (£2) noted that the CTG used out-of-date costs
and that more recent costs should be examined. The commenter mentioned that
the cost factors used in the proposed TRE formula have not been examined in
five years, even though they were inflated to 1980 levels. This commenter
further stated that adopting a CTG on outdated costs is poor scientific and
technical practice. The commenter recommended the formula be revised to
allow the use of present and projectable future costs based on the date of
application.
Response: The Agency has reviewed the costing procedure and believes
that the current costs are not outdated. As mentioned in the response to
comment 3.1, upon reviewing all the public comments, the gas, labor and
other utility factors were reviewed and necessary revisions were made.
These revisions were made to ensure that costs most representative of 1980
would be used and, where appropriate, projectable future costs would be
incorporated in the cost algorithms. Since natural gas prices are rising
more rapidly than inflation, the Agency believes it is appropriate to use a
base-year gas price that will reflect these rising prices. The labor and
other utility factors such as electricity, water, and caustic were also
revised and are now on the same basis as the labor and other utility prices
for the new source performance standards using the TRE concept. The labor
and other utility prices are not expected to rise more rapidly than
inflation and, thus, will not affect the validity of the TRE equation.
The equipment costs used in the algorithms were based on the most
recent data available when the costing was done. Costs were updated from
1979 dollars to 1980 dollars using fabricated equipment indexes for chemical
plants. The Agency believes that it is neither feasible nor necessary in
terms of accuracy of the TRE equation to continually update equipment costs
during the development of the CTG. This is because equipment costs are not
expected to rise at a rate significantly higher than the general inflation
rate. General inflation does not affect the results of the TRE equation.
Regardless of whether it is expressed in 1980 or 1984 dollars, the TRE
equation yields the same value. The TRE index value of a particular stream
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represents the ratio of the cost-effectiveness associated with incineration
of that stream to the cost-effectiveness cutoff of $l,600/Mg. If the
cost-effectiveness value for a particular stream is increased due to general
inflation, the reference cost-effectiveness cutoff would experience the same
increase since both values are based on the same cost assumptions. Thus,
the ratio will remain the same, and the TRE index value will be unchanged.
3.4 Comment: One commenter (#5) stated the cost-effectiveness cutoff of
$l,600/Mg is too high. The commenter based this belief on the fact that
most VOC source control costs (in prior NSPS studies) have not exceeded
$l,000/Mg and questioned why EPA would propose a CTG that is more stringent
than a NSPS. This commenter also requested clarification of the base year
dollars used in the CTG. It was not clear if the 1980 dollars were updated
to current dollars in the CTG. If 1980 dollars are used, the commenter
pointed out that the cutoff of $l,600/Mg becomes $l,970/Mg when inflated to
1984 dollars.
Response: The Agency believes that a cost-effectiveness cutoff of
$l,600/Mg (1980 dollars) is a reasonable upper limit for the application of
the RACT recommendation. The Agency evaluated several factors in analyzing
the RACT alternatives. These included the energy, environmental (air and
water quality, solid waste), cost, cost effectiveness and product price
impacts associated with these alternatives. The RACT alternative
represented by a $l,600/Mg cutoff was selected because of the potential for
unreasonable economic impacts (i.e., increases in the price of chemical
products) or unreasonable cost-effectiveness values at more stringent RACT
levels.
Although a facility could theoretically incur a cost effectiveness as
high as $l,600/Mg, it is probable that lower cost-effectiveness values will
be incurred. The reasons for this are (a) other less expensive control
techniques are likely to be used by facilities; and (b) the inherent flexi-
bility within the recommended RACT encourages the use of product recovery
improvements that will reduce the cost incurred by individual facilities
while also reducing the national energy impact. The RACT impact analysis
assumes that incinerators will be used to reduce VOC emissions by 98 weight
percent. However, many facilities may opt to use boilers, process heaters,
flares, or catalytic oxidizers. When these devices are used, the costs of
control may be reduced from the cost of thermal incineration. Furthermore,
the RACT recommendation does not require the control of VOC emissions if a
TRE index greater than 1.0 is maintained. The EPA believes that many
facilities having TRE indexes of 1.0 or less will upgrade product recovery
to reduce VOC and raise their TRE values above 1.0. This will also signifi-
cantly reduce the costs of control incurred by the industry. To study the
potential impacts of requiring air oxidation facilities to control VOC
emissions using thermal incinerators, the Agency developed a statistical
profile of facilities which is assumed to represent all existing air
oxidation facilities. An analysis of these facilities indicated that the
highest cost effectiveness that a facility will actually incur as a result
of installing a combustion device is about $l,000/Mg. This analysis also
shows that facilities in the statistical profile with cost-effectiveness
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values above $l,000/Mg would be able to upgrade product recovery to achieve
a TRE greater than 1.0.
3.5 Comment: Two commenters (#5, #6) questioned the inconsistencies of TRE
formulae and the tables of coefficients in the CTG as opposed to the Air
Oxidation Processes Draft Background Information Document (BID). One commenter
(#6) felt that the wrong table of coefficients (page E-3 of the July 1981
draft CTG) was printed in the CTG. Another commenter (#5) said that the
inconsistencies between the BID and the CTG were caused by the use of
different annualized cost factors. Some of the differences in the cost
factors are:
BID CTG
Operating Labor $13.08/hr $11.10/hr
Electricity $ 0.02616/kWh $ 0.0490/kWh
Natural Gas $ 4.78/GJ $ 2.40/GJ
Caustic Price $ 0.0436/lb $ 0.0563/lb '
Source: BID Table 8-7, July 1981 Draft, CTG Table 5-7.
One commenter (#6) noted that a TRE index of 1.0 in the CTG corresponds to a
value of $l,600/Mg, while a 1.0 index in the BID corresponds to a value of
$886/Mg.
Response: There are valid reasons for the difference between the set
of TRE coefficients in Table E-l of the July 1981 draft CTG and the set of
coefficients presented in the BID. The primary reasons for the difference
are (1) a different reference cost-effectiveness value used in the TRE
equation for the draft CTG; and (2) a retrofit correction factor was
incorporated in the total installed capital cost component for the TRE
equation within the draft CTG. The retrofit factor increases the capital
cost by 62.5 percent to account for difficulties associated with adding a
control device to an existing process.
Although not a primary cause for the difference in TRE coefficients,
the different cost factors do account for some variation. However, as
indicated in the responses to comments 3.1 and 3.3, the gas, labor, and
other utility factors were revised. These revisions were made for two main
reasons: (1) to account for the fact that natural gas prices are rising
more rapidly than inflation; and (2) to use labor and other utility factors
that are more representative of 1980 costs. The gas, labor, and other
utility factors now have the same basis as the factors used in the air
oxidation NSPS. The slight differences between factors are due to the
different base year used in the CTG (i.e., 1980) compared to the NSPS (i.e.,
1978).
There is a valid reason that TRE index will correspond to different
cost-effectiveness values in the CTG and in the proposal BID. The
calculation for determining a TRE index differs between the two documents
although the method used is essentially the same. In the CTG, the TRE index
of a stream represents the ratio of the cost-effectiveness of that stream to
a reference cost-effectiveness of $l,600/Mg (i.e., the cost-effectiveness
cutoff). In the BID the TRE index of a stream represents the ratio of the
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cost-effectiveness of that stream to a different reference cost-effectiveness.
This reference cost effectiveness is $88,660/Mg (i.e., the most expensive
plant to control in the statistical profile) divided by 100 or $886/Mg.
Thus, it is correct that a TRE index of 1.0 corresponds to $l,600/Mg in the
CTG and $886/Mg in the BID. Both TRE indexes are correct and reflect the
differences reference cost effectiveness values used, as well as the fact
that a retrofit correction factor was used in the CTG. It should be noted
that the Agency intends to change the reference cost effectiveness used in
the BID to $l,900/Mg (i.e., the cost-effectiveness cutoff). This change
will cause the TRE index of 1.0 to correspond to $l,900/Mg.
3.6 Comment: One commenter (#6) stated that measurements for determining
TRE should be based on the emissions that are actually being released to the
atmosphere, regardless of whether the last step in the process is (a) product
recovery, (b) energy recovery, or (c) a less than ideal existing emissions
control device.
Response: The measurement for determining the TRE index of a stream
must be based on emissions exiting the final recovery device where the VOC
from that device is reclaimed for beneficial use (i.e., recycled or sold)
rather than for waste disposal. The reasons for this are discussed in the
response to Comment 1.4.
Any existing energy recovery device or emissions control device that
combusts the offgas would be permitted by the CTG and no additional control
would be required. Thus, for cases (b) and (c) mentioned by the commenter,
where both are combustion devices, TRE measurements would not be necessary
because the facilities would already be in compliance with the RACT
requirement. Any existing energy recovery device or emissions control
device that does not combust the offgas would be required to measure for the
TRE index after the final product recovery device where VOC is reclaimed for
beneficial reuse.
4. GENERAL
4.1 Comment: One commenter (#4) stated that his organization's data
analysis indicates that fewer than 25 plants have the potential to be
controlled more effectively under the CTG than under present controls and,
therefore, he questions the need for the CTG.
Response: The Agency believes that many facilities have the potential
to be controlled more effectively under RACT as outlined in the CTG than
under present controls. Of the four States identified in the CTG as having
state regulations applicable to SOCMI air oxidation processes, none has a
requirement more stringent than the RACT recommendation. Furthermore, even
if fewer than 25 plants could be controlled more effectively under RACT, the
Agency would pursue development of the guidelines through publication of the
CTG document. The reason for this is that one air oxidation facility can
emit a substantial amount (5,000 Mg or more) of VOC annually.
4.2 Comment: Two commenters (#1, #2) questioned apparent conflicting TRE
cutoff values, in the draft CTG. They noted that in Appendix D (page D-l),
the TRE cutoff value used for RACT is given as 2.9 but it is given as 1.0 in
both Section 5 (page 5-28) and Appendix E (page E-l).
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Response: In Appendix D (page D-l), the TRE cutoff of 2.9 is a typo-
graphical error, 1.0 is correct. The text has been revised to reflect this
correction.
4.3 Comment: Two commenters (#1, #4) stated that the general description
of the Air Oxidation Industry is vague and does not accurately detail the
industry.
Response: Although the description of the Air Oxidation Industry is
presented in a general way, the actual group of sources intended for
coverage by this RACT is clear. The recommended RACT is applicable to those
chemicals listed in Table 2-1 as well as any other synthetic organic
chemicals which are produced by air oxidation. A description of an air
oxidation unit process is given on page 2-1.
4.4 Comment: One commenter (#1) said that the discussion of Illinois State
Regulations, in Chapter 3, was incorrect and should be clarified. The
commenter stated that the Illinois regulation actually requires VOC emission
controls at one of three levels: (1) 8 pounds/hr, (2) 10 ppmv equivalent
methane, or (3) 85 percent destruction. It is stated in the CTG that
Illinois limits all VOC emissions to 100 ppm equivalent methane.
Response: Illinois State Regulations limit emissions of organic
material to eight pounds per hour unless controlled by: (a) thermal or
catalytic incineration capable of meeting emission limits of 10 ppm equivalent
methane, or 85 percent hydrocarbon destruction, (b) a vapor recovery system
that adsorbs, absorbs, or condenses at least 85 percent of the uncontrolled
organic material, or (c) any other control device approved by the Illinois
Agency as being capable of reducing uncontrolled organic material emissions
by 85 percent. The Illinois Regulations in the CTG have been corrected.
4.5 Comment: One commenter (#1) suggested that in Chapter 5, it should be
clarified that "E" (hourly emissions) is just the VOC emissions and "Flow"
is the flow of the vent stream.
Response: The text has been amended to clarify these terms.
4.6 Comment: A commenter (#2) said that NOx emissions from coal combustion
are erroneously attributed to fuel nitrogen content on page A-20. These
emissions are conventionally thought of as being independent of fuel
nitrogen.
Response: Both the Utility Boiler and the Stationary Gas Turbine
Background Information Documents (BID) note that the contribution of N0x by
fuel nitrogen can indeed be significant when burning high nitrogen fuel.
Additionally, in the July, 1979 Proceedings of the Second NO Control
Technology Seminar hosted by the Electric Power Research Institute,
J. J. Marshall and A. P. Selker of Combustion Engineering, Inc., presented a
paper stating that fuel NO can account for 30 to 75 percent of total NO
emissions in pulverized coih firing. The text of the CTG was altered to
read, "By contrast, fuel nitrogen can account for a significant percentage
of total NO emissions in the combustion of heavy oils, coal and other high
nitrogen fuils, such as coal-derived fuels and shale oils."
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4.7 Comment: The following general observations were made by four commenters
(#1, #2, #5, #6) on the July 1981 ffraft CTG.
o There is an apparent typographical error on page E-3. Line A2
should read "For Chlorinated Process Vent Streams, if 3.5 FNet
Heating Value (MJ/Nm3)."* (comrnenter #1)
o Printing errors on pages 3-17 to 3-20 have resulted in the
omission of one portion of the text and duplication of other
portions. One commenter (#2) requested a revised copy of the
document and suggested that the comment period be reopened to
allow the omitted section to be reviewed, (commenters #2, #6).
o The CTG uses "Nm3" for normal cubic meters. This is confusing
since N is the standard symbol for Newtons. (commenter #5)
Response:
o The text was corrected to read ". . . if 3.5 FNet Heating Value
(MJ/Nm3)."
o This section of the text has been corrected to include the omitted
material. The comment period was not reopened because the omitted
material contains no controversial information.
o Nm3 should not be confused with Newtons, because the unit Newton
is not used in the context of the CTG.
4.8 Comment: Three commenters (#2, #3, #4) pointed out the following
errors in Table 2-6.
o Diamond Shamrock sold its LaPorte, Texas EDC/VCM facility to
B. F. Goodrich Corporation in 1981. (commenter #2)
o The correct corporate name of Diamond Shamrock's Deer Park Plant
is Diamond Shamrock Chemicals Company, (commenter #2)
o The two Ethyl Corporation facilities manufacturing 1,2-dichloro-
ethane by air oxidation are incorrect listings, (commenter #3)
The Ethyl Corporation's Baton Rouge, Louisiana 1,2- dichloro-
ethane air oxidation process unit was shut down in
January 1983.
The Ethyl Corporation's Pasadena, Texas 1,2-dichloroethane
unit does not use air oxidation.
o Amoco Standard does not manufacture acetone and phenol in Richmond,
California and does not have a plant there, (commenters #1, #4)
Response:
oThe text has been changed to read B. F. Goodrich Corporation.
o The text has been changed to read Diamond Shamrock Chemicals
Company.
o These two Ethyl plants were deleted from the table.
o The Amoco-Standard plant was deleted from the table.
F-17
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FOREWORD
The following memorandum examines the potential of facilities with a
TRE index below the cutoff to upgrade product recovery and raise their TRE
index above the cutoff. It should be noted that this memorandum is based on
a July 1981 draft of the CTG, which includes TRE coefficients based on a
cutoff of 2.9 (equivalent to $l,600/Mg). In subsequent drafts of the CTG,
the TRE index cutoff was changed to 1.0, reflecting a change in the
reference cost effectiveness value used in the TRE index equation. New TRE
coefficients were derived that are based upon the TRE index cutoff of 1.0.
The TRE index cutoff of 1.0 is still equivalent to $l,600/Mg. Thus, the
change in the TRE index cutoff has not invalidated the examination presented
in the memorandum. The following product recovery analysis is based on the
costing procedures set forth in the July 1981 draft at the CTG and does not
reflect the costing changes discussed in this appendix. However, these
costing changes would not alter the results to such an extent that the
conclusions reached as a result of this analysis would be different.
F-18
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RADIAN
MEMORANDUM
DATE: January 11, 1984
TO: Air Oxidation Processes CTG File
FROM: Richard F. Pandullo
SUBJECT: Analysis of Plants With the Potential to Apply Process
Modifications to Raise their Cost-Effectiveness Values
Above the RACT Cutoff Point
INTRODUCTION
This memorandum describes an analysis performed to identify plants with
the potential of applying process modifications to raise their cost-
effectiveness values above the Reasonably Available Control Technology
(RACT) cutoff outlined in the Air Oxidation Processes Control Techniques
Guidelines (CTG) document. The $1600/Mg ($ 1980) RACT cutoff level is
associated with a total resource effectiveness (TRE) value of 2.9. In
areas where the RACT guidelines are adopted, plants which have a TRE value
below the cutoff may opt to upgrade existing recovery equipment or add
recovery equipment to raise their TRE values and avoid the incineration
requirement. This analysis estimates the potential number of cases for
which this option may be applied and describes qualitatively the recovery
changes that may be implemented if this option is applied. This analysis
does not investigate potential process changes (e.g., changing physical
reaction conditions, changing feedstocks or catalysts) that, if adjusted,
could change the TRE value.
A rigorous engineering analysis on individual plants was not performed
as detailed information regarding plant operations was in most cases unavail-
able in the emissions data file. Instead, the best scientific judgement was
used on the available data. This data included Houdry data reports,
Hydroscience Product Reports on specific chemical processes, and the draft
CTG document.
The reactor process vent stream characteristics for all fifty-nine
plants from Table B-4 of the draft Air Oxidation CTG document were examined.
These data are summarized in Table 1. TRE values were calculated for these
plants to identify cases where the value was just below the RACT cutoff
point of 2.9. TRE values are summarized in Table 1 and the TRE equation
used is presented in Table 2. Plants with TRE values above the cutoff point
were eliminated from further analysis because they would not be required to
use incineration if the RACT guidelines were adopted. For plants with TRE
values below 2.9. the VOC emission reductions needed to raise TRE values to
the cutoff point were estimated. Focus was given to those plants where the
VOC emission reductions needed to reach the TRE cutoff were low to moderate
F-19
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(<70 percent). On the basis of data calculated and information gathered, an
assessment was made to determine whether process modifications could achieve
the calculated VOC emission reductions.
RESULTS
Table 3 presents the results of this analysis. Twenty-four out of the
59 plants examined were estimated to have TRE values above 2.9. These
plants were excluded from further analysis because if the RACT guidelines
were adopted they would be exempt from the incineration requirement.
Nine plants were estimated to have TRE values below 1.0. Further
analysis was not performed on these plants because in such cases a VOC
reduction of 80 to 90 percent is required to reach the TRE cutoff point.
These emission reductions were considered not likely to occur with modifi-
cations to product recovery equipment.
The analysis revealed that the remaining 26 plants had TRE values above
1.0 and below 2.9. In this category, 7 plants currently use incinerators
and 9 either have been shut down or have changed processes. These plants
were excluded from the list of potential cases for process modifications.
It was estimated that two plants presently using water scrubbers (#1007,
terephthalic acid; #902, cyclohexanone) require 57 percent and 54 percent
reductions to reach the cutoff point. Another cyclohexanone plant (#903)
also presently using a water scrubber was estimated to require a 64 percent
reduction. This level of emissions reduction is not likely to be achieved
because most of the VOC emitted from these three plants is insoluble in
water and, thus, would probably not be collected by increasing the
efficiency of the water scrubber. One additional 'terephthalic acid plant
(#1004) using carbon adsorption was estimated to require a 39 percent
reduction to reach the cutoff level. A model plant for this chemical
developed by Hydroscience identifies carbon adsorption as 97 percent
efficient for VOC removal at this type of plant. This plant was determined
to be a marginal but not likely case because assuming the adsorber already
achieves a 97 percent reduction, it is unlikely tbat an additional
39 percent could be removed at a reasonable cost. '
Six plants out of 59 surveyed were determined to have the potential for
applying process modifications to raise their respective TRE values to the
cutoff point. Two formaldehyde plants (#1407 and #1420) using product
absorbers with no VOC control were estimated to require a 45 percent VOC
reduction. Two additional formaldehyde.plants (#1403 and #1404) were
estimated to require a 1 percent reduction. The Product Report for
formaldehyde manufacturing states that one manufacturer (with the same
process characteristics as those for the 4 in question) uses a water
scrubber following the product absorber which achieves a 74 percent VOC
reduction. It was assumed that these plants could potentially do the same
at a substantially lower cost than that which would be associated with
adding a thermal incinerator.
F-20
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One acetic acid plant (#205) using a water scrubber was estimated to
require a 51 percent reduction in VOC to reach the cutoff. The acetic acid
plant was considered a marginal, but likely case because the vent from this
scrubber contains a soluble component (acetaldehyde) which is present at a
much higher concentration than the non-soluble component. Therefore,
modifications to the scrubber to increase efficiency (e.g., addition of
scrubber plates) could potentially reduce this soluble component by the
required amount.
One final case where process modification could potentially be applied
is at a teraphthalic acid plant (#1005) using absorption as a product
recovery method. It was estimated that a 20 percent VOC emission reduction
is required to increase the TRE to 2.9. It was assumed that this plant
could achieve the reduction because a manufacturer using the same process
and control was found to achieve an additional 36 percent VOC reduction by
adding plates to the existing absorber.
SUMMARY
Absorbers are primarily used as product recovery devices, but can be
applied for the purposes of VOC control. In this analysis, it was determined
that four plants could potentially add an absorber (water scrubber) and 2
plants could modify existing absorbers to achieve the necessary VOC reduc-
tion. Modification of an absorber is commonly done by increasing the size,
decreasing the operating temperature, or increasing the number of plates in a
column. '
It was assumed that a plant manager would decide whether to upgrade
recovery equipment based on the fact that the alternative control measure
would be thermal incineration. In general, the capital and annualized costs,
energy requirements, and siting problems would be less significant for
upgrading recovery equipment than for applying thermal incineration. In the
latter case, equipment is more complex and expensive, fuel requirements and
other operating costs are higher, and precautionary siting measures to avoid
explosion and fires are more restrictive. The reason for the precautionary
measures is that an incinerator has to be situated far enough away from other
equipment in the plant so that leakages will not introduce volatile compounds
into the vicinity of the incinerator and thereby increase the potential for
explosions or fires. Thus, more ductwork is required and greater energy
inputs are necessary to route offgas to the incinerator. In addition to the
aforementioned relative advantages of upgrading recovery equipment over
applying thermal incineration, there is another positive aspect associated
with the former. Upgrading recovery equipment can result in an economic
benefit by increasing the amount of raw materials, products, and by-products
recovered.
F-21
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TABLE 1. EMISSIONS AND COST EFFECTIVENESS DATA FOR PLANTS
Plant
Number
5102
904
1305
1411
5101
1303
5201
5203
5103
5104d
903
1807d
5204d
1007
902
2C5C
1306d
iaoid
1407°
5207b
2203b
5208b
1420C
1004
1803d
1802d
1005C
2303b
2302b
2308b
1806d
1404C
5209b
1804d
1403C
Hourly Net
Emissions Heating Value
(Kg/hr)
2150
407
666
357
1370
326
616
433
895
1210
103
355
348
223
80.2
75.0
115
52S
33.7
464
155
371
31.4
323
205
211
188
617
203
219
135
20.3
78.9
136
15.1
(MJ/NmJ)
1.71
1.63
1.13
3.05
1.12
0.635
4.56
2.13
0.781
0.725
0.465
0.308
2.84
0.165
0.472
0.251
0.535
0.419
2.82
0.325
0.233
0.825
2.76
0.289
0.415
0.360
0.153
0.099
0.154
0.157
0.359
2.63
0.825
0.483
2.82
Offgas
Flowrate
(NmJ/min)
1280
235
493
510
1330
430
269
113
1420
1950
170
566
201
527
170
142
181
2110
56.5
283
481
226
56.6
1420
1190
1250
912
3310
1130
1230
850
67.9
48.1
481
22.7
Cost
T~- Effectiveness
0.19
0.32
0.43
0.48
0.49
0.52
0.60
0.70
0.96
1.02*
1.03e
. 1.06*
1.17e
1.25e
1.33s
1.42e
1.49e
1.53e
1.58e
1.58e
1.61e
1.63e
1.69e
1.77e
2.17e
2.27e
2.32*
2.52*
2.57*
2.58*
2.61*
2.71*
2.73*
2.82*
2.82*
(S/Mg)
106
178
240
268
273
290
334
390
535
568
574
591
652
697
741
791
830
853
880
880
897
908
942
986
1,209
1,265
1,293
1,404
1,432
1,438
1,455
1,510
1.521
1.574
1.574
F-22
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TABLE 1. (CONTINUED)
Plant
Number
2305
5206
2301
1422
1408
1416
2206
5205
1423
1410
5202
2208
1421
2205
1001
1601
2204
2207
102
1805
1601
1307
1409
1418
Hourly
Emissions
(Kg/hr)
340
125
117
23.3
14.6
39.6
36.0
228
19.5
15.8
80.2
14.6
16.0
27.9
78.7
55.0
26.4
13.7
13.7
14.1
0.217
2.12
0.025
0.0205
Net
Heating Value
(MJ/Nm3)
0.097
0.775
0.150
0.321
2.72
0.114
0.093
2.15
0.148
2.71
0.807
0.117
0.148
0.070
0.393
3.55
0.067
0.070
0.010
0.220
1.83
0.001
2.95
2.56
Offgas
Flowrate
(Nm3/m1n)
2150
133
736
93.4
70.3
164
215
603
110
161
170
90.6
110
289
1530
1520
425
142
340
1220
134
2830
31.1
25.5
IRE
3.03
3.05
3.12
3.58
3.89
3.92
4.16
4.46
4.97
5.23
5.64
6.02
6.06
6.66
8.02
8.43
9.44
10.43
15.8
37.7
443
669
1814
2125
Cost
Effectiveness3
(S/Mg)
1,689
1,700
1,739
1,995
2,169
2,185
2,318
2,486
2,769
2.917
3,143
3,355
3,375
3,712
4,470
4,698
5,259
5,815
8,816
21,000
247,000
373,000
1,010,000
1,184,000
'Cost-Effectiveness 1n $ 1980 (see page 5-25, draft Air Oxidation CTS
document).
Incineration 1s employed to control VOC (only determined for plants marked
with (ej).
cPoss1ble case for applying process modifications to raise TRE to cutoff
point.
Process, has been shut down or changed (only determined for plants marked
with (e)).
*F1ant was conslded for expanded analysis to determine whether possible case
for applying process modifications (I.e., Houdry data, Hydroscience Product
Report, and SRI directory were examined).
F-23
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TABLE 2. EQUATION FOR CALCULATING TRE VALUES
TRE = 1 [a + b(Flow)0'88 + c(F1ow) + d(Flow) HT + e(Flow)0'88 (HT)0'88 +
f(HT)°'88]
where: E = emissions, (kg/hr) 3
Flow = offgas flowrate, (Nm /mini
HT = net heating value, (MJ/Nm )
a,b,c,d,e = constants from Table 5-12, draft air oxidation
CTG document
F-24
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TABLE 3. SUMMARY OF RESULTS FOR 59 PLANTS EXAMINED
No. Plants Category Remarks
24 TRE > 2.9 Excluded from further analysis because
are already exempt from incineration
requirement.
9 TRE < 1.0 Excluded from further analysis because
plants require 80 to 90 percent reduc-
tions to raise TRE values to cutoff
point.
26 1.0 < TRE < 2.9 Considered for expanded analysis because
plants require relatively small VOC
reductions to raise TRE values to cutoff
point.
Sixteen (16) plants use incinerators,
have been shut down, or have changed
processes. Plants using incinerators
were excluded because it was assumed they
were already affected by another
regulation.
Two (2) plants (#1007, terephthalic acid
and #902, cyclohexanone) use water
scrubbers and require approximately 55
percent reductions to attain the TRE
cutoff point. Another cyclohexanone plant
(#903) using a water scrubber requires a
64 percent reduction. These were excluded
because most VOC emitted from these plants
is insoluble and would probably not be
collected.
One (1) terephthalic acid plant (#1004)
uses carbon adsorption to achieve a
97 percent VOC reduction (based on model
plant); this plant needed a 39 percent
reduction to reach the cutoff point. It
was deemed unlikely that an additional
39 percent could be attained at a
reasonable cost.
F-25
-------
TABLE 3. SUMMARY OF 59 PLANTS FROM PROFILE (Continued)
No. Plants
Category
Remarks
1.0 < TRE <2.9
Two (2) formaldehyde plants (#1407 and
#1420) using product absorbers with no
additional VOC control were estimated to
require a 45 percent VOC reduction to
reach the cutoff point. Two (2) other
formaldehyde plants (#1403 and #1404)
were estimated to require a 1 percent
reduction. The formaldehyde product
report states that one manufacturer uses
a water scrubber following the product
absorber which achieves a 74 percent VOC
reduction. It was assumed that these
plants could potentially do the same at a
substantially lower cost than that asso-
ciated with adding a thermal incinerator.
One (1) terephthalic acid plant (#1005)
using absorption needs a 20 percent VOC
reduction to reach the cutoff point.
This plant was determined to have the
potential for process modifications
because a manufacturer in the industry
using the same process and control
achieved a 36 percent VOC reduction by
adding plates in the absorber.
One (1) acetic acid plant (#205) uses a
water scrubber and needs a 51 percent VOC
reduction. This plant was determined to
be a marginal, but likely case for
process modifications based on the fact
that the vent from this scrubber contains
a soluble component and the soluble
component in the offgas is present at a
higher concentration than the non-soluble
component.
F-26
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REFERENCES
1. SRI International. 1983 Directory of Chemical Producers. California,
SRI International. 1097 pp.
2. Dylewski, S. A., 1979. Emissions Control Options for the Synthetic
Organic Chemical Manufacturing Industry. Crude Terephthalic Acid
Product Report. EPA Contract No. 68-02-2577. Emission Standards and
Engineering Division, Office of Air Quality Planning and Standards.
Research Triangle Park, North Carolina. June 1979.
3. Blackburn, J. W., W. D. Bruce, V. Kalcevic; 1980. Organic Chemical
Manufacturing. Volume 6: Selected Processes (Cyclohexanone).
EPA-450/3-80-028d. Emission Standards and Engineering Division.
Office of Air Quality Planning and Standards. Research Triangle Park,
North Carolina. 2-i. December 1980.
4. Lovell, R. J., 1980. Organic Chemical Manufacturing. Volume 9:
Selected Processes (Formaldehyde). EPA-450/3-80-028d. Emission
Standards and Engineering Division. Office of Air Quality Planning and
Standards. Research Triangle Park, North Carolina. 1-i.
December 1980.
5. Key, J. A., 1980. Organic Chemical Manufacturing. Volume 10:
Selected Processes (Acetic Acid). EPA-450/3-80-028e. Emission
Standards and Engineering Division. Office of Air Quality Planning and
Standards. Research Triangle Park, North Carolina. 9-i.
December 1980.
6. U. S. Environmental Protection Agency. Control of Volatile Organic
Compound Emissions from Air Oxidation Processes in Synthetic Organic
Chemical Manufacturing Industry. Draft Control Techniques Guidelines.
7. Radian Corporation, 1978. Control Techniques for Volatile Organic
Emissions from Stationary Sources. EPA-450/2-78-022. Emission
Standards and Engineering Division. Office of Air Quality Planning and
Standards. Research Triangle Park, North Carolina. May 1978.
F-27
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APPENDIX G: PUBLIC COMMENT LETTERS ON THE DRAFT CTG
-------
CHEMICAL MANUFACTURERS ASSOCIATION
April 26, 1984
Mr. Robert Rosensteel
Chemicals and Petroleum Branch
Emissions Standards and
Engineering Division (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
Re: CMA informal comments on EPA's Draft Control Techniques Guideline
(CTG) Document for control of Volatile Organic Compound Emissions
from Air Oxidation Processes in the Synthetic Organic Chemical
Manufacturing Industry.
Dear Mr. Rosensteel:
The Chemical Manufacturers Association (CMA). a nonprofit trade
association whose member companies represent more than 90% of the
production capacity of basic industrial chemicals within this country,
submits the following informal comments on EPA's Draft Control
Techniques Guidelines (CTG) Document for Control of Volatile Organic
Compound Emissions from Air Oxidation Processes in the Synthetic Organic
Chemical Manufacturing Industry, 49 Federal Register 8077 (March 5,
1984). Our comments/submitted today do not address all the issues
covered in this CTG: Therefore, we reserve the right to submit
additional comments as part of the future regulatory activity on this
matter. These comments were prepared after deliberation and
consultation among CMA members.
Many CMA member companies use or anticipate using chemical man-
ufacturing air oxidation unit processes that could be covered by the
proposed CTG. Accordingly, CMA has a direct and vital interest in the
content of the draft CTG as it will affect the implementation of the
proposed Air Oxidation New Source Performance Standard.
To the extent that the draft CTG document establishes a pattern for
future EPA control techniques guidelines, CMA is concerned that in
numerous respects, as described in the following paragraphs, the draft
document is technically unsound. CMA has six principal concerns with
the draft CTG:
G-l
Formerly Manufacturing Chemists Association—Serving the Chemical Industry Since 1872.
2501 M Street NW • Washmoton DC 20037 • Telenhon* ?02/B87-HOO • T»I»» «ofii?
-------
1. Inadequate general discussion.
Th« general discussion covering the Air Oxidation Industry is
vague. It does not adequately detail what the industry is or where
it is. Some of the information that is presented is incorrect and
misleading. For example, on page 2-6, Amoco-Standard Oil is listed
as manufacturing acetone and phenol. The statement is not correct.
Again, on page 2-13, Amoco-Standard Oil is listed as producing
acetone and phenol in Richmond, California. Amoco not only does
not manufacture these materials, but there is no Amoco-Standard Oil
facility in Richmond, California.
The chemicals covered by this CTG have been listed in an inappro-
priate way. The list is given as not being exclusive. This
creates a certain amount of uncertainty as to which chemicals are
coveted. This ambiguity can be easily taken care of by giving an
all-inclusive list for which this CTG applies. This has been done
in the past, as in the VOC Equipment Leaks (Fugitives) NSPS. The
burden should be on the Agency to declare beforehand what chemicals
will be controlled and not for the regulated community to guess
whether or not they are covered. On page 3-29, in a discussion of
existing state regulations, the document unfortunately
misrepresents the regulatory situation in Illinois. In fact, the
Illinois rule requires emissions to meet one of three control
levels: 1) 8 pounds/hour, 2) 10 ppmv equivalent methane, or 3) 857,
destruction. We recommend the Agency clarify these points.
2. Inadequate definition of vents controlled.
The present language in the draft CTG does not clearly indicate
which vents are.to be controlled. A reactor system may have a
bottoms stream which is liquid or solid with entrained air. This
stream is processed through product purification operations which
may subsequently have a small vent. This CTG was not intended to
cover these vents; it was intended to cover vents from the vapor
stream of the reactor. The document should be revised to so
reflect this point.
The document, as presently written, does not address the situation
where the reactor vapor stream is vented from more than one place.
For example, the gas may vent through two scrubbers in a series.
The vents should be treated separately for calculating the Total
Resource Effectiveness (TRE) index. This needs to be clarified;
otherwise, highly efficient multi-stage product recovery
technologies or control techniques may be unnecessarily
discouraged. A similar situation occurs when a side stream is
drawn off of the vent for some other purpose, such as use as a
conveying gas. The inclusion of vents from other uses could be
unrealistically restrictive in calculating the TRE index and
prescribing control requirements.
G-2
-------
3. Inadequate consideration of alternative control technologies.
The CTG states, "The choice of thermal oxidation as the single
control technique for analysis yields conservative estimates of
energy* economic, and environmental impacts since thermal oxidation
is relatively expensive and energy-intensive." While agreeing with
this statement, it is not true that the control efficiency of
thermal oxidation is much less dependent on process and waste
stream conditions than are other control techniques nor is thermal
oxidation economically applicable to all Synthetic Organic Chemical
Manufacturing Industry (SOCMI) air oxidation processes.
Destruction efficiency will depend on flame stability which, in
turn, depends on composition, heating value and flow rate of the
waste stream. Variations in these must be taken care of with
auxiliary fuel. Some process conditions will not lend themselves
to efficient operation of thermal oxidation and, therefore, other
control techniques should be used and encouraged. The draft CTG
does not adequately address alternative technology strategies which
might be more effective; we strongly recommend the draft CTG be
modified to address this matter.
4. Unrealistic economic considerations.
The economic impact of emission controls are underestimated.
First, the draft CTG Ignores the costs of siting, utilities,
services, connections and R&D. The addition of a thermal oxidizer
to an existing facility can sometimes be facilitated by using
existing services. However, many times the unit must be placed at
some distance from the vent source and requires considerable
expenditure for siting, utilities and connections. The cost
summary also assumes that the disposal cost of NaCl from scrubbers
is insignificant. If the disposal is even possible, a discharge
permit is generally required which will require monitoring and
control for pH, total dissolved solids (TDS) and organics. The
cost of such treatment and disposal is not insignificant. The
analysis also assumes a substantial energy credit in many cases.
In many processes, especially halogenation, energy recovery is not
feasible. In other processes where energy can be recovered as
steam, the steam generated would be low pressure steam which may
have no economical use within the process. For these reasons, the
costs associated with thermal oxidation have been understated. It
will cost considerably more than the EPA estimate to accomplish the
emission reductions proposed in this document. We recommend EPA
reconsider these economic costs and correct the CTG.
5. Unclear use of TRE cutoff.
We strongly support the cbncept of using the TRE index for defining
appropriate control technology. Nevertheless, additional
clarification is needed. Examples and explanations of how to use
and apply the TRE need to be included. On page 5-26, it should be
clarified that "E" (hourly emissions) is Just the VOC emissions and
"Flow" is the total flow of the vent stream.
G-3
-------
On page D-l, the document states that reasonably ava lable
control technology (RACT) requires no additional control in a
situation where the TRE is greater than 2.9. Then on page
E-2, in a discussion of the TRE, the cutoff if given as 1.0.
This is confusing. A TRE cutoff calculation is a reasonable
approach to evaluating alternative control techniques and
determining if control is necessary. CMA recommends that the
draft CTG be clarified as to the intended use of the TRE Index
and identify the " no additional control" RACT cutoff.
6. Typographical error on Page E-3.
It appears there is a typographical error on page E-3. We believe
that line A2. should read:
11 For Chlorinated Process Vent Streams, if 3.5 Net Heating Value
We submit these comments for your serious consideration and appro-
priate revision and development of a revised "CTG for Control of
Volatile Organic Compound Emissions from Air Oxidation Processes In the
Synthetic Organic Chemical Manufacturing Industry." We would be pleased
to discuss our informal comments with the Agency's personnel or furnish
further supporting data. For additional information, please do not
hesitate to call me at (202)887-1178.
Sincerely yours,
Robert R. Romano, Ph.D.
Manager - Air Programs
G-4
-------
Diamond Shamrock
Chemicals Company GU« coast
April 18, 1984
Mr. Robert Rosensteel
Emissions Standards and Engineering Division (MO-13)
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
RE: Draft Control Techniques
Guideline (CTG)
Air Oxidation Processes in the SOCMI
Dear Mr. Rosensteel:
The attached are comments submitted by Diamond Shamrock Chemicals
Company on the above referenced draft CTG. We appreciate the opportunity to
review this document. We hope that our comments will be carefully
considered and acted on by your office. Should you have any questions on
our submission, please contact me at (713) 476-1247 or the letterhead
address.
Sincerely,
M. M. Skaggs, JrC, P.E.
Senior Environmental Engineer
MMS/bh
Attachment
G-5
Diamond Shamrock Chemicals Company A SuDsifliary ot Diamond Shamrock
1149 eiisworrn Drive. Pasaoena. Texas 77501 Pnonr 713476-2000
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COMMENTS ON MARCH, 1984 DRAFT DOCUMENT ENTITLED
"CONTROL OF VOLATILE ORGANIC COMPOUND EMISSIONS FROf;
AIR OXIDATION PROCESSES IN SYNTHETIC ORGANIC
MANUFACTURING INDUSTRY"
Diamond Shamrock Chemicals Company (DSCC), a wholly owned subsidiary of
the Diamond Shamrock Corporation, owns and operates 29 domestic plants in 10
states. One of these plants is an oxyhydrochlorination plant producing
1,2-dichloroethane (EDC) in Deer Park, Texas. These comments are submitted
because of the impact that this draft CTG could have on our Deer Park
operations. The comments made below are divided into two sections -
Technical Comments and Cost Analysis.
DSCC supports the concept of using sound technical data in the
development of these CTG's, as well as the use of cost effectiveness
indexing, in determining when they should be applied. To this end, we
complement the technical work done to date on this document and on the
development of the TRE concept. We believe it is imperative that, where the
EPA is formulating major new VOC emissions reductions, the EPA should also
provide the technical means to obtain these reductions. The result
otherwise will be (and has been) inequitable across-the-board required
reductions, which generate widely varying costs per ton in the different
affected industries and facilities.
• It is with some regret, therefore, that we must raise several serious
objections to this draft document. At least two viable control schemes were
either omitted or not seriously considered in drafting this document. In
G-6
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addition, the proposed TRE scheme suffers from both theoretical and
empirical flaws. These two areas of deficiency form the bulk of our
comments on this proposal. They should be seriously addressed and undergo
additional public review before the CTG is finalized.
Technical Comments
1. A 95% control efficiency should be adopted as RACT.
This draft document proposes to use 98% as the control efficiency which
qualifies as R.A.C.T. This figure was selected because it seems to be
achievable in all conventionally fired vent gas incinerators. The reason
why 98% was selected over some nominally lesser figure (such as 95%) was not
stated. If a slightly lower figure was selected instead, the regulated
companies would have a choice of three acceptable control schemes instead of
only one. These three options would include thermal oxidation, catalytic
incineration, and flares. The 95% figure suggested in our comments should
be reviewed by EPA and revised up or down in such a way as to include all
three technologies.
We recommend that the EPA choose a figure such as 95% as the selected
RACT control efficiency. Such a revision would allow the affected companies
to choose between the alternatives based on a proper blend of capital
availability, operating costs, and process requirements. Allowing a wider
choice of control alternatives would allow more facilities to meet the less
than $l,600/Mg. criteria. Since more facilities probably would be
installing controls, greater emissions reductions would result. Thus,
selecting a 95% cut-off figure would be better for both the regulated
community and the regulators.
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2. Flares should be included as one of the control measures.
Flares are a very economical and efficient means of controlling off-gas vent
emissions of hydrocarbons. Recent work conducted by the EPA and CMA have
demonstrated the high organic destruction efficiencies of flares. Flares
are much less expensive to construct and maintain than are "thermal
oxidation" units (incinerators). It makes little sense, if a flare may be
erected for $100,000 and produce a 95% control efficiency, to require a
$5,000,000 incinerator to be installed in order to achieve a 98% efficiency.
The last 3% of reductions come at an extremely high price. As our comments
below explain, such alternative control schemes should be compared to
determine the cost per additional ton removed.
3. Catalytic Incinerators Should Qualify as RACT.
The development of effective catalytic incineration technology during the
mid-to-late 1970's was a very important technological advancement. This
technology allowed vent gases to be efficiently destructed at one-third or
less of the energy input necessary for thermal incineration. The text of
the subject draft makes it appear that the 98% figure was selected
specifically to exclude catalytic incineration. The additional 1 - 3%
removal efficiency provided by thermal incineration is only achieved at the
expense of large quantities of energy consumption. This decision seems to
be totally at odds with a national energy policy which spends over $40
billion/year attempting to conserve energy (DOE).
The emission reductions represented by 98% (over 95%) efficiency are
not likely to result in any detectible environmental benefits. Since the
G-8
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"low cost" gas of the past is no longer available, at least some of the
newly constructed thermal incinerators will burn either fuel oil or coal.
The S0~, NO , and particulate emissions from these units are likely to
b A
be quite large compared to this 1 - 3% VOC reduction. If only a few of
these units could be encouraged to use catalytic incineration (over thermal
incineration), some quite measurable environmental impacts may be avoided.
We believe that the EPA should be encouraging, not discouraging, catalytic
incineration.
4. OHC-EDC plants should not be included in this CTG.
We fail to understand why OHC-EDC plants are to be regulated under this CTG.
The chlorinated solvent industry presents fundamentally different vent
control problems from other non-halogenated processes noted. Additionally,
all but two of the affected EDC plants are presently located in Texas and
Louisiana, where vent incineration is already required (per this Draft).
One of the other two plants is located in California and is already subject
to very stringent regulation. We believe that the lone remaining facility
in Kentucky would best be addressed through that State's SIP process (if
there is environmental cause to do so).
5. NO Emissions from coal combustion are independent of fuel nitrogen.
NO Emissions from coal combustion are erroneously attributed to fuel
nitrogen content on Page A-21. These emissions are conventionally thought
of as being independent of fuel nitrogen. Technical literature as recent as
August, -1982 provides support for the AP-42 position (see "A Promising
NO^-Control Technology", Environmental Progress, August, 1982, Page
167-177). If the EPA has new data which revises this position, DSCC would
be most interested in reviewing it.
G-9
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6. Gross omissions exist at Page 3-18.
Material was omitted from this draft in the catalytic incineration section
(Pages 3-17 to 3-19). Since this section was of primary importance to OSCC,
we request that we be sent a revised copy of this document and that the
comment period be reopened to allow review of this section. The nature of
the omission makes it impossible for us to speculate how much material was
omitted. The fact that the pages are sequentially numbered (without any
numbers being missing) indicates that everyone reviewing this document were
unable to review this important section.
7. Table 2-6 contains inaccurate information.
Diamond Shamrock Corporation sold its La Porte, Texas EDC/VCM facility to B.
F. Goodrich Corporation during 1981. Please correct this entry, as well as
the corporate name (to Diamond Shamrock Chemicals Company) of our Deer Park
Plant.
8. The Draft document provides conflicting TRE index cutoff values.
The Draft document states, in Section 5 and Appendix E, that all plants with
a TRE index less than 1.0 would be required to install RACT. Appendix D
states that this cut-off value will be 2.9. We are unable to resolve this
discrepancy, but we feel that any control costs beyond the presently
proposed Sl,600/Mg. would be excessive.
G-10
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Cost Effectiveness Comments
The Index formula, as proposed, is fatally flawed.
DSCC strongly supports the concept of selecting national and state air
emissions control regulations based on cost impact. A cost per unit of
production scheme would certainly seem to be the most equitable means of
analyzing air pollution control strategies. Such a scheme would allow a
clear examination of the resources being invested in controlling these
emissions. Costs incurred in controlling emissions are passed on to the
consumers. A cost per unit of production guideline would present sxich
regulations in their true light - they are a tax on the consumer. Short of
the adoption of this alternative approach, regulations should be based on a
cost per ton of additional pollutant removed.
The TRE approach seems to be a plausible means of assessing the cost
effectiveness of the proposed controls. As presented in this draft,
however, the TRE has four significant flaws. These flaws include outdated
costs, a lack of flexibility, ignored expenses, and an inability to look at
the incremental cost aspects of the alternatives. These concerns are
discussed below.
1. Out-of-Date Costs
The cost factors used in this proposed formula have not been examined
in five years (although they were uniformly inflated to 1980 levels). The
market forces of the past five years have been unparalleled in our country's
history. Adopting a CTG based on such outdated costs is poor scientific and
technical practice. The formula should be revised to allow the use of the
G-ll
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present and reasonably projectable future costs, based on the date of
application.
2. The TRE formula is unacceptably inflexible.
The TRE formula also erroneously assumes that labor and energy costs are
uniform nationwide. It seems indefensible to require a company to calculate
their "control costs" based on $11.10/hour wages and $2.40/MCF gas prices
when they are actually paying $!8.00/hour and S5.67/MCF. Energy, labor, and
electricity ccrsts all probably vary by a factor of at least two fold within
the EDC producers group alone. The use of the TRE formula should be revised
to allow a company to use its true costs. If the regulation is intended to
measure the "cost effectiveness" of the regulation, the TRE formula must be
changed in this way.
3. The TRE index formula simply ignores several expenses.
The TRE index ignores or virtually ignores several costs. These significant
costs should be included in the revised CTG. These costs include the
following:
a) Wastewater treatment expenses (steam, neutralization expenses,
equipment, labor, etc.);
b) Carbon steel could not reasonably be used in the majority
of the affected EDC plants;
c) Heat recovery unit downtime (15S);
d) Maintenance costs (should be at least 10% per year).
G-12
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8
e) Operating Supplies (20% of operating labor);
f) Laboratory Expenses (15% of operating labor; and
g) Utility hookup, site development, process connection piping, and
land costs.
These costs should be included in the final TRE formula.
4. Incremental Cost Effectiveness
The TRE formula fails to examine the cost effectiveness problem from a
logical standpoint. To look at cost effectiveness correctly, one must
compare the cost required to remove the last ton of a pollutant as well as
the average cost per ton (present proposal). This problem can best be
understood by looking at the following example. T) Assume that control
Strategy A will remove 95% of a 1,000 TPY VOC source's emissions at a cost
of $475,000 per year. Thus, Strategy A has a cost per ton removed of
$500/ton and removes 950 TPY. 2) Assume that control Strategy B removes
98% of a 1000 TPY source at a cost of $1,500,000 per year. Thus, Strategy B
has a cost per ton removed of $1,520 (removes 980 TPY) and also easily falls
within the CTG. 3) Note, however, that the last 30 TPY were removed at a
cost of $1,025,000 per year, or at a cost of 534,167 per ton!
The above example demonstrates the problems associated with not
comparing incremental control costs of the various control schemes. The
removal of the last 30 tons is obviously a very poor investment of
resources, and is unlikely to contribute to any discernable environmental
improvement. The above example shows precisely why catalytic incineration
should be re-examined as being RACT, and why we support the use of a 95*
or similar technically supportable control limit.
G-13
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Summary
OSCC strongly supports the development of cost-based air pollution
control regulations, but we are just as strongly opposed to the use of
faulty "cost effectiveness" evaluation procedures. We request an impartial
review of the data in this Draft CTG and in other EPA air programs offices
from an incremental cost standpoint. We believe that once these economics
are re-examined, it will be obvious that the cost of going from a 952 to a
98S control efficiency is extremely high. We, therefore, request that RACT
be set at a level that will allow catalytic incinerators and flares to also
be considered. Such a level would allow impacted companies to select the
control method best (most economically) suited to their operational setting.
By allowing the use of the strategy best fitted to individual operations,
the EPA should reduce the number of companies avoiding control through the
TRE escape formula. Such an approach might also avoid some of the SO-,
NO , and TSP emissions which will result from thermal incineration by
allowing the use of catalytic controls.
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ETHYL CORPORATION
COKPOBATZ
TO: • o. BOX »»i
.... „-„, BATON »OUOC. LA.70«Zt
March 28. 1984
Emission Standards and Engineering Division (MD-13)
Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Re: Guideline Series — Control of Volatile Compound
Emissions from Air Oxidation Processes in
Synthetic Organic Chemical Manufacturing
Industries Draft Document
Attention: Mr. Robert Rosensteel:
Dear Mr. Rosensteel:
This document lists two Ethyl facilities in Table 2-6.
page 2-18, as manufacturing sites for 1,2 Dichloroethane by the
air oxidation process. This is incorrect.
In January, 1983. the 1,2 dlchloroethane air oxidation
process unit In Baton Rouge. Louisiana was shut down. The
manufacture of 1,2 dlchloroethane at Pasadena, Texas does not
employ air oxidation and uses alternative technology.
Please incorporate these changes in future revisions
of the document.
Sincerely.
D. E. Parfc. Director
DEP:j td
cc: J. W. Parson
W. F. Gafford
G-15
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Standard Oil Compar- .idiana)
20C East Random Drive
Chicago Illinois 5C601
3:2-356-2506
j. 0.
Qtntttt Manager. Environmental
Attars & Saletv
April 19. 1984
Emission Standards and Engineering Division (MD-13)
Environmental Protection Agency
Research Triangle Park, NC 27711
Attention: Mr. Robert Rosensteel
Sir:
Control Techniques Guideline Document; Air Oxidation Processes in the
Synthetic Organic Chemical Manufacturing Industry; Draft Document for
Public Review;
49 Federal Register 8077. March 5, 1984
Standard Oil Company (Indiana), on behalf of its Amoco subsidiaries,
appreciates this opportunity to comment on the draft Control Techniques
Guideline Document for volatile organic compound emissions from air
oxidation processes in the synthetic organic chemical manufacturing
industry. As indicated in the Federal Register notice, Control Technique
Guideline (CTG) Documents are meant as informational material for use by
the states in determining the appropriate controls for various stationary
sources in nonattainment areas. Both the states and industry use these
documents to determine which sources are subject to control under an
emissions reduction program. Therefore, the documents must be accurate and
clear. Our review has shown this document to be deficient in both these
areas.
This CTG focuses on the volatile organic compound control techniques for
air oxidation unit process vents in the synthetic organic chemical
manufacturing industry, and concludes that thermal oxidation is the only
demonstrated technology universally applicable. In this analysis, the
document never fully explains the scope of the potential regulation.
Neither the chemicals produced by the air oxidation process nor the
emission points potentially subject to control are clearly enumerated. The
published list of chemicals (page 2-2) is described as "not exclusive."
Thus, if a plant does not produce any chemical on the list, it cannot be
certain that it is not covered. In addition, the description of the
industry which does appear in the document is not completely accurate. For
example, "Amoco-Standard Oil" is listed as a producer of acetone (page
2-6). In fact, Amoco does not have any plants which produce acetone. In
view of these deficiencies, the CTG cannot be considered affective guidance
for the states. We suggest that EPA include a list of chamicals, similar
td that published for the New Source Performance Standards from SOCMI
Distillation Units (48 Federal Register 57538), in the final guidance
document.
6-16
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PAGE 2
As described in this document, the need for application of thermal
oxidation technology to process vents is determined by the associated total
resource-effectiveness index (TRE) calculated for a given unit. That is,
thermal oxidation is recommended only where the process flowrate, VOC
emissions, corrosion properties, net heating value, and economics combine
to make its application "reasonable." However, the document fails to
clarify the vents for which this calculation should be made. For example,
Figure 2-2 (page 2-31) illustrates a vapor phase air oxidation process.
There appear to be two vents for gases leaving the unit: one described as
"off gas" and one from the product purification section. From discussions
with the Agency, we understand that the vent from the product purification
step would not be covered by this regulation. However, the CTG itself does
not make this differentiation of vents clear.
This lack of clarity is further compounded by multiple-step process stream
vents. For example, off gas is frequently split at the end of a unit
process. Some gas passes through a scrubber and is vented. The other
portion is used as a carrier gas, and passes through to a storage vessel
and scrubber before venting. Thus, there are essentially two vents for one
process stream. These atmospheric vents either could be calculated
individually and added together or could be calculated as a unit by adding
the flourates, emissions, and heating values before application of the TRE
equation. Again, although discussions with the Agency have led us to
believe that the vents should be calculated individually, we can find no
justification for this in the document. We urge EPA to clarify the means
for application of the TRE calculation in the final CTG document.
In conclusion, Standard Oil Company (Indiana) believes the CTG document for
VOC emissions from air oxidation processes does not provide adequate
guidance for states to use in developing their control strategies.
Furthermore, our analysis of the data indicates that fewer than 25 plants
have the potential to be controlled more effectively under the CTG
guidelines than under present controls. We, therefore, question the need
for this particular CTG and suggest the Agency concentrate its resources on
developing regulations with more potential benefit.
Sincerely,
J. D. Reed
CEC/ts
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UP TEXAS CHEMICAL COWNCIL
1000 BRAZOS, SUITE 200, AUSTIN. TEXAS 78701-2476, (512) 477-4465
April 9, 1984
EMISSION STANDARDS AND ENGINEERING DIVISION (MD-13)
U. S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, N.C. 27711
ATTN: MR. ROBERT ROSENSTEEL
RE: COMMENT ON THE DRAFT CTG' DOCUMENT, AIR
OXIDATION PROCESSES IN THE SYNTHETIC
ORGANIC CHEMICAL MANUFACTURING INDUSTRY
Dear Mr. Rosensteel:
Because there was a couple weeks delay in getting copies of
the subject CTG from the Library, Texas Chemical Council (TCC) member
companies are late in reviewing and getting comments
to the EPA. TCC requests an extension until May 1st
mission of comments.
in for submittal
for the sub-
Thank you
A. H. Nickolaus
Chairman, CTG Subcommittee
cc: J. B. Cox - Exxon
R. R. Romano - CMA
AHN/cgh
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IJUP UP
TEVAO CHEMICAL COUVCIL
1000 BRAZOS. SUITE 200, AUSTIN, TEXAS 78701-2476, (512) 477-4465
April 24, 1984
EMISSION STANDARDS 4 ENGINEERING DIVISION (MD-13)
ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, N.C. 27711
Attn: Mr. Robert Rosensteel (2)
RE: Comments on the Draft CTG;
Air Oxidation Processes
Dear Mr. Rosensteel :
Attached are comments by the Texas Chemical Council on the
subject Control Technique Guideline.
Si ncerel y yours ,
A. H. Nickolaus
Chairman, CTG Subcommittee
cc : J . B. Cox
T. E . Li ngaf el ter
R. R. Romano
TCC Files
Exxon
Dow
CMA
AHN/cgh
Attachment
6-19
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COMMENTS BY THE TEXAS CHEMICAL COUNCIL
ON THE DRAFT CONTROL TECHNIQUE GUIDELINE (CTG)
FOR CONTROL OF VOLATILE ORGANIC EMISSIONS FROM
AIR OXIDATION PROCESSES IN THE SYNTHETIC ORGANIC
CHEMICAL MANUFACTURING INDUSTRY (SOCMI), MARCH, 1984
The Texas Chemical Council (TCC) is an association of 83
chemical companies having more than 70,000 employees in Texas and
representing approximately 90% of the chemical industry in the State.
Ovar 251 of the nation's air oxidation plants are located in Texas sn
the proposed CTG is of vital concern to us.
I . Cc_ncerns
The TCC's major concerns are:
e The draft CTG does not fulfill its stated purpose (page
1-1) of providing "State and local air pollution control
agencies with an initial information base for proceeding
with their own analysis of Reasonably Available Control
TechnoTogy (RACT) for specific stationary sources"(under-
1i ning added). No basis for the determination of RACT is
given. Instead RACT requirements are dictated without
explanation in Chapter 4.
9 The $l,600/Mg annual cost cutoff ($l,450/ton) is ex-
cessively expensive and, on the average, exceeds the cost
of supposedly more stringent New Source Performance
Standards (NSPS).
e The cost cutoff is understated. It is in June, 1980
dollars and is equivalent to $l,970/Mg today. Further,
cost-s are underestimated. The Total Resources Effective-
ness (TRE) calculation ignores items of appreciable cost so
that it underestimates actual costs by 50%. TCC estimates
the actual cutoff cost in current dollars to be $2,950/Mg.
9 There are inexplicable inconsistencies between the factors
used for the TRE calculation in this CTG and those used in
the recently proposed Air Oxidation NSPS (Reference 1). •
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11. Recommendations
• EPA should explain how they arrived at their RACT defi-
nition and provide more guidance to states on how they
expect them to apply it to individual situations.
• An annual cutoff cost in the range of $500/Mg in current
dollars is recommended as being consistent with existing
State Implementation Plans and average NSPS costs.
• The TRE calculation should include the cost elements
discussed in Section III C.
• The factors used in the CTG and NSPS TRE calculation should
be consistent. TCC recommends the factors from Table 8-3
of the Polymer/Resin NSPS (Reference 8).
III. Discussion
A. The Draft CTG Does Not Fulfill Its Stated Purpose.
After noting that State Implementation Plans (SIPs) must
include RACT, the introduction to the CTG states (page 1-1)
that "the purpose of CTG documents is to provide State and
local air pollution control agencies with an initial infor-
mation base for proceeding with their own assessment of
RACT for specific stationary sources" (underli ni ng added}.
The CTG does not do this. Instead, RACT requirements are
dictated without explanation in Chapter 4. No basis is
given there for the definition of RACT, what alternatives,
if any, were considered is not mentioned, what cost guide-
lines were followed is not explained, and no guidance use-
ful to "State and local air pollution control agencies ...
for proceeding with their own analysis of RACT ..." is
supplied. Further, it's virtually impossible for a State
to show that any differing state regulation is within 5% of
EPA's RACT which, we understand, was required for the 1979
SIPs. Thus the EPA is, in effect, rule-making without
going through the rule-making process.
B. The $l,60Q/Mg Cutoff (Sl.970/Mg In Current Dollars) Is Too
Hi gh.
EPA has used a $l,600/Mg cutoff in June, 1980 dollars as
the annual abatement cost which is equivalent to a TRE
Index of 1.0. Thus, using the standardized TRE cost calcu-
lation, any vent stream with an annual abatement cost less
than $l,600/Mg (June, 1980 dollars) must be abated-. This
cost 1s too high.
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1. What Kind Of Dollars Is EPA Talking About?
Clarification of what kind of dollars the EPA is
talking about is needed before discussing why their
cutoff figure is too high. The dollars in this CTG
are June, 1980 dollars. This is not made clear in the
text and is misleading since the normal presumption in
the absence of a specific note is that the dollars are
current with the publication date. Using the implicit
GNP deflator, $l,600/Mg in June, 1980 becomes about
$l,970/Mg now. An appreciable difference!
2. Why A Cutoff Of $1,600 (June '80$)/Hg Is Too High..
In discussing the cutoff for the Air Oxidation NSPS
(Reference 3) EPA admits that "in prior source cate-
gories for which NSPS have been developed, VOC maximum
estimated control costs have generally not exceeded
$1,000 per megagram." Why then is EPA proposing a CTG
that is more costly than supposedly more stringent New
Source Performance Standards? In the Air Oxidation
NSPS EPA felt obligated to justify their proposed
cutoff figure. Surely they owe the public as much
here. Incidentally, TCC found EPA's NSPS explanation
totally unconvincing as was explained by our comments
in Reference 4.
The $l,600/Mg figure is also out of line with present
State RACT regulations. In 1982 Texas had to revise
their ozone SIP for Harris County to provide addition-
al reduction of Volatile Organic Compound (VOC)
emissions. They first prepared a list of emitting
sources, next they estimated abatement costs (Refe-
rence 2), and then regulated those with the lowest
cost. Additional regulations for the chemical indus-
try were in the $200-$300/ton range with the highest
being $S32/ton for vents from carbon black manufactur-
ing - a maximum equivalent to $8107Mg in June, 1980
do!1ars .
C. The TRE Calculation Underestimates Actual Costs
The TRE calculation ignores capital and annual items of
appreciable cost so that it underestimates actual costs.
G-22
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- 4 -
1. Capital Costs
EPA's estimates of capital costs appear to be reason-
able for those elements they cover. It's those they
don't that make their estimates less than actual in
many cases. Page 5-9 of the CTG states that EPA's
costs "do not include the provisions for bringing
utilities, services, or roads to the site, the backup
facilities, the land, ... or the process piping and
instrumentation interconnections that may be required
within the process generating the waste gas feed to
the thermal oxidizer." Yet all these facilities, and
others, are required to make a system that will
operate.
TCC compared capital costs for actual flare systems
against those estimated by the EPA in the preliminary
draft Polymer/Resin NSPS (Reference 5} and found that
EPA's estimates for intermediate sized systems were
about 25% low. Simarily, piping costs on a comparable
basis were 12% to 25i below actual. TCC noted in
these comparisons the importance of items not included
in the estimate. Then on March 9, 1984, as part of
their comments (Reference 6) on the proposed Distil-
lation Unit Operations NSPS, TCC provided a detailed
estimate for a flare system for one of EPA's sample
cases. TCC's estimate compared to EPA's was:
MS (1st Qtr. 1984)
Flare
Piping
Necessary Items Not
Included by EPA
Total 388 112.5
* Costs escalated from CE Fabricated Equipment Index
of 244 in 1978 to estimated 331 in 1st Quarter 1984
G-23
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The 'magnitude of necessary items not included ir EPA's
estimate is disturbing. Time and the absence of
de.sign algorithms in this CTG have preve.ced the TCC
from making a similar estimate and comparlsor for
thermal incinerators, but such an independent estimate
needs to be made.' We urge the EPA to have the example
case in Appendix E estimated by a large construction
firm that both designs and builds chemical plants.
The estimate should i nclude al1 those elements that
are necessary to make the system operable.
In their estimate, EPA allows for only 150 feet of
ductwork between the source and the thermal oxidizer.
TCC believes costs should be estimated based on 300 to
500 feet of ductwork with pipe bridge. On June 1,
1974, an explosion occurred at a chemical plant in
Flixborough, England, killing 28 people and causing
over 80 million dollars in damage. It was caused by
leakage of cyclohexane vapors from an oxidation unit
and their subsequent ignition by a source some
distance away. The potential for such a massive ex-
plosion from this type of process had not been fully
appreciated by the chemical industry. As a result,
many owners would be unwilling to locate an ignition
source as large as an incinerator as close to process
buildings as 150 feet. Thus 300-500 feet would be a
more representative figure.
Annual Costs
EPA ignores several items of appreciable cost in its
estimate of annual costs. These include: operating
supplies, laboratory costs, engi neeri ng/envi ronrrent al
oversight, and some general plant overhead it errs. A
comparison of annual costs as estimated in this CTG
and by TCC is given in attached Table 1. Discussion
of cost elements not included by EPA is given below.
Operating Supplies
In addition to maintenance materials, operattng
supplies are also necessary. These include such
items as charts, lubricants, test chemicals,
personal safety equipment, custodial supplies,
and similar materials which cannot be consicered
raw materials or maintenance and repair materi-
als. At one large Texas SOCMI plant these
factors ranged from 9-33% of operating labor for
six SOCMI processes. For the powerhouse, r'actors
were 15-20% of operating labor over a three year
period. See also Reference 7, page 201.
G-24
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b. Laboratory Expense
Some laboratory expense is incurred by this regu-
lation and needs to be allowed for. Reference 7
recommends 10-20% of operating labor for this.
c. Technical Oversight
It may come as a surprise to the EPA but the Code
of Federal Regulations is not widely read by
production foremen and supervisors. Thus some
environmental/engineering oversight is needed for
training, monitoring oversight, filing required
reports, technical advice, etc. Total technical
costs (mechanical, chemical, environmental, etc.)
run over 25% of operating labor for many SOCMI
processes.
d. General Plant Overhead
General plant overhead covers a host of oper-
ations and services necessary for plant operation
and these are estimated in Reference 7 (page 203)
to be 50-70% of the total of operating labor pi us
supervision pj us maintenance. Some of these have
been detailed above and we presume some others
are included in the EPA's 11.10/hour (June, 1980
dollars) labor rate. Remaining unaccounted for
plant overhead costs include safety services,
plant protection, central machine shops, stores,
stenographic and mail services, purchasing,
accounting other than payroll, etc.
Recommendation
The Petroleum Refining Fugitive BID (Reference 9)
adds a 40% of operating and maintenance labor
factor to cover administrative and implementation
costs. The TCC recommends a similar factor be
included here to cover items 'b1 through 'd'
above.
G-25
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D. There Are Inexplicable Inconsistencies Between " is CTG And
The Proposed Air Oxidation NSPS.
The cost basis for both the CTG and NSPS are identical but
for the same example vent stream they arrive at different
costs .
Air Oxidation Air Oxidation
NSPS CTG
Cost Effectiveness, $/Mg 800 $1,136
Cost Base Year Dec. 1978 June 1980
Cost Effectiveness, $/Mg 1,095 $1,400
Indexed to Current Dollars 1st Q 1984 1st Q 1984
These differences arise from the use of different cost
factors in the TRE calculation. The factors are:
NSPS BID This CTG Enviroseience
Table 8-7 Table 5-7 (Reference ICT
Cost Base Year Dec. 1978 June 1980 Dec. 1979
perating Labor, S/hr. 13.08 11.10 $15.00
Includes Overheads? Yes Yes Not Specified
u
Electricity, S/KWH 0.02616 0.049 0.03
Natural Gas, $/GJ 4.78 2.40 2.00
Scrubbing Water, S/1000 gal. 0.22 0.79 0.25
Caustic Price, $/lb. 0.0436 0.0563 0.05
Although these are for different base years they cannot be
reconciled by any logical indexing scheme. Most are said
to have been indexed from Enviroscience data given in ,
Reference 10. These are shown but they don't make things
any clearer.
Obviously a consistent set of factors should be used but
TCC recommends none of the above. More rational and more
soundly based factors are supplied in the Polymer/Resin
NSPS (Reference 9) and TCC recommends them. They are:
G-26
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- 8 -
Cost Base Year
Operating Labor
(Includes Labor Related Overhead)
Electricity
Natural Gas
Steam
Water Price
Polymer/Res in BID
Table 8-3
June 1980
$18/Hour
50.049/KWH
55.67/GJ ($5.98/MM8TU)
$13.62/Mg ($6.18/1000 Lb.)
$0.079/M3 ($0.30/1000 Gal .)
E. Hi scellaneous
1. The CTG uses "Nm for normal cubic meters. This is
confusing since "NM is the standard symbol for
Newtons, a unit of force, in the International System
of Units per the American Society of Testing and
Materials "Standard for Metric Practice." TCC recom-
mends this be changed to something like "scm" as was
done in the Distillation Operation NSPS.
2. The CTG states that sodium chloride disposal c
insignificant in almost all existing plants.
that's why they have scrubbers already. But t
is not aimed at these. It's for plants that d
have scrubbers. In general the disposal of di
brine streams is not cheap unless the plant is
near salt water and can get a permit to dump i
brine. The Air Oxidation NSPS mentioned deep
disposal as an acceptable means. Operating co
these range from 3-6 $/l,000 gallons. If the
the scrubbing water at 79 cents (?) per 1,000
is significant enough to be included in the co
equations, then certainly the 3-6 $/l,000 gall
for disposing of the resultant brine should be
included also.
osts are
Maybe
he CTG
on1 t
1 ute
1 ocated
ts
well
sts for
cost of
gal 1ons
st
ons cost
IV. Contacts for Questions
If the EPA has questions
be glad to try to answer
Cox in care of the Texas
200. Austin, Texas 78701
about any of our comments the
them; contact A. H. Nickolaus
Chemical Council, 1000 Brazos
We can be reached by phone:
Nickolaus, 512/572-1277 (Du Pont - Victoria, Texas)
Cox, 713/425-1046 (Exxon Chemical - Baytown, Texas)
and
TCC will
or J. B.
Suite
A. H.
J. B.
AHN
G-27
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References
1. EPA Docket No. A-81-25, Proposed NSPS for Air Oxidation Unit
Processes, 48 FR 48932, October, 21, 1983.
2. Radian Corp. Report Prepared for Texas Air Control Board,
"Assessment of the Feasibility and Costs of Controlling VOC
Emissions from Stationary Sources in Harris County, Texas," July
29, 1981.
3. Reference 1, page 48942.
4. TCC Comments on Reference 1, Letter from A. H. Nickolaus (TCC)
to Central Docket Section -(A-130) dated December 22, 1983.
5. "Additional TCC Comments on the Draft Proposed NSPS for
Polypropylene, Polyethylene, Polystyrene, and Poly (Ethylene
Terephtlate) Manufacture" Letter from A. H. Nickolaus (TCC) to
Jack R. Farmer (EPA) dated June 24, 1983.
6. Letter: A. H. Nickolaus (TCC) to Central Docket Section
(LE-131), "Proposed NSPS for VOC Emissions from the SOCMI
Distillation Unit Operations," March 9, 1984.
7. Peters, Max S. and Timmerhaus, Klaus p., "Plant Design and
Economics for Chemical Engineers," Third Edition, Page 172-174,
McGraw-Hill (1980).
8. Polymer Manufacturing Industry - BID for Proposed Standards,
Preliminary Draft, EPA, March, 1983, Table 8-3.
9. VOC Fugitive Emissions in Petroleum Refining Industry - BID,
Preliminary Draft, EPA, April, 1981, Table 8-5.
10. Blackburn, J. W. (I. T. Enviroscience) "Control Device
Evaluation," July, 1980, EPA-450/3-80-026.
AHN
4/84
G-28
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TABLE 1
ANNUALIZED COSTS FOR AN EXAMPLE VENT STREAM
Stream: 284 SCM/Min. (10,000 SCFM)
0.37 MJ/SCM (10 BTU SCF)
76.1 Kg/Hour VOC Emissions
No Chlorinated Compounds in the Off-gas
June, 1980 Dollars
EPA TCC
Estimate Estimate Notes
Investment, 1,000 $ 1,718 1,976 1
Labor Rates, $/Hour 11.10 18.00 2
Annual Costs, 1.000 $
• Operations
Labor, 2,133 Hours 23.68 38.39 3
• Mai ntenance
Labor & Supplies, 3% Investment 51.54 59.28 4
Materials, 3% Investment 51.54 59.28 4
•%
• Utilities
Electricity, .049 $/KWH 12.30 12.30
Natural Gas 66.10 156.15 5
Operating Supplies, 15% Maintenance 0 17.78 6
Engineering, Environmental Laboratory 0 39.07 7
Analysis, and General Plant Overhead
Taxes 9 5% Investment 85.90 -98.80
Capital Recovery, 16.3% Investment 280.03 322.09
Total , 1,000 $ 519.55 803.14
G-29
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Table 1 • page
Notes:
1. Calculated for Category B per Table 5.5 in CTG. Investment in
TCC estimate has been increased by 15% to partly allow for
omitted items in EPA's estimate.
2. EPA labor rate from CTG Table 5-7. TCC rate from References 8
and 9 where $18.00 per hour "includes wages plus 40 percent for
1abor related administrative and overhead costs" (underlining
added) .
3. We presume the operating labor man-hours of 2,133 man-hour/.year
from Table 5-7 include an allowance for direct supervision as
was done in- References.
4. Maintenance labor plus materials factor of 6% split 50/50
between labor and materials. See Reference 7, page 201.
5. Intrastate natural gas in Texas in 1980 was about S2.60/MMBTU
but by 1983 had increased to nearly $4.00, an increase of about
50% while overall costs increased about 20%. Since energy costs
are still expected to increase faster than the general economy
the S5.57/GJ ($5.98/MMBTU) cost factor from Reference 8, Table
8-3 has been used here for the TCC calculation. S2.40/GJ was
used for the EPA estimate per CTG Table 5-7. These rates were
used to calculate electrical and natural gas costs per formulas
on CTG page E-5.
6. Taken as 15% of maintenance labor and materials per Reference 7,
page 201.
7. Per the discussion under Section C2 above, these have been taken
as 40% of operating plus maintenance labor.
AHN
4/84
G-30
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UNION CARBIDE CORPORATION
ETHYLENE OXIDE/GLYCOL DIVISION
P.O. BOX 8361, SOUTH CHARLESTON. WEST VIRGINIA 23303
April 23, 1984
Mr. Robert Rosensteel
U.S. Environmental Protection Agency
North Carolina Mutual Building
411 W. Chapel H111 Street (Room 730)
Durham, N.C. 27701
Mr. Rosensteel:
Union Carbide Corporation, a major producer of synthetic organic
chemicals by air oxidation processes, submits the attached comments on EPA's
draft control technology guideline (CTG) document for control of volatile
organic compound emissions from air oxidation processes in the synthetic
organic chemical manufacturing industry.
Our submission of these comments has been delayed several days beyond
the official April 19 due-date because the draft CTG was not available from
the EPA until a short time before that date. (My copy of the document arrived
with less than a week remaining.) When I called you on April 19, you said
that comments would be considered as long as they were mailed within about a
week after April 19.
We would welcome the opportunity to discuss these comments with you.
If you have any questions, please call me (304) 747-2346.
Very truly yours, ,
-------
UNION CARBIDE CORPORATION
COWENTS ON "EPA'S" DRAFT "CT6" DOCUMENT FOR CONTROL OF
VOLATILE ORGANIC COMPOUND EMISSIONS FROM AIR OXIDATION PROCESSES
We note wording on pages 4-1 and 4-2 that places restrictions on what
constitutes a proper point in an existing process unit for defining the VOC
content of the emissions. While we can see that an effort has been made in
the text to define the emissions point in a fairly broad way, it seems
logical to us to broaden the definition stm further. Simply stated, it
seems logical that the evaluation of the cost for effecting a further
reduction in emissions should start with what is actually being emitted by
the existing facility, regardless whether the last step 1n the process is
a) product recovery, b) energy recovery, or c) even a less-than-ideal (but
already existing) emissions control device.
We feel that the RACT recommended in Chapter 4 does not adequately consider
and make provision for use of catalytic oxidation as an alternative to
thermal oxidation for emissions control. We ask that clarifying additions
be made to supply state agencies with accurate and appropriate guidance in
this regard and that overly restrictive criteria be relaxed.
We find no fault with the preceding discussion in Chapter 3 - Emission
Control Techniques, inasmuch as it:
a. Cited catalytic oxidation as the second most common form of emissions
control for an oxidation process.
b. Properly described the role of catalytic oxidation under pressure as a
means of enhancing energy recovery.
c. Properly defined the range of reduction efficiencies for catalytic
oxidation.
The problem lies in the RACT Itself, where the alternatives to meeting the
TRE criterion are only a) a reduction efficiency of 98% (presumably based
on the existing emissions rate) or b) reduction of VOC to 20 ppm. The text
on page 4-1 1s somewhat ambiguous in regard to these alternative criteria
of 98% reduction or 20 ppm. However, their treatment as criteria is
brought out. quite explicitly on pages E-14 and E-15.
We strongly question the apparent premise for these restrictions, namely
that thermal oxidation is the only technology that is universally
applicable. The text on page 4-1 includes a statement that the "RACT
recommendation itself would not specify thermal oxidation as the only VOC
control method." In light of that statement, we are puzzled by the
restrictions nevertheless Imposed by the criteria. These criteria, as
Chapter 3 points out, can be met only by thermal oxidation.
G-32
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-2-
As we have emphasized earlier in commenting on the NSPS, our concern 1s
that proper cognizance is not being taken of the cost effectiveness of
catalytic oxidation, where it is applicable. The cost advantages accrue
from reduced (or even zero) requirements for supplementary air and/or fuel
and from lower investment and operational attention.
Accordingly, we urge that the RACT criteria be modified in appropriate
conformance with the text in Chapter 3.
Other comments that we wish to bring to the Agency's attention involve errors
or inconsistencies.
1. Printing errors on pages 3-18, 3-19, and 3-20 have resulted in the omission
of one portion of the text and the duplication of other portions.
2. Even though the TRE formula and the table of coefficients in the CTG appear
to be identical with the formula and coefficients, in the BID for the NSPS,
there is an inconsistency in the monetary definition of the index.
a. The CTG defines a TRE Index of 1.0 as corresponding to $1600/Mg
destroyed.
b. The BID for the NSPS specifies a value of $886.60 for a TRE Index of
1.0. (This $886.60 value, incidentally, corresponds to the value of
$1900 for a TRE Index of 2.2 that is cited in the preamble of the
published standards.)
We are puzzled as to how such divergent values can result from what
appears to be the same formula and set of coefficients.
3. We also fail to detect in the table of coefficients the changes we
would expect to see as a result of the retrofit factor of 1.625 that is
discussed earlier in the text.
(The thought strikes us that perhaps the wrong table of coefficients
has been printed in the CTG report. However, if that is the case, the
example in the appendix is also in error.)
RAH:AWB/jgh/06428,020
G-33
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APPENDIX H: REFERENCE METHODS AND PROCEDURES
-------
APPENDIX H. REFERENCE METHODS AND PROCEDURES
H.I INTRODUCTION
This appendix presents the reference methods and procedures recommended
for implementing RACT. Methods and procedures are identified for two types
of RACT implementation: (1) determination of VOC destruction efficiency for
evaluating compliance with the 98-weight percent VOC reduction or 20 ppmv
emission limit specified in the recommended RACT; and (2) determination of
offgas flowrate, hourly emissions, and stream net heating value for
calculating a TRE index. All reference methods identified in this appendix
refer to the reference methods specified at 40 CFR Part 60 - Appendix A.
H.2 VOC DESTRUCTION EFFICIENCY DETERMINATION
(a) The following reference methods and procedures are recommended for
determining compliance with the percent destruction efficiency specified in
the recommended RACT.
(1) Reference Method 1 or 1A, as appropriate, for selection of the
sampling site. The control device inlet sampling site for determination of
vent stream molar composition or total organic compound destruction
efficiency shall be prior to the inlet of any control device and after all
recovery devices.
(2) Reference Method 2, 2A, 2C, or 2D as appropriate, for
determination of the volumetric flowrate.
(3) Reference Method 3 to measure oxygen concentration for the air
dilution correction. The emission sample shall be corrected to 3 percent
oxygen.
(4) Reference Method 18 to determine the concentration of total organic
compounds (minus methane and ethane) in the control device outlet and total
organic compound reduction efficiency of the control device.
H.3 TRE INDEX DETERMINATION
(b) The following reference methods and procedures are recommended tor
determining the offgas flowrate, hourly emissions, and the net heating value
of the gas combusted to calculate the vent stream TRE index value.
(1) Reference Method 1 or 1A, as appropriate, for selection of the
sampling site. The sampling site for the vent stream flowrate and molar
composition determination prescribed in (b)(2) and (3) shall be prior to the
inlet of any combustion device, prior to any post-reactor dilution of the
stream with air, and prior to any post-reactor introduction of halogenated
compounds into the vent stream. Subject to the preceding restrictions on the
sampling site, it shall be after the final recovery device. If any gas
stream other than the air oxidation vent stream is normally conducted through
the recovery system of the affected facility, such stream shall be rerouted
or turned off while the vent stream is sampled, but shall be routed normally
prior to the measuring of the initial value of the monitored parameter(s) for
determining compliance with the recommended RACT. If the air oxidation vent
stream is normally routed through any equipment which is not a part of the
air oxidation facility as defined in Chapter 4, such equipment shall be
H-l
-------
bypassed by the vent stream while the vent stream is sampled, but shall not
be bypassed during the measurement of the initial value of the monitored
parameter(s) for determining compliance with the recommended RACT.
(2) The molar composition of the vent stream shall be determined as
follows:
(i) Reference Method 18 to measure the concentration of all organics,
including those containing halogens.
(ii) ASTM D1946-67 (reapproved 1977) to measure the concentration of
carbon monoxide and hydrogen.
(iii) Reference Method 4 to measure the content of water vapor, if
necessary
(3)
Method 2,
(4) e net eating vaue o the vent stream shall be calculated using
The volumetric flowrate shall be determined using Reference
2A, 2C, or 2D, as appropriate.
The net heating value of the vent stream shall be calculated
the following equation:
n
T l i = 1
Net heating value of the sample, MJ/scm, where
whers
where
CiHi
H
T
the net'
enthalpy per mole of offgas 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 (offgas flowrate).
K, = Constant, 1.740 x 10'
fg mole^
son
^kcTP
standard temperature for g-mole/scm is 20°C.
C. = Concentration of sample component i, ppm, as measured by
1 Reference Method 18 and ASTM D1946-67 (reapproved 1977),
reported on a wet basis.
H. = Net heat of combustion of sample component i, kcal/g-mole
1 based on combustion at 25°C and 760 mm Hg. The heats of
combustion of vent stream components would be required to be
determined using ASTM D2382-76 if published values are not
available or cannot be calculated.
(5) The emission rate of total organic compounds in the process vent
stream shall be calculated using the following equation:
where:
'TOG
Mi
Q]
compounds (minus methane
ETOC " K2 | I ^iV Qs
TOC emission rate of total organic
and ethane) in the sample, kg/hr.
Constant, 2.494 x 10 (l/ppm)(g-mole/scm) (kg/g)(min/hr),
where standard temperature for (g-mole/scm) is 20°C.
Molecular weight of sample component i, g/g-mole.
Vent stream flowrate (scm/min), at a standard temperature
of 20°C.
H-2
-------
(6) The total vent stream concentration (by volume) of compounds
containing halogens (ppmv, by compound) shall be summed from the individual
concentrations of compounds containing halogens which were measured by
Reference Method 18.
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. 2.
EPA-450/3-84-015
4. TITLE ANDSUBTITLE
Guideline Series - Control of Volatile Organic Compound
Emissions from Air Oxidation Processes in. Synthetic
Organic Chemical Manufacturing Industry
7. AUTHOR(S)
j|9. PERFORMING ORGANIZATION NAME AND ADDRESS
I Office of Air Quality Planning and Standards
E U.S. Environmental Protection Agency
t Research Triangle Park, North Carolina 27711
12. SPONSORING AGENCY NAME AND ADDRESS
Office of Air and Radiation
! U.S. Environmental Protection Agency
401 M Street , S.W.
| Washington, D.C. 20460
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
December 1984
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/ 2 00 /04
S15. SUPPLEMENTARY NOTES
i)
\
I
16. ABSTRACT
Control Techniques Guidelines (CTG) are issued for volatile organic compound
(VOC) emissions from air oxidation processes within the synthetic organic chemical
manufacturing industry. The document informs Regional, State, and local air pollu-
tion control agencies of reasonably available control technology (RACT) for develop-
ment of regulations necessary to attain the national ambient air quality standards
for ozone.
|17 KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Air Pollution
Chemical Industry
Pollution Control
Reasonably Available Control Technology
Volatile Organic Compounds (VOC)
18. DISTRIBUTION STATEMENT
b.lDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This page)
Unclassified
c. COSATI Field/Group
13b
21. NO. OF PAGES
216
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
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