United States Office of Air Quality EPA-450/3-80-026
Environmental Protection Planning and Standards December 1980
Agency Research Triangle Park NC 27711
Air
Organic Chemical
Manufacturing
Volume 4: Combustion
Control Devices
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EPA-450/3-80-026
Organic Chemical Manufacturing
Volume 4: Combustion
Control Devices
Emission Standards and Engineering Division
U S. Environmental Protection A«wc»
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 1201 rHMi
Chicago. IL 60604-3590
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
December 1980
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U,S. Environmental Protection Agency
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Ill
This report was furnished to the Environmental Protection Agency by IT Enviro-
science, 9041 Executive Park Drive, Knoxville, Tennessee 37923, in fulfillment
of Contract No. 68-02-2577. The contents of this report are reproduced herein
as received from IT Enviroscience. The opinions, findings, and conclusions
expressed are those of the authors and not necessarily those of the Environmen-
tal Protection Agency. Mention of trade names or commercial products is not
intended to constitute endorsement or recommendation for use. Copies of this
report are available, as supplies permit, through the Library Services Office
(MD-35), U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina 27711, or from National Technical Information Services, 5285 Port
Royal Road, Springfield, Virginia 22161.
D124R
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V
CONTENTS
Page
INTRODUCTION vl1
Page
Report
1. CONTROL DEVICE EVALUATION THERMAL OXIDATION 1-i
2. CONTROL DEVICE EVALUATION THERMAL OXIDATION
SUPPLEMENT 2~i
3. CONTROL DEVICE EVALUATION CATALYTIC OXIDATION 3-i
4. CONTROL DEVICE EVALUATION FLARES AND THE USE
OF EMISSIONS AS FUELS 4~1
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VI1
INTRODUCTION
A. SOCMI PROGRAM
Concern over widespread violation of the national ambient air quality standard
for ozone (formerly photochemical oxidants) and over the presence of a number
of toxic and potentially toxic chemicals in the atmosphere led the Environ-
mental Protection Agency to initiate standards development programs for the
control of volatile organic compound (VOC) emissions. The program goals were
to reduce emissions through three mechanisms: (1) publication of Control Tech-
niques Guidelines to be used by state and local air pollution control agencies
in developing and revising regulations for existing sources; (2) promulgation
of New Source Performance Standards according to Section lll(b) of the Clean
Air Act; and (3) promulgation, as appropriate, of National Emission Standards
for Hazardous Air Pollutants under Section 112 of the Clean Air Act. Most of
the effort was to center on the development of New Source Performance Stan-
dards .
One program in particular focused on the synthetic organic chemical manufactur-
ing industry (SOCMI), that is, the industry consisting of those facilities
primarily producing basic and intermediate organics from petroleum feedstock
meterials. The potentially broad program scope was reduced by concentrating on
the production of the nearly 400 higher volume, higher volatility chemicals
estimated to account for a great majority of overall industry emissions. EPA
anticipated developing generic regulations, applicable across chemical and
process lines, since it would be practically impossible to develop separate
regulations for 400 chemicals within a reasonable time frame.
To handle the considerable task of gathering, assembling, and analyzing data to
support standards for this diverse and complex industry, EPA solicited the
technical assistance of IT Enviroscience, Inc., of Knoxville, Tennessee (EPA
Contract No. 68-02-2577). IT Enviroscience was asked to investigate emissions
and emission controls for a wide range of important organic chemicals. Their
efforts focused on the four major chemical plant emission areas: process
vents, storage tanks, fugitive sources, and secondary sources (i.e., liquid,
solid, and aqueous waste treatment facilities that can emit VOC).
121F
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IX
REPORTS
To develop reasonable support for regulations, IT Enviroscience gathered data
on about 150 major chemicals and studied in-depth the manufacture of about
40 chemical products and product families. These chemicals were chosen consid-
ering their total VOC emissions from production, the potential toxicity of
emissions, and to encompass the significant unit processes and operations used
by the industry. From the in-depth studies and related investigations, IT
Enviroscience prepared 53 individual reports that were assembled into 10 vol-
umes. These ten volumes are listed below:
Volume 1
Volume 2
Volume 3
Volume 4
Volume 5
Volume 6-10
Study Summary
Process Sources
Storage, Fugitive, and Secondary Sources
Combustion Control Devices
Adsorption, Condensation, and Absorption Devices
Selected Processes
Volumes 4 and 5 are dedicated to the evaluation of control devices used as add-
on controls to reduce VOC emissions. These add-on controls are discussed general-
ly in Volumes 2 and 3 as emission control options for the control of VOC emis-
sions from generic sources. The use of these add-on controls in specific applica-
tions is demonstrated in the process studies covered in Volumes 6 through 10.
This volume covers the application of combustion devices as add-on VOC emission
control devices. Separate reports are presented covering control device evalua-
tions for thermal oxidation, special thermal oxidation requirements for VOC
containing halogens and sulfur, catalytic oxidation, flares, and the use of
emissions as fuels. These reports discuss the practical use of each control
device, describe the systems, and discuss key design considerations. Data,
tables, and curves are presented to enable preliminary cost and energy impacts
to be determined for a wide range of potential applications. These control
device evaluation reports were used to develop the cost effectiveness and
energy impact determinations presented in the process reports of Volumes 6
through 10. The focus of these reports is on control of new sources rather
than on existing sources in keeping with the main program objective of develop-
ing new source performance standards for the industry. The reports do not
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XI
outline regulations and are not intended for that purpose, but they do provide
a data base for regulation development by the EPA.
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REPORT 1
CONTROL DEVICE EVALUATION
THERMAL OXIDATION
J. W. Blackburn
IT Enviroscience
9041 Executive Park Drive
Knoxville, Tennessee 37923
Prepared for
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park, North Carolina
July 1980
D75G
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CONTENTS OF REPORT 1
Page
I. INTRODUCTION I~1
II. THERMAL OXIDIZER DESIGN CONSIDERATIONS II~l
A. Residence Time and Temperature II~1
B. VOC Destruction Efficiency I]C~3
C. Flame Stability 11-10
D. Liquid Organic Wastes 11-12
E. Heat Recovery 11-12
III. BASIS FOR THERMAL OXIDIZER DESIGN III-l
A. Effect of Sensitive Design Variables on Cost and Energy III-l
B. Procedure Used for Designing Thermal Oxidizer System III-7
C. Combustion Alternatives 111-23
IV. CONSIDERATIONS FOR INSTALLING THERMAL OXIDATION CONTROL EQUIPMENT IV-1
V. COST AND ENERGY IMPACTS OF THERMAL OXIDIZERS V-l
A. Cost Basis v~-'-
B. Capital Costs v"3
C. Annual Costs v~22
D. Cost Effectiveness and Energy Effectiveness V-37
E. Other Impacts v~37
VI. SUMMARY AND CONCLUSIONS VI"1
VII. REFERENCES VII-1
APPENDICES OF REPORT 1
APPENDIX A. PURCHASE COSTS FOR THERMAL OXIDATION COMBUSTION CHAMBERS, A-l
RECUPERATIVE HEAT EXCHANGERS, AND WASTE HEAT BOILERS
APPENDIX B. ANNUAL COST DATA B-l
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1-v
TABLES OF REPORT 1
Number Pa9e
II-l Results from Actual Thermal Oxidizer Tests II-5
II-2 Combustion Temperature, Residence Time, and VOC Destruction II-7
Relationships
III-l VOC Molar Heats of Combustion III-4
III-2 Summary of Organic Compound Components Surveyed III-5
III-3 Ratio of Combustion Air to Waste Gas Flow Rate vs Waste Gas 111-13
Heat Content
III-4 Thermal Oxidizer Size Reduction Factor for Recuperative Heat 111-15
Recovery Systems
III-5 Fuel Reduction Factors for Recuperative Heat Recovery Systems 111-16
III-6 Fuel Gas Exhaust Temperature After Heat Recovery 111-22
V-l Factors Used for Estimating Total Installed Costs V-2
V-2 Annual Cost Parameters V-22
V-3 Cost Effectiveness of Thermal Oxidation V-38
V-4 Fuel Energy Effectiveness of Thermal Oxidation V-39
V-5 Typical Thermal Oxidizer Flue Gas Composition V-43
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1-vii
FIGURES OF REPORT 1
Number Page
II-l Feed Configurations for Thermal Oxidizers Burning Low-, Medium-, II-2
and High-Heat-Content Waste Gases
II-2 Relationship Between Total VOC Destuction Efficiency Based on 11-11
Waste Gas, Fuel Destruction Efficiency, and Waste Gas Destruction
Efficiency for a 2-Btu/scf-Heat-Content Waste Gas
III-l Relationship Between Waste Gas Heat Content, VOC Composition, III-3
and VOC Molar Heat of Combustion
III-2 Supplementary Fuel Usage vs Waste Gas Heat Content III-8
III-3 Ratio of Thermal Oxidizer Flue Gas Flow to Waste Gas Flow vs III-9
Waste Gas Heat Content
III-4 Relationship Between Actual Flow Rates and Flue Gas Temperature 111-10
III-5 Flue Gas Heat Content 111-12
III-6 Recuperative Heat Exchanger Design at 1400°F Combustion 111-17
Temperature
III-7 Recuperative Heat Exchanger Design at 1600°F Combustion 111-18
Temperature
III-8 Maximum Heat Recovery from a Waste Heat Boiler 111-20
III-9 Ratio of Waste Heat Boiler Heat Exchange Surface to Flue Gas 111-21
Flow vs Flue Gas Temperature
V-l Total Installed Capital Cost for Thermal Oxidation Systems with V-4
Waste-Gas Heat Content = 10 Btu/scf, Residence Time =0.5 sec,
and Combustion Temperature - 1400°F
V-2 Total Installed Capital Cost for Thermal Oxidation Systems with V-5
Waste-Gas Heat Content = 10 Btu/scf, Residence Time =0.75 sec,
and Combustion Temperature = 1400°F
V-3 Total Installed Capital Cost for Thermal Oxidation Systems with V-6
Waste-Gas Heat Content = 10 Btu/scf, Residence Time =0.5 sec, and
Combustion Temperature = 1600°F
V-4 Total Installed Capital Cost for Thermal Oxidation Systems with V-7
Waste-Gas Heat Content = 10 Btu/scf, Residence Time =0.75 sec,
Combustion Temperature = 1600°F
V-5 Total Installed Capital Cost for Thermal Oxidation Systems with V-S
Waste-Gas Heat Content = 100 Btu/scf and Combustion Tempera-
ture = 1875°F
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1-ix
FIGURES (Continued)
Number
V-6 Total Installed Capital Cost for Thermal Oxidation Systems with V-9
Waste-Gas Heat Content = 200 Btu/scf and Combustion Tempera-
ture = 2200°F
V-7 Installed Capital Cost for the Combustion Chamber with Waste-Gas V-10
Heat Content = 10 Btu/scf, Residence Time = 0.5 sec, and Combus-
tion Temperature = 1400°F
V-8 Installed Capital Cost for the Combustion Chamber with Waste-Gas V-ll
Heat Content = 10 Btu/scf, Residence Time =0.75 sec and Combus-
tion Temperature = 1400°F
V-9 Installed Capital Cost for the Combustion Chamber with Waste-Gas V-12
Heat Contents = 10 and 100 Btu/scf, Residence Time = 0.5 sec, and
Combustion Temperature = 1600°F
V-10 Installed Capital Cost for the Combustion Chamber with Waste-Gas V-13
Heat Content = 10 Btu/scf, Residence Time = 0.75 sec, and Combus-
tion Temperature = 1600°F
V-ll Installed Capital Cost for the Combustion Chamber with Waste-Gas V-14
Heat Contents = 100 and 200 Btu/scf and Various Residence Times
and Combustion Temperatures
V-12 Installed Capital Cost for Recuperative-Type Heat Exchangers with V-16
the Waste-Gas Heat Content - 10 Btu/scf
V-13 Installed Capital Cost for Waste Heat Boilers (250 psi) V-17
V-14 Installed Capital Cost for Waste Heat Boilers (400 psi) V-18
V-15 Installed Capital Costs for Inlet Ducts, Waste Gas, and Combustion V-19
Air Fans and Stack for System with No Heat Recovery
V-16 Installed Capital Costs for Inlet Ducts, Waste Gas, and Combustion V-20
Air Fans and Stack with Recuperative Heat Recovery
V-17 Installed Capital for Inlet Ducts, Waste Gas, and Combustion Air V-21
Fans and Stack with Waste Heat Boilers
V-18 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers Using V-23
No Heat Recovery, 1400°F Combustion Temperature, 0.5 sec Residence
Time, and Heat Contents from 1 to 50 Btu/scf
V-19 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers V-24
Using No Heat Recovery, 1400°F Combustion Temperature, 0.75 sec
Residence Time, and Heat Contents from 1 to 50 Btu/scf
V-20 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers V-25
Using No Heat Recovery, 1600°F Combustion Temperature, 0.5 sec
Residence Time, and Heat Contents from 1 to 50 Btu/scf
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1-xi
FIGURES (Continued)
Number Pa9e
V-21 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers V-26
Using No Heat Recovery, 1600°F Combustion Temperature, 0.75 sec
Residence Time, and Heat Contents from 1 to 50 Btu/scf
V-22 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers V-27
Using Recuperative Heat Recovery, 1400°F Combustion Temperature,
0.5 sec Residence Time, and Heat Contents from 1 to 20 Btu/scf
V-23 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizer V-28
Using Recuperative Heat Recovery, 1400°F Combustion Temperature,
0.75 sec Residence Time, and Heat Contents from 1 to 20 Btu/scf
V-24 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizer V-29
Using Recuperative Heat Recovery, 1600°F Combustion Temperature,
0.5 sec Residence Time, and Heat Contents from 1 to 20 Btu/scf
V-25 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizer V-30
Using Recuperative Heat Recovery, 1600°F Combustion Temperature,
0.75 sec Residence Time, and Heat Contents from 1 to 20 Btu/scf
V-26 Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer V-31
Using Waste Heat Boiler, 1400°F Combustion Temperature, 0.5 sec
Residence Time, and Heat Contents from 1 to 50 Btu/scf
V-27 Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer V-32
Using Waste Heat Boiler, 1400°F Combustion Temperature, 0.75 sec
Residence Time, and Heat Contents from 1 to 50 Btu/scf
V-28 Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer V-33
Using Waste Heat Boiler, 1600°F Combustion Temperature, 0.5 sec
Residence Time, and Heat Contents from 1 to 50 Btu/scf
V-29 Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer V-34
Using Waste Heat Boiler, 1600°F Combustion Temperature, 0.75 sec
Residence Time, and Heat Contents from 1 to 50 Btu/scf
V-30 Net Annual Cost vs Waste Flow Rate for Thermal Oxidizer with No V-35
Heat Recovery and with a Waste Heat Boiler; Heat Content =
100 Btu/scf
V-31 Net Annual Cost vs Waste Flow Rate for Thermal Oxidizer with No V-36
Heat Recovery and with a Waste Heat Boiler; Heat Content =
200 Btu/scf
V-32 Cost Effectiveness vs VOC Destruction Efficiency for Waste Gases V-40
with 1 Btu/scf Heat Content
V-33 Cost Effectiveness vs VOC Destruction Efficiency for Thermal V-41
Oxidizer with No Heat Recovery and with a Waste Heat Boiler,-
Heat Contents = Between 1 and 50 Btu/scf and Waste Gas
Flows = 700 cfm
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1-xiii
FIGURES (Continued)
Number Page
V-34 Cost Effectiveness vs VOC Destruction Efficiency for Thermal V-42
Oxidizer with No Heat Recovery and with a Waste Heat Boiler;
Heat Contents = Between 1 and 50 Btu/scf and Waste Gas
Flows = 50,000 scfm
A-l Purchase Costs for Thermal Oxidation Combustion Chambers A-3
A-2 Purchase Costs for Thermal Oxidation Recuperative Heat Exchangers A-4
A-3 Purchase Costs for Thermal Oxidation Waste Heat Boilers A-5
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1-xv
ABBREVIATIONS AND CONVERSION FACTORS
EPA policy is to express all measurements used in agency documents in metric
units. Listed below are the International System of Units (SI) abbreviations
and conversion factors for this report.
To Convert From
Pascal (Pa)
Joule (J)
Degree Celsius (°C)
Meter (m)
Cubic meter (m3)
Cubic meter (m3)
Cubic meter (m3)
Cubic meter/second
(m3/s)
Watt (W)
Meter (m)
Pascal (Pa)
Kilogram (kg)
Joule (J)
To
Atmosphere (760 mm Hg)
British thermal unit (Btu)
Degree Fahrenheit (°F)
Feet (ft)
Cubic feet (ft3)
Barrel (oil) (bbl)
Gallon (U.S. liquid) (gal)
Gallon (U.S. liquid)/rain
(gpm)
Horsepower (electric) (hp)
Inch (in.)
Pound-force/inch2 (psi)
Pound-mass (Ib)
Watt-hour (Wh)
Standard Conditions
68°F = 20°C
1 atmosphere = 101,325 Pascals
Multiply By
9.870 X 10~6
9.480 X 10~4
(°C X 9/5) + 32
3.28
3.531 X 101
6.290
2.643 X 102
1.585 X 104
1.340 X 10~3
3.937 X 101
1.450 X 10~4
2.205
2.778 X 10"4
PREFIXES
Prefix
T
G
M
k
m
M
Symbol
tera
giga
mega
kilo
milli
micro
Multiplication
Factor
1012
109
106
103
io~3
io"6
1 Tg =
1 Gg =
1 Mg =
1 km =
1 mV =
1 jjg =
Example
1 X IO12 grams
1 X IO9 grams
1 X IO6 grams
1 X IO3 meters
1 X 10~3 volt
1 X IO"6 gram
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1-1
I. INTRODUCTION
Thermal oxidation is a control technology whereby organic vapors are oxidized
at high temperatures in the presence of air. Thermal oxidation units have been
constructed to control a wide variety of waste gases, the design of the unit
depending on the composition and flow rate of the waste gas. The concentration
of the volatile organic compounds (VOC) can be converted to the heat generated
by the waste gas (heat content) if the specific components and their heats of
combustion are known or can be calculated. The heat content range, together
with the waste-gas flow rate, determines the design and auxiliary fuel usage.
Three categories of heat contents are used in this report: low (<50 Btu/scf),
moderate (50 to 100 Btu/scf), and high (>100 Btu/scf). For waste gases with
low heat contents, auxiliary fuel such as natural gas or fuel oil must be added
to maintain the combustion temperatures. Heat contents of approximately 13
and 20 Btu/scf in air correspond to 25 and 40% of the lower explosive limit
(LEL). Waste gases with heat contents of 20 to 50 Btu/scf (40 to 100% of the
LEL) must be diluted with inert gases or be enriched with auxiliary fuel because
they exceed the flammable safety limits imposed by insurance companies. Moderate-
heat-content waste gases have sufficient heat content for burning but need auxili-
ary fuel for flame stability.
When the heat content is higher than ~100 Btu/scf, the waste gas possesses enough
heat value to support a flame by itself and can be considered for use as a fuel
gas or boiler feed gas. When flame temperatures resulting from incineration of
this type of waste exceed 2200°F, a considerable amount of excess air must be used
to cool the unit to 2200°F. Oxidation equipment such as water-wall boilers and
high-temperature specialty oxidizers has been successfully designed and operated
for temperatures in excess of 2200°F, but is beyond the scope of this study.
In many cases the waste gas creating excessive temperatures has been a candidate
for flaring.
Conventional thermal oxidizers range in size from a unit capable of controlling
several hundred scfm of waste gas to single or multiple units controlling waste
gas in excess of 100,000 scfm. Few single thermal oxidizers exist that are
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1-2
sized for more than 200,000 scfm of flue gas. For a combustion chamber tempera-
ture of 1400°F and a waste gas with a heat content of less than 50 Btu/scf and
no oxygen, a thermal oxidizer sized for 195,000 scfm of flue gas would handle a
waste-gas feed rate of 100,000 scfm. To provide a 1/2-sec residence time for the
actual flow rate of 737,000 cfm would require a combustion chamber volume of
6140 ft3. With the length-to-diameter ratio assumed to be 2, this volume would
require a refractory-lined cylinder that has an internal diameter of at least
16 ft and that is 32 ft long. Because of shipping size restrictions, larger
single units would require field fabrication, which would make the cost much
higher. A limit of 100,000 scfm of waste gas was used for this study. Vendors
have shop fabricated units up to that size as single units and as multiple
units.x—4
Waste gases containing sulfur or halogens require flue gas scrubbing after ther-
mal oxidation to remove the noxious gases that were formed during oxidation.
The scrubbing equipment requires additional capital investment. This analysis
is included in the Control Device Evaluation, Thermal Oxidation Supplement
(VOC containing halogens or sulfur).
Halogens in the waste gas require high-temperature oxidation to convert the
combustion product to a form that can most easily be recovered by scrubbing.
For instance chloride-containing waste gases are burned at high temperature to
convert the chloride to HCl instead of to C12, since HC1 is the more easily
scrubbed. The analysis of thermal oxidation of halogenated and sulfonated VOC
is also included in the above mentioned report.
*See Sect. VII for all references cited in this report.
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II-l
II. THERMAL OXIDIZER DESIGN CONSIDERATIONS
A variety of considerations affect the design and selection of the various com-
ponents comprising a thermal oxidizer system for the control of waste gases:
the combustion chamber residence time and temperature, which, in turn, affect
the destruction efficiency of the VOC; the auxiliary heat required for flame
stability; and the method to be used for heat recovery.
A. RESIDENCE TIME AND TEMPERATURE
Probably the most important considerations in the design of thermal oxidizers
are the combustion chamber temperature and residence time. These design variables
usually have an impact on both the destruction efficiency and the capital and
operating costs of thermal oxidizers.
The combustion temperatures of waste gases vary with the waste-gas heat content.
Waste gases with low heat contents will normally have combustion temperatures
of 1200 to 1600°F. The thermal oxidizer designer has the option of controlling
the combustion temperature by specifying additional auxiliary fuel. Waste gases
with moderate heat contents use less auxiliary fuel to support combustion, and
the combustion chamber will normally operate in the range of 1600 to 2200°F.
Waste gases with high heat contents determine their own combustion temperatures.
, The combustion temperatures of these gases can exceed 2200°F, and they are usually
satisfactory for use as fuel gases. Figure II-l shows the feed configurations
of thermal oxidizers burning waste gases with low, medium, and high heat contents.
The residence time in the combustion chamber is a design variable specified by
the system designer. The combustion chamber is a chemical reactor, and the
residence time is the time available for the reaction (oxidation) to occur.
Residence times as low as 0.3 sec to several seconds have been utilized in thermal
oxidizer designs. Different vendors have defined residence times in different
ways. Some include all the available volume of the combustion chamber. Others,
however, consider only the volume in which the flue gas is at the combustion
temperature, an approach that results in the combustion chamber being larger
than it would be if the entire internal volume were used in the calculation of
residence time. The fraction of the total volume that is at the combustion
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WASTE GAS
AUX. FUEL -
AIR
II-2
1200- 1600° F
BURNER
LOW HEAT CONTENT WASTE GAS
WASTE GAS
AUX. FUEL-
AIR
1400-2200° F
BURNER
MEDIUM HEAT CONTENT WASTE GAS
WASTE GAS
AUX. FUEL
AIR
OVER 2200°F
BURNER
HIGH HEAT CONTENT WASTE GAS
Fig II-1- Feed Configurations for Thermal Oxidizers Burning
Low-, Medium-, and High-Heat-Content Waste Gases
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II-3
temperature depends on the configuration and design of the flame burner. A
burner generating a short flame implies that the waste gas reaches it's combustion
temperature very rapidly and that nearly the entire internal volume is available
for oxidation. A burner developing a long flame has considerably less volume
at the combustion temperature than the total internal volume.
Although a design engineer should be quite concerned with the actual burner
design and residence time at the combustion temperature, in this control-device
evaluation study it is assumed that the entire combustion chamber volume is at
the combustion temperature. This is justified since later in this report it is
shown that differences as high as 50% in residence time do not significantly
affect the annual cost, including capital charges, of thermal oxidation control.
B. VOC DESTRUCTION EFFICIENCY
1. Achievable Destruction Efficiency
The temperatures and residence times of combustion for thermal oxidizers have
historically been determined by thermal oxidizer designers using rules of thumb.
It is often assumed that thermal oxidizers achieve "complete organic destruction."
When specific feed streams required specific destruction data, the chemical
manufacturers, their consultants, or the equipment manufacturers would operate
pilot units to test burn the real waste in order to determine actual destruction
efficiency. This, however, was a costly procedure and was avoided unless there
were unusual circumstances. Therefore, except for special cases, VOC destruc-
tion efficiency has rarely been measured.
Some vendors have claimed that combustion temperatures several hundred degrees
higher than the compound's autoignition temperature should be employed. To
date the correlation to destruction efficiencies by this rule of thumb has not
been established.5
Several other factors are important in determining the destruction efficiency.
Residence time at temperature, axial and longitudinal temperature profile, gas
density changes in the combustion chamber, and specific component reaction rate
(as a function of temperature) all must be known to determine the destruction
efficiency, the most important parameter. This requirement implies that for
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II-4
the thermal oxidizer the combustion chemistry of each component and the physical
design of the unit must be known in order to determine the VOC destruction effi-
ciency. Multicomponent oxidation equilibria further complicate the problem.
Recently, some studies have been performed to evaluate this problem. Barnes et
al.6 have begun a study of the specific kinetics of organic oxidations, but it
is theoretical in nature. Followup experimental studies were planned but were
cancelled. Lee et al.7 have presented a simplified experimental approach to
investigate the oxidation kinetics and have given case studies of the destruction
relationships of four compounds. In another publication these data are expanded
to develop a predictive relationship of VOC destruction. A review of these and
other technical resources in this complex area has led to the conclusion that
further experimental data are required to ensure that the time, temperature,
VOC efficiency relationship is established, which will aid future thermal oxidizer
designers. This review has been summarized as a research recommendation for
thermal oxidizers and has been submitted to the EPA.9
Table II-l presents the results from tests on five different operating thermal
oxidizers and one boiler adapted to burn a waste gas. Some of these tests were
run by EPA and some were run by the individual companies who have submitted
their data to EPA.10'11
Despite the complexity of the VOC efficiency issue and the need for further
work, some estimate of the time, temperature, VOC efficiency relationship is
required to design and evaluate thermal oxidizers for this study. Given this
need, IT Enviroscience has developed the thermal oxidizer design criteria shown
in Table II-2. These criteria are based on engineering experience with a number
of VOC applications and the data in Table II-l. In addition, these criteria are
based on designing the thermal oxidizer for the specific waste gas under considera-
tion and may involve test burns and pilot unit work with the actual waste stream.
Based on these assumptions, it was concluded that a properly operated and individ-
ually designed thermal oxidizer would achieve, as a minimum, the stated destruc-
tion efficiencies for waste gases with VOC concentration greater than 400 ppmv.
Some of the field unit test data in Table Il-i do not meet the criteria in
Table II-2. Analysis of the data lead to the conclusion that insufficient
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II-5
Table II-l. Results from Actual Thermal Oxidizer Tests
Company
v-' c J-
Union
Carbide
Rohm &
Haas
Denka
Mons anto
Koppers6
Petro-tex
Residence
Time/Inlet Temperature
Flow (SCFM) (F°)
2 to 3 sec/ 1160
20,600 1475
1 sec/tank 1425
farm vent,
(TFV)-12,500
Oxidizer 1510
vent, (OXV)-
40,000 1545
0.6 sec/33,000 1400
(Unit size)- Confidential
18' dia. X
36' (outlet
flow) 75,000
0.6 sec/30,000 1800
0.6 sec/14,400 1400
Number of
Test Runs
6C
3C
3C
4c
lc
3C
Unit l-6d
Unit 2-8d
Inlet-4c
Outlet-6c
N/A
Inlet
VOC
(ppmv) a
11,900
11,900
TFV 2580
OXV 11,600
TFV 2600
OXV 12,800
TFV 2410
OXV 12,200
950
Confidential
Confidential
850
(Set 1) 10,300
(Set 2) 10,650
(Set 3) 10,300
VOC
Outlet Destruction
VOC Efficiency
(ppmv) (%)
243
10
1330
150
25
13
25
47
(Set 1) 7
(Set 2)11
1000
215
10
96.
99.
82.
98.
99.
98.
>99
>99
99.
97.
70.
94.
99.
1
9
6
3
7
5
0
2
3
1
6
does not include methane or ethane.
destruction efficiency is weight percent.
GSampling conducted with integrated bags.
^Sampling conducted with grab sample bombs or syringes.
eThe data in Set 1 and 2 for Koppers were taken during different time periods.
flnlet and outlet VOC for Petro-tex reported as ppmv methane. This case involves
the use of an existing boiler to control a process fume. The data in set one were taken
prior to adjustment of the boiler; the data in sets two and three, after adiustment.
The specific alterations made by Petro-tex involve changes in mixing induced by retrofit
baffles.
-------
II-6
mixing or other design deficiency was the most likely cause. In addition, indivi-
dualized designing with test burns and pilot units adds to costs. In some cases,
the costs of this design procedure may be judged too high and the lower efficients
of units designed for more general application may be acceptable.
As shown by Table II-2, a longer residence time is required to complete combustion
when the thermal oxidizer feed contains more than 200 PPm carbon monoxide.
This is related to the difficulty encountered in the combustion of carbon monoxide
and the tendency for it to disrupt the VOC conversion.
The relationships in Table II-2 show the effect of increased combustion tempera-
tures at similar residence times. They do not show the effect of longer residence
times at lower temperatures. As can be seen in Table II-l, excellent destruction
efficiencies can be obtained at lower temperatures and longer residence times.
Halogenated compounds may be destroyed by using combustion temperatures on the
order of those shown in Table II-2 at a residence time of 1 sec or at much
elevated temperatures (approaching 3000°F) and shorter residence times. Chemical
equilibria between the halogenated compounds, the free halogen, the halogen
acid and the oxygen are functions of the combustion temperatures.* Since costs
are strongly influenced by operating at temperatures in excess of 2200°F, haloge-
nated hydrocarbons need to be handled separately and are discussed in a separate
control device evaluation.
The criterion in Table II-2 is based on the assumption that the combustion air
fed to the combustion chamber is sufficient to produce 3 mole % 02 in the flue
gas.
The criteria just described are not the only ones for achieving VOC destruction
at high levels. For instance, it may be possible to burn waste gases longer
(longer residence times) at lower temperatures to achieve the same ^ructxon
efficiency Also, for some easily oxidized compounds, oxidation at, say, 1400 F
and 0.5-sec retention time could develop destruction efficiencies above 99«.
Even with the attendant variations this approach is justified for two reasons.
First this criterion is comparable to that used in design and operation of
many existing thermal oxidizers and generally represents a conservative design.
-------
II-7
Table 11-2. Combustion Temperature, Residence Time, and
VOC Destruction Relationships
Combustion
Temperature
1400
1500
1600
1400
1500
1600
Residence
Time
(sec)
Waste Gas with <2000 ppm Carbon Monoxide
0.5
0.5
0.5
Waste Gas with >2000 ppm Carbon Monoxide
0.75
0.75
0.75
VOC
Destruction
Efficiency3
^90
>98
>99
>90
>98
>99
aWith waste gas feeds >400 ppm VOC.
bThe design of thermal oxidizers to achieve these efficiencies may require
test burns and pilot-plant work. In some cases, the costs for this design
work may be judged too high and the lower efficiencies of thermal oxidizers
designed for less stringent criteria may be acceptable.
-------
II-8
2.
Second, the variations of this criterion (that is, different destruction effi-
ciencies at the stated temperatures and residence times) have a small effect on
cost effectiveness (cost/lb of VOC destroyed). The major component of the annual
cost and energy impact will be related to the combustion temperature and the
auxiliary fuel used to achieve that temperature. If a unit is designed to operate
at, say, 1600°F and can be shown to achieve a greater VOC destruction than that
required by a standard, whether 99% or otherwise, the combustion temperature
and the auxiliary fuel usage can be reduced. This conservative design philosophy
is similar to the design of most new facilities in the synthetic organic chemicals
industry, and the cost impact of any regulations arising from this control device
evaluation will almost certainly be conservative. The actual annual cost, cost
effectiveness, or energy effectiveness experienced by companies using thermal
oxidation for VOC control should be lower than those shown in this report.
Calculation of Destruction Efficiency
A secondary problem in the determination of VOC destruction efficiency concerns
the method of calculation. VOC destruction efficiency is often calculated by
the so-called volumetric efficiency equation:
Volumetric efficiency = 1 -
ppm in the flue gas
ppm in the waste-gas feed
which is close to the mass-based destruction efficiency only if the average
molecular weight of the VOC in the waste gas is equal to the average molecular
weight in the flue gas and if the waste-gas-feed flow is the same as the flue
gas flow.
Since these assumptions exist in only a few cases, volumetric efficiencies can
be misleading. Mass-based efficiencies are much more desirable. There are,
however, some problems in describing thermal oxidation efficiencies in terms of
mass flow rates. A thermal oxidizer for VOC destruction receives contaminated
VOC gases (sometimes with liquids and solids) and supplementary fuels (natural
gas, fuel oils, or high-heat-content waste organic) and burns them with enough
air'for specified levels of excess or unused oxygen to be achieved in the flue
gas. The unburned VOC from both the fuels and the waste gas contribute to the
VOC in the flue gas.
-------
II-9
In order to establish an efficiency equation to account for the VOC from both
sources of flue gas (i.e., the waste gas and the fuel), it would be tempting to
define the efficiency as follows:
Total VOC destruction efficiency =
lb of VOC in the flue gas
1 " Ib of VOC in the waste gas + lb of VOC in the fuel
This approach is attractive in that it permits any VOC contribution of the unburned
fuel to be assessed directly. It is unacceptable, however, because it does not
allow for the evaluation of the degree of destruction of the waste gas. In
other words, with VOC destruction efficiencies based on the above equation, it
would not be recognized that the thermal oxidizer might burn fuel extremely
well but not destroy the waste gas.
When the waste-gas heat content is low, the fuel requirements are high (say,
10 lb of fuel to 1 lb of waste gas VOC). In the above equation the VOC in the
flue gas could come from either unburned fuel or waste gas. If the total effi-
ciency required was 90% and the fuel could be burned at 99% (which is easily
obtained), then the waste gas could pass through the oxidizer unchanged and the
oxidizer would be in compliance with the 90% efficiency requirement. Obviously
this approach thwarts the underlying reasons for VOC regulation. A second defini-
tion of VOC destruction efficiency therefore must be utilized that bases the
efficiency calculation on the waste gas alone:
VOCf, (lb ov VOC in the flue gas)
Ot(total VOC destruction efficiency) = 1 - voc "ib -Qf VOC in the waste gas) '
w
The VOC in the flue gas is comprised of the unburned VOC from the waste gas and
the unburned VOC from the fuel, each of which may be expressed in terms of the
VOC fed to the thermal oxidizer and destruction efficiency, where the efficiencies
of destruction of fuel and VOC in the waste gas are qfuel and nw, respectively:
vocflue = vocw (i - nw) + vocfuel (i - nfuel) -
-------
11-10
Therefore the VOC destruction efficiency in terms of the waste gas is
voc(i - n) + vQCfuei*1 - nfuei> .
w w
voc
w
The relationship between nw, Hfuel- and nt is shown in Fig. II-2 for the case
where a waste gas has 21 Ib of VOC per hour and 560 Ib of fuel per hour is required.
This relates to a heat content of about 2 Btu/scf. Also shown on Fig. II-2 is
the burner efficiency (nfuel) based on the EPA emission factor for burnin9 natural
gas or fuel oil in power plants, industrial boilers, and commercial systems.12
The conclusions from Fig. II-l are that if, say, 99% total efficiency is required
and if the EPA fuel oil boiler efficiency is used for the burner efficiency
(99.983%), then about 99.4% VOC destruction of the waste gas must be achieved.
Similarly, if for any reason the burner efficiency drops from 99.983% to 99.960%,
then the 99% total efficiency could not be achieved by using the above definition
of efficiency. This is particularly significant in view of the qualifications
in the EPA emission factor table12 indicating that surges, upsets, turndown, or
poor design or maintainance could increase the emission factors significantly.
From these statements it could be concluded that the 99.960% fuel efficiency
level would be difficult to maintain on a continuous basis. Overall efficiency
levels approaching 99% based on the waste gas demand the best fuel burner designs
and the smoothest possible operation.
A final consideration is that, by present definition, methane (natural gas) is
not considered to be a VOC. The VOC destruction efficiency based on the waste
gas is independent of burner efficiency if the fuel is natural gas. It has
become apparent that for a variety of reasons natural gas may not be the depend-
able choice for supplementary fuel.
C. FLAME STABILITY
An auxiliary- fuel minimum of 5 Btu/scf of waste gas for medium-heat-content
waste gases is assumed in this study. For medium- to high-heat-content waste
gases, auxiliary fuel amounting to 10% of the waste-gas heat content is added
for flame stability. A waste gas with a heat content of 100 Btu/scf thus requires
10 Btu/scf of auxiliary fuel. Obviously, for very high heat content waste gases
-------
11-11
1 0000
0.0001
TOTAL VOC DESTRUCTION EFFICIENCY
BASED ON WASTE GAS
NATURAL GAS
DOMESTIC-
COMMERCIAL-
OIL
ALL BOILERS
I^-NATURAL GAS
INDUSTRIAL
^-NATURAL GAS
POWER PLANT
r-90%
0.1 10 100 100.0
UNBURNED WASTE GAS VOC (%)
OR
100-WASTE GAS DESTRUCTION EFFICIENCY (%)
Fig. II-2. Relationship Between Total VOC Destruction Efficiency
Based on Waste Gas, Fuel Destruction Efficiency, and Waste Gas
Destruction Efficiency for a 2-Btu/scf-Heat-Content Waste Gas
-------
11-12
(>400 Btu/scf) the auxiliary fuel requirements for flame stability diminish.
The actual selection of auxiliary fuel for specific thermal oxidizer designs is
highly judgmental and requires consideration of several factors specific to the
application. The inclusion of the 10% auxiliary fuel in this evaluation is
intended to offer some credibility to the design although the actual auxiliary
fuel added may vary and may be reduced if operating experience demonstrates
good efficiency and flame stability with less auxiliary fuel.
D. LIQUID ORGANIC WASTES
Liquid organic wastes from a process may be a source of auxiliary fuel for thermal
oxidation. However, combustion of liquid waste streams in thermal oxidation
equipment can complicate the design. Inorganic compounds present in the liquids
can create very difficult particulate problems, which will require additional
equipment to solve. Since the total capital cost to deal with these factors
can be significantly higher than for conventional fume thermal oxidation, this
study does not address the complexities of feeding liquid organic wastes. "Clean"
liquids are assumed to be similar to fuel oil and using them for auxiliary fuel
will not have a significant impact on capital or annual costs.
E. HEAT RECOVERY
This report includes evaluations of thermal oxidizers without heat recovery,
with means for recuperative heat recovery such as preheating the waste gas and
combustion air to reduce auxiliary fuel usage, and with waste heat boilers for
steam generation. When heat recovery is desired, temperature considerations
could determine whether recuperative heating or waste heat boilers apply. Com-
bustion temperatures exceeding 1600°F rule out the use of recuperative heat
exchangers because of problems with materials of construction and with secondary
factors, such as precombustion occurring in the exchangers. Waste heat boilers,
however, are alternatives in this range.
Recuperative heating is possible with temperatures between 1500 and 1600°F only
if the part of the exchanger closest to the flame is manufactured from special
materials (nickel alloys, etc). Temperatures less than 1500°F are compatible
with standard recuperative heater designs. Waste heat boilers may be considered
throughout all ranges. For waste gases with moderate or high heat contents,
recuperative heating is not an option since it is of value only when used to
reduce the auxiliary-fuel requirement. Waste heat boilers may not be installed
at those production locations where additional process steam cannot be used.
-------
III-l
III. BASIS FOR THERMAL OXIDIZER DESIGN
After the design considerations described in the preceding section were evaluated,
those sensitive design variables that would have an effect on cost and energy
were identified and are described below.
A. EFFECT OF SENSITIVE DESIGN VARIABLES ON COST AND ENERGY
A distinction must be made between those design variables which, if changed by
a small amount, would cause significant changes in capital annual or energy
costs. These are called sensitive variables, and the cost curves given later
in the report generally include them as parameters. Other variables may be
quite important for an individual system design but have minor effects on economic
or energy impact conclusions.
The approach used in this study was to determine the sensitivity of certain
variables by means of computerized heat and material balance calculations.
Through this process, estimates of the relationships between the variables and
equipment design and operating costs may be derived. Primary variables that
are a function of the waste gas are the waste gas temperature, pressure, flow
rate, VOC composition and VOC average molecular weight, VOC carbon, oxygen, and
hydrogen (and other component) ratios, VOC heats of combustion, and the nitrogen
(and other inert gases), oxygen, and water contents, and the presence of special
contaminants (particulates, halogens, high levels of sulfur).
The waste gas temperature is assumed to be 100°F for the base case, but an increase
or decrease within reasonable boundaries will have little effect upon the capital
or operating costs and it is therefore not a significant variable. Sensible
heat carried by the waste gas is small compared to that required to raise its
temperature to the combustion conditions. About 3.5 Btu/scf is required to
increase the temperature of nitrogen from 80°F to 260°F. This compares with
fuel heat requirements on the order of 60 to 80 Btu/scf to raise the waste gas
to combustion temperatures. Waste gas temperature differences within this range
could not change the total heat requirements by more than about 6%. Waste gas
pressure is assumed to be 1.5 psig. Pressure changes within reasonable limits
of 1.5 psig also will have no significant effect on capital or operating costs.
-------
III-2
Flow rate is a very significant variable for both capital and operating costs.
The waste gas flows shown in the figures throughout this report are translated
to scfm of waste gas to the thermal oxidizer.
Heat content of the waste gas is a significant variable. VOC molar concentra-
tion; average molecular weight; carbon, hydrogen, and oxygen ratios; and heats
of combustion (Btu/lb of VOC) are all expressed in the variable of the heat
content of the waste gas (Btu/scf). By assessing the heat of combustion of the
VOC being destroyed and the mole % VOC concentration in the waste gas, the heat
content can be determined (Btu/scf) as shown by the family of compound lines on
Fig. III-l. Multicomponent VOC systems may be described when the mole fractions
of each component are known. The contribution of carbon monoxide to the total
heat content may also be analyzed in this way. Table III-l gives VOC molar
heats of combustion.13
If the actual flue gas composition is needed, a component material balance must
be performed, for which carbon, hydrogen, and oxygen ratios are required. In
order to estimate "typical" values for those ratios, 219 organic compounds con-
taining C, H, 0, N, and Cl were surveyed.14 Table III-2 summarizes this informa-
tion based on groupings of different classes. The VOC component averages of
68.3% carbon, 11.4% hydrogen, and 20.3% oxygen were used to establish heat value
plus heat and material balance for this evaluation. Compounds containing chlorine
or sulfur are not included in the impact assessment of this study but covered
in the Control Device Evaluation, Thermal Oxidation Supplement (VOC containing
halogens or sulfur).
The level of oxygen in the waste gas is important because compounds containing
high amounts of oxygen lessen the level of combustion air required and reduce
the total thermal oxidizer flue gas, which affect both capital and operating
costs. No additional combustion air is required when the oxygen in the flue
gas exceeds 3 mole %. This leads to a smaller unit and lower capital and operating
costs. Although some designers will use various levels of oxygen to determine
combustion requirements, the value of 3 mole % is based on accepted practice
and will be constant for all the design calculations in this evaluation. In
order to generate a conservative design and impact analysis, the waste gas in
this report is assumed to have no oxygen. Maximum combustion air is therefore
-------
WASTE GAS HEAT CONTENT (Btu/SCF)
O H
H
O I
O H
O
w »
H- ro
rt M
H- CD
0 rt
3 H-
> O
3
0> W
3 ff
0- h"
O
O
H1 CO
0) 3
H
s
ffi p)
fD en
O CD
HI fu
w
O
O K
C ft
Ul
ft O
H- O
O 3
3 rt
(D
ft
I
U>
-------
III-4
Table III-l- VOC Molar Heats of Combustion*
Compound
Methane
Ethane
Hexane
Benzene
Toluene
Ethylene
Propylene
Acetylene
Methanol
Ethanol
Acetic acid
Phenol
Methyl chloride
Methylene chloride
Chloroform
Carbon tetrachloride
Ethyl chloride
Hexachloroethane
Dichlorobenzene
Hexachlorobenzene
Carbon disulfide
Carbonyl sulfide
Thiophene
Methyl amine
Aniline
Urea
Uric acid
Ammonia
Nitromethane
Nitrobenzene
Trinitrobenzene
•
r.v^cc r,r- Hi ah-Heat of Combustion
Molecular
Weight
16
30
86
78
92
28
42
26
32
46
60
94
50.5
85
119.5
154
64.5
237
111.5
285
76
60
84
31
93
60
168
17
61
123
213
. -
_ (Btu/lb)
23,900
22,400
20,800
18,000
18,300
21,700
21,000
21,500
9,770
12,800
6,270
14,000
5,850
2,260
1,340
436
8,840
835
8,230
3,220
5,840
3,920
14,400
14,700
15,700
4,530
4,930
8,300
5,000
10,800
5,610
_
(Btu/lb -mole)
382,400
672,000
1,788,800
1,404,000
1,683,600
607,600
882,000
559,000
312,600
588,800
376,200
1,316,000
295,400
192,100
160,100
67,140
570,200
197,900
917,600
917,700
443,800
235,200
1,209,600
455,700
1,460,100
271,800
828,200
141,100
305,000
1,328,400
1,194,900
*See ref 12.
-------
III-5
Table III-2. Summary of Organic Compound Components Surveyed
_.__ — _ . • —
Class
Carbon, hydrogen
compounds only
Carbon, hydrogen com-
pounds and carbon,
hydrogen, oxygen
compounds
Carbon, hydrogen, and
chlorine compounds
only
Carbon, hydrogen, oxygen,
and nitrogen compounds
and carbon, hydrogen, and
nitrogen compounds
All compounds
Amount (wt %)
. — •
Low value*
Mean
High value*
Low value
Mean
High value
Low value
Mean
High value
Low value
Mean
High value
Low value
Mean
High value
C
79.9
85.8
92.3
27.0
68.3
92.3
7.8
34.3
64.0
26.1
60.1
78.5
7.8
62.5
92.3
H
7.7
14.2
20.1
2.1
11.4
20.4
0
4.7
9.8
3.7
11.3
15.4
0
10.4
20.1
O
0
20.3
7
0
3.6
52.0
0
17.3
20.1
N Cl
. — — —
31.5
60.6
92.2
13. C
25.0
60.8
0 0
3.9 5.9
60.8 92.2
*Low and high values correspond to the compound with the lowest and highest
percertaae of each element (e.g., carbon). Different compounds apply to
different elements; therefore the values shown will not be addrtxve.
-------
III-6
assumed. When ample oxygen in a low or medium heat content waste gas is avail-
able, the size of the combustion chamber to control the waste gas may be as low
as one-half the volume as shown in this report.
At 1600°F and 14.7 psia the heat capacity of water vapor is about 11.8 Btu/
(lb-mole)(°F). The heat capacity of air under the same conditions is 7.7 Btu/
(lb-mole)(°F).15 Since saturated conditions are assumed for the waste gas in
calculations in this report, the water content in the flue gas is at a maximum
unless entrained liquid water droplets enter with the feed. Auxiliary-fuel
requirements can increase significantly in this case since the heat capacity of
the flue gas increase and the heat of vaporization for water, 18,000 Btu/lb-mole
of water, must be supplied. However, this can normally be avoided with proper
design.
The presence of special contaminants can have significant effects on capital
and operating costs. A different design criterion is required with halogenated
feeds. Other contaminants, such as sulfur, could require the addition of absor-
bers to the control device. Investigation of these special cases are assessed
in the Control Device Evaluation, Thermal Oxidation Supplement.
A second group of significant variables relates to the design criterion of thermal
oxidation. Combustion chamber temperature and residence time must be specified
as functions of the feed components and VOC destruction efficiency. Combustion
chamber temperature has a significant effect on fuel costs for feeds with low
heat contents. Feeds with moderate heat contents determine their own combustion
temperature, whereas feeds of high heat content will markedly increase the size
of the equipment if the combustion chamber must be controlled at levels much
below their normal combustion temperatures. The addition of excess air or water
to reduce the combustion temperature results in a larger flue gas flow and larger
equipment to maintain the same residence time. Residence time has a major effect
on capital costs but a relatively small effect on operating costs. Even though
a larger unit has a larger heat loss by radiation, it is normally on the order
of a few percent and does not materially increase the operating cost.
The significant variables investigated in this report are waste gas flow, heat
content (encompassing a variety of composition-related variables), combustion
-------
III-7
temperature, residence times, and destruction efficiencies. Evaluation of these
parameters using generally worst-case or conservative assumptions will lead to
economic and energy impact conclusions that will equal or exceed actual operating
costs and energy impacts for the applicable cases. This approach, then, leads
to conservative economic and energy costs on which to base future regulations.
B. PROCEDURE USED FOR DESIGNING THERMAL OXIDIZER SYSTEM
The design procedure that was used for the thermal oxidizer unit of this study
was developed based on the above variables.
1. Combustion Chamber
The volume and composition of the waste gas were first determined. The heat
content of the gas was determined by the identification of the VOC components
(including CH4 and CO) and the use of Table III-l (plus other molar heats of
combustion data) and Fig. III-l. The minimum combustion temperature and resi-
dence times were taken from Table II-2, depending on the presence of carbon
monoxide. Supplementary fuel is required for low-heat-content waste gas to
maintain the desired combustion chamber temperature and flame stability. The
supplementary fuel requirement as a function of waste-gas heat content is shown
by Fig. III-2. The waste gas is assumed to have no oxygen and therefore the
combustion air required is at a maximum. With these data the total combustion
flue gas (in scfm) from all sources, including the waste gas, auxiliary fuel,
combustion air, and combustion products, was calculated for the waste-gas heat
content range (Btu/scf) displayed in Fig. III-2-. To correlate with the following
design, size, and cost projections for the full range of waste gas rates, the
flue gas flow of Fig. i'il-4 is expressed as a ratio of flue gas to waste gas as
a function of waste-gas heat content. In waste gases with high levels of oxygen
the ratio of flue gas to waste gas approaches 1. The more conservative case of
a waste gas with no oxygen as shown in Fig. III-3 is used in this evaluation.
Conversion of scfm to actual cubic feet per minute (acfm) is necessary for sizing
of the combustion chamber. Figure III-4 shows this relationship (based on the
ideal gas law). Standard conditions assumed throughout this report are 32°F
and 760 mm Hg and their equivalents. The ratio of acfm to scfm is read from
Fig. III-4 and is multiplied by the combustion chamber flue gas in scfm. Until
-------
SUPPLEMENTARY FUEL USAGE (Btu/SCF WASTE GAS)
H
H
I
CD
3
rt
G
0)
pi
DJ
0)
rf
(D
ffi
(B
0)
rt
O
O
3
rt
(D
3
rt
8-III
-------
19
-LINEAR ONLY IF 4-
SUPPLEMENTARY
FUEL IS ADDED
PROPORTIONALLY
TO THE CONTENT
PER DESIGN
CRITERIA
COMBUSTION
TEMPERA fURE -*- -
-1600°F 2200°F
1400°F 1875°F
, ,\
0 20 40 6(' 80100 200 300 400 500 600 700
WASTE GAS HEAT CONTENT (Btu/SCF)
800 900 1000
Fig. III-3. Ratio of Thermal Oxidizer Flue Gas Flow to Waste Gas Flow vs
Waste Gas Heat Content
-------
I
t->
o
1200 1400 1600 1800 2000 2200
COMBUSTION TEMPERATURE (°F)
Fig. IH-4. Relationship Between
Actual Flow Rates and Flue Gas Temperature
-------
III-ll
this point in the report, the term heat content has referred to the energy gen-
erated by combustion of compounds in the waste gas. Heat content when used in
relation to the flue gas in this report refers to the energy contained by the
hot gases because of their temperature. The basis used for the heat recovery
calculations is the heat content of the flue gas as a function of temperature,
as shown in Fig. III-5. The dotted lines in Fig. III-5 correspond to a reason-
able variation in specific heats or heat capacities of the flue gas.
Residence times (sec) from Table II-2 are used to calculate the combustion chamber
internal volume. The combustion chamber flue gas flow (in acfm) is converted
to actual cubic feet per second and then multiplied by the residence time (in
sec) to determine the combustion chamber internal volume in cubic feet.
2. Fans
Fans for the waste gas and combustion air are both specified. The flow rates
of the waste gas and combustion air and the pressure drops of the thermal oxidizers
are used to calculate fan sizes. Pressures drops of 6 in. of water were assumed
for the thermal oxidizer with 0 to 30% heat recovery; 8 in. was assumed for
thermal oxidizers with 50% heat recovery; and 10 in. was assumed for thermal
oxidizers with 70% heat recovery or waste heat boilers. The waste-gas fan
capacity is based on the waste-gas flow rate. Table III-3 gives the combustion
air flow/waste gas ratio as a function of waste-gas heat content. The relation-
ship is based on desired combustion temperatures, as previously discussed, and
is used to size the combustion air fan. The combustion air volume and fan size
may be determined by the use of this ratio multiplied by the volume of waste
gas. Waste gases containing significant levels of oxygen reduce the combustion
air required and reduce the size of the combustion air fan. Waste gases generated
at higher pressure often need no fan.
3. Recuperative Heat Recovery
A recuperative heat recovery system transfers heat from the flue gas into the
waste gas and combustion air, thus lowering the requirements for auxiliary fuel.
However, since less fuel is required for a given volume of waste gas, less com-
bustion air is also needed to burn the fuel and the resulting flue gas volume
is less than that of a thermal oxidizer without recuperative heat recovery.
Since the flue gas volume is lower, the amount of recoverable heat is also lower.
-------
H
H
200 400
600 800 ~ 1000 1200 1400 1600 1800 2000 2200
FLUE GAS TEMPERATURE (°F)
Fig. III-5. Flue Gas Heat Content
-------
111-13
Table III-3. Ratio of Combustion Air to Waste
Gas Flow Rate vs Waste Gas Heat Content
Waste Gas
Heat Content
(Btu/scf)
2
2
100
200
400
Combustion
Temperature
(°F)
1400
1600
1875
2200
2200
Combustion Air to
Waste Gas Flow Ratio*
/ scf of combustion air\
\ scf of waste gas
0.87
1.1
1.4
3.1
7.3
1
*Thermal oxidizer conditions:
No oxygen in waste gas.
VOC molar heat of combustion = 730,250 Btu/lb-mole-
VOC molecular weight = 50.
VOC C, H, 0 fraction = 68.3 wt % C, 11.4 wt
% H, 20.3 wt % 0.
Average waste gas molecular weight = 29.
Water content of combustion air = 1.0 wt %.
3 mole % O0 in flue gas after oxidation.
-------
111-14
The combustion chamber, combustion air fan, recuperative heat exchanger area,
and stack all vary directly with flue gas volume. Recuperative heat recovery
has the effect of shrinking the entire system, depending on the level of heat
recovery. Table III-4 gives the factors that describe this variation of system
size with various levels of recuperative heat recovery. The factors were developed
with the computerized heat and material balance for 1400°F and 1600°F combustion
temperatures and a waste gas with no oxygen. When the waste gas contains signifi-
cant levels of oxygen, the size-reduction effect as related to recuperative
heating diminishes. Although some size reduction is still seen, the factors in
Table III-4 approach 1.
The fuel used per volume of waste gas is reduced when recuperative heat recovery
is used compared to that when no heat recovery or waste heat boilers are used.
Table III-5 gives the fuel reduction factor for various heat contents, combustion
temperatures, and levels of recuperative heat recovery. These factors, multiplied
times the fuel usage values from Fig. III-2, give the actual fuel usage when
recuperative heat recovery is used. A minimum of 5 Btu/scf of fuel was used
for this evaluation.
The heat content of the flue gas from the combustion chamber is essentially a
function of temperature. Thermal oxidation flue gases from waste-gas incineration
will have similar compositions of N2, 02, H20, and C02 and therefore similar
specific heats. The level of heat recovery is defined as
heat content of flue gas after heat recovery
" heat content of flue gas before heat recovery
With it assumed that the temperature rise in the waste gases plus the combustion
air in a recuperative exchanger is equal to the temperature drop of the flue
gases in the exchangers, a design relationship may be developed relating the
heat exchanger surface area to the level of heat recovery. This assumption is
normally a realistic one since the mass flows and heat capacities of the waste
gas plus air and those of the flue gas are normally similar. Any amount of
heat recovery is possible up to the point where the temperature of the preheated
combustion feed gas approaches the flue gas temperature. This point represents
the maximum possible heat recovery for a combustion chamber at a given tempera-
ture. The heat content of the flue gas is shown in Fig. III-5. Figures III-6
-------
111-15
Table III-4. Thermal Oxidizer Size Reduction Factor for
Recuperative Heat Recovery Systems
Level of Recuperative
Heat Recovery
Size Reduction Factor
1400°F
1600°F
30
50
70
0.850
0.770
0.701
0.830
0.744
0.667
-------
111-16
Table III-5. Fuel Reduction Factors for
Recuperative Heat Recovery Systems
Level of Recupera
Heat Recovery
(%)
Fuel Reduction for Various
tive Waste Gas Heat Contents
1 Btu/scf
10 Btu/scf 13
Combustion Temperature = 1400
30
50
70
30
50
70
0.635 0.525
0.420 0.260
0.240 0.044
Combustion Temperature = 1600
0.590
0.393
0.212
0.530
0.297
0.083
Btu/scf
op
0.490
0.210
°F
0.501
0.260
0.034
20 Btu/scf
0.400
0.061
0.380
0.134
-------
111-17
1000
U=OVERALL HEAT TRANS-ER COEFFICIENT
cr
001
10
30 40 50 60
HEAT RECOVERY (%)
Fig. III-6. Recuperative Heat Exchanger Design at 1400°F Combustion
Temperature (100°F Feed Gas, Constant Specific Heat)
-------
111-18
1000
0
CO
oh
Lu
O
en 1.00
UJ
u_
UJ
a:
UJ
O
o:
tr
u
o
I
o
X
UJ
UJ
i
U-
o
Q
H
<
(T
0.10
0.01
OVERALL HEAT TRANSFER COEFFICIENT
30 40 50
HEAT RECOVERY (%)
Fig.
Combustion Temperature
-------
111-19
and 7 show the ratio of the heat exchanger surface to the flue-gas flow rate as
functions of the percent heat recovery and the overall heat transfer coefficient
(U) for a recuperative exchanger for 1400°F and 1600°F flue gases.
Overall heat transfer coefficients of these heat exchangers depend on the type of
design. Cross-flow exchangers tend to have overall heat transfer coefficients
around 2 to 5,2'3 whereas U-tube exchangers are reported to have coefficients of
6 to 8.4 Design calculations leading to cost estimates in this report assume
an overall heat transfer coefficient of about 4.
Once a value for the area-to-flow ratio is determined, the heat exchanger area
is calculated by multiplying the flue gas flow (in scfm) by the ratio.
4. Waste Heat Steam-Generation Boiler Heat Recovery
The maximum heat recovery by a waste heat steam-generation boiler depends on
the temperature of the exhaust gas after it exits the boiler. Although flue
gas temperatures can be reduced to the condensation temperatures of the compon-
ents in the flue gas, in this study it is assumed that the flue gas exhaust
temperature is 500°F. Since more heat could be recovered, this is a more con-
servative but more universal assumption. With the flue gas exhaust temperature
specified, the maximum heat recovery is established. This relationship is shown
in Fig. III-8. The dotted lines in this figure relate to a reasonable range of
heat capacities or specific heats of the flue gas. Figure III-9 relates the
ratio of boiler-tube surface area to the flue-gas flow rate and the flue gas
temperature, steam temperature, and overall heat transfer coefficient. The
surface area of the waste heat boiler is determined by multiplying the flue-gas
flow rate by the ratio from Fig. III-9. The flue-gas flow rate from a thermal
oxidizer employing a waste heat boiler is the same as that from a thermal oxidizer
using no heat recovery. Unlike the recuperative heat recovery case, no reduction
in system size or fuel use is seen when a waste heat boiler is used.
5. Stack
The cross-sectional area of the stack is determined by assuming a superficial
linear velocity (3000 fpm) and dividing into the actual flow rate of the flue
gas or exhaust gas (with or without heat recovery). Figure III-4 can be used
to convert the scfm to acfm when the temperature is known. Table III-6 lists
-------
MAXIMUM HEAT RECOVERY (%)
I
00
s
PJ
X
H-
3
(D
PJ
rt
o
o
CD
1-1
Ml
K
g
rt
(D
ffi
(D
CO
O
H-
M
U)
rt
t-3
CD
PJ
rt
CD
II
Ul
O
O
02-111
-------
100
X V> 0.50
8, STEAM 450 °F
U = 8, STEAM 250 °F
U=12, STEAM 450°F
1
, STEAM 450
, STEAM 250 °F
U=20, STEAM 250 °F
U=OVERALL HEAT
TRANSFER COEFFICIENT
0.05
1200 1400 1600 1800 2000 2200 2400 26 0
FLUE GAS TEMPERATURE (°F)
i
N)
Fig. Hl-9. Ratio of Waste Heat Boiler
Heat Exchange Surface to Flue Gas Flow vs
Flue Gas Temperature
-------
111-22
the temperatures of the gases after they are exhausted from the recuperative
heat exchangers or from the waste heat boiler. A waste heat boiler operating
at maximum heat recovery will have an exhaust gas temperature of 500°F.
Table III-6. Flue Gas Exhaust Temperature After Heat Recovery
Combustion
Chamber
Temperature Temperature (°F) After Heat Recoveries of
(°F) 30% 50% 70%
1400 1040 760 510
1600 1160 860 570
The height of the stack is based either on its proximity to tall structures or
on the maximum exhaust gas component concentrations at certain linear distances
from the stack. The latter requires air dispersion calculations and component
criteria. For convenience in this study a constant stack height of 80 ft is
assumed. Little effect on total capital costs, annual costs, or cost effective-
ness is expected if the stack height is changed within reasonable limits.
6. Other Equipment
The amount of piping or ducting required for installation of a thermal oxidizer
is dependent on site considerations and the proximity of the thermal oxidizer
to the waste gas source. This system design includes 150 ft of round-steel
inlet ductwork with four ells, one expansion joint, and one damper with control.
Considerably more ducting may be required for special cases; however, since the
ducting included comprises only 2 to 8% of the total capital costs, a great
deal of extra ducting would be required to significantly change the total capital
cost.
Some special waste gases may contain components that form noxious gases during
combustion, for example, sulfur-containing and halogen-containing waste gases.
Flue gas scrubbers are required to reduce the level of these noxious gases in
the exhaust gas. The Control Device Evaluation, Thermal Oxidation Supplement
addresses the incremental capital increase when this option is required.
-------
111-23
C. COMBUSTION ALTERNATIVES
An alternative technology that is used for incineration of waste gases with low
heat contents is catalytic oxidation, in which a catalyst is used to increase
the oxidation rate of the gases at lower temperatures. This is discussed in
the Control Device Evaluation, Catalytic Oxidation.
Waste gases with high heat contents are often candidates for use as fuel gas to
a boiler or are controlled by flaring. A control device evaluation report for
this technology is also in preparation.
-------
IV-1
IV. CONSIDERATIONS FOR INSTALLING THERMAL OXIDATION CONTROL EQUIPMENT
Thermal oxidizers can be large process units, depending on the volume of waste
gas to be controlled, and could require a plot of land as large as 300 ft by
300 ft for installation.
Since thermal oxidizers utilize combustion with a flame for achieving VOC destruc-
tion, the unit must be located at a safe distance from process equipment using
flammable chemicals or special designs must be employed to minimize the risk of
explosion.
Thermal oxidizers require natural gas or fuel oil, electrical power, and instru-
ment air and, if scrubbing is needed, water at the site. If steam is generated
from waste heat, then it is useful to minimize the distance from the waste heat
boiler to the steam consuming site. No special utilities are needed.
Retrofitting thermal oxidizers into existing plants requires careful considera-
tion of site location since all the above considerations apply and sufficient
space in an existing plant may not be available. The unit may have to be located
at longer distances from the waste gas source than would be required for a new
plant.
-------
V-l
V. COST AND ENERGY IMPACTS OF THERMAL OXIDIZERS
A. COST BASIS
The estimated capital costs for total systems combinations and for various com-
ponents are presented in this section. These estimated costs represent the
total investment, including all indirect costs such as engineering and contractors'
fees and overheads, 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.
The estimated costs are based on a new plant installation; no retrofit cost
considerations are included. Those costs are usually higher than the cost for
a new site installation for the same system and include, for example, demolition,
crowded construction working conditions, scheduling construction activities
with production activities, and longer interconnecting piping. Since these
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 will probably be the most significant of these retrofit cost factors.
These factors are so site specific that no attempt has been made to provide
costs. For specific retrofit cases, rough costs can be obtained by using the
new site data and adding as required for a defined specific retrofit situation.
The method used to develop these estimated capital costs was based on preliminary
vendor quotes for the purchase of major equipment items or from such sources as
Richardson Engineering Co. data, and factoring up to installed costs based on
the factors presented in Table V-l. The expected accuracy of the total installed
cost with this degree of engineering detail using this factor method is ±30%.
This method of obtaining estimated total installed capital costs is suitable
for a cost study or for screening estimates. Table V-l lists the factor ranges
used for various cost components and is based on historical data of IT Enviro-
science Process Engineering.
-------
V-2
Table V-l. Factors Used for Estimating Total Installed Costs
A = Major Equipment Purchase Cost
Installation Costs
Foundations
Structures
Equipment Erection
Piping
Insulation
Paint
Fire Protection
Instruments
Electrical
i
B = Base Cost
Sales Tax
Freight
Contractor's Fees
C = Total Contract
a
Engineering
. b
Contingencies
Plus 0.1 to 0.35 Allowance
0.06A + $100 X number of pumps
0.15A (no structures) to 0.30A (multideck structures)
0.15A to 0.30A (depending on complexity)
0.40A (package units) to 1.10A (rat's nest)
0.06A or 0.15 X piping (normal) to 0.30 X piping
(bulk hot or cold)
0.05A
0.01A to 0.06A (depending on requirements)
0.10A to 0.30A or 0.01A to 0.25A + $50,000 to
$300,000 for process control computer
0.15A or 0.05A + $500 per motor
. _ •—
A + Sum of Installation Costs
0.025A + 0.025B
0.16A
0.30 (B-A)
B + Taxes, Freight, and Fees
0.01C to 0.20C
0.15C
D = Process Unit Installed Cost C + Engineering + Contingencies
E = Total Subestimates
F = Total Project Cost
Sum of semidetailed subestimates (buildings, site
development, cooling towers, etc.). Each subesti-
mate should include taxes, freight, fees, engi-
neering and contingency, and should be escalated
to date of expenditure for that cost component.
Engineering costs, contingencies, and escalation
factors for these subestimates will vary according
to the type of job.
D + E
, process engineering, engineering,
, and other support groups.
snould not oe appiiea to anv cost component tnat nas ceen c=~«-
either purchase order or contract.
-------
V-3
The estimate is based on the purchase cost of major equipment A, including a 10
to 35% allowance for other equipment and an assessment of the quality of vendor
quotes. A 10% allowance is used for project definition that includes process
flow sheets and specific budget quotes and a 35% allowance flow sheet for block
flow sheet definition and generalized equipment quotes or prices.
B. CAPITAL COSTS
1. Thermal Oxidizer Complete Systems
Figures V-l through V-6 show the total estimated capital costs that were obtained
for various system combinations and operating conditions, such as various waste-
gas heat contents, residence times, operating temperatures, etc. Combinations
and conditions are as defined on each figure. The method for estimating the
total system costs consisted of combining appropriate costs for components estab-
lished as described below and of adding minimum site development, estimating
allowance, and nominal vendor startup costs. The total added costs for site
development, estimating allowance, and vendor startup were then prorated back
to each individual component. The individual component cost curves can therefore
be combined to build up the total cost for any complete system desired. Since
the component cost curves include a portion of the costs norally assigned for
final complete system installations, they are quite specific for use in estimating
thermal oxidizer systems and therefore should not be used indiscriminately as a
general cost estimating reference for the individual components. Curves showing
purchase costs of combustion chambers, recuperative heat exchangers, and waste
heat boilers are presented in Appendix A.
2. Combustion Chamber
Preliminary purchase quotes for thermal oxidizer combustion chambers were obtained
from vendors. Six vendors were contacted by telephone and letter and three of
them were visited to clarify details and costs: Combustion Engineering Air
Preheater, Peabody Engineering, and Hirt Combustion Engineers. The installed
costs shown in Fig. V-7 through V-ll were obtained by factoring the preliminary
quotes as described above.
The information furnished by vendors included thermal oxidizer purchase cost vs
capacity for several of their standard units. The units were quoted as being
-------
DECEMBER 1979 TOTAL INSTALLED CAPITAL ($1,000)
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INSTALLED CAPITAL
OXIDATION SYSTEMS TOTAI
10 Btu/scf, 0.75 sec, 1400 °F
No Heat Recovery
2. 30% Recup. Heat Recovery
3. Boiler 250 psi Steam
4. Boiler 400 psi Steam
5. 50% Recup. Heat Recovery
70% Recup. Heat Recovery
1.0
5.0 100
WASTE GAS FLOW (1,000 SCFM)
50.0
100.0
-------
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DECEMBER 1979 TOTAL INSTALLED CAPITAL ($1,000)
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-------
7,000
i—i—r
- THERMAL OXIDATION SYSTEMS TOTAL INSTALLED CAPITAL L
10 Btu/scf, 0.75 sec, 1600 °F
1. No Heat Recovery
2. 30% Recup. Heat Recovery
3. Boiler 250 psi Steam
4. Boiler 400 psi Steam
5. 50% Recup. Heat Recovery
_6. 70% Recup. Heat Recovery
5.0 10.0
WASTE GAS FLOW (1,000 SCFM)
50.0
100.0
Fig. V-4. Total Installed Capital Cost for Thermal Oxidation Systems with Waste-Gas Heat
= 10 Btu/scf, Residence Time =0.75 sec, and Combustion Temperature = 1600°F
-------
10,000
>HERMALQXIDAIIQ^SIEMSJD^ INSTALLED CAPIJAL
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100 Btu/scf, 1875°F
1. 0.5 sec, No Heat Recovery
2. 0.75 sec, No Heat Recovery
3. 0.5 sec, Boiler 250 psi Steam
4. 0.5 sec, Boiler 400 psi Steam
5. 0.75 sec, Boiler 250 psi Steam
6. 0.75 sec, Boiler 400 psi Steam
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WASTE GAS FLOW (1,000 SCFM)
50.0
1000
Fig. V-5.
Total installed Capital Cost for Thermal Oxidation Systems with Waste-Gas Heat
Content = 100 Btu/scf and Combustion Temperature = 1875 F
-------
8,000
THERMAL OXIDATION SYSTEMS TOTAL INSTALLED CAPITAL
200 Btu/scf, 2200 °F
1. 0.5 sec, No Heat Recovery
2. 0.75 sec, No Heat Recovery
3. 0.5 sec, Boiler 250 psi Steam
4. 0.5 sec, Boiler 400 psi Steam
5. 0.75 sec, Boiler 250 psi Steam
6. 0.75 sec, Boiler 400 psi Steam
100
5.0 10.0
WASTE. GAS FLOW (1,000 SCFM)
50.0
Fia V-6 Total Installed Capital Cost for Thermal Oxidation Systems with Waste-Gas Heat
Fig. V b. iuta = 2QO Btu/scf and Combustion Temperature = 2200 F
-------
4,000
o
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0-
-------
DECEMBER 1979 INSTALLED CAPITAL ($1,000)
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0% Recup.
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^
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MBER
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WASTE GAS FLOW (1,000 SCFM)
Fia v-9. Installed Capital Cost for the Combustion Chamber with Waste-Gas Heat
Contents - 10 and 100 Btu/scf, Residence Time = 0.5 sec, and Combustion Temperature - 1600 F
-------
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DECEMBER 1979 INSTALLED CAPITAL ($1,000)
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DECEMBER 1979 INSTALLED CAPITAL ($1,000)
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V-15
prepiped and prewired with burners, refractory, etc., all loaded on trucks at
the f.o.b. point. Where available and applicable, these vendors also furnished
costs for the fan, for heat exchanger/crossover, for the boiler for three steam
pressure levels, and for stacks constructed of both refractory and Corten steel.
The costs are based on natural-gas auxiliary fuel and include the necessary
controls for use of the fuel.
For ease of evaluating system component combinations, all components are presented
as a factor of the total waste gas flow in standard cubic feet per minute (scfm).
3. Recuperative Heat Exchangers
Preliminary purchase quotes were obtained from the thermal oxidizer vendors and
estimated installed costs were obtained by applying installation factors as
previously described. The cost curves of Fig. V-12 for recuperative heat exchangers
were developed by the same procedure as that described for combustion chamber
cost development.
4. Boiler
Preliminary purchase quotes for steam-generating waste heat boilers were obtained
from thermal oxidizer vendors for operation at various steam pressure levels
and various proportions of heat recovery. The estimated installed costs were
then obtained by applying installation factors to these purchase costs as previously
described. The cost curves, shown in Figs. V-13 and 14 for the boilers, were
developed as described previously.
5. Fans, Ductwork, and Stacks
The installed capital costs for the fans, ducts, and stacks are plotted in
Figs. V-15, 16, and 17 for systems with no heat recovery, with recuperative
heat recovery, and with waste-heat boilers respectively.
a. Ducts Each system is assumed to require 150 ft of round-steel inlet ductwork
with four ells, one expansion joint, and one damper with an actuator. The cost
data source is a report by CARD, Inc.,15 which was prepared for the EPA and
includes total installed costs.
-------
V-16
10,000
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1,000
10O
1O
RECUPEP/TIVE-TYPF "PAT FXCHANGER INSTALLED CAPITAL
10'Bfu/scf 0.5 or 0.75 sec., 1400 °F S 1600 °F
1. 30% Recup. Heat Recov
2. 50% Recup. Heat Recov
3. 70% Recup. Heat Recov
4-
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sn 100 50.0 100.0
0.5
WASTE GAS FLOW (1,000 SCFM)
Fig. V-12.
installed Capital Cost for Recuperative-Type Heat Exchangers with the
Waste-Gas Heat Content = 10 Btu/scf
-------
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DECEMBER 1979 INSTALLED CAPITAL ($1,000)
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-------
V-18
10,000
o
WASTE HEAT RDII ERS (4QO PSD INSTA
1 10 Btu/scf, 0.5 or 0.75 sec., 1400 °F
2 10 Btu/scf, 0.5 or 0.75 sec., 1600 °F
3 100 Btu/scf, 0.5 or 0.75 sec., 1875 F
4 200 Btu/scf, 0.5 or 0.75 sec., 2200 °F
5.0 10.0
WASTE GAS FLOW (1,000 SCFM)
50.0 100.0
Fig. V
-14. installed Capital Cost for Waste Heat Boilers (400 psi)
-------
1,000
o
o
Q.
g
Q.
Q
UJ
l! 100
CO
en
rr
UJ
m
2
UJ
o
UJ
Q
10
DUCTSL_FANS^AND STACK INSTALLED CAPITAL
No Heat Recovery
1. 10 Btu/scf, 0 5 or 0.75 sec., 1400°F & 1600 °F
2, 100 Btu/scf, 05 or 0.75 sec., 1875 °F
3. 200 Btu/scf, 0.5 or 0.75 sec., 2200 °F
~0.5 1.0 5.0 10.0
WASTE GAS FLOW (1,000 SCFM)
50.0
100.0
Fig. V-15. Installed Capital Costs for Inlet Ducts, Waste Gas, and Combustion Air Fans and Stack for
System with No Heat Recovery
-------
3
01
rt
O
PJ
>0
P-
rt
0)
O
O
en
rt
01
l-h
50 O
CO H
n
^ (B
O) rt
?- O
< e
n> o
rt
K tn
(B »
ft a
01
5d 01
(T) rt
n (D
O
< o
(D Q)
l-< 01
><
0)
O
o
w
rt
DECEMBER 1979 INSTALLED CAPITAL ($1,000)
0)
01
n
7?
H-
rt
-------
I
M
-J
W
rt
0)
a.
o
p-
rt
Ml
O
h|
fa O
tn c;
rt
0>
DECEMBER 1979 INSTALLED CAPITAL ($1,000)
o
rt
w
K -
0>
0> S
ft Cu
Cd rt
O (D
h1-
M O
fl> PJ
h( [n
en -
a.
o
o
rt
H-
O
3
M-
D
W
cn
rt
0)
o
CO
H
m
CD
>
CO
~n
r~
o
o
O
O
CO
o
H-
rt
T3-A
-------
V-22
c.
Fans Each system is assumed to require both a process-waste-gas and combustion
air fan. Various pressure-head requirements were assumed to match system require-
ments, such as increased pressure drop caused by incorporation of the heat recovery
device. The cost data source is a tabulation of equipment purchase costs by
Richardson Engineering Co.16 The installed costs shown were obtained by apply-
ing installation factors as described above.
Stacks Purchase and erection cost data were obtained from one thermal oxidizer
vendor and used as the basis for estimating the installed costs.
C. ANNUAL COSTS
Annual costs for various operating conditions are presented in Appendix B. These
costs were the basis for all the cost-effectiveness graphs included in the report.
The basis used in calculating these annual costs is defined in Table V-2. It
is necessary to fix the annual cost parameters so that costs developed in
this report are consistent with costs developed by IT Enviroscience for
other control devices. The cost methodology is well documented and annual
costs can be adjusted for future increases.
Table V-2. Annual Cost Parameters
Operating factor 8760 hr/yr*
Operating labor $15/man-hour
Fixed costs
Maintenance labor plus materials, 6%
Capital recovery, 18%b 29% installed capital
Taxes, insurances, administrative charges, 5%
Utilities
Electric power $0.03/kWh
Natural gas $2.00/million Btu
Heat recovery credit (equals natural gas) $2.00/million Btu
Process downtime is normally expected to range from 5 to 15%. If the hourly
rate remains constant, the annual production and annual VOC emissions will be
correspondingly reduced. Control devices will usually operate on the same
cycle as the process. From the standpoint of cost-effectiveness calculations,
the error introduced by assuming continuous operation is negligible.
bBased on 10-year life and 12% interest.
-------
250
HEAT CONTENT
(BTU/SCF)
10
13
20
NET ANNUAL COSTS, NO HEAT RECOVERY
TEMPERATURE: 1400°F
RESIDENCE TIME: 0.5 SEC
i
N)
U>
UJ —0 —
-50
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-18. Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers Using
No Heat Recovery, 1400°F Combustion Temperature, 0.5 sec Residence Time, and
Heat Contents from 1 to 50 Btu/scf
-------
250
HEAT CONTENT
1
NET ANNUAL COSTS, NO HEAT RECOVERY
TEMPERATURE: 1400°F
RESIDENCE TIME: 075 SEC
-50
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
-------
250
HEAT CONTENT
NET ANNUAL COSTS, NO HEAT RECOVERY
TEMPERATURE: 1600 °F
RESIDENCE TIME: 0.5 SEC
<
tn
-50
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-20. Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers Using No Heat Recovery,
1600°F Combustion Temperature, 0.5 sec Residence Time, and Heat Contents from 1 to 50 Btu/scf
-------
250
NET ANNUAL COSTS, NO HEAT RECOVERY
TEMPERATURE: 1600 °F
RESIDENCE TIME: 0.75 SEC
-50
500
50,000 100,000
Flow Rate for Thermal Oxidizers Using No Heat Recovery,
_ . , __ . .e «™ 1 4~ f^ RH TH- n /cri'F
1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
-------
250
200
u_
u
CO
g 150
§
CO
cr
o 100
to
o
CJ
^ 50
LJ
o
^4o
o
CO
1
-50
HEAT CONTENT
(BTU/SCF)
1
10
13
20
NET ANNUAL COSTS, 50% RECUPERATIVE HEAT RECOVERY
TEMPERATURE: 1400 °F
RESIDENCE TIME: 0.5 SEC
500
5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-22. Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizers Using
Recuperative Heat Recovery, 1400°F Combustion Temperature, 0.5 sec Residence Time,
and Heat Contents from 1 to 20 Btu/scf
-------
250
u_ 200
O
CO
CO
cr
O
CO
O
O
150
100
50
CO
O
0
CO
-50
HEAT CONTENT
BTU/SCF)
1
-I—Mill 1 I I I T~
NET ANNUAL COSTS, 50% RECUPERATIVE HEAT RECOVERY
TEMPERATURE: 1400 °F
RESIDENCE TIME: 0.75 SEC
<
oo
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig V-23 Net Annual Costs vs Waste Gas Flow Rate for Thermal Oxidizer Using
Recuperative Heat Recovery, 1400°F Combustion Temperature, 0.75 sec Residence Time and
Heat Contents from 1 to 20 Btu/scf
-------
250
U.
O
CO
200
O
p 150
CO
cr
O
h- 100
CO
O
o
50
< H
CO
h- O
UJ JrL
CO
0
-50
1
10
13
20
_! !—r , | |Tn 1 i r—r-r-r
NET ANNUAL COSTS, 50% RECUPERATIVE HEAT RECOVERY
TEMPERATURE: 1600 °F
RESIDENCE TIME: 0.5 SEC
HEAT CONTENT
(BTU/SCF)
<
to
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-24. Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer Using
Recuperative Heat Recovery, 1600°F Combustion Temperature, 0.5 sec Residence Time and
Heat Contents from 1 to 20 Btu/scf
-------
250
NET ANNUAL COSTS, 50% RECUPERATIVE HEAT RECOVERY
TEMPERATURE: 1600 °F
RESIDENCE TIME: 0.75 SEC
HEAT CONTENT
(BTU/SCF)
LO
o
-50
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig V-25. Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer Using
Recuperative Heat Recovery, 1600°F Combustion Temperature, 0.75 sec Residence Time and
Heat Contents from 1 to 20 Btu/scf
-------
o
250
200
= 150
<
CO
cr
o
CO
o
o
100
3 50
§ n
h- o
uj o
CO
•0
-50
HEAT CONTENT
(BTU/SCF)
1
NET ANNUAL COSTS, WASTE HEAT BOILER
(250 PSI STEAM)
TEMPERATURE: 1400 °F
RESIDENCE TIME: 0.5 SEC
<
u>
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-26. Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer Using
Waste Heat Boiler, 1400°F Combustion Temperature, 0.5 sec Residence Time, and Heat
Contents from 1 to 50 Btu/scf
-------
250
HEAT
CONTENT
(BTU/SCF)
-50
NET ANNUAL COSTS, WASTE HEAT BOILER
(250 Pol STEAM)
TEMPERATURE: 1400°F
RESIDENCE TIME: 0.75 SEC
<
to
500
10QO 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
v-27. Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer Using
Heat Boiler, 1400°F Combustion Temperature, 0.75 sec Residence Tzme, and
Heat Contents from 1 to 50 Btu/scf
-------
250
NET ANNUAL. COSTS, WASTE HEAT BOILER
50 PSI STEAM)
PERATURE: 1600°F
DENCE TIME: 0.5 SEC
HEAT
CONTENT 3
;BTU/SCF) 20
-50
I
w
co
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-28. Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer Using
Waste Heat Boiler, 1600°F Combustion Temperature, 0.5 sec Residence Time, and
Heat Contents from 1 to 50 Btu/scf
-------
250
NET ANNUAL COSTS, WASTE HEAT BOILER
HEAT 1
CONTENT 10
BTU/SCF) 13
(250 PSI STEAM)
TEMPERATURE: 1600 °F
RESIDENCE TIME: 0.75 SEC
<
UJ
500
1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig V-29 Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer Using
Waste Heat"Boiler, 1600°F Combustion Temperature, 0.75 sec Residence Time, and
Heat Contents from 1 to 50 Btu/scf
-------
250
200
150
100
— 0
-50
NET ANN
(250 PS
HEAT CC
TEMPER/
- RESIDEN
k
N?
UAL C(
>i STE/
NTENT
\TURE:
CE TIF
^
\
DSTS,
\M)
- 10
1875
vIE: C
^>
s
NO
0 B
0 F
).5S
^=
^
HE
TU/
5EC
sa=
^
AT
'S(
/5
==
=5:
c
R
;F
M[
=
]
EC
)(
•••.
— *.
:c
3.
r
"MM
——•
VERY AND V
75 SEC
slO HEAT RE
J 075 SE
=:=====
0.5 SEC
WASTE HEAT BOI
(250 PSI STEA
^laTSSEC
) 5 S^=:=:=:=::==
^ASTE
:COVER
C
LER
M)
===
HEAT
Y
i
= • —
=r
BC
-
ILE
R
. 1
U)
Cn
500 1000 5000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-30. Net Annual Cost vs Waste Gas Flow Rate for Thermal Oxidizer with
No Heat Recovery and with a Waste Heat Boiler; Heat Content = 100 Btu/scf
-------
300
NET ANNUAL COSTS, NO HEAT RECOVERY AND WASTE HEAT BOILER
(250 PS1 STEAM)
HEAT CONTENT-200 BTU/SCF
TEMPERATURE: 2200° F
RESIDENCE TIME: 0.5 SEC AND 0.75 SEC
NO HEAT RECOVERY
' I 0.75 SEC
WASTE HEAT BOILER
1(250 PSI STEAM)
U 0,75 SEC
<
U)
-300
500 1POO 5,000 10,000
WASTE GAS FLOW RATE (SCFM)
50,000 100,000
Fig. V-31.
Net Annual Cost vs Waste Flow Rate for Thermal Oxidizer with No Heat Recovery and
with a Waste Heat Boiler; Heat Content = 200 Btu/scf
-------
V-37
Figures V-18 through V-31 present the annual cost of thermal oxidation for various
cases.
D. COST EFFECTIVENESS AND ENERGY EFFECTIVENESS
The cost effectiveness and energy effectiveness are calculated by dividing the
annual cost for a particular option (Appendix B) or the fuel usage (in Btu/yr) by
the total annual amount of VOC destroyed, with the destruction efficiencies assumed
as given in Table II-2. Changes in these values with changes in destruction effi-
ciencies owing to specific applications different from the conservative design used
in this report are small.
The cost effectiveness is presented in Table V-3 and the energy effectiveness is pre-
sented in Table V-4. Cost-effectiveness graphs are shown as a function of destruc-
tion efficiency in Figs. V-32 through V-34. Data on cases not shown in the above-
mentioned tables and figures can be easily developed by use of Appendix B.
E. OTHER IMPACTS
Other than costs and energy consumption, other impacts of thermal oxidation
must be related to the flue gas and the components it emits to the environment.
A typical analysis of the flue gas with the emission ratio (Ib of component/
1000 scf of waste gas) is given in Table V-5.
-------
V-38
Table V-3. Cost Effectiveness of Thermal Oxidation
Cost Effectiveness ($ per Ib of VOC Destroyed)
90* VOC Destruction
Waste
Waste Gas Gas
Heat Flow
Content Rate
1 700
5,000
50,000
100,000
10 700
5,000
50,000
100,000
13 700
5,000
50,000
100,000
20 700
5,000
50,000
100,000
SO 700
5,000
50,000
100,000
100 500
5,000
50,000
100,000
200 500
5,000
50,000
vex:
Destroyed
(lb/hr)C
at 90%
2.59
18.5
184.9
369.7
25.9
184.9
1,849
3,697
33.6
240.3
2,403
4,806
51.8
369.7
3,697
7,394
129.4
924.3
9,243
18,486
e
e
VOC
Destroyed
(lb/hr)C
at 99%
2. 84
20.3
203.3
4O6.7
28.4
203.3
2,033
4,066
37.0
264.3
2,643
5,287
57.0
406.7
4,067
8,134
142.4
1,017
10,170
20,340
203.4
2,034
20,340
40,670
406. 7
4,067
40,670
Case I
No Heat
Recovery
S6.39
2.83
2.29
2.25
0.546
0.253
0.199
0.195
0.459
0.187
0.145
0.142
0.284
0.109
0.0821
0.0801
0.0944
0.0232
0.0123
0.0115
Case 11-50
50% Recu-
perative
Heat
Recovery
S6.35
2.00
1.26
1.20
0.534
0.159
0.0849
0.0794
0.452
0.114
0.0568
0.0527
0.284
0.0648
0.0277
0.0250
d
Case III-250
Waste Heat
Boiler
250 psi
Steam
56.61
2.01
1.25
1.19
0.566
0.170
0.0950
0.0888
0.476
0.123
0.0651
0.0603
0.295
0.0679
0.0303
0.0272
0.0988
0.0067
(0.0084)
(0.0096)
b
99% VOC Destruction
Case I
No Heat
Recovery
$6.43
3.19
2.67
2.63
0.615
0.291
0.239
0.235
0.463
0.217
0.177
0.174
0.288
0.130
0.104
0.102
0.108
0.0334
0.0232
0.0223
0.0572
0.0123
0.0069
0.0065
0.0326
O.OOB2
0.0054
Case 11-50
50% Recu-
perative
Heat
Recovery
$6.07
2.01
1.32
1.28
D.575
0.169
0.100
0.096
0.435
0.122
0.0693
0.0662
0.266
0.0635
0.0341
0.0321
d
f
f
Case I1I-2SO
Waste Heat
Boiler
250 psi
Steam
$6.31
2.08
1.35
1.28
0.603
0.180
0.107
0.100
0.454
0.132
0.0754
0.0702
0.282
0.0747
0.0381
0.0347
0.105
0.0113
(0.0033)
(0.0046)
0.0601
(0.0057)
(0.0143)
0.0211
(0.0011)
(O.O162)
aAssuraes 1400'F combustion temperature and 0.5-sec residence time.except
bAssumes 1600'F combustion temperature and 0.5-sec residence time except
CVOC molecular weight, 50; molar heat of combustion, 730,250 Btu/lb-mole
d50% recuperative heat recovery is not applicable to heat contents of 50
Sl600°F combustion temperature assumes only 99% efficiency case.
Recuperative heat recovery is not applicable to temperatures >1600°F.
where otherwise noted.
of VOC.
Btu/scf.
-------
Table V-4. Fuel Energy Effectiveness of Thermal Oxidation
FV
Waste Gas
Heat Content 90%
_Q3tu/scf)a D.egH!
1 63
10 54
13 51
(Btu/sc
.5
.2
.0
20 43.6
50 12-0
100
200
_ — "
ascf of waste gas.
Based on waste heat
C14008F and 0.5-sec
d!600°F and 0.5-sec
e>1600°F and 0.5-sec
^99% VOC destruction
b
99% vOCd 90% VOCC 99% VOCd
struction Destruction Destruction^
82.3 26.3 30.6
73.0 17.0 ^i-J
69.9 13-8 18.2
62.5 6-37 10'8
31.1 (25.2) (20.6)
13. 2e f (68.4)
in'< f (163.4)
. . — —
Energy Effectiveness (Btu/lb of VOC Destroyed)
— , — — ' "
~~~' " c 99% VOC Destruction
90% VOC Destruction _ ~™
P T Waste Heat Boiler Case I
Y 400-psi Steam No Hpat Recovery _
927 400 384,100 1,202,000
79,200 24,800 106,600
57,300 15,500 ™,500
31,800 4,700 45,600
3,500 (7,400) 9-100
f f 1 , 900
f 1,500
Case III-400
Waste Heat Boiler
400 psi-Stcam
446,900
31,100
20,400
7,900
(6,000)
(10,000)
(11,900)
boiler generating 400-psi steam.
residence
residence
residence
time .
time .
time .
only at >1600"F and 0.5-sec residence time.
-------
Q
LLJ
O
cr
h-
co
LJ
O
O
O
CO
CO
LJ
2
LJ
O
LJ
U_
U_
co
O
O
f.(J
6.0
50
40
3.0
2 0
1 r\
i
f ~ ~ *~T ' '
HMMW
„ _ .
- NO HEAT
- 250 psi \A
___ : — —
700 SCFM OFFGAS FLOW — ^
RECOVERX
/ASTE HE A"
— —
50,000 J
|
/
r BOILER
.
sCFM OFFC
.
>AS FLOW-
sr
I
I
CONDITIONS
RESIDENCE
VOC MOL/
73C
VOC MOLf
••.I-—- j '••
T
~ ,
: TIME: O.J
\R HEAT C
),250 Btu/l
OCULAR W
• — •
5 SEC.
'ONTENT:
b MOLE
rIGHT: 50
_... ~"
•
4i>
O
90 91 92 93 94 95 96
VOC DESTRUCTION EFFICIENCY (%)
Pig. V-32. Cost Effectiveness vs VOC Destruction Efficiency for Waste Gases with
1 Btu/scf Heat Content
99
-------
0.7
NO HEAT RECOVERY
10 BTU/SCF
ft •"
.R
:A
*" ™ " '*" i , -— - -^ ^*~
y
T BOILER
_— —
CONDITION
RESIDENC
VOC MOL
73(
VOC MOL
E TIME-. 0.
l\R HEAT C
3,250 Btu/
ECULAR WE
13 BTU/SCF
K err
ONTENT:
Ib MOLE
IGHT: 50
20 BTU/SCF
f
50 BTU/SCF,
93 94 95 96
VOC DESTRUCTION EFFICIENCY (%)
97
98
99
Fia V-33 cost Effectiveness vs VOC Destruction Efficiency for Thermal Oxidizer with
No ieit Recovery and with a Waste Heat Boiler, Heat Contents = Between 1 and 50 Btu/scf and
Waste Gas Flows = 700 scfm
-------
0.25
NO HEAT RECOVERY
250 psi WASTE HEAT BOILER
CONDITIONS
730,250 B,u/,b MOLE
VOC MOLECULARWEIGHT^O
-0.05
93 94 95 96 97
VOC DESTRUCTION EFFICIENCY (%)
98
99
100
.M. COS,
VOC
Ucienc,
f
-------
V-43
Table V-5. Typical Thermal Oxidizer Flue Gas Composition
Emission Ratio
Component Composition (lb/1000 scf of Waste Gas)
C02a 4.0 vol % 2.2
H20a 10.0 vol % 12.2
82.9 vol % 65.1
a
02 3.0 vol % 2.1
VOC and CH4b 500 - 50 ppm 0.0022 - 0.0002
Carbon monoxide0 10-6 ppm 0.001 - 0.0005
Particulates0 (as carbon) 30-3 ppm 0.001 - 0.0001
Sulfur oxides0 (as S02) <1 ppm 0.00005 - 0.00001
Nitrogen oxides (as N02)C 160 - 30 ppm 0.02 - 0.004
Calculated from thermal oxidizer heat and material balance for a low-
to moderate-heat-content waste gas.
Calculated for 90 and 99% total VOC destruction efficiency.
°Calculated from natural combustion emission factors for industrial
boilers reported in AP-42, Supplement 7 (ref. 12). Variations relate
to variations in factors reported and/or variations in fuel usage for
low- to moderate-heat-content waste gases.
Carbon monoxide, particulates, sulfur oxides, and nitrogen oxide emissions are
small if these agents form in similar quantities to that reported for industrial
gas boilers.12 This assumption may be adequate since the fuel burner region
approximates the fuel burners in boilers. This, however, has not been demon-
strated with experimental data. As cautioned in AP-42, these values are sensi-
tive to burner upsets and may increase by several orders of magnitude in a poorly
designed or operated unit. Increases in these compounds may be caused by waste
gases containing high levels of halogens, sulfur, or nitrogen containing VOC
compounds.
This study does not quantitatively assess the relationship between the VOC destruc-
tion efficiency and the impacts of the components emitted after thermal oxidation.
However, qualitative trends do exist. For instance, a higher VOC destruction
efficiency means a high combustion temperature (or a longer residence time). A
higher combustion temperature may increase nitrogen oxides to an unacceptable
level. However, increased temperatures with adequate oxygen should decrease
any particulate formation if it is carbonaceous in nature.
-------
VI-1
VI. SUMMARY AND CONCLUSIONS
Thermal oxidation is a widely used control technique for VOC emissions. The
limits and design principles of this technique are evaluated in this report.
Design criterion and design procedures are presented that allow for a prelimi-
nary thermal oxidizer design. Thermal oxidizers without heat recovery and with
five levels of recuperative and waste-heat steam boiler heat recovery are con-
sidered. Capital and operating costs are developed, and the annual cost of
thermal oxidation is calculated as functions of the characteristics of the waste
gas. Cost effectiveness and energy effectiveness of 90 and 99% VOC destruction
efficiencies are developed.
The conclusions derived from the cost evaluation are as follows:
1. Since the thermal oxidizer design used here is quite conservative, the
cost-related parameters actually experienced in industry are expected to
impose a lesser economic hardship than is presented.
2. The waste gas heat content is a highly sensitive variable in determining
annual costs, cost effectiveness, and energy effectiveness. In general,
as the heat content increases, the annual costs, cost effectiveness, and
the energy effectiveness decrease. This leads to the general statement
that waste gases with higher heat contents (same flow) cost less to control
than those with lower heat contents.
3. The waste gas flow rate is a highly sensitive variable in determining annual
costs and cost effectiveness. Energy effectiveness is independent of the
flow rate. As the waste gas flow increases (at a constant heat content),
the annual costs increase but the annual cost per scfm of waste gas, the
cost/feed flow ratio, decreases. This ratio decreases drastically between
low flows (700 scfm) and moderate flows (5000 scfm), but remains relatively
constant between moderate (5000 scfm) to large flows (50 to 100,000 scfm).
The increase of waste gas flow favorably decreases the cost effectiveness
of control much like the annual cost/feed flow ratio noted above. Energy
effectiveness is constant with flow.
4. Annual net costs of control decrease as the level of heat recovery increases
for the same waste gas.
-------
VI-2
The annual cost of systems using no heat recovery is normally higher than
that for systems using maximum heat recovery. This may not apply to waste
gases with low flow rates (700 scfm).
The differences in annual costs (all heat contents and flows) between recupera-
tive heat recovery at 70% and waste heat boilers generating steam at 250
and 400 psi are small. The waste heat boiler case (250 psi) may be considered
to have the lowest possible annual cost for a given heat constant and flow
rate.
Residence time increases of from 0.5 to 0.75 sec have little effect on the
annual costs or cost effectiveness, and no effect on the energy effective-
ness. Lower combustion temperatures, however, reduce the quantity of energy
recoverable from the system.
Increasing the VOC destruction efficiency from 90 to 99% by raising the
combustion temperature increases the cost effectiveness and energy effective-
ness for all cases except the cost effectiveness of low flow waste gas
with maximum heat recovery used. Social costs are not considered.
Increasing the VOC destruction efficiency through increased residence time
may be more cost effective and energy effective than increasing the effi-
ciencies by increasing the combustion temperatures.
-------
VII-1
VII. REFERENCES*
1. Personal communication between F. D'Avanzo, Combustion Engineering Air Preheater,
Atlanta, GA, and J. W. Blackburn and J. R. Fordyce, IT Enviroscience,
Feb. 23, 1979.
2. Personal communication between J. Kirkland, Hirt Combustion Co., Montebello, CA,
and J. W. Blackburn and J. R. Fordyce, IT Enviroscience, Mar. 29, 1979.
3. Personal communication between Messers Irrgang and Andreacola, Trane Thermal,
Conshohoctan, PA, and J. W. Blackburn and J. R. Fordyce, IT Enviroscience,
Feb. 28, 1979.
4. Personal communication between J. Hagan and P. Capsis, Peabody Engineering,
Stamford, CT, and J. W. Blackburn and J. R. Fordyce, IT Enviroscience, Mar. 1,
1979.
5. R. D. Ross, "Incineration of Solvent-Air Mixtures," Chemical Engineering Progress
68(8), 59—64 (August 1972).
6. R. H. Barnes, A. A. Putnam, and R. E. Barrett, Battelle Columbus Laboratories,
Columbus, Ohio, Topical Report on Chemical Aspects of Afterburner Systems (EPA
Contract No. 68-02-2629) (August 1978).
7. K. Lee, H. J. James, and D. C. Macauley, "Thermal Oxidation Kinetics of Selected
Organic Compounds," presented at the 71st Meeting of the Air Pollution Control
Association, Houston, Texas, June 25—30, 1978.
8. K. Lee, J. L. Hanson, and D. C. Macauley, Predictive Model of the Time-Temperature
Requirements for Thermal Destruction of Dilute Organic Vapors, Union Carbide
Corporation, Chemicals and Plastics Division, Research and Development Depart-
ment, P.O. Box 8361, South Charleston, WV.
9. V. Kalcevic, IT Enviroscience, letter to D. R. Patrick, EPA, May 4, 1979.
10. J. Cudahy, IT Enviroscience, Trip Report Process and Thermal Oxidation
Consultation During MRI Sampling of Union Carbide Corp., Acrolein and Acrylic
Acid Process Fume Incinerator, Taft, LA, Aug. 20, 1979 (on file at EPA, ESED,
Research Triangle Park, NC).
11. Draft EPA memo on Incinerator Efficiency, May, 1980.
12. T. Lahre, "Fuel Oil Combustion," pp. 1.3-1—1.3-5, and "Natural Gas Combustion,"
pp. 1.4-1—1.4-3 in Compilation of Air Pollutant Emission Factors, 3d ed., AP-42,
Part A (August 1977).
13. Handbook of Chemistry and Physics, 49th ed., pp. D-184—188, Chemical Rubber
Co., Cleveland, 1968.
14. R. C. Reid, J. M. Prausnitz, and T. K. Sherwood, The Properties of Liquids and
Gases, 3d ed., McGraw-Hill, New York, 1977.
15. D. M. Himmelblau, Basic Principles and Calculations in Chemical Engineering,
2d ed., pp. 444—447, Prentice Hall, New Jersey, 1967.
-------
VII-2
16 M L Kinley and R. B. Neveril, CARD Inc., Capital and Operating Costs of Selected
Air Pollution Control Systems, EPA-450/3-76-014 (May 1976).
17. The Richardson Rapid System, Richardson Engineering Services, Inc., Box 370,
Solana Beach, CA, 92075.
*When a reference number is used at the end of a paragraph or on ^heading,
it usually refers to the entire paragraph or material under the heading
however an additional reference is required for only a certain
hen owever an a
of the paragraph or captioned material, the earlier reference number may not
apply to that particular portion.
-------
APPENDIX A
PURCHASE COSTS FOR THERMAL OXIDATION COMBUSTION
CHAMBERS, RECUPERATIVE HEAT EXCHANGERS,
AND WASTE HEAT BOILERS
-------
DECEMBER 1979 BUDGET PURCHASE COST ($1,000
0)
ro
n
o
Bl
rt
en
HI
O
1-3
Sf
hi
0)
o
X
p-
rt
H-
O
n
i
tr
c
tn
ft
p-
o
3
n
tr
(D
H
en
C-V
-------
1,500
1,000
o
o
v>
in
o
o
ui
O
cc
0.
UI
o
o
3
CD
0)
h-
05
CC
UJ
CQ
UJ
O
ui
Q
100
200
1,000 10'00°
RECUPERATIVE HEAT EXCHANGER AREA (FT2)
Fig. A-2. Purchase Costs for Thermal Oxidation Recuperative Heat Exchangers
100,000
-------
o
o
700
O
O
UJ
o
DC
UJ
O
CQ
O
t*-
OJ
oc
UJ
CD
UJ
O
UJ
O
400 PSIG STEAM
— 250 PSJG STEAM
100
10
50
100
500
,HEAT RECOVERY BOILER CAPACITY (1,000 LBS/HR OF STEAM
iq. A-3. Purchase Costs for Thermal Oxidation Waste Heat Boilers
Fig
-------
APPENDIX B
ANNUAL COST DATA
-------
OFF GAS HEAT CONTENT ! BTU/SCF
RESIDENCE TIME Q.-? SEC.
COMB, TEMP L4PQ. _'F
w
I
00
-------
OFF GAS HEAT CONTENT —
RESIDENCE TIME 0.7$ SEC.
COMB, TEMP LJAOQ-'F
.BTU/SCP
w
-------
OFF GAS HE/ST CONTENT lO ..BTU/SCF.
RESIDENCE TIME O.5 5EC.
COMB, T£MP J40Q _'F
CASE
I
MO VJ PAT
RECOVERY
TL-30
3O% HEAT
RECOVERY
.TJ.-50
SO V. HEAT
RECOVERY
IT- TO
1O 7. HEAT
P-EOOVeRY
HUGO
WA5 i E HT.
BOILER
STM.
UJ-250
WASTE HT
BOILER.
STM.
3PF GAS
FLOW
SCFM j
CAPITAL
COST
MOOO
700 1 ^ 7-3
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>00
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359
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477
1 4«o <
7*493
333
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339
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1 1 "54
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79
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-------
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RESIDENCE TIME! Q»j2_ 5EC.
COMB. TEMP
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NET COST OR
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NET
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-------
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TOMB, TEMP \%OQ_'F
0
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CAPITAL '! OPERATING CO
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WC^ilDENCfi TIMC •_?-.. SEC,
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2-i
REPORT 2
CONTROL DEVICE EVALUATION
THERMAL OXIDATION SUPPLEMENT
(VOC CONTAINING HALOGENS OR SULFUR)
H. S. Basdekis
IT Enviroscience
9041 Executive Park Drive
Knoxville, Tennessee 37923
Prepared for
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park, North Carolina
November 1980
D80K
-------
2-iii
CONTENTS OF REPORT 2
Page
I. INTRODUCTION 1-1
II. THERMAL OXIDIZER AND SCRUBBER DESIGN CONSIDERATIONS II-l
A. High-Temperature Thermal Oxidation II-l
B. Flue-Gas Scrubbing for HC1 and S02 Removal II-4
C. Heat Recovery II-6
III. BASIS FOR THERMAL OXIDIZER AND SCRUBBER DESIGN III-l
A. Indentification of Sensitive Variables for Cost and Energy III-l
B. Procedure Used for Designing a Thermal Oxidizer System with III-5
a Scrubber
IV. CONSIDERATIONS FOR INSTALLING THERMAL OXIDATION CONTROL EQUIPMENT IV-1
V. COST AND ENERGY IMPACTS OF THERMAL OXIDIZERS WITH SCRUBBERS V-l
A. Cost Basis V-l
B. Capital Costs V-3
C. Annual Costs V-15
D. Cost Effectiveness and Energy Effectiveness V-30
VI. SUMMARY AND CONCLUSIONS VI-1
VII. REFERENCES VII-1
APPENDICES OF REPORT 2
A. ANNUAL COST DATA FOR SULFUR-CONTAINING VOC CONTROL
B. ANNUAL COST DATA FOR HALOGEN-CONTAINING VOC CONTROL
-------
2-v
TABLES OF REPORT 2
Number
III-l VOC Heats of Combustion III-4
III-2 Ratio of Combustion Air to Waste-Gas Flow Rate vs Combustion 111-12
Temperature
V-l Factors Used for Estimating Total Installed Costs V-2
V-2 Annual Cost Parameters V-16
V-3 Cost Effectiveness of Thermal Oxidation and Scrubbing for V-31
Control of Sulfur-Containing VOC
V-4 Cost Effectiveness of Thermal Oxidation and Scrubbing for V-32
Control of Halogen-Containing VOC
V-5 Fuel Energy Effectiveness of Thermal Oxidation for Control of V-33
Sulfur-Containing VOC
V-6 Fuel Energy Effectiveness of Thermal Oxidation for Control of V-34
Halogen-Containing VOC
-------
2-vii
FIGURES OF REPORT 2
Number
1-1 Process Flowsheet for Thermal Oxidation with a Flue-Gas Scrubber 1-3
II-l C12/HC1 Equilibrium Constant as a Function of Temperature II-3
II-2 Temperature vs Fuel Usage for a Waste Gas at a Heat Content of II-5
1 Btu/scf with 3 mole % 02 in the Flue Gas
III-l Relationship Between Waste-Gas Heat Content, VOC composition, III-3
and VOC Molar Heat of Combustion
III-2 Supplementary Fuel Usage vs Waste-Gas Heat Content III-6
III-3 Ratio of Thermal Oxidizer Flue-Gas Flow to Waste-Gas Flow vs III-8
Waste-Gas Heat Content
III-4 Relationship Between Actual Flow Rates and Flue-Gas Temperature III-9
III-5 Flue-Gas Heat Content 111-10
III-6 Maximum Heat Recovery from a Waste-Heat Boiler 111-13
III-7 Ratio of Waste-Heat Boiler Heat Exchange Surface to Flue-Gas 111-14
Flow vs Flue-Gas Temperature
III-8 Ratio of Quenched to Unquenched Flue-Gas Flow Rate vs Flue-Gas 111-16
Temperature
III-9 Makeup Water Usage Rate for Quenching Chamber 111-17
V-l Installed Capital Cost of the Scrubber Including Quench Chamber V-4
V-2 Installed Capital Cost of Thermal Oxidizer at 1800 and 2200°F V-5
Including Incinerator, Two Blowers, Ducts, and Stack
V-3 Installed Capital Cost of Thermal Oxidizer at 2600 and 3000°F, V-6
Including Incinerator, Two Blowers, Ducts, and Stack
V-4 Installed Capital Cost for Waste-Heat Boilers at 250 psi and V-7
1800, 2200, 2600, and 3000°F Combustion Temperatures
V-5 Installed Capital Cost for Waste-Heat Boilers at 400 psi and V-8
1800, 2200, 2600, and 3000°F Combustion Temperatures
V-6 Total Installed Capital Cost for Thermal Oxidation Systems V-9
with a Scrubber at a Residence Time of 0.5 sec, a Combustion
Temperature of 1400°F
V-7 Total Installed Capital Cost for Thermal Oxidation Systems with V-10
a Scrubber at a Residence Time of 0.5 sec, a Combustion
Temperature of 1600°F
V-8 Total Installed Capital Cost for Thermal Oxidation Systems with V-ll
a Scrubber at a Residence Time of 0.5 sec, a Combustion
Temperature of 1800°F
V-9 Total Installed Capital Cost for Thermal Oxidation Systems with V-12
a Scrubber at a Residence Time of 0.5 sec, a Combustion
Temperature of 2200°F
-------
2-ix
FIGURES (Continued)
Number
V-10 Total Installed Capital Cost for Thermal Oxidation Systems with V-13
a Scrubber at a Residence Time of 0.5 sec, a Combustion
Temperature of 2600°F
V-ll Total Installed Capital Cost for Thermal Oxidation Systems with V-14
a Scrubber at a Residence Time of 0.5 sec, a Combustion
Temperature of 3000°F
V-12 Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with V-17
a Scrubber Using No Heat Recovery, 1400°F Combustion, 0.5-sec
Residence Time
V-13 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with V-18
a Scrubber Using Heat Recovery, 1400°F Combustion Temperature,
0.5-sec Residence Time
V-14 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with V-19
a Scrubber Using No Heat Recovery, 1600°F Combustion
Temperature, 0.5-sec Residence Time
V-15 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with V-20
a Scrubber Using Heat Recovery, 1600°F Combustion Temperature,
0.5-sec Residence Time
V-16 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with a V-21
Scrubber Using No Heat Recovery, 1800°F Combustion Temperature,
0.5-sec Residence Time
V-17 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with a V-22
Scrubber Using Heat Recovery, 1800°F Combustion Temperature,
0.5-sec Residence Time.
V-18 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with a V-23
Scrubber Using No Heat Recovery, 2200°F Combustion Temperature,
0.5-sec Residence Time
V-19 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with a V-24
Scrubber Using Heat Recovery, 2200°F Combustion Temperature,
0.5-sec Residence Time
V-20 Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizer with a V-25
Scrubber Using No Heat Recovery, 2600°F Combustion Temperature,
0.5-sec Residence Time
V-21 Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a V-26
Scrubber Using Heat Recovery, 2600°F Combustion Temperature,
0.5-sec Residence Time
V-22 Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a V-27
Scrubber Using No Heat Recovery, 3000°F Combustion Temperature,
0.5-sec Residence Time
-------
2-xi
FIGURES (Continued)
Number Page
V-23 Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a V-28
Scrubber Using Heat Recovery, 3000°F Combustion Temperature,
0.5-sec Residence Time
V-24 Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with V-29
a Scrubber Using No Heat Recovery, 0.5-sec Residence Time,
Heat Content of 1 Btu/scf, and a Combustion Temperature of
1400°F to 3000°F
-------
1-1
I. INTRODUCTION
This report is a supplement to the control device evaluation report for thermal
oxidation* authored by J. W. Blackburn, July 1980, and describes the control
technology and costs for two additional cases. In the first case conventional
thermal oxidation is used (combustion temperature of 1200 to 1600°F) but, due
to the presence of sulfur-containing VOC in the waste gas, flue-gas scrubbing
is required for removal of S02- The second case is for control of halogen-con-
taining VOC In the waste, which requires high-temperature thermal oxidation
(combustion temperatures of 1800 to 3000°F) and flue-gas scrubbing. The flue-gas
scrubber design is assumed to be similar in each application and to be an
additional cost. The cost of the conventional thermal oxidizers for the first
case is assumed to be the same as that given in the control-device evaluation
report for thermal oxidation whereas a new set of cost data was developed for
the thermal oxidizers in the second case, which also included the cost for a
waste-heat steam-generation boiler.
Conventional thermal oxidation units for VOC control of non-sulfur-containing
and non-halogen-containing compounds normally have combustion chambers with
temperatures of 1400 or 1600°F for low-heat-content gases and temperatures in
the 2200°F range for high-heat-content (100 Btu/scf) gases. The heat content
is a measure of how much heat is generated by the gas during combustion and is
determined by the VOC concentration and its heat of combustion. The heat
content and the waste-gas flow determine the combustion chamber design and
auxiliary fuel usage. The flue-gas exhaust is usually vented to the atmosphere
through a stack without further treatment, although heat recovery units such as
recuperative heaters or waste-heat steam-generation boilers are installed when
there is an economic incentive. The technical analysis of conventional thermal
oxidizers is included in the thermal oxidation report.1*
Waste gases containing sulfur or halogen compounds require flue-gas scrubbing
after thermal oxidation to remove the noxious gases that are formed during
combustion. The flue-gas exhaust from the combustion chamber is first sent
into a water quench chamber to be cooled to its adiabatic saturation
*See References, Sect. VII.
-------
1-2
temperature and is then routed through the scrubber to remove the noxious
gases. After the flue gas goes through the scrubber, it is vented to the
atmosphere through a stack. Waste-heat recovery units can be installed before
the water quench chamber when heat recovery is desired. Figure 1-1 is a flow
diagram of a typical thermal oxidation control device with a scrubber.
Thermal oxidation control of sulfur-containing VOC can be achieved with the
thermal oxidation design procedure discussed in the thermal oxidation report
for non-sulfur-containing and non-halogen-containing VOC control, except that a
quench chamber and scrubber must be provided to remove the noxious gases produced
during combustion. In this report the design and cost of the quench chamber
and scrubber unit are given, together with operating costs associated with the
control of sulfur-containing VOC. The thermal oxidation system costs were
obtained from the control device evaluation report for thermal oxidation.
Thermal oxidation control of halogen-containing VOC requires high-temperature
oxidation to convert the combustion product to a form that can most easily be
removed by scrubbing. For instance, chloride-containing waste gases are
burned at high temperature to convert the chlorine to HCl instead of to C12,
since HCl is more easily scrubbed. In this report the design and cost of
thermal oxidation systems for combustion temperatures of 1800 to 3000°F are
presented, along with the design and cost of the quench chamber and scrubber
required in this temperature range. The waste-heat steam-generation boiler costs
for high-temperature thermal oxidation are also included. The cost of a thermal
oxidizer and waste-heat steam-generation boiler for a combustion temperature of
1800 and 2200°F is obtained from in the control device evaluation report for thermal
oxidation.
The heat content range of the waste gas used in this report is 1 to 100 Btu/scf.
For waste gases with heat contents of less than 100 Btu/scf, supplementary fuel
must be added to maintain a combustion temperature above 2200°F. Gases with
heat contents above 100 Btu/scf were not considered since most sulfur-containing
and halogen-containing compounds will not have a higher heat content unless a
very high concentration is achieved. Heat contents of 13 and 20 Btu/scf in air
normally correspond for most compounds to 25 and 40% of the lower explosive
limits (LEL). Waste gases with heat contents of 20 to 50 Btu/scf (approxi-
mately 40 to 100% of the LEL) must be diluted with air or be enriched with
-------
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t
HEAT
\1
(optional 1
RASE Q
NEUTRALIZER "
1
QUENCH
CHAMBER
i r
1
SUMP
*
^
t
SCRUBBER
A
L
5~* STACK
WATER
I
OJ
Fig.
1-1. Process Flowsheet for Thermal Oxidation with a Flue-Gas Scrubber
-------
1-4
auxiliary fuel because they exceed the flammable safety limits imposed by
insurance companies.
Conventional thermal oxidizers range in size from a unit capable of controlling
several hundred scfm of waste gas to single or multiple units controlling waste
gases in excess of 100,000 scfm. For high-temperature (>2600°F) thermal
oxidation units an upper size limit of ~50,QOO scfm was considered to be reasonable
for this report since no 100,000-scfm units are known to exist. The upper size
limit for the scrubber design used in this report is also 50,000 scfm. Multiple
scrubbers would be required for greater flows.
-------
II-l
II. THERMAL OXIDIZER AND SCRUBBER DESIGN CONSIDERATIONS
The first report on thermal oxidation discussed the effects that the combustion
chamber residence time and temperature have on the design for thermal oxidizers
in the range of 1200 to 2200°F. In this temperature range the residence time
and temperature affect the destruction efficiency of the VOC. The temperature
also affects the auxiliary heat required for flame stability, the method used for
heat recovery, and the capital and operating costs of the system. For control
of sulfur-containing VOC the same considerations and design criteria for thermal
oxidizers hold true except that a scrubber is used after the combustion chamber
to control S02 emissions.
The design considerations and assumptions used in this report are that halogen-
containing VOC are controlled by high-temperature thermal oxidation, that a
scrubbing system is used for high-temperature and conventional systems with
noxious flue gases, and that consideration must be given to heat recovery for
conventional and high-temperature systems.
HIGH-TEMPERATURE THERMAL OXIDATION
For the control of halogenated VOC a higher temperature is required to convert
the noxious combustion products to a more easily removed form. The halogen-
containing VOC most commonly encountered is the chlorinated VOC, which is the
basis of the discussion and economics in this report. Bromine-containing VOC
are more difficult to control due to the more severe conditions required to
convert Br2 to HBr. Fluorine-containing VOC are more difficult to control due
to the high corrosiveness of HF; however, high-temperatures are not required.
A combustion chamber temperature of above 1800°F for a well-designed oxidizer with
a proper residence time will have essentially 99.9% VOC destruction efficiency.2'3
The residence time in the combustion chamber is a design variable specified by
the system designer. The combustion chamber is a chemical reactor, and the
residence time is the time available for the reaction (oxidation) to occur.
Residence times as low as 0.3 sec to several seconds have been utilized in
thermal oxidizer designs. The fraction of the total chamber volume that is at
the combustion temperature depends on the chamber configuration and the design
of the flame burner.
-------
II-2
Although a design engineer should be quite concerned with the actual burner
design and residence time at the combustion temperature, in this control-device
evaluation study it is assumed that the entire combustion chamber volume is at
the combustion temperature. This assumption is justified since later it is
shown that differences as high as 50% in residence time do not significantly
affect the annual cost of thermal oxidation control; however, the capital cost
is affected.
The need of going to a higher combustion temperature for chlorinated compounds
is best shown by the relationship of the reaction of C12 and water.4 Figure II-l
shows the effect of combustion temperature on the equilibrium constant for the
following reaction:
C12 + H20 ^ > 2HC1 + HO 2
The equilibrium constant (K ) indicates the relative concentration of C12 and
HC1 in the exhaust gas from the combustion chamber by the equation
K = (HC1)2 (02)**
p (C12) (H20)
The higher the value of K , the more HC1 will be formed, which is easier to
remove from the exhaust gas than Cl2. At low temperatures (<2000°F) the equilib-
rium constant decreases rapidly, indicating that the C12 concentration in the
exhaust will increase appreciably. To achieve an acceptable low C12 concentration
in the flue gas, temperatures of above 1800°F are necessary. Another way to
increase the conversion of C12 to HCl is to inject steam into the combustion
chamber to force the equilibrium toward HCl. The actual flue-gas concentration
of C12 will not directly follow the value indicated by Fig. II-l since the
kinetics of the reaction may prevent equilibrium from being achieved in the
residence time available.5 The reverse reaction may occur as the combustion
products are cooled. The reverse reaction can be minimized by very rapid
cooling but this may prevent effective heat recovery.5 Selection of the
appropriate combustion temperature requires optimization of the operating costs
with the capital cost involved for the conversion. An optimum design will
differ for different chlorinated feeds. In this report it is assumed that the
-------
II-3
200
100-
C
(0
•+-•
en
C
o
O
£
U
k.
J3
'5
IT
Ul
10-
1800
2200
2600
3000
3400
3600
Temperature
Fig. II-l. Cl /HC1 Equilibrium Constant as a Function of Temperature
for the Reaction Cl
2HC1
1/20,
-------
II-4
VOC in the waste gas is 100% halogenated. When the halogen-containing VOC is
actually a small percentage of the VOC in the waste gas, the optimum combustion
temperature will differ.
For thermal incinerators above 2200°F special designs and materials are required
to ensure proper operation and prevent corrosion. The upper temperature range
required for thermal oxidation of halogenated organics approaches the maximum
achievable flame temperature of the fuel. The high demand for auxiliary fuel
required to maintain high combustion-chamber temperatures is further aggravated
by the large amounts of the combustion air that must also be heated to these
temperatures. For some fuels 3000°F is considered to be the maximum achievable
thermal oxidation combustion temperature. Even though no thermal oxidizers
operating at 3000°F combustion temperature are known to exist, the vendors
state that thermal oxidizers can be built to operate at a combustion tempera-
ture of 3000°F, Figure II-2 shows the effect that temperature has on auxiliary
fuel usage. Above 2600°F each additional increase in temperature requires
substantially larger amounts of auxiliary fuel.
B. FLUE-GAS SCRUBBING FOR HC1 AND S02 REMOVAL
The most common method used for removal of both HC1 and S02 is scrubbing. Many
different equipment configurations and various scrubbing agents are employed.
The key to efficient scrubbing is to establish good contact between the gas and
the liquid to effect complete interphase diffusion. The other factors affecting
scrubbing efficiency are the temperature, pH, and alkalinity of the scrubbing
agent.
The flue-gas scrubbing operation involves three basic steps: quenching of the
flue gas, contacting the flue gas with the scrubbing agent, and separating the
scrubbed material from the scrubbing agent. Quenching of the flue gas will
reduce the temperature of the flue gas and saturate it with water. Some of the
S02 or HC1 will be removed from the flue gas during the quenching operation.
The configuration arid operation of the flue-gas scrubbing-agent contacting
equipment will determine the efficiency of the S02 and HCl removal from the
flue gas. The method used to separate the SO2 or HCl from the scrubbing agent
will determine the final disposal of the sulfur and chlorine compounds. The
methods used range from purging the scrubbing agent and discharging it to the
sewer to recovery of the scrubbing agent for reuse.
-------
II-5
2000
1000'_
ra
O)
a>
in
o
tn
&
O)
re
^
Li.
100
10 i
1000
1400 1300 2200
Temperature
2600
3000
3400
Fin.
Ttraperatiiro vs Fuel Usage for a Waste Gas at a Heat Content
of 1 Btu/scf with 3 mole
O, in the Flue Gas
-------
II-6
The efficiency achieved for S02 removal by scrubbing is in the 90% range. It
is very difficult to achieve higher removal efficiencies for this compound.
However, HCl is relatively easy to remove from flue gases by scrubbing and an
HC1 removal efficiency approaching 99.9% may be achieved.
C. HEAT RECOVERY
Heat recovery offers a potential economic advantage by reducing fuel usage with
a recuperative heat recovery system or by generating steam with a waste-heat
boiler. Combustion temperatures exceeding 1600°F rule out the use of recupera-
tive heat exchangers because of problems with materials of construction and
with associated problems such as possible precombustion occurring in the exchangers.
A waste-heat boiler can be used effectively with temperatures to >3000°F.
With sulfur-containing VOC in the low heat-content range (<50 Btu/scf) recuperative
heat recovery can be used since the combustion temperature does not exceed
1600°F. Waste-heat boilers can be used throughout the operating temperature
range for sulfur-containing VOC thermal oxidation. Since halogen-containing
VOC destruction always requires high combustion temperatures, only waste-heat
boilers can be used for heat recovery. It is possible to use some combination
of waste-heat boiler and recuperative-heat recovery, but this option is considered
to be beyond the scope of this report.
Special precautions may be needed for the recuperative heaters and waste-heat
boilers to prevent excessive corrosion from the corrosive products produced
during the combustion of sulfur-containing and halogen-containing VOC. Design
considerations should include means of preventing condensation of corrosive
gases. For this report the flue-gas temperature after heat recovery will not
be cooler than 500°F.
Due to the high heat duties required for waste boilers above 2200°F there will
be an upper size limit in terms of waste-gas flow. A waste-gas flow of 50,000
scfm for 2600°F combustion, which would require four large wat,te boilers, and a
waste-gas flow of 20,000 scfm for 3000°F, which would require five large waste
boilers, are considered to be the upper size limits in this report. A
200,000,000-Btu/hr heat duty for a waste-heat boiler is considered the upper
size limit. Multiple units can be used for higher heat duties.
-------
III-l
III. BASIS FOR THERMAL OXIDIZER AND SCRUBBER DESIGN
A base case design based on certain assumptions was developed for this study to
generate capital and operating costs, and represents a typical thermal oxidizer
installation for the purpose of air pollution control. The effect that varying
the design assumptions has on capital and operating costs is discussed. Cost
estimates were generated as functions of sensitive design variables, and en-
compass the accepted range of operation of thermal oxidizers.
IDENTIFICATION OF SENSITIVE VARIABLES FOR COST AND ENERGY
A distinction must be made for those design variables which, if changed by a
small amount, would cause significant changes in capital cost, annual operating
cost, or energy usage. These are called sensitive variables, and the cost
curves given in Sect. V include them as parameters. Other variables may be
quite important for an individual system design but have relatively minor
effects on economic or energy-impact conclusions.
The approach used in this study was to determine the sensitivity of certain
variables by means of computerized heat and material balance calculations.
Through this process, estimates of the relationships between the variables and
equipment design and operating costs may be derived. The primary variables
that are a function of the waste gas are the waste-gas temperature, pressure,
flow rate, VOC composition (molecular weight, carbon, oxygen, hydrogen, sulfur,
and chloride ratios of the VOC, and VOC heats of combustion) and other waste-
gas compositions (nitrogen, other inert gases, oxygen, water content, and the
presence of special contaminants).
The waste-gas temperature is assumed to be 100°F for the base case, but an
increase or decrease within reasonable boundaries will have little effect on
the capital or operating costs and it is therefore not considered to be a
significant variable. Sensible heat carried by the waste gas is small compared
to the heat required to raise the gas to its combustion temperature. About
3.5 Btu/scf is required to increase the temperature of nitrogen from 80°F to
260°F. This compares with fuel heat requirements on the order of 60 to
80 Btu/scf to raise the waste gas to combustion temperatures. Waste-gas temper-
ature differences within this range could not change the total heat requirements
-------
III-2
by more than about 6%. Waste-gas pressure is assumed to be 1.5 psig. Pressure
changes within reasonable limits of 1.5 psig also will have no significant
effect on capital or operating costs. Flow rate is a very significant variable
for both capital and operating costs. The waste-gas flows shown in the figures
throughout this report are translated to scfm of waste gas to the thermal
oxidizer.
The heat content of the waste gas is another significant variable. VOC molar
concentration, average molecular weight, carbon, hydrogen, and oxygen ratios,
and heats of combustion (Btu/lb of VOC) are all expressed in the variable of
the heat content of the waste gas (Btu/scf) as shown by the family of compound
lines on Fig. III-l. Multicomponent VOC systems may be described when the mole
fractions of each component are known. The contribution of carbon monoxide to
the total heat content may also be analyzed in this way. Table III-l gives VOC
molar heats of combustion.6
If the actual flue-gas composition is needed, a component material balance must
be performed, for which carbon, hydrogen, oxygen, sulfur, and chloride ratios
are required. In order to estimate "typical" values for those ratios a group
of organic compounds were surveyed.1 The chlorinated VOC component averages of
34.3% carbon, 4.7% hydrogen, and 61% chlorine were used to establish heat
values plus heat and material balance for this evaluation. The sulfur-containing
VOC component averages used were the same as the chlorinated-VOC component
averages except that/61%;was assumed to be sulfur instead of chlorine. The
component values of chlorine or sulfur used in this report may be high compared
to actual component averages of waste gases, since the VOC in the actual waste
gas may not be all chlorinated or sulfur-containing VOC.
The amount of oxygen in the waste gas or that provided by the VOC is important
because it establishes the auxiliary combustion air required and has an impact
on both the capital and operating costs of the thermal oxidizer. In this report
it is assumed that the waste gas and VOC do not contain oxygen (the worst case)
and that therefore maximum auxiliary combustion air is required. The excess oxygen
in the flue gas is assumed to be 3 mole %, which is based on usually accepted
practice.
-------
•n
H
I
P>
rt
H-
0
3
P) tn
3 y
a. H-
13
O tfl
n n>
S3 fu
(D cn
p) rt
rt (D
I
O O
Ml PJ
tn
O
O S3
g ro
& p)
C rt
w
rt n
H- 0
0 D
D ft
(D
3
O
O
O
0
w
h1-
ft
Waste-Gas Heat Content (Btu/scf)
•A
o
I
u>
-------
III-4
Table III-l. VOC Heats of Combustion*
Compound
_____ _r___ i _•*- _ — „ — — .- — — •-••'
Methyl chloride
Methylene chloride
Chloro form
Carbon tetrachloride
Ethyl chloride
Hexach] oroetnane
Dichlorobenzene
Hexachlorobenzene
Carbon disulfide
Carbonyl sulfide
Methyl mercaptan
Ethyl thiocyanate
Ethyl mercaptan
Molecular
Weiqht
50.5
85
119.5
154
64.5
237
111.5
285
76
60
48
96
62
Heat
(Btu/lb)
5 , 850
2,260
1,340
436
8,840
835
8,230
3,220
5,840
3,920
11,170
11,520
13,130
of Combustion
(Btu/lb-mole)
295,400
192,100
160,100
67,140
570,200
197,900
917,600
917,700
443,800
235,200
536,200
1,105,900
814,400
"See ref 6.
-------
III-5
Since the waste gas is assumed to be saturated with water for calculations in
this report, the water content in the flue gas is at a maximum. It is also
assumed that no entrained liquid water droplets enter with the feed. Entrained
water droplets would significantly increase the auxiliary fuel requirements
since the heat capacity of the flue gas increases and the heat of vaporization
for water, 18,000 Btu/lb-mole, must be supplied. Entrainment can normally be
avoided with proper design.
The combustion temperature has a significant effect on fuel costs. As is shown
in Fig. II-2, the fuel usages increase substantially with temperature increases
above 2200°F. Residence time has a major effect on capital costs but a rela-
tively small effect on operating costs.
The significant variables investigated in this report are waste-gas flow, heat
content (encompassing a variety of composition-related variables), combustion
temperature, and residence times. Evaluation of these parameters using generally
worst-case or conservative assumptions will lead to economic and energy impact
conclusions that will equal or exceed actual operating costs and energy impacts
for the applicable cases.
B. PROCEDURE USED FOR DESIGNING A THERMAL OXIDIZER SYSTEM WITH A SCRUBBER
The design procedure that was used for conventional thermal oxidizer units for
sulfur-containing VOC is the same as that given in the control-device evaluation
report for thermal oxidation, except for the scrubbers. The discussion of
quench chambers and scrubbers in this section applies to conventional thermal
oxidizers that may require the addition of flue-gas scrubbing. The design
procedure for high-temperature thermal oxidation is presented in this section.
1. Combustion Chamber
The size of the combustion chamber depends on the flow of waste gas into the
chamber, the fuel usage, the residence time, and the combustion temperature.
The fuel usage is dependent on the heat content of the waste gas and the com-
bustion temperature. Figure III-2 shows the supplementary fuel usage of natural
gas required to sustain the combustion temperatures of 1800, 2200, 2600, and 3000°F
for various waste-gas heat contents. The combustion chamber, the heat recovery
-------
III-6
5000
.
w
ra
•*-
c
V
E
"a.
a.
100
Combustion Temperatures
(a) 3000°F
(b) 2600°F
(c) 2200°F
(d) 1800°F
Assumes no oxygen in the waste gas
(b)
40 60 80 100
Waste-Gas Heat Content (Btu/scf)
120
140
Fig..111-2. Supplementary Fuel Usage vs Waste-Gas Heat Content
-------
III-7
unit, and the scrubber must be sized to handle the flow from all sources,
including that from the waste gas, the auxiliary fuel, the combustion air, and
the combustion products. System designs calculated for this report cover the
waste-gas heat content range of 1—100 Btu/scf. Figure III-3 shows the correlation
between flue-gas flow and waste-gas flow by expressing them as a ratio and dis-
playing the ratio as a function of waste-gas heat content and combustion tem-
perature. In Fig. III-3 the 1400 and 1600°F lines curve upward above 80 Btu/scf
due to the need to add excess air to keep the combustion temperature of 1400
and 1600°F. The temperature would normally be allowed to increase rather than
excess air being added.
Conversion of scfm (standard cubic feet per minute) to acfm (actual cubic
feet per minute) is necessary for sizing of the combustion chamber. Figure III-4
shows this relationship (based on the ideal gas law). Standard temperature and
pressure conditions assumed throughout this report are 32°F and 760 mm Hg and
their equivalents. The ratio of acfm to scfm is read from Fig. III-4 and is
multiplied by the combustion chamber flue gas in scfm. Until this point in the
report the term heat content has referred to the potential energy from combustion
of compounds in the waste gas. Heat content when used in relation to the flue
gas in this report refers to the energy contained by the hot gases because of
their temperature. The basis used for the heat recovery calculations is the
heat content of the flue gas as a function of temperature, as shown in Fig. III-5.
The dotted lines in Fig. I1I-5 correspond to a reasonable variation in specific
heats or heat capacities of the flue gas.
Residence times of 1/2 and 3/4 sec are used to calculate the combustion chamber
internal volume. The combustion chamber flue gas flow (in acfm) is converted
to acfs (actual cubic feet per second) and then multiplied by the residence
time (in sec) to determine the combustion chamber internal volume in cubic
feet.
2. Fans
Fans for both the waste gas and the combustion air are provided for in the
systems evaluated. The flow rates of the waste gas and combustion air and the
pressure drops of the thermal oxidizers are used to calculate fan sizes.
System pressure drops of 6 and 10 in. H20 were assumed respectively for thermal
-------
III-8
15 r
14
_o
u. 13
*-•
ID
S. 11
2 10
tn
TO
O 8
i
o
3
E 7
Combustion Temperature
Assumes no oxygen in the waste gas
3000°F
20 40 60 80 100
Waste-Gas Heat Content (Btu/scf)
120
140
Fig. III-3. Ratio of Thermal Oxidizer Flue-Gas Flow to Waste-Gas Flow vs
Waste-Gas Heat Content
-------
in
c
O
C
O
o
•a
c
a
in
-------
Flue-Gas Heat Content JBtu/acf)
H
I
tn
c
(D
I
a
ffi
(D
n
o
rt
ro
-n
c
0
1
O
cj
(A
H
(D
3
•o
o
o
c
-
Q i
CD ,_
O
o
_h
o -
o
0
N) "
O
0
_*
A \.
O
o
a>
0
0
_^
CO
o
o
M
O
o
o
to
10
0
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ro
t*
O
O
M
a>
0
o
M
CD
o
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u
Q
O
o
\
\
\
s
_
~
-—
H
i
[
I —
i —
i
1
OT-III
-------
III-ll
oxidizers with no heat recovery and those with waste-heat boilers. A pressure
drop of 12 in. H20 is assumed when a scrubber is included. The waste-gas
fan capacity is based on the waste-gas flow rate. Table III-2 gives the combustion
air flow/waste-gas ratio as a function of combustion temperature. The relationship
is based on desired combustion temperatures, as previously discussed, and is
used to size the combustion air fan. The combustion air volume and fan size
may be determined by the use of this ratio multiplied by the volume of waste
gas. Waste gases containing significant levels of oxygen would reduce the
combustion air required and the size of the combustion air fans used in this
study. When waste gases are generated at higher pressure, often no fan is
needed.
3. Waste Heat Steam-Generation Boiler Heat Recovery
The heat recovery by a waste-heat boiler depends on the entrance flue-gas
temperature and the exhaust temperature. The entrance temperature is set by
the thermal oxidizer conditions. For this study the exhaust temperature is assumed
to be 500°F, in order to be well above the flue-gas dew point to prevent potential
corrosion from acid gases. Figure III-6 is a plot of the maximum heat and is
based on the percent of heat available from the flue gas with standard conditions
as the reference point. The dotted lines in the figure relate to a reasonable
range of heat capacities or specific heats of the flue gas. Figure III-7
relates the ratio of boiler-tube surface area to the flue-gas flow rate, the
flue-gas temperature, the steam temperature, and the overall heat transfer
coefficient. The surface area of the waste-heat boiler is determined by multi-
plying the flue-gas flow rate by the ratio from Fig. III-7. The flue-gas flow
rate from a thermal oxidizer employing a waste-heat boiler is the same as that
from a thermal oxidizer using no heat recovery.
4. Quench Chamber
The quench chamber in this study is located in the lower part of the scrubber
column and has the same diameter as the scrubber. The volume is based on a
1-sec flue-gas retention time. The quench reduces the flue-gas temperature to
the adiabatic saturation temperature of the scrubber agent. For this design
slightly alkaline water will be used as the scrubbing agent. To reduce the flue-
gas temperature to the adiabatic saturation temperature of water, considerable
-------
111-12
Table III-2. Ratio of Combustion Air to Waste-
Gas Flow Rate vs Combustion Temperature
Waste-Gas
Heat Content
(Btu/scf)
2
2
50
100
100
100
Combustion
Temperature
(°F)
1400
1600
1800
2200
2600
3000
Combustion Air to
Waste-Gas Flow Rat\o*
/scf of combustion air\
V scf of waste gas 1
0.87
1.1
1.2
1.4
3.1
9.8
*Thermal oxidizer conditions:
No oxygen in waste gas.
VOC molar heat of combustion = 746,000 Btu/lb-mole.
VOC molecular weight = 100
VOC C, H,C1 fraction = 34.3 wt % C, 4.7 wt % H, 61 wt % Cl.
Average waste gas molecular weight = 29.
Water content of combustion air = 1.0 wt %.
3 mole % 0 in flue gas after oxidation.
-------
Maximum Heat Recovery (%
T)
3
0)
M H-
X 3
3- C
fu 3
C
tn K
rt- ra
rt>
3 ?d
^a CD
(t> o
••! o
m <
rt (D
C *~1
(D
II
Mi
0
01 g
o
o PJ
o
"i s;
-- pj
0)
rt
0)
l
S
to
OJ
rt
D3
O
H-
ei-in
-------
111-14
10,
£
o
O
V
ra
in
Cl
e
to
Si
o
X
tu
CO
a
I
o
CD
O
u.
(O I
o !
I I
« 1.0 —
ul
o
L
r
L
L
0.11—
a; Overall heat-transfer coefficient = 8 ; steam=450°F
b Overall heat-transfer coefficient =1 2; steam = 450°F
c Overall heat-transfer coefficient = 8 ; steam = 250°F
id Overall heat-transfer coefficient =1 2 ; steam = 250°F
;e( Overall heat-transfer coefficient = 20; steam-450°F
'fi Overall heat-transfer coefficient =20; steam =250°F
i
o
o
o
03
cc
h-
0.01
1000
1400
1800 2200 2600 3000
Flue-Gas Temperature (°F)
_J J
3400 3800
Fig. III-7. Ratio of Waste-Heat Boiler Heat Exchange Surface to Flue-Gas
Flow vs Flue-Gas Temperature
-------
111-15
water will be vaporized in the quench and will increase the total gas flow
through the scrubber. This increased flow rate through the scrubber due to the
vaporization of water, which is a function of temperature, is shown in Fig. III-8.
The quench ratio has to be multiplied by the flue-gas rate to obtain the flow
rate through the scrubber. Makeup water usage for the quench is dependent on
the flue-gas flow rate and temperature. The makeup water rate is shown in
Fig. III-9. The quench will remove some of the noxious gases in the flue gas.
In this study it has been assumed that 50% of HC1 is removed in the quench and
that 10% of S02 is removed in the quench.
5. Scrubber
The scrubber design in this study is based on a packed column, with slightly
alkaline water used as the scrubbing agent. Different designs for the contacting
device and its aqueous scrubbing agent could be used, but they would not sig-
nificantly offset the capital cost presented. Operating cost could be signi-
ficantly different based on the alkaline agent used to neutralize the scrubbed
acid gases. Acid gas removal efficiencies would also be affected by the choice
of designs.
The column is designed with 36 ft of packing, which is assumed to remove 99.8%
of HCl or 88.9% of S02 in the scrubber. These two removal percentages combined
with the 50% of HCl or 10% of S02 removed in the quench give a total removal
efficiency of 99.9% HCl or 90% S02- The liquid-to-gas ratio (L/G) is assumed
to be 10. A superficial vapor velocity of 3 fps was used for determining the
column diameter. These assumptions are adequate for initial process designs
leading to a preliminary cost estimate.7
The water used as the scrubbing agent will have to be neutralized to control
the pH of the system; in this study caustic (NaOH) is used. The amount of
caustic used is dependent on the concentration of sulfur or chlorine in the
waste gas. The caustic addition rate is 2.50 Ib of NaOH/lb of sulfur in the
waste gas and 1.14 Ib of NaOH/lb of chlorine in the waste gas. The salt formed
will have to be purged from the system and discharged. The makeup water rate,
based on 1% dissolved solids in the water recycle, is 46.5 gal/lb of sulfur in
the waste gas and 19.2 gal/lb of chlorine in the waste gas .
-------
H
I
200
600
1000 1400 1300 2200 2600
Flue-Gas Temperature to Quench (°F)
3000
3400
Fig. III-
8. Ratio of Quenched to Unquenched Flue-Gas Flow Rate vs Flue-Gas Temperature
-------
111-17
100
1000 1400
1800 2200 2600
Flue-Gas Temperature (°F
3000
3400
Fig. III-9. Makeup Water Usage Rate for Quenching Chamber
-------
IV-1
IV. CONSIDERATIONS FOR INSTALLING THERMAL OXIDATION CONTROL EQUIPMENT
Thermal oxidizers can be large process units, depending on the volume of waste
gas to be controlled, and could require a plot of land as large as 300 ft by
300 ft for installation. 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, or special designs
must be employed to minimize the risk of explosion or fire.
Thermal oxidizers require natural gas or fuel oil, electrical power, and instrument
air and, if scrubbing is needed, water and caustic at the site. If steam is
generated from waste heat, then it is useful to minimize the distance from the
waste-heat boiler to the steam-consuming site.
Since a salt is formed during the scrubbing of the flue gas, proper waste dis-
posal of this material is required. The options of disposal range from direct
wastewater discharge to recovery of the material.
Retrofitting thermal oxidizers into existing plants requires careful considera-
tion of site location since all the above factors apply and sufficient space in
an existing plant may not be available. The unit may have to be located further
away from the waste-gas source than would be required for a new plant. Because
of these associated costs the cost of retrofitting a thermal oxidizer in an
existing plant may be appreciably greater than the cost for a new installation.
Also, 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.
-------
V-l
V. COST AND ENERGY IMPACTS OF THERMAL OXIDIZERS WITH SCRUBBERS
A. COST BASIS
The capital costs for total systems combinations and for various components
were estimated. They represent the total investment, including all indirect
costs such as engineering and contractors' fees and overheads, 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.
The estimated costs are based on installation of a new plant; no retrofit cost
considerations are included. Those costs are usually higher than the cost for
a new-site installation for the same system and include, for example, demolition,
crowded construction working conditions, scheduling construction activities
with production activities, and longer interconnecting piping. Since the
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 will probably be the most significant of these retrofit cost factors.
These factors are so site-specific that no attempt has been made to provide
costs. For specific retrofit cases rough costs can be obtained by using the
new-site data and adding as required for a defined specific retrofit situation.
The method used to develop these estimated capital costs was based on
preliminary vendor quotes for the purchase of major equipment items or from
such sources as Richardson Engineering Co. data, and factoring up to installed
costs based on the data in Table V-l. The expected accuracy of the total
installed cost with this degree of engineering detail using this factor method
is +30%. This method of obtaining estimated total installed capital costs is
suitable for a cost study or for screening estimates. The factor ranges given
in Table V-l for various cost components are based on historical data
obtained by Hydroscience Process Engineering.
-------
V-2
Table V-l. Factors Used for Estimating Total Installed Costs
A = Major Equipment Purchase
Installation Costs
Foundations
Structures
Equipment Erection
Piping
Insulation
Paint
Fire Protection
Instruments
Electrical
Cost Plus 0.1 to 0.35 Allowance
0.06A + $100 X number of pumps
0.15A (no structures) to 0.30A (multideck structures)
0.15A to 0.30A (depending on complexity)
0.40A (package units) to 1.10A (rat's nest)
0.06A or 0.15 X piping (normal) to 0.30 X piping
(bulk hot or cold)
0.05A
0.01A to 0.06A (depending on requirements)
0.10A to 0.30A or 0.01A to 0.25A + $50,000 to
$300,000 for process control computer
0.15A or 0.05A + $500 per motor
B = Base Cost
Sales Tax
Freight
Contractor's Fees
A + Sum of Installation Costs
0.025A + 0.025B
0.16A
0.30 (B-A)
C = Total Contract
a
Engineering
. b
Contingencies
B + Taxes, Freight, and Fees
0.01C to 0.20C
0.15C
D = Process Unit Installed Cost C + Engineering + Contingencies
E = Total Subestimates
Sum of semidetailed subestimates (buildings, site
development, cooling towers, etc.). Each subesti-
mate should include taxes, freight, fees, engi-
neering and contingency, and should be escalated
to date of expenditure for that cost component.
Engineering costs, contingencies, and escalation
factors for these subestimates will vary according
to the type of job.
D + E
F = Total Project Cost
Includes cost from capital project teams, process engineering, engineering,
purchasing, and other support groups.
Contingency should not be applied to any cost component that has been committed by
either purchase order or contract.
-------
V-3
The estimate is based on the purchase cost of major equipment (A), including a 10
to 35% allowance for other equipment and an assessment of the quality of vendor
quotes. A 10% allowance is used for project definition that includes process
flow sheets and specific budget quotes and a 35% allowance for block flow sheet
definition and generalized equipment quotes or prices.
B. CAPITAL COSTS
1- Thermal Oxidizer Complete System
The capital cost for thermal oxidizer systems controlling sulfur-containing VOC
is determined from the capital costs estimated in the control-device evaluation
report for thermal oxidation* (Figs. V-l to 4). The installed capital cost of
the scrubber shown in Fig. v-1 can be added to the installed capital cost
given in the cited report* to obtain the total installed capital cost of the
system.
The capital cost for thermal oxidizer systems controlling halogen-containing
VOC is determined by combining the capital cost of the thermal oxidizer
(Figs. V-2, 3), of the waste-heat boiler (Figs. V-4, 5), and of the scrubber
(Fig. V-l). At the combustion temperature of 1800 and 2200°F the capital costs
are obtained from the control-device evaluation report for thermal oxidation.*
The total installed system costs are shown in Figs. V-6 through V-ll. Figures V-9
through V-ll are based on a waste-gas heat content of 1 Btu/scf. An increase in
waste-gas heat content will decrease the flue-gas flow rate, as shown in
Fig. III-3, and decrease the scrubber size.
!- High-Temperature Thermal Oxidizers
Preliminary purchase quotes for high-temperature thermal oxidizers were obtained
from two vendors. S'9 The installed costs shown in Fig. V-3 include the cost of
fans, ductwork, and stacks. The upper size limit for the high-temperature
thermal oxidizers is assumed to be 20,000 cfm for a 2600°F combustion tempera-
ture and to be 5000 cfm for a 3000°F combustion temperature. The reason for
this limit is due to the waste stream not containing oxygen so large amounts of
combustion air is required.
-------
Installed Capital Cost, December 1979 ($1OOO
Tl
C
3
(9
T]
O
o
c
to
3-
c
cr
cr
O
O
O
O
3
-------
1 0,000
o
o
o
•f
V)
O
!*•
O)
0)
Si
£
a>
o
o
Q
o
o
H3
•*-"•
Q.
O
n
*••
c
1 000 —
100
Combustion
Temperatures
a- 1800°F in 1/2-sec residence time
b- 1800°F in 3A-sec residence time
c- 2200°F in 1/S-sec residence time
d- 2200°F in 3A~sec residence time
f
Ul
0.5
1.0
100
Waste-Gas Flow
Fig. V-2. Installed Capital Cost of Thermal Oxidizer at 1800 and 2200°F
Including Incinerator, Two Blowers, Ducts, and Stack
-------
10,000.
o
o
o
r-
o
o>
a
£
0)
(0
o
o
«
*rf
'EL
o
•o
(0
e
1,000
10O
0.5
<
(a) 2600° F combustion temperature in '/z-sec residence time
(b) 2600° F combustion temperature in %-sec residence time
(c) 3000° F combustion temperature in '/2-sec residence time
(d) 3000° F combustion temperature in %-sec residence time
1.0
10
100
Waste-Gas Flow (lOOO scfm)
Fig. V-3. Installed Capital Cost of Thermal Oxidizer at 2600 and 3000°F,
Including Incinerator, Two Blowers, Ducts, and Stack
-------
V-7
10,000
o
o
o
« 1'000
a
(0
O
•o
0)
o
Si
E
V
o
0)
a
100
10
(a) 1800°F
(b) 2200°F
(c) 2600°F
(d) 3000°F
0.5 1.0 10
Waste-Gas Flow (lOOO scfm)
100
Fig. V-4. Installed Capital Cost for Waste-Heat Boilers at
250 psi and 1800, 2200, 2600, and 3000°F Combustion Temperatures
-------
December 1979 Installed Capital j$1000)
0
o
hg M.
W LQ
p. .
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-------
10,000,—
o
o
o
a
CJ
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c.
« 1,000
a>
o
o
a
(a) No heat recovery
(bi Heat recovery with a 250-psi boiler
10o— J
500
-------
10,000,
o
o
o
TO
•*-•
'5.
o
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-------
10,000
o
o
o
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c.
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O
•o
£ 1000
15
•f*
in
c
o
H
0>
N
ro
o>
JO
E
«
o
V
a
100
(a) No heat recovery
(b) Heat recovery with a
250-psi boiler
500
1000
1 0,000
Waste-Gas Flow fscfm)
100,000
Fig. V-8. Total Installed Capital Cost for Thermal Oxidation Systems with a
Scrubber, at a Residence Time of 0.5 sec, a Combustion Temperature of 1800°F
and a Waste-Gas Heat Content of from 1 to 50 Btu/scf
-------
10,000
o
o
o
1—
£/>
en
O
O
a
(0
O
•o
0)
CO
c
o
h-
O)
E
a>
o
0)
O
1,000
100
f
(a) No heat recovery
(b) Heat recovery with a 250-psi boiler
500
JJ
1,000
_L
L
10,000
Waste-Gas Flow (scfm
100,000
Fig. V-9. Total Installed Capital Cost for Thermal Oxidation Systems with a Scrubber
at a Residence Time of 0.5 sec, a Combustion Temperature of 2200 F, and a
Waste-Gas Heat Content, of 1 Btu/scf
-------
10,000
o
o
o
r-
v>
in
O
O
"5
•*-*
a
O
o
t-
o>
E
o
o
HI
O
1,000
a)
(a) No heat recovery
(b) Heat recovery with a 250-psi boiler
100
500
i
M
U)
1,000
10,000
Waste-Gas Flow (scfm)
100,000
***
oo ^rubber
of 0.5 sec, a Combustion Temperature of 2600°F and a
Waste-Gas Heat Content of 1 Btu/scf
-------
<
I
I".
rf
o
I
O
(D
tn
pj
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(D DJ
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December 1979 Total Installed Capital Cost ($1000j
o
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-------
V-15
3. Waste-Heat Boiler
Preliminary purchase quotes for steam-generating waste-heat boilers were obtained
from vendors for operation at various steam pressure levels and various proportions
of heat recovery. The installed costs were then estimated by applying installation
factors to these purchase costs as previously described. The installed cost of
the 2600°F unit was assumed to be 10% greater than that of the 2200°F unit of
the same heat duty, and the cost of the 3000°F was assumed to be 20% greater than
that of the 2200°F unit. Multiple units were used when the capacity was in excess
of 200,000 Ib/hr of steam, or 240,000,000 Btu/hr. The cost curves shown in Figs. V-4
and V-5 for the boilers were developed as described previously.
4. Scrubbers
The estimated installed costs were obtained by applying installation factors to
the purchase cost of the column as previously described. The scrubber cost
curve shown in Fig. V-l includes the cost of the quench chamber and the recycle
water pump and the additional capital cost involved with a larger fan to overcome
the pressure drop across the scrubber.
For ease in evaluating system component combinations, all components except the
scrubber are presented as a factor of the total waste-gas flow in scfm. The
scrubber flow rate is determined by multiplying the waste-gas flow by the
flue-gas ratio (Fig. III-3) and the quench flow ratio (Fig. III-8).
C. ANNUAL COSTS
Annual costs for various operating conditions are presented in Appendix A for
sulfur-containing VOC and in Appendix B for halogen-containing VOC. The heat
recovery case refers to a 250-psi waste-heat boiler. These costs are the basis
for all the cost-effectiveness graphs included in the report. The basis used in
calculating these annual costs is defined in Table V-2.
Figures V-12 through V-15 show the annual cost of thermal oxidation for various
sulfur-containing VOC cases. Figures V-16 through V-23 show the annual cost of
thermal oxidation for various halogen-containing VOC cases. The annual cost
increases for higher waste-gas heat contents are due to the use of larger
amounts of caustic. Figure V-24 shows the annual cost of thermal oxidation for
various combustion temperatures.
-------
V-16
Table V-2. Annual Cost Parameters
Operating factor
Operating labor
Fixed costs
Maintenance labor plus materials, at 6%
Capital recovery, at 18%
Taxes, insurances, administrative charges, at 5%j
Utilities
Electric power
Natural gas
Heat recovery credit (equals natural gas)
Caustic (50% NaOH)
Makeup water
8760 hr/yr
$15/man-hr
29% installed capital
$0.03/kWh
$2. 00 /million Btu
25<£/1000 gal
aProcess downtime is normally expected to range from 5 to 15%. If the hourly
rate remains constant, the annual production and annual VOC emissions will
be correspondingly reduced. Control devices will usually operate on the
same cycle as the process. From the standpoint of cost-effectiveness cal-
culations, the error introduced by assuming continuous operation is
negligible.
j>
Based on 10-year life and 12% interest.
-------
1000
800
Heat Content (Btu/scf'
* i
50
o
in
*- 600
en
O
O
"to
c 400
200
f
100
1,000
Waste-Gas Flow Rate
10,000
SCflV
100,000
Fig. V-12. Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a Scrubber Using
No Heat Recovery, 1400 F Combustion Temperature, 0.5-sec Residence Time,and a
Heat Content of from 1 to 50 Btu/scf
-------
1000
100
M
oo
1,000
10,000
100,000
Waste-Gas Flow Rate (scfm)
H
Heat Content of from
50 Btu/scf
-------
1000
f
100
1,000
Waste-Gas Flow Rate
100,000
Fiq. V-14. Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a Scrubber Using
o
No Heat Recovery, 1600 F Combustion Temperature, 0.5-sec Residence Time, and a
Heat Content of from 1 to 50 Btu/scf
-------
1000
800
o
in
^600
.**
in
o
O
c400
20(
Heat Content
ho
O
100
1,000
10,000
100,000
Waste-Gas Flow
scfm
Fig. V-15.
n Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a Scrubber Using
Heat Recovery, 1600°F Combustion Temperature, 0.5-sec Residence Time, and a
Heat Content of from 1 to 50 Btu/scf
-------
1200
100
1000 10,000
Waste-Gas Flow (scfm)
100,000
Fig. V-16. Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with a Scrubber
Using No Heat Recovery, 1800°F Combustion Temperature, 0.5-sec Residence Time, and a Heat
Content of from 1 to 100 Btu/scf
-------
1200
Heat Content (etu/scf)
100
200
f
1000 10,000
Waste-Gas Flow (scfm)
100,000
Fig. V-17. Net Annual Cost vs Waste-Gas Flow for Thermal Oxidizers with a Scrubber
Using Heat Recovery, 1800°F Combustion Temperature, 0.5-sec Residence Time, and a
Heat Content of from 1 to 100 Btu/scf
-------
1000r
800
o
in
600
o
o
« 400
3
C
C
200
Heat Content ( Btu/scf
100
f
100
1,000 10,000
Waste-Gas Flow Rate (scfm:
.J_LLJ
100,000
Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizcrs with a Scrubber Using
2200°F Combustion Temperature, 0.5-sec Residence Time, and a
Heat Content of from 1 to 100 Btu/scf
Fig. V-18.
No Heat Recovery,
-------
1000
800
E
*•
u
600
in
O
O
Heat Content (etu/scf
400
c
200
0 I
100
100
to
-P-
1,000 10,000
Waste-Gas Flow Rate (scfm)
100,000
Fin V-19 Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a Scrubber Using
Heat Recovery, 2200°F Combustion Temperature, 0.5-sec Residence Time, and a
Heat Content of from 1 to 100 Btu/scf
-------
o
V)
tn
o
O
3
C
C
1400
1200
1000
800
600
400
200
Heat Content (etu/scf
100
100
NJ
U1
1000 10,000
Waste-Gas Flow Rate (scfm)
40,000
Fig. V-20 . Net Annual CostsQVs Waste-Gas Flow for Thermal Oxidizers with a Scrubber Using
No Heat Recovery, 2600 F Combustion Temperature, 0.5-sec Residence Time, and a
Heat Content of from 1 to 100 Btu/scf
-------
1200
1000
E
•»-
o
800
in
o 600
o
c
c
< 400
4-»
O
z
200
Heat Content [stu/scf)
100
f
ho
200
1000 10,000
Waste-Gas Flow Rate fscfmj
50,000
Fig.
V-21. Net Annual Costs vs Waste-Gas Flow for Thermal Oxidizers with a Scrubber Using
Heat Recovery, 2600 F Combustion Temperature, 0.5-sec Residence Time, and a
Heat Content of from 1 to 100 Btu/scf
-------
2400
2200
c
S 2000
VI
O 1800
c
c
OJ
z
1600
1400
1200
100
Heat Content (Btu/scf
100
Ki
1000
Waste-Gag Flov; Rate (scfm
10,000
Heat Content of from 1 to 50 Btu/scf
-------
ffi
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Net Annual Cost $/ scfm
o
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30
o
(I)
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-------
Net Annual Cost (S/scfmj
2 t-o
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-------
V-30
COST EFFECTIVENESS AND ENERGY EFFECTIVENESS
The cost effectiveness and energy effectiveness are calculated by dividing the
annual cost for a particular option or the fuel usage (in Btu/yr) by the total
annual amount of VOC destroyed. The cost effectiveness is presented in Table V-3
for sulfur-containing VOC and in Table V-4 for halogen-containing VOC. The
energy effectiveness is given in Table V-5 for sulfur-containing VOC and in
Table V-6 for halogen-containing VOC. Data on cases not shown in the cited
tables and figures can be easily developed by use of Appendices A and B.
-------
V-31
Table V-3, Cost Effectiveness of Thermal Oxidation
and Scrubbing for Control of Sulfur-Containing VOC
Cost Effectiveness (per Ib of VOC Destroyed)
Waste-Gas Waste- VOC
Heat Gas Flow Destroyed
Content Rate (lb/hr)°
(Btu/scf) (scfm) at 90%
1 700
5,000
20,000
50,000
100,000
10 700
5,000
20,000
50,000
100,000
13 700
5,000
70,000
50,000
100,000
20 700
5,000
20,000
50,000
100,000
50 700
5,000
20, ODD
50,000
100,000
aBased on 1400°F combustion
Based on 1600°F combustion
CVOC molecular weight = 300;
5.06
36.2
144.7
361.8
723.4
50.6
362
1,447
3,618
7,234
65.8
471
1,881
4,703
9,404
101.2
724
2,894
7,236
14,472
253
1,810
7,235
18,060
36,170
temperature
temperature
molar heat
VOC
Destroyed
(lb/hr)C
at 99%
5.57
39.8
159.2
398.0
796.0
55.7
398
1,592
3,980
7,960
72.4
517
2,070
5,174
10,348
111.4
796
3,184
7,960
15,920
278.5
1,990
7,960
19,900
39,800
and 0.5-sec
and 0.5-sec
90% VOC Destruction3
Waste Heat
No Heat Boiler 250-
Recovery psi Steam
$5.35
2.24
1.73
1.58
1.50
0.67
0.36
0.31
0.30
0.29
0.56
0.32
0.28
0.26
0.26
0.42
0.26
0.23
0.23
0.22
0.26
0.20
0.19
0.18
0.18
residence time.
residence time.
of combustion = 746,000 Btu/lb-mole
$5.26
1.73
1.20
1.00
0.92
0.66
0.31
0.26
0.24
0.23
0.55
0.28
0.24
0.22
0.21
0.41
0.23
0.21
0.20
0.19
0.26
0.19
0.1S
0.17
0.17
of VOC.
99% VOC Destruction
No Heat
Recovery
$5.27
2.39
1.99
1.76
1.68
0.65
0.37
0.33
0.30
0.30
0.54
0.31
0.28
0.27
0.26
0.40
0.25
0.23
0.22
0.22
0.24
0.19
0.10
0.17
0.17
Waste Heat
Boiler 250-
psi Steam
$4.90
1.73
1.24
1.03
0.95
0.61
0.30
0.25
0.23
0.22
0.51
0.26
0.23
0.21
0.20
0.38
0.22
0.20
0.19
0.18
0.24
0.17
0.16
0.16
0.16
-------
V-32
Table V-4. Cost Effectiveness of Thermal Oxidation
and Scrubbing for Control of Halogen-Containing VOC
Co-t Effectivpp"" (per Ib of VOC Destroyed)
Combustion Temperature
1 ROOT
Waste-Gas
Heat
Content
1
10
13
20
50
100
Waste-
Gas Flow
Rate
700
5,000
20,000
50,000
700
5,000
20,000
50,000
700
5,000
20,000
50,000
700
5,000
20,000
50,000
700
5,000
20,000
50,000
700
500
20,000
50,000
VOC
Destroyed
(lb/hr)a
at °9.9
5.62
40.2
160.8
402
56.2
402
1,608
4,020
73.1
523
2,090
5,230
112.4
804
3,216
8,040
281
2,010
8,040
20 , 100
562
4,020
16,080
40,200
No Heat
Recovery
• ' "•"
$6.03
2.73
2.22
2.06
0.65
0.32
0.27
0.26
0.51
0.26
0.22
0.21
0.35
0.19
0.16
0.16
0.17
0.11
0.10
0.10
0.12
0.08
0.08
0.08
Waste Heat
Boiler 250-
psi Steam
55.53
1.81
1.22
1.07
0.60
0.23
0.17
0.16
0.48
0.19
0.15
0.13
0.33
0.14
0.11
0.11
0.17
0.10
0.08
0.08
0.11
0.07
0.07
0.07
Combustion Temperature
2200°F
No Heat
Recovery
$7.41
3.95
3.43
3.24
0.78
0.44
0.39
0.37
0.61
0.35
0.31
0.29
0.42
0.24
0.22
0.21
0.20
0.13
0.12
0.11
0.12
0.09
0.08
0.08
Waste Heat
Boiler 250-
psi Steam
$6.30
2.54
1.97
1.66
0.67
0.30
0.24
0.21
0.53
0.24
0.20
0.17
0.36
0.17
0.14
0.13
0.17
0.10
0.09
0.08
0.11
0.07
0.07
0.06
Combustion Temperature
2600 °F
No Heat
Recovery
$12.50
7.35
6.33
1.29
0.78
0.68
1.00
0.61
0.53
0.67
0.41
0.36
0.30
0.19
0.17
0.17
0.12
0.11
Waste Heat
Boiler 250-
psi steam
9.46
4.11
3.13
0.99
0.45
0.36
0.77
0.36
0.28
0.52
0.25
0.20
0.23
0.19
0.17
0.14
0.09
0.08
aVOC molecular weight = 100; molar heat of combustion = 746,000
-------
Table V-5. Fuel Energy Effectiveness of Thermal Oxidation
for Control of Sulfur-Containing VOC
Fuel Energy Usage
(Btu/scf)
Waste-Gas
Heat Content
(Btu/scf)
1
10
13
20
50
90% VOCb
Destruction
63.5
54.2
51.0
43.6
12.0
99% VOCC
Destruction
82.3
73.0
69.9
62.5
31.1
Net Energy Usagea
(Btu/scf)
90% VOCb
Destruction
26.3
17.0
13.8
6.37
(25.2)
99% VOCC
Destruction
30.6
21.3
18.2
10.8
(20.6)
Energy Effectiveness
(Btu/lb of VOC Destroyed)
90% VOC
No Heat
Recovery
527,100
45,000
32,600
18,100
2,000
Destruction
Waste Heat
Boiler 250-
psi Steam
218,300
14,100
8,800
2,600
(4,200)
99% VOC
No Heat
Recovery
620,600
55,000
40,500
23,600
4,700
d
c
Destruction
Waste Heat
Boiler 250-
psi Steam
230,700
16,100
10,600
4,100
(3,100)
Based on a waste heat boiler generating 250-psi steam.
Based on 1400°F combustion temperature and 0.5-sec residence time.
CBased on 1600°F combustion temperature and 0.5-sec residence time.
dVOC molecular weight = 100; molar heat of combustion = 746,400 Btu/lb-mole of VOC.
w
w
-------
Table V-6. Fuel Energy Effectiveness of Thermal Oxidation
for Control of Halogen-Containing VOC
' ~ Fnerov Effectiveness (Btu/lb of VOC Destroyed) _ _
Waste-Gas
Heat Content
(Btu/scf)
1
10
13
20
50
100
Combustion T
1800
No Heat
Recovery
777,200
71,000
52,800
31,800
8,200
400
emperature
op
Waste Heat
Boiler 250-
psi Steam
247,900
18,100
12,200
5,300
(2,400)
(4,900)
Combustion Temperature
2200 °F
Heat
Recovery
1,225,600
115,800
85,700
53,100
14,000
1,700
Waste Heat
Boiler 250-
psi Steam
306,400
23,900
14,900
7,100
(4,300)
(7,500)
Combustion Temperature
2600 °F
No Heat
Recovery
2,466,200
246,600
175,900
112,100
36,800
12,600
Waste Heat
Boiler 250-
psi Steam
739,900
62,800
43,100
25,800
2,200
(4,700)
aVOC molecular weight = 100; molar heat of combustion = 746,400 Btu/lb-mole of VOC.
-------
VI-1
VI. SUMMARY AND CONCLUSIONS
Thermal oxidation is a widely used control technique for control of sulfur-
containing and halogen-containing VOC. This evaluation describes the limits
and design principles of this technique. Design criterion and design procedures
are presented that allow for the preliminary design of high-temperature thermal
oxidizers and flue-gas scrubbing for both conventional and high-temperature
thermal oxidizers. Thermal oxidizers without heat recovery and with waste-heat
steam-boiler heat recovery are considered. Capital and operating costs are
developed and the annual cost of thermal oxidation is calculated as a function
of the characteristics of the waste gas.
The conclusions derived from the cost evaluation are as follows:
1. Since the thermal oxidizer design used here is quite conservative, the
control costs actually experienced in industry are expected to be less than the
costs presented in this report.
2. The waste-gas heat content (VOC content) is a highly sensitive variable in
determining annual costs, cost effectiveness, and energy effectiveness. As the
heat content of the waste gas increases, the annual cost and the cost per scf
increase, whereas the energy effectiveness and the cost effectiveness sharply
improve. The increase in annual cost and cost per cfm is due to the increased
amounts of caustic and water required to control the S02 or HCl in the flue
gas. This is largely the result of the assumption that the VOC in the waste
gas is 100% sulfonated or halogenated. When the sulfur-containing or halogen-
containing VOC is actually a small percentage of the VOC in the waste gas, the
caustic and water requirements will be less than those presented in this report.
3. The waste-gas flow rate is a highly sensitive variable in determining
annual costs and cost effectiveness; energy effectiveness is independent of the
flow rate. As the waste gas flow increases (at a constant heat content), the
annual costs increase but the annual cost per scfm of waste gas and the cost per Ib
of VOC decrease. This ratio decreases drastically between low flows (700 scfm)
-------
VI-2
and moderate flows (5000 scfm), but remains relatively constant between moderate
(5000 scfm) to large flows (50,000 to 100,,000 scfm). Energy effectiveness per
scf is constant with flow.
4. Net annual costs for controlling the VOC decrease when heat recovery is
included, provided that there is a use for the steam generated.
S. For high-temperature thermal oxidation (1800 to 3000°F) the annual cost,
cost effectiveness, and energy effectiveness increase exponentially with an
increase in combustion temperature.
6. The effects of residence time, VOC destruction efficiency for conventional
thermal oxidation, and different heat recovery systems on annual costs, cost
effectiveness, and energy effectiveness can be found in the control-device
evaluation report for thermal oxidation1.
-------
VII-1
VII. REFERENCES
1. J. W. Blackburn, IT Enviroscience, Inc., Control Device Evaluation
Thermal Oxidation (July 1980) (EPA/ESED report. Research Triangle Park, NC).
2. K. Lee, H. J. Jahnes, and D. C. Macauley, Thermal Oxidation Kinetics of
Selected Organic Compounds, presented at the 71st Meeting of the Air Pollution
Control Association, Houston, Texas, June 25—30, 1978.
3. K. Lee, J. L. Hanson, and D. C. Macauley, Predictive Model of the Time-Temperature
Requirements for Thermal Destruction of Dilute Organic Vapors, Union Carbide
Corp., South Charleston, WV.
4. J. J. Santoleri, "Chlorinated Hydrocarbon Waste Recovery and Pollution
Abatement" pp. 66—74 in Proceedings of 1972 National Incinerator Conference,
The American Society of Mechanical Engineers, New York, 1972.
5. D. L. Ulrichson and Yu-sung Yeh, Thermochemical Water Splitting: The Reverse
Deacon Reaction and Alternatives, IS-M-63 (NTIS) 1975).
6. Handbook of Chemistry and Physics, pp. D-184-188, 49th ed., edited by R. C. Weast,
Chemical Rubber Co., Cleveland, 1968.
7. J. Happel and D. G. Jordan, Chemical Process Economics, 2d ed, Marcel Dekker,
Inc., New York City, 1975.
8. Personal communication between J. Kirkland, Hirt Combustion Co., Montebello, CA,
and J. R. Fordyce, IT Enviroscience, Inc., July 25, 1979.
9. Personal communication between S. Korn and P. Capsis, Peabody Engineering,
Stamford, CT, and J. R. Fordyce, IT Enviroscience, Inc., July 19, 1979.
-------
APPENDIX A
ANNUAL COST DATA FOR SULFUR-CONTAINING VOC CONTROL
-------
A-3
Annual Cost Data Calculations
(Applies to Appendices A and B)
The annual costs of thermal oxidation systems are presented in Tables A-5 to
A-14 and B-3 to B-20. Each table shows the costs at a specific offgas heat content
and combustion temperature at various flow rates, residence time, and with and
without heat recovery. The heat recovery case includes a 250-psi waste heat
boiler.
The following sample calculation is for a stream with an offgas heat content of
10 Btu/scf, a combustion temperature of 2600°F, a residence time of 0.5 sec, a
flow rate of 5000 scfm, and with heat recovery.
Capital cost = thermal oxidizer ($1,250,000) + waste heat boiler ($734,000) +
scrubber ($912,000) = $2,896,000
Thermal oxidizer = $1,250,000 — from Fig. V-3 at 5000 scfm, 0.5 sec
resistance, and 2600°F
Waste heat boiler = $734,000 — from Fig. V-5 at 5000 scfm, 250 psi, and
2600°F
Scrubber = $912,000 — from Fig. V-l at 5000 scfm X 5.1 (from Fig. Ill-3) X
1.07 (from Fig. III-8)
Fixed cost = $2,896,000 X 0.29*) = $840,000/yr
Operating cost = fuel ($1,660,000) + electricity ($23,100) + makeup water quench
($1,300) + makeup water scrubber ($10,200) + caustic ($243,200) + labor ($36,000) =
$l,974,000/yr
Fuel = (315.8 Btu/scf (from figure III-2)) X (5000 scfm) X ($2.00/million Btu*) X
(60 min/hr) X (8,760 hr/yr) = $l,660,000/yr
Electricity = (22 in HJD) X (.000157 —- ) X (I/.60 efficiency) X (.746 kWh) X
^ an. H_u
(5000 scfm) X ($0.03/kWh*) X (8760 hr/yr) = $5,640/yr plus electricity for
combustion air blower = 3.1 (from table III-3) X $5,640/yr = $17,500/yr +
$5,640/yr = $23,100/yr
See table V-2.
-------
A-4
Makeup water quench = (2 gal/1000 scf (from Fig. III-9)) X (5000 scfm) X
($0.25/1000 gal*) X (60 min/hr) X (8,760 hr/yr) = $l,300/yr
Makeup water scrubber = [19.2 gal/lb of chlorine (from text III-B-5)] X
(0.0487 Ib/hr of chlorine/scfm) X (5000 scfm) X ($0.25/1000 gal*) X
(8,760 hr/yr) = $10,200/yr
Caustic = [1.14 Ib/lb of chlorine (from text III-B-5)] X (0.0487 Ib/hr of
chlorine/scfm) X (5000 scfm) X ($0.10/lb of 100% caustic*) X (8,760 hr/yr) =
$243,200/yr
Labor = $36,000/yr (from ref 1); the labor cost for a system without heat
recovery is $18,000/yr.
Credit = (13,900 Btu/hr/scfm) X (5000 scfm) X ($2.0/million Btu*) X (8,760 hr/yr) =
$l,218,000/yr
Annual cost = fixed cost ($840,000) + operating cost ($1,974,000) - credit ($1,218,00
$1,596,000
Net cost = ^nual cost ($1 596,000/yr) = ^^ $/scfm
Flow rate (5000 scfm)
-------
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A I 93.
1211",,
?9flT5,
591 T, i ,
170.
121.
717.
1197.
1919.
4 38,
2907.
115IH.
28712.
5744/,
;?H,
198.
792,
1 9BO.
3960.
580
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12166.
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580.
11495.
71
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60S,70
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591.51
823.,-(0
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572,15
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554.07
6 i 0 . 5 4
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"78.33
593,15
828.72
407,8V
?74,73
'/.'.1 . OJ
555.71
-------
i
OFFhAs HFAl rHNTFrlf I
COMBUSTION TEMPERATURE
CASE OFFGAS
Fi OU
SCFli
.00 PTU/SCF
1600 F
CAPI I I'll
TOST
(000)
OPERATI.NC. (,()!,T -Ok-I.REDIT
,-KEI, OI'FRATING RECOVERY
cosr cor.T CRFJHI
'
NET
ANNUAL TZED
ObT OF1 CREDIT
i»!F-T TOST
OR SiWIMGJ
F-hR S.CFrf
•»/t;r,Fri
RESTDEJ!
M-C
TIME"
U . UV PI L.
HO HFAT RECOVERY
RESinEflCi flrtE
0 . 50SEC
HEAT RECOVERY
;oo,
5000.
500 0 0 .
1 00000.
"00.
5000.
2 0 0 'J 0 .
50000 .
100000.
587.
1 108.
2698.
1107.
6377.
592.
1 190.
2798.
4701.
755?.
170.
3° 1 .
782,
1191.
18-19.
172.
811 .
1363.
2190.
88.
20 <.>:•',
•1985.
V9V,1.
105.
2010.
4971.
9907.
0.
0.
0.
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0,
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272 .
1086.
271 6.
5131 .
258.
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61 76.
11801 .
239 .
603.
3619,
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139.3d
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118,01
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NO HEAT RECOVERY
RES) TiFLnr.:" f 1 HE
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HEAT RF COVERS
/OO.
5000.
20000.
50000.
I 00000.
700.
5000.
20000.
50000.
100000.
594.
I 149.
2910.
1190.
7057,
599,
1211.
3010.
8232.
172,
333.
844.
1302.
2047 .
174.
357.
873.
J 174.
2387.
88.
*" 1 cr
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2005.
1985.
99,.,-.'.
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1971 .
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272.
1086,
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2849.
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98
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99
84
60
63
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C 0 fl fi U S T 1 0
r riT-I T F HI 10.00 B T l) / P T F
F. 1600 F
CASE
RESiriEMfT Tint
0 , 50SEC
NO HFAT RECOVERY
r ITME
0.50SEC
HEAT RFCOVERY
0.75SEC
NO HEAT
OFFGr.S
F L 0 U
5CFh
RECOMFRY
CAPITAI
r.OST
(000)
700,
5000.
'JO 000.
50000.
lOOOt'O,
587.
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2698.
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1849.
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3825
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OPFRATTMr- rOST-dk l RED i
FIXED UPFROTING
COST POTT CREIUT
(000) (000) (000)
/ 0 0 .
5000.
20000.
50000.
100000,
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700.
5000,
20000,
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1190,
7057.
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333
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357
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19010.
38.
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MET
AMflDAI TZED
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(000)
K'ET [,|if. I
OR SAUTJIGt
PFR SCFrt
460f<,
107?3,
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100000,
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172.
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1086.
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305,
1070.
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8?82.
15967.
459. ''7
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2 ;0, '10
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177,80
16 ',. 4 2
157,69
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233. ",7
? 1 1, 0 3
180,88
1 f>"-i, i4
157,67
-------
OFHiA!>
LOnBUS
Hrfil flMlTFfil 13.00 BTU/SCF
TION TEfnr'EFi'iTURF I ft(>C' F
I.ASE
OFF GAS
FLOW
SCFh
CfiF'TTAL
COST
(000)
i u-ir, (.of>r -OR- i,Ki-n rr
! i)&;-
COSII fiR CREDIT HIR i,(,Fh
(000) t/SCFM
RESinENf;- Mr-it-
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NO HEAT RECOVFRf
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HEAT RFCDVERC
/OO.
5000.
I'vOOO.
5 0 0 0 0 .
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700,
5000.
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587.
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2798.
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1363.
2190.
173
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193,76
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'00,
5000.
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50000.
L 0 0 0 0 0 .
594.
1 1 19.
2910.
1 -190,
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172,
333.
841.
1 302,
2047.
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"'00.
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599.
1 '31 .
3010.
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1.7/i.
357.
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190
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5276,
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A-13
o
cj
rx bi
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r. rx -c c>-
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cc -r- ^',
o iv f
T-I ••- in
<• o> 'x
cc u- i-
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Cf- UT o: r;
rj rx <- o- tx
r-j <^ co ir -<
ii". cc r;
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r, co o •?•
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rj Hi — M c-
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rj in o
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OFF ;;rr->
CQnPtiM
CASE
RESHtFiiri- TIhE
NO HEr.T RECOVER f
RFsIliniCi M flE
0 . 503FC
HEAT RFCOYERY
RES) PEr-IC:- IThF
0,7f,SKC
rIO HFftT RECOVER/
RES 1 1iFr\ir,l 1 TrfF
0 . 7 f, 5 E C
H E .1 T R F r 0 <,' E R Y
HI- nT i" i i i ' T F i-t 1 5 0 .
1 C N T E rl F E R T, T 1 1 F. F
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1 00000.
700,
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866, 7 H
66',. 22
638.08
621.38
615.63
83'»,63
6 1 ff. 61
5 b ci , ", 3
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564 .27
-------
APPENDIX B
ANNUAL COST DATA FOR HALOGEN-CONTAINING VOC CONTROL
-------
6 I ' fc <'
:r '88
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vyz t
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ON IFhPFPf.r'lRF UJC'O F
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OFFGAS HFAT CONTENT 1.00 BTU/SCF
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CASE
RESIDENCE TIMF
0.50SEC
NO HFAT RECOVERY
RESIDENCE TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
0.75SEC
NO HEAT RECOVERY
RESIDENCE TIME
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HEAT RECOVERY
OFFGAS
FLOU
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OPERATING COST-OR-CREIHT NET NET COST
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COST COST CREDIT COST OR CREDIT PER SCFM
(000) (000) (000) (000) $/SCFM
345.
768.
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350.
842.
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360.
835.
1875.
365.
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270.
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445.71
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289.31
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230.04
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OFFGAS HEAT CONTENT 10.00 BTU/SCF
COMBUSTION TEMPERATURE 2600 F
CASE
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
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908.39
547.55
475.60
694.97
319.22
250.47
929. 11
560.89
435.12
715.69
332.56
260.04
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OFFGAS HEAT CONTENT 13.00 BTU/SCF
COMBUSTION TEMPERATURE 2600 F
CASE
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
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2282.
299.
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314.
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557.46
485.56
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329.20
260.47
938.84
570.80
495.13
725.51
342.54
270.04
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QFFGAS HEAT CONTENT 20.00 BTU/SCF
COMBUSTION TEMPERATURE 2600 F
CASE
RESIDENCE TIME
0.50SEC
NT) HEAT RECOVERY
RESIDENCE TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
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OFFOAS
FLOU
SCFM
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CAPITAL
COST
(000)
1184.
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OPERATING COST-OR-CREDIT
COST
(000)
343.
762.
1666.
349.
838.
2086.
358.
829.
1857.
363.
904.
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COST
(000)
315.
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331.
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315.
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0.
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170.
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170.
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NET
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(000)
659.
2903.
10176.
509.
1762.
5676.
673.
2970.
10367.
524.
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NET COST
Oft SAVINGS
PFR SCFM
t/SCFM
940.83
580.56
508.80
727.70
352.46
283.80
961,54
593.90
518.37
748.42
365.80
293.37
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OFFGAS HEAT CONTENT 50.00 BTU/SCF
COMBUSTION TEMPERATURE 2600 F
CASE
OFFGAS
FLOU
SCFM
CAPITAL
COST
(000)
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HEAT RECOVERY
700.
5000.
20000.
700.
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700.
5000.
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700.
5000.
20000,
1175.
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5647.
1197,
2866.
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2822.
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3096,
7782,
341 .
752.
1638.
347.
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2065.
355.
819.
1829.
362,
898.
2257.
386.
2646.
10530.
402.
2647.
10481.
386.
2646.
10530.
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2647.
10481 .
0.
0.
0.
170.
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4871.
0.
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4871 .
727 .
3398 .
12168.
578.
2261 .
7676,
741 .
3465.
12360.
593.
2328.
7867.
1038.12
679.59
608.41
825.89
452.17
383.80
1058.84
692.93
617.98
846.61
465.51
393.37
W
-------
1
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OFFGAS HFAT CONTENT 100 . 00 BTII/SCF
COMBUSTION TEMPERATURE 2600 F
CASE
OFFGAS
FLOW
SCFM
CAPITAL
COST
(000)
FIXED
COST
(000)
OPERATING CflST-OR-CRFPIT
OPERATING RECOVERY
COST CRF.niT
(000) (000)
NET
ANNIJALIZED
COST OR CREDIT
(000)
NET COST
OR SAVINGS
PER SCFM
t/SCFM
RESIDENCE TIME
0.50SEC
NO HEAT RECOVERY
RESIDENCF TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
0.75SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.75SEC
HEAT RECOVERY
700.
5000.
30000.
700.
5000.
20000.
700.
5000.
20000.
700.
5000.
20000.
1160,
2535.
5485,
1185.
2828.
7004.
1210.
2765,
6145,
1235.
3058.
7664.
336.
735.
1591 .
344.
820.
2031,
351 .
802.
1782.
358.
887.
2223.
504.
3488.
1389R.
519.
3489.
13849.
504.
3488.
13898.
519.
3489.
13849.
0.
0.
0.
170.
1218.
4871.
170.
1218.
4871 .
840.
4223.
15489.
693.
3092.
11009.
855.
4290.
15680,
707.
3158.
11201 .
1200.29
844.63
774.43
989.55
618.36
550.47
1221.00
857.97
784.00
1010.26
631 .70
560.04
f
-------
OFFGAS HEAT CONTENT 1,00 BTU/SCF
COMBUSTION TEMPERATURE 3000 F
CASE
OFFGAS
FLOU
SCFrt
CAPITAL
COST
(000)
OPERATING COST-OR-CREDIT
FIXED OPERATING RECOVERY
COST COST CREDIT
(000) (000) (000)
NET
ANMUALI7.ED
COST OR CREPT!
(000)
NET COST
OR SAVINGS
PFR SCFM
t/SCFM
RESIDENCE TIME
0.50SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
0.75SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.75SEC
HEAT RECOVERY
700.
5000.
700.
5000.
700.
5000.
700.
5000.
1870.
4878.
2090.
5548.
1970.
5638.
2190.
6308,
542.
1A 1.5 .
606.
1609.
571,
1635.
635.
1829.
782.
5472.
798.
5480.
782.
5472.
798.
5480.
0.
0.
530.
3784.
530.
3784,
1324.
AR87.
874.
3304.
1353.
7107.
903.
3525.
1891.13
1377.41
1249.04
660.87
1932.55
1421.49
1290.47
704.95
W
-------
OFFfiAS HEAT CONTENT 10.00 PTU/SCF
COMBUSTION TEMPERATURE 3000 F
CASE
OFFGAS
FLOU
SCFH
CAPITAL
COST
(000)
OPERATING COST-OR-CRFDIT
FIXED OPERATING RECOVERY
COST COST CREDIT
(000) (000) (000)
NFT
ANNUITIZED
COST OR CREDIT
(000)
NET COST
OR SAVINGS
PER SCFH
$/SCFM
RESIDENCE TIME
0 .50SEC
NO HFAT RECOVERY
RESIDENCE TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
0.75SEC
NO HEAT RECOVERY
RESHiFNCF TIME
0.75SEC
HEAT RECOVERY
700.
5000.
700.
5000.
700.
5000.
700.
5000.
1865.
4859.
2086.
5537.
1965.
5619.
2186.
6297,
541.
1409.
605.
1606.
570.
1629.
634.
J826.
801 .
5610.
817.
5617.
801.
5610.
817.
5617.
530.
3784,
530.
37R4,
1342.
7019.
893.
3438,
1371 .
7239.
922.
3659.
1916.83
1403.78
1275.19
687.69
1958.26
1447.86
1316.62
731.77
Cd
-------
OFFfiAS HEAT CONTENT 13.00 BTII/STF
COMBUSTION TFhPFRATURF. 3000 F
CASE
RESIDENCE TIME
0.50SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
0.75SEC
MO HEAT RECOVERY
RESIDENCE TIME
0.75SEC
HFAT RECOVERY
OFFGAS
FLOU
SCFM
700.
5000.
700.
5000.
700.
5000.
700,
5000,
CAPITAL
COST
(000)
1864.
4853.
2085.
5533.
1964.
5613.
2185.
6?93.
OF'FRATINn CflST-OR-CRFDIT NET
FIXED OPERATING RECOVERY ANNUALI7ED
COST COST CREDIT COST OR CREDIT
(000) (000) (000) (000)
541,
1407,
605.
1605.
570.
1628,
634,
1825.
807.
5656.
824.
5663.
807.
5656.
824.
5663.
530.
3784,
530.
3784.
1348.
7063.
899.
3483.
1377.
7283.
928.
3704.
NET COST
OR SAVINGS
PER SCTh
t/SCFM
1925,40
1412,57
1283.91
696.63
1966.8?
1456.65
1325.33
740.71
I
ho
u>
-------
OFFOAS HEAT CONTENT 20.00 BTU/SCF
COMBUSTION TFMPERATURE 3000 F
CASE
OFFGAS
FLOU
SCFh
CAPITAL
COST
(000)
OPERATING COST-OR-CREniT
FIXED OPERATING RECOVERY
COST COST CREDIT
(000) (000) (000)
NET
ANNUALIZED
COST OR CREDIT
(000)
NET COST
OR SAVINGS
PFR SCFM
$/SCFM
RESIDENCE TIME
0.50SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
0.75SFC
NO HEAT RECOVERY
RESIDENCE TIME
0.75SEC
HEAT RECOVERY
700.
5000.
700.
5000.
700.
5000.
700.
5000.
1861 .
4838.
2083.
5524.
1961 .
5598.
2183.
62K4.
540.
1403.
604.
1602.
569.
1623.
633.
1822.
82?.
5762.
839.
3770.
822,
5762.
839.
5770.
530.
3784.
530,
3784.
13A2
7165
913.
3587.
1391 .
7386,
942 .
3808.
1945.39
1433.08
1304,24
717.49
1986.81
1477. 16
1345.67
761.57
I
ho
-------
OFFGAS HEAT CONTENT 50.00 BTIJ/SCF
COhHJSTION TEMPERATURE 3000 f
CASE
OFFGAS
Fl 010
SCFM
CAPITAL
COST
(000)
OPERATING COST-OR-CRFDTT
FIXED OPERATING RECOVERY
COST COST CREDIT
(000) (000) (000)
NET
ANNUAL I ZED
COST OR CREDIT
(000)
NET COST
OR SAVINGS
PER SCFM
$/SCFM
RESIDENCE TIME
0.50SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TJhF
0.75SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.75SEC
HEAT RECOVERY
700.
5000.
700.
5000.
700.
5000.
700.
5000.
1846.
4775.
207?.
5487.
1946.
5535.
217?.
6247.
535.
1 385.
601.
1591..
564.
1605.
630.
1811.
886.
6220.
903.
6228.
886.
6220.
903.
6228.
530.
3794.
530.
3784.
1422.
7605,
974.
4034.
1451 .
7825,
1003.
4255.
2031.06
1520.99
139] .41
806.88
2072.49
1565.07
1432.P4
850.96
ho
-------
HEAT CONTENTIOO . 00 PTU/SCF
COMBUSTION TEMPERATURE 3000 F
CASE
OFF'GAS
FLOW
SCFM
CAPITAL
COST
(000)
FIXED
COST
(000)
OPERATING nOST-OR-CRErUT
OPERATING RECOVERY
COST CREDIT
(000) (000)
NET
ANNUALIZED
COST OR CREDIT
(000)
NET COST
OR SAVINGS
PER SCFM
$/SCFM
RESIDENCE TIME
0.50SEC
NO HEAT RECOVERY
RESIDENCF TIME
0.50SEC
HEAT RECOVERY
RESIDENCE TIME
0.75SEC
NO HEAT RECOVERY
RESIDENCE TIME
0.75SE.C
HEAT KECOVFK'Y
700.
5000,
700.
5000.
700.
5000.
700.
5000.
1823.
4670,
205?.
5-124.
1923.
5430.
2155.
A184.
529.
1354.
596.
1573.
558.
1575,
625.
1793.
993.
6983.
1010.
6991 ,
993.
6983.
1010.
6991,
530.
3784.
530.
3784,
1522.
8337,
1076.
4779.
1551.
8558.
1105.
5000.
1667.50
1536.69
955.8A
2215.28
1711.58
1578.11
999 .94
-------
3-i
REPORT 3
CONTROL DEVICE EVALUATION
CATALYTIC OXIDATION
J. A. Key
IT Enviroscience
9041 Executive Park Drive
Knoxville, Tennessee 37923
Prepared for
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park, North Carolina
October 1980
D94I
-------
CONTENTS OF REPORT 3
I. INTRODUCTION 1.1
II. CATALYTIC OXIDATION SYSTEMS AND FACTORS INFLUENCING PERFORMANCE II-l
AND DESIGN
A. System Description II-l
B. Catalytic Oxidation Efficiencies H-g
III. CONSIDERATIONS FOR INSTALLATION OF CATALYTIC OXIDIZERS III-l
A. New Plants III-l
B. Existing Plants III-l
IV. COST AND ENERGY IMPACTS OF CATALYTIC OXIDATION IV-1
A. Base-Case Catalytic Oxidizer Design Summary IV-1
B. Cost Basis IV-1
C. Annual Costs IV-7
D. Cost and Energy Effectiveness IV-15
V. SUMMARY AND CONCLUSIONS V-l
VI. REFERENCES VI_1
APPENDICES OF REPORT 3
A. PURCHASE COSTS A_!
B. ANNUAL COST DATA B_!
-------
3-v
TABLES OF REPORT 3
Number
H-1 Parameters for Catalytic Oxidation Calculations
IV-1 Factors Used for Estim
IV-2 Annual Cost Parameters
IV-1 Factors Used for Estimating Total Installed Costs
Page
1-1 Catalytic Ignition Temperature for 90% Conversion j_2
II-5
IV-2
IV-8
IV-3 Cost Effectiveness of Catalytic Oxidation Iv_16
IV-4 Fuel Energy Effectiveness of Catalytic Oxidation Iv_17
-------
3-vii
FIGURES OF REPORT 3
Number
II-l Basic Catalytic Oxidizer II-2
II-2 Flue-Gas Heat Content H-7
II-3 Recuperative Heat Exchanger Design at 900 to 1200°F II-8
Flue-Gas Temperature (100°F Waste Gas and Air, Constant
Specific Heat)
IV-1 Installed Capital Costs of Catalytic Oxidizer Systems for IV-4
Waste Gas with a Heat Content of 0 to 10 Btu/scf
IV-2 Installed Capital Costs of Catalytic Oxidizer Systems for IV-5
Waste Gas with a Heat Content of 20 Btu/scf
IV-3 Installed Capital Costs of Catalytic Oxidizer Systems for IV-6
Waste Gas with a Heat Content of 10 Btu/scf in Air
IV-4 Net Annual Costs vs Waste-Gas Flow Rate for Catalytic IV-9
Oxidizers Having a Destruction Efficiency of 90% and with
No Heat Recovery
IV-5 Net Annual Costs vs Waste-Gas Flow Rate for Catalytic IV-10
Oxidizers Having a Destruction Efficiency of 90% and with
Recuperative Heat Exchangers
IV-6 Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers IV-11
Having a Destruction Efficiency of 90% and with Waste-Heat
Boilers
IV-7 Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers IV-12
Having a Destruction Efficiency of 99% and with No Heat Recovery
IV-8 Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers IV-13
Having a Destruction Efficiency of 99% and with Recuperative
Heat Exchangers
IV-9 Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers IV-14
Having a Destruction Efficiency of 99% and with Waste-Heat
Boilers
A-l Purchase Costs for Catalytic Oxidizers A-3
A-2 Purchase Costs for Catalysts A-4
A-3 Purchase Costs for Waste-Heat Boilers Producing 100-psig Steam A-5
-------
1-1
I. INTRODUCTION
Catalytic oxidation is a control technology, currently used by many industries,
that involves the oxidation of volatile organic compounds (VOC) in the presence
of a catalyst. The principles and the equipment, except for the catalyst, are
similar to those used for thermal oxidation, the subject of a previous control-
device evaluation report.1* A waste-gas stream and oxygen, usually from air,
are contacted with the catalyst at a temperature that allows the oxidation
reactions to proceed rapidly. The primary difference between the equipment
used for catalytic oxidation and that used for thermal oxidation is the added
provision for the catalyst, which is usually composed of a noble-metal coating
on activated alumina. Nonprecious-metal catalysts may be used when selectivity
is not critical. Because of the catalyst the oxidation reaction takes place at
a lower temperature, and therefore less fuel is required to heat the waste gas
than for thermal oxidation (see Table 1-1 for catalytic ignition temperatures
of some common VOC as given by Oxy-Catalyst, Inc., in their brochure2). The
actual temperatures required will vary with different catalysts and different
supports.3
The energy in the hot flue gas leaving the catalyst may be recovered by use of
a recuperative heat exchanger to preheat the waste gas and combustion air or by
use of a waste-heat boiler to produce steam, in the same that way energy is
recovered from the hot flue gases of a thermal oxidizer. When the concen-
tration of VOC is high enough, a catalytic oxidizer with a recuperative heat
exchanger can be designed that requires no additional fuel after operating
temperatures are reached.2—5
Catalytic oxidation accomplishes the same results as thermal oxidation, i.e.,
the oxidation of the VOC in the waste gas to water and carbon dioxide. The
catalyst increases the rate of oxidation, and thus the reaction proceeds to
equilibrium at a lower temperature (energy level). The reactions of the indi-
vidual molecules take place at active sites on the surface of the catalyst.
The VOC and oxygen are first transferred to the surface of the catalyst by
diffusion in the waste gas and are then chemisorbed in the pores of the catalyst
to the active sites, where the reaction (oxidation) takes place. The reaction
*See Sect. VI for the references cited in this report.
-------
1-2
Table i-l. Catalytic ignition Temperature for 90% Conversion^
Component
Hydrogen
Acetylene
Carbon monoxide
Propyne
Propadiene
Propylene
Ethylene
rv-Neptane
Benzene
Toluene
Xylene
Ethanol
Methyl ethyl ketone
Methyl isobutyl ketone
Propane
Ethyl acetate
Dimethyl formamide
Ethane
Cyclopropane
Methane
it
See ret 2.
-------
1-3
products are then desorbed from the catalyst sites and transferred by diffusion
into the waste-gas stream leaving the catalyst. The heat of combustion released
by the catalytic oxidation reaction is the same as that released by thermal
oxidation.2—4
An advantage of catalytic oxidation over thermal oxidation is that less NO^ is
formed as the results of the lower temperature used and of operating close to
the required stoichiometric amount of oxygen. Because of the theoretical
relationships between VOC and NO , attaining the ozone standard may be served
better by a lower destruction of VOC with less NO^ formation.6
Catalytic oxidation has some limitations that do not apply to thermal oxidation.
Normally the waste gas should not contain materials that poison the catalyst,
such as phosphorus, bismuth, lead, arsenic, antimony, mercury, iron oxide, tin,
silicon, zinc, sulfur, or halogens. Care must be taken that liquid or solid
particles do not deposit on the catalyst and form a coating. In some applica-
tions it may be possible to adequately remove the poison or particulate materials,
or catalytic oxidation systems may be available that will effectively handle
some of the poisons, such as sulfur compounds, or some halogenated compounds.
The VOC content of the waste gas should be relatively constant and low enough
(or the waste gas diluted with air) so that the catalyst is not overheated and
its activity destroyed. Because of safety considerations it is general practice
to keep the concentration of VOC at less than 25 to 30% of the lower explosive
limit. This concentration is in the range of 12 to 14 Btu/scf in air or 20 to
22 Btu/scf in nitrogen. Design for a specific application requires good basic
data and experience; a pilot study is often necessary. This report is intended
for use in preliminary screening studies to indicate whether additional investi-
gation of catalytic oxidation is advisable.2—7
Catalytic oxidizers are being used successfully as emission control devices on
the off-gases (waste gases) from the production of ethylene oxide, cumene,
caprolactam, phthalic anhydride, bisphenol A, formaldehyde, acrylonitrile, and
ethylene dichloride, and have been considered for use on maleic anhydride waste gas,
all in the synthetic organic chemical manufacturing industry (SOCMI).24'7
-------
II-l
II. CATALYTIC OXIDATION SYSTEMS AND FACTORS INCLUENCING
PERFORMANCE AND DESIGN
In this section the main elements of a catalytic oxidizer system are discussed
(or reference is made to the thermal oxidizer report,1 in which the elements
discussed are the same). The factors influencing catalytic oxidizer design and
performance are analyzed, with the analysis directed toward development of a
design for a typical or base-case system. This base-case catalytic oxidizer
and variations of it form the basis for the cost estimation given in Sect. IV.
A. SYSTEM DESCRIPTION
The catalyst bed in a catalytic oxidizer usually follows a burner and mixing
chamber (see Fig. II-l). The waste gas enters the mixing chamber and is heated
by mixing with the combustion products from the burner. The mixing chamber and
burner should be carefully designed so the mixed gas is uniformly heated and
distributed before it enters the catalyst bed. The catalyst bed is usually a
deposit of platinum or another noble metal on the surface of a ceramic base
that is shaped so that contact with the mixed gas is enhanced. Alternatively,
the deposit may be on a metal mesh-pad structure. The catalyst bed depth is
normally 12 in. but may be 8 to 24 in., and the volume may vary from 0.5 to 2
ft3 per 1000 scfm of flow through the bed.2—5
When heat recovery is practiced, the recuperative heat exchanger or waste-heat
boiler is connected to the catalyst chamber. The hot flue gases leaving the
catalyst are cooled by (1) the entering waste gas and/or combustion air being
heated in the recuperative heat exchanger or (2) by the steam being produced in
the waste-heat boiler.
If the waste gas is not under pressure in the process, a fan is usually required.
If the waste gas does not contain at least 16 mole % oxygen, combustion air is
required for the burner and another fan is required. When the VOC is mixed with
air, the combustion air fan is not required.
The complete catalytic oxidizer system also has contol instruments for tempera-
ture, flow, and fuel and for combustion safety. A stack is needed to exhaust
the flue gases at sufficient height to be safely dispersed.
4
-------
FLUE GAS
A
BURNER-
CATALYST
BED
WASTE GAS
FROM
PROCESS
WASTE
GAS FAN
NAT. GAS
FUEL
AIR
MIXING
CHAMBER
STACK
HEAT I
RECOVERY I
[optional 1 {
H
H
COMBUSTION
AIR FAN
Fig. II-l. Basic Catalytic Oxidizer
-------
II-3
The important variables in sizing a catalytic oxidizer system are the following:
1. the waste-gas flow rate
2. the waste-gas oxygen content
3. the VOC destruction efficiency
4. the waste-gas heat content, which is a function of the VOC concentration
and composition
5. the operating temperatures
1
Except for item 5 the values for the parameters are the same as those used in
the thermal oxidation report.1 In addition to the case for which the waste-gas
oxygen content is assumed to be zero, a study was made of the case in which the
waste-gas oxygen content is the same as that for air.
The operating temperature conditions are more complex, with the following
values assumed for this study:
1. the temperature of the waste gas from the process is 100°F,
2. the minimum temperature of the mixed gases entering the catalyst bed is
600°F to ensure an adequate initial reaction rate,
3. the minimum temperature of the flue gas leaving the catalyst bed is 900°F
to ensure an adequate overall reaction rate to give the desired VOC destruc-
tion efficiency,
4. the maximum temperature of the flue gas leaving the catalyst bed is 1200°F
(ref 5) to prevent catalyst deactivation by overheating,
5. the minimum temperature of the flue gases leaving the heat recovery sec-
tion is 500°F to prevent condensation and corrosion of the heat-transfer
surfaces.
For specific applications other temperatures may be appropriate. For example,
temperatures of 400 to 450°F are reported at one installation and 500 to 550°F
at another. The temperature of the flue gas leaving the catalyst bed is a
function of VOC concentration and specific heat and may be less than 900°F for
some waste gases that are more easily oxidized and still give the desired VOC
destruction.6
-------
II-4
Only 1 or 2% excess of oxygen may be required with an effective catalyst,
although a minimum of 3 mole % oxygen in the flue gas is assumed for this
study, as was used for the thermal oxidation study. By keeping air addition to
the minimum required, supplemental fuel usage is minimized.6
Two levels of VOC destruction efficiency are assumed, 90% and 99%. See Table II-l
for the specific parameters used for the five waste-gas composition cases
studied for this report.
1. Catalyst Bed Size
The amount of catalyst and the depth and cross-sectional area of the catalyst
bed depend to a certain extent on the vendor's experience with waste gases
having similar compositions to the one under consideration. When such ex-
perience is lacking, a pilot unit should be run on the actual stream for a
period of time. For the base case of 90% destruction efficiency a catalyst
volume of 1 ft* per 1000 scfm of flue-gas flow is used; 1.5 ft* of catalyst per
1000 scfm of flue-gas flow is assumed to give 99% destruction of VOC as indi-
cated by Du Pont.5 They also indicate that the bed depth is normally 12 in.
but can vary from 8 to 24 in.5 The degree of removal of combustible gaseous
compounds depends on the mass-transfer limitations. A unit can be designed for
a high degree of VOC removal by making it long enough (more catalyst), but this
introduces a higher pressure drop through the device. In some cases therefore
this increased pressure drop can be a limiting factor that dictates the degree
of destruction.6
2. Mixing Chamber Design
The mixing chamber must be of sufficient length and design so that the flame
from the preheat burner will not impinge on the catalyst bed and so that the
waste gas will be well mixed and evenly heated before it enters the catalyst
bed. The mixing chamber designs on which this study is based are those used by
catalytic oxidizer vendors.5' 13—" Details of the designs were not furnished.
A typical design velocity of 25—35 fps for the heated mixed gases is usually
adequate for mixing and is used for at least one type of catalyst bed.3
-------
Table II-l. Parameters for Catalytic Oxidation Calculations
t-io Ht-at Recovery
T-'i. "erature ( °F)
W-.stc-Gas
Heat Content To From
(Bta/sci) Cat.al>-",t Cataiyr.t
0 900 900
2 855 900
10 600 900
?0 600 1150
10 (in air) 600 1019
Catalytic oxidizer conditions:
VOC molar heat o£ combustion = 730,
VOC molecular weight = 50.
VOC C, H, 0 fraction = 68.3 wt % C ,
or with Waste-Heat Be
Ratio
/ Flue -Gas Flow \
\ V,'r. -ite-Ga , F low /
1.'15
1.48
1.45
1.58
1.0
250 Btu/Jb-rrole.
1 1 , 4 wt % H , 20 . 3 wt
>iler
Fuel
Required
(Utu/scf )
23.9
24.2
14.6
15.9
10.1
% O.
With
Temperature (°
From Heat To
Exchanger Catalyst
400 900
400 850
400 600
600 600
600 600
Recuperative Heat Exchanqer
F) Ratio j
r - ( Flue-Gas F]ow -\ p,"iuir-J
Cataly-st \ Waste-Gas Flo • / (Btu/scf )
900 1.34 14.1
900 1.36 14.2
930 1.35 5.6
1200 1.39 0
1032 1.0 0
Jiverage waste-gas molecular weight - /I9.
No oxygen in waste gas except where indicated "in air."
Water content of combustion air =1.0 wt %.
3 nole % oxygen or greater in flue gas after oxidation.
bTemperature of flue gas leaving waste-heat boiler = 500°F.
H
un
-------
II-6
3 . Fans
Fans for both the waste gas and the combustion air are required unless the
waste gas contains sufficient oxygen (16 mole %) to be used in burning the
auxiliary fuel. The pressure drops used in this report for catalytic oxidizer
systems with conversions of 90% are 5 in. H20 with no heat recovery and 14 in.
H20 with heat recovery, for either a recuperative heat exchanger or for a
waste-heat boiler. For a system with 99% conversion, pressure drops of 7 in.
H20 with no heat recovery and 16 in. H20 with heat recovery are used. The cost
of the fans is included in the catalytic oxidizer costs given in Appendix A.
4. Recuperative Heat Exchangers
A recuperative heat exchanger transfers heat from the flue gas to the waste gas
and combustion air, lowering the amount of fuel and combustion air required.
See Sect. III-A-2 of the thermal oxidizer report1 for a discussion of heat
recovery by recuperative heat exchange. The heat content of the flue gas* from
the catalytic oxidizers studied for this report is shown in Fig. II-2. The
actual heat content of a flue gas depends on the relative quantities of fuel,
air, VOC, and waste gas going to the catalytic oxidizer. The straight line of
Fig. II-2 represents a best fit to several data points and is adequate for
estimating the heat recovery and the surface area required. Figure II-3 shows
the ratio of the heat exchanger surface to the flue-gas flow rate as a function
of the percent of heat recovery and the overall heat-transfer coefficient (U)
for recuperative heat exchangers for flue gases having temperatures of 900 to
1200°F. An overall heat-transfer coefficient of 4 Btu/(hr) (ft2) (°F) is used in
this study.
5 Waste-Heat Boiler
For this study a waste-heat boiler producing 100-psig steam was chosen because
the temperature of the flue gas from a catalytic oxidizer is 1200°F or less.
temperature of 500°F for the flue gas exhausted from the waste-heat boiler is
used for this study. See Sect. III-A-4 in the thermal oxidizer report* for a
discussion of heat recovery by use of a waste-heat boiler.
A
the VOC contained in the waste gas.
-------
0
500
H
I
600 700 800 900 1000 1100 1200
Flue-Gas Temperature (°F)
Fig. 11-2. Flue-Gas Heat Content
-------
II-8
1.OO
U = Overall Heat
Transfer Coefficient
20 30 4O
Heat Recovery (%)
Fig. II-3. Recuperative Heat Exchanger Design at 900 to 1200°F
Flue-Gas Temperature (100°F Waste-Gas and Air, Constant
Specific Heat)
-------
II-9
6. Stack and Other Equipment
The stack and ducting for this report are based on the same parameters used for
the thermal oxidizer (see Sects. III-A-5 and 6 in the thermal oxidizer report1).
B. CATALYTIC OXIDATION EFFICIENCIES
The destruction efficiency (conversion of VOC to carbon dioxide and water) for
catalytic oxidizers depends on the catalyst type and volume, the operating
temperature, and the composition and concentration of VOC in the waste gas.
The chemical structure of a compound affects the destruction efficiency of a
catalytic oxidizer more than it does a thermal oxidizer. A portion of the
waste gas can by-pass the catalyst at times in most bed designs, and this
limits the destruction efficiency that can be achieved.6 The catalyst may lose
activity with time for such reasons as sintering, accumulations of poisons, or
an accumulation of products. Although a higher operating temperature may
compensate to some extent for this loss in activity., there is a limit dictated
by the maximum operating temperature of the catalyst. In some cases the catalyst
may have to be cleaned periodically for activity and destruction efficiency to
be maintained. The actual life of the catalyst will vary with application and
is uncertain for a new use. Some catalysts are reported to have been in use
for over 8 years, but in some applications the catalyst must be replaced every
year; the average life appears to be in the range of 3 to 5 years. For this
study replacement of the catalyst every three years is assumed.2—5
-------
III-l
III. CONSIDERATIONS FOR INSTALLATION OF CATALYTIC OXIDIZERS
A. NEW PLANTS
All requirements that are considered when thermal oxidizers are installed also
apply to the installation of catalytic oxidizers (see Sect. IV of the thermal
oxidizer report1).
B. EXISTING PLANTS
All considerations for installation of a catalytic oxidizer in a new plant also
apply to retrofitting one in an existing plant. However, if the steam generation
boiler in an existing plant is adequate, a waste-heat boiler may not be economi-
cally feasible. The costs and cost-effectiveness data presented in this report
are not intended to apply to retrofitted catalytic oxidizer systems. In
retrofitted systems additional costs may be encountered because of such items as
demolition requirements, crowded construction working conditions, scheduling
construction activities with production activities, and longer interconnecting
ducts. These factors are site-specific, and no attempt has been made to provide
costs. For specific retrofit cases, rough costs may be obtained by using the
new-site data and adding as required for a specific retrofit situation.
-------
IV-1
J ENERGY IMPACTS OF CATALYTIC OXIDATION
^U OXIDIZER DESIGN SUMMARY
jost- and energy-effectiveness calculations for the typical or
ealytic oxidation system are presented here. The catalytic oxidizer
T«J, the waste-gas heat contents, and the resulting temperatures given in
V il-l for the base-case design establish the fuel requirement, the ratio of
.e-gas flow to waste-gas flow, and the percent of heat recovered. Costs are
.stimated for seven waste-gas flows.- 700, 2,000, 5,000, 10,000, 20,000, 50,000,
and 100,000 scfm,- for destruction efficiencies of 90 and 99%; and for no heat
recovery, heat recovery with a recuperative heat exchanger used to heat the
waste gas and combustion air, and heat recovery with a waste-heat boiler used to
produce steam.
B. COST BASIS
The estimated capital costs for the catalytic oxidation systems described repre-
sent the total investment required for purchase and installation of all equipment
and material to provide a facility like that described in Sect. II. This includes
all indirect costs, such as engineering and contractors' fees and overheads.
The estimated capital costs are battery-limits costs and do not include provi-
sion for bringing utilities, services, or roads to the site, backup facilities,
land, research and development, or process piping and instrumentation intercon-
nections that may be required within the process generating the waste-gas feed
to the catalytic oxidation system.
The method used to develop the estimated capital costs was based on applying
certain factors to the purchase prices of equipment to arrive at an installed
capital cost. Purchase costs were obtained from vendors and previous EPA reports
as described below. Table IV-1 gives the ranges used for factoring up the
purchased price of equipment to the installed cost and is based on historical
data of IT Enviroscience Process Engineering. The expected accuracy of the total
installed cost thus obtained is in the range of ±30%. This method of obtaining
total installed capital costs is suitable for study or screening estimates.
For catalytic oxidation systems a 30% allowance was added to the estimated major
equipment purchase cost to compensate for unspecified items, resulting in the
-------
IV-2
Table IV-1. Factors Used for Estimating Tota
A = Major Equipment Purchase
Installation costs
Foundations
Structures
Equipment Erection
Piping
Insulation
Paint
Fire Protection
Instruments
Electrical
B = Base Cost
Sales Tax
Freight
Contractor's Fees
C = Total Contract
a
Engineering
. b
Contingencies
D = Unit Installed Cost
E = Total Subestimates
F = Total Project Cost
Cost Plus 0.1 to 0.35 Allowance
0.06A + $100 X number of pumps
0.15A (no structures) to 0.30A (mu
0.15A to 0.30A (depending on complex.
0.40A (package units) to 1.10A (rat's .
0.06A or 0.15 X piping (normal) to 0.30 ^ t
(bulk hot or cold)
0.05A
0.01A to 0.06A (depending on requirements)
0.10A to 0.30A or 0.01A to 0.25A + $50,000 to
$300,000 for process control computer
0.15A or 0.05A + $500 per motor
A + Sum of Installation Costs
0.025A + 0.025B
0.16A
0. 30 (B-A)
B + Taxes, Freight, and Fees
0.01C to 0.20C
0.15C
C + Engineering + Contingencies
Sum of semidetailed subestiraates (buildings, site
development, cooling towers, etc.). Each subesti-
mate should include taxes, freight, fees, engi-
neering and contingency, and should be escalated
to date of expenditure for that cost component.
Engineering costs, contingencies, and escalation
factors for these subestimates will vary according
to the type of job.
D + E
Includes cost from capital project teams, process engineering, engineering,
purchasing, and other support groups.
"contingency should not be applied to any cost component that has been committed by
either purchase order or contract.
-------
IV-1
IV. COST AND ENERGY IMPACTS OF CATALYTIC OXIDATION
A. BASE-CASE CATALYTIC OXIDIZER DESIGN SUMMARY
The results of cost- and energy-effectiveness calculations for the typical or
base-case catalytic oxidation system are presented here. The catalytic oxidizer
conditions, the waste-gas heat contents, and the resulting temperatures given in
Table II-l for the base-case design establish the fuel requirement, the ratio of
flue-gas flow to waste-gas flow, and the percent of heat recovered. Costs are
estimated for seven waste-gas flows: 700, 2,000, 5,000, 10,000, 20,000, 50,000,
and 100,000 scfm; for destruction efficiencies of 90 and 99%; and for no heat
recovery, heat recovery with a recuperative heat exchanger used to heat the
waste gas and combustion air, and heat recovery with a waste-heat boiler used to
produce steam.
B. COST BASIS
The estimated capital costs for the catalytic oxidation systems described repre-
sent the total investment required for purchase and installation of all equipment
and material to provide a facility like that described in Sect. II. This includes
all indirect costs, such as engineering and contractors' fees and overheads.
The estimated capital costs are battery-limits costs and do not include provi-
sion for bringing utilities, services, or roads to the site, backup facilities,
land, research and development, or process piping and instrumentation intercon-
nections that may be required within the process generating the waste-gas feed
to the catalytic oxidation system.
The method used to develop the estimated capital costs was based on applying
certain factors to the purchase prices of equipment to arrive at an installed
capital cost. Purchase costs were obtained from vendors and previous EPA reports
as described below. Table IV-1 gives the ranges used for factoring up the
purchased price of equipment to the installed cost and is based on historical
data of IT Enviroscience Process Engineering. The expected accuracy of the total
installed cost thus obtained is in the range of ±30%. This method of obtaining
total installed capital costs is suitable for study or screening estimates.
For catalytic oxidation systems a 30% allowance was added to the estimated major
equipment purchase cost to compensate for unspecified items, resulting in the
-------
IV-2
Table IV-1. Factors Used for Estimating Total Installed Costs
A = Major Equipment Purchase
Installation costs
Foundations
Structures
Equipment Erection
Piping
Insulation
Paint
Fire Protection
Instruments
Electrical
B = Base Cost
Sales Tax
Freight
Contractor's Fees
C = Total Contract
a
Engineering
. b
Contingencies
D = Unit Installed Cost
E = Total Subestimates
F = Total Project Cost
Cost Plus 0.1 to 0.35 Allowance
0.06A + $100 X number of pumps
0.15A (no structures) to 0.30A (multideck structures)
0.15A to 0.30A (depending on complexity)
0.40A (package units) to 1.10A (rat's nest)
0.06A or 0.15 X piping (normal) to 0.30 X piping
(bulk hot or cold)
0.05A
0.01A to 0.06A (depending on requirements)
0.10A to 0.30A or 0.01A to 0.25A + $50,000 to
$300,000 for process control computer
0.15A or 0.05A + $500 per motor
A + Sum of Installation Costs
0.025A + 0.025B
0.16A
0.30 (B-A)
B + Taxes, Freight, and Fees
0.01C to 0.20C
0.15C
C + Engineering + Contingencies
Sum of semidetailed subestimates (buildings, site
development, cooling towers, etc.). Each subesti-
mate should include taxes, freight, fees, engi-
neering and contingency, and should be escalated
to date of expenditure for that cost component.
Engineering costs, contingencies, and escalation
factors for these subestimates will vary according
to the type of job.
D + E
"includes cost from capital project teams, process engineering, engineering,
purchasing, and other support groups.
Contingency should not be applied to any cost component that has been committed by
either purchase order or contract.
-------
IV-3
total estimated equipment purchase cost designated A in Table IV-1. This estab-
lished the basis for the application of all the installed capital cost factors
shown.
The sum of the installation costs for a catalytic oxidizer without a catalyst
bed or a connecting duct and with a minimum stack was estimated to be about 1.1
times A. The base cost (B) is therefore approximately 2.1 times the total
estimated equipment purchase cost (A). Additional percentages were applied to
the base cost (B) as shown in Table IV-1 to arrive at a unit installed cost (D)
for a catalytic oxidizer with a minimum stack but without a catalyst bed and
without a connecting duct to the process. The initial catalyst installed cost
(D) was estimated by multiplying the catalyst purchase cost obtained from
Fig. A-2 by 1.2 to account for the costs of freight, taxes, and labor and fees
for installing the catalyst bed in the oxidizer.
The sum of the installation costs for a waste heat boiler was also estimated to
be about 1.1 times A. For a recuperative heat exchanger, for the connecting
duct from the process to the catalytic oxidizer, and for the 80-ft stack the sum
of the installation costs was estimated to be about 0.5 times A (B is therefore
approximately 1.5 times A) because the foundations, structures, erection, and
piping will be incremental and relatively small when compared to those required
for the catalytic oxidizer. The same additional percentages for sales tax, freight,
contractor's fees, engineering, and contingencies were applied to the base cost (B)
to arrive at the unit installed costs (D) (see Table IV-1). Allowances for the
cost of site development and for the cost of vendor assistance during startup were
added to the total of all the unit installed costs (D) for each case to give the
total installed capital costs shown in Figs. IV-1 through IV-3.
The basic pieces of equipment are catalytic oxidizers, recuperative heat ex-
changers, and waste-heat boilers, plus the catalyst, ducts, and stacks. The
sources of purchase cost data for these items follow, and curves showing pur-
chase costs of the catalytic oxidizers, the catalyst, and the waste-heat boilers
are given in Appendix A. A curve showing the purchase costs of recuperative
heat exchangers is shown in Appendix A of the thermal oxidizer report.1
-------
10,000
o
o
o
in
O
O
73
*-•
'a
0 1000-
•o
-------
December 1979 Total Installed Capital Cost ($1000)
w •
rt
fO H
3 <
w i
to
HI •
o
If
H
s; 3
P) Ul
w rt
rt pj
fD H
h-'
0)
* g?
H- *O
ft H-
ff rt
cu
ffi O
fD 0
p) W
rt rr
cn
O
0 O
3 Hi
rt
fl> O
a pj
rt rt-
Cu
O M
Hi ••<
rt
K) H-
o o
W O
rt x
C H-
\ Oa
cn H-
O N
Hi fD
D)
(0
O
u
to
T1
O
cn
o
S-AI
-------
10,000
-— 99% Destruction
90% Destruction
No heat recovery
Waste-heat boiler, 56% recovery
Recuperative heat exchanger, 53% recovery
H
<
cn
100
100
1000
10,000
100,000
Waste-Gas Flow (scfm)
Fig. IV-3. Installed Capital Costs of Catalytic Oxidizer Systems
for Waste Gas with a Heat Content of 10 Btu/scf in Air
-------
IV-7
1. Purchase Costs of Catalytic Oxidizers
Preliminary purchase costs for catalytic oxidizers were obtained from vendors.
Several vendors were contacted by telephone and letter and three supplied cost
data and other information: Du Pont,5 Englehard,13 and Oxy-Catalyst.14 The
costs were for prepiped and prewired units complete with the burner, blower, re-
fractory, controls, etc., required for handling various waste-gas flows [in
standard cubic feet per minute (scfm)]. Purchase cost data were also extracted
from previous EPA reports and escalated to December 1979. The curves shown in
Appendix A for the purchase costs of the catalytic oxidizers and of the catalyst
were derived from the combined data.
2. Purchase Costs of Recuperative Heat Exchangers
The purchase costs of recuperative heat exchangers were obtained from Appendix A
of the thermal oxidizer report.1
3. Purchase Costs of Waste-Heat Boilers
The purchase costs of waste-heat boilers for 100-psig steam were estimated by
adjusting the purchase costs from the thermal oxidizer report1 to compensate for
the differences in flue-gas temperatures and steam pressures.
4. Purchase Costs of Ducts
Each system is assumed to require 150 ft of round-steel inlet ductwork with the
same fittings shown for the thermal oxidizer.1 The costs used are also the
same.
5. Purchase Costs of Stacks
The costs of the stacks are the same as those used for thermal oxidizers.1
C. ANNUAL COSTS
Annual costs for various operating conditions are given in Appendix B. These
costs are the basis for all the net annual cost graphs included in the report.
The basis used in calculating these annual costs is defined in Table IV-2.
Figures IV-4 through IV-9 present the net annual costs of catalytic oxidation
for various cases.
-------
IV-8
Table IV-2. Annual Cost Parameters
Operating factor
Operating labor
Fixed Costs
Maintenance labor plus
materials, 6%
Capital recovery, 18%
Taxes, insurances,
administration charges, 5
Utilities
Electric power
Natural gas
Heat recovery credits
(equivalent to natural gas)
8760 hr/yrc
$15/man-hr
29% of installed
capital
$0.03/kWh
$2.00/million Btu
$2.00/million Btu
Control devices will usually operate on the same cycle as the process.
Process downtime is normally expected to range from 5 to 15%. If the hourly
rate remains constant, the annual production and annual VOC emissions will be
correspondingly reduced. From the standpoint of cost-effectiveness calcula-
tions, the error introduced by assuming continuous operation is negligible.
Based on 10-year life and 12% interest.
-------
E
•*-
o
200,
1501
in
O
U
- 100
05
3
c
c
U
z
50
r
Conditions
90% Conversion of VOC
No Heat Recovery
Waste-Gas Heat Content
— 10
10 (in air)
(Btu/scf
H
<
100 1000 10iooo
Waste-Gas Flow Rate (scfm)
Fig. IV-4. Net Annual Costs vs Waste-Gas Flow Rate for Catalytic
Oxidizers Having a Destruction Efficiency of 90% and with No Heat Recovery
100,000
-------
200
150
w
o
<-> 100
"ra
a
c
c
0)
z
50
100
Conditions
90% Conversion of VOC
Recuperative Heat Exchanger
Waste-Gas Heat Content IBtu/scf):
2
H
<
O
_L_J I L_L
1000 10'000
Waste-Gas Flow Rate (scfm)
100,000
Fig. IV-5. Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxiclizers
Having a Destruction Efficiency of 90% and with Recuperative Heat Exchangers
-------
200
E
o
150
in
O
" 100
15
3
C
C
* 50
Conditions
90% Conversion of VOC
Waste-Heat Boiler, 100-psig Steam
Waste-Gas Heat Content (etu/scf
10
20; 10 (in air)
J L
100 1000 10,000
Waste-Gas Flow Rate (scfm)
Fig. IV-6. Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers
Having a Destruction Efficiency of 90% and with Waste-Heat Boilers
100,000
-------
200
150
Conditions
99% Conversion of VOC
No Heat Recovery
Waste-Gas Heat Content (Btu/scf):
2
20
10
10 (in air)
M
to
100
1000 10,000
Waste-Gas Flow Rate (scfm)
100,000
Fig IV-7 Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers
Having a Destruction Efficiency of 99% and with No Heat Recovery
-------
200
150
« 100
o
O
ra
c
<
o
z
50
100
_l
Conditions
99% Conversion of VOC
Recuperative Heat Exchanger
Waste-Gas Heat Content (etu/scf)
I
M
U>
_L
J_
1000 10,000
Waste-Gas Flow Rate (scfm)
100,000
Fig, IV-8. Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers
Having a Destruction Efficiency of 99% and with Recuperative Heat Exchangers
-------
200
100
Conditions
99% Conversion of VOC
Waste-Heat Boiler, 100-psig Steam
Waste-Gas Heat Content (Btu/scf
2
10
20 ; 10 (in air)
H
f
1000
10,000
100,000
Waste-Gas Flow Rate
Fig IV-9. Net Annual Costs vs Waste-Gas Flow Rate for Catalytic Oxidizers
Having a Destruction Efficiency of 99% and with Waste-Heat Boilers
-------
IV-15
COST AND ENERGY EFFECTIVENESS
The cost effectiveness and energy effectiveness were calculated by dividing the
annual cost for a particular option (Appendix B) or the fuel usage in Btu/yr by
the total annual amount of VOC destroyed with the conversion efficiencies assumed
in Sect. II. The cost effectiveness is given in Table IV-3 and the energy
effectiveness is given in Table IV-4. Data on cases not shown in the cited
tables can be easily developed by use of Appendix B.
-------
Table IV-3. Cost Effectiveness of Catalytic Oxidation
w t • t v Waste-Gas VOC
' . " J rlow Destroyed
Cogent Hate (lb/hr)
(BLUA-.CO (^ISL^ £t^0^_
"2 700 5.18
5,000 37.0
50,000 370
100,000 739
700 25.9
30
5,000 185
50,000 1,850
100,000 3,700
700 51.8
5,000 370
50,000 3,700
100,000 7,390
700 25.9
10 (in air)
5,000 185
50,000 1,850
100,000 3,700
—
aVOC molecular weight = 50; molar heat of
bl ft3 of catalyst per 1000 scfm.
C1.5 ft3 of catalyst per 1000 scfm.
voc
Dostroyci
(lb/hr)
at 99ta
5.69
40.7
407
813
28.5
203
2,030
4,070
56.9
407
4,070
8,130
26.5
203
2,030
4,070
_. ._.. , •
combustion =
—
—
Co'-t Effectiveness (per Ib ot vu^J ueatiuyeu, . .
b 99» VOC Destruction
901 VGC Destruction __
d
Ho Heat Recuperative
$2.00 $2.37
0.758 0.733
0.517 0.410
0.503 0.390
0.367 °-445
0.120 0.118
0.0719 0.0538
0.0692 0.0497
0.188 0.219
0.0632 0.0529
0.0388 0.0200
0.0375 0.0180
0.336 0-423
0.0977 0.0985
0.0518 0.0348
0.0488 0.0305
730,250 Btu/lb-mole.
Waste-Heat
Boiler
$2.63
0.735
0.389
0.362
0.495
0.116
0.0472
0.0417
0.239
0.0481
0.0127
0.00925
0.466
0.0961
0.0297
0.0242
No Heat
Recovery
$1.84
0.710
0.489
0.476
0.338
0.113
0.0691
0.0665
0.173
0.0596
0.0373
0.0361
0.309
0.0916
0.0497
0.0469
Recuperative
Heat Exchanger
$2.18
0.685
0.391
0.372
0.409
0.111
0.0524
0.0486
0.201
0.0500
0.0200
0.0181
0.387
0.0924
0.0342
0.0302
Waste-Heat
Bo 1 ] e r
$2.41
0.688
0.373
0.348
0.454
0.110
0.04G7
0.0416
0.219
0.0459
0.0135
0.0104
0.427
0.0901
0.0296
0.0246
H
-------
Table iv-4. Fuel Energy Effectiveness of Catalytic Oxidation
Hc,-,t ConLCi.t
(Btu/sct I or WastL-llo^t Boiler Heat Lxcr .-:ic;L'r
2 24.2 i-;.2
10 14.G
20 15.9
10(in air) 10.1
i: .8
2.2
(6.1)
(1.0)
J:l1^/jy_J^fpctivenj2SS__(liLu/lb of VOC Destro'.-J)'
'0 .. VCXJ Destruc
n ui t
He it exchanger
115,000
9,090
0
0
tion
W
Boiler
96,000
3,570
(4,900)
(1 ,620)
Po co very
179,000
21,500
11,700
14,900
99 i VOC ^-t>-,--t i - -
Rocu; . r.itive ,s
Hc.it E.-c!u---.aji-
Iu5,000
8,2oO
J
0
1.5 ft of catalyst per lOOu scftn.
-------
v-i
V. SUMMARY AND CONCLUSIONS
Catalytic oxidation is used in several industries as a control technique for
VOC emissions. The VOC in the off-gases from several processes in the synthetic
organic chemical manufacturing industry are controlled by use of catalytic
oxidation. A design criterion and design procedures are presented that allow
for a preliminary catalytic oxidation design. A catalytic oxidation system
with two destruction efficiencies and three heat recovery options, i.e., no
heat recovery, heat recovery with a recuperative heat exchanger, or heat
recovery with a waste-heat boiler, is considered. Capital and operating costs
are developed, and the annual cost of catalytic oxidation is calculated as a
function of the characteristics of the waste gas. The cost effectiveness and
energy effectiveness of the two VOC destruction efficiencies and of three heat
recovery cases are developed.
The conclusions of the cost evaluation are as follows:
1. The waste-gas flow rate is a highly sensitive variable in the determina-
tion of the annual cost and cost effectiveness (see Table IV-3). Energy
effectiveness is independent of flow rate. As the feed flow rate increases,
the annual costs increase but the annual cost per scfm decreases. The
annual cost per scfm decreases quickly between 700 and 4000 scfm. The
ratio decreases moderately between 4,000 and 40,000 scfm and is almost
constant above 40,000 scfm.
2. The cost effectiveness and the energy effectiveness are strongly dependent
on the waste-gas heat content, i.e., the VOC concentration (see Table IV-3,
Table IV-4, and Appendix B). At 20 Btu/scf or 10 Btu/scf in air no fuel
is required when recuperative heat recovery is used and the system is at
operating temperature so that the energy effectiveness is almost zero. At
the same VOC concentrations the recovery credit is greater than the fuel
energy required if a waste-heat boiler is employed.
3. The annual cost, cost effectiveness, and energy effectiveness are slightly
sensitive to the destruction efficiency or amount of catalyst (see
Tables IV-3 and IV-4 and Figs. IV-4 through IV-9). This sensitivity is
greater at low waste-gas flow rates than at high flow rates.
-------
VI-1
VI . REFERENCES*
1. J. W. Blackburn, IT Enviroscience, Inc., Control Device Evaluation. Thermal
Oxidation (July 1980) (EPA/ESED report, Research Triangle Park, NC) . -
2. R. W. Kent, A Guide to Catalytic Oxidation. Oxy-Catalyst, Inc., Research-
Cottrell, Inc., West Chester, PA (in-house brochure).
3. R. W. Rolke et al. , shell Development Company, Afterburner Systems Study
EPA-R2-062, Research Triangle Park, NC (August 1972). -
Emission Control Systems . Oxy-Catlyst, Inc., West Chester PA
(in-house brochure).
5. G. I. Madden, E. I. du Pont de Nemours & Company, letter dated Oct 4 1979 to
J. A. Key, IT Enviroscience, Inc., with data on catalytic oxidation.
6. J. Beale, Chemical Manufacturers Association, letter dated July 14 1980
with attached comments on draft Catalytic Oxidation Report.
7. J. A Key, IT Enviroscience, Inc., notes on EPA meeting on RShne-Poulenc S A
catalytic oxidation technology, at Durham, NC, on Aug. 23, 1979.
8. J. C. Zimmer Rhone-Poulenc S.A., letter dated May 29, 1979, to R. Walsh, EPA
regarding phthalic anhydride, maleic anhydride, and bisphenol A.
9. B. Tichenor, EPA, memorandum dated Feb. 25, 1980, to L. B. Evans, EPA with
data on formaldehyde from work on EPA Contract No. 68-02-3133.
10. J A. Key, IT Enviroscience, Inc., Trip Report for Visit to E. I. du Pont de
Nemours & Company, Beaumont, TX. Sept. 7, 1977 (Acrvlonitrile) (data on file at
fcPA, ESED, Research Triangle Park, NC) .
11- W. R. Taylor, Diamond Shamrock Corporation, letter dated Oct 3 1977 to D R
Goodwin, EPA, regarding ethylene dichloride oxychlorination vent.
12. J. F. Lawson, IT Enviroscience, Inc., Trip Report for Visit to Union Carbide
Corporation, South Charleston, WV. Dec. 1, 1977 (Ethvlene oxid»l (*»*»£%,.
at EPA, ESED, Research Triangle Park, NC) .
13. R. D. Uhlman, Engelhard Minerals & Chemicals Corporation, letter dated
Oct^ 24, 1979, to J. A. Key, IT Enviroscience, Inc., with data on catalytic
oxidation. J
14. T. T. Fung, Oxy-Catalyst, Inc., letter dated Nov. 9, 1979 to J A Key
IT Enviroscience, Inc., with data on catalytic oxidation.
15. CE Air Preheater, Industrial Gas Cleaning Institute, Report of Fuel Requirements
Capital Cost and Operating Expense for Catalytic and Thermal Afterburners, - '
EPA-450/3-76-031, Research Triangle Park, NC (September 1976).
-------
VI-2
16. M. L. Kinkley and R. B. Neveril, Card, Inc., Capital and Operating Costs
of Selected Air Pollution Control Systems, EPA-450/3-76-014, Research Triangle
Park, NC (May 1976).
17. Industrial Gas Cleaning Institute, Air Pollution Control Technology and Costs
in Seven Selected Areas, EPA 450/3-73-010, Research Triangle Park, NC (December
1973).
^Usually, when a reference is located at the end of a paragraph, it refers to
the entire paragraph. If another reference relates to certain portions of
that paragraph, that reference number is indicated on the material involved.
When the reference appears on a heading, it refers to all the text covered by
that heading.
-------
APPENDIX A
PURCHASE COSTS FOR CATALYTIC OXIDIZERS,
CATALYST, AND WASTE-HEAT BOILERS
-------
1000
99% Destruction
90% Destruction
Without Catalyst
100
1000 10,000
Flue Gas Flow (scfm)
100,000
A-l. Purchase Costs for Catalytic Oxidizers
-------
500
• 99% Destruction
90% Destruction
o
o
o
o
O
a
u
9
O)
TJ
3
m
O)
r-
o>
-------
500
o
o
o
O
O
a>
in
re
3
Q.
m
O)
u.
0)
I
0)
o
0)
Q
/
100
xX
/
X
50
— 900° F Flue Gas
— 1200°F Flue Gas
i
m
5 10 50 100
Waste-Heat-Boiler Steam Capacity (lOOOIb/hr)
500
Fig. A-3. Purchase Cost for Waste-Heat Boilers Producing 100-psig Steam
-------
APPENDIX B
ANNUAL COST DATA
-------
B-3
SAMPLE CALCULATIONS- — ANNUAL COST DATA
The following sample calculations are based on an off-gas stream having a
heat content of 10 Btu/scf and consisting primarily of nitrogen (combustion
air must be supplied to the preheat burner and air must also be mixed with
the off-gas so that after combustion of the fuel to the burner and oxidation
of the VOC in the off-gas the flue gas contains 3 mole % oxygen) .
Basis of calculations:
Off-gas flow rate 8,000 scfm
Off-gas temperature 100 °F
Destruction of VOC 99%
Flue gas to off-gas ratio 1.45 scf/scf (Table II-l)
Heat recovery Waste-heat boiler generating
100-psig steam with 50% heat
recovery and flue gas in at
900 °F and out at 500 °F
Capital cost = $563,000; from Fig. IV- 1.
Fixed cost = ($563,000 X 0.29*) + catalyst replacement cost ($16,000) = $179,000/yr.
Catalyst replacement cost =
catalyst purchase cost ($40,000) X installation factor (1.2)
3-yr replacement
Catalyst purchase cost = $40,000; from Fig. A- 2
(1.45 X 8000 scfm = 11,600 scfm of flue gas).
Operating cost = fuel ($122,780) + electricity ($9,551) + labor ($36,000)
= $168,331/hr.
Fuel = [14.6 Btu/scf (Table II-l] X (8,000 scfm) X ($2.00/million Btu*) X
(60 min/hr) X (8760 hr/yr) = $122,780/yr.
Electricj-ty =
(16 in. HO X (o. 0001575 T-^_\ X (8,000 scfm) X fl.45 S°f °f air
z V ln- H°/ \
.
2°/ \ scf of off-gas /
• - — - — - — — . — - - — - . - . - , - _ X
0.60 efficiency
X (0.746 kWh) X ($0.03/kWh*) X (8760 hr/yr) = $9,551/yr.
Labor = $36,000/yr (from ref 1) ; the labor cost for a system without
heat recovery is $18,000/yr.
*
See Table IV-2.
-------
B-4
Credit = (8.56 Etu/scf) X (8,000 scfm) X (l.45 ^f of waste^as) X (6° min/hr) x
X ($2.00/million Btu) X (8760 hr/yr) = $104,000/yr.
Annual cost = fixed cost ($179,000/yr) -f- operating cost ($168,000/yr) -
credit ($104,000/yr ) = $243,000/yr.
Net cost = - nn - $30.4/scfm.
flow rate (8,000 scfm)
-------
ANNUAL COSTS OF CATALYTIC OXIDATION SYSTEMS
90% CONVERSION OF VOC
OFF-GAS HEAT CONTENT! 0.0 PTU/SCF
CASE OFF-GAS CAPITAL
FLOW COST
(SCFM) ($1000)
NO HEAT RECOVERY
700, 184.
2000. 236.
5000. 314.
10000. 411.
20000. 574.
50000. 1022.
100000. 1812.
RECUPERATIVE HEAT EXCHANGER
37% HEAT RECOVERY
700. 236.
2000. 311.
LiOOO. 429.
10000. 582.
20000. 841.
50000. 1347.
100000. 2740,
WASTE HEAT BOILER,100 PSIG STEAM
SOX HEAT RECOVERY
700. 251.
2000. 322.
5000. 444.
10000. 612.
20000. 909.
50000. 1716.
100000. 2950.
OPCRrM TNG
FIXEIi
COST
54.
71 .
98.
132.
192.
359.
649.
69.
93.
131.
181.
268.
507,
910.
74.
96.
135.
191 .
290.
561.
979.
COST OR CREDIT
OPERATING
COST
36.
69,
MS ,
273.
528,
1293,
2568,
38.
59.
106.
185.
342.
815.
1602.
54.
38.
167.
298.
559.
1315.
2653.
< $1000)
RECOVERY
CREDIT
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
9.
26.
65 .
130.
261 .
652.
130T..
NET
ANNUAL!ZED
COST OR CKEDIT
($1000)
90.
140.
213.
405.
720.
1652.
3216.
107.
151.
237.
366.
610.
13?2.
2512.
119.
158.
237.
358.
588.
1253.
2327.
NET COST
OR SAVINGS
<«/SCFM>
129.
70.
49.
41 .
36.
33.
32,
154,
76,
47.
37,
31.
26 .
25.
170,
79.
47,
36.
29.
25.
23.
ft)
Ul
-------
ANNUAL COSTS OF CATAIYTFC OXIDATION SYSTEMS
90X rOK'VFRBION OF VOC
QFF-fiAS HEAT CONTENT! 2.0 BTU/SCF
T.ASE
OFF-GAS
FLOU
(SCFM)
CAPITAL
COST
(tlOOO)
NO HEAT RECOVERY
700 .
2000 .
5000.
10000.
20000.
50000.
100000.
RECUPERATIVE HEAT EXCHANGER
-177. HEAT RECOVERY
700.
2000.
5000.
10000.
20000.
50000.
100000.
UASTE HEAT BOILER,100 PSIG STEAh
505! HEAT RECOVERY^
2000.
5000.
10000.
20000.
50000.
100000.
184.
237.
316.
-115.
580.
1037.
236.
311.
429.
D82.
841 .
1547.
2740.
252.
323.
446.
615.
915.
1731.
2983,
OPERATING COST OF; CRtlU f
PTXED OPERATING
COST COST
54.
72.
98.
134.
195.
365.
661.
69.
93.
131 .
181 .
268.
507,
910.
74.
97.
136.
192.
n92 »
566.
991 i
36.
70.
147.
?76.
534.
1308.
2598.
38.
59.
107.
186.
345.
822.
1617.
55.
89.
168.
301 .
566.
1360.
2685.
(41000)
RECOVERY
CREDIT
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
9.
27.
67.
133.
266.
666.
1332,
NET
ANNUALIZED
COST OR CREDIT
($1000)
91 .
141 .
246.
110.
729.
1673.
3259.
108.
152.
237.
367.
613.
1329.
2527 ,
119.
159.
238.
339.
591,
1241,
2344 ,
MET COST
OR SAVINGS
(t/SCFH)
129 .
71 .
49 .
41 .
36.
33.
33.
154.
76.
f.7 .
37.
31 .
27.
25.
170.
79.
48.
36.
30.
25.
23.
W
I
-------
ANNUAL COSTS OF CATALYTIC OXIDATION SYSTEMS
907. CONVERSION OF VOC
OFF-GAS HF.AT CONTENT! 10.0 BTU/SCF"
CASE OFF-GAS CAPITAL
FLOW COST
(SCFM) ($1000)
NO HEAT RECOVERY
700. 184,
2000. 236.
5000. 314.
10000. 411.
20000. 574,
50000. 1022.
100000. 1812,
RECUPERATIVE HEAT EXCHANGER
36X HEAT RECOVERY
700. 235.
2000. 309.
5000. 426,
10000. 576.
20000. 830,
50000. 1520.
100000. 2684.
UASTE HEAT BOILER»100 PSIG STEAM
SOX HEAT RECOVERY
700. 251.
2000. 322.
5000. 444.
10000. 612.
20000. 709.
50000. 1716,
100000. 2950.
OPERATING
FIXED
COST
54.
71 .
98.
132.
192.
359.
649.
69.
92.
130.
179.
265.
500.
894,
74,
96,
135,
191 ,
290 ,
561 ,
979,
COPT OR CREDIT
OPERATING
COST
29.
49.
97.
175.
333.
305,
1592.
32,
41.
41.
96.
165.
371.
715.
47.
69.
118,
200.
364 ,
837.
1678.
t 000)
RECOVERY
CREDIT
0,
0.
0.
0.
0.
0.
0.
0,
0.
0.
0.
0.
0.
0.
9.
26.
65.
] 30.
261 .
652.
1305,
MET
ANNUALIZED
COST OR CREDIT
(tlOOO)
83.
121 .
194 .
308.
525.
1164.
2241 .
101 .
133.
191 .
T75.
429.
871 .
1609.
112.
139.
188.
260.
393.
765.
1351 .
NET COST
OR SAVINGS
($/SCFM)
119.
60,
39.
31,
26.
23.
144,
66,
38,
28,
21 ,
17,
16,
160,
69.
38,
26.
20,
15.
14,
W
-------
ANNUAL COSTS OF CATALfTtC OXIDATION SYSTEMS
902 CONVERSION OF VUC
OFF-GAS HEAT CONTENT! 20.0 BTII/SCF
CASE
OFF-GAS
FLOU
(SCFM)
CAPITAL
COST
($1000)
OPERATING
FIXED
COST
COPT OR CREDIT
OPERATING
COST
($1000)
RECOVERY
CREDIT
NET
ANNUALIZED
COST OF: CREDIT
(*1000>
NET COST
OR SAVINGS
(*/SCFH>
NO HEAT RECOVERY
700. 187.
2000. 241.
5000. 323.
10000. 126.
20000. 600.
50000. 1037.
100000. 1958.
RECUPERATIVE HEAT EXCHANGER
452 HEAT RECOVERY
700. 244.
2000. 326.
5000. 459.
10000. 633.
20000. 933.
50000. 1763.
100000. 3182.
UASTE HEAT &OILER.100 PSIG STEAM
62'X HEAT RECOVERY
700. 258.
2000. 338.
5000. 476.
10000. 676.
20000. 1027.
50000. 1962.
100000. 3295.
73.
101.
138.
202.
383.
702.
72.
97.
139.
196.
295.
572.
1041 .
76.
101.
146.
210.
326.
637.
1090.
30.
52.
104.
189.
360.
873.
1729.
28.
29.
32.
37.
47.
77.
127.
48.
72.
125.
214.
393.
928.
1820.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
16.
46.
116.
231 .
462.
1155.
2310.
85.
125.
205.
327.
562.
1207.
2430.
99.
126.
171 .
233.
342.
649.
1168 .
108.
126.
156.
194.
257.
•110.
599.
122.
63.
41 .
33.
28.
25.
24.
142,
63.
34.
23.
17,
13,
12,
155.
63.
31 .
19 .
13,
8.
6,
CO
I
00
-------
ANNUAL COSTS OF CATALYTIC OXIDATION SYSTEMS
90% CnK'UFRSrdN OF VDC
OFF-GAS HEAT CONTENT.1 10.0 BTU/SCFdN AIR)
CASE OFF-GAS CAPITAL
FLOW COST
(SCFM) ($1000)
NO HEAT RECOVERY
700. 172.
2000. 215,
5000. 279.
10000. 357.
20000. 482.
50000. 802.
100000. 1330.
RECUPERATIUE HEAT EXCHANGER
53X HEAT RECOVERY
700. 233.
2000. 308.
5000, 428.
10000. 335.
20000. 852.
50000. 1373.
100000. 2766.
UASTE HEAT HOILER.100 PSIG STEAM
56X HEAT RECOVERY
700. 238.
2000. 299.
5000. 401.
10000. 542.
20000. 789.
50000. 1138.
tOOOOO. 2390.
OPERATING
FIXED
COST
51 .
64.
86.
1 13.
158.
276.
472.
68.
91 .
129.
179.
265.
500.
888.
70.
88.
121 .
166.
247.
461 .
779.
COST OR CREDIT
OPERATING
COST
40.
72.
127.
236.
563.
110P.
28.
28.
31 .
34.
41 .
63.
99.
44.
39,
93.
130,
263,
604.
1172.
<*1000)
RECOVERY
CREDIT
0,
0.
0.
0.
0.
0 ,
0.
0.
0.
0.
0.
0.
0.
0.
8.
23.
58.
117.
233.
OS3.
1167.
MET
ANNUALIZED
COST OR CREDIT
($1000)
76.
104 .
158.
240.
394.
839.
1579.
96.
120.
160,
213.
307,
563.
987,
106.
124.
156.
199.
277.
481 ,
784.
NET COST
OR SAVINGS
(*/SCFM>
109,
52,
32.
24,
20,
17,
16,
137,
60.
32,
21 .
15.
1 1 .
10,
151,
62.
31 ,
20.
14 ,
10 ,
M
-------
ANNUAL COSTS OF CATALYTIC OXIDATION SYSTEMS
992 CONVERSION OF VOC
OFF-GAS HEAT CONTENT! 0.0 &TU/SCF
CASE
OFF-CAS
FLOU
(SCFM)
CAPITAL
COST
($1000)
NO HFAT RECOVERY
700. 18?.
2000. 240.
5000. 324.
10000. 431.
?0000. 613.
50000. 1117.
100000. 1996.
RECUPERATIVE HEAT EXCHANGER
377. HEAT RECOVERY
700. 238,
2000. 315.
5000. 439.
10000. 601.
20000. 878.
50000. 1635.
100000. 2912.
UASTE HEAT BOILERflOO PSI6 STEAM
•-,07. HEAT RECOVERY
700. 253.
2000. 326.
5000. 454.
10000. 632.
20000. 948.
50000. 1811,
100000, 3134,
OPERATING
FIXED
COPT
74 .
104 .
145.
217.
418.
763.
70.
95.
137.
193.
291 .
562,
1017,
75.
99.
142.
203.
314.
619.
1093,
cam OR CREDIT
OPERATING
COST
36.
69.
146.
274,
531 .
1300.
2583.
38.
09.
106.
186.
345.
822.
1616.
54.
39.
168.
299,
562.
1352.
2668.
($1000)
RECOVERY
CREDIT
0 .
0,
0.
0.
0.
0,
0 .
9 ,
26.
65 .
130.
261 ,
652,
1305,
NET
ANNUALIZED
COST OF: CREDIT
($1000)
91 .
143.
250 .
119.
748.
1719.
3346 .
108.
154.
243.
379.
636.
1334,
2633,
120.
161 .
244 .
372.
615,
1319,
2457 ,
MET COST
OR SAVINGS
($/<3CFM>
130.
72.
50.
42 .
37.
34.
33.
155.
77 .
49.
38.
32.
28.
26 ,
172,
81 .
49,
37,
31 ,
26,
td
M
O
-------
ANNUAL COSTS OF CATALYTIC OXIDATION SYSTEMS
99% r.OHVFRSION OF MOC
OFF-GAS HEAT CONTENT: 2.0 BTU/SCF
CASE OFF-GAS CAPITAL
FLOU COST
(SCFh)
NO HEAT RECOVERY
700. 184.
2000, 241,
5000. 327.
10000. 435.
20000. 620.
50000. 1133.
JOOOOO. 2033.
RECUPERATIVE HEAT EXCHANGER
.37% HEAT RECOVERY
700. 238.
2000. 315.
5000. 439.
10000. 601,
20000. 878.
50000. 1635,
100000. 2912.
UASTE HEAT BOILERflOO PSIG SIEAM
50% HEAT RECOVERY
700. 253.
2000. 3^3,
5000. 456,
10000, 635.
20000. 955.
50000. 1828.
100000. 3171 .
OPERATING
FIXED
COCT
74.
105.
146.
219.
425.
778.
70.
95.
137.
193.
291 .
562.
1017.
75.
99.
143.
205.
317.
626.
1108.
COST OR CREDIT
OPERATING
COST
36.
70.
MS.
278.
537,
1316.
2613.
38.
59,
107,
187.
348 ,
829,
1631 ,
55,
89,
169 ,
302.
569,
1368.
2700,
($1000)
RECOVERY
CREDIT
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
9.
27.
67.
133.
266,
666.
1332.
NET
ANNUALIZEO
COST OR CREDIT
($1000)
92.
144 .
253.
424.
756.
1741 .
339t .
109 .
154.
244 .
380,
639,
1391.
2648 .
120.
162.
245.
374.
619.
1328.
2476 .
NET COST
OR SAVINGS
(*/SCFM)
131 ,
72 .
51 ,
42.
38,
35.
34.
77.
49,
38.
32,
28,
26.
172,
81 .
49 ,
37 .
31 ,
27.
25,
ft)
-------
ANNUA1 COSTS OF CATALfTJC OXIDATION SYSTEMS
99% (-(INVERSION OF VOC
OFF-GAS HEAT CONTENT! 10.0 BTII/SCF
CASE OFF-GAS CAPITAL
FLOU COST
(SCFM) ($1000)
NO HEAT RECOVERY
700. 185,
2000. 240,
5000. 324.
10000. 131.
20000. 613.
50000. 1117.
100000. 1996.
RECUPERATIVE HEAT EXCHANGER
36X HEAT RECOVERY
700. 237.
2000. 313.
5000. 435.
10000. 594.
20000. 866.
50000. 1608.
100000. 2858.
WASTE HEAT HOILERtlOO PSIG STEAH
f.0% HEAT RECOVERY
700. 253.
2000. 326.
5000. 454.
10000. 632.
20000. 948.
50000. 1811.
100000. 3134.
OPERATING COST OR CRtDIT (*1000)
FIXED OPERATING RECOVERY
COST COST CREDIT
74.
104 .
145.
217.
120.
62 .
40.
32 .
28.
25.
24 .
146 .
68.
40.
29.
23 ,
19 .
17,
162.
71 .
39 .
27 ,
21 ,
17.
15.
td
H»
N:
-------
ANNIIAI COSTS OF CATALYTTC OXIDATION SYSTEMS
992 CONVERSION DF VOC
OFF-GAS HEAT CONTENT! 20.0 BTU/3CF
CASE OFF-GAS CAPITAL
FLOU COST
(SCFM) ($1000)
NO HEAT RECOVERY
700, 188.
2000. 246,
5000. 334.
10000. 448,
.70000. 643.
50000. 118?,
100000. 2158.
RECUPERATIVE HEAT EXCHANGER
45% HEAT RECOVERY
700. 245.
2000. 330.
5000. 468.
10000. 652.
20000. 970.
50000. 1354,
100000, 3358,
WASTE HEAT BOILER*100 PSIG STEAM
62% HEAT RECOVERY
700. 260.
2000, 343.
5000. 489,
10000. 697.
20000. 1070.
50000. 2064,
100000. 3495,
OPERATING
FIXED
COST
56.
76,
108.
151.
2°9.
447.
826.
73.
100,
146,
208.
319.
628.
1151 ,
77,
104,
153.
** ^4
352.
701,
1214.
COPT OR CREDIT
OPERATING
COST
30.
53 .
104.
191.
363.
882.
1745.
28.
29.
33.
38.
50,
84.
141 .
49.
72,
126.
216.
396.
936.
1836.
($1000)
RECOVERY
CREDI r
0.
0.
0.
0.
0.
0,
0.
1 6,
46,
116.
231 .
462 .
1155,
2310.
MET
ANNUAL I ZED
COST OR CREDIT
($1000)
86.
128.
212.
342,
592.
1329.
2571.
100.
129.
178.
247.
369.
712.
1293.
109.
130,
163.
209,
286.
432.
740.
NET COST
OR SAVINGS
(*/SCFM>
123.
64 .
42 .
34.
30.
27.
26.
143,
65.
36.
25.
18.
14 .
13.
156,
65.
33.
21.
14 ,
10 .
7.
tn
-------
ANNUAL COSTS OF CATALYTIC OXIDATION SYSTEMS
99X CONVERSION OF VOC
OFF-GAS HEAT CONTENT: 10.0 BTU/SCF(IN AIR)
CASE OFF-GAS
FLOU
(SCFM)
HO HEAT RECOVER'
;oo.
2000.
5000.
10000.
:;oooo.
50000.
tooooo .
RECUPERATIVE HEAT EXCHANGER
53* HEAT RECOVERY
700.
2000.
5 0 0 0 .
10 ""'" •
100030.
H-A1 f. OILEHitOO PSTG 31 i
-,6X. H^AT RECOVERY
700.
2000 .
5000.
10000.
:: o o o o.
50000.
100000.
CAPITAL
COST
($1000)
173 .
218.
237 .
3M .
509.
863.
1458.
234.
311.
436 .
-, 79 ,
AM
240.
302.
409.
556.
816.
1504.
2517.
OPERATING
r i x E D
COST
51 .
66.
90.
121 .
175.
318.
69.
93.
13,1.
138.
292.
511 .
968.
71 .
90.
126.
175.
264.
502.
859.
COST OR CREIiIT
OPERATING
COST
26.
40.
73.
128.
238.
568.
1118.
28.
29.
31 .
35.
43 .
68.
109,
44 ,
59.
93.
151 .
265.
609 .
1182,
(t1000)
RECOVERY
CREDIT
0.
0,
0 .
0.
0.
0.
0.
0.
0.
0 .
0 .
o.
0,
0.
23.
OP.
117.
233.
583.
1167,
NET
ANNUALIZED
COST OR CREDIT
($1000)
77.
1 06.
163.
249.
413.
836.
1670.
97.
122.
165.
223.
326.
609 .
107B.
106.
126.
161 .
20? .
296 .
528.
875.
MET COST
OR SAVINGS
(*/SCFM)
110.
53.
33.
25.
21 .
18.
17,
138.
61 .
33.
1 -)
16 .
12.
1 1 .
1!
63.
32 .
21 .
15.
11 .
9 .
-------
4-i
REPORT 4
CONTROL DEVICE EVALUATION
FLARES AND THE USE OF EMISSIONS AS FUELS
V. Kalcevic
IT Enviroscience
9041 Executive Park Drive
Knoxville, Tennessee 37923
Prepared for
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
ENVIRONMENTAL PROTECTION AGENCY
Research Triangle Park, North Carolina
February 1981
-------
4-iii
CONTENTS OF REPORT 4
Page
I. INTRODUCTION
II. SYSTEM DESCRIPTIONS
A. Elevated Flares
B. Enclosed Ground Flares
C. Fuel-Gas Source
III. SYSTEM EFFICIENCIES
A. Steam-Assisted Elevated Flares
B. Enclosed Ground Flares
C. Fuel-Gas Source
IV. DESIGN BASIS
A. Steam-Assisted Elevated Flares
B. Enclosed Ground Flares
C. Fuel-Gas Source
V. COST AND ENERGY IMPACTS
A. Steam-Assisted Elevated Flares
B. Enclosed Gound Flares
C. Fuel-Gas Source
VI. SUMMARY AND CONSLUSIONS
A. Steam-Assisted Elevated Flares
B. Enclosed Ground Flares
C. Fuel-Gas Source
VII. REFERENCES
1-1
II-l
II-l
II-4
II-6
III-l
III-l
III-2
III-3
IV-1
IV-1
IV-9
IV-9
V-l
V-4
V-9
V-9
VI-1
VI-1
VI-1
VI-2
VII-1
APPENDICES OF REPORT 4
A. ELEVATED-FLARE DESIGN EQUATIONS
B. INSTALLED CAPITAL COSTS
C. SAMPLE CALCULATIONS
A-l
B-l
C-l
-------
4-v
TABLES OF REPORT 4
Number
V-l Factors Used for Estimating Total Installed Costs V-2
V-2 Annual Cost Parameters
V-3
-------
4-vii
FIGURES OF REPORT 4
Number
Page
II-l Diagram of Steam-Assisted Smokeless Elevated-Flare System H-2
II-2 Diagram of Enclosed Ground-Flare System H_5
II-3 Diagram of Emission-Fuel-Gas System jj_7
IV-1 Elevated-Flare Capacity IV_2
IV-2 Maximum Steam Availability at Elevated-Flare Tip IV-3
IV-3 Elevated-Flare Height IV_5
IV-4 Natural Gas Required for Elevated Flare Iv_7
IV-5 Gas Transfer-Line and Flame Lengths for Elevated Flare IV-8
IV-6 Pressure Drop of Elevated-Flare System IV-io
IV-7 Ground-Flare Capacity TV-11
IV-8 Ground-Flare Height IV-12
IV-9 Natural Gas Required for Ground Flare IV-13
IV-10 Fuel-Gas Source Transfer-Line Capacity IV-14
V-l Elevated-Flare-System Installed Capital Cost V-5
V-2 Elevated-Flare-System Gross Annual Operating Cost V-6
V-3 Cost Effectiveness of VOC Destroyed by an Elevated-Flare V-7
System
V-4 Energy Effectiveness for VOC Destroyed by an Elevated-Flare V-8
System
V-5 Ground-Flare-System Installed Capital Cost V-10
V-6 Ground-Flare-System Gross Annual Operating Cost V-ll
V-7 Cost Effectiveness of VOC Destroyed by a Ground-Flare System V-12
V-8 Energy Effectiveness for VOC Destroyed by a Ground-Flare V-n
System
V-9 Fuel-Gas-System Installed Capital Cost y-14
V-10 Fuel-Gas-System Gross Annual Operating Cost y-15
V-ll Cost Effectiveness for VOC Destroyed by a Fuel-Gas System V-16
B-l Elevated-Flare-System Installed Capital Cost B-3
B-2 Ground-Flare-System Installed Capital Cost B-4
B-3 Fuel-Gas-System Installed Capital Cost B-5
-------
1-1
I. INTRODUCTION
This control device evaluation deals with volatile organic compound emissions
(VOC) being destroyed by a high-temperature oxidation flame to the normal
combustion products carbon dioxide and water. Three types of systems are
evaluated: an elevated flare, an enclosed ground flare, and using the emissions
as a fuel. To be controlled by these systems the emission must have sufficient
fuel value, or be enriched with auxiliary fuel, for a stable flame to be
maintained. Normal safety precautions for handling combustible gases must be
exercised. If the emission contains constituents such as sulfur and halogen
compounds, they will be oxidized to noxious gases that will be discharged to
the atmosphere.
The elevated flare, which is a single burner tip elevated above ground level
for safety reasons, burns the vented gases in essentially a diffusion flame.
This type of system, especially in the large sizes, can create problems with
luminosity, combustion noise, and heat radiation.
The ground flare is composed of multiple gas burner heads that are grouped in
an enclosure and are staged to operate based on the flow of the vented gas. The
enclosures reduce the luminosity, noise, and radiation problems and allows the
flare to be located at ground elevation.
For the emissions to be used as a fuel the need for it must be established and
transportation from the point of generation to the point of use must be possible.
These restrictions usually limit this control method to emissions that have a
fairly steady generation characteristic.
The three control systems can be used in combinations for improved handling of
emissions, for instance, for a facility that has some steady emissions, has
potential for some fairly frequent intermediate-size emissions, and requires infre-
quent emergency venting. The fuel-gas system could be designed to handle the steady
emissions; emissions in excess of the fuel needed would go to an enclosed
ground flare sized to handle the intermediate-size emissions; then further
excess emissions would go to an elevated flare sized to handle the emergency
-------
1-2
venting. This combined system would maximize energy conservation, burn most of
the emissions in a potentially more efficient and acceptable manner, and yet be
capable of safely handling emergency conditions. Because a combined system is
very site-specific this report treats each control method independently.
-------
II-l
II. SYSTEM DESCRIPTIONS
A. ELEVATED FLARES
There are three general types of elevated flares: those that are nonsmokeless,
those that are smokeless, and those that are fired or endothermic. The first
type, which is the most simple one, is just a flare tip without any special
provision for enhancing the mixing of air into its flame. Its use is limited
essentially to gas streams that burn readily without producing smoke, for
example, streams that contain predominately methane, hydrogen, or carbon mon-
oxide. In the second type, which is the one most widely used and is the most
versatile, an exterior momentum source is used to improve the flame-air mixing
and turbulence. The momentum sources that have been used are steam, water
sprays, high-pressure gas, air blowers, and compressed air. The third type
uses a high-energy-content fuel gas to provide heating value to a lean flare
gas that will not support a stable flame by itself, usually a gas with less
than 115 Btu/ft3 heating value.1 This type of flare has very limited use. It
has been used for disposal of such streams as sulfur tail gases and ammonia
waste gases. Although each flare type may have potential application to a
specific situation in the synthetic organic chemicals manufacturing industry,
this study deals only with the steam-assisted smokeless flare, which has been
reported to account for qreater than 95% of the flares installed.2
Figure II-l is a diagram of a steam-assisted elevated smokeless flare system
showing the usual components that are used. The emission source gas is con-
veyed by a transfer line from the facility release point to the flare location.
The line is equipped for purging so that explosive mixtures do not occur in the
flare system either on startup or during operation. The usual purge gas is
natural gas, although other fuel gases and inert gases such as nitrogen can be
used.
Liquids that may be in the emission source gas or that may condense out in the
collection headers and transfer line are removed by a disentrainment drum
located close to the flare. Liquids in a flare gas can cause smoke to form
because of incomplete burning and if the size of the droplets3 is greater than
*See Sect. VII for the references cited in this report.
-------
P\L.OT
7—Ch
TUBE
IG|U\T\OVJ
Fig. II-l. Diagram of Steam-Assisted Smokeless Elevated-Flare System
-------
II-3
150 pm may generate a spray of burning chemicals that could reach ground level
and present a safety hazard. A water seal is usually located between the dis-
entrainment drum and the flare stack to prevent flashbacks into the system.
Other devices, such as flame arresters and actuated check valves, may sometimes
replace a water seal or be used in conjunction with it.
For safety reasons a stack is used to elevate the flare. The flare must be
located so that it does not present a hazard to surrounding personnel and
facilities; therefore the usual choice is to elevate it. The height is deter-
mined by designing for a maximum ground-level heat radiation and possibly also
for plume dispersion in case of emission ignition failure. A stack seal is
normally used just below the flare tip to impede the incursion of air back into
the flare system, which could create an explosion potential. The use of a seal
reduces the operating purge-gas requirements.
The burner tip is designed to give an environmentally acceptable combustion of
the flare gas over the flare system's capacity range. Consideration is given
to flame stability, ignition reliability, effective assist-steam injection,
and, possibly, noise suppression. The burner tips are normally proprietary in
design. Flame stability can be enhanced by flame holder retention devices
incorporated in the flare tip inner circumference. With burner tips with
modern flame holder designs the flame can be stable over a flare-gas exit
discharge velocity range of 1 to 600 fps.* Reliable ignition is obtained by
continuous pilot burners designed for stablility and positioned around the
outer perimeter of the flare tip. The number of pilot burners required depends
on flare size and, possibly, on flare gas composition and wind conditions. The
pilot burners are ignited by an ignition source system, which can be designed
for either manual or automatic actuation. Effective assist-steam injection to
promote turbulence and mixing of air into the flare gas flame for more effi-
cient combustion and smoke suppressions is generally accomplished by using
high-velocity steam jets positioned around the outer perimeter of the flare
tip. For the larger flares steam can also be injected concentrically into the
flare tip. For some proprietary designs steam injection includes the aspira-
tion of air along with the steam.
-------
II-4
Steam flow can be controlled manually but automatic control, based on flare gas
flow and flame radiation, gives a faster response to the need for steam and a
better adjustment of the quantity required. The physical limitation on the
quantity of steam that can be delivered and injected into the flare flame
determines the smokeless capacity of the flare, which is usually less than its
stable flame capacity. The use of steam injection into a flare flame can
produce other results in addition to air entrainment and turbulence. For
example, the water in the steam can enter into a water/gas reaction with carbon
or into a steam—re-forming reaction with hydrocarbons; either reaction can
reduce smoke formation. Steam can moderate the flame temperature, which could
inhibit flare-gas consituents from participating in cracking reactions that
form carbon and smoke. A detrimental effect of steam usage is that it can
aggravate the flare noise problem by producing high-frequency jet noise and by
increasing the combustion rate. The jet noise can be reduced by the use of
small multiple steam jets and, if necessary, by accoustical shrouding.
B. ENCLOSED GROUND FLARES
An enclosed ground flare has multiple burner heads that are staged to operate
based on the quantity of gas being released to the flare. The size, design,
number, and arrangement of the burner heads depend on the flare-gas characteri-
stics. An exterior motivation source, such as steam or air, to enhance com-
bustion and prevent smoke formation is not required except in rare applica-
tions. Stable combustion can be obtained with some gases that have heat con-
tents as low as 50 to 60 Btu/ft3 (ref 4). Reliable and efficient operation can
be attained from 0 to 100% of capacity.4
Figure 11-2 is a diagram of an enclosed ground flare system with the components
that are normally used. The emission source gas is conveyed from its facility
release point to the flare location by a transfer line. Purge gas probably is
needed only for initial purging of the system on startup. Liquids that may be
in the emission source gas or that may condense out in the collection headers
and transfer line are removed by a disentrainment drum located close to the
flare. If a potential for overloading the ground-flare system exists, the
excess gas may need to be diverted to an elevated flare or other safety precau-
tions taken. A water seal can be located between the disentrainment drum and
the ground flare if the potential exists for flashbacks into the system.
-------
TO ELEVAvTED-
PUR^E
I
I
J.
COUJeCT\OM HEADER
AMD TRANSFER LIME
Y
DRUM
f
WATER
HEAD'S
3ROUUD-
\
PILOT
BuRMeR
^PIUTT
Fig. II-2. Diagram of Enclosed Ground-Flare System
-------
II-6
The number of burner heads and their arrangement into groups for staged opera-
tion depend on the discharge characteristics of the emission source gas. To
ensure reliable ignition, pilot burners with igniters are provided. The burner
heads are enclosed in a shell that is internally insulated and that can be of
several shapes, such as cylindical, hexagonal, or rectangular. The height
must be adequate for creating enough draft to supply sufficient air for smoke-
less combustion of the waste gas and for dispersion of the thermal plume.
Also, dispersion of toxic substances or VOC on flameout can be a problem. The
base of the enclosure is surrounded by an accoustical fence.
C. FUEL-GAS SOURCE
To use an emission as a fuel gas requires that the emission be of fuel quality
and that it be collected from its source and transported to the point of use.
A typical system is shown in Fig. II-3; an actual system may differ signifi-
cantly, depending on site-specific factors. The decision to use an emission as
a fuel gas is normally based on economics. For a system to be economically
viable usually requires that the emission be fairly consistent in flow and
quality and that there be a use for it in a transportable distance. If there is
a potential for overloading the system or if there may not be a use for the
fuel in the quantity generated or when generated, the excess may be diverted to
a ground or elevated flare.
-------
TO EUCLO<5EO
OR EUEVATeD-
<=J>C6>TEM
/
COLUECTIOM
HEADER AMO
DRUM
OR
COMPRESSOR
UKIE TO
'HEADED
H
M
I
Fig. II-3. Diagram of Emission-Fuel-Gas System
-------
III-l
III. SYSTEM EFFICIENCIES
Little information is presently available on the combustion efficiency of
flares. Although some test data are available (and discussed below), the
results are not applicable to the combustion of typical SOCMI off-gas streams
in typical SOCMI flares.
Flare efficiencies of 98% and 99% are used for the purpose of cost-effective-
ness calculations in this report. It should not be assumed that typical SOCMI
flares will obtain efficiencies in this range. Well-designed and well-operated
small flares burning easily combusted gases do obtain high efficiencies but
further work is necessary to determine efficiencies of typical flares in this
industry. The EPA is presently (1981) conducting studies on the efficiencies
obtained by a variety of flares at typical operating conditions.5
A. STEAM-ASSISTED ELEVATED FLARES
An elevated flare without steam assistance would burn as one large diffusion
flame. A diffusion flame is one in which air diffuses across the boundary of
the fuel/combustion product stream toward the center of the fuel flow, forming
an envelope of a combustible gas mixture around a core of fuel gas. This
stream, on ignition, establishes a stable flame zone around a gas core above
the burner tip. This inner gas core is heated by diffusion of hot combustion
products from the flame zone. Cracking can occur with the formation of small
hot particles of carbon that give the flame its characteristic luminosity. If
there is an oxygen deficiency and if the carbon particles are cooled to below
their ignition temperature, they can escape the flame zone as smoke. Also, in
large diffusion flames, combustion product vortices can form around burning
portions of the gas and shut off the supply of oxygen. This localized insta-
bility causes elongations and contractions (flame flickering), which can be
accompanied by soot formation. Steam jets directed into the flame or used to
aspirate air into the flowing gas improve the mixing of air with the fuel and
give the flame some premixed flame character, thereby reducing or eliminating
soot formation.
Sampling a commercial-size flare is very difficult with the methods now avail-
able and results obtained from testing small flares cannot at the present time
-------
III-2
be scaled up for commercial-size flares. Three programs are reported for
testing smaller sized commercial flares.1/6/? In one program flares with
2-in., 3-in., and 6-in. tip sizes were tested;1 results are given for selected
tests with natural gas as the fuel and without the use of assist steam. From
those results the methane hydrocarbon feed destruction efficiency was calcu-
lated to be >90% in only two tests and <70% in four tests. In another program6
the flare tip size was 16 in.; the flare gas was a mercaptan in nitrogen and
assist steam was not used. The efficiencies reported ranged from 92 to >99%.
An extensive flare test program has been conducted in Germany.7 The flare tip
was a truncated cone 20 cm (7.9 in.) at the flare-gas entrance, 50 cm
(19.7 in.) long, and 70 cm (27.6 in.) at the exit. The cone was fitted with
six steam nozzles that aspirated air into the flaming gas before it exited the
cone. The operating parameters used were the following: flare gas flow, 0.13
to 2.9 mt/hr; gas composition density, 0.54 to 1.86 kg/m3,- steam-to-gas weight
ratio, 0 to 1.73; and cross wind, 0 to 6 m/s. The gases combusted had a high
proportion of hydrogen and a low proportion of unsaturated hydrocarbons.
Typically the hydrogen concentration was greater than 50%. Of 1298 measure-
ments at the flame end and downstream from the flame end for the complete range
of test conditions, in only 4 measurements were the local burnouts to carbon
dioxide less than 99%.
The efficiencies used for cost-effectiveness calculations in this report are
99% for flares to 12 in. in diameter and 98% for flares over 12 in. in diam-
eter .
B. ENCLOSED GROUND FLARES
An enclosed ground flare burns with multiple small diffusion flames from burner
heads that can be stage-operated based on flare gas flow and that are enclosed
on the sides. An enclosed ground flare has the control capabilities to maxi-
mize combustion efficiency for most operating conditions. The burner heads can
be sized and designed for the materials in the flare gas; they can be stage-
operated to give a turndown from 100 to 0%« of design; and the enclosure design
allows for a degree of combustion air and temperature control.
-------
III-3
Although the design of an enclosed ground flare would allow the combustion
gases to be monitored to determine combustion efficiency, there are no reported
test programs on commercial-sized units. One reference1 cites that a perfor-
mance estimate was made for an open-flare flame.
The efficiency used in this report for cost-effectiveness calculations is 99%.
C. FUEL-GAS SOURCE
When an emission is used as a fuel gas, the VOC destruction efficiency depends
on the waste gas composition and on the combustion conditions. The efficiency
used in this report for cost-effectiveness calculations is >99.9%. According
to the emission factors given in AP-428 for natural gas and LPG when burned
under proper operating conditions, this efficiency is attained. This combus-
tion efficiency does not apply to dilute VOC streams introduced into a combus-
tion device in any way other than as a fuel gas.
-------
IV-1
IV. DESIGN BASIS
The capital and operating costs developed for this study are based on model
designs discussed in this section. The three control systems, steam-assisted
elevated flares, enclosed ground flares, and emissions used as a fuel source,
are evaluated independently. For all systems a model-waste-gas emission was
used that had properties equivalent to those of propylene. The standard con-
struction material is carbon steel except where it is standard practice to use
other materials, such as burner tips.
A. STEAM-ASSISTED ELEVATED FLARES
1. Flare-Tip Capacity
The maximum and minimum capacity of a flare tip to burn a flared gas with a
stable flame (not necessarily smokeless) is a function of tip design. At too
high an exit velocity the flame can lift off the tip and flame out, while at
too low a velocity it can burn back into the tip or lick down the sides of the
stack. Modern commercial flares with flame retention rings are reported to
have stable flame capabilities over flare-gas discharge velocities of 1 to 600
fps.1 The actual maximum capacity of a flare tip is usually limited by the
flare-gas pressure available to overcome the system pressure drop. For the
purpose of determining flare heights the practical capacity in this study was
assumed to be the model-waste-gas flow at ambient conditions, which results in
a flare-tip pressure drop of 18 in. H20. For the larger flare-tip sizes these
conditions would result in a discharge velocity of about 200 fps. Flare capa-
city based on the correlations in ref 9 (see Appendix A) is plotted in
Fig. IV-1.
The capacity of a steam-assisted flare to burn smokelessly is limited by the
quantity of steam that is available. There is a physical limit to the quantity
of steam that can be effectively delivered to a flare tip. Figure IV-2 is a
smoothed curve of the quantity that can be delivered based on a practical
design of steam piping on the flare and on 150-lb steam pressure being avail-
able to the flare site.10 Another steam limit could be the availability of
steam-generation capacity. In this study it was assumed that steam would be
available to the flare site, on demand when needed.
-------
IV-2
1,000,000rr
to 100,000
(0
o
V)
(0
T3
O
5
(0
~ 10,000 —
o
CO
a
(0
O
to
u.
1000
Based on correla-
tions in ref 9;
see Appendix A.
Based on the steam
availability of
Fig. IV-2 and on 0.3 Ib
of steam per Ib of flare
gas for flare tips 24-in.
and smaller and 0.45 Ib
of steam per Ib of flare
gas for larger flare tip
sizes.
1
10
60
Flare-Tip Diameter (in.)
Fig. IV-1. Elevated-Flare Capacity
-------
IV-3
200,000
100,000 —
1000
Flare-Tip Diameter (in
Fig. IV-2. Maximum Steam Availability at
Elevated-Flare Tip
-------
IV-4
The steam requirement per quantity of flare gas depends on the composition of
the gas flared and on the flare-tip design. Typical values range from 0.15 to
0.50 Ib of steam per pound of flare gas.11 Olefins, such as propylene, re-
quire higher steam ratios than would a paraffin hydrocarbon to burn smokeless-
ly. A flare with a small-diameter tip can use steam more efficiently than a
large-diameter tip to mix air into the flame and promote turbulence. The
ratios of steam to model waste gas used in this study, which are based on
experience,10 are 0.3 Ib per pound of flare gas for flare tips to 24 in. in
diameter and 0.45 Ib/lb for larger flares. The design also assumes instrument
control of steam flow for optimum usage. Smokeless flare capacity based on
those ratios and on the steam availability shown in Fig. IV-2 is plotted in
Fig. IV-1.
2. Flare Height
The flare-height design is usually a function of maximum ground-level heat-
radiation intensity. This study is based on the assumptions of a ground-level
radiation of 1500 Btu/(hr)(ft2), which is the maximum allowed for short-term
personnel exposure, and of a sunny-condition solar radiation of 300 Btu/(hr)
(ft2).3 The difference, 1200 Btu/(hr)(ft2), is the maximum design radiation
from the flare flame. Figure IV-3 is a plot of the total flare heights used
and is based on the equations given in ref 12 (see Appendix A). It is further
assumed for cost estimating purposes that as a minimum a 40-ft flare height is
required. (The minimum height requirement can be very site specific,- one
company reports that they use 150 ft as a minimum standard.)13
Flare height may sometimes be determined by the need to safely disperse the
flared gas in case of flame out. The height in these cases would be based on
dispersion modeling for the particular installation conditions.
3. Purge-Gas Requirements
The minimum continuous purge gas required is determined by the design of the
stack seals, which are usually proprietary devices. An older reference14
reports that the gas velocity required is 0.10 to 0.15 fps; modern seals are
stated to require less. This study is based on a flow of 0.03 fps,10 which is
stated to be adequate for normal applications without any type of conservation
Use of various purge-gas conservation systems can reduce this consumption.
15
-------
Flare Height (ft)
o
o
o
o
o
1—TTT
W
M
to
(0
o.
R
ff
H-
t
o
i
•5
o
OJ'
3
(D
F*
O
H
Ul
0>
o
-------
IV-6
The purge gas is assumed to be a constant flow of natural gas at 60°F and
1 atm. Figure IV-4 shows a plot of these requirements. Purge gas also may be
needed to purge the system before startup and to prevent a vacuum from sucking
air back into the system after a hot gas discharge is flared. These uses are
assumed to be minor.
4. Pilot-Gas Requirements
Pilot-gas usage is a function of the number of pilot units required to ensure
positive ignition of the flared gas, of the design of the pilots, and of the
mode of operation. This study is based on the practice of one vendor for a
certain number of pilots versus the flare size, the pilot size, and the use of
a wind speed and direction controller to operate the pilots for gas conserva-
tion.16 The average pilot-gas consumption under these conditions for all flare
sizes is 60 scfh. Figure IV-4 is a plot of these requirements, as well as of
the gas requirement without gas conservation control.
5. Gas Transfer Lines
The gas collection header and transfer-line requirements are very site specific
and depend on the process facility where the emission is generated and on where
the flare is located. For the purposes of estimating capital cost and system
pressure drop it was assumed that the gas transfer line would be the same size
as the flare tip and that the total length would be 3 times the calculated
flame length at 18 in. H20 flare-tip pressure-drop capacity, but with a 100-ft
minimum. Figure IV-5 is a plot of the gas transfer-line length used and the
calculated flame length (see Appendix A for flame-length calculation equation).
6. System Pressure Drop
The total system pressure drop is a function of the design of the various
system components and the flare-gas flow. The following pressure-drop relation-
ships are assumed-.10'16
Flare tip, calculated (see Appendix A)
Stack seal, 1.5 times flare-tip AP
Stack
Water seal
0.5 times flare-tip
Disentrainment drum
Transfer line, calculated based on diameter, length, and gas flow
-------
IV-7
2000
1000 —
o
(0
•o
0)
v_
'5
cr
(0
O
I
15
*.
3
100
10
Pilot Gas
Conservation Control
Pilot Gas with
Conservation
Control
10
6O
Flare-Tip Diameter (in.)
Fig. IV-4. Natural Gas Required for Elevated Flare
-------
Transfer-Line and Flame Lengths (ft)
H-
H
un
o
&
in
H 3
^ &>
i' ?
I i1
2 2
§ 0)
» 3
H O
Q ^**
3 <0
(fl —
3
M
M
(D
(D
O-
o
o
o>
o
o
o
H
03
-------
IV-9
Figure IV-6 is a plot of system pressure drops for operation at smokeless
capacity and at 18 in. H20 flare-tip pressure-drop capacity. For this study it
was assumed that the process emissions would have sufficient pressure to over-
come the system pressure drop.
B. ENCLOSED GROUND FLARES
An enclosed ground flare consists of burner heads designed for the flare-gas
properties in sufficient number to handle the maximum design flow and staged to
operate based on the flare-gas flow rate. The enclosure is of sufficient cross
section for the maximum heat release and is high enough to shield the illumina-
tion and radiation from the flame and to adequately disperse the heat plume.
Figures IV-7, 8 and 9, based on information from a vendor for an enclosed
circular type of ground flare,16 give the capacity, height, and pilot-gas
requirements used in this study. It was assumed for estimating costs that the
flare would be located in the area where the emission is generated and that the
waste gas emission transfer-line requirement would be minimal. The location of
the flare can be very site specific and the cost in some cases can be signifi-
cant, especially in retrofit situations. It is estimated that 1-psig maximum
gas pressure will be adequate to activate the burner head staging controls and
to assure proper burner operation. It was also assumed that the process emis-
sion would have sufficient pressure to overcome the system pressure drop.
If the potential emission rate to the enclosed ground flare can overload the
flare, it should have overfire protection and probably should be associated
with an elevated flare or some other safety precaution to take care of the
overload.
C. FUEL-GAS SOURCE
The design of a system to use an emission as a fuel-gas source is site specif-
ic. For the purposes of estimating capital and operating costs the following
assumptions were made for this study: The compressor is located in the area
where the emission is generated and the gas collection line required is mini-
mal, the compression ratio is from 0 to 30 psig, the high-pressure transfer
line is 500 ft, and the system capacity is the model-waste-gas flow that gives
0.5-psi pressure drop per 100 ft of the high-pressure line. Figure IV-10 is a
plot of the transfer-line fuel-gas capacity.
-------
IV-10
300
100
O
CM
X
a
o
&_
a
V)
V)
o
E
-------
IV-11
100,000
400
10 40
Flare Enclosure Diameter (ft J
Fig. IV-7. Ground-Flare Capacity
-------
IV-12
-^100
.E
CD
'o
I
C)
=5
0)
^
u
C
ui
0)
k.
12
u.
10
10
Flare Enclosure Diameter (ft)
Fig. IV-8. Ground-Flare Height
50
-------
IV-13
300
x:
•*-
o
O
3 100
en
OJ
O
i_
o
c
CO
jD
a
10
1 10
Flare Enclosure Diameter (ft)
Fig. IV- 9. Natural Gas Required for Ground Flare
50
-------
IV-14
20,000
10,000 —
OT
O
*<•
re
£
_ 1000 -
Q>
•o
O
(0
re
o
-------
IV-15
If the potential emission rate to the fuel-gas source can overload the compres-
sor or if there is not a reliable use for the emission, then an associated
flare system or some other method probably should be provided to handle the
emission during these periods.
-------
V-l
V. COST AND ENERGY IMPACTS
The capital and operating costs and the energy impacts in this section are
based on the model designs discussed in Sect. IV and on a model waste gas with
properties similar to those of propylene as the emission. Each control sys-
tem—steam-assisted elevated flares, enclosed ground flares, and use of the
emission as a fuel source—is evaluated independently. To aid in adjusting the
costs presented in this section to other situations that may vary considerably
from the model conditions assumed, the installed capital costs of each system
are presented based on the physical sizes shown in Appendix B.
The estimated capital costs represent the total investment, including all
indirect costs such as engineering and contractors' fees and overheads that
will be required for purchase and installation of all equipment and material to
provide a facility as described. These are battery-limit costs and do not
inlcude 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. These costs are based on a new-plant
installation; no retrofit cost considerations are included. Those costs are
usually higher than the cost for a new-site installation for the same system
and include, for example, demolition, crowded construction working conditions,
scheduling construction activities with production activities, and longer
interconnecting piping. These factors are so site specific that no attempt has
been made to provide costs. For specific retrofit cases, rough costs can be
obtained by using the new-site data and adding as required for a defined speci-
fic retrofit situation.
The method used to develop these estimated capital costs was based on prelim-
inary vendor quotes for the purchase and installation of major equipment items
or from such sources as Richardson Engineering Co. data and factoring up to
total installed costs based on the factors in Table V-l. The expected accuracy
of the total installed cost with this degree of engineering detail using these
methods is ±30%. These methods of obtaining estimated total installed capital
costs are suitable for a cost study or for screening estimates. The bases used
in calculating annual operating costs are given in Table V-2.
-------
V-2
Table V-l. Factors Used for Estimating Total Installed Costs
A = Major equipment purchase cost plus 0
Installation costs
Foundations
Structures
Equipment erection
Piping
Insulation
Paint
Fire protection
Instruments
Electrical
.1 to 0.35 allowance
0.06A + $100 X number of pumps
0.15A (no structures) to 0.30A (multideck
structures)
0.15A to 0.30A (depending on complexity)
0.40A (package units) to 1.10A (rat's
nest)
0.06A or 0.15 X piping (normal) to 0.30 X
piping (bulk hot or cold)
0.05A
0.01A to 0.06A (depending on requirements
0.10A to 0.30A or 0.01A to 0.25A +
$50,000 to $300,000 for process control
computer
0.15A or 0.05A + $500 per motor
B = Base cost
Sales tax
Freight
Contractor's fees
A + sum of installation costs
0.25A + 0.025B
0.16A
0.30 (B-A)
C = Total contract
a
Engineering
. b
Contingencies
B + taxes, freight, and fees
0.01C to 0.20C
0.15C
D = Process unit installed cost
C + engineering + contingencies
E = Total subestimates
F = Total project cost
a
Sum of semidetailed subestimates (build-
ings, site development, cooling towers,
etc.); each subestimate should include
taxes, freight, fees, engineering, and
contingency, and should be escalated
to date of expenditure for that cost
component; engineering costs, conting-
encies, and escalation factors for thes
subestimates will vary according to the
type of job involved
D + E
includes cost from capital project teams, process engineering, engineering, purchasing,
and other support groups.
"contingency should not be applied to any cost component that has been committed by eith,
purchase order or contract.
-------
V-3
Table V-2. Annual Cost Parameters
Operating factor 8760 hr/yr3
Operating labor Negligible
Fixed costs
Maintenance labor plus
materials, 6%
Capital recovery, 18%
Taxes, insurances,
b
29% of installed
capital cost
administration charges, 5%
Utilities
Electric power $0.03/kWh
steam $2.50/thousand Ib
Natural gas $2.00/thousand ft3
Heat recovery credits $2.00/million Btu
(equivalent to natural gas)
Control devices will usually be available for operation on the same cycle as
the process. Process downtime is normally expected to range from 5 to 15%.
From the standpoint of cost-effectiveness calculations the error introduced
by assuming continuous availability is minor. The percent of capacity opera-
tion that the control device is utilized will be discussed as a variable in
this section.
b
Based on 10-year life and 12% interest.
-------
V-4
A. STEAM-ASSISTED ELEVATED FLARES
The installed capital costs, annual operating costs, cost-effectiveness, and
energy-effectiveness curves for the model systems based on the model waste gas
as the VOC emissions are shown in Figs. V-l to V-4 respectively. For installed
capital costs based on flare size see Appendix B.
The annual operating cost will vary with the capacity of operation because
steam assistance is used only during the time that flaring takes place. Nor-
mally an elevated flare will operate for only a very small percentage of the
time; even so, steam costs can be an important factor. In this study it was
assumed that 150-psig steam is available to the flare on demand at a nominal
cost of $2.50 per thousand pounds.
The cost effectiveness and energy effectiveness of elevated flares are sensi-
tive to the capacity of operation in the low ranges of operation that are
normal. One-tenth percent of annual capacity operation is equal to about 9 hr
per year of flaring at smokeless capacity, or 18 hr at half capacity. Natural
gas used for purge gas and for the pilots and steam used for injection at the
flare tip are the sources of energy consumption. It was assumed that modern
flare-tip seal designs would be used to minimize the need for purge gas and
that instrumentation would be used to reduce pilot-gas consumption. The devia-
tion in cost and energy effectiveness shown on Fig. V-3 and V-4 at the larger
capacities results from a higher ratio of steam to model waste gas being used
for flares larger than 24-inch tip diameter and from the fact that purge gas
consumption increases as the cross section of the flare while the smokeless
capacity proportionately decreases because of steam availability. This effect
is more pronounced for the lower percent of annual capacity operation and for
the energy effectiveness ratio.
The cost and energy effectiveness presented here is based on the flare being
used for pollution control. This must be evaluated with caution in many actual
situations since elevated flares are frequently designed and installed as
safety devices.
-------
1000
O)
O)
r*
b»
O
e
4)
O
u
o
O
-------
700i
Percent of Annual Capacity
o
o
o
in
O
O
O)
c
'•M
(0
h.
«
a
O
c
-------
.24
.22 -
.20
.18
.16
.12
.10
o
£ -08
UJ
w .06
o
O
.04
_ .02
0)
o
I -O:
ra
(0
- 0.5
Percentage of Annual Capacity
f
10 100 400
Elevated-Flare Smokeless Capacity as Model Waste Gas (1000 Ib/hr)
Fig. V-3. Cost Effectiveness of VOC Destroyed by an Elevated-Flare System
-------
Energy Effectiveness (lOOO Btu consumed/lb of VOC)
_k _i ->•
(D
Mi
(D
o
ft
(D
cn
O
O
(D
W
rt
g
M
M
(D
<
£
(D
&
TJ
M
P
n
(D
cn
^<
w
H-
CD
8-A
-------
V-9
B. ENCLOSED GROUND FLARES
The installed capital costs, annual operating costs, cost-effectiveness, and
energy-effectiveness curves for the model systems based on the model waste gas
as the VOC emission are plotted in Figs. V-5 to V-8 respectively. For
installed capital costs based on flare size see Appendix B.
The cost effectiveness and energy effectiveness of ground flares are sensitive
to the capacity of operation in the low ranges of operation that are probable.
A 0.25% of annual capacity operation is equal to about 22 hr per year of
flaring at capacity, or 44 hr at half capacity. The discontinuities in the
energy-effectiveness curves reflect the need for additional pilot burners as
the flare increases in size.
C. FUEL-GAS SOURCE
The installed capital cost, annual operating costs, and cost-effectiveness
curves for the model systems based on the model waste gas are shown in
Figs. V-9 to V-ll respectively. For installed capital costs based on the
fuel-gas-line size see Appendix B.
The costs associated with the use of VOC emission as a fuel gas are very site
specific. The costs presented here are valid only for the models described but
are descriptions of what may be expected. There is a cost-effectiveness sav-
ings, except for low-capacity operation, when the VOC emission is credited at a
fuel-gas value equivalent to $0.0392 per pound of model waste gas ($2.00/mil-
lion Btu). Use of VOC as a fuel may be an attractive disposal method but only
if the emission meets the requirements of being satisfactory for use as a fuel,
is reasonably consistent in generation, and there is an adequate use for it at
a reasonable distance.
Using a VOC emission as a fuel can be very energy effective. For the model
system about 40 Btu of electrical energy is consumed per pound of model waste
gas compressed, whereas the net heat of combustion for the model waste gas is
19,600 Btu/lb.
-------
1000
I I II 111
I
I—'
o
100
Ground-Flare Capacity as Model Waste Gas (1000 Ib/hr)
Fig. V-5. Ground-Flare-System Installed Capital Cost
-------
300
§ 10°
V)
o
O
o>
c
y
(0
w
o>
a
O
75
3
C
C
(0
O
O
10
1
J I L
0.4 1 10
Ground-Flare Capacity as Model Waste Gas (1000 Ib/hr)
100
Fig. V-6. Ground-Flare-System Gross Annual Operating Cost
-------
Percent of Annual Capacity
to
100
Ground-Flare Capacity as Model Waste Gas (lOOOIb/hr)
Fig. V-7. Cost Effectiveness of VOC Destroyed by a Ground-Flare System
-------
Percent of Annual Capacity
1 10
Ground-Flare Capacity as Model Waste Gas (1000 Ib/hr)
100
Fig. V-8. Energy Effectiveness for VOC Destroyed by a Ground-Flare System
-------
400
o
0)
.0
e
o
u
0)
O
o
O
V)
o
o
15
*^
'5.
03
O
4->
V)
c
100
100
1000 10,000 20,000
Fuel-Gas-System Capacity as Model Waste Gas (ib/hr)
Fig. V-9. Fuel-Gas-System Installed Capital Cost
-------
200
o
o
o
V)
o
O
Cf)
c
'•4-1
a
w
o
a
O
15
3
C
C
V)
v>
o
w
O
Percent of Annual Capacity
100
10
100
1000 10,000
Fuel-Gas-System Capacity as Model Waste Gas (ib/hr)
U1
30,000
Fig. V-10. Fuel-Gas-System Gross Annual Operating Cost
-------
V)
(0
d)
c
0)
O
0)
| .02
09
.04
.06L_
100
Percent of Annual Capacity
1
1,000 10,000
Fuel-Gas-System Capacity as Model Waste Gas (lb/hr)
f
M
CJ1
20,000
Fig. V-ll. Cost Effectiveness for VOC Destroyed by a Fuel-Gas System
-------
VI-1
VI. SUMMARY AND CONCLUSIONS
The emission control methods of burning VOC emissions in an elevated flare, in
a ground flare, or using it as a fuel have been evaluated in this study.
Flares frequently are installed primarily for the purpose of safety. Each
control method has its advantages and its limitations and could, for appro-
priate emission sources, be installed in an integrated system. Such integrated
systems would be very site specific and are beyond the scope of this study.
A. STEAM-ASSISTED ELEVATED FLARES
1. Steam-assisted elevated flares can be designed for large capacities and
can take overloads, but the smokeless capacity is usually limited to the
amount of steam available.
2. Operation can be highly transitory.
3. The data on VOC destruction efficiency are limited. This study for cost-
effectiveness presentation purposes only is based on an efficiency of 99%
for flare tips under 12-in. diameter and 98% for those over 12-in. diameter.
The EPA is conducting further testing.
4. An elevated flare must be ready for use at any time that there is poten-
tial for emissions, but it may be actually flaring for a very small per-
cent of the time. Under these circumstances the energy consumption per
quantity of VOC destroyed could be high.
B. ENCLOSED GROUND FLARES
1. Enclosed ground flares can be designed for a wide capacity range but may
need overload protection if potential for overloading exists.
2. Operation can be highly transitory, but 100 to 0% of capacity turndown
exists.
3. VOC destruction efficiency data are not available; a 99% destruction was
used to calculate cost effectiveness.
4. When a ground flare is used to burn emissions for only a small percent of
its available time, the energy consumption per quantity of VOC destroyed
can be high. The energy use can be comparable to that of an elevated
flare that is designed and operated to minimize natural-gas consumption.
-------
VI-2
C FUEL-GAS SOURCE
1 Using VOC emission as a fuel can give a cost-effectiveness savings pro-
vided that the emission is of fuel quality, is produced in a reasonably
consistent volume, and there is an adequate use for it.
2 The VOC destruction efficiency used for cost-effectiveness calculations
was >99 9% According to emission factors given in AP-42 for natural gas
and LPG when burned under proper operating conditions, this efficiency xs
attained.
-------
VI I-1
VII. REFERENCES*
1. John F. Straitz, III, National Air Oil Burner Company, Inc., Flaring for
Gaseous Control in The Petroleum Industry, reprint of paper presented at the
Annual Meeting of the Air Pollution Control Association, June 20, 1978, Austin,
Texas.
2. M. G. Klett, Lockheed Missiles and Space Company, Report on a Trip to the John
Zink Company to Discuss EPA Tank 3, Flare Systems Study, Feb. 19, 1974.
3. John F. Straitz, III, National Air Oil Burner Company, Inc., and Ricardo J.
Altube, Tecna Estudios Y Proyectos, Flares; Design and Operation (in-house
brochure).
4. NAO Ground Flares, Bulletin 36 (in-house brochure). National Air Oil Burner
Company, Inc. Philadelphia, PA.
5. EPA Contract No. 68-02-3661 with Energy and Environmental Research Corpora-
tion, Santa Ana, CA.
6. William R. Chalker, E. I. du Pont de Nemours and Company, letter dated May 16,
1979, to Donald R. Goodwin, Emission Standards and Engineering Division, EPA.
7. K. D. Siegel, Degree of Conversion of Flare Gas in Refinery High Flares.
Pollutant Emission from Refinery High Flares as a Function of Their Operating
Conditions, dissertation for the degree of Ph.D in Engineering Science at the
Chemical Engineering Department of the University in Karlsruhe, West Germany,
February 1980.
8. T. Lahre, "Natural Gas Combustion," p 1.4-2, and "Liquified Petroleum Gas
Combustion," p 1.5-2 in Compilation of Air Pollutant Emission Factors, AP-42,
Part A, 3d ed. (August 1977).
9. John F- Straitz, III, "Nomogram Determines Proper Flare-Tip Diameter," Oil, Gas
and Petroleum Equipment (July 1979).
10. Personal communication Feb. 25, 1980, between John F. Straitz, III, National
Air Oil Burner Company, Inc., and V. Kalcevic, IT Enviroscience.
11. John F. Straitz, III, "Flaring for Safety and Environmental Protection,"
Drilling-DCW (November 1977).
12. John F. Straitz, III, "Nomogram Determines Proper Flare-Stack Height," Oil,
Gas and Petrochem Equipment (August 1977).
13. R. L. Foster, Union Carbide Corporation, letter dated Dec. 19, 1980, to EPA
transmitting CMA comments on draft report.
-------
VII-2
14. Robert D. Reed, "Design and Operation of Flare Systems," Chemical Engineering
Progress (June 1968).
15. John F. Straitz, III, National Air Oil Burner Company, Inc., letter dated
Oct 21 1980 to EPA with comments on draft report.
16. John F.'straiiz, III, Combustion Unlimited, Inc., letter dated June 5, 1980, to
V. Kalcevic, IT Enviroscience, Inc.
When, however, an additional reference *' ™^;£*/££°«nCe number
of the paragraph or captioned material, tne
apply to that particular portion.
-------
APPENDIX A
ELEVATED-FLARE DESIGN EQUATIONS
-------
A-3
A. FLARE CAPACITIES AND PRESSURE DROPS
Flare capacities and pressure drops used in this report are based on the
following relationship.-9
2.72 X 10"3 (F)
v '
46°
MW
D =
where
D = flare-tip diameter, in.,
F = flare gas flow rate, Ib/hr,
T = temperature, °F (assumed to be 60°F),
MW = molecular weight (propylene, 42),
Ap = flare-tip pressure drop, in. H20.
B. FLARE HEIGHTS
The flare heights used in this report are based on the following relationship:12
F X LHV X £ l/Ap
12.56 I " 3'33 D } 55 cos 0
where
1.47 V
0 = tan"1 w
550
in which Vw = wind velocity, mph (assumed to be 60),
H = flare height, ft,
F = flare gas flow rate, Ib/hr,
LHV = flare gas lower heating value, Btu/lb (propylene, 19,600).
£ = flame emissivity (propylene, 0.13),
I = flame radiation intensity, Btu/(hr)(ft2) (assumed to be 1200),
D = flare-tip diameter, in.,
Ap = flare-tip pressure drop, in. H20.
*See Sect. VII for references.
-------
A-4
C. FLAME LENGTHS
The flame lengths used in this report to determine the gas transfer-line
lengths are based on the following relationship:3
Lf = 10 X D X
where
Lf = flame length, ft,
D = flare-tip diameter, in.,
Ap = flare-tip pressure drop, in. H20 (assumed to be 18).
-------
APPENDIX B
INSTALLED CAPITAL COSTS
-------
B-3
1000
0)
O)
T—
l_
fl>
E
Q)
o 100
O
o
O
O
a
CO
O
ra
CO
c
10
10
60
Flare-Tip Diameter (in.)
Fig. B-l. Elevated-Flare-System Installed Capital Cost
-------
B-4
tf>
o
o
"co
'5.
(0
o
•o
—
"a
*->
v>
c
1000
in
a>
£ S
•O O
c •*"
3
2 5
o .Q
H- E
O 0)
^ o
Q>
o
100
o
o
o
10
1
10
50
Flare Enclosure Diameter (ft)
Fig. B-2. Ground-Flare-System Installed Capital Cost
-------
B-5
o
1000
£
o
o
o
O
O
^ 100
•4->
w
o
O
a
a
O
ca
*-
-------
APPENDIX C
SAMPLE CALCULATIONS
D108E
-------
C-3
COST AND ENERGY SAMPLE CALCULATIONS
This report is based on using a model waste gas with properties similar to
those of propylene as the VOC emissions. The curves presented can be used in
most cases for other VOC emissions with results probably within the accuracy of
the curves developed. For emissions that have a character significantly
different from the model ones it may be advisable to review the design bases
discussed in Sect. IV and then use the installed capital costs given in
Appendix B.
A. STEAM-ASSISTED ELEVATED FLARES
This example is based on a 23,000-lb/hr maximum model-waste-gas VOC emission
rate.
1. Installed Capital Cost Versus Flare Capacity (Fig. V-l)
a. From Fig. IV-1, a 10-in. tip diameter flare is required.
b. From Fig. B-l, the installed capital cost for a 10-in. flare is $105,000.
2. Gross Annual Operating Cost (Fig. V-2)
a. From Table V-2 the fixed cost, including capital recovery, is 29% of the
installed capital cost:
105,000 X 0.29 = $30,450/yr.
b. From Fig. IV-4 the natural gas used for the pilots is 60 scfh and for
purging it is 60 scfh. From Table V-2 the cost for gas is $2.00 per
thousand ft3:
(60 + 60) X 8760 X ~ = $2100/yr.
c. From Sect. IV-A-1 of the report 0.3 Ib of steam is required per pound of
VOC; from Table V-2 the cost for steam is $2 . 50/thousand Ib:
-------
C-4
2 50
0.3 X 23,000 X 8760 X ' X fraction of annual capacity operation
= 151,000 X fraction of annual capacity operation.
d. Annual cost summary
Fixed
Gas
Steam
Total
Cost per Capacity Operation of
100% 1% 0%
$ 30,450 $30,450 $30,450
2,100 2,100 2,100
151,100 1,510
$183,650 $34,060 $32,550
3. Cost Effectiveness (Fig. V-3)
Cost effectiveness is the gross annual operating cost (A-2-d above) divided by
the annual waste-gas VOC destroyed at 99% efficiency.
a. Annual VOC destroyed = 23,000 X 8760 X 0.99 X annual fraction of
capacity operation.
b. Example at 1% of annual capacity operation is
34,060
23,000 X 8760 X 0.99 X 0.01
= $0.017/lb of VOC destroyed.
4. Energy Effectiveness (Fig. V-4)
Energy effectiveness is the energy consumed in the gas pilots, the purging gas,
and the steam-assist gas divided by the annual waste-gas VOC destroyed at 99%,
or 98% efficiency.
a. From A-2-b, natural gas consumed is 120 scfh, at 1000 Btu/ft3 =
120,000 Btu/hr.
b. From A-3-c, steam consumed is 0.3 Ib/lb of waste-gas VOC, at 1000 Btu/lb
of steam; this results in 300 Btu/lb of waste-gas VOC.
-------
C-5
c. Example at 1% of annual capacity operation:
/ 120,000 X 8760 \ l
^23,000 X 8760 X 0.01 + ) X o799 ~ 83° Btu/lb of Voc destroyed.
B. ENCLOSED GROUND FLARES
This example is based on 20,000-lb/hr maximum waste-gas VOC emission rate.
1. Installed Capital Cost Versus Flare Capacity (Fig. V-5)
a. From Fig. IV-7 a 15-ft-diam enclosure flare is required.
b. From Fig. B-2 a 15-ft enclosed ground flare installed capital cost is
$248,000.
2. Gross Annual Operating Cost (Fig. V-6)
a. From Table V-2 the fixed cost is 29% of the installed cost:
248,000 X 0.29 = $71,900/yr.
b. From Fig. IV-9 the natural gas used for the pilots is 100 scfh. From
Table V-2 the cost for gas is $2.00/thousand ft3:
100 X 8760 X —— = $1750/yr.
c. Total Cost
Fixed $71,900
Gas 1,750
$73,650
3. Cost Effectiveness (Fig. V-7)
Cost effectiveness is the gross annual operating cost (B-2-c) divided by the
annual waste-gas VOC destroyed at 99% efficiency.
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06
a. Annual VOC destroyed = 20,000 X 8760 X 0.99 X annual fraction of
capacity operation.
b. Example at 1% of annual capacity operation:
73'650 = $0.042/lb of VOC destroyed.
20,000 X 8760 X 0.99 X 0.01 9 '
4. Energy Effectiveness (Fig. V-8)
Energy effectiveness is the energy consumed for the pilots divided by the
annual waste-gas VOC destroyed at 99% efficiency.
a. From B-2-b, natural gas consumed is 100 scfh; at 1000 Btu/ft3 amounts to
100,000 Btu/hr.
b. Example at 1% of annual capacity operation:
100>000 X 8760 = 5Q5 Btu/lb of voc destroyed'
20,000 X 8760 X 0.99 X 0.01
C. FUEL-GAS SOURCE
This example is based on 850-lb/hr maximum waste-gas VOC emission rate.
1. Installed Capital Cost Versus Flare Capacity (Fig. V-9)
a. Figure IV-10 shows that a 2-in. fuel-gas transfer line is required.
b. Figure B-3 indicates that a 2-in. line installed capital cost is $65,000.
2. Annual Operating Costs
a. From Table V-2 the fixed cost is 29% of the installed cost:
65,000 X 0.29 = $18,850/yr.
b. The electrical power consumption for compressing the gas must be calcu-
lated. For the model system of compressing from atmospheric pressure to
30 psig the adiabatic horsepower required was calculated to be 9.65
-------
C-7
(Eq. 6-23 on page 6-16 of Perry's Chemical Engineers Handbook, 5th ed. ,
McGraw-Hill, was used). Assuming an 85% electric motor efficiency and an
85% compressor efficiency and converting horsepower to kilowatts (1 hp =
0.746 kW), the electric power consumption rate is
X °-746 = 9'96
' 5 5
From Table V-2 the electrical cost is $0.03/kWh. For a 60% of annual
capacity operation example the cost is
9.96 X 8760 X 0.03 X 0.60 = $1570/yr.
c. From Table V-2 the fuel credit is $2.00/million Btu. For waste gas with a
net heating value of 19,600 Btu/lb this is equal to a credit of $0.0392/lb
of waste gas. For the example of 60% of annual capacity operation the
credit is
850 X 8760 X 0.6 X 0.0392 = $175,130/yr.
d. Annual cost summary
Fixed $18,850
Electrical 1,570
Gross (Fig. V-10) 20,420
Credit (175,130)
Met (154,710) Savings
3. Cost Effectiveness (Fig. V-ll)
Cost effectiveness is the net annual operating cost (C-2-d) divided by the
annual waste-gas VOC destroyed at 99.9% efficiency.
a. Annual VOC destroyed = 850 X 8760 X 0.999 X annual fraction of capacity
operation.
-------
C-8
b. Example at 60% of annual capacity operation:
850 X 87io5x'o!999 X 0.60 = <*>-°346)/lb of VOC destroyed savings
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£-ORT N'O
EPA-450/3-80-026
IP} n, ,TECHNICAI- REPORT DAT A
(Pkasc read Inaction: on rhf reverse before complcnn^
[3. RECIPIENT'S ACCESSION NO?
i ~E AMD SUBTITLE
Organic Chemical Manufacturing
Volume 4: Combustion Control Devices
ORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO
AUTHOR(S)
J. W. Blackburn
H. S. Basdekis
-.j NAME AND ADDRESS
—->, Inc.
9041 Executive Park Drive
Suite 226
Knoxville, Tennessee 37923
J. A. Key
v. Kalcevic
and Standards
• ,- „ . -./ • •— 13 uiiu o L
Tce of Air, Noise, and Radiation
4. SPONSORING AGENCY CODE
--.
Triangle Park, North Carolina 27711
EPA/200/04
: SUPPLEMENTARY NOTES
5 REPORT DATE
December 1980
o. PROGRAM ELEMENT NO.~
Xffi^
under Section 112 for volatile oraan r rnmnn H fo>". hazardous air pollutants
chemical manufacturing ?ac ties' n sSK^'70"^^ fr°m Or9anfc
on chemical processing routes VOC emission, ™ * th V^ort> d^a were gathered
and environmental impacts r ^ ulting Torn cSntro? ? tec,hn^^s' Control costs,
and assimilated into the ten volumls ^ *"*
_KEY WORDS AND DOCUMENT ANALYSIS
I >..i— .... .
b. IDENTIFIERS/OPEN ENDED TERMS
Unlimited Distribution
19 SECURITY CLAiiS (Tins
Unclassified
c. COSATl Reid/Group
13B
21. NO. OF PAGES
354
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