United States Office of Air Quality EPA-450/3-79-024
Environmental Protection Planning and Standards April 1979
Agency Research Triangle Park NC 27711
__
vvEPA Guidance for Lowest
Achievable Emission
Rates from 18 Major
Stationary Sources
of Particulate, Nitrogen
Oxides, Sulfur Dioxide,
or Volatile Organic
Compounds
-------
JAN
ERRATA for
EPA-450/3-79-024
"Guidance for Lowest Achievable Emission Rates from
18 Major Stationary Sources of Particulate, Nitrogen
Oxides, Sulfur Dioxide, or Volatile Organic Compounds"
1. On page 3.1-7, Table 3.1-1, the uncontrolled emission factors for sulfur
dioxide and nitric oxides under g/kWh and lb/103 hp-h should be changed:
from:
g/kWh lb/103 hp-h
S02 5.35-7.75 8.75-13.5
N0y 7.3-4.0 12-66
A
to:
lb/103 hp-h
S02 5.35(S)-7.75(S) 8.75(S)-13.5(S)
N0y 0.73-4.0 1.2-6.6
A
2. On page 3.2-7, Table 3.2-1, under "Ratio of flue gas rate to pulp production,"
the symbols for metric and English units should be changed:
from:
m3, dry/Mg ADP/day | (scfm/ton ADP)
dscm/min/Mg ADP/day | (scfm/ton ADP/day)
3. On page 3.2-15, line 10 should be changed:
from:
available. Table 3.2-3 reflects the better AIP levels that have
to:
available. Table 3.2-2 reflects the better AIP levels that have
-------
4. On page 3.4-3, line 7 should be changed:
from:
lyst to burn the coke, which reheats the catalyst. The resulting
tp_:
lyst to burn the coke, which regenerates the catalyst. The resulting
5. On page 3.4-13, Reference 2 should be changed:
from:
2. Data compiled from files of Greene & Associates, Inc.
to:
2. Data supplied by Greene & Associates, Dallas, Texas.
6. On page 3.9-10, Table 3.9-3, columns 4 through 7 should be changed
from:
to:
Coverage ,
liters/
103m2
119
21
56
7
49
(qal/103ft )
(1.7)
(0-3)
(0.8)
(0.1)
(0.7)
Range of VOC emissions
o
g/m coated
31 - 62
3.6 - 11.3
25 - 56
2.5 - 5.9
26 - 38.7
Total 88 - 174
lb/103ft2
(3.7 - 7.5)
(0.4 - 1.4)
(3.0 - 6.9)
(0.3 - 0.7)
(3.1 - 4.6)
(11 - 21)
Coverage ,
liters/
103m2
69
12.2
32.6
4
28.5
(gal/103ft?)
(1.7)
(0.3)
(0.8)
(0.1)
(0.7)
Range of VOC emissions
g/m coated
18 - 37
2.1 - 6.6
14 - 33
1.5 - 3.4
15 - 23
lb/103ft2
(3.7 - 7.5)
(0.4 - 1.4)
(3.0 - 6.9)
(0.3 - 0.7)
(3.1 - 4.6)
Total
51 - 103 (11 - 21)
-------
3
7. On page 3.9-11, line 2 should be changed:
from:
range from 88 to 174 g/km2 (11 to 21 lb/1000 ft2) of flat wood coated.
to:
range from 51 to 103 g/m3 (11 to 21 lb/1000 ft2) of flat wood coated.
8. On page 3.9-14, in Table 3.9-5, the words "Print ink" in the first
column should be changed to "Grain ink."
9. On page 3.9-16, the last sentence in Section 3.9.3.5 should be changed:
from:
The major deterrent to its use is the highest of both
the EB system and the costing materials.
to:
The major deterrent to its use is the high cost of both the EB system and the
coatinq materials.
10. On page 3.9-20, Reference 16 should be added:
16. Personal Communication with M. Kay, Southcoast Air Quality Management
District, El Monte, California.
11. On page 3.12-3, in Table 3.12-1, the second line under note d should be
changed:
from:
light liquid means a liquid lighter than kerosene; liquid means a liquid equal to
to:
light liquid means a liquid lighter than kerosene; heavy liquid means a liquid
equal to
-------
12. On page 3.13-3, in the first sentence of Section 3.13.3, the words
"as summarized in Table 3.13-2" should be deleted.
13. On page 3.15-6, line 15 of the first paragraph of Section 3.15.3 should
be changed:
from:
have demonstrated 93 percent solvent reduction.* A more complete descrip-
tor
have demonstrated 93 percent solvent reduction. A more complete descrip-
14. On page 3.15-6, the footnote at the bottom of the page should be deleted.
15. On page 3.15-8, line 2 should be changed:
from:
produced an 87 percent reduction at some large appliance plants.* Temper-
to:
o
produced an 87 percent reduction at some large appliance plants. Temper-
16. On page 3.15-8, line 14 should be changed:
from:
into the bed.*^ For metal furniture or large appliance coating lines the
to:
g
into the bed. For metal furniture or large appliance coating lines the
17. On page 3.15-8, the two footnotes at the bottom of the page should be
deleted.
-------
5
18. On page 3.15-9, line 9 should be changed:
from:
powder coating by electrostatic spray methods is 99 percent.* Several limi-
to:
g
powder coating by electrostatic spray methods is 99 percent. Several limi-
19. On page 3.15-9, line 20 should be changed:
from:
The average achievable reduction is 78 percent.* Higher-solids coatings are
to:
Q
The average achievable reduction is 78 percent. Higher-solids coatings are
20. On page 3.15-9, the footnote at the bottom of the page should be deleted.
21. On page 3.15-12, the following references should be added:
8. Information supplied by Larry F. Nonemaker, E. I. Dupont Demours & Co., Inc.,
Winnewood, Pa., April 14, 1978.
9. Letter from W. C. Moses, Technical Manager, Chemical Plant Division,
Suttcliffe, Speakman & Company, Limited, March 10, 1978.
22. On page 3.2-7, in the fourth line under "explanation of abbreviations,"
"m3, dry/Mg ADP/day" should be changed to "dscm/min/Mg ADP/day."
-------
-------
EPA-450/3-79-024
Guidance for Lowest Achievable Emission
Rates from 18 Major Stationary Sources
of Particulate, Nitrogen Oxides, Sulfur
Dioxide, or Volatile Organic Compounds
by
PEDCo Environmental, Inc.
Chester Towers
11499 Chester Road
Cincinnati, Ohio 45246
EPA Project Officers: John H. Haines and Gary D. McCutchen
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711 _ ,,0-,,^.
APT.M979 V) S. &*•*"«**£$" 'HCy
Mprn ia/a u.<>; w c , ;^r-,rv ^rL-J.^-J' .„.. ciQQr
-------
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD-35), U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; or, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22161.
This report was furnished to the Environmental Protection Agency
by PEDCo Environmental, Inc., Chester Towers, 11499 Chester Road,
Cincinnati, Ohio 45246, in fulfillment of Contract No. 68-0.1-4147.
Mention of company or product names is not to be considered as an
endorsement by the Environmental Protection Agency.
Publication No. EPA-450/3-79-024
n S Environmental Protection
WjW-
ii
-------
ERRATA for
EPA-450/3-79-024
"Guidance for Lowest Achievable Emission Rates from
18 Major Stationary Sources of Particulate, Nitrogen
Oxides, Sulfur Dioxide, or Volatile Organic Compounds"
1. On page 3.1-7, Table 3.1-1, the uncontrolled emission factors for sulfur
dioxide and nitric oxides under g/kWh and lb/103 hp-h should be changed:
from:
g/kWh lb/103 hp-h
S02 5.35-7.75 8.75-13.5
N0v 7.3-4.0 12-66
A
to:
g/kWh lb/103 hp-h
S02 5.35(S)-7.75(S) 8.75(S)-13.5(S)
N0v 0.73-4.0 1.2-6.6
X
2. On page 3.2-7, Table 3.2-1, under "Ratio of flue gas rate to pulp production,"
the symbols for metric and English units should be changed:
from:
m3, dry/Mg ADP/day | (scfm/ton ADP)
_to:
dscm/min/Mg ADP/day | (scfm/ton ADP/day)
3. On page 3.2-15, line 10 should be changed:
from:
available. Table 3.2-3 reflects the better AIP levels that have
to:
available. Table 3.2-2 reflects the better AIP levels that have
-------
4. On page 3.4-3, line 7 should be changed:
from:
lyst to burn the coke, which reheats the catalyst. The resulting
to:
lyst to burn the coke, which regenerates the catalyst. The resulting
5. On page 3.4-13, Reference 2 should be changed:
from:
2. Data compiled from files of Greene & Associates, Inc.
to:
2. Data supplied by Greene & Associates, Dallas, Texas.
6. On page 3.9-10, Table 3.9-3, columns 4 through 7 should be changed:
from:
to:
Coverage ,
liters/
103m2
119
21
56
7
49
(qal/103ft )
(1.7)
(0.3)
(0.8)
(0.1)
(0.7)
Range of VOC emissions
p
g/m coated
31 - 62
3.6 - 11.3
25 - 56
2.5 - 5.9
26 - 38.7
Total 88 - 174
lb/103ft2
(3.7 - 7.5)
(0.4 - 1.4)
(3.0 - 6.9)
(0.3 - 0.7)
(3.1 - 4.6)
(11 - 21)
Coverage ,
liters/
103m2
69
12.2
32.6
4
28.5
(gal/103f£)
(1.7)
(0.3)
(0.8)
(0.1)
(0.7)
Range of VOC emissions
0
g/m coated
18 - 37
2.1 - 6.6
14 - 33
1.5 - 3.4
15 - 23
lb/103ft2
(3.7 - 7.5)
(0.4 - 1.4)
(3.0 - 6.9)
(0.3 - 0.7)
(3.1 - 4.6)
Total
51 - 103 (11 - 21)
-------
3
7. On page 3.9-11, line 2 should be changed:
from:
range from 88 to 174 g/km2 (11 to 21 lb/1000 ft2) of flat wood coated.
to:
range from 51 to 103 g/m3 (11 to 21 lb/1000 ft2) of flat wood coated.
8. On page 3.9-14, in Table 3.9-5, the words "Print ink" in the first
column should be changed to "Grain ink."
9. On page 3.9-16, the last sentence in Section 3.9.3.5 should be changed:
from:
The major deterrent to its use is the highest of both
the EB system and the costing materials.
to:
The major deterrent to its use is the high cost of both the EB system and the
coating materials.
10. On page 3.9-20, Reference 16 should be added:
16. Personal Communication with M. Kay, Southcoast Air Quality Management
District, El Monte, California.
11. On page 3.12-3, in Table 3.12-1, the second line under note d should be
changed:
from:
light liquid means a liquid lighter than kerosene; liquid means a liquid equal to
to:
light liquid means a liquid lighter than kerosene; heavy liquid means a liquid
equal to
-------
12. On page 3.13-3, in the first sentence of Section 3.13.3, the words
"as summarized in Table 3.13-2" should be deleted.
13. On page 3.15-6, line 15 of the first paragraph of Section 3.15.3 should
be changed:
from:
have demonstrated 93 percent solvent reduction.* A more complete descrip-
to:
g
have demonstrated 93 percent solvent reduction. A more complete descrip-
14. On page 3.15-6, the footnote at the bottom of the page should be deleted.
15v On page 3.15-8, line 2 should be changed:
from:
produced an 87 percent reduction at some large appliance plants.* Temper-
to.:
o
produced an 87 percent reduction at some large appliance plants. Temper-
16. On page 3.15-8, line 14 should be changed:
from:
into the bed."f* For metal furniture or large appliance coating lines the
to:
into the bed.9 For metal furniture or large appliance coating lines the
17. On page 3.15-8, the two footnotes at the bottom of the page should be
deleted.
-------
5
18. On page 3.15-9, line 9 should be changed:
from:
powder coating by electrostatic spray methods is 99 percent.* Several limi-
to:
o
powder coating by electrostatic spray methods is 99 percent. Several limi-
19. On page 3.15-9, line 20 should be changed:
from:
The average achievable reduction is 78 percent.* Higher-solids coatings are
to:
p
The average achievable reduction is 78 percent. Higher-solids coatinqs are
20. On page 3.15-9, the footnote at the bottom of the page should be deleted.
21. On page 3.15-12, the following references should be added:
8. Information supplied by Larry F. Nonemaker, E. I. Dupont Demours & Co., Inc.,
Winnewood, Pa., April 14, 1978.
9. Letter from W. C. Moses, Technical Manager, Chemical Plant Division,
Suttcliffe, Speakman & Company, Limited, March 10, 1978.
22. On page 3.2-7, in the fourth line under "explanation of abbreviations,"
"m3, dry/Mg ADP/day" should be changed to "dscm/min/Mg ADP/day."
-------
-------
CONTENTS
Acknowledgment v
1. Introduction and General Discussion 1-1
1.1 Introduction 1-1
1.2 Relationship of NSPS, BACT, and LAER 1-2
1.3 Legislative Basis 1-4
1.4 LAER Guidance Documents 1-5
2. Methodology: Approach and Procedures 2-1
2.1 Introduction 2-1
2.2 State Implementation Plans (SIP) Limitations 2-1
2.3 Achieved-In-Practice (AIP) Limitations 2-4
2.4 New Source Performance Standards (NSPS)
Limitations 2-5
2.5 LAER Finalization 2-6
3. LAER Guidelines 3-1
3.1 Stationary Gas Turbines/Electric Utilities 3.1-1
3.2 Kraft Pulp Mills 3.2-1
3.3 Electric Arc Furnaces at Steel and Gray
Iron Foundries 3.3-1
3.4 Petroleum Refineries—Catalytic Cracking
and Fuel Burning 3.4-1
3.5 Fabric Coating 3.5-1
3.6 Large Industrial Boilers 3.6-1
3.7 Primary Aluminum Plants 3.7-1
3.8 Bulk Gasoline Terminals 3.8-1
3.9 Flat Wood Paneling 3.9-1
3.10 Petroleum Liquids Storage 3.10-1
3.11 Petroleum Refineries—Wastewater Separators 3.11-1
3.12 Petroleum Refineries—Fugitive Emissions 3.12-1
3.13 Graphic Arts Printing 3.13-1
3.14 Automobile and Light Truck Coating 3.14-1
3.15 Metal Furniture and Large Appliance Coating 3.15-1
3.16 Can Coating 3.16-1
3.17 Metal Coil Coating 3.17-1
3.18 Paper Coating 3.18-1
111
-------
CONTENTS (continued)
4. Cost Estimating Methodology 4-1
4.1 Introduction 4-1
4.2 Factors Affecting the Cost of Emission
Control 4-2
4.3 Capital Cost Estimates 4-3
4.4 Methodology for Estimating Annualized Costs 4-12
4.5 Cost-effectiveness 4-23
5. Financial and Economic Analysis Techniques 5-1
5.1 Introduction 5-1
5.2 The Analysis Techniques 5-2
5.3 Information Needed to Perform Analysis
Techniques 5-lf
Appendix A A-l
Appendix B B-l
IV
-------
ACKNOWLEDGEMENT
This report was prepared under the direction of Mr. Jack A.
Wunderle. Principal authors within PEDCo Environmental, Inc.,
were Messrs. Joseph Carvitti and Jack A. Wunderle. The JACA
Corporation prepared Chapter 5.
Project Officers for the Environmental Protection Agency
were Messrs. John H. Haines and Gary D. McCutchen. The authors
appreciate the contributions made by the EPA project officers and
their associates.
-------
SECTION 1
INTRODUCTION AND GENERAL DISCUSSION
1.1 INTRODUCTION
The Clean Air Act as amended in 1977 (CAAA 1977) contains three
technology-based limitations affecting the location and construction of new or
modified air pollution sources: (1) New Source Performance Standards (NSPS);
(2) Best Available Control Technology (BACT); and (3) Lowest Achievable
Emission Rate (LAER). Although NSPS and BACT are relatively familiar
concepts that have been incorporated into statutes, regulations, and imple-
mentation plans, LAER is relatively new. The 1977 amendments established
LAER as a rtatutory requirement, and EPA's Emission Offset Interpretative
Ruling incorporated LAER as a regulatory demand in the preconstruction
review of major stationary sources which would contribute to a violation of
an NAAQS. Additionally, the CAAA 1977 (§178) requires that the Admin-
istrator issue guidance documents for the purpose of assisting states in
implementing the requirements of §129 and §173 pertaining to lowest achievable
emission rate.
The purpose of this document is to provide technical assistance and
guidance to those who must prepare and submit applications for proposed
*
construction or modification of sources and facilities and to those who must
approve or deny such applications.
Throughout this document the use of certain terms--major new
source, facility, major modification, potential emissions,
allowable emissions, NSPS, BACT, LAER--is intended to reflect
the meanings imparted to those terms by the CAAA 1977.
1-1
-------
The following sections deal with the interrelationships of the new source
requirements embodied in the CAAA 1977; the legislative basis of LAER
(including the factors that must be considered in determining LAER); some of
the limitations and constraints involved in LAER determination; and, finally,
the scope, intent, applicability, use, and limitations of the source-specific
guidance in Section 3.
1.2 RELATIONSHIP OF NSPS, BACT, AND LAER
Because LAER is a relatively new requirement, it should be considered
in relation to the other requirements applicable to new or modified major
sources or facilities, that is, to NSPS and BACT.
The NSPS are applicable wherever a new source intends to locate (01 in
the case of a modified source—is located). They are limited to the specific
sources and facilities that are the subject of a Federal promulgation (Title 40,
Chapter I, Subchapter C, Part 60 CPU—Statutory authority, §111). An NSPS
generally embodies specific emission limitations and may include operational
and performance standards. The statute directs that the "standard of
performance" shall be the best technological system of continuous emission
reduction adequately demonstrated, considering cost, energy requirements,
and other effects, such as socioeconomic impacts.
The BACT requirement is to be applied to new and modified sources
subject to Prevention of Significant Deterioration (PSD) review and is
required for each pollutant subject to regulation under the Act. The BACT
review is relevant to major new or modified stationary sources or facilities. '
The BACT and NSPS definitions are similar in that BACT must be technically
achievable and must also reflect consideration of cost, energy requirements,
and other possible impacts. The BACT requirement however is to be applied
on a case-by-case basis and is also to consider any alternatives (production,
process modification, control methods, systems, and techniques) that either
singly or in combination could lead to further reduction in emissions if
1-2
-------
applied. Further, BACT is to be at least as stringent as any applicable
NSPS or National Emission Standards for Hazardous Air Pollutants
(NESHAPS). In a given case, therefore, the imposition of BACT limitations
may be more stringent than NSPS or NESHAPS.
The LAER requirements are imposed in the review process on a proposed
major new source or proposed major modification in a nonattainment area.
As applied to a modification, LAER means the lowest achievable emission rate
for the new or modified facilities within the source.
Section II.A.7 of the proposed Emission Offset Interpretive Ruling
defines LAER as follows:
"Lowest achievable emission rate" means for any source,
that rate of emissions based on the following, whichever is
more stringent:
(i) the most stringent emission limitation which
is contained in the implementation plan of any State
for such class or category of source, unless the owner
or operator of the proposed source demonstrates that
such limitations are not achievable, or
(ii) the most stringent emission limitation which
is achieved in practice by such class or category of
source.
This term, applied to a modification, means the LAER
for the new or modified facilities within the source.
In no event shall the application of this term permit a
proposed new or modified source to emit any pollutant in
excess of the amount allowable under applicable new source
standards of performance.
Although transfer of technology had only a minor role in the determi-
nation of LAER in this document, such decisions were guided by a pertinent
discussion in EPA's proposed Emission Offset Interpretive Ruling. This
discussion ("Technology transfer in determining LAER," p. 3208) states:
It has been EPA's interpretation that in determining
the lowest achievable emission rate (LAER), the reviewing
authority may consider transfer of technology from one
source type to another where such technology is applicable.
Although Congress changed the definition of LAER, EPA con-
tinues *:o believe that technology transfer may be considered
in dete .mining LAER. Congress intended to require new
1-3
-------
sources in nonattainment areas to apply the "maximum feas-
ible pollution control," even if this involves
"technology-forcing." Therefore, the Agency does not feel
that the phrase "achieved in practice by such class or
category of source" [under Section 171(3)] prohibits
technology transfers from other types of sources. If
pollution-control technology can feasibly be transferred
from one type of source to another, then for purposes of
determining LAER, EPA will consider both types of source to
be in the same "class or category of source."
Of course, technology transfer need not be considered in determining
LAER if it is not feasible for the specific application under consideration.
Further, NSPS, BACT, and LAER all must be achievable before they are
applied. The LAER provisions are generally more stringent than BACT, and
BACT may be more stringent than NSPS. Neither BACT nor LAER can be
less stringent than an applicable NSPS for the specific source or facility and
the specific pollutant emitted.
1.3 LEGISLATIVE BASIS
Insight as to Congressional intent in adopting the LAER requirement and
guidance to be followed in developing LAER limits are found in the Congress-
ional Record (House, August 3, 1977, p. H 8551). The following quotation is
from conference agreements between House and Senate.
The House definition of "lowest achievable emission
rate" is adopted for purposes of this section. In determin-
ing whether an emission rate is achievable, cost will have
to be taken into account, but cost factors in the nonattain-
ment content will have somewhat less weight than in deter-
mining new source performance standards under Section 111.
Of course, health considerations are of prime importance.
Facilities seeking to locate or expand in areas not meeting
air quality health standards should be required to use the
best control technology and processes available. The defi-
nition is intended to describe the lowest rate which is
actually, not theoretically, possible. If the cost of a
given control strategy is so great that a new major new
source could not be built or operated, then such a control
would not be achievable and could not be required by the
Administrator.
1-4
-------
These citations show clearly that LAER is intended to require more than
add-on control devices. It calls for the consideration, selection, and appli-
cation of alternative production procedures, modifications of unit processes,
and control techniques in a combination that results in minimal pollutant re-
lease. In so doing, it establishes environmental concern as a prominent con-
sideration in the early stages of planning of new and modified sources.
1.4 LAER GUIDANCE DOCUMENTS
1.4.1 Purpose
The CAAA 1977 calls for the issuance of guidance documents to assist the
state in implementing Part D, Title 1, of the Act as it pertains to application
of the lowest achievable emission rate to major new or modified stationary
sources (§178). In satisfying this requirement, EPA intends to provide
guidance in the form of reference material that is useful to engineers in
industry and in state or local agencies, to those who prepare and those who
review permit applications, to those regulated by the LAER requirement, and
to those who implement that requirement.
1.4.2 Scope and Limitations
The user must recognize that the guidelines presented herein are limited
as to scope and subject. This document pertains to selected major stationary
sources, to certain emitting facilities within those sources, and to specific
emissions from those sources or facilities. In the section on primary aluminum
reduction plants, for example, the LAER guidance addresses only sulfur
dioxide emissions from anode bake ovens and reduction cell facilities. It does
not address LAER for grinding and mixing of materials, casting and tapping
of metal, or other emission points. Nor does it address other emissions (such
as hydrocarbons, fluorides, and particulates) from the anode bake and reduc-
tion cell operations.
It is important to emphasize that the LAER criteria apply to all proposed
major new or modified sources. The fact that no guidance document has been
1-5
-------
issued for a source-facility emission grouping does not relieve the appropriate
authority from the obligation to apply LAER criteria in the permit review
process; nor does it relieve the applicant from seeking to attain the lowest
achievable emission rate.
The LAER requirement, like BACT and NSPS, is considered to be evolu-
tionary and subject to change. Achievable levels of air pollution control will
improve with technological advances. As new and improved technologies or
processes are conceived, demonstrated, and practiced, they will be recognized
and used. Today's state of the art will be replaced by that of tomorrow.
Finally, the technical information and guidance presented in this report
are not intended to apply to all situations and specific conditions of the
industrial processes and pollutants described here. This is termed a guid-
ance document because it provides useful reference materials, but it should
serve only as a starting point in a LAER investigative review.
In preparing these initial LAER guidelines, the time constraints specified
in the CAAA 1977 and the need to allocate technical and professional resources
within that time frame limited the scope and detail of the document. These
time and manpower constraints dictated the following limitations on preparation
of the guidance documents:
0 No visits were made to sources or facilities to confirm
technology and/or performance.
0 The technical data base was drawn from telephone or
written communication with equipment vendors, facility
owners, governmental control agencies, and other
groups, coupled with limited perusal of published
literature.
0 A cut-off date was established for data acquisition to
provide sufficient time to catalog and analyze the
information before preparing the document.
0 A "current as of" date was fixed for review of regula-
tions set forth in the State Implementation Plans
(SIP), which undergo frequent revision.
Acquisition of technical information and SIP limitations through query by
telephone or mail is subject to the celerity and generosity of the respondent.
1-6
-------
Although every effort was made to maximize the quality of the data, the need
to impose deadlines on data acquisition may have caused the exclusion of
certain appropriate and relevant information.
1-7
-------
REFERENCES
Appendix S—Emission Offset Interpretive Ruling Federal
Register, Vol. 44, No. 11, January 16, 1979. p. 3282.
(Although this was designated in the Federal Register as a
final rule, the Administrator did invite comment on certain
portions of the Ruling, indicating the possibility of
change).
Title 40, part 51 of the Code of Federal Regulations,
§51.24(b), (1) and (2), FR Vol. 43, No. 118, June 18, 1978,
p. 26382 and as specified in §169(1), CAAA 1977.
3. Reference 2.
4. Reference 1,
5. Reference 1.
6. Reference 1.
p. 3283.
§51.24(b)(17) p. 26383.
(II)(A) Definitions. (4) and (5) p. 3282.
(II)(A) Definitions. (6). p. 3282.
(IV, Condition 1). p. 3284 and footnote 2,
1-8
-------
SECTION 2
METHODOLOGY: APPROACH AND PROCEDURES
2.1 INTRODUCTION
The CAAA 1977 defines LAER as the more stringent of two
emission limitations for a class or category of source—that
contained in the implementation plan of any state or that
achieved in practice. The Act further requires that LAER be at
least as stringent as an applicable NSPS limitation. Thus, the
Act gives clear direction as to the major considerations in
determining LAER. The methodology, approach, and procedures
utilized v.ere geared to discovering, for each source/facility/
pollutant grouping, the most stringent emission limitation
embodied in a State Implementation Plan (SIP), achieved in
practice (AIP), or required by an applicable New Source Perfor-
mance Standard (NSPS). Figure 2-1, LAER Determination Decision
Tree, illustrates the approach and procedures used.
2.2 STATE IMPLEMENTATION PLAN (SIP) LIMITATIONS
The first step in the review of SIP limitations was to ac-
quire an up-to-date file of current air pollution control regula-
tions of the major state and local air pollution control agen-
cies. The acquisition and verification procedures were as fol-
lows:
1. Letters were mailed to all state agencies and the most
significant city, county, and regional agencies within
each state. This letter advised the agency of the
purpose of the LAER study and requested that the agency
send, as soon as possible, a complete and current copy
of its air pollution control laws and regulations.
2-1
-------
REG.
REVIEW
QUERY CONTACTS:
STATE AND LOCAL,
CONTROL VENDORS,
TRADE ASSOC.,
SOURCE OWNERS,
ETC.
SELECT
MOST
STRINGENT
E.L.(TENTATIVE)
NEDS
RETRIEVAL
*
EXAMINE
FOR AIP
SOURCE RESIDENCE,
REG. INTERPRETATION,
ACHIEVED IN PRACTICE
AND CONTROL TECHNOLOGY
QUERIES
ASSESS EMISSION
REDUCTION METHODS
SELECT TENTATIVE
BERS COMBINATION
LEGEND:
SIP -
AIP -
NSPS -
E.L. -
REG -
LAER -
BERS -
NEDS -
STATE IMPLEMENTATION PLAN
ACHIEVED-IN-PRACTICE
NEW SOURCE PERFORMANCE STANDARDS
EMISSION LIMIT
REGULATION
LOWEST ACHIEVABLE EMISSION RATE
BEST EMISSION REDUCTION SYSTEM
NATIONAL EMISSION DATA SYSTEM
Figure 2-1. LAER Determination "Decision Tree"
2-2
-------
2. Approximately 2 weeks after the letters were sent,
follow-up calls were made to jurisdictions that had not
yet responded. The agency was again advised of the
study purpose and requested to send a copy of current
regulations.
3. Two cross-checks were made to verify that the state
regulations provided were, in fact, the most current:
the regulations given in the Environmental Reporter
State Air Laws, published by the Bureau of National
Affairs, Inc., were compared with those sent by the
states; the PEDCo files of state and local air pollu-
tion regulations, last updated in June 1976, were also
examined.
Each response, as received, was dated and filed. An ac-
counting of those jurisdictions not responding was maintained.
Final tabulations indicated that the files contained current
regulations for all states and for 54 city, county, and local
jurisdictions. Generally, all regulations were current as of
January 31, 1978.
In review of the regulations of each jurisdiction to ascer-
tain the lowest emission limitation required in an SIP, the regu-
lations were grouped into sets and subsets:
General Fuel Burning Regulations
- Particulate
- Sulfur Dioxide
- Oxides of Nitrogen
General Manufacturing Process Regulations
- Particulate
- Sulfur Dioxide
- Volatile Organic Compounds
Source-Specific Regulations
- By the specific major source types named in the
guidance document
2-3
-------
The regulations of each jurisdiction were reviewed and placed
into the above groupings. Where a particular jurisdiction had no
applicable regulation specific for a given source (e.g., Kraft
Pulp Mills or Primary Aluminum Plants) an applicable general
process regulation was cited. Each category was then examined to
ascertain the most stringent SIP emission limitation. The limi-
tations were viewed in conjunction with the specified compliance
determination method (source test or other) because the two
parameters--emission limitation and compliance determination
method—together determine the relative degree of stringency of a
limitation.
This process served to identify the most stringent SIP
limitation and the responsible jurisdiction. The final steps
were to determine whether a source is resident in the jurisdic-
tion (or whether the regulation was designed to preclude entrance
of such source), to resolve any questions involving interpreta-
tion of a regulation, and to acquire information regarding
sources that had attained emission levels within the limitation.
2.3 ACHIEVED-IN-PRACTICE (AIP) LIMITATIONS
Three methods were used to obtain information regarding the
lowest emission rate achieved in practice and the attendant con-
trol technology: queries were made to state and local control
agencies, control equipment vendors, trade associations, source
owners, and other; published literature was reviewed; and a
limited "quick look" retrieval was obtained from the National
Emissions Data System (NEDS). This retrieval covered the entire
nation and listed for each pollutant/facility/source grouping of
interest the source and location, source classification code,
control device used, and emission reduction achieved. To reduce
the volume of this listing the retrieval logic incorporated a
control efficiency cut-off for each source-facility so that only
those attaining a control efficiency greater than the specified
cut-off value were listed. Information gleaned from the several
2-4
-------
methods was then examined to determine the lowest emission rate
achieved in practice.
2.4 NEW SOURCE PERFORMANCE STANDARDS (NSPS) LIMITATIONS
EPA regulations adopted under statutory authority of Section
111, CAAA 1977, and promulgated under Title 40, Chapter I, Sub-
chapter C Part 60 CFR are known as New Source Performance Standards
(NSPS). Such standards are required by the Act to reflect the
degree of emission limitation achievable by application of the
best system of emission reduction that has been adequately demon-
strated. NSPS have been promulgated for some of the sources
addressed in this document. The NSPS citation in the Code of
Federal Regulations (CFR) and the companion LAER guidance cate-
gory (subsection of Section 3) are listed below.
LAER CATEGORY
3.1 Stationary Gas Turbines
(utility power plants -
oxides of nitrogen, sulfur
dioxide)
3.2 Kraft Pulp Mills (lime
kilns - particulate; re-
covery furnaces - sulfur
dioxide; and power boilers
- particulate)
3.3 Electric Arc Furnaces
(steel and gray iron found-
dries - particulate)
3.3 Electric Arc Furnaces
(steel and gray iron
foundries - particulate)
3.4 Petroleum Refiners (cata-
lytic crackers - sulfur
dioxide)
NSPS - 60 CFR SUBPART
(AFFECTED FACILITY)
GG Stationary Gas Turbines
(>1000 Hp - oxides of nitro-
gen, sulfur dioxide) - pro-
posed only - Oct. 1977
BB Recovery furnaces (particulate),
Smelt dissolving tanks (partic-
ulate), Lime kilns [particulate,
total reduced sulfur (TRS)
limited to 5 ppmv for seven
facilities].
Z Ferroalloy Production Facilities*
(electric submerged arc furnaces -
particulate).
AA Steel Plants* (electric arc fur-
naces - particulates)
Petroleum Refineries (catalytic
cracker - particulate, CO)
3.6 Industrial Boilers D
(particulate, sulfur di-
oxide, oxides of nitrogen)
3.7 Primary Aluminum Reduction S
(reduction cells and anode
bake oven - sulfur dioxide)
3.10 Petroleum Liquids
Storage (hydrocarbons)
Fossil-Fuel-Fired Steam Gen-
erators (>250 million Btu/h -
particulate, sulfur dioxide,
oxides of nitrogen)
Primary Aluminum Reduction
Plants (reduction cell pot-
rooms and anode bake plant -
fluorides)
Storage Vessels for Petroleum
Liquids (>40,000 gal capacity
hydrocarbons)
* NSPS are planned specific to particulates from electric arc
furnaces in steel and gray iron foundries.
2-5
-------
The NSPS specifies an affected facility and the pollutants
covered by the standard. The LAER guidance also pertains to
specific facilities and pollutants. The two NSPS and LAER cate-
gories were examined for a match of source/facility/pollutant
groupings. Where that match occurred, the NSPS emission limita-
tion was recorded for comparison with the AIP- and SIP-derived
LAER values.
2.5 LAER FINALIZATION
The tentative LAER limits from review of AIP and SIP were
then compared and the more stringent of the two was selected.
Where an NSPS was applicable, the AIP-SIP selection was compared
with the NSPS limitation and again the more stringent was se-
lected. Finally consideration was given to changes in raw ma-
terial input, to production and process modifications, and to
technology transfer in a combination that would represent a best
system of emission reduction that could be applied to a given
source/facility/pollutant set. A final LAER value was then
selected, and the technology for achieving the emission limita-
tion was described. Factors that could limit application of the
technology were addressed.
The draft document was then organized in standard format of
the EPA Office of Research and Development (ORD), subjected to
editorial scrutiny, and offered to affected and interested par-
ties for review and comment. The comment period was intended to
allow for discovery and correction of any errors and to permit
consideration of comments and other information that would en-
hance the clarity and technical accuracy of the document. Appro-
priate modifications based on these and internal review comments
have been incorporated into the final document.
2-6
-------
SECTION 3
LAER GUIDELINES
This Section consists of 18 subsections that deal with LAER
for pollutants emitted from the facilities of certain major
sources. Not all pollutants that may be emitted from a facility
are covered, nor are all the facilities at a major source. The
guidance pertains to a limited number of stationary sources, to
selected facilities within those sources, and to specific emis-
sions from those facilities. The format of each guidance con-
sists of Process Description, Emissions, Control Measures, Emis-
sion Limits, and Determination of LAER.
This is a technical document, for guidance only, and it
should not be construed as regulatory in nature. Its purpose is
to provide technical information and reference materials for use
as a starting point in making a LAER determination, not for
rigidly prescribing LAER. The information presented is limited
in scope and is not intended to apply to all situations and
conditions that may be encountered in the review of permit appli-
cations. The guidances do not replace the individualized atten-
tion and consideration to be afforded an entity that seeks ap-
proval to install a new--or modify an existing—source. The
review authority is encouraged to recognize the individuality of
each permit application and the desirability of a case-by-case
approach that ultimately leads to a LAER determination based on
and specifically tailored to a given set of circumstances.
Caution should be exercised in utilizing this document be-
cause of the anticipated changes in the CAAA 1977 specified
criteria upon which LAER determinations are to be made, i.e.,
State Implementation Plan (SIP) limits, achieved-in-practice
3-1
-------
(AIP) levels, and New Source Performance Standards (NSPS).
Changes in SIP-related limitations are imminent in response to
CAAA 1977 requirements that SIP's be revised for areas where the
National Ambient Air Quality Standards (NAAQS) have not been
attained. Also, advances in control technology and in equipment
performance can be expected to result in AIP levels lower than
those reported here. Furthermore, an expanded list of sources
are to be the subject of NSPS promulgation in the near future,
and consideration is being given to revising some NSPS. There-
fore, the user should verify that the SIP, AIP, and NSPS limits
in this document are currently applicable and have not changed
since document publication.
Finally, it is important to note that these guidelines apply
to both new and modified facilities. With regard to modified or
reconstructed facilities, the reviewer may give case-by-case
consideration to any special economic or physical constraints
that might limit the application of certain control techniques to
a modification project, i.e., the level of control required for a
process undergoing modification or reconstruction may not be as
stringent as that required if the same process were a grass-roots
construction project.
3-2
-------
3.1 MAJOR SOURCE CATEGORY: STATIONARY GAS TURBINES/ELECTRIC
UTILITIES—NITRIC OXIDE AND SULFUR DIOXIDE EMISSIONS
3.1.1 Process Description
A gas turbine is a rotary engine, of which a common example
is the jet aircraft engine. Compressed air is rapidly expanded
by the combustion of a fuel in a combustion chamber. The high
velocity and high temperature gases rotate a turbine fan that
drives a power-output shaft. Figure 3.1-1 presents a cutaway
view of a stationary gas turbine. Turbines range in size from
less than 30 kW (40 hp) to over 75 MW (105 hp).2 Manufacturers
continue to increase turbine capacity, and turbines are often
installed in groups, so that the combined power output from one
location may exceed 1.12 GW (1.5 x 106 hp).3 Over 90 percent of
the horsepower sold in the U.S. goes to utilities and that margin
4
continues to widen.
Three basic types of gas turbines are used in the electric
power industry: simple cycle, regenerative cycle, and combined
cycle. A simple cycle gas turbine consists typically of one or
more compressor stages, one or more combustion chambers where
liquid or gaseous fuels are burned, and one or more turbines to
drive the compressor and the load. These can be arranged in
various configurations. Figure 3.1-2 is a block diagram of a
typical simple cycle gas turbine. The turbine is started with
an electric motor, diesel engine, or other energy source to
rotate the compressor that provides compressed air to the combus-
tors. Fuel is then introduced into the combustors and burned to
produce hot gases, which expand across the first set(s) of tur-
bine blades, providing the driving force to continue rotating the
compressor(s) mounted on the same shaft. The hot gases are
further expanded across the power turbine blades that drive the
electrical generators. The exhaust gases, containing pollutants,
exit to the atmosphere at temperatures ranging from 430° to 600°C
(800° to 1100°F).6
3.1-1
-------
EXHAUST
I
N)
EXHAUST
DUCT
HIGH
COMPRESSOR
HIGH
COMPRESSOR
TURBINE
LOW
COMPRESSOR
TURBINE
POWER
TURBINE
Figure 3.1-1. Cutaway view of a typical stationary gas turbine.
-------
U)
I
u>
STATIONARY GAS TURBINE
Vy
ROTARY
ENERGY
J
LOAD
Figure 3.1-2. Typical simple cycle gas turbine.
-------
The regenerative cycle gas turbine is essentially a simple
cycle gas turbine with an added heat exchanger, as shown in
Figure 3.1-3. Thermal energy is recovered from the 430° to
f.
600°C (800° to 1100°F) exhaust gases and used to preheat the
compressed air. Since less fuel is required to heat the com-
pressed air to the design turbine inlet temperature, the regen-
erative cycle improves the overall efficiency of the simple
cycle.
The combined cycle gas turbine also recovers waste heat from
the turbine exhaust gases. It is essentially a simple cycle gas
turbine with the hot gases vented to a waste heat boiler, as
Q
shown in Figure 3.1-4. Steam generated by the waste heat boiler
can be used to generate electricity with conventional steam
turbines. Some waste heat boilers are designed to generate
additional steam by the firing of conventional fuels in a fire-
box. Such systems are known as supplementary-fired combined
cycle gas turbines.
3.1.2 Emissions
The pollutants generated by gas turbines are those common to
all combustion processes: NOX, HC, CO, S02, particulates, and
visible emissions. Table 3.1-1 summarizes the typical pollutant
emissions, which are dependent on such variables as turbine
firing temperature, turbine pressure ratio, turbine load, com-
bustor design, fuel characteristics, and atmospheric conditions.
This section discusses only S02 and N0x, for which lowest achiev-
able emission rates (LAER) are developed.
3.1.2.1 Nitric Oxides (NO )--
J\
Nitric oxides produced by combustion of fuels in stationary
gas turbines are formed by the combination of nitrogen and oxygen
in the combustion air (thermal NO ) and from the reaction of the
X
nitrogen in the fuel with the oxygen in the combustion air
(organic NO ). Formation mechanisms are complex, and detailed
X
discussion is beyond the scope of this document.
3.1-4
-------
U)
•
M
I
Ul
EXHAUST
STATIONARY GAS TURBINES
LOAD
Figure 3.1-3. Typical regenerative cyclone gas turbine,
-------
FUEL
WASTE HEAT
BOILER
COMPRESSED
AIR —»
AIR
COMBUSTION
CHAMBER I
-EXHAUST-H—
COMPRESSOR
AIR
STATIONARY GAS TURBINE
LOAD
ROTARY
ENERGY
Figure 3.1-4. Typical combined cycle gas turbine,
-------
TABLE 3.1-1. UNCONTROLLED POLLUTANT EMISSIONS
FROM TYPICAL STATIONARY GAS TURBINES9
u>
Pollutant
Carbon
monoxide
Sulfur b
dioxide
Nitric
oxides
Hydro
carbons
Particulate
Symbol
CO
S02
NO
X
HC
Uncontrolled emissions
g/kWh
0.13-16
5.35-7.75
7.3-4.0
0.22-1.1
NR
lb/103 hp-h
0.2-26
8.75-13.5
12-66
0.36-1.8
NR
ppmv @ 15% O2
2.3-160
NR
50-350
1-5 (as hexane)
0.002-0.1 gr/scf
Highly dependent on combustion efficiency.
S = sulfur content of fuel in weight percent.
Highly dependent on combustion temperature, combustor
design, fuel nitrogen, and other factors as discussed.
d
Highly dependent on type of fuel and combustion efficiency.
NR = not reported.
-------
Several major factors limit the formation of NC>X: the
availability of 02/ the combustor residence time and temperature,
the amount of moisture in the inlet air, and combustor pres-
sure.10'11'12 The quantity of NO emissions generated by gas
X
turbines is limited by the residence time of the hot gases in the
engine combustors and by the rapid quenching of these gases by
dilution air. Therefore, very high combustion efficiencies (high
temperature) can be attained without generating the very high
equilibrium quantities of NOX. Humidity in the inlet air will
decrease NO formation by reducing the combustion flame tempera-
12 x
ture.
Organic NO is formed during combustion by the chemical
combination of the nitrogen atoms contained in the fuel molecule
with oxygen in the air. The exact mechanism is not
known.13'14'15 Generally, organic N0x is a problem only in
burning of residual oils, blends, some crude oils, or heavy
distillates that have high nitrogen contents. ' Table 3.1-2
indicates the nitrogen content of various fuels.
NO emissions from gas turbines were measured and reported
for over 50 source tests.20 Uncontrolled NOX emissions ranged
from about 40 to 500 ppm at 15 percent 02 for all fuels, and
averaged 90 ppm for natural gas, 130 ppm for distillate fuel, and
190 ppm for jet-A type fuel. Table 3.1-3 gives the range and
average of uncontrolled NOX emissions from the sources that were
tested which include combustor rigs (models) as well as full-
scale turbines.
3.1.2.2 Sulfur Dioxide (S02)--
The formation of S02 in stationary turbine operations is
strictly a function of the sulfur content of the fuel. Generally
100 percent of the sulfur is converted to SO2. Table 3.1-2 shows
the typical concentrations of sulfur in common fuels. Turbine
operators generally use low-sulfur natural gas and light distil-
lates,21 although crudes and residuals can also be used.
3.1-8
-------
TABLE 3.1-2. NITROGEN AND SULFUR CONTENTS OF COMMON FUELS
Fuel
Natural gas
Distillate oil
Crude oil
Residual oil
Content, percent by weight
Nitrogena
nil
<0.015
<0.2
<2.0
Sulfurb
0-0.1
0.01-0.48
0.06-3.0
0.5-3.2
References 15 and 16.
References 17 and 18.
TABLE 3.1-3. N0v EMISSIONS BY TYPE OF FUEL
X
20
Uncontrolled NO emissions,
X
ppmv @ 15% 09
Fuel
Natural gas
Distillate fuel
Jet-A
Range
40-150
50-240
40-500
Average
90
130
190
Number of tests
18
30
9
3.1-9
-------
The SO_ concentration is calculated at 180 to 260 S ppm,
depending upon the sulfur content (S) of the fuel and the exhaust
gas rate. The sulfur content is expressed in weight percent.
The mass rate emission factor is determined to be 0.02 S kg
S02/kg fuel (0.02 S Ib SO2/lb fuel), where S is the sulfur con-
tent in percent by weight. This is approximately equivalent to
5.3 S to 7.7 S g S02/kWh (8.7 S to 13 S Ib SO2/103 hp-h).
3.1.3 Control Measures
3.1.3.1 NO Control--
X
Wet control techniques--Because formation of NO is ex-
• —LJ - ,/V
tremely sensitive to flame temperature, injecting water or steam
22
into the reaction zone will reduce production of NO . In
X.
full-scale field operations reductions of up to 70 to 90 percent
have been achieved at water-to-fuel (w/f) ratios of 1.0 and
reductions of 50 to 70 percent have been observed at w/f ratios
from 0.5 to 0.7, as shown in Figure 3.1-5.23 Industry readily
24
accepts this technique for control of NO . One manufacturer
X
guarantees an NO emission limit of 75 ppm at 15 percent stack
25 X
gas oxygen.
For distillate-fuel-fired turbines, one EPA test shows the
highest reduction of 85 percent, from 315 ppm to 58 ppm N0x (w/f
ratio of l.l).26 Another EPA test showed the lowest concentra-
tion of about 26 ppm NO , inlet concentration 163 ppm, and 84
J*.
percent efficiency in the stack gas of a liquid-fuel-fired tur-
97
bine at a water-to-fuel ratio of 1.1. For natural-gas-fired
turbines the highest reduction in one source test was from 110
ppm to 13 ppm NO (88 percent) at a w/f ratio of 1.0. This
X
facility also yielded the least NO emissions (13 ppm) with wet
. , 28 X
controls.
Water-to-fuel ratios above 1.0 do not decrease the formation
of NO substantially. Water and steam injection have essentially
J\
the same effect on NO emissions. The overall gas turbine ef-
2^
ficiency is reduced by about 1 percent at a w/f ratio of 1.0,
3.1-10
-------
o
-=>
o
90
80
70
60
50
40
30
20
10
D NATURAL GAS
O LIQUID FUEL
/
o
o0o
/ o
/
/DO o
/
o
D
0 0.2
0.4 0.6 0.8
WATER/FUEL RATIO
o
o
o
1.0 1.2
Figure 3.1-5. Effectiveness of water/steam injection
in reducing NOX emissions.1°
3.1-11
-------
29
corresponding to about a 5 percent increase in fuel consumption.
This control technique is considered to be the best system of emission
reduction to achieve NSP standards for NO on turbines with capacities
J\.
greater than 10.7 gigajoules per hour of heat input. This is equivalent to
o
approximately 0.75 MW (10 hp) output capacity. Manufacturers estimate that
30
3 years will be required to incorporate wet controls for smaller units.
Dry control techniques--Dry control techniques consist of operational or
design modifications that govern the conditions of combustion to reduce NO
2\.
formation. In full-scale turbine applications, some dry methods have reduced
31
NO emissions by more than 40 percent.
A.
Although dry NO control techniques have not been adequately demon-
.K-
strated on full-scale turbines, research and development efforts with
combustor rigs (models) indicate NO reductions of up to 94 percent may be
.X.
possible by various combustion modifications. These methods have not been
incorporated in production turbines.
Table 3.1-4 indicates the degree of NO reduction achieved with various
X.
dry methods on combustor rigs. Some of these methods have reduced
emissions on full-scale engines by about 40 percent. These data represent
the potential of efficient dry control methods which may not be developed for
30
production turbines until 1982.
Combined wet and dry control methods—Emission tests showed the best
performance of combined wet and dry controls with a peaking gas turbine
using distillate fuel. Uncontrolled NOV was measured at 173 ppm at 15 percent
yC
O-. By combustion modification (lean primary zone), emissions were reduced
to 82 ppm (53 percent reduction). By water injection, emissions w^re
reduced to 34 ppm (80 percent reduction). By a combination of lean
combustion in the primary zone and water injection, NO emissions were
32
reduced to 16 ppm, corresponding to 91 percent reduction.
Catalytic control methods--Catalytic exhaust control consists of NOX
reduction by ammonia in the presence of a catalyst.
3.1-12
-------
Laboratory tests have demonstrated reductions of up to 98 per-
cent. Because this technique has not been demonstrated on
30
full-scale turbines,
method.
it cannot be considered as a LAER control
TABLE 3.1-4. N0x EMISSION REDUCTIONS BY DRY CONTROL
TECHNIQUES ON EXPERIMENTAL COMBUSTOR RIGS32
Technique
Lean burn, fuel-air mixing in full-
size combustor rig
Lean primary in half-size combustor
rig
Exhaust gas recirculation, half-
size combustor rig
Rig tests; premix, prevaporization,
staged combustion, lean burn
Lean primary, reduced residence
time in full-size combustor rig
Lean burn, premix, staged fuel and
air; full-size rig
Vortex air blast rig
NO reduction, %
X
12-44
15-20
30-38
35-61
40
51-60
94
3.1.3.2 S02 Control—
Because SO emissions from gas turbines are strictly a func-
tion of the fuel sulfur content (and essentially all sulfur is
converted to SO2), the only technique being used to control SO2
emissions from gas turbines is use of low-sulfur fuels. Flue gas
desulfurization (stack gas scrubbing) systems are economically
unattractive compared to the cost of low-sulfur fuel because of
the large gas volumes to be treated and the low SO2 concentra-
tions .
Sulfur content of distillate fuels used in gas turbines
commonly ranges from 0.01 to 0.48 percent by weight; sulfur in
3.1-13
-------
crudes ranges from 0.06 to 3.0 percent, and in residual oils from
17 1ft
0.5 to 3.2 percent. ' Some residual oils have much higher
sulfur contents, but these are unusable in gas turbines. Sulfur
17 18
content of natural gas may range from 0 to 0.1 percent. '
3.1.4 Emission Limits
3.1.4.1 NO Limits--
A.
Although a few state and local control agencies apply regu-
lations specifically to stationary gas turbines, most states
apply general standards to gas turbines. The most stringent SIP
limits on NO emissions applicable to gas turbines are 86 g
NO /GJ (0.2 Ib NO /106 Btu) input for gas-fired burners and 128
X X c 04 qc
g/GJ (0.3 Ib NO /10 Btu) for oil-fired burners. ' These
X.
standards, approximately equivalent to 50 and 75 ppmv, respec-
tively, are applied in eight states. Apparently the most strin-
gent of all state regulations is that of San Diego County,
California, which limits emissions to 75 ppmv and 42 ppmv at 15
percent oxygen when burning liquid and gaseous fuels, respec-
tively.36
The New Source Performance Standards (NSPS) for stationary
gas turbines are applicable to turbines whose peak load is equal
to or greater than 10.7 GJ/h (10 x 106 Btu/h) of heat input. The
emissions limit for NOx is 75 ppm by volume at 15 percent oxygen
and International Standard Organization (ISO) ambient atmospheric
conditions. The standard also includes an adjustment factor for
gas turbine efficiency and a fuel-bound nitrogen allowance.
emissions would be limited according to the following equation:37
NO
3.1-14
-------
STD = (0.0075 E) + F
STD = allowable NO emissions (percent by volume at
15 percent oxygen)
E = efficiency adjustment factor
= 14.4 kJ/Wh (13,600 Btu/kWh)
Actual ISO Actual ISO heat
heat rate rate
F = Fuel-bound nitrogen allowance
Fuel-bound nitrogen F
(percent by weight) (NO , percent by volume)
X
N <_ 0.015 0
0.015 < N <^ 0.1 0.04 (N)
0.1 < N <_ 0.25 0.004 + 0.0067 (N-0.1)
N > 0.25 0.005
The NSPS would allow an additional 50 ppm NOx attributable to
fuel N0x.
The most stringent of all NO regulations applicable to gas
X
turbines appears to be the 42 ppm limit of San Diego County for
gaseous fuels.
The lowest NO emission rate achieved in practice, based on
available data, is 13 ppm [21 g NO /GJ (0.05 Ib NO /106 Btu)
O fi
input] by an 88 percent reduction using water injection. An
NO concentration of 16 ppm has been achieved by combined wet and
X
dry control techniques with an efficiency of 91 percent.
3.1.4.2 S02 Limits--
State implementation plans limit the amount of sulfur in
fuels to 0.3 to 2.6 percent by weight, with an average of 1.0
38
percent. The most stringent 0.3 percent limit corresponds to
about 130 g S02/GJ (0.3 Ib S02/106 Btu) input.
New Source Performance Standards require SO- reduction to
150 ppm by volume, corrected to 15 percent oxygen, or a maximum
3.1-15
-------
39
fuel sulfur content of 0.8 percent by weight. The 150 ppm limit corre-
sponds to about 346 g SO2/GJ (0.8 lb/106 Btu) input.
The most stringent current SO^ regulation applicable to gas turbines
appears to be an SIP limit of 0.3 percent sulfur content of the fuel, corre-
sponding to 130 g SO2/GJ (0.3 Ib of SO2/106 Btu) input or about 56 ppm by
volume.
3.1.4.3 Most Stringent Limits--
The most stringent NO limit is the San Diego 42 ppm limit, and the
most stringent SO2 limit is the SIP and NSPS maximum of 0.3 weight percent
sulfur content in liquid fuels and essentially zero for natural gas.
3.1.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
3.1-16
-------
3.1.5.1 LAER for NO —
.X.
The recommended LAER guidelines for NO emissions from stationary gas
.A.
turbines are based on the lower NO emission concentrations achieved in
X
practice by wet control techniques. In addition a turbine efficiency factor
and an allowance for the fuel nitrogen content is incorporated into the LAER
guideline.
The controlled NO concentrations achieved by wet techniques are indi-
X
cated in Figure 3.1-6. The broken line indicates the baseline LAER at 50
ppmv NO at 15 percent oxygen. Since NO emissions increase with turbine
X X
efficiency, a turbine efficiency factor is included so as not to penalize energy
efficient operations. This efficiency factor was developed under the NSPS
studies. It is computed as follows,
„„. . ,. . p 14.4 kJ/watt-h
Efficiency factor, E = ^ r—T~- =j rTLnA .—.
lower heating value (.LHVJ neat
input per unit of power output
The fuel-bound nitrogen allowance is incorporated in the LAER since fuel
NO is not effectively controlled by wet control techniques. Hence, if a
X
turbine firing low nitrogen content fuel and having a control efficiency of 90
percent was required to switch to a fuel having a higher nitrogen content,
the NO control efficiency would decrease. The fuel-bound nitrogen allow-
X
ance concept was developed under the NSPS and would equally apply for the
LAER guideline. A maximum increase of 50 ppmv NO above the 50 ppmv
X
NO LAER baseline is suggested. This allowance is computed according to
X
the following method:
Fuel-Bound Nitrogen Allowance
(percent by weight) F
N < 0
0.015 < N < 0.1 0.04 (N)
0.1 < N < 0.25 0.004 + 0.0067 (N-0.1)
N > 0.25 0.005
3.1-17
-------
LEGEND
o WATER/FUEL RATIO
• NO WATER USED IN COMBUSTION
X WATER/FUEL RATIO UNKNOWN
J^U
300
280
260
240
c^ 220
»a
ir>
Z 200
(0
1 ^0
CO
§ 160
t— •
t/?
£ 140
X
0
z 120
100
80
60
40
20
n
GAS TURBINE
f
f
t
t
t
i
T
-1-
t
•+-
i"1.
To x'^
-•- To '
j- ! ^-3
rr^ i
o •
1 o 1
! i
«X>
' "1
O
1C
Vd
T^
t
r--
o-
^
— •
—
—
—
—
—
—
—
t
—
•
CNJ •
O • T
To f I
I ~j
i !
! "i
O • II
' o i A
I LTI 0
i— 'd nr
" "5° \~*>[if> \ ~\i i"
o r^ 1 v 9
i !^ ! !
. Lrt....o^r^in' i — — ...
SIZE, MW °^---^"""g ^^5
FUEL TYPE [*- LIQUID FUEL (DISTILLATE) 4"~NATURAL GAS~H
LAER VALUE
3 Tests made on model combustor rigs rather than in the field
Figure 3.1-6. Summary of NOX emission data .„
from gas turbines using wet control techniques.
(Taken from field or engine tests except where noted.)
3.1-18
-------
Like the proposed NSPS, the measured NOx emission rate is corrected to
15 percent oxygen and ISO conditions. ISO conditions are defined as stan-
dard ambient conditions of 1 atmosphere pressure, 60 percent relative humid-
ity, and 288°K.
The recommended LAER guidelines for NOv emissions are stated as the
.A.
following:
NOX = [0.0050 (E) + F]
where: NO = NO emission LAER at 15 percent O~
XX "
E = Efficiency factor, above
F = Fuel-nitrogen allowance, above
3.1.5.2 LAER for S02~-
The LAER for SO2 is recommended to be the emission rate associated
with firing liquid fuels containing a maximum of 0.3 percent by weight sulfur.
This is approximately equivalent to 50 ppmv SO2 or 130 g/GJ (0.3 lb/10 Btu)
and is based on the most stringent SIP regulation. The LAER for gaseous
fuels would be essentially no SO2 emissions.
3.1-19
-------
REFERENCES
1. Standard Support and Environmental Impact Statement Volume I:
Proposed Standards of Performance for Stationary Gas Turbines.
EPA-450/2-77-017a, U.S. Environmental Protection Agency. Office of Air
Quality Planning and Standards. Research Triangle Park, North
Carolina. September 1977. p. 3-2.
2. EPA-450/2-77-017a, p. 3-1.
3. Analysis of the Cost and Benefits of Nitrogen Oxide Emission Control in
Proposed Johnsonville and Gallatin Gas Turbines. Tennessee Valley
Authority. Muscle Shoals, Alabama. November 1974.
4. EPA-450/2-77-017a, p. 3-13.
5. EPA-450/2-77-017a, p. 3-37.
6. Scott Research Laboratories, Inc. Turbine Exhaust Emissions Measured
at Facilities of New York Power Pool. Prepared for General Applied
Science Laboratories. Report No. SRL 1378-01-0374. March 1974. p.
9-28.
7. EPA-450/2-77-017a, p. 3-43.
8. EPA-450/2-77-017a, p. 3-45.
9. EPA-450/2-77-017a, Table 3.8. and pp. 3-46 to 3-49.
10. Dilmore, J.A., and W. Rohrer. Nitric Oxide Formation in the
Combustion of Fuels Containing Nitrogen in a Gas Turbine Combustor.
ASME 74-GT-37. April 1974. p. 3.
11. General Electric Corporation. Advanced Combustion Systems for
Stationary Gas Turbines Proposal in response to EPA, RFP Number
DU-75-A182. May 8, 1975. p. 15.
12. EPA-450/2-77-017a, p. 3-73.
3.1-20
-------
13. Dilmore and Rohrer (1974), p. 2.
14. General Electric (1975), pp. 18-19.
15. Johnson, R.H., and F.C. Wilhelm. Control of our Turbine Emissions in
the World Environment. General Electric Company. 1974. p. 11.
16. General Electric (1974), p. 19.
17. Personal communication from E.W. Zeltmann, General Electric, to D.
Walters, EPA, June 15, 1973.
18. Burnes Fuel Oils. Mineral Industry Survey. Petroleum Products
Survey Number 71. U.S. Department of Interior, Bureau of Mines.
1972.
19. Johnson, R. and C. Wilkes. Comments of the General Electric Gas
Turbine Products Division on the Impact of Fuel-Bound Nitrogen on the
Formation of Oxides of Nitrogen from Gas Turbines. January 28, 1974.
p. 5.
20. EPA-450/2-77-017a, Appendix C.
21. EPA-450/2-77-017a, p. 4-7.
22. EPA-450/2-77-017a,
23. EPA-450/2-77-017a, Table 4-14 and p. 4-27.
24. EPA-450/2-77-017a, p. 4-24.
25. Personal communications between R.H. Gaylord, Turbodyne Corporation,
to D.R. Goodwin, EPA. Section F. December 19, 1975.
26. EPA-450/2-77-017a, Appendix C, Table 45,
Facility Code FA. p. C-69.
27. EPA-450/2-77-017a, Appendix C, Table 47,
Facility Code HAl. p. C-71.
28. EPA-450/2-77-017a, Appendix C, Table 48,
Facility Code HA2. p. C-72.
29. EPA-450/2-77-017a, p. 4-36.
30. Stationary Gas Turbines. Standards of Performance for New Stationary
Sources. Federal Register, Part III. October 3, 1977. p. 53,784.
3.1-21
-------
31. EPA-450/2-77-017a, p. 4-96.
32. EPA-450/2-77-017a, Appendix C. Table 37. Facility Code Z2. p. C-57.
33. EPA-450/2-77-017a, Table 4-11. p. 4-91.
34 Dibelius N.R., and R.J. Ketterer. Status of State Air Emissions
Affecting Gas Turbines. General Electric. ASME Publication.
73-Wa/GT-8. 1973.
35. Duncan, L.J. Analysis of Final State Implementation Plans - Rules and
Regulations. APTD-1334. pp. 69-65.
36. San Diego Air Pollution Control District. Rules and Regulations. Rules
68, 50, 52, and 62. February 1972.
37. EPA-450/2-77-017a, pp. 1-1 to 1-2.
38. Duncan, APTD-1334, pp. 58-63.
39. EPA-450/2-77-017a, p. 1-3.
40. EPA-450/2-77-017a, p. 8-21.
3.1-22
-------
3.2 MAJOR SOURCE CATEGORY: KRAFT PULP MILL LIME KILNS, POWER
BOILERS (BARK AND COMBINATION) FOR PARTICULATE ONLY; RE-
COVERY FURNACE FOR SULFUR DIOXIDE ONLY
3.2.1 Process Descriptions^
3.2.1.1 Kraft Pulp Mill—
The Kraft chemical wood pulping process involves the extrac-
tion of cellulose fibers, or "wood pulp," from the wood by dis-
solving and removing the lignin that binds the cellulose fibers
together. The pulp is suitable for making paper, paperboard, and
building materials. More than 80 percent of the chemical wood
pulp made in the United States is produced by the Kraft method,
which can be used with almost any wood species, requires a rela-
tively short time period to complete delignification, does not
degrade the valuable cellulose and hemicelluloses in the wood as
badly as other chemical pulping processes, and permits recovery
2
of a high percentage of the cooking chemicals.
Figure 3.2-1 is a flow sheet of typical Kraft pulp mill
operations showing the recovery and recycling of the valuable
sodium salts. Pulpwood logs are debarked and chipped (not
shown), and the chips are fed into a continuous digester counter-
current to a fresh chemical stream (called white liquor) con-
taining about 21 percent active chemicals, of which three quar-
ters is sodium hydroxide and one quarter is sodium sulfide in
water solution. The digester is held at 7.03 to 9.49 kg/cm2 (100
to 135 psig) and 170° to 175°C (338° to 347°F).3 Time required
for the cooking cycle is from 1 hour for unbleached brown pulp to
3
as much as 5 or 6 hours for pulps that are to be bleached. The
cooking process causes formation of malodorous sulfide gases,
such as hydrogen sulfide, methyl mercaptan, and dimethyl sulfide.
Venting of these gases gives a kraft mill its typical sour odor.
The contents of the digester exit through a "blow tank,"
where steam and noncondensibles are flashed-off, and cooked chips
3.2-1
-------
H2S, CH3SH, CH3SCH3,
AND HIGHER COMPOUNDS
CHIPS
CH3SH, CH3SCH3, H2S
ac.
UJ
I—
tx>
U)
I
NJ
RELIEF
T s-u.cu ru-cru-, Ho<;
HEAT
EXCHANGER
NONCONDENSABLES
,i t , ,
,
NONCONDENSABLES
SEPARATOR
BLOW
TANK
1/1
z
Ul
Q 1— .
z
o
o
H.W.
ACCUM.
Y
TURPENTINE
CONTAMINATED WATER
STEAM, CONTAMINATED WATER,
CONTAMINATED *H2S, AND CH3SH
• WATER
AIR
PULP
SPENT AIR,
AND CH3SSCH3
OXIDATION
TOWER
ON
!
1
i
ac.
o
I—
o
D-
UJ
t
BLACK LIQUOR
50% SOLIDS,,
DIRECT CONTACT
EVAPORATOR
WATER
RECOVERY
FURNACE
OXIDIZING
ZONE
REDUCTION
CAUSTICIZER
\
t t
GREEN
LIQUOR
LSMELT ZONE]
NazS + Na2C(
IH™
Figure 3.2-1. Typical kraft sulfate pulping and recovery process.
-------
are sent to a filter that separates the pulp from the spent cooking liquor,
now called "black liquor." The pulp passes on for further refining and
possibly bleaching before it is pressed, dried, and sold as pulp or made into
paper or other products.
Satisfactory economics for the Kraft process require efficient recovery of
sodium and sulfur values from the black liquor, as depicted on the flow
sheet. The organic sulfides, also called "reduced sulfur" or "mercaptans,"
are often oxidized as an air pollution control measure to render them less
volatile and thus diminish loss when a direct contact evaporator is used in
subsequent steps. The black liquor is then concentrated to 50 percent solids
in a multiple-effect evaporator and pumped to the recovery furnace.
At the recovery furnace the black liquor is concentrated to 70 percent
combustible solids, in the case of direct contact evaporation, by counter-
current flow against hot combustion gases from the furnace. If good
oxidation is obtained upstream, this unit will emit only small quantities of
volatile reduced sulfur compounds.
The black liquor concentrate is sprayed into the recovery furnace,
where the carbon from the wood is burned, the remaining water is
evaporated, and the sodium is changed to molten sodium carbonate or sodium
sulfide. These molten salts, or "smelt," are redissolved in water to form
"green liquor," then are clarified and causticized with lime.
The calcium carbonate resulting from causticizing is filtered from the
"white liquor" and is passed on to an oil- or gas-fired kiln. Entering the
kiln at 35 percent moisture, the calcium carbonate is dried and then
decomposes at about 1300°C (2370°F) to calcium oxide and carbon dioxide.
The "white liquor" is recycled to the digester.
3.2.1.2 Lime Kiln—
The lime kiln is essential to the system of recycling caustic soda for
reuse in digestion. It receives lime "mud" or calcium carbonate and burns it
to quicklime (calcium oxide), which, after being slaked, is allowed to react
with sodium carbonate in the green liquor to make the caustic soda.
3.2-3
-------
Most lime kilns used by pulp mills are of the rotary type and are
constructed of refractory-lined steel. They are 2.4 to 4 m (8 to 13 ft) in
diameter and 38 to 122 m (125 to 400 ft) long.4 They are inclined, and the
lime mud is fed into the elevated end, where it contacts the counterflow of
combustion gases from an oil- or gas-fired burner located at the opposite
end. The kiln rotates slowly, at about 0.5 to 1.0 rpm. As it moves down
the inclined kiln, the mud dries, agglomerates into pellets, and finally is
calcined into calcium oxide in the hot zone of the kiln. The fresh, hot lime
pellets are discharged at the lower end of the kiln and usually are slaked
immediately.
The lime kiln has several major limitations. It is not efficient in the use
of heat; the burnt lime product may vary widely in its subsequent, reactivity;
and unless the sodium content of the mud is kept at 0.25 percent or higher,
large loose balls or rings of lime adhere to the inner surface of the kiln and
cause stoppages. Efforts have been made to improve the energy efficiency,
the reactivity of the lime product, and the operability of the unit by flash-
drying the mud ahead of the kiln or by calcining it in a fluid-bed unit in
which time-temperature relationships can be controlled closely. Flash-dried
mud enters the kiln at about 10 percent moisture. Tests run at a kraft mill
in Albany, Oregon, indicated that feeding "dry mud" doubled the drying
capacity of the kiln, produced a more reactive lime product, and reduced lime
emission losses to 10 percent.7 Fluid-bed calciners are in limited use, but
their production rates are relatively low, about 20 to 140 Mg/day (25 to 150
tons/ day).4 Another development, the use of oxygen to boost kiln output,
should decrease the amount of dust carryover per ton of burnt lime produc-
tion, because it is claimed that lime production increases 25 percent in a kiln
retrofitted for oxygen enrichment. The fuel requirements per increased ton
of lime output are about half that required with air alone. Advantages are
reduced fuel requirement and reduced gas volume per ton of burnt lime and
the attendant reduction of emissions.
3.2-4
-------
3.2.1.3 Power Boilers (Bark and Combination)--
Kraft pulp mills use about 5 Mg of steam per megagram of air-dried pulp
(ADP) (5 tons steam per ton of ADP).9 Before 1960 nearly all of this steam
was made at the mill in conventional oil-, gas-, or coal-fired boilers. Wood
waste materials, including bark, shavings, sander dust, log yard cleanup,
and sawdust (often called "hogged fuel"), were burned in a tepee burner,
which gave no heat recovery, had no combustion controls, and emitted large
amounts of particulate. By 1973, 88 of 273 mills had at least one power boiler
that could burn wood bark.
Bark is difficult to burn. Depending on its source, it may contain a
large percentage of ash and abrasive sand and as much as 50 percent water.
Bark requires a higher temperature than conventional fuels for good combus-
tion; if it is charged wet, it must remain in the combustion zone long enough
for the water and volatiles to boil off before it ignites.
Bark char is very light, about 1/6 the weight of water. It occurs as
round, flat flakes, which have a large surface to mass ratio and readily
12
become entrained with the combustion gases. Recent theoretical studies
indicate that at normal flue gas velocities, char of certain particle sizes does
13
not burn out in a conventional furnace and is always carried over.
3.2.1.4 Recovery Furnace--
Figure 3.2-1 shows the position of the recovery furnace in the chemicals
recovery process. Black liquor of 40 percent to 55 percent solids content
from the multiple-effect evaporators is concentrated to as high as 70 percent
solids in a direct-contact evaporator heated by recovery furnace flue gas.
This direct-contact evaporator may be a cyclonic or venturi-type liquid-gas
contactor, or it may be a cascade evaporator. Depending on the pH and
temperature of the black liquor, this contactor can remove appreciable
quantities of residual SO^ from the flue gas.
The black liquor concentrate is sprayed into the combustion zone of the
furnace, where the organic materials burn. The chemicals, chiefly sodium
salts, melt and are accumulated on a shallow hearth at the base of the
furnace. The molten salts, or smelt, are subsequently dissolved in water to
3.2-5
-------
form green liquor, which is causticized to white liquor and recycled to the
digesters.
The recovery furnace in a large, modern kraft mill can supply a major
fraction of the process steam needed [as much as 5 Mg/Mg ADP (10,000 Ib/ton
ADP)]. It is also a major source of emissions,, both particulate and the
malodorous reduced sulfur compounds.
3.2.2 Emissions
3.2.2.1 Lime Kiln Particulate Emissions--
The rolling and tumbling action of lime mud in a rotary kiln and the
vaporization of sodium compounds in the high-temperature zone cause most of
the particulate emissions. Lime dust is made up of particles ranging from 1 to
100 urn in diameter; soda fume is very small and less than 1 [m in diameter.
Thus, lime particulate is relatively easy to remove and soda fume is very
difficult to remove. Because sodium is held at less than 0.5 percent of the
feed material, soda fume constitutes a minor percentage of the particulate
generated, but its small particle size makes it a major contributor to
emissions.
Stack emission data for 66 controlled and uncontrolled lime kilns were
reported by 35 mills in 1973.16 The data have limited value since the methods
used to determine emissions are unknown. Averages for the 10 lowest and 10
highest emitters are given in Table 3.2-1. Reference 1, the source of most of
the data, does not specify the type of fuel or the control equipment, if any,
3.2-6
-------
TABLE 3.2-1. LIME KILN PARTICULATE EMISSIONS
U)
•
to
I
-J
Lower 10 emitters1
Average
Range
Higher 10 emitters17
Average
Range
NSPS, Sept. 24, 1976
Gas fuel
Oil fuel
Emission factor
Untreated
Scrubber
Emission concentration.
g/m'1 , dry
0.08a
0.02-0.21a
2.70a
0.57-9.163
0.15
0.30
(gr/dscf )
(0.037)a
(0.01-0.09)3
(1.18)a
(0.25-4.0)3
(0.065)
(0.130)
Weight rate, of
emission ,
kg/Mg ADP
0.1
0.037-0.26
5.9
2.59-21.5
22.5
1 .5
Ratio of flue gas rate
to pulp production,
m!, dry/Mg ADP/day
0.91
1 .72
(scfm/ton ADP)
(29)
(55)
Explanation of abbreviations:
g/m3, dry is grams of particulate per dry standard cubic meter of exhaust gas.
gr/dscf is grains of particulate per dry standard cubic foot of exhaust gas.
kg/Mg ADP is kilograms per megagram of air-dried pulp.
m3 , dry/Mg ADP/day is dry standard cubic meters per minute per megagram of air-dried pulp per day.
Method of stack test unknown.
Equivalent to pounds per 1000 pounds ADP.
-------
used by each of the reporting mill operators. It can be assumed
that many of the large emitters were older mills using inadequate
control equipment. These data are now about 5 years old; prob-
ably the larger emitters have now modified their kiln systems to
reduce emissions. Table 3.2-1 also shows that the higher emit-
ters vent nearly twice the flue gas per unit weight of air-dried
pulp produced.
3.2.2.2 Power Boilers (Bark and Combination), Particulate
Emissions--
Emissions from bark-fired (hogged-fuel) boilers and boilers
burning combinations of bark plus oil, gas, or coal are chiefly
ash and unburned wood particulate. Emissions also include some
"tramp" sand caught in the bark during logging and transport of
the pulpwood. This sand has little visibility in the stack gas,
but it does contribute weight. Coal used as an auxiliary fuel
will contribute fly ash the same as if the coal were burned
alone. Neither oil nor wood contains appreciable ash. Because
of the low density and airfoil shape of wood fuels, it is easy
for certain sizes of wood-carbon particulate, perhaps incandes-
cent, to be swept out the stack.
The type of auxiliary fuel used probably affects particulate
emissions: tests at one mill showed that the combination of
natural gas and bark gave the lowest emissions, followed in order
18
by oil and coal.
Review of the recent literature on hog-fueled boilers indi-
cates that although no single design optimizes emissions, certain
design and operational practices can help reduce them. These
include predrying of wood fuel, control of fly ash reinjection,
and proper adjustment of overfire and underfire air, which are
discussed more fully in the Controls section.
Uncontrolled emissions from power boilers range from 25 to
37.5 g/kg of bark fired (50 to 75 Ib/ton).
3.2-8
-------
3.2.2.3 Recovery Furnace, S02 Emissions—
As shown in Figure 3.2-1, flue gases from the recovery fur-
nace in a typical kraft pulp mill go to a direct-contact evapor-
ator and the combined vapors then go to an electrostatic precipi-
tator prior to discharge. To date, operators have shown little
concern about S02 emissions from the recovery furnace. Even
though concentrations of S02 from the recovery furnace may be as
high as 700 to 800 ppm, the contact evaporator usually reduces
this to 50 to 100 ppm before the gas reaches the stack. Atten-
tion has been focused on emissions of total reduced sulfur (TRS)
and of particulate, which apparently are considered much more
serious. Most of the literature on control of recovery boiler
effluents deals with these two kinds of emissions.
Emissions of S0« from recovery furnaces are a function of
operating parameters, as discussed in the Controls section.
3.2.3 Control Measures
3.2.3.1 Lime Kiln Particulate—
Wet scrubbers, usually venturi or impingement-type, are the
most common devices used in the kraft pulp industry to control
19
lime kiln particulate emissions. The venturi scrubber is more
efficient (97 to 99%), but it requires a higher pressure drop
[2.5 to 7.5 kPa (10 to 30 in. H,0)] than the impingement-type
20
scrubber [1 to 2 kPa (4 to 8 in. H20)].
Three process changes (described briefly at page 3.2-4) are
reported to be effective in reducing lime kiln emissions. The
predrying of lime mud before calcination, the use of oxygen to
boost lime kiln output and fluid-bed calcination reportedly
reduce lime losses per unit of throughput, provide energy sav-
ings, and increase production. None of the literature indicates
that all of these steps have been applied together in a single
operating mill. Such modifications would be most feasible at new
installations and are worthy of consideration in devising an
overall control methodology for a new lime kiln facility.
3.2-9
-------
EPA Method 5 tests on lime kilns have shown that emissions
can be controlled to 0.07 g/m3, dry (0.03 gr/dscf) on a gas-fired
unit21 and to 0.21 g/m3, dry (0.09 gr/dscf) on an oil-fired
unit.22 The control devices in both instances were venturi
scrubbers with pressure drops in the range of 5 to 6 kPa (20 to
24 in. of water).
3.2.3.2 Power Boilers (Bark and Combination) Particulate
Control--
In general, current practice is to control bark-fired and
combination-fired boilers by the use of dry mechanical cyclones
as the primary control device, followed by a scrubber, baghouse,
electrostatic precipitator or granular filter (dry scrubber) for
secondary control. Because the use of bark-burning boilers is
relatively new to the paper industry and involves some unusual
12
combustion problems, the variety of secondary control devices
in use is not surprising. In combination boilers, the auxiliary
fuel and furnace design also affect selection and performance of
the secondary control device.
In addition to the add-on control devices, certain practices
in the design of the bark furnace and in the preparation of bark
fuel can reduce the loading in the exhaust stream:
0 Design for temperature of the combustion zone to be
maintained at or above 1093°C (2000°F) to improve
burning of the wood carbon.
0 Reduce flue gas velocity, and hence the entrainment of
very light wood particles, by careful control of excess
air. Predrying the wood also reduces particle reen-
trainment, and it reduces the moisture content of the
fuel.
0 Control particle-size range of freshly hogged wood fuel
and of reinjected fly ash so that these materials will
not pass through the furnace without burning. The
quantity of particles sized below 0.3 mm should be
limited.
3.2-10
-------
As noted earlier, the furnace design must take into account
the control devices to be used. For instance, if a baghouse is
proposed, care must be taken to ensure against incandescent
particles reaching the bags and damaging them. Electrostatic
collectors may achieve desired performance only when coal is
fired with the bark. The average of emissions from the five
best-controlled combination bark-fuel boilers (data for 26 units
reporting in 1973) was 3.9 g/Mg (7.8 Ib/ton) of bark fired.
These values are equivalent to 0.17 g/GJ (0.4 lb/10 Btu) or 0.4
g/m3, dry (0.18 gr/dscf). As indicated in Table 3.2-2, various
control technologies have reduced emission rates markedly since
1973. Table 3.2-2 also illustrates the general effect on emis-
sions when gas, oil, and coal are used as auxiliary fuels.
3.2.3.3 Recovery Furnace, Sulfur Dioxide Emissions Control--
A number of variables in recovery furnace operation can
affect SO,., emissions. One investigator has shown how control of
turbulence, secondary air, and spray-droplet size can reduce SO,.,
27
in recovery furnace flue gas to near zero. Another has found
that simply holding excess oxygen to 3 percent reduces S0~ levels
28
to 25 ppm. One theoretical study points out that very small
changes in sulfur or sodium emissions inside the furnace can give
29
rise to very large excursions in SO., concentration. A series
of tests showed that SO, emissions from a recovery furnace could
30
be held at 50 to 100 ppm. Concentrations of SO2 ranged from 5
to 100 ppm in combined exhausts from the recovery furnace and
31
contact evaporator at a North Carolina mill. Measured SO2
emissions in the furnace exhaust ranged from 0 to 200 ppm (55 ppm
32
average) at an Alabama mill. A summary of these literature
citations indicates that the following operating conditions tend
to minimize S02 emissions:
0 Holding excess oxygen at or above 3 percent
0 Injection of large spray droplets of black liquor in
the furnace
3.2-11
-------
TABLE 3.2-2. PARTICULATE EMISSIONS FROM POWER BOILERS (BARK AND COMBINATION)
Fuel
Bark and coal
Bark and gas
Bark and oil
Bark and coal
Bark
Bark
Bark
Bark and oil
Bark
Bark and oil
Barkb
Controls
Cyclone, ESP
Multicyclones
and
wet scrubber
Fabric filter
Multicyclones/scrubber
Multicyclones/venturi
Cyclone/wet scrubber
Granular filter
(dry scrubber)
Granular filter
(dry scrubber)
Granular filter with
electrostatic mode
Average emissions,
g/m3 , dry
0.026
0.032
0.126
0.137
0.069
0.032
0.037
0.059
0.105
0.158
0.018
(gr/dscf )
(0.012)
(0.014)
(0.055)
(0.06)
(0.03)
(0.014)
(0.016)
(0.026)
(0.046)
(0.069)
(0.008)
Reference
(date)
23
(1978)
18
(1974)
24
(1978)
25
(1978)
26
(1978)
60 to 65 percent coal, 35 to 40 percent bark.
Full-sized demonstration unit operated on a portion of the exhaust stream
from a 100 percent bark-fired boiler.
-------
0 A high percentage of solids in the liquor
0 A ratio of sulfur to sodium below 0.5:
0 High turbulence at the secondary air inlet ports
Recent information on factors that affect SC>2 emissions from
kraft recovery furnaces indicate that sulfidity plays a dominant
role.33'34 Lower sulfidity levels (20 to 24 percent) have ad-
verse effects on pulp quality and increase safety problems;
medium levels (25 to 30 percent) allow these problems to be
averted, and sulfidity levels in excess of 31 percent sharply
increase S09 emissions. This information indicates that optimum
^
process control—limiting sulfidity levels to 30 percent and
keeping furnace operating conditions close to optimum—will keep
the 24-hour average emission rate below 250 ppm and the monthly
average rate to about 100 ppm.
The possibility of using flue gas desulfurization (FGD) to
34
reduce SO9 emission levels from recovery furnaces was examined.
^
It was concluded that available FGD systems have successfully
controlled sources having gas volumes and S02 concentrations
comparable to those of kraft recovery furnaces; FGD is therefore
considered "available technology." Although no detailed cost
analysis was made, capital cost was estimated to be about
$5000/ton per day of furnace capacity, and annual cost was esti-
mated to be $1600/ton per day of furnace capacity.
In summary, recovery furnace operating conditions can in-
fluence SO2 emissions, and optimization of operating conditions
will curtail these emissions. The sulfidity level plays a major
role: the higher the sulfidity, the greater the SO2 emissions.
The type of pulp or paper manufactured affects the sulfidity
level in the process. For lower-sulfidity pulp, attentive con-
trol of sulfidity levels (optimum process control) results in
minimum S02 emissions. Flue gas desulfurization has been used to
control sources comparable to recovery furnaces in gas volume and
3.2-13
-------
concentration; therefore EPA considers FGD to be "available
technology" for the control of S09 emissions from recovery fur-
^
naces. On recovery furnaces operating at high sulfidity levels,
FGD offers a means of reducing S02 emissions.
3.2.4 Emission Limits
This section summarizes emission limitations categorized by
state implementation plans (SIP), new source performance stan-
dards (NSPS), and achieved-in-practice (AIP) levels for lime
kilns, power boilers, and recovery furnaces.
3.2.4.1 Lime Kiln, Particulate Emissions—
The NSPS for lime kilns in Kraft pulp mills are set at 0.15
and 0.30 g/m3, dry (0.067 and 0.134 gr/dscf) for gas- and oil-
fired units, respectively. These are approximately equivalent to
0.27 and 0.59 kg/Mg ADP (0.54 and 1.08 Ib/ton ADP).
In six states having major Kraft pulp producers, the SIP
limit for particulate emissions from lime kilns is the same and
is the most stringent of all the SIP limits. This limit is 0.5
kg/Mg ADP (1.0 Ib/ton ADP), equivalent to 0.28 g/m , dry (0.122
gr/dscf), with distinction regarding the type of fuel fired.
Thus, the SIP limit for oil-fired kilns is slightly more strin-
gent than the NSPS.
The lowest AIP emission levels are well below SIP and NSPS
limits. Emissions from gas-fired lime kilns have been controlled
to 0.07 g/m3, dry (0.03 gr/dscf). Oil-fired kilns have been
controlled to 0.21 g/m3, dry (0.09 gr/dscf).
3.2.4.2 Power Boilers, Particulate—
No NSPS have been promulgated for bark-fired boilers serving
kraft pulp mills.
The most stringent SIP limitation is that of Florida: 0.047
kg/GJ input (0.1 lb/106 Btu input), which is roughly approximated
as 0.09 g/m3, dry (0.04 gr/dscf).
3.2-14
-------
The BACT level proposed by EPA Region X is 0.09 g/m , dry
(0.04 gr/dscf). This BACT proposal is based on a fabric filter
installation on a hogged-fuel power boiler for which tests have
ns
22
o
indicated particulate emissions of 0.069 g/m , dry (0.03 gr/dscf)
with 100 percent bark-firing.
The AIP levels vary with the type of fuel or fuel combina-
tions fired and the control device applied. Information suffi-
cient for full definition of the relationship and impact of
varying fuels and fuel combinations on emission levels is not
available. Table 3.2-3 reflects the better AIP levels that have
been reported. These AIP levels appear to be significantly lower
than SIP or NSPS limitations.
3.2.4.3 Recovery Furnace, SO_ Emissions—
^
No NSPS are applicable to SO2 emissions from recovery fur-
naces.
Although SIP's do not specifically limit S02 emissions from
recovery furnaces, they do contain regulations covering all new
sources. The most stringent SIP limits are 300 ppm SO2, typical
of California and Oregon regulations.
The BACT level proposed by EPA's Region VI is 250 ppm SO
£*
for the paper mill at Morrilton, Arkansas, including the recovery
furnace.
The lowest AIP levels from recovery furnaces, achieved by
optimizing process conditions, have been 0 to 25 ppm SO,,; excur-
sions to 100 to 200 ppm are common, however, even under these
optimum conditions.
The AIP levels are significantly lower than SIP or BACT
limits. It is not known whether SO2 emissions from most recovery
furnaces can be reduced to the lowest SIP levels. AIP levels
cannot be compared directly with SIP or BACT limits, since the
latter include all emissions from the paper mills.
3.2-15
-------
3.2.5 Determination of Lowest Achievable Emission Rate (LAER)
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
The LAER levels recommended for each process pollutant are based on
AIP emissions. These recommendations are summarized in Table 3.2-3.
TABLE 3.2-3. RECOMMENDED LAER FOR KRAFT PULP MILL PROCESSES
Process
Pollutant
Recommended LAER
Lime Kilns
Gas-fired
Oil-fired
Power Boilers
Auxiliary gas-fired
Auxiliary oil-fired
Auxiliary coal-fired
100% bark-fired
Recovery Furnace
Particulate
Particulate
Sulfur
dioxide
0.07 g/nu, dry (0.03 gr/dscf)
0.21 g/m , dry (0.09 gr/dscf)
0.032 g/m., dry (0.014 gr/dscf)
0.059 g/rru, dry (0.026 gr/dscf)
0.026 g/nu, dry (0.012 gr/dscf)
0.032 g/m , dry (0.014 gr/dscf)
50 ppmv daily average
100 ppmv - 3 hour maximum
3.2.5.1 Lime Kiln, Particulate--
The recommended LAER values are based on achieved-in-practice levels.
The suggested value for gas-fired kilns is 0.07 g/m3, dry (0.03 gr/dscf) and
3.2-16
-------
for oil-fired units, 0.21 g/m3, dry (0.09 gr/dscf). The literature reports
process changes such as predrying of lime muds, use of oxygen, and
fluidized-bed calcination could provide benefits in the form of energy conser-
vation, production increase, and emission reduction. Such process changes
should be considered along with a high-pressure-drop venturi or another
equally effective device when devising an overall control strategy to attain
the lowest achievable emission rate.
3.2.5.2 Power Boilers (Bark and Combination), Particulate--
The fuel or fuel combination fired affects the quantity of paniculate
emissions from power boilers, the type of control used, and the performance
of that control. Although available stack test data are insufficient to define
this relationship fully, the reported AIP levels provide a basis for LAER
determinations. The suggested LAER values are as follows: for 100 percent
bark fired boilers, 0.032 g/m3, dry (0.014 gr/dscf); for gas/bark-fired,
0.032 g/m3, dry (0.014 gr/dscf); for oil/bark-fired, 0.059 g/m3, dry (0.026
gr/dscf); and for coal/bark-fired, 0.026 g/m3, dry (0.012 gr/dscf).
Depending on fuel composition and fuel mix, a LAER value more or less strin-
gent than that suggested may be appropriate on a case by case basis.
3.2.5.3 Recovery Furnace, S02"
It is recommended that LAER be set at a maximum value of 50 ppm by
volume on a daily average basis, with excursions allowed to 100 ppm over a
period of no more than 3 hours in any 24-hour period. Pulp or paper manu-
facturing of the low-sulfidity type can meet this or a lower limitation by
attentive control of process variables. Operation at high sulfidity levels may
require the application of FGD technology in addition to optimum process
control to meet the LAER limitation.
3.2-17
-------
REFERENCES
1. Atmospheric Emissions from the Pulp and Paper Manufacturing
Industry. EPA-450/1-73-002, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina. September
1973. p. 5.
2. Casey, J.P. Pulp and Paper, Chemistry and Chemical Tech-
nology; Volume I: Pulping and Papermaking. Interscience
Publishers, Inc., New York. 1952. pp. 133-167.
3. Casey (1952). p. 145.
4. EPA-450/1-73-002. p. 53.
5. Casey (1952). pp. 172-3.
6. Wenzl, H.F.J. Kraft Pulping, Theory and Practice. Lockwood
Publishing Co., Inc., New York. 1967. pp. 124-126.
7. Wenzl (1967), p. 125.
8. Oxygen Boosts Kiln Output. TAPPI,60(11). November 1977.
pp. 37-8.
9. Shreve, R.N. The Chemical Process Industries, McGraw-Hill
Book Company, Inc., New York. 1945. p. 705.
10. Effenberger, H.K., et al. Control of Hogged-Fuel Boiler
Emissions, A Case History. TAPPI,56(2): 111-115. February
1973. p. 111.
11. EPA-450/1-73-002. pp. 77-79.
12 Barren, A.J. Studies on the Collection of Bark Char
Throughout the Industry. TAPPI, 53(8 ) -.1441-1448. August
1970. p. 1441.
13 Adams, T.N. Particle Burnout in Hog Fuel Boiler Furnace
Environments. TAPPI,60(2):123-125. February 1977. p. 135.
14. EPA-450/1-73-002. p. 21.
3.2-18
-------
15. Compilation of Air Pollutant Emission Factors, 2nd Edition,
AP-42, Part A. U.S. Environmental Protection Agency, Re-
search Triangle Park, North Carolina. May 1974. pp. 10,
1-5.
16. EPA-450/1-73-002. p. 55.
17. EPA-450/1-73-002. p. 92-93.
18. Kutyna, A.G., et al. Combination Fuel-Boiler Particulate
Emission Control Pilot Studies. TAPPI,57(9):139-143. Sep-
tember 1974. pp. 141-143.
19. EPA-450/1-73-002. p. 12.
20. EPA-450/1-73-002. p. 54.
21. Air Pollution Emission Test. Project No. 74-KPM-17. U.S.
Environmental Protection Agency. Office of Air Quality
Planning and Standards, Emission Measurements Branch, May
1974.
22. Air Pollution Emission Test. Project No. 74-KPM-19. U.S.
Environmental Protection Agency. Office of Air Quality
Planning and Standards, Emission Measurements Branch,
September 1974.
23. Personal communication with Nick Burkholtz. State of
Virginia EPA Office, Richmond, Virginia. March 13, 1978.
24. Personal communication with Larry Sims. EPA Region X
Office, Seattle, Washington. March 13, 1978.
25. Wood Residue-Fired Steam Generator Particulate Matter Con-
trol Technology Assessment. EPA 450/2-78-044, Office of Air
Quality Planning and Standards, U.S. Environmental Protec-
tion Agency, Research Triangle Park, North Carolina.
October 1978. p. 16.
26. Combustion Power Company. Stack test data on dry scrubber
installations. 1346 Willow Road, Menlo Park, California.
January 1979.
27. Thoen, G.N., et al. Effect of Combustion Variables on the
Release of Odorous Compounds from a Kraft Recovery Furnace.
TAPPI, 51(8):329-333. August 1968.
28. Walther, J.E., and H.R. Amberg. A Positive Air Quality
Control Program at a New Kraft Mill. Air Pollution Control
Association, 20(1):9-18. January 1970.
3.2-19
-------
29. Borg, A., et al. Inside a Kraft Recovery Furnace - Studies
on the Origins of Sulfur and Sodium Emission. TAPPI,
57(1):126-128. January 1974.
30. Blue, J.D., and W.F. Llewellyn. Operating Experience of a
Recovery System for Odor Control. TAPPI, 54(7):1143-1147.
July 1971.
31. Fluharty, J.R. Progress in Air and Water Pollution Abate-
ment in a 65-Year Old Mill. TAPPI, 58(5):83-85. May 1975.
32. Lange, H.B. Jr., et al. Emissions from a Kraft Recovery
Boiler - the Effects of Operational Variables. TAPPI,
57(7):105-109. July 1974.
33. Improved Air Pollution Control for a Kraft Recovery Boiler:
Modified Recovery Boiler No. 3. EPA 650/2-74-071a, U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina. August 1974.
34. Internal EPA memo, E.J. Vincent to R.O. Pfaff, Region IV,
regarding BACT for SO9 from Kraft mills. June 8, 1977.
3.2-20
-------
3.3 MAJOR SOURCE CATEGORY: ELECTRIC ARC FURNACES AT STEEL
FOUNDRIES AND GRAY IRON FOUNDRIES; PARTICULATE, ONLY:
CHARGING (AND BACKCHARGING AT STEEL FOUNDRIES) AND TAPPING.
3.3.1 Process Description
Castings made of iron or steel are solid solutions of iron and carbon to
which various amounts of alloying elements have been added. The carbon
content of the finished casting is what distinguishes iron from steel; irons
typically contain 2 to nearly 4 percent carbon, whereas steels contain less
than 2 percent carbon.
' The direct arc furnace is widely used today in both iron and steel
foundries. The furnace is usually charged with solid scrap, iron, or steel,
although molten pig iron from a blast furnace or prereduced iron pellets
sometimes form part of the charge. An electric arc furnace (EAF) is a cylin-
drical refractory-lined vessel, above which are suspended three carbon elec-
trodes that can be lowered through the furnace roof to a position above the
charged materials. These electrodes can be retracted, and the furnace roof
can be rotated aside to permit charging. Alloying agents and slagging mate-
rials are usually added through doors in the side of the furnace. Once the
charge is in place, the electrodes are lowered into the furnace and current is
switched on. Arcing of current from the electrodes into the scrap generates
heat to melt the scrap.
When the charge is melted and the temperature is adjusted, the slagging
operation is begun. In slagging, the carbon and oxygen contents are adjusted
to the values desired for the iron or steel product. Molten slag is withdrawn
from the furnace and various elements are added—carbon to the iron and
possibly iron oxide to the steel.
When the desired chemistry has been achieved, the electrodes are lifted
out and the furnace is tilted as much as 45 degrees towards the ladle that
receives the furnace charge. The hot steel or iron is then poured from the
ladle into holding furnaces or directly into sand molds, from which, after
cooling, the rough casting is taken for cleaning, possibly annealing, and
other finishing operations. Figure 3.3-1 shows the process flow in a typical
3.3-1
-------
2
iron foundry that uses an EAF as the melting vessel. Except for the
cupola, which is not used in a steel foundry, Figure 3.3-1 also represents the
process flow in a steel foundry.
3.3.2 Emissions
Production of steel or of gray iron for castings from an EAF is a batch
process in which the following steps generate significant emissions:
1. Charging the furnace. Scrap metal is the major mate-
rial, plus additives such as "carbon raiser," ferro
silicon (for gray iron), and limestone and coke (for
steel). The roof is open.
2. Meltdown operations. These include unscheduled occur-
rences such as "cave-ins" of unmelted material from the
furnace walls into the molten pool and "pulling bot-
tom," which is undesired boring into the furnace bottom
by electrodes lowered too far. This category also in-
cludes scheduled operations such as "backcharging"
(usually for steel), which is the addition of a large
quantity of additional scrap to the molten bath imme-
diately after the first charge is partially melted.
The roof is closed during meltdown; charging doors, or
the roof itself, is opened during "backcharging."
3. Oxygen lancing, in steelmaking furnaces only. The roof
is closed.
4. Slagging, refining, and "working the heat," during
which the steel or iron is brought to the proper com-
position and temperature. Some alloy steels require a
second or reducing slag, which must be accomplished
with minimum induction of air. The roof is closed; the
furnace is tilted to remove slag.
5. Reestablishment of the arc after an interruption. The
roof is closed.
6. Tapping of the metal into a ladle. The roof is closed;
the furnace is tilted.
3.3-2
-------
METALLICS
U)
OJ
I
FLUXES
FINISHING
DUST
PARTICIPATE
l\0 \ O) EMISSIONS
METAL
MELTING -L
•A'(./i EMISSIONS
CASTING
SHAKEOUT
COOLING AND
CLEANING
CORE
MAKING
SAND
PREPARATION
Figure 3.3-1. Iron foundry process flow and emission sources.
-------
In the following discussion the distinction between iron and
steel foundries is made only when the EAF emissions differ sig-
nificantly. During melting and refining, uncontrolled particu-
late emissions from iron furnaces range from 2 to 20 kg/Mg (4 to
40 Ib/ton) of iron charged and average 7.0 kg/Mg (14 Ib/ton).
The emission rates from steel furnaces are reported to average
8.0 kg/Mg (16 Ib/ton) charged. Emission factors for charging and
tapping are not available. Based on extrapolation of limited
emission test data, charging and tapping emissions together
account for 10 percent of the total uncontrolled emissions (0.7
kg/Mg for iron and 0.8 kg/Mg for steel furnaces). These values
assume alloying takes place in the ladle. Charging and tapping
are estimated as about 5 percent of total furnace emissions when
no alloys are added to the ladle.3 It is to be noted that emis-
sions may vary considerably as a result of furnace type and age,
the kinds of scrap processed, the additives to the melt, and the
types of iron or steel products.
Rotation of the furnace roof to the side during charging
renders ineffective all of the close-coupled evacuation systems
during this period of intense emissions. Most of these emissions
are due to oil on the scrap, sand embedded in the recycled cast-
ings, and miscellaneous organic materials and dirt. Tests of the
effects of cleanliness and quality of scrap on intensity of emis-
sions have shown that emissions doubled when dirty, low-quality
scrap was used.4 When a 5-ton-per-heat gray-iron EAF was charged
with scrap wetted to 1 weight percent with oil, more than 9 kg
(20 Ib) of soot and dust was emitted in a short time. Emissions
during charging and tapping of a steel furnace are perhaps 10
percent of the total. In contrast, emissions during charging and
tapping of a gray iron EAF can be 5 percent of the total. Emis-
sions during tapping are usually negligible unless alloying in
2
the ladle is practiced.
During meltdown the charge is rapidly brought up to tempera-
ture; all remaining oil and some volatile nonferrous metals such
3.3-4
-------
as lead, zinc, and magnesium are expelled. "Cave-ins" and "pulling bottom"
can exacerbate these meltdown emissions beyond the volume capacity of the
ventilation system. Since the roof covers the furnace during this period,
however, adjustment of electrode positioning and of power input should hold
the emissions to a level that is controllable by a well-designed ventilation and
particulate capture system. In "backcharging," which is common practice
with steel EAF's, the cold metal scrap produces a violent eruption when it
hits the molten pool, and the amount of pollutants generated at this time is
probably higher than at any other time during the heat. Because charging
doors must be opened, or the entire roof rotated away, capture of these
intense emissions is incidental.
Oxygen lancing, used in steel furnaces, helps remove carbon and accel-
erates the melting process. Although oxygen generates gaseous emissions of
carbon monoxide and carbon dioxide and increases the potential for particulate
emissions, the practice of careful control of oxygen rate (to maintain the
correct chemistry of the heat) and keeping the furnace roof closed during
lancing should minimize escape of particulates. Near the end of the lancing
period, some iron oxidizes to a highly visible, fine red fume that is most
difficult to capture. During the peak of oxygen lancing, the emission rate
has been measured at 2 to 3 times that occurring during average furnace
operation.
Slagging is done once per heat in producing gray iron, but may be
required twice to make certain alloy steels. This second slagging must be
done with minimum inleakage of air, i.e., ventilation must be stopped or
heavily restricted within the furnace. During this period, fumes escape
upward through the electrode holes and into the foundry building bay area.
Emissions during the first slagging are less pronounced (via the electrode
holes). They are more pronounced in furnaces with direct shell evacuation
than on furnaces with side draft hood evacuation. The operations of refining
and working the heat, which are combined with the second slagging, are done
principally in producing steel castings where standards for soundness and
strength of the casting are very high. Because this step involves only slight
temperature changes and very little reaction, emissions are of moderate inten-
sity. During the period of no furnace ventilation, slagging presents emission
problems.
3.3-5
-------
At any time during the operation the arc may be lost, for such reasons
as shutoff due to a preset "demand limiter," mechanical failure, or faulty
positioning of the electrodes. If the arc can be reestablished quickly, this
loss has slight effect on emission level, since the roof is closed and the melt
is hot. If the bath must cool, however, striking the arc again will vaporize
metal and cause a surge of very high particulate. Minimizing arc inter-
ruptions is the best means of preventing such emissions.
Tapping iron and steel is done with the power off, the electrodes lifted,
and the furnace tilted. During the pouring of iron or steel, very fine partic-
ulate escapes as sparks or fume along the flowing stream of hot metal. These
emissions are negligible in gray iron production, but perhaps because of the
much higher temperatures needed for steel [200°C or (390°F)], they can be
at least as severe as those during charging. Treatments such as deoXidation
or special alloying are often done while the molten metal is poured or is in the
ladle and can cause violent emissions of short duration.
3.3.3. Control Measures
Control of air pollution at an iron or steel foundry is a function of the
efficiency of two operations:
1 Capture and containment of particulate-laden gases as
they are generated at the furnace or at the ladle.
2 Treatment of the captured, particulate-laden gases in a
control system to remove the particulate material.
Methods and equipment for capture of pollutants are described in
Reference 2. Important among these methods is the use of large canopy
hoods which are positioned over the open furnace and over an open ladle
during charging and during tapping/alloying in the ladle. While the lid is on
the furnace, either a roof or side-draft hood on the furnace roof or a direct
furnace evacuation system on the furnace roof is used. The canopy hoods
must be located precisely so as to maximize pollutant capture and minimize the
total amount of air pulled into the hood with minimal interference to operation
of the overhead crane, charging buckets, and other equipment. Some means
of eliminating crosscurrents of air, such as a shroud enclosure around part of
the furnace, improves the efficiency of the canopy hoods.
3.3-6
-------
Hoods must be designed to maximize pollutant capture with low air inleak-
age and without creating significant operational and maintenance problems.
Direct shell evacuation, or "fourth-hole," systems are effective and simple,
allowing minimal inleakage. Roof hoods and direct shell evacuation are alter-
native controls, although roof hoods are no longer being installed. These
systems for pollutant capture have been available and in use for many years
in both iron and steelmaking.
Side-draft hoods mounted on the furnace roof are used with gray iron
2
and smaller steel foundry furnaces. One side is open to provide maintenance
access to the electrodes. These hoods are effective in collecting fumes
escaping via the electrode holes. This type of hood does require larger
exhaust volumes than do roof hoods or direct furnace evacuation systems, but
these larger volumes reduce temperature at the control device and assure
complete combustion of carbon monoxide.
Fabric filter collectors (baghouses) are regarded as the most efficient
and versatile device for removal of particulates in the exhaust from EAF's.
Major control system components consist of an exhaust fan, a cooler to reduce
the temperature of the hot gases so that they will not damage bag fabrics,
and a baghouse. Filter velocities are as low as 1.1 cm/s (2.1 ft/min) and as
t;
high as 1.3 cm/s (2.55 ft/min). Wet scrubbers and electrostatic precipitators
appear applicable to EAF particulate control, but neither device has been
2
widely used by U.S. foundries.
A number of process and/or equipment changes have been proposed that
o
would reduce emissions and in some cases save energy. These include a
closed charging system, preheating of scrap to drive off oil and moisture, a
hooded charge bucket, a hooded tapping ladle, degreasing of scrap, and the
use of an enclosure around the furnace. Of these, only the enclosure or
shroud has been tried in the United States, and this installation is on steel-
c
making furnaces of 60-ton capacity.
3.3.4 Emission Limits
1. Standards of Performance for New Stationary Sources
(NSPS), Electric Arc Furnaces in the Steel Industry; Federal Register,
3.3-7
-------
Tuesday, September 23, 1975. These standards apply to steelmaking only,
and not to foundries using electric arc furnaces. The following pertinent
sections of this NSPS for steelmaking provide a reference point for emission
limits from foundries.
"...no owner or operator....shall cause to be discharged...
from an electric arc furnace any gases which:
(1) Exit from a control device and contain particulate
matter in excess of 12 mg/dscm (0.0052 gr/dscf)
(2) Exit from a control device and exhibit 3 percent
opacity or greater.
(3) Exit from a shop and, due solely to operations of any
EAF's, exhibit greater than zero percent shop opacity
except:
(i) Shop opacity greater than zero percent, but less
than 20 percent, may occur during charging peri-
ods.
(ii) Shop opacity greater than zero percent, but less
than 40 percent, may occur during tapping peri-
ods."
Identical standards were adopted by California South Coast (12-3-1976)
and California Bay Area for facilities modified or built after October 21, 1974,
again for electric arc steelmaking and not for steel or iron foundries.
Figure 3.3-2 illustrates the relationship of emission limits on EAF's as
specified in NSPS and in the state regulations of California, Pennsylvania,
and New Jersey. For comparison purposes, it shows the achieved-in-practice
(AIP) emission levels at six steel and six iron foundries. ' The values
represent particulate concentration (g/m3, dry) in the exhaust from the con-
trol device. In Figure 3.3-3 the data are presented on the basis of mass
emission rate (kg/h). The figures indicate that most AIP values, especially
at production rates of 10 Mg/h, are lower than either the SIP requirements or
NSPS for steelmaking.
3.3-8
-------
0.048
Of\A C
.U4o
-o 0.044
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* O-.
o<0.022
>-. CO
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SoO.016
itA nJ
££0.014
-J Od
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M 2 0.012
. ^,
Sc 0.010
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0.008
0.006
0.004
0.002
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O
0 0458 SIP LIMITS FOR CALIF.. N.J., AND PA.
-
7
^_
_
o
A
NSPS; U.S. AND CALIFORNIA FOR STEELMAKING EAF'S "
0.012 (DOES NOT APPLY TO FOUNDRIES)
^ O
O
A O
-
A
A A
A O STEEL FOUNDRY AIP .
° A IRON FOUNDRY AIP
1 1 __!_ 1 1 —
10 15 20
HOT METAL POURED, Mg/h
25
30
Figure 3.3-2. Particulate concentration
versus production rate.
15,
10
CO
CO
CJ
I—
ce.
1
O STEEL FOUNDRY AIP
A I RON FOUNDRY AIP
PROPOSED LAER, EQUIVALENT TO
0.05 kg/Mg METAL POURED
10 15 20
HOT METAL POURED, Mg/h
25
30
Figure 3.3-3. Particulate emissions by weight
versus production rate.
3.3-9
-------
The lowest AIP emission levels discovered in preparing this guideline for
both iron and steel foundries were those reported in Reference 7. All test
results reported here were based on EPA Method 5.. This reference reports
an AIP value of 11.0 mg/m3, dry (0.0048 gr/dscf) for a new iron foundry.
At a second and newer foundry having an EAF and control system design that
was based on the experience of the first, the test results showed 8.9 mg/m ,
dry (0.0039 gr/dscf) at the control device outlet. In both instances the
EAF's were equipped with side-draft hoods and hoods above the pouring
spout and slag door. Reference 7 reports the lowest achieved values for
steel EAF control systems to be 5.74 mg/m3, dry (0.0025 gr/dscf) and 6.63
mg/m3, dry (0.0029 gr/dscf). The capture system for both steel foundry
EAF's was by direct shell evacuation. The control equipment at the iron and
steel foundry EAF's reported here was a fabric filter device.
3.3.5 Determination of Lowest Achievable Emission Rate (LAER)
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is particu-
larly necessary when addressing modified or reconstructed facilities subject to
the provisions of Section 173 of the Clean Air Act. Emission limitations reason-
able for new sources may in some instances be economically or technically
unreasonable when applied to modified or reconstructed sources of the same
type.
On the basis of the reported AIP levels, the suggested LAER ^s 9.2
mg/m3, dry (0.004 gr/dscf) for iron foundry EAF's and 6.9 mg/m , dry
3.3-10
-------
(0.003 gr/dscf) for steel foundry EAF's. These values represent the average
emission limit over a complete furnace cycle, which includes charging,
melting, slagging, and tapping. Because the volume of exhaust per ton of
molten metal varies with the capture device used, the suggested LAER limits
are in terms of control device outlet concentration rather than mass emission
rate.
3.3-11
-------
REFERENCES
1. McGannon, H.E. The Making, Shaping and Treating of Steel,
United States Steel, Ninth Edition. 1971.
2. Georgieff, N.T., and F.L. Bunyard. An Investigation of the
Best Systems of Emission Reduction for Electric Arc Furnaces
in the Gray Iron Foundry Industry. (Draft) U.S. Environ-
mental Protection Agency, Research Triangle Park, North
Carolina. October 1976. Ch. 3,4,6.
3. Air Pollution Control Techniques for Electric Arc Furnaces
in the Iron and Steel Foundry Industry. Guideline Series.
EPA 450/2-78-024, U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards. June 1978.
p. 2-16.
4. Coulter, R.S. Smoke, Dust, Fumes Closely Controlled in
Electric Furnaces. The Iron Age, 173:107-110, January 14,
1954.
5. Georgieff, N.T. Addendum to: An Investigation of the Best
Systems of Emission Reduction for Electric Arc Furnaces in
the Gray Iron Foundry Industry to Include Electric Arc
Furnaces in the Steel Foundry Industry. (Draft) U.S. Envi-
ronmental Protection Agency, Research Triangle Park, North
Carolina. 1976. pp. 3-6, 4-1 to 4-7, Cl-4.
6. Attachment to trip report, Lone Star Steel Company, Lone
Star, Texas. EPA Contract No. 68-01-4143. Sept. 14, 1977.
7. EPA 450/2-78-024, pp. A-l, A-ll.
3.3-12
-------
3.4 MAJOR SOURCE CATEGORY: PETROLEUM REFINERIES CATALYTIC
CRACKING UNIT AND LIQUID FUEL BURNING--SULFUR DIOXIDE
EMISSIONS
3.4.1 Process Description
3.4.1.1 Catalytic Cracking—
Catalytic cracking is a high-temperature, low-pressure pro-
cess that converts certain heavier portions of crude oil primar-
ily into gases, gasoline blend stocks, and distillate fuels.
Feedstocks to catalytic cracking units are gas oils from atmos-
pheric or vacuum crude oil distillation units, thermal cracking
units, lube oil extraction and dewaxing units, coking units, or
deasphalting units. Catalytic cracking units are normally oper-
ated to produce a maximum of gasoline blend stocks, but the units
are very flexible and operating conditions can be varied to
maximize other products.
As of January 1, 1978, catalytic cracking capacity in the
3
United States as reported in the Oil & Gas Journal was 788,050 m
(4,956,682 bbl) per stream day. Two types of catalytic cracking
processes are in use today: (1) the fluid process, which uses
powdered catalyst, and (2) the Houdry and Thermafor Catalytic
Cracking (TCC) processes (in limited use), which use a pelletized
catalyst. Of the 285 U.S. petroleum refineries, approximately
124 contain fluid catalytic cracking units, 17 contain TCC facil-
ities, and 3 contain Houdriflow units.
A fluid catalytic cracking unit is composed of three basic
sections: cracker, regenerator, and fractionator. As shown in
Figure 3.4-1, the cracking reactions take place continuously in
the cracking section, with the spent catalyst being continuously
regenerated and returned to the cracking section. Both the
cracking and regeneration sections operate on the fluidization
principle, which makes possible a continuous flow of catalyst as
well as hydrocarbon feed. Gas oil feedstock is mixed with the
hot catalyst and introduced into the cracker. Steam is added at
the base of the cracker to strip and purge the spent catalyst of
3.4-1
-------
FRACTIONATOR
u>
I
to
GAS
CRACKER
STRIPPING
STREAM
RECYCLE FEED
FRESH EAS/OIL FEED.
GASOLINE
LIGHT CYCLE OIL
RECYCLE FEED.
TOWER BOTTOMS _
PARTICULATE
CONTROL
DEVICE
^
CO BOILER
1
GAS
COOLER
COMBUSTION AIR
Figure 3.4-1. Generalized schematic of a fluid catalytic cracking unit.
-------
adsorbed hydrocarbons. The hydrocarbon products are withdrawn
from the top of the cracker and sent to a fractionator for separ-
ation into product streams.
The coke-laden spent catalyst is withdrawn from the base of
the cracker and transferred to the regenerator. A controlled
amount of air is introduced into the regenerator with the cata-
lyst to burn the coke, which reheats the catalyst. The resulting
combustion gases are channeled through a series of cyclone
separators located inside the regenerator to remove most of the
entrained catalyst fines. The remaining catalyst fines can be
removed from the gases by electrostatic precipitators or a
third-stage cyclone separator outside the regenerator. The
regenerated catalyst is withdrawn from the bottom of the
regenerator vessel and returned to the cracker to complete the
cycle.
The hot flue gases, at about 538°C (1000°F) contain 5 to 10
percent carbon monoxide (CO), which generally is burned in a CO
or waste heat boiler to recover a considerable amount of energy.
The CO boiler is located either upstream or downstream of the
electrostatic precipitator. If the CO boiler is downstream of
the electrostatic precipitator, the flue gas must be cooled to
less than 315°C (600°F) in a cooler before entering the electro-
static precipitator. Gases leaving the CO boiler are discharged
to the atmosphere and can be a source of air pollution.
The hydrocarbon product vapors leaving the fluid catalytic
cracker are sent to a fractionator for the first separation of
products into gases, gasoline, and cycle oils. These streams are
further separated in the refinery as needed. Typical operating
ranges and yields for a fluid catalytic cracker are as follows:
3.4-3
-------
Temperature, °C (°F) 460° to 524°C (860° to 975°F)
Pressure, kPa (psig) by 68.9 to 172.4 kPa (10 to 25 psig)
Catalyst/oil ratio by wt. 4:1 to 20:1
Gasoline yield, vol. % of feed 35 to 50
Coke formation, wt. % of feed 4 to 12
Dry gas formation, wt. % 7 to 11
Conversion of feed to lighter
products, vol. % 60 to 90
Coke content of spent catalyst,
wt. % 0.25 to 2.3
Regenerator:
Temperature, °C (°F) 566° to 740°C (1050° to 1300°F)
Pressure, kPa (psig) 6.9 to 172.4 kPa (1 to 25 psig)
Coke content of regenerated
catalyst, wt. % 0.10 to 0.50
Hydrocarbon cracking deposits a small portion of the feed on
the catalyst in the form of coke. Likewise, some sulfur origi-
nally present in the feed is deposited on the catalyst. The
amount of sulfur varies with the type of feed, rate of recycle,
steam stripping rate, type of catalyst, cracking temperature, and
other factors.
The amount of hydrocarbon that remains on the spent catalyst
as it leaves the cracker is important for safe operation of
catalytic cracking units. Essentially all coke-forming compounds
are removed in the regenerator by air oxidation. The oxidation
reaction is highly exothermic and results in a temperature in-
crease in the regenerator. Excessively high temperatures in the
regenerator can be detrimental to the catalyst and also can cause
afterburning downstream of the regenerator, which may lead to
severe damage of cyclones and auxiliary equipment. Oxidation of
coke is accomplished with an amount of air that is insufficient
for complete combustion so that only a portion of the carbon is
oxidized to carbon dioxide. Usually the volume ratio of carbon
dioxide to carbon monoxide is maintained between 1 and 2. The
carbon monoxide in the flue gas from the regenerator is then
burned to carbon dioxide to recover the remaining energy for
steam generation. When CO boilers are used to recover heat in
3.4-4
-------
conjunction with the catalytic cracking unit, supplemental fuel
is usually provided. The type and amount of fuel used to supple-
ment the carbon monoxide will affect the type and amount of
pollutants emitted.
3.4.1.2 Liquid Fuel Burning—
When a refinery process requires a temperature higher than
that obtainable from the steam supply or any other available hot
stream, direct-fired furnaces are used. These furnaces or fired
heaters burn liquid fuels, refinery gases, or commercially avail-
able natural gas. The liquid fuels are reduced crude oils,
Bunker fuels, vacuum tower bottoms, No. 4 or No. 2 fuel oil, or
components comprising these fuels. Operators commonly limit the
use of the lighter distillate fuel oils because of their market
value and the need for special equipment for safe and efficient
combustion.
The number of applications for liquid fuel burning varies
among individual refineries, depending on processing complexity.
Liquid fuels are used typically in the furnaces for crude oil
atmospheric distillation, vacuum distillation, visbreaking,
catalytic cracking, coking, thermal cracking, solvent deasphalt-
ing, hydrotreating, catalytic reforming, and asphalt stripping.
Although refinery furnaces vary in shape and form, with various
burner and tube arrangements, they usually consist of two main
sections: the radiant section and the convection section. Some
unique problems may be associated with certain furnace designs
and special fuels such as those of low molecular weight.
3.4.2 Emissions
3.4.2.1 Catalytic Cracker—
Atmospheric emissions from catalytic cracking operations
have been measured by several investigators. The primary emis-
sions from catalytic cracking include sulfur oxides, nitrogen
3.4-5
-------
oxides, carbon monoxide, carbon dioxide, oxygen, water, nitrogen,
hydrocarbons, ammonia, cyanides, and participates.
Concentrations of sulfur oxides in regenerator flue gases normally range
from 150 to 3500 ppm. The concentration of sulfur oxides is a function of the
amount of sulfur in the coke present on the catalyst and the amount of air
used for regeneration. Because the amount of sulfur present on the spent
catalyst in the regenerator is a function of the sulfur level in the crude oils
and the processing of the feedstock before it reaches the cracker, the levels
of sulfur oxides emitted from the cracker can vary widely. Generally about
10 percent of the total sulfur in the reactor feedstocks remains with the coke
on the catalyst. This percentage increases to about 20 percent if the feed-
stock has been hydrodesulfurized or cracked in another process before being
2
fed to the catalytic cracker.
3.4.2.2 Liquid Fuel Burning-^
Potential pollutants from liquid fuel burning include nitrogen oxides,
carbon monoxide, particulate, and sulfur dioxide. The formation and emission
of pollutants in a furnace depend on the fuel, the operation of the furnace,
and the design of the firebox and burners. Because emissions of SO2 are
essentially determined by the sulfur in the fuel, they can be reduced by
firing fuels containing lower levels of sulfur but not by redesigning the
burners or the firebox.
A high sulfur fuel oil containing 4.0 percent sulfur by weight, when
fired in a furnace with 40 percent excess air, could produce a flue gas
containing about 0.18 volume percent SO2 or 1800 ppm by volume. A furnace
firing 0.3 percent sulfur fuel oil with 40 percent excess air would discharge
0.015 volume percent SO2 or 150 ppm by volume in the flue gas.
Either improper atomization of the fuel oil in the burner or provision of
insufficient air to burn the fuel oil completely will produce unburned carbon,
which is emitted as particulate matter. Excess air is required in all furnaces
to assure complete combustion, and thereby minimize carbon monoxide in the
flue gas, but high excess air rates reduce thermal efficiency. When fired
with liquid fuel oils, refinery furnaces operate with 30 to 50 percent air in
3.4-6
-------
excess of that theoretically required. When fired with natural gas, they use
only 10 to 25 percent excess air.
3.4.3. Control Measures
3.4.3.1 Catalytic Cracker Units--
Two types of control measures have been applied to control of SO- at
catalytic cracking operations: desulfurization of the cracker feed and flue
gas desulfurization (FGD) of the effluent from the regenerator.
A large research effort has been directed toward development of hydro-
desulfurization technology, and many processes applicable to catalytic
cracking feedstocks are available. Although hydrodesulfurization does reduce
the emission of SO2/ its use is limited for certain feedstocks. The degree of
desulfurization required to sufficiently reduce SO2 emissions involves such
severe conditions and such Jorge amounts of hydrogen that complete hydro-
desulfurization of feedstocks is not possible.
FGD is based on intimate contact between the flue gas and the liquid
droplets of the scrubbing solution. Over the past 15 years, many absorption
mediums and contactors have been tried. A system developed by a major oil
company consists of a dilute caustic stream in conjunction with a venturi
scrubber, which efficiently captures both the sulfur oxides and particulates.
The process is in commercial application at four major refineries located in
New Jersey, Louisiana, and Texas. The scrubber can be used on regen-
erators downstream of the waste heat boilers or after heat removal from a
high-temperature regenerator, providing adequate pressure drop is available.
The technology is offered for license, and reportedly two other commercial
installations are planned. No other scrubbing systems are known to be in
commercial use on catalytic cracker regenerators, but several FGD's are
installed on oil and coal fired boilers.
The mixture of gas and scrubbing solution droplets, after passing
through the venturi contactor, passes to a separator where clean flue gases
are separated from the scrubbing liquid. The vent gas is discharged to the
atmosphere. A purge liquid stream is removed to keep the circulating liquid
stream suitable for scrubbing. Purge stream treatment facilities are required
prior to effluent disposal.
3.4-7
-------
A commercial-scale FGD system on a cracker regenerator has been in
3
operation since March 1974. The design capacity of this unit is 141.6 m'/s
(300,000 cfm) of flue gas, and the unit has achieved an SO2 collection effi-
ciency above 95 percent. It has completed a 29-month run with no
problems.
3
To achieve the same levels of pollutant removal on a 12,719 m .(80,000
bbl) per day Gulf Coast fluid catalytic cracking unit processing a gas oil
containing 3.2 percent sulfur, the FGD system requires an investment .only
two-thirds of that required for combined hydrodesulfurization of the feed and
electrostatic precipitation of the flue gas. Annual operating costs are esti-
mated at half of the costs of hydrodesulfurization and electrostatic precip-
itation. The benefits to a refiner of products with lower sulfur contents are
not considered in these economic comparisons.
3.4.3.2 Liquid Fuel Burning--
The two methods available to reduce SO2 emissions are desulturization of
the fuel before combustion and FGD.
Reducing the sulfur content of fuel is practiced in some petroleum refin-
eries. To prepare low-sulfur-content liquid fuel acceptable to the home
heating market, refiners often desulfurize a distillate stream by the use of
hydrogen (hydrodesulfurization). To prepare heavier liquid fuels, marketed
with higher sulfur content, the same desulfurized distillate stream is often
blended with a residual stream to yield the desired products. Without blend-
ing, the high-sulfur-content residual stream would not be marketable.
Although the costs vary widely depending on the crude oil type, it is very
costly to prepare heavy fuel oils with less than 0.3 percent sulfur by weight
from any crude oil; thus most heavy fuel oils produced have sulfur contents
of 0.3 percent or higher. Only a small portion of the total production of
liquid fuels is burned in the refinery. By the burning of hydrodesulfurized
gas, oils and other distillate streams, a refiner can reduce the level of sulfur
oxides emitted from the furnaces. At the present time no FGD systems have
been utilized in the U.S. to control sulfur dioxide emissions from petroleum
refinery heaters and boilers. In Japan, FGD's are used extensively to
control SO2 emissions from oil-fired boilers and heaters.
3.4-8
-------
3.4.4 Emission Limits
3.4.4.1 New Source Performance Standards (NSPS) Limits--
NSPS require control of carbon monoxide and participate emissions from
fluid catalytic cracking unit catalyst regenerators and from FCC incinerator
waste heat boilers; there is no limit on SO- emissions from such units. In
regard to liquid fuel burning, NSPS have been enacted for SO0 emissions
fi
from fossil-fuel-fired boilers of more than 73 MW (250 x 10 Btu/h) heat input
rate. The NSPS limit for SO9 emissions from units of this size that fire
fi
liquid fossil fuels is 340 ng/J (0.80 lb/10 Btu) heat input. Refinery combus-
tion devices are generally exempt from this NSPS because of their smaller size
and/or because they are not used to generate steam.
3.4.4.2 State Implementation Plan (SIP) Limits--
Catalytic crackers--A search of SIP regulations and state laws revealed
no SO9 emission limits that apply specifically to catalytic cracker regen-
4
erators. In the absence of source-specific regulations for catalytic cracker
regenerators, applicable regulations are those that fall under such general
classifications as "other process sources," "noncommercial fuel," or "emissions
from fuel combustion operations." The most stringent state and local general
process regulations applicable to catalytic cracker regenerators are a New
Jersey regulation limiting emissions from noncommercial fuel to 312 ppm SO9 by
5
volume and a regulation of the Bay Area Air Pollution Control District, San
Francisco, California, (Regulation No. 2 3122) limiting concentrations to 300
ppm SO2 by volume.
Liquid fuel burning—Review of state regulations has shown wide
variation in the types of regulations, degree of stringency, and methods of
enforcing the limitation. In general SO9 emissions are limited by a regulation
restricting the quantity of SO9 emitted per unit quantity of heat input or by
one limiting the sulfur content of the fuel. In some states the regulations
specify maximum allowable ground-level concentrations resulting from emis-
sions. Many states have several forms of regulations, each applying to a
different fuel or type of source. Limits on the sulfur content in fuel oils for
3.4-9
-------
all purposes range from a low of 0.15 percent to a high of 4.4 percent by
weight. Most states differentiate the various grades of oil, allowing higher
sulfur contents in residual oils than in distillate oils. The most restrictive
regulation of fuel oil sulfur content is about 0.15 percent sulfur; this is a
regulation of Clark County, Nevada, which, however, has no petroleum refin-
ery. The most restrictive regulation applicable to an area (New Jersey) in
which refineries are operated is 0.2 percent sulfur in No. 2 and lighter
commercial fuel oils, and 0.3 percent sulfur in Nos. 4, 5, and 6 residual fuel
oils.
3.4.4.3 Achieved in Practice (AIP) Limit--
A commercial-scale FGD unit has demonstrated 95 percent removal of the
2
SO2 component in exhaust from a catalytic cracker regenerator. The diver-
sity of liquid fuel burning units and of the fuels they burn precludes deter-
mining an AIP limit for refinery furnaces. A general AIP limit would be 0.3
weight percent sulfur in fuel.
3.4.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
3.4-10
-------
3.4.5.1 Catalytic Cracking Unit--
The San Francisco Bay Area limitation of 300 ppm is the most stringent
regulation adopted to date. Compliance with this regulation can be achieved
with FGD on even the highest concentration of SO- anticipated in regenerator
flue gases. Additionally, the period of operation between turnarounds on an
FGD system has been demonstrated to be as long as the period between
turnarounds on catalytic cracker units, or longer. An FGD system can be
used on a waste gas stream from a high-temperature regenerator or a CO
boiler.
An alternative control measure applicable to most catalytic cracker feed-
stocks is hydrodesulfurization or the processing of low-sulfur feed stocks.
Application of this process is limited, however, because the degree of desul-
furization needed to conform with strict emission regulations is extremely high
relative to normal feedstock desulfurization requirements.
Therefore, it is concluded that the LAER for SO- emissions from cata-
lytic cracker regenerators is 300 ppm or a 95 percent by volume reduction of
the uncontrolled concentration from the source, whichever is less stringent;
this degree of control may be achieved by application of FGD or by other
equally effective methods.
3.4.5.2 Liquid Fuel Burning--
Although some industries are installing FGD systems on industrial-size
boilers and furnaces, none are yet installed in petroleum refineries. A petro-
leum refiner's primary business is production of marketable fuels that meet
Federal, state, and local regulations on sulfur or SO^ content. Because he
burns for for his own use only 2 to 6 percent of the fuel produced, the
refiner may be in a position to achieve a low emission rate by preparing and
burning low-sulfur fuels. Most other industries, lacking the capability to
produce their own fuel and to ensure a low-sulfur fuel supply, may have to
attain LAER by alternative means.
Alternatively, refiners are also in a better position than their customers
to install an FGD system and burn high sulfur residual oil. The furnaces at
3.4-11
-------
refineries are located near the process they serve and therefore are sometimes
scattered throughout the refinery property. The distance between furnaces
could require that separate systems be installed if FGD were chosen for
reduction of SO- emissions. New refineries can generally incorporate plans to
install fuel oil desulfurization equipment on a single stream, produce low-
sulfur fuel oil, and overcome the constraints involved in FGD application.
In summary, SO2 emission from liquid fuel burning is directly related to
the sulfur content of the fuel. The LAER for liquid fuel burning is that SO2
emission level equivalent to the use of fuel having 0.3 weight percent sulfur,
corresponding to approximately 150 ppmv SO-.
3.4-12
-------
REFERENCES
1. Annual Refining Survey. The Oil and Gas Journal, March 20,
1978.
2. Data compiled from files of Greene & Associates, Inc.
3. Fluid Catalytic Cracking Unit Flue Gas Scrubbing. Exxon
Technology Sales Bulletin, April 1977.
4. National Summary of State Implementation Plan Reviews (Sec-
tion 4 ESECA). EPA-450/3-75-053b. July 1975.
5. State Air Laws. Environmental Reporter, published by the
Bureau of National Affairs.
3.4-13
-------
3.5 MAJOR SOURCE CATEGORY: FABRIC COATING--VOLATILE ORGANIC
COMPOUND (VOC) EMISSIONS
3.5.1 Process Description
Fabric coating involves the coating of a textile substrate
to impart properties that are not initially present, such as
strength, stability, water or acid repellency, or appearance.
The fabric coating industry is diverse, with wide variations in
both products and plant sizes. The coated textiles are used in
industrial and electrical tapes, tire cord, utility meter seals,
imitation leathers, tarpaulins, shoe materials, upholstery fab-
rics, and rubber-coated fabrics.
Coating solutions may be either aqueous or organic based.
The latter produces organic emissions. It is estimated that 36
Gg/h (80 x 106 Ib/yr) of VOC is emitted in the United States by
the vinyl-coated fabric segment of the industry.
Figure 3.5-1 shows a typical fabric coating operation.
Milling and mixing of coatings are primarily restricted to coat-
ings containing rubber, and emissions are not considered signif-
icant.
Fabric is usually coated with a knife or a roller coater.
Both are spreading devices for high-speed application of coatings
to flat surfaces; the operations are very similar to the paper
coating techniques shown in Section 3.18, Figures 3.18-2 and
3.18-3.
In knife coating, probably the least expensive method, the
substrate is held flat by a roller and is drawn beneath a knife
that spreads the viscous coating evenly over the full width of
the fabric. Knife coating may not be appropriate with materials
such as certain unstable knit goods or in applications requiring
great precision in the coating thickness.
In roller coating, the coating material is applied to moving
fabric, in a direction opposite to the movement of the substrate,
3.5-1
-------
RUBBER
PIGMENTS
CURING AGENTS
SOLVENT
MILLING
MIXING
DRYING AND
CURING
COATING
APPLICATION
FABRIC
COATED PRODUCT
Figure 3.5-1. Typical fabric coating operation,
3.5-2
-------
by hard rubber or steel rolls. Roller coaters apply a coating of
constant thickness without regard to fabric irregularities.
Rotogravure printing is widely used in vinyl coating of
fabrics and is a large source of solvent emissions. Rotogravure
printing involves a roll coating technique in which the pattern
to be printed is etched on the coating roll with thousands of
tiny recessed dots. The recessed dots pick up ink from a res-
ervoir and transfer it to the fabric surface.
After being coated, the fabric is sent to drying ovens.
Typical drying ovens process fabric continuously, operating with
a web or conveyor feed system. Ovens can be enclosed or semi-
enclosed; depending on size, they exhaust from a few thousand to
tens of thousands of cubic feet per minute of air. Newer instal-
lations are reported to operate with exhaust concentrations up to
40 percent of the lower explosive limit (LEL). The oven heat
accelerates evaporation of the solvent and can produce chemical
changes within the coating solids to give desired properties to
the product. Many operators control evaporation rates to give
desired properties to the coated fabric. High air velocities
distribute heat uniformly over the fabric surface, facilitate
heat transfer to the coating and substrate (by minimizing the
laminar zone next to the the coated surfaces), and remove evap-
orated solvents from the oven at a rate that will prevent their
buildup to explosive levels.
3.5.2 Emission of Pollutants
The coating line, consisting of the coating application area
and drying oven, is the largest source of solvent emissions in a
fabric coating plant. It is also the most readily controllable.
The coater and the oven are both considered significant emitting
facilities. Some coating plants report that over 70 percent of
the solvents used within the plant are emitted from the coating
line. Other plants, especially those using vinyl coatings,
report that only 40 to 60 percent of the solvents purchased are
3.5-3
-------
emitted from the coating line. The remaining solvents are lost
as fugitive emissions from other stages of processing and clean-
up. Control techniques for fugitive sources include tightly
fitting covers for open tanks, collection hoods for areas where
solvent is used for cleanup, and closed containers for solvent
wiping cloths.
Solvent emissions from the coating applicator account for 25
to 35 percent of all solvent emitted from a coating line. This
solvent may be collected by totally enclosing the appliccitor in a
small room or booth and exhausting the booth to a control device.
Another method is to cover the applicator with a hood that can
collect most of the solvent emissions. Solvent emissions from
the ovens account for 65 to 75 percent of all solvent emitted
from a coating line. In most ovens, almost all the solvent
emissions are captured and vented with exhaust gases. On some
coating lines, emissions from the coating applicator hood are
ducted to the oven and included with the oven exhaust.
3.5.3 Control Measures
Although few fabric coating facilities have elected to con-
trol organic emissions, several technically feasible control
systems are available. These are carbon adsorption and incinera-
tion. Another approach to reducing organic emissions is to
switch to coatings with lower organic solvent content, such as
aqueous emulsion coatings.
As in the paper coating industry (Section 3.18), carbon
adsorption systems on fabric coating lines have been shown to be
97 to 98 percent efficient in controlling organic solvent vapors
that are drawn into the carbon bed.2' Control efficiencies are
limited somewhat by the inability to capture all emissions from
the coating application area. In paper coating operations,
recovery of the solvent introduced to the coating line has been
documented in the range of 96 percent. The similarity between
3.5-4
-------
fabric and paper coating lines suggests that this efficiency is
also achievable in fabric coating operations. ' The FACT docu-
ment pertaining to fabric coating suggests a minimum of 90 per-
cent efficiency for collection of coating line emissions.
Both catalytic incinerators and thermal incinerators (after-
burners) can destroy 95 to 99 percent of the organic emissions
introduced to them. As stated earlier, the overall facility
control is dependent on the solvent emission capture efficiency.
Although the use of afterburners in fabric coating plants has not
been documented, afterburner efficiencies of 98 to 99 percent
/:
have been obtained across the device. The same efficiencies
should also be achievable in fabric coating operations.
Although incineration consumes energy, recovery of heat can
eliminate or minimize this disadvantage. Fuel costs can also be
reduced by increasing the organic level in exhaust gases, i.e.,
by reducing dilution air.
As shown in Table 3.18-1 (paper coating), an overall reduc-
tion of 80 to 100 percent can be attained through the use of
coatings with inherently low levels of organic solvents. The
degree of reduction depends on the organic solvent contents of
the coating used originally and the new coating. No industry
contacts reported information from plants using low-solvent coat-
ings. Although some plants have converted to use of low-solvent
coatings, this action cannot be considered a universally ap-
plicable control measure. Coating line operations and fabric
specifications vary widely.
Several considerations affect the technical and economic
feasibility of organic emission control in the fabric coating
industry. Although the larger facilities may specialize in a
specific product, many plants produce a variety of products or
operate under contract to coat products to a customer's speci-
fications. The latter operators, often called "commission coat-
ers," must use a variety of coating formulations to comply with
3.5-5
-------
the customer's specifications. The resulting variations in
emissions present problems in the design of control systems.
Even if the operator knows the solvent compositions, exhaust
volume and controls must be based on the most critical or diffi-
cult situation. The number of solvents used also affects the
owner's ability to recover and reuse the solvent. Thus, the type
of coating is an important factor in the cost of controlling
emissions from a fabric coating plant.
3.5.4 Emission Limits
The initial criterion for defining LAER for a surface coat-
ing industry is the degree of emission control required by the
most stringent regulation adopted and successfully enforced by a
state or local air pollution control agency.
As reported elsewhere, most regulations of organic solvent
emissions are patterned after what is now Rule 442 of the South
7
Coast (California) Air Quality Management District. Review of
regulations in the 16 states that contain about 85 percent of all
surface coating industries showed them to be essentially the same
Q
as Rule 442. Indiana has the most stringent regulation in that
it limits organic solvent emissions to 1.4 kg/h (3 Ib/h) or 6.8
kg/day (15 Ib/day) unless such emissions are reduced by at least
85 percent, regardless of the reactivity or temperature of the
solvent. Organic solvents that have been determined to be photo-
chemically unreactive or that contain less than specified per-
centages of photochemically reactive organic materials are exempt
from this regulation.
The California Air Resources Board recently adopted a model
rule for the control of VOC emissions from paper and fabric
Q
coating operations. This model rule, which must be met 3 years
from the date of adoption, limits VOC emissions from the coating
line to 120 g solvent/liter (1.0 Ib/gal) of coating minus water.
This is to be accomplished by the use of add-on control equipment
3.5-6
-------
unless the solvent content of the coating used is no more than 265 g/liter
(2.2 Ib/gal) of coating minus water.
In the definition of LAER for surface coating emissions, it is not
appropriate to exempt solvents based on their reactivity. Recent research
has indicated that substituting low-reactivity solvents for higher-reactivity
solvents may improve photochemical oxidant air quality in one city while
worsening it in downwind regions.10 Accordingly, EPA has adopted a policy
emphasizing the need for "positive reduction techniques" rather than
Y
substitution of compounds.
Emission controls achieved in practice for fabric coating exceed
regulatory requirements by a wide margin. Therefore, it is concluded that
LAER for fabric coating is a function of controls achieved in practice rather
than controls required by current regulations.
3.5.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modifed in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is
particularly necessary when addressing modified or reconstructed facilities
subject to the provisions of Section 173 of the Clean Air Act. Emission
limitations reasonable for new sources may in some instances be economically
or technically unreasonable when applied to modified or reconstructed sources
of the same type.
Control efficiencies greater than 95 percent across the control device
have been documented on fabric coating operations using thermal or catalytic
3.5-7
-------
*J *\ 4 f\
incineration or carbon adsorption systems. ' ' ' At least 90 percent of the
VOC emissions from fabric coating can be sent to a control device that yields
an overall control efficiency of 85 percent, which is equivalent to the uncon-
trolled emissions from a low-solvent coating containing 310 g of solvent/liter
(2.6 Ib/gal) of coating minus water. The following shows this derivation:
Assuming a typical coating contains 22 percent solids,
100 gallons of coating contains 22 gal solids
and 78 gal solvent
Reducing the solvent emitted yields: (78) - [0.85 (78)] =
11.7 gal permitted
Assuming a solvent density of 7.36 Ib/gal, 11.7 gal =86.1
Ib solvent
Equivalent coating required = 86.1 Ib solvent/(22 + 11.7)
gal of coating minus water
= 2.6 Ib solvent/gal coating
minus water
= 310 g solvent/liter coating
minus water
Although conversion to a waterborne or higher-solids coating
will significantly reduce VOC emissions, the 310 g/liter (2.6
Ib/gal) limitation may not be achievable, in which case control
of part of the VOC emissions is still recommended. The recom-
mended LAER limitation for vinyl coating is 370 g solvent/liter
(3.0 Ib/gal) minus water, based on solids content of 15 percent
and a solvent density of 826 g solvent/liter (6.7 Ib/gal).
Complete control of VOC emissions using add-on control devices
providing at least 85 percent overall plant control is also
acceptable.
3.5-8
-------
REFERENCES
1. Control of Volatile Organic Emissions for Existing Station-
ary Sources, Volume II: Surface Coating of Cans, Coils,
Paper, Fabrics, Automobiles, and Light-duty Trucks.
EPA-450/2-77-008, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina. May 1977.
2. Letter from W. C. Moses. Technical Manager, Chemical Plant
Division, Sutcliffe, Speakman & Company, Limited. March 10,
1978.
3. Personal communications with R. W. Laundrie. Manager-
Ecology, Safety and Health Engineering, Chemical/Plastic
Division, General Tire and Rubber Company, Akron, Ohio.
March 1978.
4. Personal communications with N. Glazer. Philadelphia Air
Management Services. February 21 and 28, 1978.
5. Personal communication with S. Bruntz. Division of Air
Pollution, Kentucky Department of Environmental Protection.
March 1, 1978.
6. Vincent, E.J., et al. Are Afterburners Obsolete? Presented
at Air Pollution Control Equipment Seminar, APCA/National
Association of Corrosion Engineers, Altanta, Georgia.
January 17-19, 1978.
7. Recommended Policy of Control of Volatile Organic Compounds.
Federal Register, 42 FR 131, U.S. Environmental Protection
Agency. July 8, 1977.
8. Source Assessments: Prioritization of Air Pollution from
Industrial Surface Coating Operations. EPA 650/2-75-0192,
U.S. Environmental Protection Agency. February 1975.
9. Lam, J.Y., et al. Consideration of a Proposed Model Rule
for the Control of Volatile Organic Compounds from Paper and
Fabric Coating Operations. Prepared for California Air
Resources Board, Sacramento, California. August 23, 1978.
3.5-9
-------
10. Control Strategy Preparation Manual for Photochemical
Oxidant. OAQPS 1.2-047, U.S. Environmental Protection
Agency. January 1977.
11. Recommendation by U.S. Environmental Protection Agency,
ESED. Raleigh-Durham, North Carolina, August 8, 1978.
3.5-10
-------
3.6 MAJOR SOURCE CATEGORY: LARGE INDUSTRIAL BOILERS--PARTICULATE,
SULFUR DIOXIDE, AND NITROGEN OXIDE EMISSIONS
3.6.1 Process Description
Industrial boilers are fired with coal, natural gas, oil,
and industrial wastes. The resulting heat of combustion is then
used -to produce steam in the boilers. Liquids other than water
may be heated in the boiler for use in subsequent industrial
processes. The hot flue gases, after producing steam in the
boiler, pass through an economizer and sometimes an air heater
and are finally discharged through a stack.
This section deals with coal-fired boilers in the heat input
range of 58 to 175 MW (200 to 600 x 106 Btu/h), including stokers
in the range of 88 to 117 MW (300 to 400 x 106 Btu/h); and with
oil-fired boilers in the range of 73 to 102 MW (250 to 350 x 10
Btu/h).
3.6.1.1 Pulverized-Coal-Fired Boilers--
For combustion in a pulverized-coal-fired boiler, coal is
pulverized so that at least 70 percent passes through a 200-mesh
sieve. This finely ground coal is conveyed pneumatically to a
burner located in the furnace. The system operates as a con-
tinuous process; within specified design limitations, the coal
feed can be varied as required by boiler load. Figure 3.6-1
depicts a pulverized-coal-fired boiler system.
A small portion of the air required for combustion (15 to 20
percent in current installations) is used to transport the coal
to the burner. This is known as primary combustion air. The
primary air is also used to dry the coal in the pulverizer. The
remainder of the combustion air (80 to 85 percent) is introduced
at the burner and is known as secondary air. The control system
regulating the flow of both coal and primary air is so designed
that a predetermined air/coal ratio is maintained for any given
load.1
3.6-1
-------
PENTHOUSE
PENDANT
REHEATER
STEAM DRUM
SECONDARY
SUPERHEATER
ELECTROSTATIC
PRECIPITATOR
PRIMARY
SUPERHEATER
ECONOMIZER
STEAM COIL
AIR HEATER
FORCED DRAFT FAN
PRIMARY AIR FAN
Figure 3.6-1. Radiant boiler for pulverized coal firing,
(The Babcock & Wilcox Co.)
3.6-2
-------
Burners are characterized by firing position, i.e., wall-
fired or tangential. Arrangements for the introduction of
primary, secondary, and, in some cases, tertiary air vary with
burner manufacturers. One manufacturer uses an adjustable burner
that can be tilted upward or downward to control the furnace
outlet temperature so that steam temperature can be regulated
over a wide range.
Pulverized-coal-fired boilers may be designed as either wet
or dry bottom units. In a wet bottom furnace, the temperature is
maintained above the ash fusion temperature and the ash is melted
so that it can be removed from the furnace as a liquid. In a dry
bottom furnace, the temperature is maintained below the ash
fusion temperature so that the ash will not fuse.
3.6.1.2 Stoker-Fired Boilers—
Stoker-fired boilers are used in the small to medium size
ranges from 9 to 117 MW (30 to 400 x 10 Btu/h). The stokers are
designed to feed coal onto a grate in the furnace and to remove
the ash residue. Higher rates of combustion are possible, and
the continuous process of stoker firing permits good control and
high efficiency. Stokers are often preferred over pulverizers
because of their greater operating range (i.e., operation at low
loads) and lower power requirements, and because they can burn a
variety of solid fuels.
The grate area required for a given stoker type and capacity
is determined from rates established by experience. Table 3.6-1
lists maximum recommended coal burning rates for three types of
stokers, which are discussed in the following paragraphs.
3.6-3
-------
TABLE 3.6-1. MAXIMUM ALLOWABLE COAL BURNING RATES FOR
THREE TYPES OF STOKERS1
Type of stoker
Multiple-retort
underfeed stokers
Chain- or traveling-
grate stokers
Spreader stokers
Coal burning rate
MW/mz
1.89
1.58
2.36
(Btu/ft'-h)
(600,000)
(500,000)
(750,000)
Multiple-retort underfeed stokers—In a multiple-retort,
rear-end-cleaning stoker the retort and grate are inclined 20 to
25 degrees. These units usually consist of several inclined
retorts side by side, with rows of tuyeres between each retort
(Figure 3.6-2a). Coal is worked from the front hopper to the
rear ash-discharge mechanism by pushers. The forced-air system
is zoned beneath the grates by means of air dampers, and combus-
tion control is fully modulated. In larger furnaces the walls
are water-cooled, as are the grate surfaces in some units. Use
of multiple-retort underfeed stokers is declining. Capacities
generally range from 7 to 146 MW (25 to 500 x 106 Btu/h).
Chain-grate or traveling-grate stokers—A chain-grate (Fig-
ure 3.6-2b) or traveling-grate unit consists essentially of grate
sections that move from the front to the rear, carrying coal from
the hopper in front into the combustion zone. The fuel bed moves
progressively to the rear, where the ash is continuously dis-
charged. Modern units have zone-controlled forced draft.
Complete combustion-control systems are used, and overfire air,
especially in the front wall, aids combustion of the volatiles in
the fuel. Capacities range from 6 to 88 MW (20 to 300 x 10
Btu/h) heat input.
Spreader stokers—The spreader stoker combines suspension
and fuel bed firing by the stoker mechanism, which throws coal
into the furnace over the fire with a uniform spreading action
(Figure 3.6-2c). Because coal is burned partly in suspension and
3.6-4
-------
COAL HOPPER
| COAL RAMS
ASH DISCHARGE PLATE
FUEL
DISTRIBUTORS
a. Multiple-retort underfeed stoker.
OVERFIRE-AIR
NOZZLES
COAL HOPPER
COAL GATE!
-RETURN
BEND
DRAG
PLATE
STOKER
CHAIN
DRIVE
SPROCKET
HYDRAULIC
DRIVE
b. Traveling-grate spreader stoker with front ash discharge.-1
COAL
HOPPER
FEEDER
STOKER
CHAIN
ASH HOPPER
OVERFIRE
AIR
OVERTHROW OVFRFTR[r
ROTOR OV!?"RE'
Al K
c. Chain-grate stoker.
Figure 3.6-2. Types of stokers.
3.6-5
-------
partly on the grate, the coal forms a thin, fast-burning bed.
This method of firing provides rapid response to load fluctua-
tions. The grates are either stationary or move continuously
from the rear to the front.
Partial suspension burning of coal in a spreader stoker
results in greater carry-over of particulate matter in the flue
gas. Spreader stokers therefore must be equipped with dust
collectors, and the larger carbon-bearing particles are often
recirculated to the furnace for further burning. Recirculation
of the larger particulate into the furnace can result in an
increase in boiler efficiency of 2 to 3 percent. Capacity of
spreader stokers range from 2 to 146 MW (6 to 500 x 106 Btu/h)
heat input. '
3.6.1.3 Oil-Fired Boilers—
Fuel oil is atomized and burned in suspension. Atomization
produces fine oil droplets that expose a large surface area per
unit of oil volume to the hot furnace and promotes combustion.
The oil burners are normally located in the vertical walls
of the furnace, as shown in Figure 3.6-3. Before the oil reaches
the burner it is passed through a strainer or filter that removes
sludge. This filtering process prolongs pump life, reduces
burner wear, and increases combustion efficiency.
For proper atomization, oil of a grade heavier than No^ 2
must be heated to reduce its viscosity to 26 to 30 x 10 m /s
(130 to 150 Saybolt Universal). Steam or electric heaters are
required to raise the oil temperature to the required degree:
approximately 57°C <135°F) for No. 4 oil, 85°C (185°F) for No. 5
oil, and 93° to 12l°C (200° to 250°F) for No. 6 oil.
3.6.2 Emissions
3.6.2.1 Emissions from Coal-Fired Boilers—
Flue gases from coal-fired boilers contain particulate
matter and gaseous products of combustion, including oxides of
sulfur and nitrogen.
3.6-6
-------
CENTERING AIR REGISTER DOOR OIL
SUPPORT (SECONDARY AIR) ATOMIZER
LIGHTER
REGISTER
DRIVE ROD
IMPELLER REFRACTORY THROAT WATER-COOLED
WITH STUDDED TUBES FURNACE WALL
Figure 3.6-3. Oil firing burner with water-cooled throat.'
3.6-7
-------
Particulates—The quantity of uncontrolled particulate
emissions depends primarily on the type of combustion unit, the
ash content of the coal, the fuel rate, and the degree of fly ash
reinjection. On stoker-fired units, the grate heat-release rate
and coal size also affect emissions.
When pulverized coal is burned, nearly all the ash particles
are formed in suspension and about 80 percent of the ash leaves
the furnace entrained in the flue gas. In a slag-type or wet
bottom furnace, however, as much as 50 percent of the ash may be
retained in the furnace.
In a properly operated stoker burning coal, the passage of
air and the agitation of the fuel bed on the grate serve to keep
ash accumulations more or less porous, and the ash is discharged
to an ashpit in fairly large pieces.
With a spreader stoker, some of the fuel is burned in sus-
pension and a considerable quantity Of ash particles, containing
some unburned fuel, is consequently carried over with the gases.
This material is usually collected in hoppers and may be rein-
jected into the furnace for further burning.
Sulfur oxides—In a coal-fired furnace, about 90 to 95
percent of sulfur in the coal is converted to sulfur oxides
(SO ).4 The balance of the sulfur is emitted in the fly ash or
•"• >
combines with the slag or ash in the furnace and is removed with
them. Sulfur dioxide is the principal oxide of sulfur; only 2 to
3 percent of the sulfur content of the coal is emitted as sulfur
trioxide. Rates of sulfur oxides emissions depend on the sulfur
content of the coal and not on the type of furnace.
Nitrogen oxides—Emissions of nitrogen oxides (NOX) are
caused by high-temperature reaction of atmospheric nitrogen and
oxygen in the combustion zone (called "thermal N0x") and also by
partial combustion of nitrogenous compounds in the fuel ("fuel
nitrogen"). The important factors that affect NOx production are
flame and furnace temperature, residence time of combustion gases
3.6-8
-------
at the flame temperature, rate of cooling of the gases, and
amount of excess air in the flame.
Emission factors for coal-fired boilers are presented in
Table S.6-2.5
3.6.2.2 Emissions from Oil-Fired Boilers—
Emissions from fuel oil combustion depend on the grade and
composition of the fuel, the type and size of the boiler, the
firing and loading practices, and the level of equipment main-
tenance. Table 3.6-3 presents emission factors for fuel oil
combustion in industrial boilers without control equipment. The
emission factors for industrial boilers are grouped into dis-
tillate and residual oil categories because the combustion of
each produces significantly different emissions of particulates,
SO , and NO .
X X
Particulates—Particulate emissions are most dependent on
the grade of fuel fired. The lighter distillate oils cause
significantly lower particulate formation than do the heavier
residual oils. In boilers firing Grade 6 oil, particulate emis-
sions generally can be considered as a function of the sulfur
content of the oil. This is because Grade 6 oil, whether refined
from naturally occurring low-sulfur crude oil or desulfurized by
one of several processes currently in practice, has substantially
lower viscosity than other grades, and also lower asphaltene,
ash, and sulfur contents, all of which lead to better atomization
and cleaner combustion.
Boiler load can affect particulate emissions in units firing
Grade 6 oil. At low loads particulate emissions may be reduced
by as much as 60 percent. No significant particulate reductions
at low loads have been noted in boilers firing any of the lighter
grades.
Nitrogen oxides—Emissions of NO formed from fuel nitrogen
X
are primarily a function of the nitrogen content of the fuel and
the available oxygen. Emissions of thermal NO are largely a
X
3.6-9
-------
TABLE 3.6-2. EMISSION FACTORS FOR BITUMINOUS-COALgFIRED
INDUSTRIAL BOILERS WITHOUT CONTROL EQUIPMENT
Furnace capacity,
MW (106 Btu/h)
heat input
Greater than 29 (100)
Pulverized
Wet bottom
Dry bottom
Spreader stoker
Particulates,
kg/Mt (Ib/ton)
coal burned
6.5A (13A)C
8.5A (17A)
6.5A (13A)e
Sulfur *
oxides,
kg/Mt (Ib/ton)
coal burned
19S (38S)
19S (38S)
19S (38S)
Nitrogen
oxides,
kg/Mt (Ib/ton)
coal burned
15 (30)
9 (18)
7. .5 (15)
a The letter A on all units indicates that the weight percentage
of ash in the coal should be multiplied by the value given.
Example: If the factor is 8 and the ash content is 10 per-
cent, the particulate emissions before the control equipment
would be 10 times 8, or 80 kg of particulate per Mt of coal
(10 times 16, or 160 pounds of particulate per Mt of coal).
b S equals the sulfur content (see footnote a above).
0 Without fly-ash reinjection.
d For all other stokers use 5A for particulate emission factor.
Emission factor data for stokers with capacities greater than
29 MW are not documented.
e Without fly-ash reinjection. With fly-ash reinjection from
first-staged collector, use 20A.
3.6-10
-------
TABLE 3.6-3. EMISSION FACTORS FOR FUEL OIL COMBUSTION'
Pollutant
Residual oil,
kg/kl (lb/103 gal)
Distillate oil,
kg/kl (lb/103 gal)
Particulate
Sulfur dioxide
Nitrogen oxides
(total as N02)
19.25 (158.65)
7.5C (60)C
0.25 (2)
17.2S (143.68)
2.8 (22)
Particulate emission factors for residual oil combustion are
best described, on the average, as a function of fuel oil
grade and sulfur content, as shown below.
Grade 6 oil
kg/kl = 1.25(S) + 0.38
[lb/103 gal = 10,(S) + 3]
where: S is the percentage, by weight, of sulfur
in the oil
Grade 5 oil: 1.25 kg/kl (10 lb/103 gal)
Grade 4 oil: 0.88 kg/kl (7 lb/103 gal)
S is the percentage, by weight, of sulfur in the oil.
Nitrogen oxides emissions from residual oil combustion in
industrial and commercial boilers are strongly dependent on
the fuel nitrogen content and can be estimated for accurately
by the following empirical relationship:
kg N02/kl = 2.75 + 50(N)2,
[Ib N02/103 gal = 22 + 400(N)2]
where: N is the percentage, by weight, of nitrogen
in the oil. Note: For residual oils having
high (>0.5%, by weight) nitrogen contents,
one should use 15 kg N02/kl (120 Ib N02/103
gal) as an emission factor.
3.6-11
-------
function of peak flame temperature and available oxygen, factors
that depend on boiler size, firing configuration, and operation
practices. Fuel NO are the predominant NO emissions in boilers
X X
firing residual oil. Thermal NO emissions predominate in units
*\
firing distillate oils, primarily because the nitrogen content of
these lighter oils is negligible.
3.6.3 Control Measures
3.6.3.1 Particulate—
Problems of ash removal and disposal are significant, prin-
cipally where solid fuels are burned. Fuel oil contains little
ash, and any ash formation primarily affects the furnace and
boiler interiors. Mechanical dust collectors are used occasion-
ally.
With the early methods of burning coal on grates with
natural draft, most of the coal ash remained on the grate and was
ultimately discharged into a hopper for disposal. With the newer
boilers, such as the spreader stoker and the pulverized-coal-
fired boilers, part or all of the burning occurs in suspension,
leading to greater carry-over of particulate matter in the flue
gas.
Achieving a low emission rate requires some form of particu-
late control equipment to remove the fly ash from flue gases of
units that burn solid fuels. In addition, careful operation and
use of the fuel specified for the boiler are required to minimize
visible emissions. The commercially available high-efficiency
particulate removal equipment includes electrostatic precipita-
£i
tors, fabric filters, and wet scrubbers.
Electrostatic precipitators—Precipitators are the most
widely used particulate control device on pulverized-coal-fired
boilers. Electrostatic precipitators impart an electric charge
to the particles to be collected and then propel the charged
particles by electrostatic force to the collecting electrodes.
3.6-12
-------
Collection efficiency of an electrostatic precipitator depends on
the time of particle exposure to the electrostatic field, the
strength of the field, and the resistivity of the dust particle.
Efficiency above 99 percent can be achieved when the unit is
properly designed. Table 3.6-4 presents selected operating and
design data for a spreader-stoker coal-fired boiler.
Fabric filters—These devices are being used increasingly on
coal-fired stokers, but to a lesser extent on those burning pul-
verized coal. Use of fabric filters is favored when sulfur
content of the coal is very low and when carbon content of the
particulate is high (as in spreader stokers).
Fabric filters trap dust particles by impingement on the
fine fibers of the fabric. As the collection of dust continues,
an accumulation of dust particles adheres to the fabric surface,
forming a highly efficient filter cake. The fabric filter
achieves maximum efficiency during this period of dust buildup.
After a fixed operating period, which depends on the pressure
drop, the bags are cleaned by passage of a reverse flow of air or
by mechanical vibration. Filtering efficiency is slightly lower
after cleaning until the collected dust again forms a filter
cake.
The fabric filter can be applied to any boiler for which dry
collection is desired and maximum temperatures are lower than
about 288°C (550°F).7 Coated fiberglass filters are generally
used at the upper temperature limit. Efficiencies greater than
99 percent can be achieved, as shown in Table 3.6-5.
Wet scrubbers—Wet scrubbers remove dust from a gas stream
by collecting it with a suitable liquid. A good wet scrubber can
effect intimate contact between the gas stream and liquid for the
purpose of transferring suspended particulate matter from the gas
to the liquid. Collection efficiency, dust-particle size, and
pressure drop are closely related in the operation of a wet
scrubber. The required operating pressure drop varies inversely
with dust-particle size at a given collection efficiency; or, for
3.6-13
-------
TABLE 3.6-4. EXAMPLE OF AN ESP APPLICATION ON A
COAL-FIRED BOILER6
Plant name
Heskett Unit 1
Location
Boiler capacity
Boiler type
Fuel type
Sulfur content
Ash content
Moisture content
Flue Gas
Temperature
Volume
Velocity in ESP
Collecting surface3
Inlet loading
Outlet loading
Efficiency
Mandan, North Dakota
25 MW (output); about 75 MW input
Spreader stoker
Coal, lignite
0.3 to 1.4 %
6.7 %
36.1 %
214°C (418°F)
180,000 Nm3/h (189,000 acfm)
1.16 m/s (3.8 ft/s)
6180 m2 (66,500 ft2)
5.7 to 9.4 g/m3 (2.5 to 4.1 gr/ft3)
0.023 g/m3 (0.01 gr/ft3)
99.68% (designed for 99.45%)
a Specific collection area is 1154 m2/1000 irfVmin (352 ft /1000
acfm).
3.6-14
-------
TABLE 3.6-5. EXAMPLE BAGHOUSE DESIGN PARAMETERS AND
OVERALL EFFICIENCY6
Plant name
Location
Boiler type
Boiler capacity
Gas flow rate
Compartments
Fabric
Air-to-cloth ratio,
6 compartments
Air-to-cloth ratio,
5 compartments
(cleaning or maintenance
on one compartment)
Pressure drop (normal)
Pressure drop (cleaning)
Nucla Station
Nucla, Colorado
Spreader stoker
12.65 MW (one of three boilers);
about 40 MW input
146,000 m3/h (86,240 acfm)
6
Fiberglass with graphite finish
51 m3/h per m2 (2.8 acfm/ft2)
61 m3/h per m2 (3.35 acfm/ft2)
1120 Pa (4.5 in. H20)
Up to 1490 Pa (6 in. H20)
Load,
MW
Overall efficiency,
Total particulate emission,
ng/J (lb/106 Btu)
6
11
12
99.98
99.97
99.92
3.0 (0.007)
8.6 (0.02)
17.2 (0.04)
3.6-15
-------
a given dust-particle size, collection efficiency increases as operating
pressure drop increases. Although scrubbers are not widely used on boilers,
they can achieve collection efficiencies in the range of 80 to 99 percent, as
C
shown in Table 3.6-6.
3.6.3.2 Sulfur Oxides-- ••
Sulfur oxides can be controlled by burning low-sulfur fuel (naturally
occurring or pretreated for sulfur removal) or by removing the sulfur oxides
from the combustion gases before they are released (flue gas desulfurization,
FGD). The pretreating techniques include physical and chemical coal clean-
ing, coal liquefaction and coal gasification. Physical coal cleaning is limited
to removal of pyritic sulfur and can achieve up to 50 percent SO2 removal.
Chemical coal cleaning, gasification, and liquefaction are not in commercial
operation at this time. FGD technologies include:
1. Injection of materials such as limestone or dolomite
into the furnace.
2. Wet scrubbing of flue gases.
3. Use of dry sorbent systems.
Of these processes, only wet scrubbing is widely used with industrial boilers.
Wet_scrubbinq of flue gases-Wet scrubbing FGD systems applied on
coal-fired industrial boilers in the United States include lime or limestone
scrubbing, the dilute or concentrated double alkali process, and scrubbing
with sodium carbonate or sodium hydroxide solutions.8 In these systems, flue
gases contact the scrubbing solution after fly ash is removed in an ESP or
prescrubber. Sulfur dioxide reacts with the slurry in a scrubber-absorber
and forms large quantities of sludge. The sludge is separated and disposed
of, while the scrubbing solution is recirculated with the makeup slurry.
These FGD units have achieved efficiencies above 90 percent, as shown in
Table 3.6-7, but long-term monitoring data are lacking. Many other sulfur
oxide removal systems are used on large utility boilers and on industrial
oil-fired boilers.
3.6-16
-------
TABLE 3.6-6. EXAMPLE OF A WET SCRUBBER APPLICATION FOR
PARTICULATE REMOVAL ON A COAL-FIRED BOILER6
Plant name
Lewis and Clark Station
Montana-Dakota Utilities
Boiler capacity
Boiler type
Fuel type
Sulfur content
Ash content
Wet scrubber
Design
Vendor
L/G ratio, inlet
L/G ratio, outlet
Pressure drop
Open or closed loop
Electric power requirement
Particulate removal
efficiency
S02 removal efficiency
55 MW; about 170 MW input
Pulverized coal-fired
Coal, lignite
0.45 %
9.0 %
Venturi, flooded disc
Research-Cottrell
1.755 liters/Nm3 (13 gal/1000 ft3)
2.295 liters/Nm3 (17 gal/1000 ft3)
3235 Pa (13 in. H2O)
Closed
0.5 MW
98% [0.064 g/m3 (0.028 gr/scfd)]
15% (minimum) at 0.45% sulfur
content
3.6-17
-------
TABLE 3.6-7. EXAMPLES OF FGD APPLICATIONS ON INDUSTRIAL BOILERS8
u>
•
CTi
I
I—'
CO
Plant name,
location
Caterpiller
Tractor,
Joliet, 111.
FMC Soda Ash
Green River,
Wyo.
General Motors
Parma, Ohio
Rickenbacker AF
Columbus, Ohio
Kerr-McGee
Chem. Corp.
Trona, Calif.
(under con-
struction)
No. of
boilers
2
2
4
B 7
2
Total boiler
capacities,
MW
18
200
32
20
64
Total gas 1
flow rates,
Nm3/h
152,500
705,600
@160°C
217,600
84,750
776,200
@160°C
Fuel,
(% s)
Coal
(3.2)
Coal
(1)
Coal
(2.5)
Coal
(3.6)
Coke, coal
or oil
(0.5-5)
FGD system
and vendor
Double alkali
(dilute), Zurn
Industries
Sodium scrub-
bing , FMC
Double alkali
(dilute), GM
Environmental
Limestone
scrubbing,
Research-
Cottrell/
BAHCO
Sodium scrub-
bing, C.E.A.
S02 removal
efficiency, /
90+
87-94
90
90
98+
Note- The S02 removal efficiencies shown were obtained during specific test periods
test periods and are not long-term averages.
-------
3.6.3.3 Nitrogen Oxides--
Techniques for controlling NO from large oil-fired and
X
pulverized-coal-fired boilers include flame temperature modera-
tion by two-stage combustion, low-excess-air firing, and furnace
modifications such as recirculation of flue gas through the
combustion zone. These approaches involve reduction of peak gas
temperatures and changes in the time-temperature conditions of
g
combustion.
Control of NOx by scrubbing techniques is under active
investigation, but has not yet been used on industrial boilers in
the United States.10
3.6.4 Emission Limits
3.6.4.1 State Implementation Plan (SIP) Limits—
Most state regulations include emission limitations for
industrial boilers under general regulations for fuel burning
equipment. Emission limits vary with the type of fuel fired
(coal, oil, or other) and with boiler size, but they do not
usually specify boiler type.
Particulate emission regulations are commonly set at 43 ng/J
(0.1 lb/10 Btu), the most stringent limitations are imposed by
the District of Columbia (coal) and New Mexico (oil) as follows:
District of Columbia (see Figure 3.6-4) —Range is
about 16 to 24 ng/J (0.04 to 0.06 lb/106 Btu).
New Mexico-- 2.7 ng/J (0.006 lb/106 Btu) on the basis
of 7000 hours per year.
Sulfur dioxide emission regulations are frequently set at
516 ng/J (1.2 lb/106 Btu) for coal-fired boilers; the most strin-
gent limitations are imposed by the State of Wyoming and Clark
County, Nevada, as follows:
Wyoming - 86 ng/J (0.2 lb/106 Btu).
Clark County, Nevada-- 65 ng/J (0.15 lb/106 Btu).
3.6-19
-------
BOILER HEAT INPUT, MW
2.93 29.3
293
LO
CTi
I
IS)
•z.
O
CO
o
-------
Nitrogen oxide emission regulations are generally set at 301
and 129 ng/J (0.7 and 0.3 lb/10 Btu) for coal and oil, respec-
tively. The most stringent regulation is imposed by New York
City: 103 ng/J (0.24 lb/106 Btu) for both coal and oil.
3.6.4.2 New Source Performance Standards--
Federal regulations of particulate, SO«, and NO emissions
£ X
apply to all types of coal- and oil-fired boilers with heat input
greater than 73 MW (250 x 10 Btu/h) . The following limitations
apply to all sources that were built after August 17, 1971:
Particulate—43 ng/J (0.1 lb/106 Btu); SO2—520 ng/J
(1.2 lb/106 Btu) for coal and 344 ng/J (0.8 lb/106 Btu)
for oil; NO --301 ng/J (0.7 lb/106 Btu) for coal and
X
129 ng/J (0.3 lb/106 Btu) for oil.
Revisions that would reduce these emission limits are cur-
rently being studied, but no definite values have been prom-
ulgated.
3.6.4.3 Achieved-in-Practice (AIP) Limits--
Data on particulate emissions from industrial-sized boilers
are often obtained under constant operating conditions with all
combustion and control system parameters set at a level to mini-
mize emissions. Under these conditions, emissions as low as 6.9
3
mg/m (0.003 gr/dscf) were measured at the Caterpillar Tractor
Co., in Decatur, Illinois, utilizing a fabric filter system.
This rate is approximately equal to 2.6 ng/J (0.006 lb/10 Btu).
Emissions with fabric filter systems and high-efficiency electro-
static precipitators range more typically from 13 to 17.2 ng/J
(0.03 to 0.04 lb/106 Btu) range. Emissions from distillate-oil-
fired boilers are about 5.6 ng/J (0.013 lb/ 106 Btu) with no
control. Well-operated residual-oil-fired boilers emit particu-
lates in the range of 21 to 43 ng/J (0.05 to 0.1 lb/106 Btu) with
no controls.
3.6-21
-------
Sulfur dioxide emissions vary directly with fuel sulfur content. The
coal -fired boiler achieving best control is the FMC plant in Green River,
Wyoming, which reportedly has measured up to 94 percent SO2 removal while
burning a 1 percent sulfur content coal (see Table 3.6-7). This 3-stage tray
scrubber utilizes sodium carbonate at liquid-to-gas ratios of 1.3 to 2 liters/m
(10 to 15 g/1000 ft3) and a pressure drop of 2.8 to 3.2 cm (7 to 8 in.) of
water.
Lowest achievable NOX emissions are .not well documented, but EPA
programs to acquire NOX emission data for large industrial boilers are sched-
uled for completion during 1979.
3.6.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional SIP
regulations covering these sources will be promulgated and/or modified in 1979
and 1980 and that appreciable new performance data will become available in
the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
The following discussion pertains to coal-fired boilers in the 58 to 175 MW
(200 to 600 x 106 Btu/h) heat input range including stokers of 88 to 117 MW
(300 to 400 x 106 Btu/h) and to oil-fired boilers in the range of 73 to 102 MW
(250 to 350 x 106 Btu/h) heat input. Based on particulate control efficiencies
of high-efficiency fabric filter and ESP systems, an emission limit of 13 ng/J
3.6-22
-------
£
(0.03 lb/10 Btu) can be achieved. This level of particulate emission will also
require controls on some residual-oil-fired boilers depending on fuel compo-
sition and firing efficiency. Control efficiencies in the range of 40 to 70
percent will be required.
A sulfur dioxide emission reduction of 90 percent can be achieved on
coal-fired units by use of FGD. The economic feasibility of using FGD on
smaller boilers, especially those that already burn low-sulfur fuel, is question-
able.
Nitrogen oxide emissions from packaged oil-fired boilers can be limited to
130 ng/J (0.3 lb/106 Btu). With pulverized-coal-fired boilers, a limit of 260
£•
ng/J (0.6 lb/10 Btu) is achievable; this value is based on studies performed
for NSPS revisions. A limit of 2.7 ng/J (0.5 lb/106 Btu) can be achieved by
subbituminous coal-fired boilers. NC> levels for stoker fired boilers will be
X
determined by a current study on industrial boilers. The above limits for
SO2 and NOx are on a 30 day average basis using a continuous monitor, while
the particulate level is based upon the average of three or more runs using
EPA Method 5.
3.6-23
-------
REFERENCES
1. Smith, W. S., and C. W. Gruber. Atmospheric Emissions from
Coal Combustion - An Inventory Guide. Public Health Service
Publication No. 999-AP-24, U.S. Department of Health, Edu-
cation, and Welfare. April 1966.
2. The Babcock & Wilcox Co. Steam/Its Generation and Use, 38th
edition. 1975.
3. Smith, W. S. Atmospheric Emissions from Fuel Oil Combustion
- An Inventory Guide. Public Health Service Publication No.
999-AP-2, U.S. Department of Health, Education, and Welfare.
November 1962.
4. Weisburd, M. I., A. Stein, R. J. Bryan, L. G. Wayne, and A.
Kokim. Air Pollution Control Field Operations Manual, A
Guide to Inspection and Enforcement. Vol. II, U.S. Environ-
mental Protection Agency Contract No.. CPA 70-122, Task Order
1. February 1972.
5. Compilation of Air Pollutant Emission Factors, 2nd Edition.
Publication No. AP-42, U.S. Environmental Protection Agency.
February 1976.
6. Szabo, M. F., and R. W. Gerstle. Operation and Maintenance
of Particulate Control Devices on Coal-fired Utility
Boilers. EPA-600/2-77-129, U.S. Environmental Protection
Agency. July 1977.
7. Danielson, J.A., ed. Air Pollution Engineering Manual, 2nd
Edition. AP-40, U.S. Environmental Protection Agency. May
1973.
8. 'Tuttle, J., A. Patkar, and N. Gregory. Environmental Pro-
tection Agency Industrial Boiler FGD Survey: First Quarter
1978. EPA 600/7-78-052a. March 1978.
9. Air Quality Criteria for Nitrogen Oxides, Air Pollution
Control Office. AP-84, U.S. Environmental Protection
Agency. January 1971.
3.6-24
-------
10. Ando, J. Status of S02 and NO Removal Systems in Japan.
Presented at FGD Symposium, Hollywood, Florida. November
8-11, 1977.
11. Air Pollution Emission Test - Caterpillar Tractor Co.
Project 77-SPP-18, Emission Measurement Branch, U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina. April 1977.
3.6-25
-------
3.7 MAJOR SOURCE CATEGORY: PRIMARY ALUMINUM PLANT REDUCTION
CELLS AND ANODE BAKE OVENS--SULFUR DIOXIDE EMISSIONS
3.7.1 Process Descriptions
3.7.1.1 Primary Aluminum Plant--
The base ore for primary aluminum production is bauxite, a hydrated
oxide of alumina consisting of 30 to 70 percent alumina (Al-CO, and lesser
c* O
amounts of iron, silicon, and titanium. The bauxite ore is purified to alumina
by the Bayer process and then transported to the primary aluminum reduction
plant.
At the reduction plant the alumina is electrolytically reduced to metallic
aluminum in a bath of molten cryolite (the electrolyte) by the Hall-Heroult
process. The heavier molten aluminum settles beneath the cryolite. It is
periodically decanted, transferred by crucible to holding furnaces, and then
cast into ingots, billets, slabs, and other bulk shapes for shipment to
customers.
Figure 3.7-1 is a schematic of a primary aluminum reduction plant.
3.7.1.2 Reduction Cell—
The electrolytic reduction of alumina takes place in shallow, rectangular
carbon-lined steel shells (pots) arranged in series to form a "pot line."
Cryolite serves as both the electrolyte and the solvent for the alumina.
Carbon blocks (anodes) are suspended in the pots (cathodes), and the two
are connected electrically to accomplish the electrolytic reaction. The heat
generated by electrical resistance to high-amperage, low-voltage direct
current applied across the electrodes creates operating temperatures between
950° and 1000°C (1728° and 1832°F). The carbon anodes are depleted by the
reaction of oxygen formed in the process (2A12O3 -» 4A1 + 2O3) with anode
carbon (2C + Cs -> CO + CO-). Because the process is continuous, both the
3.7-1
-------
POWER PLANT
RECEIVE, RECTIFY
DISTRIBUTE POWER
V- «/ a T=s
_J -f^"®
/ t
ALUMINA CR
Y^
POT CHARC
MATERIAL!
1
RAW MATERIALS
RECEIVE, STORE
DISTRIBUTE
/ ^ X ,
(PITCH I /COKE ]
YOLITE """-^-^-"^
ANODE PLANT
. ./ GRIND, MIX
y^ '. PITCH/COKE
T , ,
JE JANODE PASTE
OR
CATHODE PLANT
BUILD CARBON
LINED STEEL POT
1
CATHODE CELL
(POT)
\
TO
| SODERBERG ] ] PREBAKE | POT HOUSE
|
TO MOLD/B
POT HOUSE ANOD
AKE
ES
TO
POT HOUSE
rau
POT HOUSE
REFINE, ALLOY,
CAST METAL
SHIP
PRODUCT
Figure 3.7-1. Schematic of primary aluminum
reduction plant.
3.7-2
-------
anodes and the cryolite-alumina bath components that are consumed or
removed in the process must be replenished periodically.
Aluminum reduction cells are of two main types, prebake (PB) and
Soderberg. Soderberg cells are designated according to the manner of mount-
ing the stud in the carbon anodes: vertical stud Soderberg (VSS) or hori-
zontal stud Soderberg (HSS). The prebake and Soderberg processes differ
in the preparation of the anodes. In the Soderberg process the anode paste
mixture is formed (baked) in place by the pot heat. In the prebake process,
as the name implies, the anode is baked (usually in a facility separate from
the pot room) before it is inserted into the pot. Although it requires more
electrical power, the Soderberg cell has been favored by the industry because
no separate facility is needed for manufacture of anodes. The trend in
recently constructed plants, however, is to prebake anodes. One reason for
this change in preference is the lower power requirements of the PB cell;
another is that Soderberg cells generate volatile pitch vapors that must be
captured and treated, often leading to plugging of ductwork and control
devices by organic condensibles.
3.7.1.3 Prebake Anode Manufacturing--
Pitch and petroleum coke, including recycled anode butts, are mixed
with a pitch binder to form a paste used in the cathodes (pot liners) and the
"green" anodes for prebake cells. The approximate blend is 75 percent coke
and 25 percent pitch binder. Anode making at the "green mill" (paste
preparation plant) includes crushing, grinding, screening, and sizing the
coke, then blending the sized coke fractions with binder in heated mixers.
For prebake anodes the paste is transferred to molds and densified by a
hydraulic press or by mechanical vibration. The green anodes are then
baked in furnaces to develop thermal stability, strength, and electrical conduc-
tance properties. Anodes are generally baked in a series of sunken pits
(called ring-type furnaces) served by a flue system that circulates hot combus-
tion gases from the heated pit through preceding sections to preheat the
anodes. Anodes are packed into the pits, and a layer of coke is placed over
and around them. The pits are fired with gas or oil through mobile manifold
3.7-3
-------
burners at a temperature of approximately 1200°C (2190°F). The complete
cycle—charging of pits, preheating, firing, cooling, and anode removal-
requires approximately 28 days.
A recent development is use of an indirect-fired tunnel kiln fitted with
air locks and an inert atmosphere to preclude oxidation of the carbon anodes.
This system is more complex and is subject to mechanical problems. The
advantages are a shorter and more uniform baking cycle, reduced space
requirements, and recycling of hydrocarbon emissions to the firebox as a fuel
supplement.
The final step is to fit the baked anodes with a metal rod yoke assembly
that supports the anodes in the reduction cell and provides electrical conduc-
tivity. The baked anodes are airblasted or brushed to remove surface fines;
then the rod yoke assembly is mated to the anodes and cemented in place,
usually with molten iron.
3.7.2 Emissions
3.7.2.1 Prebake Anode Manufacturing Emissions—
Anode paste preparation emissions--Material handling operations in anode
paste preparation generate airborne particulate matter (coke dust). Spent
anode butts recycled to the plant have surface deposits of pot materials that
can be a source of coarse particulate fluorides in the regrinding and mixing
process. Small amounts of volatile hydrocarbons are released during paste
mixing. Paste preparation generates no sulfur dioxide (SO2).
Anode bake oven emissions—Materials entering the anode bake oven
(furnace or kiln) consist of the green anodes, coke or anthracite packing,
and combustion fuel, either natural gas or oil. Emissions from the bake oven
include the products of fuel combustion; burned and unburned hydrocarbons
consisting principally of high-boiling-point organics formed by the cracking,
distillation, and oxidation of the paste binder pitch; sulfur dioxide from the
carbon paste; fluorides from recycled anode butts; and other particulate
matter.
Sulfur dioxide emissions result from oxidation of sulfur contained in the
raw materials used in anode manufacture: high-grade coke (petroleum and
3.7-4
-------
pitch coke) and pitch. Before calcining, the coke portion of the anode paste
has already been subjected at the refinery coke operation to temperatures as
high as that in the bake oven or higher; therefore, the SO- emissions in the
bake exhaust are primarily from the sulfur in the pitch (0.5 percent sulfur)
and from combustion gases. Data pertaining to SO- emissions from anode
bake stacks are very sparse. Uncontrolled emissions in the exhaust are
reported as follows: 5 to 47 ppm; 0.7 to 2 kg SO0/Mg aluminum produced*
2
(1.4 Ib to 4 Ib SO9/ton). Results of source tests reported by the National
£i
Emission Data System (NEDS) indicate that emissions range from 0.09 to 1.7
kg/Mg (0.18 to 3.4 Ib/ton).
3.7.2.2 Reduction Cell Emissions--
Emissions from the reduction cell include (1) particulates from the peri-
odic addition of alumina and cryolite and from condensation of vaporized
materials at the bath and anode surfaces;
(2) carbon monoxide and carbon dioxide from oxidation of carbon anodes; (3)
organics (tar fog) from volatilization of the anode materials by the high-
temperature bath in the cell; and (4) oxides of sulfur from the anode
materials. Emissions of organics and of SO2 are greater from Soderberg cells
than from prebaked cells because the lower-boiling-point organics and some
sulfur are driven off in the anode prebaking oven. In all types of reduction
cells the "primary" emissions are those captured by the pot hood exhaust
system and conveyed to a control device. The "secondary" (roof) emissions
are those that escape the exhaust system and exit through the roof monitors.
Few measurements of SO- emissions from reduction cells have been
reported. One report indicates up to 80 ppm in the exhaust from Soderberg
plants. Reference 2 reports "sulfur dioxide data ranged from 5 ppm for a
prebake plant to 80 ppm for a vertical stud Soderberg plant. No sulfur
Emission values given throughout this subsection are in terms
of the quantity of aluminum produced; e.g., the notation kg/Mg
denotes kilograms SCL per megagram of aluminum produced.
3.7-5
-------
dioxide data were obtained on a horizontal stud Soderberg plant." Values
reported for VSS plants include a range of 200 to 300 ppm (basis of 2 percent
sulfur) or 17.5 to 25 kg/Mg (35 to 50 lb/ton),3 and a 200-ppm average.
Reference 2 reports emissions from prebake plants in the range of 30 kg/Mg
(60 lb/ton) on the basis of 3 percent sulfur in coke, and Reference 3 gives a
range of 20 to 30 ppm SO2. NEDS data from source tests at PB plants
indicate a range of 20.9 to 23.4 kg/Mg (41.7 to 46.8 lb/ton) and an average
of 22.4 kg/Mg (44.8 lb/ton). NEDS gives no data on VSS or HSS facilities,
and no data on HSS plants were discovered.
3.7.3 Control Measures for SO2
The two methods available for reducing SO2 emissions from anode bake
ovens and reduction cells at a primary aluminum plant are (1) flue gas desul-
furization (FGD) systems that remove SO2 from the exhaust stream and (2)
limitations on the sulfur content of coke used in anode manufacture.
3.7.3.1 Flue Gas Desulfurization (FGD)--
Use of FGD systems has been associated primarily with the relatively
strong concentrations of SC>2 in combustion gases from fossil-fuel-fired boilers
at utility plants. To a lesser extent, FGD has been applied to industrial
combustion and process sources. Because most applications have been for
control of significant SO2 concentrations, relatively little information is avail-
able regarding efficiency or operation of FGD on weak SO2 streams similar to
those from reduction cells and anode bake ovens. Even though FGD systems
designed specifically for SO2 control have not been demonstrated at these
primary aluminum plant operations, technology transfer is possible.
Use of FGD systems has been successful on the exhausts from boilers
fired with low-sulfur oil and gas, from foundry cupolas using low-sulfur
coke, and from certain industrial processes.5'6 The SO2 concentrations in
the exhaust streams from such sources approximate those from reduction cells
and anode bake ovens. Collection efficiencies cited in Reference 5 range from
70 to 98 percent for boilers, 47 to 99 percent for cupolas, and 50 to 90
percent for industrial processes. As regards SO2 control at a VSS plant,
3.7-6
-------
Reference 6 cites measured efficiencies of 53 to 83 percent for systems consid-
ered to be technology transfer candidates and indicates a design efficiency of
95 percent as achievable for a suggested hypothetical pot room SCU control
system. The authors conclude that the greatest degree of control being
adequately demonstrated by technology transfer candidates is approximately 80
to 85 percent. Considering the uncertainties, they believe that 70 percent
SO- collection efficiency is achievable by transfer of technology at a VSS
plant.
In the potential application of FGD to control pot room SO2 emissions at
a primary aluminum plant, it is important to recognize the differences in
operation and in pot room exhaust volumes associated with VSS, HSS, and PB
plants. The primary system exhaust volumes at PB and HSS plants are
generally higher than those at VSS plants by 6 to 7 times and 8 to 10 times,
respectively. Accordingly the larger volumes and weaker concentrations at
HSS and PB plants would reguire proportionally larger control system capacity
for anodes of a given sulfur content. Additionally, the anticipated trend to
prebaked cell plants could require provision of SO- control on anode bake
oven emissions either separately or as added primary control system capacity.
As an alternative to use of two systems--a dry fluoride/ particulate
control followed by an FGD system--it would seem technically feasible to use a
wet control system to capture both contaminants. Reference 6 reports that a
wet scrubber/wet electrostatic precipitator system installed on a VSS plant for
purposes of fluoride and particulate control collects approximately 70 percent
of the SO9 emissions from the primary system. The application of any wet
£*
system would require provision of treatment facilities to satisfy wastewater
discharge requirements.
As discussed in Section 1, the determination of LAER is primarily a
technology-oriented consideration, in which economics is relegated to a
relatively minor role. As regards the economic impact of environmental
controls in the primary aluminum industry, it has been stated that controls
(associated with fluorides) more stringent than the NSPS will tend to discrim-
inate against the small market entrant that is without existing capacity, tend
to encourage a greater proportion of imports of primary ingot, and encourage
3.7-7
-------
higher domestic prices for primary aluminum and fabricated products.
Although these observations refer to the imposition of an NSPS standard for
fluorides, they should also be considered when developing LAER standards
for S02 where the control costs are substantial. Substantial costs for SO2
control could result where the fluoride control system selected to meet the
NSPS requirement would not also provide the required SO2 control. Sub-
stantial costs could also be associated with wastewater treatment.
3.7.3.2 Limitation of Sulfur in Petroleum Coke--
Sulfur dioxide emissions from anode bake ovens and reduction cells stem
from the sulfur content of the coke (usually petroleum coke) and the coal tar
pitch binder. The emissions relate directly to the amount of sulfur in these
raw materials, much as the SO2 emissions from fuel combustion relate to the
sulfur content of fossil fuels. Limitation of sulfur content, as is often
applied to fuels, can be similarly applied to anode materials.
Good quality feedstocks for anode coke include thermal tar, cat cracker
slurry, decanted oil, and coal tar pitch. Poor feedstocks include vacuum
residuals and derivatives from high-sulfur crudes.7 To some extent sulfur
can be removed from coke by calcination. If the coke is to be used for anode
manufacturing, however, caution must be exercised. The usual calcination
temperature (1370° to 1425°C, or 2500° to 2600°F) has no deleterious effect,
but high-temperature calcining (at 1590° to 1650'C, or 2900° to 3000'F) tends
to cause expansion ("popcorning") of coke and to reduce its density. This
effect is just the opposite of the intended purpose-densification. The
expanded coke requires addition of more pitch binder at the bake step.
Moreover, the baked anode becomes porous and brittle, with the deleterious
effect of' increased electrical resistivity and an attendant power requirement
penalty.8
Pitch ordinarily contains about 0.5 percent sulfur; petroleum coke
usually contains 2.5 to 5 percent sulfur but may have as little as 1.5 percent
and as much as 7 percent.8 The sulfur content of coke depends on the
crude stock and the sulfur distribution in the crude, i.e., the tendency of
sulfur to concentrate or not to concentrate in the bottoms and thus in the
coke.
3.7-8
-------
Marketing factors related to availability of low-sulfur coke are extremely
complicated and uncertain, and the trend appears to be toward coke with
higher sulfur content; however, it is reported that for the near term, coke
containing 3 percent sulfur or less should be available. One petroleum coke
manufacturer indicates that very little low-sulfur coke (2.5 percent or less) is
now available, that 4 to 5 percent coke is abundant, and that low-sulfur coke
(when available) commands a price four to five times that of the high-sulfur
coke.
3.7.4 Emission Limits
3.7.4.1 New Source Performance Standards (NSPS) Limits-
No NSPS limitations are applicable to SO? emissions from anode bake oven
and electrolytic reduction cell facilities at primary aluminum plants.
3.7.4.2 State Implementation Plan (SIP) Limits--
No SIP contains SC^ emission limitations that pertain specifically to anode
bake oven or electrolytic reduction cell operations. Such limitations are
embodied in general regulations intended to limit SO2 emissions from process
sources. The most frequent SIP limitation on process sources limits emissions
to no greater than 500 ppm S02 on a volume basis. The most stringent
limitation is Regulation No. 2, Sec. 3122 of the Bay Area Air Pollution Control
District, San Francisco, which provides that SG>2 emissions shall not exceed
300 ppm. Because the volumes of exhaust from VSS, HSS, and PB plants are
variable, it is difficult to judge compliance with a 300-ppm limitation. Limited
stack test data indicate, however, that SO9 concentrations in uncontrolled
c.t
exhaust from reduction cells and anode bake ovens remain below this level
without the use of control equipment specifically designed for SO2 removal.
3.7.4.3 Achieved-in-Practice (AIP) Limits—
As mentioned earlier, no FGD systems specifically designed for SO,,
control on HSS, VSS, and PB pot lines have been installed at primary alum-
inum plants in the United States. At a VSS plant the wet systems used to
control particulate and fluoride reportedly also capture 70 percent of the SO?
3.7-9
-------
in the primary exhaust and 45 percent of the SO2 in the secondary (roof)
system. (Emissions are approximately 6.3 kg/Mg or 12.6 Ib/ton, with a basis
of 2 percent sulfur coke. )
One aluminum producer reportedly will install FGD systems at two VSS
plants.3'6 The proposed system will consist of a wet scrubber following a
dry fluoride/particulate control device serving the pot exhaust and an exist-
ing wet scrubber for secondary (roof) emissions. With changes in cell tech-
nology, 95 percent capture and transport of cell emissions to the primary
system (5 percent to secondary system), and attentive cell operational
procedures, it is expected that overall SO2 control efficiency will be about 84
percent. Resultant SO2 emissions, based on use of 2.8 percent sulfur coke
(and an alumina sulfur content of 0.045 percent), are projected to be 4.1
kg/Mg (8.1 Ib/ton). The installation is in response to a PSD-BACT deter-
mination that gave approval subject to an emission limitation of 9.5 kg/Mg (19
Ib SO2/ton).6
No achieved-in-practice information was discovered relative to ancillary
control of SO2 by wet fluoride/particulate control systems on PB, HSS, or
anode bake plants. Several PSD-BACT review determinations on PB plants
have been approved with an SO2 limitation based on 3 percent sulfur in the
coke. In the absence of other specific information, the achieved-in-practice
limitations are those values given in Section 3.7.2, Emissions.
In summary, for both anode bake ovens and reduction cells, the applied
controls based on wet methods were designed and installed for the primary
purpose of controlling fluoride and particulates; reduction of SO2 emissions is
generally secondary and incidental; emission measurements are oriented toward
fluoride/particulates; and SO2 emissions are largely unreported. Because SO2
emissions are directly related to sulfur content of the coke, the best achieved-
in-practice levels are usually use of low-sulfur coke rather than application of
control technology.
3.7.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
3.7-10
-------
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change freguently. Since LAER is
near the vanguard of control technology, a more detailed analysis particularly
is necessary when addressing modified or reconstructed facilities subject to
the provisions of Section 173 of the Clean Air Act. Emission limitations reason-
able for new sources may in some instances be economically or technically
unreasonable when applied to modified or reconstructed sources of the same
type.
No NSPS limitations are applicable to sulfur dioxide emissions from either
anode bake ovens or reduction cell pot lines at primary aluminum plants.
Limited stack test data indicate that uncontrolled emissions are within the
most stringent limitation embodied in a State Implementation Plan. For both
anode bake oven and reduction cell emissions, the achieved-in-practice levels
are highly variable and depend primarily on the coke sulfur content. Emis-
sion data are insufficient, particularly for anode bake ovens or HSS or PB
cell plants, to allow definition with any degree of confidence of a best achieved
-in-practice level.
The most practical method of limiting SO2 emissions from primary alumi-
num plants is to utilize low-sulfur materials in the anodes. The sulfur
content of coke is directly related to the guality of the crude from which it is
produced. Supplies of 3 percent sulfur coke derived largely from domestic
crude are expected to be available for the next 5 to 10 years. Since future
supplies of coke will depend primarily on foreign crudes, the future avail-
ability of low-sulfur coke is uncertain. Given the domestic dependence on
and the competing demands for various petroleum products, it is unadvisable
to suggest a single value that would purport to represent LAER when the
determining emission parameter—coke sulfur content—is uncertain.
3.7-11
-------
It is appropriate to suggest factors to be considered in deriving LAER
once a specific case is in hand and the unknowns are resolved. The fol-
lowing are therefore presented as general guidance to be considered in deter-
mining LAER for SO2 emissions from primary aluminum reduction plants.
3.7.5.1 Sulfur-in-Coke Limitation--
For all plant types consider a limitation on sulfur content in coke that
reflects the lowest-sulfur coke available. The limitation should allow no
greater than 3 percent sulfur in coke and lesser-sulfur coke should be
required unless it can be adequately demonstrated that it is not available.
Coke blending should be considered where supplies of low-sulfur coke are
available but limited in quantity.
3.7.5.2 Application of FGD--
Consider the application of FGD on a case-by-case basis, [n examining
the merits of applying FGD technology to aluminum reduction plant emissions
the following general observations are worthy of consideration:
At this time FGD systems have not been applied to primary aluminum
plant facilities for the sole and specific purpose of SO2 control. Wet systems
installed for particulate arid fluoride control at a VSS plant have, however,
reportedly effected a 70 percent SO2 removal in the secondary system. In
addition, proposed FGD systems at two VSS plants are to be installed as a
result of BACT determinations and are expected to provide an overall SO2
control efficiency of approximately 84 percent. The use of FGD appears to be
technically feasible at aluminum reduction plants, although costs are expected
to be high compared with those associated with FGD use at power plants.
Because of the lower exhaust volumes and higher SO2 concentrations
resulting from coke of a given sulfur content, FGD is more readily applicable
to VSS than to HSS or prebake facilities. The larger exhaust volumes and
attendant dilute SO2 concentrations at HSS and PB plants would necessitate
much larger FGD system capacity than for a VSS plant. New plants are
expected to be of the PB type.
3.7-12
-------
Wet systems used to control particulates and fluorides may be utilized to
achieve SO9 control as well. Where wet systems cannot be adapted to achieve
£j
adequate SO2 control, two systems could be used to satisfy LAER and NSPS
limitations. Depending on the sulfur content of the coke used and the
resultant SO2 emission rate, consideration could be given to specifying a
LAER limitation that could be met by excellent capture and FGD treatment of
primary emissions only. In such case neither the secondary emissions from
reduction cells nor the bake plant emissions would require FGD treatment.
Wet scrubber effluent must be handled in a manner that conforms with
wastewater treatment standards and water quality requirements.
Costs associated with installation of FGD systems and attendant waste-
water treatment facilities would exercise economic constraints on the viability
of constructing a new (modified) primary aluminum reduction facility.
3.7-13
-------
REFERENCES
1. Background Information for Standards of Performance: Pri-
mary Aluminum Industry, Volume 1: Proposed Standards. EPA
450/2-74-020a. U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina. October 1974.
2. Singmaster and Breyer. Air Pollution Control in the Alumi-
num Industry, Volume I. Contract No. CAP-70-21, Environ-
mental Protection Agency. July 23, 1973.
3. Personal communication with Fred Fenske, Washington State
Department of Ecology, May 10-11, 1978.
4. Personal communication with Paul Boys, Region X, U.S. Envi-
ronmental Protection Agency, April 13, 1978.
5. PEDCo Environmental, Inc. Summary Reports on SC^ Control
Systems for Industrial Combustion and Process Sources -
Volumes I and IV. Industrial Environmental Research Labor-
atory, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina. December 1977.
6. Final Determination Analysis Document; Prevention of Signif-
icant Deterioration, Approval of Modifications to Martin
Marietta Aluminum Plants. Region X, iJ.S. Environmental Pro-
tection Agency. January 11, 1977.
7. Internal Memo - Office of Air Quality Planning and Stan-
dards, Research Triangle Park, North Carolina. Reid Iverson
to Gordon Rapier re: Determination of BACT for S02 Emissions
from Primary Aluminum Plant. December 19, 1977.
8. Personal communication with Richard Albrecht, Sohio, Cleve-
land, Ohio, April 12, 1978.
3.7-14
-------
3 8 MAJOR SOURCE CATEGORY: BULK GASOLINE TERMINALS TRUCK
LOADING OPERATIONS—VOLATILE ORGANIC COMPOUNDS (VOC)
3.8.1 Process Description
Gasoline and other liquid petroleum products are distributed
from the refinery to the consumer by an extensive network of
pipelines, tank trucks, railroad tank cars, and marine tankers or
barges. The bulk gasoline terminal is an integral part of this
network, serving as the primary storage and distribution facility
for a regional marketing area. Within this area it provides
products to smaller but similar distribution facilities, called
bulk plants, that serve smaller, localized areas. In this
report, a bulk terminal is defined as a distribution facility
with an average daily gasoline throughput of greater than 76,000
liters (-20,000 gallons) and a bulk plant as one with an average
daily gasoline throughput of 76,000 liters or less. The bulk
terminal receives gasoline by pipeline, ship, rail, or barge;
stores it in tanks; then redistributes it by tank-truck to bulk
plants, commercial accounts, or retail outlets.
Equipment and structures at the typical bulk terminal in-
clude storage tanks, loading (unloading) equipment, liquid lines,
tank trucks, parking and access roadways, and business offices.
The gasoline is usually stored above grade in floating-roof tanks
that have large storage capacities [generally greater than
250,000 liters (65,000 gallons) at new installations]. The
loading facility consists of equipment to meter and deliver
gasoline into tank trucks from the storage tanks. It is located
at a central island (loading rack) accessible to tank trucks.
The loading rack may be at grade level to accommodate bottom
filling of tank-trucks or above grade for loading through top
hatches. Liquid lines provide the link between storage tanks,
the loading rack, and the tank truck. This guidance pertains to
emissions of voltaile organic compounds (VOC) during the truck
loading operations at bulk terminals.
3.8-1
-------
3.8.2 Emissions
Volatile organic compound emissions at bulk terminals can
occur from storage tanks when the contents are at rest, during
transfer (loading) of gasoline from storage tank into tank truck,
from the tank truck, and at points along the gasoline liquid or
vapor plumbing lines. Evaporative emissions from these sources
are categorized as standing storage or "breathing" loss, liquid
transfer or "working" loss, and miscellaneous or "fugitive" loss.
VOC emissions from storage tanks are discussed in Section 3.10,
"Gasoline and Crude Oil Storage."
Working loss from tank trucks results from the active move-
ment of liquids, most commonly when vapors are displaced from" a
vessel as liquid is added. Working loss includes both filling
and emptying or drainage losses, i.e., the vapors displaced
during filling and those generated after draining by the inter-
action of residual liquid and the air introduced into the vessel.
The quantity and composition of emissions are related to the
physical and chemical characteristics of the old (residual) and
the new (loading) cargo; the rate and amount of unloading and
loading; leakage from the vessels; the liquid lines and their
connections and fittings; temperature differentials between
vessels and liquids; and, most importantly, the loading method,
whether splash or submerged fill.
Figure 3.8-1 depicts the several tank truck loading methods:
overhead, either by splash- or submerged-fill pipe, and bottom
fill. Top-splash fill generates relatively greater amounts of
vapors because of turbulence and the opportunity for contact of
vapor, air, and liquid during the liquid free-fall. Both sub-
merged fill, wherein the fill tube is always near or below the
liquid level, and bottom fill, wherein the inflow is always below
the liquid surface, minimize vapor generation, turbulence, and
VOC emission.
Fugitive losses, largely preventable, result from improper
operation and maintenance, faulty equipment, and human error.
3.8-2
-------
U)
oo
I
LEGEND:
4
SPLASH
— TOP LOADING-
f
CLOSED !
HATCH 'VAPOR VENT
SUBMERGED PIPE
y
sr
S*
8
-. 1
U* 1 * "
jl\ | VAPOR ZONE \ 1
TO | I
j
1 L10UID ZONE ,
1 - XX I
^r- 4
** /
•*~ /
/
. ,
-4-
-••^ ^*" *
r
.s
•^_
LIQUID LEVEL
Y
< 15 cm (6 in.)
->• LIQUID FLOW
BOTTOM LOADING
+- VAPOR FLOW
3.8-1. Loading methods.
-------
Such losses include leaks from liquid and vapor lines, connec-
tions, hatch covers, and fittings- caused by improper mating or
deterioration of components; defective or maladjusted sensors and
relief valves; vessel overfills; open hatches; backflow and
drainage; and similar losses.
Typical values for uncontrolled emissions from truck loading
of gasoline at bulk terminals are presented in Table 3.8-1. The
emission values do not include fugitive emissions due to inept
loading or faulty equipment.
3.8.3 Control Measures
Effective control of tank-truck loading operations at bulk
terminals includes measures to suppress vapor generation; a
vaportight and properly sized system for capturing, collecting,
and conveying the vapors; and an efficient means of vapor dis-
posal. Such measures, together with design features that enhance
vapor capture, disposal, and spill prevention; good operational
procedures; preventive maintenance practices; and attentive
housekeeping provide effective control.
The use of submerged fill rather than splash loading reduces
vapor generation by approximately 58 percent. Of the two sub-
merged-fill methods, bottom loading is preferred over a sub-
merged-fill pipe because the installation is much simpler, the
inflowing gasoline is always below the liquid level, and the
independent vapor extraction and gasoline filler lines facilitate
vapor collection.
The vapor collection system captures the vapors and conveys
them to a vapor processing system. The system must be maintained
vaportight throughout, with particular attention to leak-prone
points such as top-hatch closures, vapor holders, knockout (con-
densate) tanks, backflow valves, and pressure-vacuum relief
valves. Proper setting of fill meters and valves is important,
particularly during rapid loading. The system should incorporate
3.8-4
-------
TABLE 3.8-1. HYDROCARBON EMISSION FACTORS .
FOR LOADING GASOLINE INTO TANK CARS AND TRUCKS*
Emission source
Emission factor
Submerged loading—normal service
lb/103 gal transferred
kg/103 liters transferred
Splash loading—normal service
lb/103 gal transferred
kg/103 liters transferred
Submerged loading—balance service
lb/103 gal transferred
kg/103 liters transferred
Splash loading—balance service
lb/103 gal transferred
kg/103 liters transferred
5.0
0.6
12.0
1.4
8.0
1.0
8.0
1.0
Reference 1, p. 4.4-8.
b The gasoline used in this example has a Reid vapor pressure of
10 psia.
0 Emission factors are calculated for a dispensed fuel
temperature of 60°F.
3.8-5
-------
design features that prevent vapor backflow (drainage) when
connections are removed, maintain a vaportight connection as the
tank vehicle settles with increasing load, and eliminate the need
for open "topping," i.e., visual observation as liquid level is
adjusted to tank capacity. Gasoline loading lines should incor-
porate similar features to prevent liquid leaks and drainage
spills. Tests at bulk terminals have shown that 30 to 70 percent
2
of the vapors can escape capture at the truck.
A recent EPA publication on reasonably available control
technology (RACT) states the importance of maintaining vapor- and
liquid-tight systems and the techniques for detecting, control-
ling, and minimizing leaks from tank trucks and vapor collection
systems. This publication defines leak-tight conditions for
RACT; describes compliance test methods and procedures for ascer-
taining the degree of leak-tightness and for detecting leaks; and
suggests useful record keeping, inspection, and reporting methods
for ensuring that leak-tight conditions are maintained. The
equipment performance criteria and the regulation recommended in
this publication are briefly discussed below.
Both the compliance test procedure and the recommended
regulation in this publication define a "leak-tight condition" as
one that is equivalent to 99 percent capture efficiency during
vapor transfer from a truck tank. The publication points out
that this capture efficiency will decrease because some sources
(e.g., pressure and vacuum valves and hatch seals) may leak
shortly after maintenance. The suggested control approach of the
publication is to encourage more frequent and effective mainte-
nance procedures and adherence to the test and monitoring proce-
dures described below. The recommended regulation states that
gasoline tank trucks and their vapor collection systems (which
are tested annually) should not sustain a pressure change of more
than 750 pascals (3 in. of water) in 5 minutes when pressurized
to 4500 pascals (18 in. of water) or evacuated to 1500 pascals (6
in. of water). For tank trucks and vapor collection systems, a
combustible gas detector is used as a monitoring procedure to
3.8-6
-------
ascertain leak-tightness. During loading operations, the recommended regu-
lation requires that no reading be greater than or equal to 100 percent of the
lower explosive limit (LEL, measured as propane) at 2.5 cm (1 in.) around
the perimeter of a potential leak source in the system. (The vapor collection
system includes all piping, seals, hose connections, pressure-vacuum vents,
and other possible leak sources between the truck and the vapor processing
unit and/or the storage tanks and vapor holder.)
The recommended regulation further requires that the vapor collection
and vapor processing system be designed and operated to prevent gauge
pressure in the tank truck from exceeding 4500 pascals (18 in. of water) and
prevent vacuum from exceeding 1500 pascals (6 in. of water). No visible
liquid leaks that can be avoided are allowed from either the tank truck or the
vapor collection system.
Two general types of vapor processing systems are applicable to bulk
terminal truck loading: systems that thermally destroy the vapors, and
systems that recover the vapors as useful product. It is emphasized that the
values for mass emission rates at the outlet of the vapor processing units
discussed below will vary with the leak-tight condition of the tank trucks and
vapor piping.
Thermal oxidizers (destructors, afterburners, or incinerators) are com-
monly used at some industrial processes for the control of combustible aero-
sols, vapors, gases, and odors. At gasoline terminals the thermal oxidizer
(TO) converts gasoline vapors to essentially carbon dioxide and water rather
than recovering them as liquid gasoline. The most effective type of TO unit
consists of a vapor holder, propane tank, burner (flare), and associated
piping. Gasoline vapors are directed to the vapor holder, where propane is
added when necessary to maintain the VOC/air ratio above the flammability
limit. Vapors are drawn from the vapor holder, pass through the burner,
mix with metered air, and are combusted. Later models of TO systems do not
require a vapor holder; the vapors from tank trucks are vented directly to
the TO unit. Requisite safety features include flashback and safety interlock
flame guards and automatic malfunction shutdown; heat recovery is optional.
The TO units have been used for the destruction of VOC vapors from bulk
3.8-7
-------
terminal operations. The EPA test results on four TO units—two with vapor
holders and two without--indicated average mass emission rates at the outlet
of 8.7, 1.3, 28.5 and 31 mg/liter loaded.4'8
Vapor recovery systems used at bulk terminals include those employing
compression-refrigeration-absorption (CRA), compression-refrigeration-conden-
sation (CRC), straight refrigeration (RF), and carbon adsorption (CA). The
technology of these systems is well understood; the reliability and control
efficiencies are good and are being improved.
The CRA unit is based on the absorption of gasoline vapors under
pressure with cool gasoline from storage. The system generally includes a
saturator, vaposphere, chilled gasoline absorber, compressor, pumps, and
instrumentation. Incoming vapors are passed through the saturator and
sprayed with gasoline as a safety measure to ensure that the vapor concen-
tration is above the explosive level. The vapors are then compressed,
cooled, and passed to the absorber, where they are brought into contact with
chilled gasoline. The bottoms from the absorber containing gasoline and the
absorbed vapors are returned to storage, and the remaining air is vented to
the atmosphere. The EPA test results on four CRA units indicated average
mass emission rates at the outlet of 59, 43, 40, and 31 mg/liter of gasoline
Q-13
loaded. 1J
The straight refrigeration (RF) system condenses vapors by refrigeration
at atmospheric (ambient) pressure. Since vapors are treated on demand, no
vapor holder is required. The vapors are fed directly to the condenser,
cooled to minus 73°C (minus 100°F), and condensed. Condensate is with-
drawn from the condenser bottom and air is vented from the top. The stored
brine is cooled by a two-stage refrigeration unit. Cooling for condenser coils
is supplied by methyl chloride. The EPA test results on three RF units
indicated average mass emission rates at the outlet of 63, 37, and 34 mg/liter
14-17
of gasoline loaded.
Carbon adsorption (CA) systems are based on the affinity of activated
carbon for hydrocarbon vapors. Equipment consists of twin activated carbon
beds, a vacuum regeneration unit, a condenser-separator, and pumps. Inlet
vapors are passed through a carbon bed, the gasoline vapor is adsorbed on
3.8-8
-------
the activated carbon, and air is vented to the atmosphere. The adsorbed
vapors are then vacuum-stripped and passed to the condenser-separator.
The recovered gasoline is pumped to storage. The air and any remaining
hydrocarbons are recycled from the condenser-separator through the carbon
bed to the atmosphere. During operation one carbon bed is in the adsorption
cycle and one is in the desorbtion or regeneration cycle. The EPA test
results on two CA units indicated average mass emission rates at the outlet
(during normal periods of operation*) of 3, 10, and 2 mg/liter of gasoline
loaded.18"20
3.8.4 Emission Limits
3.8.4.1 New Source Performance Standards (NSPS) Limits--
No NSPS are applicable to VOC emissions from the loading of tank trucks
at bulk gasoline terminals.
3.8.4.2 State Implementation Plan (SIP) Limits—
Air pollution control regulations of some state and local agencies contain
provisions specifically applicable to'gasoline transfer operations. Table 3.8-2
lists major provisions of the more restrictive of such regulations as they
apply to gasoline loading at bulk terminals.
The emission rates during abnormal unit operations were not cal-
culated for the average mass emission rate at the outlet; e.g.,
emission rates during incorrect timer settings (Reference 18),
and while the unit was purposely overloaded (Reference 19).
3.8-9
-------
TABLE 3.8-2. STATE IMPLEMENTATION PLAN (SIP) REQUIREMENTS.
APPLICABLE TO GASOLINE LOADING OPERATIONS OF BULK TERMINALS'
SIP agency
Regulatory requirement
California
San Francisco Bay
area
South Coast
Colorado
New Mexico
Alburquerque
Missouri
St. Louis
Organic emissions with vapor pressure
greater than 10.3 kPa (1.5 psia) shall
be reduced by at least 90% of the amount that
would be emitted without controls.
Submerged fill pipe.
Vapor collection and disposal system or
equal required; vapor disposal system
(if absorber or condensation system)
must recover 90% by weight of vapors.
Vapor collection and disposal system or
equal required; drainage prevention;
vaportight lines at. all times; all vapors
to vapor recovery or disposal unit;
final emissions not to exceed 0.155
kg/liter (1.24 lb/103 gal) loaded.
Similar to Colorado regulations.
Vapor recovery system or equal required;
adsorber, condensation, or equal systems
must limit discharge of hydrocarbons to
0.5 g/gal (0.13 kg/kl or 1.1
lb/103 gal) loaded.
a Gasoline loading facilities having an average daily through-
put greater than 76,000 liters (20,000 gal).
b The 90 percent requirement in the California area regulations
would be approximately equivalent to an emission limit of
0.14 kg/kl (1.2 lb/103 gal), i.e., (1-0..9) x uncontrolled
VOC emission factor of 1.4 kg/kl (12 lb/103 gal).
3.8-10
-------
Table 3.8-2 illustrates the similarity of formats and emission limitations in
SIP regulations. The most stringent limitation is that of Missouri for the St.
Louis area, which requires that vapor recovery system or equal be provided,
displaced vapors be vented to vapor recovery system, drainage spill be
prevented, and the vapor disposal system meet an emission limit of 130
mg/liter (1.1 lb/103 gal). Some state SIP regulations are presently being
revised to reflect the stricter requirements (an emission limit of 80 mg/liter
loaded) achievable with RACT.
3.8.4.3 Achieved-in-Practice (AIP) Limits--
Available test data indicate the control efficiency achieved in practice
with some types of TO and CA units approaches 99.9 percent. Slightly lower
control efficiencies have been reported for other vapor recovery units. It is
emphasized that these values pertain to the emission reduction across the
control device only and therefore assume 100 percent collection and transport
of vapors to the disposal unit—a condition that has not been observed in
practice.
3.8.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
3.8-11
-------
No NSPS limitations are applicable to VOC emissions from tank-truck
loading at bulk gasoline terminals. The most stringent SIP imposes an
emission limit of 130 mg/liter (1.1 lb/103 gal) loaded. Emission values less
than this SIP limitation have been achieved in practice.
LAER for tank-truck loading operations at bulk terminals is determined
to be an emission limit of 30 mg/liter (0.25 lb/10 gal) of gasoline loaded and
reguires an overall system efficiency of 97 percent. On the basis of EPA
emission test data, this value appears achievable with thermal oxidizer,
carbon adsorption, or other vapor recovery units operated at optimal effi-
ciency in conjunction with a highly effective capture-collection system that
provides virtually leakproof transport of vapors to the control unit.
It should be emphasized that effective vapor collection and leak-tight
delivery to the processing unit are required to maintain the integrity of the
vapor control system and to minimize VOC emissions. The RACT performance
criteria, compliance test methods, and other related requirements are recom-
mended for attaining and maintaining a leak-tight system.
The following measures are designed to reduce or preclude VOC
emissions and to support LAER controls.
1. System design features that provide vaportight connec-
tions at all times, incorporate closed hatch "topping,"
accomodate vehicle settling, prevent venting of the
relief valve during loading at maximum rate, prevent
all backflow or drainage when connections are made or
disengaged, and provide maximum legal release pressure
for all relief valves.
2. Supervised standard operating practices that curtail
VOC loss due to poor housekeeping and/or operating
procedures. Examples of poor operating practices
include excessive fill rates that increase vapor gen-
eration and pressures, improper setting of fill meters
(causing overfills), careless or improper connections,
improperly set pressure/vacuum relief valves, and open
hatches.
3. Supervised programs of preventive maintenance and
scheduled inspections with the objective of maintaining
liquid- and vapor-tight systems, preventing leaks in
liquid/vapor plumbing and fittings, and repairing or
replacing defective or malfunctioning hardware.
3.8-12
-------
REFERENCES
1 Supplement No. 7 for Compilation of Air Pollution Emission
Factors, Second Edition. Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency. April
1977.
2 Control of Hydrocarbons from Tank Truck Gasoline Loading
Terminals, Guidelines Series. EPA-450/2-77-026, Office of
Air Quality Planning and Standards, U.S. Environmental
Protection Agency. October 1977. pp. 2-3.
3. Control of Volatile Organic Compound Leaks from Gasoline
Tank Trucks and Vapor Collection Systems, EPA-450/2-78-051,
Office of Air Quality Planning and Standards No. 1.2-119,
U.S. Environmental Protection Agency, Research Triangle
Park, N.C. December 1978.
4. EPA-450/2-77-026, Table 3-2. pp. 3-5.
5. Report on Performance Test of Vapor Control System at the
AMOCO Terminal, Baltimore, Maryland. Contract No.
68-01-4145, Task 12, U.S. Environmental Protection Agency,
Region III and Division of Stationary Source Enforcement.
September 1978.
6. Demonstration of Reduced Hydrocarbon Emissions from Gasoline
Loading Terminals. EPA-650/2-75-042, Office of Research and
Development, U.S. Environmental Protection Agency. June
1975. Table VI, p. 18.
7. Report on Performance Test of Vapor Control System at
Belvoir Terminal, Newington, Virginia. Contract No.
68_0i-4145, Task 12, U.S. Environmental Protection Agency,
Region III and Division of Stationary Source Enforcement.
September 1978.
8. Air Pollution Emission Test. Project No. 78-BEZ-5, Office
of Air Quality Planning and Standards, Emission Standards
and Engineering Division, Emission Measurement Branch, U.S.
Environmental Protection Agency. May 12, 1978.
3.8-13
-------
9. EPA-450/2-77-026, Table 3-2. pp. 3-5.
10. Report on Performance Test of Vapor Control System at Crown
Central Terminal, Baltimore, Maryland. Contract No.
68-01-4145, Task 12, U.S. Environmental Protection Agency,
Region III and Division of Stationary Source Enforcement.
September 1978.
11. Air Pollution Emission Test. Project No. 76-GAS-17, Office
of Air Quality Planning and Standards, Emission Standards
and Engineering Division, Emission Measurement Branch, U.S.
Environmental Protection Agency. September 1976.
12. Report on Performance Test of Vapor Control System at Texaco
Terminal, Coraoplis, Pennsylvania. Contract No. 68-01-4145,
Task 12, U.S. Environmental Protection Agency, Region III
and Division of Stationary Source Enforcement. September
1978.
13. Air Pollution Emission Test. Project No. 75-GAS-10, Office
of Air Quality Planning and Standards, Emission Standards
and Engineering Division, Emission Measurement Branch, U.S.
Environmental Protection Agency. December 1974.
14. EPA-450/2-77-026, Table 3-2. pp. 3-5.
15. Air Pollution Emission Test. Project No. 77-GAS-18, Office
of Air Quality Planning and Standards, Emission Standards
and Engineering Division, Emission Branch, U.S.
Environmental Protection Agency. November 1976.
16. Air Pollution Emission Test. Project No. 75-GAS-8, Office
of Air Quality Planning and Standards, Emission Standards
and Engineering Division, Emission Measurement Branch, U.S.
Environmental Protection Agency. December 1975.
17. Air Pollution Emission Test. Project No. 76-GAS-16, Office
of Air Quality Planning and Standards, Emission Standards
and Engineering Division, Emission Measurement Branch, U.S.
Environmental Protection Agency. September 1976.
18. Air Pollution Emission Test. Project No. 77-GAS-19, Office
of Air Quality Planning and Standards, Emission Standards
and Engineering Division, Emission Measurement Branch, U.S.
Environmental Protection Agency. October 1977.
3.8-14
-------
19. Report on Performance Test of Vapor Control System at
Phillips Fuel Terminal, Hackensack, New Jersey, Draft
Report. Contract No. 68-01-4145, Task 12, U.S.
Environmental Protection Agency, Region II and Division of
Stationary Source Enforcement, January 1979.
20. Report on Performance Test of Vapor Control System at
British Petroleum Terminal, Finksburg, Maryland. Contract
No. 68-01-4145, Task 12, U.S. Environmental Protection
Agency, Region III and Division of Stationary Source
Enforcement. September 1978.
3.8-15
-------
-------
3.9 MAJOR SOURCE CATEGORY: FLAT WOOD PANELING--VOLATILE
ORGANIC COMPOUNDS (VOC) EMISSIONS
Flat wood products include a variety of materials such as plywood,
particleboard, hardboard, panelboard, fiberboard, insulation board, and
molding. In 1976 approximately 640 flat wood plants were in operation; 247 of
these were hardwood plywood and 240 were softwood plywood plants.
Plants that apply coatings to their wood products generate emissions of
volatile organic compounds (VOC), which is the subject of this section. On
the basis of membership in national associations of flat wood producers, it is
estimated that 40 percent of hardwood plywood plants, 10 percent of the
softwood plywood plants, and under 15 percent of the particleboard plants
apply coatings. For this reason, the major emphasis in this guidance is
directed toward the hardwood plywood industry. It is intended to apply to
printed interior wall panels made from hardwood plywood and thin particle-
board, natural finish hardwood plywood panels, and Class II finishes for
hardboard paneling. Segments of the flat wood products industry not
addressed are exterior siding, tileboard, and particleboard used as a furni-
ture component.
3.9.1 Process Description
Figure 3.9-1 is a general flow diagram of flat wood coating processes
utilizing conventional coatings with organic solvents. As the diagram indi-
cates, the first operation has an optional step, the sanding of particleboard
before it enters the brushing unit. All other flat wood products go directly
to the brushing operation. After the brushing operation, the stock is
directed to a reverse-roll coater for filler application. Normally, filler is not
2
applied to hardboard before the application of a base coat. If the panel is
not to be filled, it bypasses the filler and drying oven and proceeds to a
direct-roll coater for application of a sealer or first base coat. Drying ovens
can be gas-fired or electrically heated. If ultraviolet-curable coatings
(commonly called UV coatings) are applied, a UV oven is used for curing.
3.9-1
-------
FILLER
OJ
>£>
I
OFF-
T.OADING
SEALER OR FIRST
BASE COAT
FIRST BASE COAT
OR
SECOND PASE COAT
PRINT
Figure 3.9-1. General process flow.
-------
The most common flat wood products coated by the industry are ply-
wood, particleboard, and hardboard. A few plants coat pine and cedar
siding. Coatings that can be factory-applied include filler, sealer, base coat,
ink, and topcoat. Fillers are used to fill voids and cracks in the wood to
provide a smooth surface. Sealers seal off pores and substances in the wood
that may affect subsequent finishes. Base coats are used as the primary
coating/coloring of the panels, and inks are used only for decorative or
simulated grain panels. Topcoats provide both a protective coating and a
finished appearance. Not all factory-prefinished wood products undergo the
complete series of coatings. For instance, a sealer is not required after the
application of certain fillers; also, some builders are losing interest in top-
coat-finished materials because they damage easily during installation.
Following application of the sealer or first base coat, a second direct-roll
coater is used to apply an initial or a second base coat to the panel. The
filled, sealed, base-coated board can be shipped as is after drying, or it can
be given wood grain or topcoats. The grainprinter is a direct-roll coater.
Usually, three or four such printers are used in series to provide different
colors of grain. After it is printed, the panel goes through a direct-roll
coater or a curtain coater (often used by plywood coating plants) to receive a
protective coat. The panel then goes through a drying oven for curing
before shipment.
Similar processes are used by plants with waterborne coating systems.
The main differences are longer ovens, lower operating rates, or higher oven
temperatures (for proper curing).
Among the several methods of applying coatings to flat wood, the pre-
ferred ones are roll coating and curtain coating. In roll coating (Figure
3.9-2) the coating material is applied to the wood by cylindrical rollers. If
the cylinder rotates in the same direction as panel movement, the applicator is
called a direct-roll coater, generally used to apply base coat, print, and top-
coat. If the cylinder rotates in the opposite direction of panel movement
(reverse-roll coater), the coating is forced into voids and cracks in the
panels, fills these depressions, and provides a smooth surface.
3.9-3
-------
In curtain coating (Figure 3.9-3), used mostly for topcoating, the
coating material forms a curtain through which the panel passes. Coating
material is metered into a pressure head and is forced through a calibrated
slit between two knives to form a continuous, uniform curtain. The rate of
panel movement determines the coating thickness. All excess coating is
caught in a trough and recirculated.
3.9.2 Emissions
Volatile organic compounds are emitted by the evaporation of volatile
organic solvents used in conventional coatings applied to flat wood products.
Small quantities of dust and smoke also may be emitted to the atmosphere.
3.9.2.1 Nationwide Emissions--
No more than one-quarter of the U.S. plants that turn out flat wood
products apply coatings. Most of these are primarily hardwood plywood
plants, and in some cases they coat only a small percentage of production.
In 1975 the total VOC emissions from all flat wood plants was estimated
to be 67,000 Mg (74,000 tons). This estimate is based on annual coating
•3 c o
usage of 132 Mm (35 x 10 gal), an average emission factor of 0.5 kg
VOC/liter (4.2 Ib/gal) of coating, and no emission control. In the same
year, VOC emissions from stationary and automotive sources were estimated to
be 17.3 Tg (19 x 106 tons) and 10.8 Tg (12 x 106 tons).5 Therefore, VOC
emissions from flat wood products manufacturing account for less than 0.4
percent of emissions from stationary sources, or about 0.2 percent of all VOC
emissions.
3.9.2.2 Sources and Quantity of VOC Emissions --
Emissions of volatile organic solvents at flat wood coating plants occur
primarily at the coating lines. Oven exhausts are discrete point sources, and
coaters and rollers are termed fugitive emission sources. Solvents used in
organic-based coatings are normally multicomponent mixtures that may include
methyl ethyl ketone, methyl isobutyl ketone, toluene, xylene, butyl acetates,
propanol, ethanol, butanol, VM and P naphtha, methanol, amyl acetate,
3.9-4
-------
COATING
APPLICATOR
(a)
APPLICATOR
ROLL
COATING
PANEL
(b)
(ARROWS SHOW DIRECTION OF ROLLER AND PANEL
MOVEMENTS)
Figure 3.9-2. Simplified schematic of roll coaters. (a) direct-
roll coater, (b) reverse-roll coater.
3.9-5
-------
COATING
RESERVOIR
Figure 3.9-3. Pressure head curtain coater,
3.9-6
-------
mineral spirits, SoCal I and II, glycols, and glycol ethers. Organic solvents
most often used in waterborne coatings are glycol, glycol ethers (such as
butyl cellosolve), propanol, and butanol. Contents of volatile organics in the
different types of conventional coatings supplied to the flat wood coating
industry are shown in Table 3.9-1 with estimated emission factors. The
composition of the solvent determines the type of VOC emitted. Waterborne
coatings are discussed under control measures.
3.9.2.3 Factors Influencing VOC Emissions--
Table 3.9-2 lists the common organic solvents used in conventional
coatings and their vapor pressures and relative evaporation rates. The
evaporation rate indicates the rate of VOC emissions relative to each com-
pound. For example, ethanol evaporates three times faster than iso-butanol
at constant temperature, pressure, and humidity. Coating mixtures contain a
number of these solvents and vary with each operation (filling, sealing, base
coating, topcoating) and plant. The VOC emissions from each operation and
plant therefore vary widely in mass rate per unit production, in mass rate
per unit weight of coating used, and in concentration. In addition, the
distribution of solvent emissions from solvent mixing, handling, and
application (workroom emissions exhausted through roof vents and windows),
and from drying ovens (point sources) can vary widely. For example, a
plant that uses highly volatile solvents such as methanol, ethanol, and methyl
ethyl ketone will emit much greater amounts of VOC through roof vents and
windows (say 70 percent) than through drying oven exhaust (say 30
percent). In contrast, a plant that uses relatively low-volatility solvents
such as amyl acetate, butanol, and VM and P naphtha will emit much less
VOC from handling, mixing, and application (say 20 percent) than from
drying oven exhaust (say 80 percent). The first example is probably the
more typical.
3.9.2.4 Summary--
Table 3.9-3 presents estimates of potential VOC emissions from each
Q
operation using conventional coatings. At plants applying filler, sealer,
3.9-7
-------
U)
I
oo
1.9-1. VOC CONTENT OF CONVENTIONAL FLAT WOOD COATINGS3
J. t\D .i-U-J —
Paint type
Filler
Sealer
Base coat
Grain ink
Topcoat
Number
of companies
4
3
7
6
8
Density ,
kg/liter
1.7
1.1
1.4
1.2
1.1
(Ib/gal)
(14.5)
(9)
(11.5)
(10)
(8.8)
Volatile
weight
15 -
15 -
40 -
30 -
50 -
organics ,
percent
30
50
75
70
75
a Source: Miscellaneous paint companies and Mr. Martin Kay, South Coast Air Quality
Management District California. Reference 7.
-------
TABLE 39-2 SOLVENTS USED IN COATINGS AND THEIR VAPOR PRESSURE
AND EVAPORATION RATEb
Compound
Butanol, iso
Butanol, n
Butanol, sec
Ethanol, anhydrous
Propanol, anhydrous
Methanol
Methyl ethyl ketone
Methyl isobutyl ketone
Toluene
Xylene
Butyl acetate, sec
Butyl acetate, iso
Butyl acetate, n
VM and P naphtha
Amyl acetate (primary)
Glycols
Glycol ethers
Vapor pressure,
at 20°C, mm Hg
8.8
4.4
12.7
44.0
31.2
96.0
70.6
16.0
38.0
9.5
4.0
12.5
7.8
2.0
4.0
<0.01
<1.0
Evaporation rate
0.63
0.46
0.90
1.9
1.7
3r"
. 5
4.6
If
. 6
IP
.5
0.75
1r\
. 9
1.45
1f\
. 0
OA r"
. 45
0.4
<0. 01
Relative to that of butyl acetate, 1.0.
3.9-9
-------
TABLE 39-3 POTENTIAL VOC EMISSIONS FROM FLAT WOOD OPERATIONS USING
CONVENTIONAL COATINGS
Operation coating
Filler
Sealer
Base coat
Grain ink
Topcoat
Range of VOC emissions ,
kg/liter
coating
0.26 - 0.53
0.17 - 0.54
0.44 - 1.0
0.36 - 0.84
0.53 - 0.79
Ib/gal
coating
(2.2 - 4.4)
(1.4 - 4.5)
(3.7 - 8.6)
(3.0 - 7.0)
(4.4 - 6.6)
b
Coverage ,
liters/
103m2
119
21
56
7
49
(gal/103ft)
(1.7)
(0.3)
(0.8)
(0.1)
(0.7)
Range of VOC emissions
g/m2 coated
31 - 62
3.6 - 11.3
25 ~ 56
2.5 - 5.9
26 ~ 38.7
.
Total 88 - 174
lb/103ft2
(3.7 - 7.5)
(0.4 - 1.4)
(3.0 - 6.9)
(0.3 - 0.7)
(3.1 - 4.6)
(11 - 21)
*Table 3.9-1 presents typical VOC contents.
DPaint coverage information is from Reference 10.
-------
base coat, grain ink, and topcoat, the estimated VOC emission factor may
range from 88 to 174 g/km2 (11 to 21 lb/1000 ft2) of flat wood coated.
Because the volatile fraction of the coatings contributes essentially 100
percent of the VOC emissions, the total emissions from a plant are essentially
the product of the weight fraction of volatile organics in the coatings and
coating usage. Composition of the VOC emissions depends upon the types of
solvents used. Exhausts from the ovens release practically all of the
incoming volatile compounds, and the fraction of total plant emissions that-
comes from the dryer ovens depends on the types of solvents used, or more
specifically their relative volatility or evaporation rate. Apparently no
emission test data are available.
3.9.3 Control Measures
Technology for reduction of VOC emissions from flat wood operations
includes use of low-solvent, ultraviolet-curable coatings; waterborne coatings;
and incinerators. Generally, adsorption or add-on control devices other than
incinerators are not considered feasible or demonstrated technology.1
High-solids coatings are not practical for current use; however, their use as
fillers and sealers has been demonstrated and may be further developed.
Electron-beam (EB) curing systems may have potential application for some
product lines; however, only one commercial facility in the United States has
installed such a system. '
3.9.3.1 Incineration--
The use of add-on control devices such as direct-flame and catalytic
incinerators (afterburners) is very limited in the flat wood industry. Two
plants, both in southern California, operate afterburners, but one has peti-
tioned to stop operations of the burner because they are using Rule
66-approved solvents. Data are not available on control efficiency or fuel
requirements at that plant.15 The afterburner at the second plant has been
tested several times, but it has not met control efficiency requirements.
No adsorption system is known to be used in the flat wood industry.
Use of multicomponent solvents and the use of different coating formulations
3.9-11
-------
at various steps along the coating line are not conducive to the application of
adsorption techniques for emission control. Specific applications may be
found in redwood surface treatment facilities, where over 90 percent of the
coating is volatile and can be recycled by carbon adsorption.
3.9.3.2 Waterborne Coatings--
The primary emission reduction technique used in the flat wood industry
is conversion from conventional high-solvent coatings to waterborne coatings.
Paint manufacturers have developed and are continuing to develop waterborne
coating formulations to replace conventional coatings for many factory flat
wood applications. The use of applicable waterborne coating in place of a
conventional organic solvent-borne coating can reduce volatile organic emis-
sions by at least 70 percent.17 Table 3.9-4 presents typical values of volatile
organics in conventional and waterborne coatings. Table 3.9-5 presents an
estimate of VOC emissions in weight per area of surface covered.
Major changes are not required for use of waterborne coatings. The
primary use of waterborne coatings is in the filler and base coat applied to
printed interior paneling. Limited use has been made of waterborne materials
for inks, groove coats, and topcoats on printed paneling, and for inks and
groove coats on natural hardwood panels. Waterborne coatings can reduce
fire hazards, fire insurance costs, and air pollution. Problems with water-
borne coatings include possible grain raising, wood swelling, and poor quality
finish.17 A major complaint is that the waterborne coatings available to date
require longer cure times.
19
3.9.3.3 Ultraviolet Curing --
Ultra violet-curable coatings, where applicable, effect almost 100 percent
reduction of VOC emissions. In the flat wood industry, UV coatings have
found use as clear to semitransparent fillers and topcoats for interior printed
paneling and cabinetmaking products.
Ultraviolet-curable coatings are a combination of resin, prepolymers and
monomers, and a photosensitizer (which serves as a catalyst). Polyester,
acrylics, methane, and alkyds are common coating materials. Applied as a
3.9-12
-------
TABLE 3.9-4. VOLATILE ORGANICS IN FLAT WOOD COATINGS
18
Paint
category
Filler
Sealer
Base coat
Grain ink
Topcoat
Paint
typea
C
W
C
W
C
W
C
W
C
W
Density
kg/
liter
1.7
1.7
1.1
1.1
1.4
1.4
1.2
1.3
1.1
1.1
(Ib/gal)
(14.5)
(14.5)
(9)
(9)
(11.5)
(12)
(10)
(10.5)
(8.8)
(9)
Weight
percent
non-
volatile
75
75
60
55
45
55
40
50
40
45
Typical VOC
content
kg/
liter
0.43
0.05
0.43
0.12
0.76
0.08
0.72
0.18
0.64
0.17
(Ib/gal)
(3.6)
(0.4)
(3.6)
(1.0)
(6.3)
(0.7)
(6.0)
(1.5)
(5.3)
(1-4)
VOC content
(less water)
kg/
liter
0.43
0.07
0.43
0.23
0.76
0.19
0.72
0.38
0.64
0.32
( Ib/gal )
(3.6)
(0.60)
(3.2)
(1.9)
(6.3)
(1.6)
(6.0)
(3.2)
(5.3)
(2.7)
VOC reduction
for equivalent
coverage, %
-
90
-
70
-
90
-
80
-
80
I
I—I
CO
C = conventional paint with organic solvent.
W = waterborne, i.e., at least 80 percent of the volatile portion of the coating
is water.
Data received indicate that all companies providing information were able to meet
the VOC content given for waterborne coatings.
-------
-1 p
TABLE 3.9-5. ESTIMATED3 VOC EMISSIONS
Paint
Filler
Sealer
Base coat
Print ink
Topcoat
Total
b
Coverage,
liters/103m2 (gal/1000 ft2)
Waterborne
112 (1.6)
25 (0.35)
46 (0.65)
7 (0.1)
46 (0.65)
236 (3.4)
Conventi onal
119 (1.7)
21 (0.3)
56 (0.8)
7 (0.1)
49 (0.7)
252 (3.6)
Potential VOC emissions,
kg/100 m2 coated (lb/1000 ft2 coated)
Waterborne
0.3 (0.6)
0.2 (0.4)
0.2 (0.5)
0.1 (0.2)
0.4 (0.9)
1.2 (2.6)
Conventional
3.0 (6.1)
0.54 (1.1)
2.4 (5.0)
0.3 (0.6)
1.8 (3.7)
8.0 (16.5)
UV
nil
0
0.24 (0.5)
0.1 (0.2)
nil
0.4 (0.8)
vo
I
a Table 3.20-4 presents typical VOC content.
b Paint coverage based on information from Reference 11. Adjustments made for
waterborne and conventional paints are based on typical nonvolatiles content.
c UV line uses no sealer; uses waterborne base coat and ink. Total is adjusted
to cover potential emissions from the UV coatings.
-------
liquid, the coating is cross-linked and hardened on exposure to UV. The
curing is extremely fast. Although there have been attempts to develop
opaque UV coatings, none is yet available.
The advantages of UV coatings include reduced power requirements,
space savings through reduced storage and oven size, very little emission of
VOC, and the essentially 100 percent usable coating (since all components of
the coating normally react and become part of the coating). Moreover, the
short cure times can be measured in seconds, and a superior product results.
Since little or no curing takes place after the panel leaves the oven, proper
cure times must be carefully established. Safety precautions must be taken
to minimize exposure to UV radiation and to avoid contact with the coating, as
20
some of the raw materials can cause chemical burns.
3.9.3.4 Electron Beam Curing--
One commercial facility in the United States uses an electron beam (EB)
system. Opaque coatings can be cured to a depth of approximately 15 mils.
Three to 5 mils of EB-cured coating produce a smooth, wear-resistant finish
with performance comparable to that of many plastic laminates. ' Although
emissions from the system are still unknown, some airborne acrylics have been
13
reported, and monomers and ozone emissions are possibilities. Over 99
percent control of VOC is expected from EB systems.
3.9.3.5 Summary of Control Measures--
The highest reduction of VOC emissions, about 97 percent, can be
achieved by use of UV-curable coatings. This control measure, however, can
be only applied to certain products and operations. The use of waterborne
coatings can achieve up to 90 percent reduction over conventional coatings,
although use is limited somewhat by the necessity of maintaining acceptable
surface and appearance quality. Incineration of dryer exhaust
3.9-15
-------
gases can reduce overall plant emissions by about 75 percent. At
some installations incineration might also be used to control
coating line emissions and provide an overall reduction of 95
percent or more. Electron beam curing can provide both a 99
percent control of VOC emissions and excellent surface finish
quality. The major deterrent to its use is the highest of both
the EB system and the costing materials.
3.9.4 Emission Limits
Review of State Implementation Plans (SIP) showed no VOC
emission limitations specific to the flat wood industry. Rather,
states have adopted general hydrocarbon emission regulations
patterned after Los Angeles Rule 66. The South Coast Air Quality
Management District Rule 442 (formerly Los Angeles Rule 66)
places limitations on emissions from equipment using organic
solvents or organic materials containing organic solvents. For
organic materials that come into flame contact or are baked,
heat-cured, or heat-polymerized the limitation is 1.4 kg (3.1 Ib)
per hour, not to exceed 6.5 kg (14.3 Ib) per day. For organic
materials emitted from use of photochemically reactive solvents,
the limitation is 3.6 kg (7.9 Ib) per day. For organic materials
emitted from use of photochemically reactive solvents, the limi-
tation is 3.6 kg (7.9 Ib) per hour, not to exceed 18 kg (39.6 Ib)
per day if not in flame contact, baked, heat-cured, or heat-poly-
merized. The above-mass emission rate limitations do not apply
if the emissions are reduced by at least 85 percent.
Recent research has indicated that substituting low-reac-
tivity solvents for high-reactivity solvents may reduce photo-
chemical oxidant levels locally while increasing them in downwind
regions. Accordingly, EPA's current policy on VOC emissions
emphasizes reduction of all hydrocarbons rather than substitution
of exempt for nonexempt solvents.
3.9-16
-------
The EPA has set no NSPS for this source category. It appears LAER
will be determined by estimated reduction levels achieved in practice by use
of waterborne coatings in combination with solvent-borne coatings.
3.9.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing mah
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
A study was made by EPA to determine the lowest emission levels being
21
achieved by manufacturers of flat wood paneling. Since no state regu-
lations are more restrictive, the emission limitations recommended in this
document are considered representative of LAER. Table 3.9-6 presents these
limitations.
The recommended emission limits are stated in terms of kg of VOC per
2 2
100 m of coated surface (Ib per 1000 ft ) to give operators necessary
flexibility in adjusting the VOC content of the various coatings applied to a
given panel. Because practices vary, it would be difficult to set a VOC limit
for each type of coating. By balancing the VOC content and properties of
the various coats, it is possible to achieve acceptable VOC reductions without
sacrificing product quality.
3.9-17
-------
TABLE 3.9-6. RECOMMENDED EMISSION
LIMITATIONS EOR FACTORY-FINISHED PANELING
Product category
Printed interior wall panels
made of hardwood plywood and
thin particleboard
Natural-finish hardwood
plywood panels
Class II-finished hardboard
paneling
Recommended limitation
kg of VOC
per 100 m2 of
coated surface
2.9
5.8
4.8
Ib of VOC
per 1000 ft2 of
coated surface
6.0
12.0
10.0
For printed interior panels, emission limits are based on partial use of
waterborne and solvent-borne coatings. Waterborne coatings that produce
acceptable quality are not available for all coatings, particularly clear topcoats
and printing inks. For natural-finish paneling, the limits are based on use
of solvent-based coatings of lower solvent content than conventional coatings.
The number of coats and coverage of coatings vary, but (for typical usage)
the recommended limitations are equivalent to usage of coatings that have
average VOC contents of 0.20 kg/liter (1.7 Ib/gal) for printed hardwood
paneling, 0.38 kg/liter (3.2 Ib/gal) for natural-finish paneling, and 0.32
kg/liter (2.7 Ib/gal) for Class II-finish hardboard paneling.
3.9-18
-------
REFERENCES
1. Pacific Environmental Services, Inc. Control of Volatile
Organic Emissions from Existing Stationary Sources. Volume
VII Factory Surface Coating of Flat Wood Paneling. EPA
450/2-78-032, U.S. Environmental Protection Agency OAQPS.
Research Triangle Park, North Carolina. June 1978, pp. 1-2,
3.
2. Personal communication between F.T. Fisher, Pacific Finish-
ing Company, Paramount, California, and Pacific Environ-
mental Services, Santa Monica, California.
3. Cohen, R.W. Napko Uses Aqueous Coating Systems for Panel
Refinishing. Plywood and Panel Magazine, June 1977.
4. Pacific Environmental Services, Inc. (1978). p. B-l.
5. Control of Volatile Organic Emissions from Existing Station-
ary Sources-Volume I: Control Methods for Surface Coating
Operations. EPA-450/2-76-028, U.S. Environmental Protection
Agency OAQPS, Research Triangle Park, North Carolina.
November 1976. p. 1.
6. EPA 450/2-78-032, p. 1-15.
7. EPA 450/2-78-032, p. 1-16.
8. Physical Properties of Common Organic Solvents. The Sol-
vents and Chemicals Companies. (Promotional Literature).
1976.
9. EPA 450/2-78-032, p. 2-4.
10. Personal communication with P. Russel, Abitibi Corporation,
Cucamonga, California.
11. EPA 450/2-78-032, p. 2-2.
12. Price, M.B. Reliance Universal, Inc., The Future of High-
Solids Coatings. In: Proceedings of the Fourth Waterborne
and Higher-Solids Coatings Symposium, New Orleans, 1977. p.
155.
3.9-19
-------
13. Personal communications with B. Christopherson, and D.B.
Carnagey, Williamette Corporation, Bend, Oregon.
14. Space-Age Coating of Particleboard Offers Enduring Surface.
Furniture Methods and Materials, May 1977.
15. Personal communication with J. Davis, Masonite Fabrication
Corporation, City of Industry, California.
17. EPA 450/2-78-032, p. 2-3.
18. EPA 450/2-78-032, pp. 2-4,5.
19. EPA 450/2-78-032, p. 2-6.
20. EPA 450/2-78-032, p. 4-2.
21. EPA 450/2-78-032, pp. iv-v.
3.9-20
-------
3 10 MAJOR SOURCE CATEGORY: PETROLEUM LIQUIDS STORAGE-
VOLATILE ORGANIC COMPOUNDS (VOC) EMISSIONS
3.10.1 Process Description
In this report, petroleum liquids are defined as crude oil,
condensate, and any finished or intermediate products manufac-
tured or extracted in a petroleum refinery. These definitions
are intended to apply to tanks with capacities greater than
150,000 liters (40,000 gallons) for the storage of petroleum
liquid with a true vapor pressure greater than 10.5 kPa (1.5
psi).
The three major types of storage tanks for petroleum liquid
are fixed-roof, external (open-top) floating-roof, and internal
floating-roof. Figures 3.10-1, 3.10-2, and 3.10-3 are cross-
sectional drawings of these tanks.
Fixed-roof tanks are generally cylindrical, with a conical
roof permanently attached at the top. These tanks are commonly
equipped with a pressure-vacuum vent that allows them to operate
at a slight internal pressure or vacuum. The pressure-vacuum
valves (vents) prevent release of vapors only during very small
changes in temperature, pressure, or liquid level. These tanks
are generally considered to represent the minimun acceptable
standard for the storage of petroleum liquids.
The external floating-roof tank has a steel cylindrical
shell fitted with a deck or roof that floats on the liquid sur-
face and rises and falls with the liquid level. The liquid
surface is completely covered by the floating roof except in the
small annular space between the roof and the tank shell. A seal
attached to the roof contacts the tank shell and covers the
annular space. The seal slides against the tank shell as the
roof is raised or lowered.
Internal floating-roof tanks are fixed-roof tanks in which
an internal roof or cover floats on the liquid surface. Opera-
tion is analagous to the external floating roof. The two kinds
3.10-1
-------
CONSERVATION
(PRESSURE VACUUM)
VENT
GAUGE
HATCH
. MANHOLE
NOZZLE
MANHOLE
Figure 3.10-1. Fixed-roof (cone-roof) storage tank.
Figure 3.10-2. Single deck, external floating-roof storage
tank.2
FIXED ROOF
I
FIXED-ROOF
SUPPORTS-^
FLOATING ROOF
\ SLEEVE AND
\
MANHOLE
6UIOE AND /
RUCTURAL COLUMNS
MANHOLE
Figure 3.10-3. Covered floating-roof storage tank with
internal floating cover.
3.10-2
-------
of internal covers commonly used are pan-type steel covers (known as
covered floating roofs) and nonferrous (plastic or aluminum) covers (known
as internal floating covers). The fixed roof shields the internal roof from
weather effects and from structural damage or sinking due to accumulated
rain or snow.
3.10.2 Emissions
VOC emissions from fixed-roof storage tanks are classified either as
breathing losses or working losses. These losses occur when the working
limit of the pressure-vacuum vent is exceeded. Breathing losses consist of
vapors expelled from the tank because of the thermal expansion/contraction
caused by diurnal temperature and barometric pressure changes.
Working losses consist of filling and emptying losses. Filling loss results
from vapor displacement by the input of liquid. Emptying loss results from
expulsion of vapor after product withdrawal and is attributable to vapor
growth as the newly inhaled air becomes saturated with VOC.
Factors affecting the emission rate are the true vapor pressure
(volatility) of the product stored, the temperature change (diurnal) in the
tank vapor space, height of vapor space, tank diameter, schedule of emptying
and filling, and mechanical condition of the tank.
Because its design dictates operation over a small pressure-vacuum
range, the fixed-roof tank is subject to appreciable breathing and working
losses. Pressure-vacuum valves restrict vapor release during small temper-
ature-pressure fluctuations, but they allow venting during filling, emptying,
and breathing.
The main source of emissions from external floating-roof tanks is attri-
butable to wind-induced loss by the seal. Wind-induced emissions occur when
the air flow across the tank creates pressure differences around the circum-
ference of the floating roof and causes air to flow by the seal into the
annular vapor space on the leeward side and air plus VOC to flow out on
3.10-3
-------
the windward side. Improper or loose fit of the seal can create gaps or
openings between the seal and tank shell, which can cause increased
wind-induced losses. Other VOC losses are associated with evaporation from
the wetted wall after emptying and leakage of VOC vapor through the fabric
cover that bridges the space between the shoe seal and floating roof.
Internal floating-roof tanks are usually equipped with special air vents
in the fixed roof or at the top of the shell. These provide ventilation to
minimize the possibility of VOC reaching the flammable range in the tank
vapor space. Any VOC that flows by the seal because of wind-induced
pressure differentials or by other seals in the floating cover escapes through
these vents. The fixed roof reduces the wind-induced pressure differential
around the seal, and emissions are lower than from external floating-roof
tanks equipped with single seals.
Reference 3 presents formulas and tables of emission factors for
calculating emissions from fixed-roof tanks, external floating-roof tanks, and
internal floating-roof tanks. Because of the many variables that effect
emissions from these tanks, it is recommended that these formulas be used to
calculate emissions. For external floating-roof tanks with secondary seals and
for all internal floating-roof tanks, standing storage losses are computed by
using Equation (3), Section 4.3.2.2 of Reference 3, and then reducing that
value by 75 percent (i.e. 25% Ls). No additional reduction is recognized at
this time for secondary seals on internal floating roofs. The basic equations
for calculating emissions from floating roof tanks are being revised by the
American Petroleum Institute based on recently completed studies and tests.
Appropriate revisions will be made to Reference 3 when this work is com-
pleted .
3.10.3 Control Measures
Besides improving air quality and eliminating (or at least reducing)
safety (fire) hazards, the control of VOC emissions effects an economic
savings through retention of valuable products. The most feasible and tech-
nically sound methods of control are floating roofs and vapor disposal
systems.
3.10-4
-------
3.10.3.1 External Floating-Roof Tanks--
External floating roofs virtually eliminate the vapor space above the
stored liquid and essentially eliminate the working and breathing losses asso-
ciated with fixed-roof tanks. The critical point is the sliding seal or closure
covering the annular space between the tank wall and the roof. The seal is
basically either a metallic shoe seal or a nonmetallic foam-filled or liquid-filled
seal. Use of a primary (single) seal can be expected to reduce VOC
emissions by more than 90 percent over uncontrolled (fixed-roof) tanks.
The metallic shoe seal is characterized by a 75 to 135 cm (30 to 51 in.)
high long metal sheet held against the tank shell. The shoe is attached to
the roof by braces and held against the wall by springs or weighted levers.
A flexible, impervious fabric (envelope) from the top of the shoe seal to the
roof top closes the annular space between the roof and the seal. The vapor
space is restricted to the small area between the liquid surface and the
envelope. (See Figure 3.10-4a).
Emissions occur from the exposed liquid surface of the gap spaces
between the shoe and tank wall, and through openings in the envelope or
shoe. The envelope and shoe conditions affect emissions since holes, tears,
or other openings provide a direct path between the annular vapor space
(bounded by the shoe liquid surface, envelope, and roof) and the atmo-
sphere.
The nonmetallic seal, usually a flexible tube filled with resilient foam or
liquid, is attached to the outer periphery of the floating roof and covers the
annular space between the roof and shell (Figure 3.10-4, b-d). The
liquid-filled seal is liquid-mounted and the foam-filled seal is either
liquid-mounted or vapor-mounted. When the vapor-mounted seal is suspended
3.10-5
-------
SECONDARY SEAL
(WIPER TYPE)
TANK
WALL
METALLIC WEATHER GUARD
^FLOATING ROOF
SCUFF BAND
LIQUID FILLED
TUBE
-TANK
WALL
METALLIC WEATHER GUARD
=4-
FLOATING ROOF
SEAL FABRIC
RESILIENT FOAM
LOG
VAPOR SPACE
TANK
WALL
METALLIC WEATHER GUARD
Figure 3.10-4. Primary seals.
3.10-6
-------
above the liquid surface, an annular vapor space (bounded by the tank shell,
seal, roof, and liquid surface) exists and any gap between the seal and shell
provides direct access of vapors to the atmosphere. Liquid-mounted seals
rest on the liquid surface in the annular space between the shell and roof.
Thus the annular vapor space is essentially eliminated. The fluid used in
liquid seals should be compatible with the stored products to avoid contami-
nation if the tube ruptured. Because of their flexibility, nonmetallic seals
have some ability to adapt themselves to imperfections in tank walls, thereby
reducing the gap space somewhat.
The use of a secondary seal that is located above and completely covers
the primary seal can effectively control the VOC emissions that escape by the
primary seal or through the shoe seal envelope. Two types of secondary
seals are commonly installed--rim-mounted (Figure 3.10-5) and shoe-mounted
(Figure 3.10-4a). The rim-mounted secondary seal is preferred since the
shoe-mounted secondary seal does not provide protection against VOC leakage
through the primary shoe seal envelope.
Wind-induced air flow around the primary seal system is the main cause
of VOC losses through primary seals. Improper fit and leakage through the
shoe seal envelope and shoe can also contribute to VOC emissions. Reference
4 states that rim-mounted secondary seals are effective in controlling
emissions from liquid and vapor-mounted primary seals. The references cited
as the basis for this statement are various industry sponsored test programs
(Reference listings 5 through 10).
In reference 4 the reductions that would occur from installing secondary
seals over primary seals have been calculated for various primary-secondary
seal type combinations. The calculations indicate that the use of a tight
fitting, rim-mounted secondary seal over primary seals effectively curtails
emissions and that the quantity of emissions curbed increases as the true
vapor pressure of the stored liquid increases.
3.10-7
-------
RIM-MOUNTED
SECONDARY SEAL
TANK
WALL
• TANK
WALL
RIM-MOUNTED
SECONDARY SEAL
^-FLOATING ROOF
SEAL FABRIC
RESILIENT FOAM
LOG
VAPOR SPACE
^-FLOATING ROOF'
SCUFF BAND
LIQUID-FILLED
TUBE
-TANK
RIM-MOUNTED
SECONDARY SEAL
Figure 3.10-5. Rim-mounted secondary seals
3.10-8
-------
3.10.3.2 Internal Floating Roof Tanks--
The internal floating-roof tanks described in 3.10.1 are currently
considered equivalent to external floating-roof tanks equipped with secondary
seals (as discussed in 3.10.3.1).
3.10.3.3 Vapor Recovery/Disposal Systems—
Two general types of these systems are used most frequently to
effectively reduce emissions from fixed-roof storage tanks: systems that
thermally destroy collected vapors (disposal) and systems that recover
collected vapors as useful product (recovery). The thermal oxidizers (e.g.,
afterburners, flares) combust the vapors and result in emissions that are
essentially water and carbon dioxide. The vapor recovery systems can
employ compression, adsorption, refrigeration, and absorption principles to
recover the VOC in the vapor as liquid product. Control efficiencies range
from 85 to 98 percent, depending on the physical properties of the stored
liquids and the design of the equipment.
Systems can be designed to collect, transport, and dispose of both
working and breathing emissions from a series of interconnected tanks. Such
systems should include the ability to isolate each tank and prevent vapor
backflow from the entire system during sampling, gauging, or pressure
change at an individual tank. Vapor recovery/disposal systems are most
often found at gasoline marketing terminals; they have not been used
extensively on large tanks or at tank farms. Figure 3.10-6 is a schematic
layout of a hypothetical system.
3.10.4 Emission Limits
3.10.4.1 New Source Performance Standards--
Present NSPS require that storage vessels with capacities greater than
151,412 liters (40,000 gallons) containing petroleum liquid with a true vapor
pressure greater than 10.5 kPa (1.5 psia) be equipped with an external or
internal floating roof, a vapor recovery system (collection and disposal), or
their equivalents. Tanks in which crude oil and condensate are stored before
3.10-9
-------
VAPOR MANIFOLD HEADER
RECOVERED PRODUCT RETURN
TANK FARM
VENT
STRIPPER
~
PUMP
ADSORBERS I
S^
VAPOR
HOLDER
VAPOR RECOVERY SYSTEM6
Figure 3.10-6. General schematic of vapor recovery system.
The principle, design, mode of operation, and components of
systems vary. Systems principles qenerally include, one.or
more of the following: 'adsorption, absorption, combustion,
and refrigeration.
3.10-10
-------
custody transfer are specifically exempted. A revised NSPS proposed in May
1978 has not yet been promulgated and is therefore not applicable until final
promulgation. Since promulgation of the standard may occur in late 1979, the
main features of the proposed standard are relevant and worthy of mention
here. The proposed standards would require a floating roof; an external
floating roof with double seals that meet specified gap limitations or a vapor
recovery system; or the equivalent of either device. The exemption on crude
oil and condensate tanks was removed. A final review of the comments
received on the proposal and the most recent emission data is being completed.
The promulgation will reflect changes to the proposal as a result of the final
review.
3.10.4.2 State Implementation Plans--
The most stringent SIP requirement discovered was the South Coast
(California) Air Quality Management District Regulation 463 (Storage of
Organic Liquids). This SIP limitation requires floating roofs or vapor
recovery systems (or the equivalent) for liquids of a true vapor pressure
between 78 to 570 mm Hg (1.5 to 11.1 psia), inclusive, stored in tanks with a
capacity greater than 150,000 liters (39,630 gal); double seals on external
floating-roof tanks; specific allowable gaps between seal and tank wall in
terms of width and percent of circumference; and internal floating-roof covers
on fixed-roof tanks or vapor recovery/disposal systems of equal reduction
efficiency.
3.10.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
3.10-11
-------
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
The LAER recommendations below are intended for application to petro-
leum liquid storage tanks greater than 150,000 liters (40,000 gallons) contain-
ing petroleum liquids with a true vapor pressure greater than 10.5 kPa (1.5
psi). The suggested requirements are in the form of devices that contain
and prevent emissions rather than a specified emission limit or rate.
The recommended LAER for petroleum liquids storage in external floating-
roof tanks is the application of double-seal technology as briefly discussed in
Section 3.10.3. (An expanded treatment of double-seal technology can be
found in Reference 4.) Double-seal technology consists of a primary seal
(either a metallic-type shoe seal; a liquid-mounted foam-filled seal; a liquid-
mounted liquid-filled type seal; or another equally effective closure device)
and a continuous secondary seal extending from the floating roof to the tank
wall (a rim-mounted secondary). The seal closure devices should have no
holes, tears, or other visible openings in the seal or seal fabric; should be
intact; and have a uniform, tight fit between the roof and tank wall around
the roof circumference. All openings in the roof, except rim space-vents
should project below the liquid surface. Openings, except for rim space-
vents, automatic bleeder vents, leg sleeves, and emergency drains, should be
equipped with a cover or lid that is closed at all time except when in actual
use.
The importance of minimizing the gap between the rim-mounted secondary
seal and the tank wall in preventing VOC emissions is emphasized. At this
time specific gap requirements have not been promulgated by EPA. It is
suggested that the gap area specified in Reference 4, page 5-2, be used as
an interim guide until more definitive requirements become available.
3.10-12
-------
Reference 4 suggests that the gap area of gaps exceeding 0.32 cm (1/8 inch)
in width between the secondary seal and the tank wall not exceed 6.5 cm per
0.3 M of tank diameter (1.0 square inch per foot of tank diameter).
For fixed roof tanks, the recommended LAER is an internal floating-type
cover with a single continuous closure device between the tank shell and the
floating-cover edge.
Vapor recovery/disposal systems of equivalent VOC control capability can
also be used to meet the LAER requirements, as can other systems that have
satisfactorily demonstrated an equal reduction performance.
The reader is reminded that should the revised NSPS sched-
uled for promulgation in late-1979 contain any provisions more
stringent than this LAER determination, then, under Section
171(3) of the Clean Air Act as Amended August 1977, these pro-
visions of the NSPS would apply.
3.10-13
-------
REFERENCES
1. Control of Volatile Organic Emissions from Storage of Petro-
leum Liquids in Fixed-Roof Tanks. Office of Air Quality
Planning and Standards, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina.
2. Background Information for Proposed New Source Performance
Standards: Asphalt Concrete Plants, Petroleum Refineries,
Storage Vessels, Secondary Lead Smelters and Refineries,
Brass or Bronze Ingot Production Plants, Iron and Steel
Plants, Sewage Treatment Plants, Volume 1. Office of Air
Quality Planning and Standards, U.S. Environmental Protec-
tion Agency, Research Triangle Park, North Carolina. June
1973. Main Text pp. 32-33.
3. Compilation of Air Pollutant Emission Factors. U.S. Envi-
ronmental Protection Agency, Research Triangle Park, North
Carolina. April 1977. Section 4.3.
4. Control of Volatile Organic Emissions from Petroleum Liquid
Storage in External Floating Roof Tanks. EPA-450/2-78-047,
Guideline Series, Office of Air Quality Planning and Stan-
dards, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina. December 1978. p. 3-1.
5. SOHIO/CBI Floating-Roof Emission Program, Interim Report.
October 7, 1976.
6. SOHIO/CBI Floating-Roof Tank Emission Program, Final Report.
November 1976.
7. Chicago Bridge & Iron Company. Western Oil and Gas Associ-
ation, Metallic Sealing Ring Emission Test Program, Interim
Report. January 1977.
8. Chicago Bridge & Iron Company. Western Oil and Gas Associ-
ation, Metallic Sealing Ring Emission Test Program, Final
Report. March 1977.
9. Pittsburgh-Des Moines .Steel Company. Measurement of Emis-
sions from a Tube Sear^ Equipped Floating Roof Tank.
October 9, 1978.
10. Western Oil and Gas Association, Metallic Sealing Ring
Emission Test Program, Supplemental Report. June 1977.
3.10-14
-------
3.11 MAJOR SOURCE CATEGORY: PETROLEUM REFINERIES—WASTEWATER
SEPARATORS, PROCESS UNIT TURNAROUNDS, AND VACUUM PRODUCING
SYSTEMS—VOLATILE ORGANIC COMPOUNDS (VOC).
3.11.1 Process Description
3.11.1.1 Wastewater Separators—
Petroleum refineries operate wastewater treatment facilities
to meet standards for process effluent. The wastewater separator
is the first stage of water treatment. Contaminated wastewater
is collected from process drains, storm sewers, and equipment
cleaning operations. Additionally, water from leaks, spills,
pump and compressor sealing, flushing, and sampling may go into
the wastewater system. Because rains can cause sudden surges in
the volume of water handled, the storm sewer water is usually
segregated and retained in a separate holding pond before treat-
ment in the wastewater separator. The wastewater separator skims
oil from the water and returns it to the process. The wastewater
then undergoes additional treatment to meet effluent standards.
Refinery wastewater drains and treatment facilities can emit
volatile organic compounds (VOC) by evaporation. Volatile or-
ganics may be emitted at any place that wastewater is exposed to
the atmosphere. Sealing sewer openings by the use of liquid
traps or other devices minimizes VOC emissions. Refinery opera-
tors have used such sealing devices for many years because of the
safety hazard associated with hydrocarbon-air mixtures.
Wastewater separators, the most common of which are API
separators, are possibly the largest source of VOC emissions from
wastewater treatment. An API separator is a gravity differential
device consisting of a series of baffles and weirs in a container
operated at atmospheric pressure. Because the input is by grav-
ity flow from an underground sewer, the tank or container is
underground. Although early practice did not include covering of
3.11-1
-------
these tanks, some refiners now cover the forebays of API separa-
tors to control VOC emissions and a few cover the entire separa-
tor area.
3.11.1.2 Process Unit Turnarounds—
Periodic process unit turnarounds are required to ensure
safe and efficient operation of equipment. Insurance require-
ments, safety regulations, and industry standards require peri-
odic inspection and maintenance of all vessels. Thus, process
unit turnarounds are an essential operation in a refinery.
A turnaround entails emptying the equipment for inspection
and maintenance. A typical procedure involves draining the
liquids from the vessel; depressuring the vessel; flushing the
vessel with water, steam, or inert gases to remove all hydrocar-
bons; and then air blowing to provide oxygen for breathing. The
operations provide many opportunities for VOC emissions to the
atmosphere. The vapor content of vessels is usually vented to a
flare system, through a furnace firebox, to a vapor recovery
system, or directly to the atmosphere, depending on operating
practice and refinery configuration.
3.11.1.3 Vacuum-Producing Systems—
Use of vacuum-producing systems is principally at vacuum
towers for distillation of the very high-boiling components of
crude oil from residuum fractions. Other uses include evacuation
of processing equipment for maintenance and for removing noncon-
densables from condensers that process steam from turbines.
This separation of high-boiling fractions (340° to 566°C or
650° to 1050°F gas oils) from residuum is required because it
renders the gas oils more valuable for subsequent processing.
Separation is accomplished by distillation under vacuum because
the oil will crack at temperatures required to distill it under
atmospheric pressure. Distillation under vacuum greatly in-
creases the overall yield of gas oil fractions of the crude oil.
3.11-2
-------
Distillation involves heating the so-called reduced crude
oil to about 400°C (750°F) and sending it to a tower operated
under vacuum. The flash zone at which the vapors and residuum
are separated typically operates above 370°C (700°F) and at
absolute pressures of 1.3 to 16 kPa (10 to 120 mm Hg). Instru-
ments on the vacuum-producing system control the flash zone
pressure and, indirectly, the pressure at the top of the tower.
Effective pressure in the flash zone may be further reduced by
introduction of steam with the feed or at the bottom of the
tower, the latter providing a stripping action on the residuum
product before it leaves the bottom of the tower.
The vapor portion of the feed flows upward through an en-
trainment removal section and then through distillation trays,
which intimately mix the vapors with cooled heavy-vacuum gas oil
pumped back into the tower at a higher level as reflux and as
cooling fluid. The remaining vapors then proceed through a simi-
lar section with light-vacuum gas oil as reflux and coolant. The
vapors that leave the top of the tower are exhausted by the
vacuum-producing system.
The basic types of vacuum-producing systems are ejectors and
mechanical pumps (compressors). An ejector system is a gas com-
pressor that uses the high-pressure energy of one fluid to com-
press another. The high-pressure fluid is almost always steam,
which is "jetted" from a nozzle through a vacuum chamber at high
velocity, entraining the vapors from the tower. The steam from
the ejector is then condensed by contact with water (either
directly or through tubes of a water cooler) or by an air cooler.
The noncondensables are vented to the atmosphere, to another
stage of jet ejection, or to a blower. The vacuum towers in oil
refineries usually require three ejectors in series.
For the large ejector systems required on large vacuum
units, the steam is condensed and the gas is cooled. The re-
sultant mixture of water, hydrocarbons, and dissolved gases is
sent to a ground-level accumulator called a "hotwell." Water
3.11-3
-------
from the hotwell requires treatment to remove oil, and vapors from the hotwell
may require containment and disposal. Use of a surface condenser, either
water- or air-cooled, greatly decreases the volume of water that must be
treated, because the cooling water is not contaminated with hydrocarbons.
Although refineries use steam ejectors almost exclusively because of their
initial low cost, lack of moving parts, operating simplicity, and reliability,
vacuum pumps also can produce the necessary vacuum. Such pumps are
being considered more and more because of increasing concern with water
pollution and because of rising energy costs, which favor pumps over the
very thermally inefficient steam ejectors. No refinery is known to have
installed vacuum pumps. They are particularly expensive for use at very low
vacuums below 50 mm Hg absolute pressure. Although the fuel savings
offered by vacuum pumps is substantial, the pumps are much less reliable
than steam injectors and cost much more to install and maintain. It is
anticipated that serious consideration will be given to vacuum pumps for
application to new vacuum towers on the basis of energy cost savings.
3.11.2 Emissions
3.11.2.1 Wastewater Separators--
Because the VOC at wastewater separators come from many refinery
sources served by the collection system, volatility of the compounds emitted
ranges widely. Typically, the compounds include Cj to Cg paraffins, olefins
and aromatics, hydrogen, hydrogen sulfide, and ammonia. None of the data
adequately quantified emissions from wastewater separators, although it is
estimated that the emissions from uncovered wastewater separators can be
large.
3.11.2.2 Process Unit Turnarounds—
Potential emissions from turnarounds include the full range of hydro-
carbons in a refinery. Emissions also may include hydrogen, ammonia, carbon
monoxide, hydrogen sulfide, sulfur oxides, and particulates.
3.11-4
-------
3.11.2.3 Vacuum-Producing Systems—
The barometric condenser hotwell accumulators and the last
stage of the steam ejector system emit light, noncondensed hydro-
carbon compounds (VOC), which would generally include hydrogen,
methane, ethane, propane, butanes, pentanes, and hydrogen sul-
fide, together with low concentrations of olefins and uncondensed
gases (nitrogen, oxygen, and CO-).
3.11.3 Control Measures
3.11.3.1 Wastewater Separators—
Volatile organic emissions from wastewater separators can be
reduced and well controlled by covering the separators and all
openings to enclose completely the liquid contents. A floating
cover equipped with closure seals between the edges of the cover
and the separator can minimize VOC emissions. Use of separator
covers and liquid trap seals for sewer drains should minimize VOC
emissions from wastewater systems.
3.11.3.2 Process Unit Turnarounds—
Control of VOC emissions during process unit turnarounds
starts with the pumping of liquid contents from the process unit
to storage. This operation now involves enough economic incen-
tive for complete compliance to be anticipated. Collecting the
vapors from the depressuring of vessels is the next most effec-
tive step. The purged vapors along with vapors forced from the
system by flushing of the process unit with water, steam, or
inert gas can be directed to a vapor control system, to a flare
header system, or to a firebox for incineration.
3.11.3.3 Vacuum-Producing Systems—
Vapors from the last stage of a vacuum-producing system and
from the hotwell can be collected and sent to a furnace firebox
or to a vapor recovery unit with the assistance of a mechanical
3.11-5
-------
blower (compressor). Both recovery and use-as-fuel systems pro-
vide incentives related to the concern with air quality and
energy costs and the trend to larger vacuum units in refineries.
3.11.4 Emission Limits
No New Source Performance Standards (NSPS) have been promul-
gated for wastewater separators, process turnarounds, or vacuum-
producing systems at refineries, nor is information available
upon which to base an achieved-in-practice emission limit.
3.11.4.1 State Implementation Plan (SIP) Limits—
Specific regulations applicable to vacuum-producing systems
and wastewater separators are embodied in California's South
Coast Basin rules; these are the most restrictive found in any
SIP. No regulation specific to process unit turnarounds was
found.
Under Rule 465 of the California South Coast Air Quality
Management District (SCAQMD), the discharge from vacuum-producing
devices is limited to no more than 1.36 kg (3.0 Ib) of organic
materials in any 1 hour from any vacuum-producing devices or
systems, including hotwells and accumulators, unless such dis-
charge has been reduced by at least 90 percent. In other areas
of the country VOC emissions are limited under a general rather
than a source-specific regulation. For example, the Bay Area Air
Pollution Control District, San Francisco, California, (Regula-
tion 3101) states "....a person shall not discharge into the
atmosphere an effluent containing a concentration of more than 50
ppm or organic compounds calculated as hexane (or 300 ppm total
carbon)."
Wastewater separators are addressed specifically in SCAQMD
Rule 464 of the California South Coast Basin, which states that a
person shall not use any compartment of any vessel or device
operated for the recovery of oil from effluent water, unless such
3.11-6
-------
compartment is equipped with one of the following vapor-loss control devices:
a. A solid cover on which all openings are sealed, thereby
totally enclosing the liquid contents of the compart-
ment.
b. A floating pontoon or double-deck type cover equipped
with closure seals between the cover's edge and the
compartment wall. [Gaps between the compartment wall
and seal are limited to 0.32 cm (1/8 in.) for an accum-
ulative length of 97 percent of tank perimeter, and are
not to exceed 1.3 cm (1/2 in.) for an accumulative
length of the remaining 3 percent of tank perimeter.
No gap is to exceed 1.3 cm (1/2 in.) in width.]
c. A vapor recovery system that reduces the emission of
all hydrocarbon vapors and gases into the atmosphere by
at least 90 percent by weight.
d. Other equipment having an efficiency equal to or
greater than a, b, or c (listed above) and approved by
the Air Pollution Control Officer.
3.11.5 Determination of LAER; Controls to Achieve LAER
3.11.5.1 Wastewater Separators—
In the absence of achieved-in-practice data and NSPS, the lowest
achievable emission rate is determined to be that degree of VOC emission
reduction required by the South Coast Air Quality Management District Rule
464 (see Section 3.11.4.1). The LAER is therefore a vapor-recovery system
that reduces all VOC by at least 90 percent by weight, or certain specified
equipment, or other equipment of equal or greater control efficiency. Control
equipment includes the covering of separators, forebays, and other openings
with seal-equipped floating roofs; use of liquid trap seals for sewer drains;
and a monitoring and inspection program to detect any excessive VOC releases
to the drainage system.
3.11.5.2 Process Unit Turnarounds--
LAER for process unit turnarounds is that emission rate resulting from
collecting and subsequently either incinerating or recovering the vapors
3.11-7
-------
released during the depressuring and purging of process units. It is
estimated that LAER is an overall reduction of 90 percent by weight, or
greater in potential emissions from the turnaround process. A piping system
would be required to convey the VOC emissions to the control device.
3.11.5.3 Vacuum-Producing Systems--
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
shew that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
LAER for vacuum-producing systems is a 90 percent by weight reduction
of the VOC emissions from the last stage of the system and the associated
hotwell. This reduction anticipates effective capture, collection, and trans-
port of VOC to the control unit by the collection system. Available controls
to achieve LAER include an effective collection system and vapor disposal by
either incineration (e.g., a furnace firebox) or vapor recovery.
3.11-8
-------
REFERENCES
1. Monroe, E.S. Energy Conservation and Vacuum Pumps. Chem-
ical Engineering Progress, Vol. 71, No. 10. October 1975.
pp. 69-73.
3.11-9
-------
-------
3.12 MAJOR SOURCE CATEGORY: PETROLEUM REFINERIES—FUGITIVE
EMISSIONS—VOLATILE ORGANIC COMPOUNDS (VOC)
3.12.1 Process Description
Equipment leaks provide numerous sources of fugitive vola-
tile organic compound (VOC) emissions in petroleum refineries.
Among the equipment items that are subject to leaks are pump and
compressor seals, valve stems and bonnets, flanges, pressure-
relief devices, process drains, sample valves, and other open-end
valves.
The proper mating of two sealing surfaces is essential if
pump seals, compressor seals, valve stem seals, valve seats,
bonnets, flanges, and other connections are to maintain their
sealing ability. These sealing surfaces are sometimes finely
machined surfaces and sometimes compressed packing (gaskets).
Proper design and maintenance are required to minimize leakage.
Properly seated pressure relief devices will provide a good
seal until they have been opened and closed several times and
foreign matter (such as corrosion products, carbon particles, and
gum) collects on the seats, after which the seal may no longer be
free of leaks.
The open-end valves used for sampling and bleeding lines
become a source of fugitive emissions if they are not completely
closed or are not seating properly.
3.12.2 Emissions
Although a wide range of volatile organic compounds is
emitted as a result of equipment leaks, most are hydrocarbons
with one to six carbon atoms, such as olefins, paraffins, and
aromatics. Their composition depends on the kinds of crude oil
processed in the refinery, the complexity of the refining proc-
ess, and the specific processing units involved. The volume of
pollutants emitted depends on these same items in addition to
maintenance practices and refinery age.
3.12-1
-------
Available data regarding emissions from fugitive sources are
limited, and EPA is currently conducting studies to quantify
these emissions. Data regarding leak rates and VOC emissions for
fugitive refinery sources recently became available as a result
of one such study.1 These are presented in Table 3.12-1, which
indicates the percentage of all sources of a given type that
exhibited leaks (estimated percent leaking) and the average VOC
emissions from those that were leaking (emission factor esti^
mate). The data were derived from studies at nine refineries
(large and small, new and old) and from an examination of 500 to
600 sources at each of the refineries studied.
3.12.3 Control Measures
Many design and operational measures are available for
reduction of emissions at petroleum refineries. A well planned
and executed monitoring and maintenance program is one of the
most effective methods. For many years refineries have used such
programs to prevent the formation of vapor clouds and to elimi-
nate the possibility of explosion; however, only recently have
refiners used portable flame ionization detectors and other
analytical instruments to determine total hydrocarbon levels near
major process equipment. Analytical instruments capable of
measuring hydrocarbon concentrations in a range from 1 or 2 to
several thousand parts per million are necessary for this type
monitoring.
Because fugitive emissions at pump seals, compressor seals,
and valve stems occur at random and cannot be predicted, a peri-
odic walk-through inspection and monitoring program are required
to detect leaks if emissions are to be reduced significantly.
Although initially expensive, a properly designed and permanent
monitoring system would serve to discover, relay to, and alert
refinery personnel to the presence of VOC and the need for cor-
rective action.
3.12-2
-------
TABLE 3.12-1. ESTIMATED EMISSION FACTORS.
FOR SELECTED PETROLEUM REFINERY VOC SOURCES
Source type
Estimated
percent,
leaking
Emission factor estimate
g/h per source (Ib/h per source)
U)
NJ
I
U)
Valves j
Gas/vapor service
Light liquid/two-phase service
Heavy liquid service
Pump seals
Light liquid service
Heavy liquid service
Compressor seals
Hydrocarbon service
Flanges
Drains
Relief valves
29.3
36.5
6.7
63.8
22.6
70.3
3.1
19.2
39.2
21.0 (0.047)
10.0 (0.023)
0.3 (0.0007)
118.0 (0.26)
20.0 (0.045)
440.0 (0.98)
0.26 (0.00058)
32.0 (0.07)
86.0 (0.19)
Adapted from Table 1-1, p. 2, Reference 1.
Estimate of percent of total sources found to be leaking. A leaking source is
defined as a source with measured leakage values equal to or greater than 200 ppmv
or sources with measured leak rates greater than 0.00454 g/h (0.00001 Ib/h).
Emission factor estimate for leaking sources only, i.e., those found to leak as
defined in "a" above.
Gas/vapor service means the hydrocarbon stream was a vapor at process conditions;
light liquid means a liquid lighter than kerosene; liquid means a liquid equal to
or heavier than kerosene.
-------
Design changes that can reduce fugitive emissions at new
facilities include pumps and compressors equipped with fluid-
flushed, double mechanical seals and a vapor collection and
recovery system. (Pumps with double seals and various kinds of
flushing fluids are currently used by refineries when handling
toxic fluids.) Other design changes include enclosures around
flanges and the use of double pipes; however, the high initial
cost and even higher maintenance costs render both impractical.
3.12.4 Emission Limits
No New Source Performance Standards (NSPS) limits apply to
fugitive emissions from refineries, and Achieved in Practice
(AIP) limits have not been adequately quantified.
3.12.2.1 State Implementation Plan (SIP) Limits—
In many states VOC emission regulations require that all
persons use reasonable care to avoid discharge, leaking, spil-
ling, seeping, pouring, or dumping of compounds, or that they use
known and existing vapor control emission devices or systems.
California's South Coast Air Quality Management District
(SCAQMD) Rule No. 466 (adopted May 7, 1976, and amended September
2, 1977) prohibits the use of any pump or compressor to handle
organic materials with a Reid vapor pressure of 80 mm mercury
(1.55 lb/in.2) or greater unless such pump or compressor is
equipped with a mechanical seal in good working order or some
other device of equal or greater efficiency and approved by the
Executive Officer. The rule specified that mechanical seals be
maintained so that there is (1) no leakage greater than three
drops per minute, (2) no visible mist from liquid being pumped
where such liquids do not condense at ambient conditions, and (3)
no visible indication of leakage evident at or near the seal/
shaft interface of gas compressors. An inspection for visible
leaks at pumps and compressors is required once every 8-hour
period unless the refinery is located more than 3 miles
3.12-4
-------
from a continuously manned control center. In this case an inspection is
required once every 24 hours.
SCAQMD Rule No. 467 (adopted May 7, 1976) prohibits the use of any
safety pressure relief valve on any equipment that handles organic materials
o
with an absolute pressure of more than 776 mm mercury (15 Ib/in. ) unless
the relief valve is vented to a vapor recovery or disposal system, is protected
by a rupture disc, or is maintained by an inspection system approved by the
Air Pollution Control Officer. SCAQMD Rule No. 466.1 (adopted November 3,
1978) pertains to valves and flanges. The general requirements are record
keeping, periodic leak inspection, leak repair within 2 days (some exceptions
allow a greater repair time), and the use of a seal (cap, plug, or flange) on
each valve at the end of a pipe or line containing VOC when the line is not
in use (certain valves exempted).
3.12.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
3.12-5
-------
The complexity of processing units used in refineries varies, depending
on the different crude oils processed and products produced. These differ-
ences among refineries and refinery operations and the fact that fugitive
emissions occur randomly, originate from numerous sources, and are not
precisely quantified, make it difficult to establish an acceptable national
standard for limiting mass emissions.
The lowest achievable emission rate (LAER) for fugitive VOC emissions at
petroleum refineries is therefore determined to be the emission rate that
occurs after equipment designed to minimize emissions has been properly
installed and a program of practical housekeeping, monitoring, routine inspec-
tion, preventive maintenance, and equipment repair/replacement has been
established. Where technically feasible, pumps and compressors should have
double mechanical seals that are fluid-flushed, and the flushing fluid facilities
should be equipped with a vapor collection/recovery system. Certain types of
compressors can be equipped with appropriate purge systems. The provisions
of California's SCAQDM Rule 466 (see 3.14.4) in regard to inspection
schedule, leakage rate, and visible emissions are considered applicable as
LAER guidelines for pumps and compressors. The inspection-maintenance
program should include a periodic walk-through inspection using visual tech-
niques and, where appropriate, be supplemented by hydrocarbon detection
equipment to provide early detection of existing or developing leaks.
Particular attention should be directed to pipeline valves, sampling equipment,
and pressure relief valves. All leaking or defective components should
command early attention and be isolated and repaired or replaced to protect
air quality and safety.
3.12-6
-------
REFERENCES
Emission Factors and Frequency of Leak Occurrence for Fit-
tings in Refinery Process Units. EPA-600/2-79-044, U.S.
Environmental Protection Agency, Industrial Environmental
Research Laboratory, Research Triangle Park, North Carolina
February 1979.
3.12-7
-------
3.13 MAJOR SOURCE CATEGORY: GRAPHIC ARTS PRINTING--VOC
EMISSIONS
In 1970 there were more than 40,000 printing and publishing
establishments in the United States. Total solvent usage in
2
this industry in 1976 was estimated at 340 Gg (380,000 tons).
With an overall degree of emission control estimated at 30 per-
cent, the total of national organic compound emissions was esti-
mated at 240 Gg (270,000 tons). The approximate contributions of
each major graphic arts process are gravure, 41 percent; lithog-
raphy, 28 percent; letterpress, 18 percent; and flexography, 13
2
percent.
3.13.1 Process Descriptions
High-volume printing operations utilize rotary presses in
which the image carrier is curved and mounted on a rotating
cylinder. In gravure, the image cylinder rotates in the ink
trough (ink fountain). In other processes a second cylinder
rotates in an ink trough and delivers ink to the plate cylinder
(image), usually through a series of distribution rollers. In
direct printing operations, the image carrier transfers the image
directly to the print surface. In offset printing operations, an
intermediate surface transfers the image to the print surface.
Printing methods are classified by the principles upon which
the printing image carriers are based. Two types are discussed
herein: rotogravure and flexography.
Printing presses are fed by sheet or roll paper. Roll-fed
operations require dryers to evaporate the solvent from the ink.
Dryers are high-velocity hot-air dryers, direct-flame dryers, or
indirect steam-heated dryers.
3.13.1.1 Rotogravure—
In gravure printing, the image areas are recessed relative
to the nonimage areas. The gravure cylinder rotates in an ink
3.13-1
-------
trough or fountain. Excess ink is removed by a steel doctor
blade. The paper is pressed against the cylinder as it turns, by
use of a rubber-covered impression roll. When the process is
roll-fed it is known as rotogravure. Sheet-fed gravure is not
widely used.
Rotogravure requires very fluid inks, with solvent contents
ranging from 55 to 75 percent and higher. Typical solvents
include alcohols, aliphatic naphthas, aromatic hydrocarbons,
esters, glycol ethers, ketones, nitroparaffins, and water.
Solvent is evaporated in low-temperature dryers [(23° to 120°C),
(70° to 250°F)], usually indirectly heated by steam or hot air.
Steam drum dryers can be used.
3.13.1.2 Flexography—
In flexographic printing, as in letterpress, the image areas
are raised above the nonimage surface. The distinguishing fea-
ture is that the image carrier is made of rubber and other elas-
tomeric materials. Flexographic presses are usually rotary web
presses, i.e., roll-fed. The flexographic printing market in-
cludes flexible packaging and laminates, multiwall bags, milk
cartons, folding cartons, corrugated paper, paper cups and
plates, labels, tags, tapes, envelopes, and gift wrap.
Flexography uses very fluid inks with organic solvent con-
tent ranging from 50 to 85 percent. The inks dry by solvent
evaporation, usually in high-velocity air dryers at air temper-
atures below 120°C (250°F). Solvents that do not damage rubber
must be used. Typical solvents are alcohols, aliphatic hydro-
carbons, glycols, esters, glycol ethers, glycol ether esters, and
water.
3.13.2 Emissions
The major air pollutants from printing operations are those
from evaporation of organic solvents used in ink dilution and
3.13-2
-------
cleanup. Minor quantities of dust (from workroom activity) and
diffuse fumes (from dryers) may be also vented to the atmosphere.
The primary sources of organic emissions are from the drying
of inks. Types and quantities of emissions depend mainly on the
inks and solvents used, the type and size of printing process,
the requirements of the job being printed (ink consumption), and
the degree of emission reduction achieved by control devices.
Printing inks are composed of materials similar to those
used in surface coatings: pigments, vehicles, and solvents. The
specifications for an ink vary widely according to the applica-
2
tion and influence the quantity and composition of the VOC
emissions.
3
The following materials used as solvents in printing inks,
usually in combinations, determine the composition of the VOC
emissions:
toluene methanol
xylene ethanol
heptane propanol
hexane isopropanol
isooctane butanol
mineral spirits ethylene glycol
Stoddard solvent glycol ether esters
naphthas glycol esters
heavy naphthas acetone
methyl ethyl ketone ethyl acetate
methyl isobutyl ketone isopropyl acetate
ethyl acetate normal propyl acetate
Inks incorporating these solvents are considered conven-
tional inks. Ultraviolet and electron-beam-curable inks, water-
borne inks, and heat-reactive inks are discussed under control
measures. In gravure and flexography more solvent is added
directly to the ink troughs, and emissions are not directly re-
lated to the ink composition.
3.13.3 Control Measures
Emissions can be reduced by add-on control devices and by
the use of low-solvent inks as summarized in Table 3.13-2. The
3.13-3
-------
applicability of each control method to each printing technique
is discussed below.
3.13.3.1 Add-On Control Equipment—
Fume incinerators (direct flame and catalytic) and carbon
adsorbers are the only devices with proven high efficiency in
controlling hydrocarbon vapors from rotogravure and flexographic
printing operations.
Incineration--Incineration is a technically feasible method
of controlling emissions from all printing operations. Both
direct-flame and catalytic incinerators are potential methods of
controlling emissions from flexography and package gravure print-
ing. In a direct-flame incinerator a temperature of 600° to
680°C (1100° to 1250°F) and a residence time of 0.3 to 0.5 second
are generally sufficient to achieve 90 percent oxidation of most
organic vapors passing through the device. Temperatures of 760°
to 820°C (1400° to 1500°F) may be necessary to oxidize aromatics
such as toluene and xylene.
Heat recovery can substantially reduce the cost of incin-
eration. Heat recovery equipment that uses the hot incinerator
gases to preheat dryer exhaust gases prior to incineration re-
duces incinerator fuel requirements. In some cases heat equip-
4
ment can be used to supply the heated air required at the dryer.
A third type of incinerator, the pebble-bed, has been sug-
gested as an applicable control for graphic arts processes.
Pebble-bed incinerators combine the functions of a heat exchanger
and a combustion device, as shown in Figure 3.13-1. The solvent-
laden exhaust from the dryers and floor sweeps enters one of the
pebble beds, which has been heated by combustion chamber exhaust.
Oxidation of the vapors starts in the preheated bed and is com-
pleted in the combustion chamber. The exhaust gases exit through
a second pebble bed, transferring heat to the pebbles. Pebble-
bed systems are designed to achieve a heat recovery efficiency
3.13-4
-------
TO ATMOSPHERE
I
en
AND
DAMPE
DAMPER ':
rfH?
DRYERS
npsuFTPs
ft,
.K _^^_
v:W
•M^H
CERAMIC
.'•; BED VI
\ "••';.••
•/•. • •
•
X^~^
1,400°F
ct,
~-
GAS OR OIL
(\MPER
> t
*
; DAMPER
1 A A
T W
TO D
200-
[
RYERS
600° F
Figure 3.13-1. Ceramic-bed regenerative-type incineration and heat recovery system,
-------
of 85 percent. Use of pebble-bed incinerators appears to be best
suited to continuous printing operations having rich VOC exhaust
streams.
Carbon adsorption--Recovery of solvents by use of carbon
adsorption systems has been successful at several large roto-
gravure plants. Rotogravure presses used a single, water-immis-
cible solvent (toluene) or else a mixture which is recovered in
approximately the proportions used in the ink. Three such sys-
tems are reported to recover 23 to 26 kl per day (6000 to 7000
gal/day) of solvent at an average efficiency of 90 percent or
c a *"7
greater. These recovery systems were installed for regula-
tory and economic reasons. Solvent is evaporated from the web in
indirect steam-heated ovens, which preclude any solvent decompo-
sition. Regeneration of the carbon is accomplished by use of
steam, followed by condensation and decantation.
Some rotogravure operations, such as printing and coating of
packaging materials, use inks and coatings containing complex
solvent mixtures. Many of the solvents are water-soluble. A
folding carton operation for example, requires at least five
solvents, some of which are soluble in water. Also, when fre-
quent product changes call for different solvent combinations,
solvent recovery is virtually impossible. Reformulation of inks
may offer a possible method of avoiding these difficulties.
A new type of carbon adsorption system, a fluidized bed
system developed in Japan, reportedly offers a method of avoiding
the problems associated with the use of water-soluble solvents in
conventional fixed-bed systems. This new system utilizes nitro-
gen gas as the desorbent. Because the solvent is condensed in
indirect heat exchangers and the nitrogen is recycled, there is
no mixing with water at desorption. The advantages claimed
include better thermal efficiency, lower power consumption, and
regeneration at higher temperatures to remove high boiling mate-
rials. The disadvantages include possible higher capital cost
and a requirement that relatively constant air volume be main-
tained.
3.13-6
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Where add-on devices are used, the overall VOC reduction
(control) efficiency is dependent upon the extent to which the
capture system collects, contains, and delivers the VOC vapors to
the control device inlet. Capture system efficiencies vary with
the complexity and configuration of the printing operation and
with the difficulty encountered in accessing emission points.
The efficiency of capture systems at existing plants are reported
to be 75 to 85 percent for publication rotogravure, 75 percent
for packaging rotogravure, and 70 percent for flexography. Such
capture systems, coupled with the 90 percent or greater VOC
reduction achievable with incineration or carbon adsorption
systems, provide an overall VOC reduction of 75 percent for
publication rotogravure, 65 percent for packaging rotogravure,
and 60 percent for flexography.
3.13.3.2 Use of Low-Solvent Inks—
Low-solvent inks are of three types: waterborne, high-
solids, and radiation curable. Only waterborne inks are now
widely used for packaging gravure and flexographic printing.
Waterborne inks are not completely solvent-free because the
volatile portion contains up to 35 percent water-soluble organic
compounds. Although waterborne inks are used extensively in
printing corrugated paperboard for containers, multiwall bags,
and other packaging materials made of paper and paper products,
their use is somewhat limited because they absorb into thin paper
stocks and seriously weaken the paper.
Flexographic and rotogravure packaging printing operations
with less demanding quality requirements can use waterborne inks
to achieve emission levels comparable to those attained by the
application of add-on control devices. A waterborne ink consist-
ing of 75 volume percent water and 25 volume percent organic
solvent in the solvent portion of the ink is considered to be
equivalent in control effectiveness to either carbon adsorption
9
or incineration.
3.13-7
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3.13.4 Emission Limits
Review of existing State Implementation Plans (SIP) showed no VOC
emission limitations specific to the graphic arts industry. Rather, states have
adopted general hydrocarbon emission regulations patterned after the Los
Angeles Rule 66,10 which has been modified pursuant to an EPA ruling that
regards all hydrocarbons as photochemically reactive.
The South Coast Air Quality Management District Rule 442 (formerly Los
Angeles Rule 66) places limitations on emissions from equipment using organic
solvents or organic materials containing organic solvents. For organic
materials that come into flame contact or are baked, heat-cured, or heat-
polymerized, the limitation is 1.4 kg (3.1 Ib) per hour, not to exceed 6.5 kg
(14.3 Ib) per day. For organic materials emitted from the use of photo-
chemically reactive solvents, the limitation is 3.6 kg (7.9 Ib) per hour, not to
exceed 18 kg (39.6 Ib) per day if not in flame contact, baked, heat-cured, or
heat-polymerized. The above mass emission rate limitations do not apply if
the emissions are reduced by at least 85 percent.
At this time no NSPS have been promulgated for the graphic arts
industry. It is anticipated that such standards will be proposed for
publication rotogravure in late 1979, after the completion of emission surveys
and control technology studies.
3.13.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
3.13-8
-------
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
The most stringent regulations in State Implementation Plans are
patterned after Los Angeles Rule 66. Emission reductions achieved in
practice exceed those required by the most stringent SIP regulations.
Incineration, carbon adsorption, and the use of low-solvent-content inks are
proven techniques for reducing VOC emissions from rotogravure and flexo-
graphic printing.
The use of incineration may be constrained where natural gas is in short
supply. Incorporating heat recovery to the extent possible will reduce the
total fuel requirements. Generally, incineration is technically feasible when
carbon adsorption with solvent recovery is not possible. The use of carbon
adsorption may increase energy requirements, but it also may enable recycling
of solvents. Waterborne ink can generally be used for packaging and
specialty rorogravure and flexographic printing operations with relatively
sturdy substrate. The feasibility of ink substitution must be determined on a
case-by-case basis, depending on product specifications and the type of
process used. Low-solvent inks may be developed and used to yield
reductions equal or close to those achieved with control system hardware.
In actual operation, direct-flame and catalytic incinerators have demon-
strated emission reductions of 90 to 95+ percent on certain types of printing
operations. Carbon adsorption units can reduce emissions by 90 percent or
more on rotogravure processes using solvents that are insoluble in water.
These values pertain to the efficiency of the device only.
This guideline relies substantially on information provided in the EPA
Control Techniques Guideline (CTG), Volume VIII: Graphic Arts--
Rotogravure and Flexography (Reference 2). The overall emission reductions
reported as achievable in the CTG pertain to retrofit application of control
strategies. Since LAER applies only to new (modified) facilities, greater
3.13-9
-------
emission reduction can be expected. Unlike retrofit systems, new installations
offer an opportunity to maximize plant layout, process methods, and capture-
control system designs to obtain the most effective VOC control. Considering
these factors, it appears the following overall reductions of VOC emissions
from solvent-borne inks are attainable with effective capture-control systems
and are presented as suggested LAER values: publication rotogravure, 80
percent; packaging rotogravure, 70 percent; and flexography, 65 percent.
Comparable emission reductions achieved by use of water-borne and/or
low-solvent (high-solids) inks rather than solvent-borne inks are considered
as meeting the LAER values.
3.13-10
-------
REFERENCES
1. Gadomski, R.R., et al. Evaluations of Emissions and Control
Technologies in the Graphic Arts Industries, Phase I.
Graphic Arts Technical Institute. August 1970.
2. Control of Volatile Organic Emissions from Existing Sta-
tionary Sources, Volume VIII: Graphic Arts-Rotogravure and
Flexography, Guideline Series. EPA 450/2-78-033, U.S.
Environmental Protection Agency, Office of Air Quality
Planning and Standards. December 1978. pp. 2-7, 2-8.
3. EPA 450/2-78-033. p. 2-6.
4. EPA 450/2-78-033. p. 3-4.
5. George, H.F. Gravure Industry's Environmental Program.
EPA-5601/1-75-005. In: Proceedings of Conference on Envi-
ronmental Aspects of Chemical Use in Printing Operations,
Office of Toxic Substances, Environmental Protection Agency.
January 1976. pp. 204-216.
6. Watkins, E.G., and P. Marnell. Solvent Recovery in a Modern
Rotogravure Printing Plant. EPA-5601/1-75-005. In: Con-
ference on Environmental Aspects of Chemical Use in Printing
Operations, Office of Toxic Substances, Environmental Pro-
tection Agency. January 1976. pp. 344-355.
7. Harvin, R.L. Recovery and Reuse of Organic Ink Solvents.
EPA-5601/1-75-005, In: Proceedings of Conference on Envi-
ronmental Aspects of Chemical Use in Printing Operations,
Office of Toxic Substances, Environmental Protection Agency.
January 1976.
8. EPA 450/2-78-033. p. 3-5.
9. EPA 450/2-78-033. pp. 3-9, 3-10.
10. Rule 66 of the Rules and Regulations of the County of Los
Angeles Air Pollution Control District. Los Angeles,
California. January 1973.
11. Personal communication with E. Vincent, Industrial Studies
Branch, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina. March 12, 1978.
3.13-11
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3.14 MAJOR SOURCE CATEGORY: AUTOMOBILE AND LIGHT TRUCK COATING--
VOLATILE ORGANIC COMPOUND (VOC) EMISSIONS
3.14.1 Process Description
Automobile and light truck coating is a multistep operation
carried out on a conveyor system where each vehicle body receives
several coats of paint to enhance appearance and protect against
adverse weathering. In some coating operations, hoods and
fenders are coated separately from the main body line and joined
to the body after coating.
Although no automobile or light truck assembly line is
"typical," features common to all are shown in Figure 3.14-1. As
the process begins, an automobile body emerges from the body shop
and undergoes a solvent wipe and metal treatment step (usually a
phosphate wash cycle) to improve paint adhesion and corrosion
resistance. The first coat, a primer, is applied by dip or spray
methods; then the unit is baked. A second prime coat (surfacer
or guide coat) is sometimes applied by spraying. After the prime
coats have been baked, the topcoat is applied by a combination of
manual and automatic spray devices in a spray booth. The topcoat
is applied in one to three steps with a bake (cure) step after
each. Additional coats of different colors may also be applied.
The coated body then goes to the trim shop, where the interior
and exterior trim is applied.
Touchup coating is applied at various stages of the top-
coating line and the touchup sprays are cured in the line oven.
After the final touchup, the coating must be cured in a low-
temperature oven to protect heat-sensitive plastics and rubber
parts built into the vehicle. Organic-solvent-borne coatings
have been used in conjunction with the low-temperature curing.
3.14.2 Emission of Pollutants
Emissions of volatile organic compounds (VOC) occur at three
significant facilities in a vehicle finishing operation: 1) the
3.14-1
-------
FROM BODY SHOP
METAL
PRETREATMENT
DRY-OFF OVEN
PRIME
APPLICATION
AREA
PRIME CURE OVEN
FIRST TOPCOAT
APPLICATION AREA
FIRST TOPCOAT
CURE OVEN
SECOND TOPCOAT
APPLICATION AREA
(IF ANY)
SECOND TOPCOAT
CURE OVEN
(IF ANY)
COATED PARTS FROM
OTHER LINES
THIRD TOPCOAT
APPLICATION AREA
(fF ANY)
THIRD TOPCOAT
CURE OVEN
(IF ANY)
1
TRIM APPLIED
(SEATS. RUGS,
DASH. TIRES. ETC.)
REPAIR TOPCOAT
APPLICATION AREA
REPAIR TOPCOAT
OVEN
(LOW TEMPERATURE)
FINISHED
PRODUCTS
Figure 3.14-1. General flow diagram for automotive and light
truck assembly plants. Main bodies may be on
separate lines from hoods and fenders.
3.14-2
-------
prime coating line, 2) the topcoating line, and 3) the final repair area. In
each of these facilities, emissions occur in the application area, the flash-off
area, and the cure oven.
The prime coat serves the dual function of protecting the surface from
corrosion and providing for good adhesion of the topcoat. Organic-solvent-
borne primer is usually applied by a combination of manual and automatic
spray methods, with or without the use of electrostatic techniques. When
manual methods are used, health regulations require that solvent concen-
trations be kept low. Waterborne primers may be applied by spray or dip
methods. When organic-solvent-borne spray is used, 85 to 90 percent of the
solvent evaporates in the booth and flash-off area; the remaining 10 to 15
percent evaporates in the oven. Typical solvent emissions from the prime
coating operation are 193 kg/h (425 Ib/h) with a spray applied two-coat prime
containing 32 percent solids enamel, and 18 kg/h (40 Ib/h) with EDP coating.
The EDP is followed by a prime surfacer coat that has typical solvent
emissions ranging from (120 to 300 Ib/h) depending on the type of coating
used.
The topcoat is applied in one to three steps, each followed by a curing
oven. The topcoat colors used on-line vary in accordance with consumer
requests. Metallic and "tutone" finishes are also applied on the topcoat line.
The coating is applied by manual and/or automatic spraying in an enclosed
spray booth. Solvent concentrations in the manual booth must comply with
health regulations. Because of the length of time that the auto body is in
the spray booth, 85 to 90 percent of the solvent evaporates in the booth and
its flash-off area. Typical solvent emissions from the topcoat line are 386
kg/h (850 Ib/h) with a 32 percent solids enamel, 1.3 Mg/h (3000 Ib/h) with a
12 percent solids lacquer, and 77 kg/h (170 Ib/h) with waterborne coatings.
Areas damaged during trim application or imperfections not detected in
the main paint shop are repainted in a final repair step. Because the vehicle
now contains heat-sensitive materials, coatings used for repair are generally
limited to solvent-borne materials that can be dried in low-temperature ovens.
Production in the repair area is intermittent. Typical emissions from the final
repair area are 13.3 kg/h (29.3 Ib/h) with solvent-borne coatings.
3.14-3
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Uncontrolled organic emissions from coating of vehicles with organic-
solvent-borne coatings can range from less than 272 kg/h (600 Ib/h) to more
than 1.8 Mg/h (4000 Ib/h) over an entire assembly line. This wide range is
caused by variations in the surface area coated on different vehicles, the
number of vehicles coated per hour, the coating application method, and. the
solvent content of the coatings. A plant may operate more than one assembly
line.
Sources of organic emissions from a vehicle assembly plant that are not
considered here include the application of adhesives and soundproofing
materials. These account for about 10 to 30 percent of total organic emissions
from the plant. Other fugitive emissions occur during the initial solvent
wipe, plant cleanup, and solvent storage.
3.14.3 Control Measures
3.14.3.1 Prime Coating Line--
The use of waterborne spray primers and/or electrocoating systems
provides substantial reductions in VOC emissions and is the most common
control measure now used in the industry. The greatest emission reduction
occurs when primer is applied by electrophoretic (electrodeposited) dip of the
total body. Only waterborne coatings can be applied by this process.
Typical solvent contents of the coatings (not including water) range from 0.8
to 2.0 Ib solvent/gal coating. The object to be coated is immersed in a
waterborne coating and an electric potential difference is induced between the
object and the coating bath. As the object emerges from the bath, its
coating is 90 percent solids (by volume), 9 percent water, and 1 percent
organic cosolvent. Excess coating is returned to the bath by washing the
object with makeup and ultra-filtered water. Because of the extremely
low-solvent usage [about 3 kg/h (7 Ib/h)], the exhaust from this oven
requires no further emission control unless it presents an odor problem. The
electrophoretic dip process is used at over^ 40 percent of U.S. assembly
plants and is very widely used in Europe. ' '
The percentage reduction achieved by a change to electrophoretic
coatings depends on the original system. For example, if the change is from
3.14-4
-------
a 32-percent solids primer [about 2.4 kg (5.3 Ib) of organic solvent per
gallon of coating] to electrophoresis [about 0.45 kg (1.0 Ib) of organic solvent
per gallon of coating], the reduction is 80 percent. Reduction in emissions of
95 percent by use of this priming method have been reported.
The major limitations of electrophoretic dip coating are that it can be
used only directly over metal or other conductive surfaces and only one coat
can be applied. Electrical requirements increase by about 1400 kW with this
method; this represents a 12 percent increase over the 12,000 kW required for
applying organic-solvent-borne primers. Additionally, the electrophoretic dip
coatings may contain amines that are driven off during the curing step;
incineration of the oven exhaust is then required to eliminate the visible
emissions and malodors associated with amines.
Spraying of waterborne primers is possible, but such operations are not
readily automated. Some plants do spray waterborne primers, and this is a
viable option for many plants, especially when more than one primer coat is
required.
The use of organic-solvent-borne coatings with relatively high solids
content inherently reduces VOC emissions because of the lower-solvent
content. The achievable reduction depends on a comparison of the higher-
solids coating with the coating that would otherwise be used. For example, a
coating with 50 percent solids achieves an 86 percent reduction of emissions
compared with a coating with a lacquer with 12 percent solids; the reduction
is only 53 percent, however, with respect to use of an enamel with 32 percent
solids. Obviously, even further reductions can be achieved if the transfer
efficiency is improved or an add-on control device is also installed. Topcoats
containing 37-40 volume percent solids and nearly 50 percent solids have been
used by Volkswagen and American Motors, respectively.
Add-on control measures available for use on prime coating lines include
activated carbon adsorption and incineration. Pilot studies on the use of
carbon adsorption in primer spray booths and flash-off areas have indicated
fi 7
potential for reductions of greater than 85 percent. ' Presently, no full-
scale carbon adsoption systems are in operation on any automobile or truck
coating line. Carbon adsorption is technically feasible, however, and General
3.14-5
-------
Motors has acknowledged that activated carbon can be used effectively on
spray booths and ovens to reduce solvent emissions by 90 to 95 percent if the
fi 7
system is properly engineered and regularly maintained. '
Both catalytic and thermal incinerators could be used to control VOC
emissions from prime and topcoating spray booths and ovens. Incinerators
operated at high temperatures can almost completely destroy organic vapors.
Reductions in VOC emissions of 90 to 98 percent have been reported with the
159
use of thermal incinerators on primer and topcoat ovens. ' ' The fuel con-
sumption by incinerators of oven exhaust need not be excessive if the oven
operates at a relatively high proportion of the lower explosive limit (LEL).
Heat recovery systems become attractive with increased VOC concentration.
With spray booth and flash-off area exhausts, however, the high flow rates
and very low organic vapor concentrations require that an incinerator
consumes huge amounts of fuel. Moreover, the opportunity for more than
primary energy recovery is restricted by the. limited need for the large
amount of energy available. For these reasons, although technically feasible,
incineration of spray booth and flash-off area exhaust is not practiced at any
plant.
3.14.3.2 Topcoating Line--
Many of the control measures applicable to the prime coating line can
also be used on the topcoating line. Reductions in organic solvent emissions
of up to 92 percent from topcoat spray booths and ovens are possible by use
of waterborne topcoats. As before, the exact reduction depends on the
original coating and the substitution. Waterborne coatings are currently
being used at two General Motors automobile assembly plants in California on
a full-scale basis. These plants have reported 88 percent reductions in VOC
emissions as a result of the coating substitution.5 As with waterborne primer
systems, however, use of waterborne topcoats increases electrical usage (in
this case, by 42 percent). Difficulties in precipitation and dewatering of the
collected overspray increase the solid waste disposal problem. Waterborne
coatings are sensitive to humidity, and it has been reported that suitable
waterborne coatings do not exist for van interiors.
3.14-6
-------
The use of higher-solids coatings, activated carbon adsorption, or
thermal and catalytic incineration on the topcoat line can achieve the same
reductions as presented for prime coatings and are subject to the same
limitations described earlier.
Recently developed powder coatings may have possible application in the
automobile and light-duty truck coating industry. To date, their use in this
industry has been limited by the need to change colors often and the lack of
availability in metallic colors. Preliminary studies indicate that powder
coating systems reduce energy requirements, have acceptable durability, offer
95 to 99 percent utilization, and essentially eliminate all organic solvent
emissions.5' Within the last year, the major auto producers have resumed
investigation of powder coatings.
3.14.3.3 Final Repair--
Control of emissions from the final repair spray booth and oven has not
been practiced because the intermittent operations make add-on control equip-
ment less cost-effective than in other areas. These emissions can be collected
and sent to an activated carbon adsorption unit or incinerator at another
location within the plant. This system, however, would not provide cost-
effective control. Considerable reductions in emissions can be accomplished
by the use of higher-solids repair coatings, but this measure has not been
practiced at any plant.
3.14.4 Emission Limits
The initial criterion for defining lowest achievable emission rate (LAER)
for a surface coating industry is the degree of emission control required by
the most stringent regulation adopted and successfully enforced by a state or
local air pollution control agency.
Most organic solvent emission regulations are patterned after what is now
Rule 442 of the South Coast (California) Air Quality Management District.
Review of the regulations applicable in the 16 states that contain about 85
percent of all surface coating industries showed that these are essentially the
same as Rule 442. Indiana has the most stringent regulation, which limits
3.14-7
-------
organic solvent emissions to 1.4 kg/h (3 Ib/h) or 6.8 kg/h (15 Ib/day) unless
such emissions are reduced by at least 85 percent, regardless of the reactiv-
ity or temperature of the solvent. Organic solvents that have been deter-
mined to be photochemically unreactive or that contain less than specified
percentages of photochemically reactive organic materials are exempt from this
regulation. Recent research, however, has indicated that substituting low-
reactivity solvents for higher-reactivity solvents may improve photochemical
13
oxidant air quality in one city while worsening it in downwind regions.
Accordingly, EPA has adopted a policy emphasizing the need for "positive
reduction techniques" rather than substitution of compounds. Thus, the
"low reactivity" solvents will no longer be exempt.
California Air Resources Board has recently adopted a model rule for the
control of VOC emissions from light- and medium-duty vehicle assembly
plants. This rule limits VOC emissions from the prime or topcoat lines to
0.275 kg/liter (2.29 Ib/gal) of coating as applied, excluding water, unless the
emissions are reduced by 90 percent through treatment of the exhaust.
Other recommended emission limitations represent rates achievable by appli-
cation of reasonably available control technology (RACT). It has been pro-
posed that these rates also be adopted as new source performance standards
(NSPS) for the industry. The recommended VOC emission limitations achiev-
able by application of RACT are: 1) 0.23 kg/liter (1.9 Ib/gal) of coating
minus water for the prime coating line, 2) 0.34 kg/liter (2.8 Ib/gal) for the
topcoating line, and 3) 0.58 kg/liter (4.8 Ib/gal) for the final repair area.
The recommended limitation for prime coating is based on the use of water-
borne electrophoretic dip primer, 0.15 kg/liter (1.2 Ib/gal) of coating minus
water, followed by water-borne primer surfacer with 0.34 kg/ liter (2.8
Ib/gal) of coating minus water.
3.14.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
3.14-8
-------
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
LAER for automobile and light-duty truck coating is determined to be a
combination of limitations represented by RACT and the emission reductions
achieved-in-practice using current technology and control measures. For
prime coat application, the use of waterborne coatings in the electrophoretic
dip process followed by water-borne primer surfacer represents LAER. This
reduction is comparable to the RACT limitation of 230 g of solvent/liter (1.9
Ib/gal) of coating minus water and can also be achieved using higher solids
coatings in conjunction with an oven incinerator.
For the topcoating line, LAER can be met by the use of waterborne
coatings with achievable reductions of 88 to 92 percent, which is again
comparable to the RACT limitation of 320 g of solvent/liter (2.8 Ib/gal) of
coating minus water. Similar reductions are achievable when using other
low-solvent coatings such as powders or higher solids coatings, although oven
exhaust incineration is required when higher solids coatings are used to
achieve the 88 to 92 percent reduction.
For the final repair area, higher solids coatings would represent LAER if
this technology had been demonstrated in the industry. LAER is considered
to be the recommended VOC limitation capable of being met by the application
of RACT, i.e., 580 g of solvent/liter (4.8 Ib/gal) of coating minus water.
3.14-9
-------
REFERENCES
1. Much of the material that follows is extracted almost
directly from: Control of Volatile Organic Emissions for
Existing Stationary Sources. Volume II: Surface Coating of
Cans, Coils, Paper, Fabric, Automobile, and Light-duty
Trucks. U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina. Publication Number EPA
450/2-77-008. May 1977.
2. Letter from V.H. Sussman, Ford Motor Company, Dearborn,
Michigan to J. McCarthy regarding draft of reference 1.
August 6, 1976.
3. Report of trip by J.A. McCarthy, U.S. Environmental Protec-
tion Agency, Research Triangle Park, North Carolina to
General Motors assembly plants in South Gate and Van Nuys,
California. November 17, 1975.
4. Report of trip by J.A. McCarthy, U.S. Environmental Protec-
tion Agency, Research Triangle Park, North Carolina to
assembly plant in Framingham, Massachusetts. November 17,
1975.
5. Carson, W., et al. Proposed Model Rule for the Control of
Volatile Organic Compounds from Automobile Assemblyline
Coating Operations. Prepared for California Air Resources
Board, Sacramento, California. January 26, 1978.
6. Evaluation of a Carbon Adsorption Incineration Control
System for Auto Assembly Plants. Radian Corporation,
Austin, Texas. Prepared for U.S. Environmental Protection
Agency. EPA Contract No. 68-02-1319, Task No. 46. January
1976.
7. Letter from W.R. Johnson, General Motors Corporation,
Warren, Michigan to Radian Corporation commenting on
Reference 6. March 12, 1976.
8. Vincent, E.J., et al. Are Afterburners Obsolete? (Pre-
sented at Air Pollution Control Equipment Seminar
APCA/National Association of Corrosion Engineers. Atlanta,
Georgia. January 17-19, 1978.)
3.14-]0
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9. Taback, H.J., et al. Control of Hydrocarbon Emissions from
Stationary Sources in the California South Coast Air Basin.
KVB Consultants, Tustin, California. Prepared for
California Air Resources Board. KVB Interim Report
5804-714. November 1976.
10. Levinson, S.B. Electrocoat, Powder Coat, Radiate. Which
and Why? Journal of Paint Technology. 44(570):42, July
1972.
11. Recommended Policy on Control of Volatile Organic Compounds.
U.S. Environmental Protection Agency. Federal Register July
8, 1977 (42 FR 131).
12. Data on the geographical distribution of surface coating
industries can be found in: Sources Assessments: Priori-
tization of Air Pollution from Industrial Surface Coating
Operations. U.S. Environmental Protection Agency. Publi-
cation Number EPA 650/2-75-0192. February 1975.
13. A series of documents which are referenced and summarized
in: Control Strategy Preparation Manual for Photochemical
Oxidant. U.S. Environmental Protection Agency. Publication
Number OAQPS 1.2-047. January 1977.
3.14-11
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3.15 MAJOR SOURCE CATEGORY: METAL FURNITURE AND LARGE
APPLIANCE COATING - VOLATILE ORGANIC COMPOUND (VOC)
EMISSIONS
3.15.1 Process Description
Metal furniture is manufactured for both indoor and outdoor use by two
general consumer categories: business/institutional and residential. Metal
furniture products include tables, chairs, wastebaskets, beds, desks,
lockers, benches, shelving, file cabinets, lamps, room dividers, and many
other similar items. Size of the plants varies with the type of furniture
manufactured, the number of manufacturing and coating lines, and the amount
of assembly required.
Large appliance products include doors, cases, lids, panels and interior
support parts of residential and commercial washers, dryers, ranges, refrig-
erators, freezers, water heaters, dishwashers, trash compactors, air condi-
tioners and similar products. A typical large appliance plant is much bigger
than a typical metal furniture plant, but may manufacture only one or two
different types of appliances and contain as few as two coating lines. Most of
the coatings used in these industries are enamels, although quick-drying
lacquers are sometimes applied to repair scratches and nicks that occur
during assembly. Some coatings are metallic. The coatings applied to metal
furniture and large appliances must protect the metal from the corrosive
action of agents such as heat, water, detergents, and the outdoor elements.
They must have good adhesion properties to prevent peeling or chipping,
must be durable, and must meet customer standards of appearance. Coatings
may contain mixtures of 2 to 15 different solvents. Prime and interior single
coat materials are typically 25 to 36 percent solids by volume, and topcoat
and exterior single coats are 30 to 40 percent solids. The underside of many
exterior large appliance parts are sprayed with gilsonite to provide additional
moisture resistance and sound-deadening properties. The gilsonite is typi-
cally sprayed at about 25 to 30 percent solids by volume.
A typical metal furniture line is depicted in Figure 3.15-1; a typical large
appliance line is shown in Figure 3.15-2. Unassembled, partly assembled, or
3.15-1
-------
en
I
NJ
FROM
MACHINE SHOP
CLEANSING AND
PRETREATMENT
PRIME COAT FLASHOFF AREA
AND OVEN
(OPTIONAL)
ELECTROSTATIC. OR
CONVENTIONAL AIR OR
AIRLESS SPRAY COATING
FLOW COATING
TOfCOATM SINGLE
HAT AffllCATION
Fiqure 3.15-1. Coating of metal furniture,
-------
DIRECT TO METAL TOPCOAT
FLASHOFF
(OPEN OR TUNNELED)
FROM SHEET METAL MANUFACTURING
EXTERIOR PARTS
(CASES. LIDS AND DOORS)
U)
INTERIOR CLEANSING AND
PARTS PRETREATMENT
SECTION
FLASHOFF
(OPEN OR TUNNELED)
PRIME DIP
TO ASSEMBLV
Figure 3.15-2. Coating of large appliances.
-------
totally assembled furniture or appliance pieces are first transported on a
conveyor through an alkaline cleansing and pretreatment process. Sometimes
the wash section is omitted and the pieces are cleaned in a shot-blasting
chamber or organic solvent cleaning operation.
Most metal furniture and some large appliance pieces are finished with a
single coat. Other surfaces, however, require a prime coat because of the
topcoat formulation or the intended use. The prime coat may be applied by
electrostatic or conventional spray, dip, or flowcoating techniques (coating
techniques are discussed below). The substrate with the prime coat then
goes through a flash-off period to prevent popping of the film when the
coating is baked. The prime coat is usually baked in an oven at about 160°
to 200°C (300° to 400°F).
The topcoat or single exterior coat may be applied to metal furniture by
spraying, dipping, and flowcoating. Large appliances are usually sprayed.
A touch-up operation or application of highlighting tone follows. The coated
part passes through a flash-off zone and into a baking oven. The baking
oven usually contains several temperature zones ranging from 160° to 230°
(300° to 400°F). Some metal furniture parts are air dried, but all appliance
parts are heat cured.
The heart of a coating line is the method by which the coating is
applied. Regardless of the type of coating, there are basically three possible
modes of application: dip coating, flow coating, and spraying. Each are
briefly described below.
Dip coating is the immersion of pieces into a coating bath. The tank
that contains the coating is continuously agitated. As the parts move on a
conveyor, they are immersed in the coating and withdrawn; the excess
coating is then allowed to drain back into the tank. Dip coating, in addition
to being one of the most efficient coating methods, also provides the best
coverage of cavities and crevices. Consequently, it is used largely for prime
or undercoating but may also be used for top coating in cases where the
plant uses one or two colors.
Flow coating is also used when only one or two colors are applied. As
the parts are moved by a conveyor through an enclosed booth, stationary or
3.15-4
-------
oscillating nozzles at various angles emit streams of coating, which flow over
the part. Excess coating, which drains into a sink on the bottom of the
booth, is filtered and recycled.
Spraying is the most used of all coating application techniques. There
are three natural categories of spray coating based upon the way the coating
is atomized and transported from the delivery device to the metal surface.
Air spray utilizes a high velocity air gun to atomize the coating into fine
droplets and carry the droplets to the substrate. Airless spray is accom-
plished by forcing a liquid coating through a small orifice at very high
pressures. In electrostatic spraying, the coating is atomized by one of the
above methods or by feeding the coating to a disk or bell rotating at high
rpm. The paint particles are given a negative charge by the atomization
device and are attracted to the grounded metal parts. Any of the spraying
methods can be used manually or with automatic controls. Most spray coating
in metal furniture facilities is done manually, whereas in large appliance
facilities it is done automatically. The important difference among spray
coating methods is transfer or application efficiency. Conventional air or
airless sprays are typically 30 to 50 percent efficient. Electrostatic spray
guns can be as high as 65 percent efficient and high speed disks and mini
bells can achieve 90 percent efficiency.
Spray coating and, frequently, other coating methods are performed in a
booth to contain any over-spray or drippings, to prevent dirt from contacting
the paint, and to control the temperature and humidity at the point of appl-
ication. Air flow rates through spray booths vary depending on whether
they are occupied and on their size. OSHA prescribes minimum air velocities
to assure capture of overspray and to keep VOC concentrations below the
threshold limit values (TLV).
As has already been mentioned, the baking oven usually contains several
zones at temperatures ranging from 160° to 230°C (300° to 450°F). The
exhaust air flow rate depends on the size of oven openings through which
parts enter and exit. Insurance underwriter requirements typically limit the
atmosphere within industrial baking ovens to 25 percent of the lower explosive
limit (LEL); however the use of continuous monitoring equipment changes the
requirements and allows concentrations as high as 40 percent of the LEL.
3.15-5
-------
3.15.2 Emission of Pollutants
The significant emitting facilities in a metal furniture or large appliance
coating plant are the prime and topcoating lines. On each line, VOC's are
emitted from the coating area, flash-off area, and oven.1 As shown in Table
3.15.1, it is estimated that 65 to 80 percent of the uncontrolled VOC emissions
are released from the spray booth and flash-off area in spray applications,
and the remaining 20 to 35 percent from the oven. In a dip or flowcoat
application, an estimated 50 to 60 percent of the VOC emissions come from the
coating and flash-off area, and the other 40 to 50 percent from the oven.
Typical uncontrolled VOC emissions from the coating of metal file cabinets are
6.8 kg/h (15 Ib/h) from the entire plant. Typical uncontrolled emissions from
the coating of automatic washers are 13.2 kg/h (29 Ib/h) from the coating
area and oven, and 11.8 kg/h (26 Ib/h) from the sound-deadener application.
3.15.3 Control Measures
Operators of metal furniture and large appliance coating processes use
several measures to reduce VOC emissions at the point of application or
remove them from the exhaust stream. Waterborne coating is a feasible
control measure. Waterborne coating can be applied by spray, dip, flowcoat,
or electrodeposition (EDP). Electrodeposition is limited to waterborne coat-
ings used for the primer or single coat application. EDP coatings are applied
from an aqueous bath, which contains about 10 to 15 percent solids (by
volume) and 2 to 4 percent organic solvents. Applying direct current in the
bath causes the solids to become attached to the grounded metal piece.
Electrodeposition can be performed either anodically or cathodically. The
metal parts emerge from the bath with a coating containing about 90 percent
solids (by volume), 1 to 2 percent organic solvent, and the balance water.
Two automobile finishing plants using this application method report reduc-
tions in VOC emissions of 95 percent.2 Large appliance plants using EDP
have demonstrated 93 percent solvent reduction.* A more complete descrip-
tion of this process is presented in Section 3.14.3.
Emission reductions of 60 to 90 percent may be obtained by use of water-
borne coatings on topcoat lines and primer or single coat lines where the
Data on metal furniture and large appliance operations supplied by
paint company. April 14, 1978.
3.15-6
-------
TABLE 3.15-1. DISTRIBUTION OF VOC EMISSIONS FROM METAL
FURNITURE AND LARGE APPLIANCE COATING LINES3
(percent)
Application
method
Electrostatic spray
Conventional air or
airless spray
Dip
Flow
Application and
flash-off area
65
80
50
60
Oven
35
20
50
40
Source: Reference 1, Volume III.
a The base case coating is applied at 25 volume percent solids
and 75 volume percent organic solvent, which is equivalent
to a VOC emission factor of 0.66 kg of organic solvent
per liter of coating (5.5 Ib/gal) minus water.
3.15-7
-------
coating is applied by spray, dip, or flowcoat. Use of these coatings has
produced an 87 percent reduction at some large appliance plants.* Temper-
ature, humidity, gun-to-metal distance, and flash-off time affect the appear-
ance and other characteristics of the coating.
Activated carbon adsorption, although technically feasible, has not been
used in the metal furniture or large appliance coating industries. Carbon
adsorption is a feasible control option for the application and flash-off areas
because exhaust gases are at ambient temperatures and contain only small
amounts of particulate matter that could foul the carbon bed. (Some partic-
ulate removal would be necessary at spray booths). Carbon adsorption could
reduce emissions from these areas by 70 to 90 percent of the vapors that are
drawn into the bed.1 Use of activated carbon adsorption on paper and fabric
coating lines has provided up to 98 percent removal of VOC vapors drawn
into the bed.t For metal furniture or large appliance coating lines the
mixture of solvents that are recovered cannot be used without further treat-
ment. Collected mixed solvents can be used as fuel for ovens or other
heating processes.
No serious technical problems are associated with the use of either
catalytic or thermal incinerators at these facilities. Documentation of
achievable reductions of 96 to 99 percent across the control device for incin-
erators used at automobile, can, coil, and paper coating facilities is presented
in Sections 3.14, 3.16, 3.17, and 3.18, respectively. As discussed in Section
3.14.3, incineration of exhausts from the spray booth and flash-off areas
requires auxiliary fuel. Fuel input can be reduced with heat recovery
equipment.
Emissions from topcoat and single coat application and curing can be
controlled by use of powder coatings. These may be applied electrostatically
by spraying or dipping, or by dipping the preheated metal into a fluidized
bed. Electrostatic spraying is more widely used than dipping because it can
apply thinner films of coating. Powder spray coating requires a booth, as
*Data on metal furniture and large appliance operations supplied
by paint company. April 14, 1978.
letter from W. C. Moses, Technical Manager, Chemical Plant
Division, Suttcliffe, Speakman & Company, Limited. March 10, 1978.
3.15-8
-------
does spray coating with conventional coatings. Ventilation requirements are
greatly reduced because the booths are not occupied. Electrostatic dipping is
limited to simple shapes. The fluidized bed dipping method applies the
powder only in thick films. Use of powder coating reduces energy require-
ments in the application area and greatly reduces VOC emissions. These
coatings have acceptable durability and offer more than 95 percent utiliza-
o
tion. Reduction in VOC emissions may range from 95 to 99+ percent over
conventional systems. Data reveal that the average solvent reduction for
powder coating by electrostatic spray methods is 99 percent. Several limi-
tations are associated with the use of powder coatings in the metal furniture
coating industry. Color changes require about half an hour of downtime to
evacuate the spray booth and purge the former color from the application
device. Color matching during manufacture of the powder is difficult;
metallic coatings are not presently available; powder films have appearance
limitations; they do not coat well within small recesses; and excessive
humidity during storage or application can affect performance.
Reductions of VOC emissions by choosing higher-solids coatings over
conventional organic-solvent-borne coatings may range from 50 to 82 percent,
depending on the solids content of the coating that would otherwise be used.
*
The average achievable reduction is 78 percent. Higher-solids coatings are
applied most effectively by automated electrostatic spraying, but manual and
conventional spraying techniques can also be used. Some minimal increase in
energy may be required to raise the pressure of the spray gun or heat the
more viscous coating so that it can be pumped and atomized. Emissions from
gilsonite application in the large appliance industry can also be controlled
through use of higher-solids coatings; no data are available on the solvent
reductions that can be obtained.
3.15.4 Emission Limits
The initial criterion for defining LAER for a surface coating industry is
the degree of emission control required by the most stringent regulation
*
Data supplied by paint company. April 14, 1978.
3.15-9
-------
adopted and successfully enforced by a state or local air pollution control
agency.
Most organic solvent emission regulations are patterned after what is now
Rule 442 of the South Coast (California) Air Quality Management District.
Review of the regulations applicable in the 16 states that contain about 85
percent of all surface coating industries showed that they were essentially the
same as Rule 442.5 Indiana has the most stringent regulation in that it limits
organic solvent emissions to 1.4 kg/h or 6.8 kg/h (3 Ib/h or 15 Ib/day) unless
such emissions are reduced by at least 85 percent, regardless of the reac-
tivity or temperature of the solvent. Organic solvents that have been deter-
mined to be photochemically unreactive or that contain less than specified
percentages of photochemically reactive organic materials are exempt from this
regulation.
In defining LAER for surface coating emissions, it is not appropriate to
exempt solvents on the basis of their reactivity. Recent research has
indicated that substituting low-reactivity solvents for higher-reactivity
solvents may improve photochemical oxidant air quality in one city while
£
worsening it in downwind regions. Accordingly, EPA has adopted a policy
emphasizing the need for "positive reduction techniques" rather than sub-
A
stitution of compounds.
California Air Resources Board has recently adopted a model rule for the
control of VOC emissions from metal parts and product coating operations.
This rule must be met within 3 years from the date of adoption. It limits the
VOC emissions from baked coatings to 275 g solvent/liter (2.3 Ib/gal) coating
minus water, and from forced-air-dried coating to 340 g solvent/liter (2.8
Ib/gal) of coating minus water.
A recent EPA publication presents emission limits achievable through the
application of reasonably available control technology (RACT). The recom-
mended limitation for metal furniture coating is 0.36 kg of organic solvent/
liter of coating minus water (3.0 Ib/gal); for large appliance coating it is 0.34
kg/liter (2.8 Ib/gal). These limitations are comparable to an 80 percent
reduction in solvent emissions from each affected facility. There are
currently existing facilities which meet or exceed the RACT limitations for
3.15-10
-------
both categories; therefore, it is concluded that LAER for metal furniture and
large appliance coating is a function of controls achieved in practice rather
than controls required by existing regulations.
3.15.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional .
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become
available in the near term. Conceivably, some SIP regulations may be more
stringent than the LAER suggested herein. Furthermore, performance testing
may show that more stringent limits that those suggested are feasible or it
may show that the suggested limits are appropriate or that they are not
achievable for some specific subcategories. In any case, the basis for deter-
mining LAER for many source categories is expected to change frequently.
Since LAER is near the vanguard of control technology, a more detailed
analysis is particularly necessary when addressing modified or reconstructed
facilities subject to the provisions of Section 173 of the Clean Air Act.
Emission limitations reasonable for new sources may in some instances be
economically or technically unreasonable when applied to modified or recon-
structed sources of the same type.
The lowest achievable emission rate for metal furniture and large
appliance coating is determined to be a combination of limitations represented
by RACT and emission reductions achieved in practice. For metal furniture
coating operations, LAER can be met by the use of waterborne coatings,
which can achieve reductions of 88 to 92 percent. This is comparable to the
RACT limitation of 360 g solvent/liter (3.0 Ib/gal) of coating minus water.
For large appliance coating, LAER is also equal to RACT that requires the
use of a coating containing 340 g solvent/liter (2.8 Ib/gal) of coating minus
water. Similar reductions for these operations can be achieved by the use of
other low-solvent coatings (such as powders) or higher-solids coatings. The
application of add-on control devices capable of providing equivalent reductions
is also an acceptable way of meeting these limitations.
3.15-11
-------
REFERENCES
1. Much of the material on emissions is extracted almost
directly from: Control of Volatile Organic Emissions for
Existing Stationary Sources. Volume III: Surface Coating
of Metal Furniture, and Volume V: Surface Coating of Large
Appliances. EPA 450/2-77-032 and 034, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina.
December 1977.
2. Taback, H. J., et al. Control of Hydrocarbon Emissions from
Stationary Sources in the California South Coast Air Basin.
KVB Consultants, Tustin, California. Prepared for Cali-
fornia Air Resources Board. KVB Interim Report 5804-714.
November 1976.
3. Levinson, S. B. Electrocoat, Powder Coat, Radiate. Which
and Why? Journal of Paint Technology 44(570):42, July 1972.
4. Recommended Policy on Control of Volatile Organic Compounds.
U.S. Environmental Protection Agency. (42 FR 131) Federal
Register, July 8, 1977.
5. Data on the geographical distribution of surface coating
industries can be found in: Sources Assessments: Prioriti-
zation of Air Pollution from Industrial Surface Coating
Operations. EPA 650/2-75-0192, U.S. Environmental Protec-
tion Agency. February 1975.
6. A series of documents referenced and summarized in: Control
Strategy Preparation Manual for Photochemical Oxidant.
OAQPS 1.2-047, U.S. Environmental Protection Agency.
January 1977.
7. Fugita, E., et al. Consideration of a Proposed Model Rule
for the Control of Volatile Organic Compound Emissions from
the Surface Coating of Manufactured Metal Parts and Prod-
ucts. Presented to California Air Resources Board,
Sacramento, California. September 27, 1978.
3.15-12
-------
3.16 MAJOR SOURCE CATEGORY: CAN COATING—VOLATILE ORGANIC
COMPOUND (VOC) EMISSIONS
3.16.1 Process Description
Cans are manufactured by two different processes.1 The three-piece
can is made from a rectangular sheet and two circular ends. The metal sheet
is rolled into a cylinder and soldered, welded, or cemented at the seam. One
end is attached during manufacturing and the other during packaging of the
product. The two-piece can is drawn and wall-ironed from a shallow cup and
requires only one end, which is attached after the can is filled with product.
Two-piece can manufacturing is a high-speed process that combines the
fabricating and coating operations. These cans are most commonly used by
the beverage industry. Figure 3.16-1 presents a process flow diagram of
fabricating and coating two-piece cans.
Metal for two-piece cans is received in coil form and is fed continuously
into a press (cupper) that stamps and forms a shallow cup. The cups go
through an extrusion process that, in a lubricating solution, draws and
wall-irons them into cans in a lubricating solution and trims the uneven
edges. The formed cans are then cleansed to remove the lubricating solution,
rinsed with hot water, and dried.
The exteriors of the cans are sometimes roller coated with a base coat.
The base coat is transferred from a feed tray, over a series of rollers, and
onto the can, which rotates on a mandrel. The coating is cured or baked at
177° to 204°C (350° to 400°F) in single or multipass continuous ovens at a
rate of 500 to 2000 cans per minute.
Designs and lettering are transferred to the cans from a printing blanket
on a rotary printer. A protective varnish is sometimes roll coated directly
over the inks on the same line. The decorative coating and varnish are
cured or baked in single or multipass continuous, high-production ovens at
163° to 204°C (325° to 400°F).
After printing, the cans are necked, flanged, and tested. The cans are
spray coated on the interior and spray and/or roll coated on the exterior of
the bottom end. The coating is usually cured or baked in a continuous,
3.16-1
-------
CANS
8)
COIL
^
COPPER
n
WALL
IRONER
WASHER
OVEN
iSE COAT TRAY
EXTERIOR BASE COATER,
I
to
$%
OVEN INTERIOR BODY SPRAY
AND EXTERIOR END SPRAY
AND/OR ROLL COATER
LEAK
TESTER
PRINTER AND OVER
COLOR 4
COLOR 3
COLOR 2
COLOR 1
VARNISH
^•~^
COATER ft y-N VA
J
RNISH
FRAY
NECKER AND
FLANGER
OVEN
Figure 3.16-1. Two-piece can fabricating and coating operation
-------
singlepass oven at temperatures of 107° to 204°C (225° to 400°F). Coated
cans are stacked on pallets for shipment to users.
The three-piece can manufacturing process consists of two major
operations: sheet coating and can fabricating. The sheet coating operation
consists of base coating and printing, which includes the overvarnish coat.
The sheets are roll coated on one side only by transfer of the coating
through a series of rollers from the coating tray onto the sheets. Sheets are
then picked up by preheated wickets and transported through a continuous,
multizone oven at rates of 50 to 150 sheets per minute, depending on the type
of coating. The coating is cured at temperatures up to 218°C (425°F); sheets
are air cooled in the last zone of the oven. Oven exhaust rates usually
range between 0.94 and 6.6 Nm3/s (2000 and 14,000 scfm).
The sheet printing or lithograph operation usually involves applying one
or two colors of ink on the exterior base coat, or directly on the metal. Inks
are applied by a series of rollers that transfer the design first to a blanket
cylinder, then onto the metal sheet, as shown in Figure 3.16-2. Varnish is
applied directly over the wet inks by a direct-roll coater. Inks and over-
varnish are cured in a wicket oven similar to, but usually smaller than, the
base coat oven; exhaust rates are 0.7 to 3.8 Nm3/s (1500 to 8000 scfm). If
the design requires more than two colors, the first set of inks is dried in an
oven before additional color inks are applied. After all inks are applied, the
sheets are overvarnished and then cured in another oven.
The three-piece cans are fabricated by forming the can bodies from
coated sheets. This process includes a side-seam spray to protect the
soldered seam and an inside spray to protect the inside surfaces. These
processes are not considered in this guidance document.
3.16.2 Emission of Pollutants
Two significant emitting facilities at can manufacturing plants are the
base coating line and the overvarnish coater/oven portion of the printing
line. On each of these lines emissions are generated from both a roller coater
and an oven. Uncontrolled VOC emissions from the line for base coating of
sheets (three-piece cans) average 50.8 kg/h (112 Ib/h); emissions from
3.16-3
-------
INK
APPLICATORS
BLANKET
CYLINDER
U)
(T)
I
SHEET (PLATE)
FEEDER
LITHOGRAPH
COATER
OVER VARNISH
COATER
WICKET OVEN
SHEET (PLATE)
STACKER
Figure 3.16-2. Sheet printing operation,
-------
printing of sheets average 29.5 kg/h (65 ib/h). Typical combined emissions
from base coating and overvarnishing on a two-piece can coating line are 39
kg/h (86 Ib/h).1 These emissions may range from 9.1 to 270 kg/h (20 to 600
Ib/h) uncontrolled, depending on the line size and speed and the type of
coating.
When solvent-borne sheet coatings are applied by roller, 8 to 27 percent
of the coating line emissions occur in the coater area and 73 to 92 percent are
from the oven. It has been suggested that as little as 20 percent of the
solvent is emitted in the oven. (In two-piece exterior coating lines, up to 88
percent of the emissions occur in the coater area before the can bodies enter
the oven.) The oven emissions are low in concentration of solvent per unit
of exhaust (most can coating ovens are designed to operate at 25 percent of
the lower explosive limit (LEL) and can be incinerated.
The spray coating of the side seams and can interior, end sealing, end
spraying or roll coating (exterior), coating storage, and cleaning operations,
are not considered in this document. Waterborne interior and end sealing
coatings are available for some applications. The contact between these
coatings and the canned product must be taken into account.
3.16.3 Control Measures
The two principal control measures utilized in the can industry coating
lines are low solvent coating materials and fume incinerators.
The two types of fume incinerators are thermal incinerators, operating in
the temperature range of 649° to 760°C (1200° to 1400°F), and catalytic
incinerators, operating in the temperature range of 343° to 510°C (650° to
950°F). Thermal incinerators operate typically at 90 percent efficiency of
hydrocarbon control (across the device) with reported values up to 98 per-
cent efficiency, dependent upon the specific installation and coating materials
being used. ' ' ' Catalytic incinerators have reported control efficiencies
(across the device) of 90 percent.
Fume incinerators have been used with coating materials and can coating
lines with high solvent to solids content ratios.
3.16-5
-------
If the coater area (the point of application of the coating material) were
enclosed and the emissions combined with those from the oven, a high per-
centage of the coating line emissions would be directed to the fume incin-
erator. This has reportedly been attempted at only one plant, because the
industry feels that enclosures hinder control and operation of the coaters.
Reduction of organic emissions from the point of application of the
coating material by the use of low solvent coatings (waterborne and/or high
solids) is 60 to 90 percent, dependent upon the particular type of coating line
and the solvent content of the coating materials that would otherwise be used.
The use of low solvent coating materials, as compared to high solvent coating
materials, eliminates some of the concern over controlling fugitive emissions.
Powder coating systems have limited potential application to exterior base
coats, interior body sprays, and overvarnish. They are essentially 100
percent solids and therefore produce no organic solvent emissions.
Waterborne coatings contain a polymer or resin base, water, an organic
cosolvent, and a solubilizing agent. The organic cosolvent improves stability
and flow-out, depresses foaming action, and controls the drying rate. High-
solids coatings, with 70 to 80 percent solids by weight, may be difficult to
apply because the material is highly viscous. A heating unit may be used to
raise the application temperature and thereby reduce viscosity. Powder
coatings require a different type of application equipment. Powder coating
technology has not yet been developed to the point that thin, continuous films
can be produced at high line speeds, as with solvent or waterborne coatings.
Although waterborne, high-solids, and powder coatings are comparable in
performance to solvent-borne coatings in some applications in the can industry,
they are not available to replace many of the present solvent-borne formu-
lations. Therefore, this control option is not universal. The availability of
low-solvent coatings should increase substantially in the next several years,
however. The can coating industry will require extensive testing of these
new coatings to determine their effects on the manufacturing and packaging
processes and on the canned product.
3.16-6
-------
Ultraviolet-curable inks are cured with a UV light source such as
mercury vapor lamps. Although these are totally organic, very little vapor-
ization occurs during the almost instantaneous curing. Therefore, UV-curing
can reduce VOC emissions by nearly 100 percent (there may be slight volatil-
ization of low-molecular-weight compounds). This technology is currently
limited to application of thin, semitransparent coating films and operations
that would normally reguire oven drying between applications of ink colors.
UV curing is being investigated for single-pass curing of base coat, inks,
and overvarnish coat for both sheet and two-piece beverage cans.
Inks reguiring no overvarnish are currently in use. These "No-Var"
inks are cured by exposure to ultraviolet light. When "No-Var" inks are
used, solvent emissions from overvarnish are eliminated and a great deal of
energy is saved in comparison to conventional oven curing of inks and over-
varnish .
3.16.4 Emission Limits
The initial criterion for defining LAER for a surface coating industry is
the degree of emission control required by the most stringent state regu-
lation .
Most organic solvent emission regulations are patterned after what is now
Rule 442 of the South Coast (California) Air Quality Management District.
Review of regulations applicable in the 16 states that contain about 85 percent
of all surface coating industries showed that they are essentially the same as
Rule 442.8 Indiana has the most stringent regulation, which limits organic
solvent emissions to 1.4 kg/h or 6.8 kg/day (3 Ib/h or 15 Ib/day) unless
such emissions are reduced by at least 85 percent, regardless of the reactiv
ity or temperature of the solvent. Organic solvents that have been deter-
mined to be photochemically unreactive or that contain less than specified
percentages of photochemically reactive organic materials are exempt from this
regulation.
California Air Resources Board has recently adopted a model rule for the
control of VOC emissions from can and coil coating operations. This model
rule, which must be met 3 years from the date of adoption, limits VOC
3.16-7
-------
emissions from 3-piece sheet base coating and overvarnish to 180 g solvent/
liter (1.5 Ib/gal) of coating minus water, and from 2-piece base coating and
overvarnish to 250 g solvent/ liter (2.1 Ib/gal) of coating minus water.
These limits can be achieved by the use of low solvent coatings or with
add-on control eguipment.
In defining LAER for surface coating emissions, it is not appropriate to
exempt solvents on the basis of their reactivity. Recent research has
indicated that substituting low-reactivity solvents for higher-reactivity
solvents may improve photochemical oxidant air quality in one city while
worsening it in downwind regions.1 Accordingly, EPA has adopted a policy
emphasizing the need for "positive reduction techniques" rather than sub-
stitution of compounds.
Emission controls achieved in practice for can coating exceed regulatory
requirements by a wide margin. Therefore, it is concluded that LAER for
can coating is a function of controls achieved in practice rather than controls
required by current regulations.
3.16.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/or modified in
1979 and 1980 and that appreciable new performance data will become available
in the near term. Conceivably, some SIP regulations may be more stringent
than the LAER suggested herein. Furthermore, performance testing may
show that more stringent limits than those suggested are feasible or it may
show that the suggested limits are appropriate or that they are not achievable
for some specific subcategories. In any case, the basis for determining LAER
for many source categories is expected to change frequently. Since LAER is
near the vanguard of control technology, a more detailed analysis is partic-
ularly necessary when addressing modified or reconstructed facilities subject
to the provisions of Section 173 of the Clean Air Act. Emission limitations
reasonable for new sources may in some instances be economically or tech-
nically unreasonable when applied to modified or reconstructed sources of the
same type.
3.16-8
-------
The lowest achievable emission rate for sheet facecoating and overvarnish
and two-piece can (exterior) basecoating and overvarnish is determined to be
a combination of limitations represented by RACT and emission reductions
achieved in practice. The LAER can be met by the use of waterborne coat
ings, which can achieve reductions of 88 to 92 percent. This is comparable
to the RACT limitation of 340 g solvent/liter Ib/gal) of coating minus water.
Similar reductions can be achieved by the use of other low-solvent coatings
(such as powder) or higher-solids coatings. The application of add-on
control devices capable of providing equivalent reductions is also an
acceptable way of meeting these limitations.
3.16-9
-------
REFERENCES
1. Control of Volatile Organic Emissions for Existing Station-
ary Sources. Volume II: Surface Coating of Cans, Coils,
Paper, Fabrics, Automobiles, and Light-duty Trucks.
EPA-450/2-77-008, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina. May 1977.
2. Listing of Surface Coating Industry Sources from National
Emission Data System (NEDS). Unpublished. U.S. Environ-
mental Protection Agency, Research Triangle Park, North
Carolina. February 1978.
3. Incinerator Efficiency Tests. (Confidential report provided
by can coating company.) May 1975.
4. Source Listed in State of Indiana Emission Inventory System
(EIS). Communication with M. Knudson, Indiana Air Pollution
Control Division. February 20, 1978.
5. Personal communication with J. Helgeson, Continental Can
Company, Portage, Indiana. February 20, 1978.
6. Levinson, S.B. Electrocoat, Powder Coat, Radiate. Which
and Why? Journal of Paint Technology. 44(570):42, July
1972.
7. Recommended Policy of Control of Volatile Organic Compounds.
U.S. Environmental Protection Agency. Federal Register (42
FR 131). July 8, 1977.
8. Source Assessments: Prioritization of Air Pollution From
Industrial Surface Coating Operations. EPA 650/2-75-0192.
U.S. Environmental Protection Agency. February 1975.
9. Pantalone, J.A., and L. Shepard. Consideration of Model
Rule for the Control of Volatile Organic Compound Emissions
From Can and Coil Coating Operations. Prepared for
California Air Resources Board. July 26, 1978.
10. Control Strategy Preparation Manual for Photochemical Oxi-
dant. OAQPS 1.2-047, U.S. Environmental Protection Agency.
Januarv 1977.
3.16-10
-------
3.17 MAJOR SOURCE CATEGORY: METAL COIL COATING—VOLATILE
ORGANIC COMPOUND (VOC) EMISSIONS.
3.17.1 Process Description
Coil coating is the coating of any flat metal sheet or strip
that comes in rolls or coils. The metal is typically roll
coated on one or both sides on a continuous production line. The
metal may also be printed or embossed. The coated metal is slit
and fabricated by drawing, stamping, roll forming, or other
shaping operations into finished products to be used for cans,
appliances, roof decks, shelving, industrial and residential
siding, cameras, culvert stock, cars, gutters, and many other
items.
On some lines, the metal is uncoiled at one end of the line
and recoiled at the opposite end. On other lines, called
"wraparound" lines, the metal is uncoiled and recoiled at about
the same point on the line. Some coil coating lines have a
single coater and one curing or baking oven; others, called
"tandem" lines, have several successive coaters, each of which is
followed by an oven so that several different coatings may be
applied in a single pass. Figure 3.17-1 is a schematic of a
tandem coil coating line.
The metal is moved through the line by power-driven rollers.
It is uncoiled as the process begins and goes through a splicer,
which joins one coil of metal to the end of another coil for
continuous, nonstop production. The metal is then accumulated so
that, during a splicing operation, the accumulator rollers can
descend to provide a continuous flow of metal throughout the
line. The metal is cleaned at temperatures of 49°C to 71°C
(120°F to 160°F), brushed, and rinsed to remove dirt, mill scale,
grease, and rust before coating begins. Pretreatments, varying
with the type of metal being coated and the type of coating being
applied, are then applied to the metal to protect against cor-
rosion and provide proper coating adhesion.
3.17-1
-------
aCCUWVlATOM
ACCUMUIATON
MME
COATEM
METAL CLEAHINB
M
IETMEATMEI
T
D
MME
OVEN
PRME
OUENCM
3
SHEAR
D
TOTCOAT
COATED
TOPCOAT
TOPCOAT
QUENCH
U u
MECOIlflIC
METAL
Figure 3.17-1. Diagram of coil coating line.
-------
The first or prime coat may be applied on one or both sides
of the metal by a set of three or more power-driven rollers. The
pickup roll, partially immersed in the coating, transfers the
coating to the applicator roll. The metal is coated, typically
in a reverse roll fashion, as it passes between the applicator
roll and the large backup roll. A third roll, called a "doctor"
roll, may be used to control film thickness when applying a high
viscosity coating by making contact with the pickup roll.
The applied coating is usually dried or baked in a con-
tinuous, multizone, high production catenary, flotation, or
double-pass oven. The temperatures of the preheat, drying, or
baking zones may range from 38°C to 538°C (100°F to 1000°F)
depending on the type and film thickness of coating used and the
type of metal being coated. The flow rates of exhaust from the
3 3
ovens range from approximately 1.9 Nm /s to 12.3 Nm /s (4000 scfm
to 26,000 scfm). Many of these ovens are designed for operation
at 25 percent of the room-temperature lower explosive level when
coating at rated solvent input. As the metal exits the oven, it
is cooled in a quench chamber by a spray of water or a blast of
air and then is water-cooled.
A second coat or topcoat may be applied and cured in a
manner similar to the prime coat. The topcoat oven, however, is
usually longer than the prime coat oven and contains more zones.
Another method of applying a prime coat on aluminum coils or
a single coat on steel coils is to electrodeposit a waterborne
coating to one or both sides of the coil. The coil enters a
V-shaped electrocoating bath that contains a roll on the bottom.
As the metal goes around the roll, electrodes on each side can be
activated to permit coagulation of the paint particles on one or
both surfaces of the coil. The coated coil is then rinsed and
wiped by squeegees to remove the water and excess paint parti-
cles. With steel coils, the electrodeposited coating must be
baked in an oven. With aluminum coils, however, the prime coat
is stable enough that the metal can be passed immediately over
3.17-3
-------
rolls to the topcoat coater without destroying the finish and
then can be baked as a two-coat system.
After cooling, the coated metal passes through another
accumulator, is sheared at the spliced section, waxed, and
finally recoiled. The accumulator rolls rise during the shearing
process, collecting the coated metal to ensure continuous pro-
duction.
3.17.2 Emissions of Pollutants
Emissions from a coil coating line come from the coating
area, the preheat and baking zones of the oven, and the quench
area. These emissions are mainly volatile organics and other
compounds, such as aldehydes, that result from thermal degra-
dation of volatile organics. Emissions from the combustion of
natural, gas, the fuel used most commonly to heat the ovens, are
carbon monoxide, unburried fuel, nitrogen oxides, and aldehydes.
When fuel oil is used to heat the ovens, sulfur oxides and
greater quantities of nitrogen oxides and particulates will be
emitted.
Of the uncontrolled organic vapors emitted from the coil
coating line, the oven emits approximately 90 percent, the coater
area approximately 8 percent, and the quench area the remaining 2
percent. Only these organic vapors are of concern in this docu-
2 3
ment.z'J
3.17.3 Control Measures
Three types of control measures have been widely applied to
coil coating operations: thermal incineration, catalytic in-
cineration, and reformulation from solvent-based to water-based
or high-solids coatings.
Thermal incinerators, successfully used in many coil coating
facilities, have achieved organic emission reduction efficiencies
of 90 to 99 percent, depending on the specific operation. ' The
3.17-4
-------
overall plant reduction in emissions depends on the VOC capture
efficiency at the coating application area. The coating area can
be enclosed, and essentially all of the organic vapors can be
captured and vented to the incinerator. As a minimum, 96 percent
of the vapors from the coating line should be subject to collec-
tion—100 percent of oven emissions plus 60 percent of emissions
from the coater and quench areas. Table 3.17-1 presents typical
emissions based on assumed control efficiencies for various coil
coating operations.
Many coil coating facilities are currently using catalytic
incinerators to reduce organic emissions and are achieving re-
duction efficiencies of 85 to 95 percent, depending on the
4 5
specific operation. '
Reformulation of coatings is from organic solvents to
waterborne or high-solids coatings. Waterborne coatings have
been successfully applied, within limits, to several coating
lines and have reduced organic emissions by 70 to 95 percent,
depending on the processes and the solvent level of the original
solvent-borne coating. ' High-solids coatings have only re-
cently seen significant use in the coil coating industry, but
progress is being made in commercializing coatings with medium-
high to high-solids content. Table 3.17-2 lists the potential
percentage reduction, in pounds of organic solvent per unit
volume of coating, that can be realized by converting to water-
borne and high-solids coatings.
The options, however, are limited. There is a lack of
waterborne and high-solids coatings equivalent to organic-
solvent-borne coatings for many applications, especially where
resistance to corrosion or wear is critical, or where forming
operations are severe. Some coatings used in the industry can
poison incinerator catalysts. Incineration, especially non-
catalytic, will increase the use of natural gas or other fuels if
no nearby operations can use the recovered energy. This latter
3.17-5
-------
U)
-J
I
en
TABLE 3.17-1. EMISSIONS FROM COIL COATING OPERATIONS
4
[Emission rates in kg/h (lb/h)]
Type of operation
Duct work
Canopies and
awning
Fencing
Screening
Gutters
Metal doors, exclud-
ing garage doors
Typical
uncontrolled
145.6
(320.6)
83.99
(185.0)
29.5
(64.9)
20.6
(45.4)
12.9
(28.5)
7.63
(16.8)
Incineration
1.5
(3.2
0.86
(1.9
0.32
(0.7
0.23
(0.5
0.14
(0.3
0.091
(0.2
-14.6
- 32.1)
- 8.40
- 18.5)
- 2.9
- 6.5)
- 2.0
- 4.5)
- 1.3
- 2.9)
- 0.77
- 1-7)
Controlled
catalytic,
combustion
7.3 - 21.8
(16.0 - 48.1)
4.2 - 12.6
(9.3 - 27.8)
1.5 - 4.4
(3.2 - 9.7)
1.0 - 3.1
(2.3 - 6.8)
0.6 - 2.0
(1.4 - 4.3)
0.4 - 1.1
(0.8 - 2.5)
Based on 90 to 99 percent control.
Based on 85 to 95 percent control.
-------
TABLE 3.17-2. POTENTIAL REDUCTIONS FROM USE,OF
WATERBORNE AND HIGH-SOLIDS COIL COATINGS
Coating
formulation,
by volume
Waterborne
32% solids
54.4% water
13.6% organic
solvents
Organic
solvent-borne
20% solids
80% solvent
50% solids
50% solvent
70% solids
30% solvent
kg of organic
splvent per
m of coating
minus water
264
708
444
264
(Pounds of organic
solvent per gallon
of coating minus
water)
(2.2)
(5.9)
(3.7)
(2.2)
Potential reduction
by using waterborne
coatings, %
90
58
0
-------
limitation has been overcome through the use of total energy
, . 6,8,10
recycling.
3.17.4 Emission Limits
The initial criterion for defining LAER for a surface coat-
ing industry is the degree of emission control required by the
most stringent regulation adopted and successfully enforced by a
state or local air pollution control agency.
As reported elsewhere, most regulations of organic solvent
emissions are patterned after what is now Rule 442 of the South
Coast (California) Air Quality Management District. Review of
regulations in the 16 states that contain about 85 percent of all
surface coating industries showed them to be essentially the same
as Rule 442.12 Indiana has the most stringent regulation in that
it limits organic solvent emissions to 1.4 kg/h or 6.8 kg/day (3
Ib/h or 15 Ib/day) unless such emissions are reduced by at least
85 percent, regardless of the reactivity or temperature of the
solvent. Organic solvents that have been determined to be photo-
chemically unreactive or that contain less than specified per-
centages of photochemically reactive organic materials are exempt
from this regulation.
California Air Resources Board has recently adopted a model
rule for the control of VOC emissions from can and coil coating
operations.13 This model rule, which must be met 3 years from
the date of adoption, limits VOC emissions from the coil prime
and topcoating or single coating line to 120 g solvent/liter (1.0
Ib/gal) of coating minus water through the use of add-on control
equipment, unless the solvent content of the coating used is no
more than 200 g/liter (1.7 Ib/gal) of coating minus water.
In defining LAER for surface coating emissions, it is not
appropriate to exempt solvents on the basis of reactivity.
Recent research has indicated that substituting low-reactivity
solvents for higher-reactivity solvents may improve photochemical
3.17-8
-------
oxidant air quality in one city while worsening it in downwind regions.
Accordingly, EPA has adopted a policy emphasizing the need for "positive
reduction techniques" rather than substitution of compounds.11
Emission controls achieved in practice for metal coil coating exceed
regulatory requirements by a wide margin. Therefore, it is concluded that
the LAER for metal coil coating is a function of controls achieved in practice
rather than controls required by existing regulations.
3.17.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/ or modified
in 1979 and 1980 and tht appreciable new performance data will become
available in the near term. Conceivably, some SIP regulations may be more
stringent than the LAER suggested herein. Furthermore, performance testing
may show that more stringent limits than those suggested are feasible or it
may show that the suggested limits are appropriate or that they are not
achievable for some specific subcategories. In any case, the basis for
determining LAER for many source categories is expected to change frequen-
tly. Since LAER is near the vanguard of control technology, a more detailed
analysis is particularly necessary when addressing modified or reconstructed
facilities subject to the provisions of Section 173 of the Clean Air Act.
Emission limitations reasonable for new sources may in some instances be
economically or technically unreasonable when applied to modified or recon-
structed sources of the same type.
Incineration efficiencies of 98 to 99 percent have been documented and
are attainable for coil coating operations where thermal incinerators (after-
r- Q v
burners) are used. ' Incineration efficiencies of 95 percent have been
attained for operations utilizing catalytic incineration. As discussed earlier,
overall control efficiency also depends on VOC collection efficiency. All of
the oven exhaust can be directly vented to the control device, and if the
coating area is enclosed, essentially all of the VOC emissions from this facility
can also be captured for incineration. Switching to waterborne or highsolids
3.17-9
-------
coatings will eliminate some of the concern over collection of solvent emissions
since the organic content is substantially reduced. The derivation of an
equivalent waterborne coating followings:
Overall control = 96% collection, 97% reduction
= 93%
Assuming a typical coating contains 25 percent solids,
100 gallons of coating contains 25 gallons solids
75 gallons solvent
Reducing the solvent by 93% = (75) - [0.93 (75)] =5.3
gallons of solvent allowed
Assuming a solvent density of 7.36 Ib/gallon, 5.3 gallons =
39 Ibs of solvent.
Equivalent coating required = 39 Ib of solvent/(25 + 5.3)
gallons coating munus water
= 1.3 Ib of solvent/gallon
coating minus water
= 155 g of solvent/liter
coating minus water
The best controlled systems consist of an enclosed coating area and a
thermal incinerator. The use of a heat recovery system on this type of
operation has the additional capability of actually reducing the fuel usage in
the plant up to 87 percent.6 Therefore, it may be concluded that the lowest
achievable emission rate for a coil coating line (coating application area and
oven) is an efficient VOC collection scheme in conjunction with a 97 to 99
percent reduction in emissions, or use of the equivalent low-solvent coating.
3.17-10
-------
REFERENCES
1. Much of the material that follows is extracted almost
directly from: Control of Volatile Organic Emissions from
Existing Stationary Sources. Volume II: Surface Coating of
Cans, Coils, Papers, Fabrics, Automobiles, and Light-Duty
Trucks. U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina. Publication Number EPA
450/2-77-008. May 1977.
2. Cosden, W.B. The Ecology of Coil Coating, Metal Finishing.
November 1974. p. 55-58.
3. A Study of Gaseous Emissions from the Coil Coating Process
and Their Control. Scott Research Laboratories,
Plumsteadvilie, Pennsylvania. (Prepared for the National
Coil Coaters Association. October 1971.)
4. Hughes, T.W., D.A. Horn, C.W. Sandy, and R.W. Serth. Source
Assessment: Prioritization of Air Pollution from Industrial
Coating Operations. Monsanto Research Corporation, Dayton,
Ohio. Prepared for U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina. Publication Number
EPA 650/2-75-019. February 1975.
5. Telephone conversation with Dr. F. Graziano, Pre-Finished
Metals, Incorporated, Elk Grove, Illinois. January 23,
1978.
6. E.J. Kurie, Manager, Ross Air System Division, Midland Ross
Corporation, New Brunswick, New Jersey. INERTAIR Drying
Dramatically Reduces Fuel Consumption on Coil Coating Line.
(Prepared for National Coil Coaters Association Fall Tech-
nical Meeting. Chicago, Illinois. October 1977.)
7. E.J. Vincent, et al. Are Afterburners Obsolete? (Presented
at Air Pollution Control Equipment Seminar, APCA/National
Association of Corrosion Engineers. Atlanta, Georgia
January 17-19, 1978.)
8. W. Parsons, Project Engineer, Inyrco, Incorporated,
Milwaukee, Wisconsin. Thermal Oxidation System Actually
Saves Energy for Coil Coater. Reprint, Pollution Engineer-
ing. May 1977.
3.17-11
-------
9. Telephone conversation with J.C. Magdich, Plant Engineer,
Kaiser Aluminum and Chemical Corporation, Toledo, Ohio.
January 25, 1978.
10. Telephone conversation with W.B. Cosden, Vice-President,
National Coil Coaters Association, PPG, Incorporated,
Beverly, New Jersey. January 30, 1978.
11. Recommended Policy on Control of Volatile Organic Compounds.
U.S. Environmental Protection Agency. Federal Register July
8, 1977 (42 FR 131).
12. Data on the geographical distribution of surface coating
industries can be found in: Source Assessments: Prioriti-
zation of Air Pollution from Industrial Surface Coating
Operations. U.S. Environmental Protection Agency. Publi-
cation Number EPA 650/2-75-0192. February 1975.
13. A series of documents which are referenced and summarized
in: Control Strategy Preparation Manual for Photochemical
Oxidant. U.S. Environmental Protection Agency. Publication
Dumber OAQPS 1.2-047. January 1977.
3.17-12
-------
3.18 MAJOR SOURCE CATEGORY: PAPER COATING— VOLATILE ORGANIC
COMPOUND (VOC) EMISSIONS
3.18.1 Process Description
Paper is coated for a variety of decorative and functional
purposes by applying waterborne, organic-solvent-borne, or sol-
ventless extrusion materials. Products with coatings that
incorporate organic solvents include adhesive tapes and labels,
decorated paper, waxed paper, book covers, office paper, carbon
paper, typewriter ribbons, and photographic films.
Figure 3.18-1 shows a typical paper coating line. Com-
ponents include an unwind roll, a coating applicator, an oven,
various tension and chill rolls, and a rewind roll. Coatings may
be applied to paper in several ways. The main applicators are
knives, reverse rollers, or rotogravure devices. A knife coater
consists of a blade that scrapes excess coating from the paper,
as shown in Figure 3.18-2. The position of the knife can be
adjusted to control the thickness of the coating. The reverse
roll coater applies a constant thickness of coating to the paper,
usually by means of three rollers, each rotating in the same
direction, as shown in Figure 3.18-3. A transfer roll picks up
the coating solution from a trough and transfers it to a coating
roll. A "doctor" roll removes excess material from the coating
roll, thereby determining the thickness of the coating. A rubber
backing roll supports the paper web at the point of contact with
the coating roll, which is rotating in a direction opposite to
that of the paper. Rotogravure is usually considered a printing
process—the coating is picked up in a recessed area of the roll
and transferred directly to the substrate.
Ovens range from 6.1 to 61 m (20 to 200 ft) in length and
may be divided into two to five temperature zones. The first
zone, where most of the solvent is evaporated, is usually at a
low temperature 43.3°C (£llO°F). Other zones are maintained at
progressively higher temperatures to cure the coating after most
3.18-1
-------
ZONE1
EXHAUST
ZONE 2
EXHAUST
CO
I
HEATED AIR
FROM BURNER
REVERSE ROLL
COATER
UNWIND
\
^ — , _ .
•^^1 1
-*"O O
| If 1 1 -
0 0
OVEN
HOT AIR NOZZLES
TENSION ROLLS
REWIND
Figure 3.18-1. Typical paper coating line.
-------
EXCESS COATING
BLADE COATED WEB
PAPER WEB
Figure J.18-2. Knife application technique for coating paper,
DOCTOR ROLL
METERING GAP
TRANSFER ROLL
COATED PAPER WEB
BACKING ROLL
COATING RESERVOIR
Figure 3.18-3. Reverse roll application technique for coating paper,
3.18-3
-------
of the solvent has evaporated. Exhaust streams from different
zones may be discharged independently or collected in a common
header in front of the air pollution control device. The average
exhaust temperature is about 93.3°C (200°F).
3.18.2 Emissions of Pollutants
Many different organic solvents are used, including toluene,
xylene, methyl ethyl ketone, isopropyl alcohol, methanol, ace-
tone, and ethanol. Solvent emissions from an individual coating
plant vary with the size and number of coating lines. In a
typical paper coating plant, about 70 percent of all solvents
used are emitted from the coating line. Uncontrolled emissions
from a single line may vary from 2.3 to 454 kg/h (50 to 1000
Ib/h), depending on the line size. A coating line consists of a
coatir" applicator and a drying oven, the two significant emit-
ting facilities.
The remaining 30 percent of plant emissions are from sources
such as solvent transfer, storage, and mixing operations.
3.18.3 Control Measures
Reductions in solvent emissions of 80 to 99 percent are
achievable by use of low-solvent coatings, as shown in Table
3.18-1. These coatings form organic resin films with properties
equal to those of typical solvent-borne coatings. Waterborne
coatings are two-phase systems in which water is the continuous
phase and a polymer resin is the dispersed, phase. When the water
is evaporated, the polymer coating is cured and forms a film with
properties similar to those of organic-solvent-borne coatings.
Plastisols usually contain little or no solvent, although solvent
is occasionally added to improve flow characteristics. Hot-melt
coatings contain no solvent. The polymer resins are applied to
the paper surface in a molten state, and all materials deposited
on the paper remain as part of the coating. A plastic extrusion
3.18-4
-------
TABLE 3.18-1. SOLVENT EMISSION REDUCTIONS ACHIEVABLE BY USE
OF LOW-SOLVENT COATINGS IN THE PAPER COATING INDUSTRY
Type of low-solvent coating
Reduction achievable, %c
Waterborne coatings
Plastisols
Extrusion coatings
Hot-melts
Pressure-sensitive adhesives
Hot-melt
Waterborne
Prepolymer
Silicone release agents
Waterborne emulsions
100 percent nonvolatile coatings
80-99
95-99
99+
99+
99
80-99
99
80-99
99+
Based on comparison with a conventional coating containing
35 percent solids by volume and 65 percent organic solvent
by volume.
3.18-5
-------
coating is a type of hot-melt coating in which a molten thermo-
plastic sheet is discharged from a slotted dye onto a paper
substrate. The moving substrate and molten plastic are combined
in a nip between a rubber roll and a chill roll. Prepolymer
adhesive coatings are applied as a liquid composed of monomers
containing no solvent. The monomers are polymerized by either
heat or radiation. Although these prepolymer systems show prom-
ise, they are only in a developmental stage.
Carbon adsorption systems can be 97 to 98 percent efficient
in controlling organic solvent vapors that are drawn into the
carbon bed.2'3 Carbon adsorption has been used since the 1930's
for collecting solvents emitted from paper coating operations,
mainly because it is profitable to reclaim the emitted solvent.
The efficiency of control equipment operation depends largely on
inlet solvent concentration; with an inlet concentration of 1000
ppm toluene, the achievable control efficiency is 97 percent,
whereas with an inlet concentration of 3000 ppm it is practicable
to achieve control efficiencies of 98 percent.2 These control
efficiencies pertain to the control equipment only and do not
reflect the efficiency of solvent capture and emission delivery
to the control device. Essentially all of the emissions from
this area can be captured with hoods. Solvent recovery in the
range of 96 percent of the solvent introduced to the coating line
14
has been demonstrated. '
Thermal incinerators may be used to control organic vapors.
Catalytic incinerators have rarely been applied in paper coating
operations using roll or knife coaters, but certainly are appli-
cable. Incinerators operating at high temperatures can be up to
99 percent efficient in controlling organic vapors directed to
the incinerator.5 Although no documentation has been acquired,
industry sources have stated that high efficiencies (98 to 99
percent across the device) are achievable by use of an after-
burner in a paper coating plant. Overall facility control would
be less because of emissions that escape capture.
3.18-6
-------
Incinerators and carbon adsorbers are the two proven add-on
control devices for controlling organic solvent emissions from
paper coating lines. Both have been retrofitted onto paper
coating lines and are being operated successfully. The main
constraint on the use of incinerators is the possible shortage of
natural gas. Often the combination of afterburner and oven,
however, uses no more fuel than the oven alone, with proper heat
/?
recovery. The major disadvantage of carbon adsorption is that
some solvent mixtures may not be economically recoverable in
usable form. If the solvent can be recovered for reuse, carbon
adsorption represents an economic advantage.
Control of solvent emissions from such sources as transfer,
storage, and mixing operations requires that solvent-containing
vessels be equipped with tight-fitting covers that are kept
closed. Areas frequently cleaned with solvent should be equipped
with hoods to capture solvent fumes, which are then ducted to a
control device. Sol vent-soaked rags should be kept in closed
containers.
3.18.4 Emission Limits
Initial criterion for defining lowest achievable emission
rate (LAER) for a surface coating industry is the degree of
emission control required by the most stringent regulation adop-
ted and successfully enforced by a state or local air pollution
control agency.
As reported elsewhere, most organic solvent emission regu-
lations are patterned after what is now Rule 442 of the South
Coast (California) Air Quality Management District.7 Review of
regulations applicable in the 16 states that contain about 85
percent of all surface coating industries showed them to be
o
essentially the same as Rule 442. Indiana has the most strin-
gent regulation in that it limits organic solvent emissions to
1.4 kg/h (3 Ib/h) or 6.8 kg/day (15 Ib/day) unless such emissions
are reduced by at least 85 percent, regardless of the reactivity
3.18-7
-------
or temperature of the solvent. Organic solvents that have been determined to
be photochemically unreactive or that contain less than specified percentages
of photochemically reactive organic materials are exempt from this regulation.
California Air Resources Board has recently adopted a model rule for the
control of VOC emissions from paper and fabric coating operations. This
model rule, which must be met 3 years from the date of adoption, limits VOC
emissions from the coating line to 120 g solvent/liter (1.0 Ib/gal) of coating
minus water through the use of add-on control equipment, unless the solvent
content of the coating used is no more than 265 g/liter (2.2 Ib/gal) of coating
minus water.
In defining LAER for surface coating emissions, it is not appropriate to
exempt solvents on the basis of their reactivity. Recent research has
indicated that substituting low reactivity solvents for higher reactivity
solvents may improve photochemical oxidant air quality in one city while
worse^ng it in downwind regions.10 Accordingly, EPA has adopted a policy
emphasizing the need for "positive reduction techniques" rather than substi-
tution of compounds.
Emission controls achieved in practice for paper coating exceed regula-
tory requirements by a wide margin. Therefore, it is concluded that LAER
for paper coating is a function of controls achieved in practice rather than
controls required by existing regulations.
3.18.5 Determination of LAER
The recommended limitations are based on SIP's and on performance
information available in early 1979. It is anticipated that several additional
SIP regulations covering these sources will be promulgated and/ or modified
in 1979 and 1980 and tht appreciable new performance data will become
available in the near term. Conceivably, some SIP regulations may be more
stringent than the LAER suggested herein. Furthermore, performance testing
may show that more stringent limits than those suggested are feasible or it
may show that the suggested limits are appropriate or that they are not
achievable for some specific subcategories. In any case, the basis for deter-
mining LAER for many source categories is expected to change frequently.
3.18-8
-------
Since LAER is near the vanguard of control technology, a more detailed
analysis is particularly necessary when addressing modified or reconstructed
facilities subject to the provisions of Section 173 of the Clean Air Act.
Emission limitations reasonable for new sources may in some instances be
economically or technically unreasonable when applied to modified or recon-
structed sources of the same type.
Control efficiencies of greater than 95 percent across-the-control device
have been documented and are achievable for paper coating operations in
which thermal or catalytic incineration or carbon adsorption systems are
>2 O C
used. ' ' A paper coating operation can deliver at least 90 percent of the
VOC emissions to a control device that yields an overall control efficiency of
85 percent; this is equivalent to the uncontrolled emissions from a low-sol vent
coating containing 310 g of solvent/liter (2.6 Ib/gal) of coating minus water.
This derivation is shown in the following calculation:
Assuming a typical coating contains 22 percent solids,
100 gal of coating contains 22 gal solids
78 gal solvent
Reducing the solvent emitted yields: (78) - [0.85 (78)] =
11.7 gal permitted
Assuming a solvent density of 7.36 Ib/gal, 11.7 gal =
86.1 Ib solvent
Equivalent coating required = 86.1 Ib solvent/(22 + 11.7)
gal of coating minus water
= 2.6 Ib solvent/gal coating
minus water
= 310 g solvent/liter coating
minus water
Although conversion to a waterborne or higher-solids coating will
significantly reduce VOC emissions, it may not achieve the 310 g/liter (2.6
Ib/gal) limitation, in which case control of part of the VOC emission is still
recommended. Control of VOC emissions using add-on control devices
providing at least 85 percent overall plant control is also acceptable.
3.18-9
-------
REFERENCES
1. Control of Volatile Organic Emissions for Existing Station-
ary Sources, Volume II: Surface Coating of Cans, Coils,
Paper, Fabrics, Automobiles, and Light-Duty Trucks.
EPA-450/2-77-008, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina. May 1977.
2. Personal communication with W. C. Moses. Technical Manager,
Chemical Plant Division, Sutcliffe, Speakman & Company,
Limited. March 10, 1978.
3. Taback, H. J., et al. Control of Hydrocarbon Emissions from
Stationary Sources in the California South Coast Air Basin.
Prepared for California Air Resources Board, KVB Interim
Report 5804-714, KVB Consultants, Tustin, California.
November 1976.
4. Personal communication with S. Bruntz. Division of Air
Pollution, Kentucky Department of Environmental Protection.
March 1, 1978.
5. E. J. Vincent, et al. Are Afterburners Obsolete? Presented
at Air Pollution Control Equipment Seminar, APCA/National
Association of Corrosion Engineers, Atlanta, Georgia.
January 17-19, 1978.
6. Young, R.A. (ed.). Heat Recovery: Pays for Air Incinera-
tion and Process Drying. Pollution Engineering, 7^:60-61.
September 1975.
7. Recommended Policy on Control of Volatile Organic Compounds.
Federal Register, 42 FR 131, U.S. Environmental Protection
Agency. July 8, 1977.
8. Source Assessments: Prioritization of Air Pollution from
Industrial Surface Coating Operations. EPA 650/2-75-0192,
U.S. Environmental Protection Agency. February 1975.
9. Lam, J. V., et al. Consideration of a Proposed Model Rule
for the Control of Volatile Organic Compounds from Paper and
Fabric Coating Operations. Prepared for California Air
Resources Board, Sacramento, California. August 23, 1978.
3.18-10
-------
10. Control Strategy Preparation Manual for Photochemical Oxi-
dant. OAQPS 1.2-047, U.S. Environmental Protection Agency.
January 1977.
11. Recommendation by U.S. Environmental Protection Agency,
ESED. Raleigh-Durham, North Carolina. August 8, 1978.
3.18-11
-------
-------
SECTION 4
COST ESTIMATING METHODOLOGY
4.1 INTRODUCTION
4.1.1 Purpose
The purpose of this chapter is to provide air pollution
control officials and industry personnel with a method of esti-
mating preliminary costs of air pollution control measures. The
method presented herein should provide estimates accurate to
within + 20 to 30 percent for specific cases when adequate data
are available.
4.1.2 Scope
A methodology for developing total installed capital cost
estimates and total annualized cost estimates is presented. This
is a generalized approach; specific process or equipment costs
are not included herein. Emphasis is on costs of add-on control
systems; however, by following the general procedure and basic
principles, costs can be developed for process modifications and
material or fuel substitution.
Design parameters and other factors affecting the overall
cost of installing and operating control systems are discussed.
Capital costs may be estimated for both new plants and retrofit
situations. Annualized cost components are separately computed
as operating costs, maintenance costs, capital charges, and
product and energy recovery credits. Secondary environmental
costs for wastewater and solid waste treatment and disposal can
also be developed. An example of a cost estimation for a control
system is presented, and forms are provided for actual cost
estimation.
4-1
-------
4.2 FACTORS AFFECTING THE COST OF EMISSION CONTROL
The major gas stream characteristics affecting costs and
selection of equipment are the exhaust volume, pressure, temper-
ature, moisture content, and corrosiveness. Accurate data are
necessary for accurate cost estimation. Variations of these
parameters, especially exhaust volume, must be studied and con-
sidered in the control design. Fluctuation in gas flow rates
affect the performance of some control devices more than others.
Gas conditioning equipment such as precleaners, cooling chambers,
and humidifiers are required for some control options. Certain
gaseous components in the gas stream, especially oxides of sul-
fur, require that corrosion-resistant materials be used in the
control system.
The physical properties of the pollutant and the gas stream
affect the control system design and hence the cost. These
properties include particle size, pollutant concentration, elec-
trical properties of the particles, and moisture content of the
gas stream. Accurate data on only the basic variables, however,
will enable manufacturers or suppliers to furnish costs that can
be used to develop preliminary estimates of capital costs.
Process operating methods and cycles necessarily influence
system design, which may affect overall costs. Age, type, and
size of facility; availability of space for locating the control
device; and ease of retrofitting existing facilities all affect
system selection and ultimate costs.
Plant parameters such as the requirements for an availabil-
ity of utilities and wastewater and solid waste treatment/dis-
posal facilities affect the design and cost of a control system.
Plant location, local climate, geography, and demography may
determine more stringent emission limitations.
4-2
-------
4.3 CAPITAL COST ESTIMATES
Total capital costs include equipment costs, direct capital
costs, indirect capital costs, and contingencies. The cost
estimate for a complete system will include the cost of the
control device and auxiliary equipment such as fans, pumps, and
duct work. Capital costs associated with wastewater and solid
waste treatment/disposal facilities can also be estimated.
4.3.1 Limitations, Restrictions, and Uncertainties
The accuracy of a cost estimate for an APC system may vary
from + 20 to 30 percent (when based on preliminary design of
major equipment) to + 5 percent (when prepared from complete
drawings, specifications, and site surveys). The procedure
outlined in this section will provide predesign estimates accu-
rate to within + 20 to 30 percent of actual costs if sufficient
exhaust gas, emission, and operating data are available.
The use of direct cost factors without giving proper con-
sideration of their applicability to site specifics lends un-
certainty to the final estimates. The factors represent the
average or typical installation, and these factors will vary with
individual installations. Because 10 to 15 equipment items may
be involved in a total cost estimate, however, the errors will
tend to average out. The use of other factors such as material
cost factors, cost-scaling exponents, and cost indices will add
to the error and uncertainty of cost estimates.
4.3.1.1 Retrofitted Systems—
Because retrofitted control systems may cost considerably
more (or sometimes less) than a complete system incorporated into
the design of a new plant, the effect of retrofitted systems must
be considered. This requires site-specific considerations such
as existing duct work, physical obstruction, and process equip-
ment configurations. The cost estimating procedure assumes that
4-3
-------
actual retrofitting requirements are known for the sources for
which costs are being developed.
4.3.1.2 Process Modifications and Fuel/Material Substitution--
In some cases a process modification and/or fuel or material
substitution is necessary to reduce emissions to a desired level.
Examples of such process changes include combustion modification
to control NO emissions from power boilers; the substitution of
ultraviolet dryers for hot-air dryers to eliminate VOC emissions
from printing operations; or the conversion of dry rock grinding
to wet rock grinding to eliminate particulate emissions.
The cost methodology does not specifically give direct
information required tc estimate costs of process modifications.
By following the general procedures, however, estimates can be
developed. For example, the —ices for major equipment are
obtained and cost factors are "-pplied in the same way as cost
factors for add-on control devices.
4.3.2 Capital Cost Components
Total installed cost, or total capital investment, is
developed from the base purchase prices of equipment items by
multiplying the unit costs by individual direct labor and mate-
rial cost factors and by indirect cost factors.
4.3.2.1 Equipment Cost—
Sources of cost information—An index to industrial equip-
ment and manufacturers ~an be consulted to obtain companies and
contacts for acquiring cost information on each individual
component. Chemical Engineering Equipment Buyers' Guide and
other indexes, advertisements in technical journals, and the
yellow pages in telephone books provide an excellent means of
locating sales representatives. Capital and Operating Costs
of Selected Air Pollution Control Systems, (EPA-450/3-76-014, May
1976)2 is an excellent publication source of equipment costF.
4-4
-------
Past purchase orders are also useful in determining equip-
ment costs, even though they do not readily provide exact equip-
ment size and current costs. Cost indexes and cost scaling
methods can be used to determine proper costs.
A third source of cost information is actual or model cost
studies for similar processes given in technical journals, trade
publications, EPA documents, etc. The disadvantage of using
these sources is that they are sometimes general in their treat-
ment of processes and control systems. Many times, however, this
can be a reasonable method of estimating costs, with some adjust-
ment of the data.
Cost indexes—Since prices and labor costs vary widely from
one time period to another, cost indexes are used to update
equipment costs from those indicated in a previous year. One
source of data on wage and price fluctuations is the Monthly
Labor Review published by U.S. Bureau of Labor Statistics. The
Chemical Engineering plant index (CE Index) is frequently used to
extrapolate entire system costs to current or future dollars, and
the Marshall and Stevens (M&S) Equipment Index can be used for
specific equipment items. Table A-l in Appendix A presents
suitable cost indexes for various types of equipment. Figure 4-1
shows the trend of plant costs and construction labor cost
indexes from 1957 through 1977.
EXAMPLE: The purchase price of a 500-hp fan was $20,000 in
1962. The price of the same fan in 1975 would be estimated by
multiplying the 1962 price by the ratio of 1975 Fabricated
Equipment Cost Index in Appendix A to the 1962 index as follows:
(1975 price) = (1962 price) (^5 index}
$20,000 x
$38,000
4-5
-------
t/*>
o
57 58 59 60
76 77
Figure 4-1.
Chemical Engineering plant cost and construction labor index.
(Information obtained from Reference 2.)
-------
Scaling exponents — When the purchase price is available on
an identical type of equipment of a different size, scaling
exponents can be used to adjust the price to apply to equipment
of the desired size or capacity. Tables 4-1, 4-2, and 4-3 pre-
sent scaling exponents found in or derived from various cost
sources. Size/price relationships are generally exponential and
follow the equation:
CA x
P = P (— — }
A rB
-------
TABLE 4-1. COST FACTORS AND SCALING EXPONENTS FOR AIR POLLUTION CONTROL DEVICES
I
oo
Control device
Fabric filter
Electrostatic precipitator
Wet collector
Cyclones
Absorption units
Carbon adsorber
Catalytic incinerator
Thermal incinerator
with heat exchanger
without heat exchanger
Condensers
Direct cost
factor3
2.0
2.0
3,0
1.7f
3.0
1.6d
1.6
1.6
1.6
3.0
Stainless ,
steel factor
1.5d
2.4
2.4e
?.0e
2.5g
2.5h
Scaling exponents0
Unit
ft2 cloth
ft2 plate
acfm
acfm
acfm
Ib carbon
acfm
acfm
acfm
acfm
Exponent
0.95
0.37
0.70
0.80f
0.62g
0.90d
0.60
0.70
0. 4-0. 5
0.70g
Consi dpr<=-d an approximate average; cost factors could vary by up to + 40 to 50 percent or
more in some cases. Includes equipment, material and labor costs. Does not include indirect
cost. Developed from PEDCo experience unless otherwise noted.
Suitable for approximation of 304 or 316 type stainless steel.
To escalate cost of a similar unit of a different size.
Reference 2.
Reference 3.
Reference 4.
Reference 5.
Reference 1.
-------
s 4-2.
COST FACTORS AND SCALING EXPONENTS FOR AUXILIARY EQUIPMENT ITEMS
Equipment item
Fan system
Pump system g
Reciprocating
Centrifugal
e
Drivers
e
Chemical injection
Heat exchanger (S/T)
Air cooler
Quench tower
Spray chamber
Reheater
Ductwork
Exhaust stack
e
Hoppers
Transformers
Screw conveyors
Direct cost
factor3
2.0
2.4
2.4
2 A
. *4
1.6
2.3
1.6
3.0
2.5
3.5
2.6
1.5
11
. 1
1.2
1.6e
Stainless b
steel factor
2.8d
2.4
2.0
2.0
CS/SS 2.5
SS/SS 3.1
3.0
3.3
3.3
2.5d
3.3g
3.0
Scaling exponents
Unit
BHP
BHP
BHP
BHP
BHP
ft2s.a.
ft2s.a.
acfm
acfm
acfm
ft c.s.a.
ft
ft3
kVa
length, ft
Exponent
0.96
0.52
0.52
1.00
0.60
0.70
0.70
f
0.85
0.43f
0.78
0.55e'h
1.0
0.68
0.33
0.8e'f
Considered an approximate average; cost factors could vary by up to + 40 to 50 percent
or more in some cases. Includes equipment, material and labor costs. Does not include
indirect cost. Developed from PEDCo experience unless otherwise noted.
b Suitable for approximation of 304 or 316 type stainless steel.
c To escalate cost of a similar unit of a different size.
Reference 1.
Reference 4.
Reference 2.
Reference 6.
h Resulting cost is expressed as dollars per linear foot of ductwork installed.
-------
TABLE 4-3. COST FACTORS AND SCALING EXPONENTS FOR WASTEWATER
AND SOLID WASTE TREATMENT EQUIPMENT
I
h-1
o
Equipment item
Storage tanks
Less than 40,000 gal
More than 40,000 gal
Clar if ier
Vacuum t liter
Sludge dryer
Centrifuge
Rotary drum filter
Ion exchangers
Carbon adsorption
Reverse osmosis units
Direct cost
factor3
2.0
2.0
2.5
4.0
4.0
3. 5
1.6
1.7f
1.5f
1.7
Stainless ,
steel factor
3.25d
3.35d
2.5h
2.5h
^
Scaling exponent
Unit
gal
gal
ft2c.s.a
gprn
gpm
gpm
ft2s.a.
Exponent
0.29d'e
0.63d'e
0.63f
0, 41 f
0.45g
0.44f
0. 63f
a Considered an approximate average; cost factors could vary by up to +_ 40 to 50 percent
or more in some cases. Includes equipment, material and labor costs. Does not include
indirect cost. Developed from PEDCo experience unless otherwise noted.
Suitable for approximation of 304 or 316 type stainless steel.
C To escalate cost of a similar unit of a different size.
Reference 7.
e Exponents are for total installed costs.
Reference 8.
Reference 4.
Reference 1.
-------
carbon steel prices to stainless steel prices on control devices
and auxiliary equipment. These factors are suitable for esti-
mating 304 or 316 type stainless prices. Cost factors for other
materials can be found in the cited literature.
EXAMPLE: The 1959 price of a 10-hp carbon steel centrifugal
pump was $400. The stainless steel factor is 2.0 (Table 4-2).
The 1977 price of a 30-hp stainless steel centrifugal pump is
estimated as follows:
(1977 price) = $400 x () x (°° ) x 2.0 = $2800
The accuracy of this 1977 price is lessened because it is neces-
sary to use multiple cost factors.
4.3.2.2 Direct Capital Costs —
Direct costs are those associated with the direct installa-
tion of equipment. They include materials and labor for the
installation of instrumentation, electrical work, foundations,
structural work, site work, insulation, painting, and piping.
The direct cost factors in Tables 4-1 through 4-3 were
obtained from PEDCo experience, cost handbooks, and the cited
literature. These cost factors are multiplied by the purchase
price of each equipment item required to obtain the direct cost
of installing that equipment item, including material, labor, and
equipment cost.
The direct cost factors in these tables are considered to be
average or typical; they can vary substantially from job to job.
To ensure accuracy when using these factors, consideration must
be given to site-specific conditions.
4-11
-------
4.3.2.3 Indirect Capital Costs--
Indirect costs include engineering, field and labor expenses, contractor's
fee, freight, off site, spares, sales tax, and allowance for shakedown. These
costs are determined by multiplying the total direct cost by the indirect cost
factors presented in Table 4-4. These factors, which were developed from
the cited references, are. considered typical for air pollution control systems.
Consideration must be given to their use for site-specific case conditions to
ensure accuracy.
4.3.2.4 Contingencies--
Contingencies incorporate additional unforeseen expenses resulting from
equipment breakage, inclement weather, strikes, shipment delays, and related
items. Generally, these costs run between 10 and 20 percent of the combined
direct and indirect costs. For the purpose of this cost estimating procedure,
a contingency factor of 15 percent will be used.
4.3.2.5 Total Capital Cost---
The total capital cost is the sum of the direct capital costs, indirect
capital costs, and contingencies. If possible, estimated production losses,
research and development, and other related costs should be added directly
to this total. Table 4-5 illustrates the complete capital cost estimating
procedure.
4.4 METHODOLOGY FOR ESTIMATING ANNUALIZED COSTS
Annualized costs include direct operating costs (labor, maintenance,
utilities, and raw materials) and fixed costs (overhead, property taxes,
insurance, capital recovery costs). The annualized costs for operating solid
waste and wastewater treatment/disposal systems associated with the emission
control facilities are included. Some pollutants can be recycled to the
4-12
-------
TABLE 4-4. INDIRECT CAPITAL COST FACTORS
1,10
Cost item
Interest during construction
Field labor and expenses
Contractor's fee
Engineering
Offsite
Spares
Sales tax
Start-up and shakedown
Total indirect cost
Percent
of direct cost
5.0
10.0
5.0
10.0
1.3
0.5
1.5
5.0
38
4-13
-------
TABLE 4-5. CAPITAL COST ESTIMATION
Equipment
item
Purchase
price
Direct
cost factor'
Direct
Equipment
costc
Total
direct
A. Total direct costs
B. Total indirect costs at 38% (A)
C. Contingencies at 15% (A + B)
Total capital costs
(A + B + C)
a
b
From Tables 4-1, 4-2, and 4-3.
Includes equipment cost and installation, instrumentation,
electrical work, foundations, structural work, site work,
painting, piping, and labor.
Sum of equipment purchase prices.
Sum of individual direct costs.
Includes engineering, contractor's fee, interest during
construction, shakedown, spares, freight, taxes, offsite,
and field and labor expenses.
4-14
-------
system, used as a component of another product, or used as a fuel
supplement. Whenever an economic value can be attributed to the
captured pollutant, an appropriate credit must be included in
computing the annualized costs.
4.4.1 Limitations, Restrictions, and Uncertainties
The estimated annualized cost may be somewhat less accurate
than the estimated capital cost because the accuracy of the fixed
costs depends largely on the accuracy of the estimates of capital
cost and equipment life. When adequate operating and exhaust gas
data are available, the estimate of the annualized cost will fall
within + 30 to 40 percent of actual costs. The annualized cost
factors in this section are considered to be average or typical
and consideration should be given to site-specific conditions.
4.4.2 Annualized Cost Components
A discussion of the individual annualized cost components
and methodology for estimating total annualized costs are pre-
sented in this section.
4.4.2.1 Utilities-
Utilities include electricity, water, steam, fuel oil, and
natural gas requirements. Annual incremental quantities are
determined through the use of fan equations, heat balances, and
the like. These quantities are then multiplied by the unit cost
for the local area. Unit costs for utilities vary widely de-
pending on the geographical location, user classification, and
consumption rates.
4.4.2.2 Raw Materials—
Raw materials and special chemicals are required for certain
control systems, e.g., activated carbon for adsorption units,
adsorption chemicals, limestone for flue gas desulfurization
4-15
-------
units, and sulfur trioxide for ESP flue gas conditioning. Cost
data are not presented for these materials because of the wide
variety of materials used. Prices can be obtained from chemical
suppliers or price catalogs. Annual consumption is determined
and is multiplied by the unit cost to obtain the annual cost of
raw materials. Incremental costs for fuel and material substi-
tution are computed in the same manner.
EXAMPLE: A continuous source operation emits 16 kg/h (35
Ib/h) of toluene. The adsorption rate of activated carbon is 7
percent, and the attrition rate 1 percent. The unit cost is
assumed to be $1.01/kg. The carbon requirements and costs are
estimated as follows:
-, ,- , ^ a. i . ,0.07 kg toluene, _ ,~n ,,_ ^aT-Knn/h
16 kg/h toluene -r (1>(? kg\arbon ) - 230 kg carbon/h
annual consumption = 230 kg carbon/h x 0.01 x 8000 h/yr
= 18,400 kg
annual carbon cost = $1.01/kg x 18,400 kg
= $18,580 per year
4.4.2.3 Operating Labor—
Operating labor depends on the type, size, and complexity of
the control system. A large, complex system such as the flue gas
desulfurization system may require the continuous effort of two
or three operators (2 to 3 hours of labor/hour of operation),
whereas a small wet collector may require only occasional obser-
vation (0.05 to 0.1 hour of labor/hour of operation). The degree
of system automation and the continuity of operation also in-
fluence operating labor requirements. Labor demands must be
determined on a case-by-case basis, considering each equipment
component and the overall system operation. The total man-ho>urs
per hour of operation is multiplied by the annual system opera-
ting time and labor rate to determine annual operating labor
costs. Labor rates vary widely according to the geographical
location.
4-16
-------
4.4.2.4 Maintenance--
Maintenance costs include the material, labor, replacement
parts, and supervision necessary to maintain the control system
at the desired level of performance. These costs are sometimes
very difficult to predict since they vary with the age of the
system and modes of operation. Table 4-6 presents the ranges of
maintenance costs for various types of control devices in terms
of dollars per m3/s (cents per acfm). These data generally
correlate with data from other cost sources. The estimator must
determine whether maintenance will be low, typical, or high,
based on the complexity of a specific application in order to
estimate the annual maintenance cost. An alternate method is
given in Table 4-7 where maintenance costs are expressed as a
percentage of capital investment.
The exhaust gas conditions and system complexity largely
determine the degree of maintenance of control systems. For
example, a flue gas desulfurization system is a highly automated
and complex system that has problems associated with scaling and
corrosion. High maintenance costs are expected.
A high-temperature gas stream from an electric arc furnace
may have to be cooled before it enters a fabric filter.
Occasional bag failure and replacement necessitate normal
maintenance.
A process with ambient operating conditions and exhaust
temperatures controlled by a medium-energy wet collector is an
example of a simple system with little mechanization and low
maintenance costs.
4-17
-------
TABLE 4-6. ANNUAL MAINTENANCE COSTS OF CONTROL DEVICES'
[dollars per m /s (cents/acfm)]
Generic type
Gravitational and dry
centrifugal collectors
Wet collectors
Electrostatic precipitators
High voltage
Low voltage c
Fabric filters
Afterburners
Direct flame
Catalytic
Low
17 (0.8)
68 (3.2)
34 (1.6)
17 (0.8)
68 (3.2)
102 ( 4.8)
237 (11.2)
Typical
51 (2.4)
136 (6.4)
68 (3.2)
47 (2.2)
170 (8.0)
203 ( 9.6)
680 (32.0)
High
93 (4.0)
203 (9.6)
102 ( 4.8)
68 ( 3.2)
270 (12.8)
340 (16.0)
1190 (56.0)
Includes material, labor, and supervision.
Reference 11; escalated to 1977 prices by Chemical Engineering
Labor Cost Index.
Add bag replacement cost: Assume 1- to 2-year life and
$18/m2 ($0.50/ft2) cloth.
4-l8
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TABLE 4-7. PROCESS MAINTENANCE COSTS
Type of system
Simple
Normal0
Complex
Annual maintenance cost
as a percent of capital investment
Labor
1-3
2-4
3-5
Materials
1-3
3-5
4-6
Adapted from Reference 1, p. 134.
Atmospheric conditions, little mechanization.
Normal operating condition; average system.
Corrosive and severe operating conditions or extensive
instrumentation.
4.4.2.5 Fixed Cost—
Fixed costs include capital charges, property taxes,
insurance, overhead, and administrative costs. Capital charges
are determined by multiplying the total capital cost of the
system by the capital recovery factor. The capital recovery
factor is a function of the interest rate and overall equipment
life. Capital recovery factors for various interest rates and
equipment lives are shown in Appendix A. A 10 percent interest
rate can be used in most cases. Insurance, property taxes,
overhead, and other administrative costs are usually estimated at
12
4 percent of the total capital investment.
Equipment life of pollution control devices is generally 10
to 15 years, depending upon the application. Better estimates
can be obtained through equipment manufacturers and suppliers.
EXAMPLE: The following procedure is used to determine the
total fixed cost of a control system requiring an initial capital
investment of $1.2 million at an interest rate of 10 percent and
having an overall equipment life of 22 years. The capital
recovery factor for 22 years and 10 percent is 0.11401.
4-19
-------
Therefore,
Capital recovery cost = 0.11401 ($1.2 million) = $136,800
Taxes, insurance, etc. = 0.04 ($1.2 million) = 48,000
Total fixed costs = $184,800
Product recovery and energy credits—When the capture of
pollutants results in an economically recyclable, recoverable, or
salable product, product recovery credits should be applied
against annual costs. Sometimes such credits substantially
reduce operating costs. First, the value (unit cost) of the
pollutant must be determined. If the collected pollutant is
recycled, the actual value can be assumed to be the final product
price less processing costs. The annual amount of pollutant
capture is estimated and multiplied by the net unit value to
determine the product recovery credit.
Similarly, credits for energy (heat) recovery should be
estimated when applicable. Heat recovery from the high tempera-
ture exhausts from incineration controls can greatly reduce
operating costs.
Solid/liquid waste disposal—It is necessary to dispose of
pollutants that cannot be recycled, recovered, or reused. Solid
waste disposal techniques include several methods of landftiling.
Liquid waste disposal methods include landfilling, incineration,
dry-well injection, and ocean dumping. Selection of a disposal
technique depends on the nature and quantity of the waste and
geographical location. Annual costs of each method are not
readily available, and a detailed discussion of these disposal
methods is beyond the scope of this document. Annual costs can,
however, be estimated by considering the following items:
0 Expenses, capital recovery, and maintenance on capital
items (trucks, land, equipment, etc.)
0 Fuel costs
4-20
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0 Electricity costs
0 Operating labor
stationary equipment
mobile equipment
0 Materials (barrels, chemicals, etc.)
0 Landfill fees
0 Administrative costs
The cost of operating landfills ranges from $2 to $5/Mg of waste for small
10
operations to $1 to $3/Mg for large operations. If solid waste materials are
hazardous, they may require special handling, such as disposal in sealed
barrels. Barrels alone cost $20 each, and hold up to 250 kg of waste. This
would make disposal cost at least $80/Mg.
Wastewater treatment- -Wastewater treatment facilities at a plant may have
sufficient capacity to handle any additional volume generated by an emission
control system. The unit treatment cost in dollars/103 gallons is determined
from operating records, EPA documents, or other sources, then multiplied by
the incremental volume to be treated annually to estimate incremental costs.
When new or expanded wastewater treatment facilities are required, the
cost of utilities, raw materials, chemicals, operating labor, and maintenance
and fixed costs are incorporated in the annualized cost estimate for the over-
all system. These costs can be separated out from among the direct emission
control costs.
4.4.3 Total Annualized Costs
Direct operating costs, fixed costs, product credits, and energy credits
for the operation of air pollution control systems and secondary facilities can
be summarized in a format given in Table 4-8.
4-21
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TABLE 4-8. SUMMARY OF PREDESIGN ESTIMATE OF ANNUALIZED COSTS
I
to
ro
Item
DIRECT OPERATING COST
I. Utilities
Raw materials
Electricity
Water
Steam
Gas
Fuel oil
II. Operating labor
Direct labor
Supervision
III. Maintenance (see Tables 4-6
Labor and materials
Supplies
Replacement parts
IV. Sludge disposal
V. Wastewater treatment
FIXED COSTS
I. Taxes, insurance, over-
head, etc.
II. Capital recovery charges
PRODUCT RECOVERY CREDIT
Unit
$
S
$
$
$
$
$
15%
, 4-7
$
$
cost Quantity Cost
/ton tons/yr
/kWh kWh
/103 gal 103 gal/yr
,/103/lb 103 Ib/yr
/106 Btu 106 Btu/yr
10J gal 10J gal/yr
/man-hour man-hours/h
direct labor operation
)
/ton tons/yr
/103 gal 103 gal/yr
TOTAL DIRECT OPERATING
4% of total capital investment
% of total capital investment
$
TOTAL FIXED COSTS
/ton tons/yr
TOTAL ANNUALIZED COSTS
-------
4.5 COST-EFFECTIVENESS
The cost-effectiveness of a control technique is arrived at
by comparing the degree of emission reduction with the total cost
of achieving the reduction. It is expressed in dollars per unit
weight of pollutant removed and is computed by dividing the total
annualized cost by the total annual quantity of pollutant re-
moved. As control efficiency improves, the quantity of emissions
is reduced, but the cost of control increases. Cost-effective-
ness relationships are useful in emission control decision making
since several feasible systems usually are available for con-
trolling each source of emission. Cost-effectiveness relation-
ships vary from industry and from plant to plant within an
industry.
EXAMPLE: Assuming the annualized cost of an air pollution
control system is estimated at $126,000, the system captures 99
percent of the 39 kg/h of emissions generated, and total oper-
ating time is 8000 hours per year, cost-effectiveness is deter-
mined as follows:
Amount of pollutant captured =0.99 (39 kg/h) (8000 h/yr)
= 3.09 x 105 kg/yr
jt. -i • ,
Cost-effectiveness = -
3.09 x 105 kg/yr
= $0.41/kg pollutant removed
4-23
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REFERENCES
1. Peters, M.S., and K.D. Timmerhaus. Plant Design and
Economics for Chemical Engineers. McGraw-Hill, New York,
New York. 1968.
2. Kinkley, M.L., and R.B. Neveril. Capital and Operating
Costs of Selected Air Pollution Control Systems.
EPA-450/3-76-014, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina. May 1976.
3. Manual published by Richardson Engineering Service, Inc.
Downey, California. 1974.
4. Guthrie, K.M. Capital Cost Estimating. Chemical Engineer-
ing Magazine. March 24, 1969. p. 114.
5. Control Techniques for Hydrocarbon and Organic Solvent
Emissions from Stationary Sources. Publication No. AP-6B.
U.S. Dept. H.E.W., Public Health Service, Washington, D.C.
March 1970.
6. Robert Snow Means Company, Inc. Building Construction Cost
Data, 1977. Duxbury, Massachusetts. 1977.
7 Guthrie, K.M. Process Plant Estimating Evaluation and
Control. Craftsman Book Co., Solano Beach, California.
1974.
8 Blecker, H.C., et. al. Wastewater Equipment. Chemical
Engineering Deskbook Issue. October 21, 1974. p. 115.
9 Chemical Engineering Equipment Buyers Guide, 1977-78.
Chemical Engineering Magazine. McGraw-Hill, New York, New
York. July 1977.
10. Perry, J.H., ed. Chemical Engineer's Handbook, 4th edition.
McGraw-Hill, New York, New York. 1963.
11 Control Techniques for Particulate Air Pollutants. Publi-
cation No. AP-51. Office of Air Programs, Environmental
Protection Agency, Research Triangle Park, North Carolina.
January 1969.
4-24
-------
12. Memo from Bill Hamilton of Economic Analysis Branch, U.S.
Environmental Protection Agency, Research Triangle Park,
North Carolina, to staff. Subject: EAP Input to RACT/CTD
Documents. March 14, 1977.
13. Lund, H.F., ed. Industrial Pollution Control Handbook.
McGraw-Hill Book Co., New York City. 1971. Chapter 26, p,
7-46.
4-25
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SECTION 5
FINANCIAL AND ECONOMIC ANALYSIS TECHNIQUES
5.1 INTRODUCTION
This section of the guidance document is intended as general
reference for state and local agencies, to assist them in deter-
mining the economic impact upon major stationary sources that
may result from application of pollution controls.
The costs incurred by the source as a result of control are
assumed to be directly obtainable from the source or obtained by
the procedures discussed in Section 4.
Subject to this assumption, generalized methodology will be
described for evaluating the economic impact of these costs upon
the source (i.e., the individual plant) that is being subjected
to the control requirements.
Six techniques for performing relevant economic and finan-
cial analysis will be presented, with comments on the factors
that might affect the selection of one or another of these tech-
niques (or combination of techniques) for a given situation.
These factors influencing selection of an appropriate analysis
technique include the impact to be measured, the available data,
the personnel and other resources available to the state or local
agency for processing the data, and interaction with certain
special incentive arrangements that are available for financial
needs arising from pollution control.
In conjunction with the description of each analysis tech-
nique, the data that must be available with respect to the par-
ticular source in order to make proper use of that technique will
be defined. This is a "feedback" situation: initial selection
of a particular analysis technique will define the particular
5-1
-------
data needed. This will lead to a determination of the availabil-
ity of these data, and that in turn may necessitate a change in
the selection of the analysis technique. An important objective
in what follows, therefore, is to clarify the relationships
between the various analysis techniques and their respective data
requirements.
In addition to the foregoing, consideration will be given to
whether the capital needed for compliance is available to a
particular source. This is only one facet of the various poten-
tial economic impacts of the costs of compliance. However, it is
sufficiently fundamental to call for special highlighting.
The intent here is not to provide a textbook on economics
and finance, to address a readership of financial experts, or to
assume the place of a qualified analyst. Rather, the objective
is to provide uncomplicated, straightforward explanations (in
sufficient detail that the information can serve as the framework
on which to construct practical applications) for readers not
having specific background in finance.
The discussion is presented in two parts: description of
the analysis techniques (5.2) and information needed to perform
analysis techniques (5.3).
5.2 THE ANALYSIS TECHNIQUES
Six techniques for analysis of the economic impact of pollu-
tion control upon individual plants are presented below and
detailed in Table 5-1:
1. Computation of Debt Service Coverage Ratio
2. Computation of Return on Investment (ROI) Ratio
3. Computation of Discounted Cash Flow
4. Reference to Previous Impact Studies
5. Reference to Financing Decisions by Others
6. Computation of Increase in Operating Costs or Assets
5-2
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Table 5-1. COMPARISON OF ANALYSIS TECHNIQUES
Techniques
Debt Service Covei ngo
Ratio
Return on Jn vestment
(ROD Ratio
Discounted Cash Flow
(t)CF) Computation
Impact
Being
Analyzed
Capital Availability
Prof i tabili ty
Profitability
Availability of Data
Sources (Prioritized)
Plant
Other Studies
FPA
OSHA
References
Census of Manufacturers
Robert Morris Associates
Ti oy Almanac
Trade Associations
Federal Trade Commission
Per i odicals
Plant
Other Studies
F,PA
OSHA
References
Robert Morris Associates
Troy Almanac
Federal Trade Commission
Equipment Suppliers
Census of Manufacturers
Trade Associations
Peri odical s
PI ant
Availability
Existing Source
- Moderately Easy
New Source
- Difficult
Exi sti ng Source
- Moderately Easy
New Source
- Difficult
Existing Source
•- Moderately
Di Ff icu 1 t
New Source
- Difficult
Agency Level
" Of Effort "~
Required
Moder ate
Ex tens i ve
Forecasting
Required
Moderate
Extensive
Forecasting
Required
Extensive
Forecasting
Required
Extensive
Forecasting
Required
Limitations
1) Veriti cat inn of
forecasts Cor new
or expanded source.
2) Considerable
error possible if
measuring at: arm's
length.
1) Verification of
forecasts for new
or expanded source.
2) Indirectness of
measure .
1) Verification of
forecasts for all
sources .
2) Considerable
error possible if
measuring at arm's
1 ength.
(Jl
I
L/J
(continued)
-------
Table 5-1 (continued).
Techniques
Heliance Upon Previous
Impact Studies
Financing Decision By
Others
rncrcase in Operating
Cor. ts or Assets
Impact
Doing
Ana ly zed
Whatever Impacts
Studied Previously
Capital Availability
Availability of Data
Sources (Prioritized)
EFA: Rconomic Analysis
Branches of offices of
Air Quality Planning &
Standards (Durham, NC)
and Office of Water
Programs (Washington,- IT)
OSHA
Plant
Dun and Bradstreet
Local Industrial Directory
SBA (Size Standard)
Prof i tability
Plant
Availability
Relatively Easy
Moderately Easy
If Working With
Source
Difficult If Doing
Arm's Length Analysi
Existing Source
- Moderately
Difficult
New Source
- Difficult
Agency Level
Of Effort
Required
Minimum
Minimum
-S
Moderate
Extensive
Forecasting
Required
Limitations
1) Control costs
magnitude may be
so different that
makinq judgments
may be difficult.
2^ If control costs
being analyzed are
additive to ones
studied (rather
than substituted)
then judgments may
be dif f icu 1 t .
3) Industry may not
have been studied.
1) If analysis IR
performed without
having source apply
then it is difficult
to analyze existing
source and very di f-
ficult to analyze
new or expanded
source .
1) Verification of
forecasts for now
sources .
2) Accuracy of
allocation of
overhead expenses
from another part
of company.
3) Indirectness of
measure.
Ui
I
-------
This list does not represent an exhaustive set of analysis
techniques. There are others, but these six were chosen because
they cover a variety of possible circumstances. The first three
listed techniques are conventional tools for analysis of business
financial conditions. The next two techniques are not so con-
ventional, but are particularly applicable to pollution control
impact financial conditions. The sixth technique was created for
this guidance and is intended for special circumstances when it
is impractical to establish net income figures for a plant.
In all these techniques it is most important to determine
when the impact crosses the threshold from minimal to signifi-
cant. The definition given to "significant" is that the plant
will close because it is no longer able to conduct business or
because continuing operation is not as profitable as other
i
options. In several of these techniques the criteria for signif-i
icant impact are well defined, e.g., necessary funds cannot be
obtained for the pollution control expenditure, or the owners
would be better off liquidating the plant and investing the money
elsewhere rather than buying pollution control equipment. In
other techniques (including some of the conventional ones), there
are no widely recognized specific numerical criteria for deter-
mining significant impacts, for which the analyst may be required
to use extensive judgment. Some judgments will be relatively
simple and others will be difficult. Further, some techniques
are more direct than others in measuring significant impact. For
example, although the ROI and discounted cash flow techniques
both measure profitability, ROI does not necessarily indicate the
precise level at which the plant would choose to close, whereas
the discounted cash flow technique does indicate such a level.
Before the six techniques are described, a definition of
individual plant source is provided. A plant is the single
physical location where the pollution control equipment is to be
5-5
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installed. It is analyzed on a stand-alone basis without regard
to other operations of the company at other locations. Analysis
is relatively straightforward when a plant is the whole company
or a separate subsidiary of a larger company. Analysis may still
be fairly straightforward when the plant is a division or a
specific profit center of the company. Analysis is much more
complicated when the plant is part of a division and buys and
sells material from and to other plants or divisions within the
corporation. The main problems in the latter case are validating
company-submitted data that have not been independently audited
or are not publicly available and assigning a value or transfer
price to the intracompany goods in order to derive net income.
In the subsections that follow, the individual techniques
are first briefly discussed. Following that is a comparison of
the techniques that will aid an analyst in selection of tech-
niques for a given situation.
5.2.1 Analysis Technique 1; Computation of Debt Service
Coverage Ratio
The debt service coverage technique involves an analysis of
whether or not a source can meet debt (i.e., interest and princi-
pal), lease, and long-term payment obligations, including those
for the new pollution control expenditure, at the level of cash
flow that exists at the source. It is therefore also a measure
of the capital availability impact of a pollution control regula-
tion.
The lending community looks to this ratio in longer-term
borrowing situations to determine whether adequate funds will be
available to repay debt obligations.
Cash flow from the operation includes net profit before
taxes, lease, and interest payments plus depreciation. It is
only out of this cash flow that payments can be made for such
obligations unless the company has "unproductive" assets that it
5-6
-------
could convert to cash to buy control equipment. "Unproductive"
designates assets unrelated to the nature of the business, for
example, long-term marketable securities or certificates of
deposit.
This technique can be applied as a verification of a financ-
ing inability determined under Technique 5 or as a prediction of
whether financing may be obtainable. It can be used for a new or
an existing plant. It is used primarily when the agency and the
source are engaged in deliberations, since the level of obliga-
tions that are a crucial part of the analysis is highly dependent
upon the particular circumstances of the plant.
The results of the debt service coverage analysis will be a
ratio, the numerator of which is cash flow from operations and
the denominator of which is future debt and other long-term
obligations. The ratio needs to be computed on a "before" and
"after" pollution control basis. In order for a financing source
to loan money to a plant, the "after" ratio should exceed 1.0.
Most financing sources, however, would require an ample cushion
greater than 1.0 to reflect risk over time. If the "after" ratio
exceeds 2.0, it can be assumed that there is no significant
impact. If the ratio is between 1.5 and 2.0, chances are that
the financing is still obtainable but the company is in a risk
situation unless it is accustomed to operating at that ratio. A
ratio between 1.0 and 1.5, for the purposes of this analysis,
will be considered to indicate significant impact.
The banking industry, although using this technique exten-
sively, does not specify a criterion to be used in making judg-
ments. For example, a bank may grant financing in a case where
the ratio is less than 1.5 because the company has historically
operated at that level and has been able to meet its obligations.
Thus it is important to do both before and after analyses of the
ratio to indicate the extent of change of the ratio as well as
the absolute level after pollution control impacts.
5-7
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In this technique and several others, the analyst must con-
sider the extent to which a price increase may occur to cover the
pollution control expenditures. This consideration is discussed
here and is not repeated in the next three technique descrip-
tions. The determination of impact from any pollution control
situation is highly sensitive to whether a plant source can
increase the price of its products and therefore pass on to the
consumers the costs of pollution control. To the extent that
this can occur, the impact of pollution controls does not have to
be absorbed by the company.
The increase of price, however, can sometimes lead to a
slight reduction in total products purchased from the company.
Therefore, although the revenue of the company goes up to cover
the pollution control costs, it can come back down slightly if
fewer products of the company are purchased. The quantitative
measure of this effect of a change in quantity purchased due to a
change in price is referred to as elasticity. It is typical,
however, that the quantitative determination of elasticity is not
available in an analysis. Therefore the impact over a range of
possible price behaviors can be approximated by performing the
analysis as if there were no price increase and as if there were
a full price increase without any change in quantity of products
sold. (The analytical tables presented later do include pro-
visions for cases in which an elasticity figure is available.)
Then the analyst must use judgment to determine where in the
range the impact is likely to occur. Such a judgment can be made
only if the analyst can determine at least qualitatively the
possible price increase that the company would be able to set for
its products. The analyst should consult economic textbooks to
determine how to assess elasticity.
Performing this analysis for an existing plant requires a
moderate amount of effort. Performing this analysis for a new or
expanded plant requires a considerable amount of forecasting by
the source, not only of profit and loss but also of equity and
debt financing practices.
5-8
-------
5.2.2 Analysis Technique 2: Computation of Return on
Investment (ROI) Ratio
ROI is a measure of how efficiently the investments (assets)
of a plant are being utilized and thus is a measure of profit-
ability. It is not a direct measure of capital availability.
The ROI measure is a ratio: the numerator is net profits,
and the denominator is the assets value of the plant including
net working capital and the net book value of fixed assets. No
single criterion is recognized for determining when the ROI ratio
of a plant is significantly impacted. The analyst, therefore,
may perform "before" and "after" ROI impact evaluations, taking
into consideration a possible price increase.
The preferred ratio with which to compare the "after" ROI is
the plant's threshold rate. By threshold is meant the plant's
minimum acceptable rate of profit per each new investment. Most
plants have such a threshold ROI rate, which may or may not be
obtainable. The analyst should remember that the minimum thresh-
old rate for a new investment may be higher than the average ROI
for existing investments.
If the threshold rate is not obtainable, the analyst may be
able to obtain the industry average ROI for comparison with the
plant's "after" ROI. Sources of an industry average ROI value
include trade associations, Robert Morris Associates, the Federal
Trade Commission, and previous industry impact studies. The
analyst must use judgment to determine how much deviation from
the industry average constitutes a significant impact.
If the above two rates are not obtainable, the analyst could
compare the plant ROI with the marginal cost of capital, i.e.,
the plant's cost of the next source of funds for its investments.
Significant impact would occur when the ROI is less than the
marginal cost of capital.
5-9
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This technique can be applied to new or existing plants and
to plants with which an agency is in deliberation or is analyzing
at arm's length, i.e., predicting impact without being engaged in
deliberations.
In analysis of a new plant the future financial conditions
must be estimated in order to perform the ROI calculation. It
will be necessary for the source to forecast at least the first 2
or 3 years of operation so that the ROI impact for more than 1
year can be viewed. This measurement requires a moderate to
extensive level of effort for the agency analyst.
5.2.3 Analysis Technique 3: Computation of Discounted Cash Flow
(DCF)*
The discounted cash flow technique involves looking at the
future operations of a plant to determine whether it would be
better for the plant owners to liquidate assets or to continue
operating the plant with the pollution control equipment in-
stalled. The discounting refers to a consideration of the value
of money over time. This technique is a direct measure of prof-
itability.
The technique is applicable to analysis of new or existing
plants and is more applicable to plants with which the agency is
in deliberations than to those being analyzed at arm's length
without benefit of the plant's financial data.
The general procedure for performing this analysis is to
predict the future financial conditions of the company during the
useful life of the pollution control equipment. The value of
future net cash flows from the plant operations plus the future
terminal value of the plant (appropriately discounted) at the end
of the useful life of the pollution control equipment are com-
puted to obtain present value.
* Reference for this discussion and for several of the tabular
formats presented later was Appendix A: Draft Guidance on
Nonferrous Smelter Orders Under Section 119 of the Clean Air
Act, EPA Division of Stationary Source Enforcement.
5-10
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The value of future cash flows must then be compared to the
present value of the plant if it were immediately liquidated. If
the value of future operations is greater than the present value,
the firm, according to rational decision-making theory, would
purchase the pollution control equipment. If the future value is
less than the present value, the plant would be liquidated and
the money invested elsewhere at a greater return.
The discount rate is of particular significance to this
technique. The discount rate used in this analysis is a weighted
average cost of capital. Capital is defined as sources of long-
term funds for the company and typically includes long-term debt,
preferred stock, common stock, and earnings retained in the
business. Most going concerns are already earning money at a
rate greater than their cost of capital. This technique is based
on the premise that when the plant earns less than what the funds
cost, the plant will choose to close.
The discounted cash flow technique requires forecasts in all
situations. One of the difficult aspects of forecasting is that
projections of greater than 2 or 3 years are often inaccurate.
In addition, because forecasts are not subject to an independent
audit and because they are supplied by the company, the analyst
must verify or test the reasonableness of the forecast. It is
therefore appropriate for an analyst to request that the company
not only make a financial forecast but also describe the physical
inputs that went into it. The physical inputs consist of the
amounts of raw materials, labor, and other supplies needed to
manufacture the product. The analyst then must obtain (from the
source or others) price factors to use with the physical inputs
in deriving financial data that can be compared with those
supplied by the plant.
Since forecasts are realistic only for periods up to 3
years, the analyst must extrapolate net cash flow for the remain-
ing years to the end of the useful life of the pollution control
equipment.
5-11
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The analysis of discounted cash flow should be done on a
"before" and "after" pollution control basis and with or without
a price increase to cover the pollution control costs.
This particular method is the most highly labor-intensive of
those presented. The extrapolations require a considerable
amount of time, as does determination of the proper labor and
cost factors for the physical inputs.
5.2.4 Analysis Technique 4: Reference to Previous Impact
Studies
Often an analyst can obtain an EPA economic impact study of
the entire industry of which the plant under consideration is a
part. Although such a study may pertain to compliance with
pollution control regulations other than the one in question, it
may provide applicable information on pollution control costs and
economic impacts.
Economic impact analyses have been done for New Source Per-
formance Standards (NSPS) and NESHAPS regulations by the Economic
Analysis Branch of the Office of Air Quality Planning and Stand-
ards. To date approximately two dozen such studies have been
performed. These studies are available through the Economic
Analysis Branch Office in Durham, North Carolina. Many addition-
al industry impact studies relating to water pollution control
regulations have been performed by the Economic Analysis Branch
EPA Office of Water Programs, Washington, D.C. A state or local
agency analyst may wish to contact these two branches of EPA to
obtain a list of available studies.
Application of an earlier study is most straightforward when
the control cost magnitudes are similar, the regulatory impact
under consideration is not in addition to the regulatory impact
of the other study, and the other study reaches a definitive
impact decision.
If the control costs are similar in magnitude and the other
study concludes that a significant impact will occur, then it is
5-12
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likely that such a conclusion also holds for the present situa-
tion. When the conclusion is that no significant impact will
occur, the analyst must use judgment to determine how far the
control costs of the other study could expand while maintaining
the same conclusion. The expansionary consideration can cover
circumstances where the control costs of the present situation
are greater than those previously studied or when the present
regulatory impact is in addition to the previous one. No clear-
cut criteria can be presented here to aid the analyst in calcu-
lating the expansionary limits. The judgment depends upon the
particular facts of the previous study.
To the extent that another impact study is useful for
gauging the impact of the situation under consideration, the
amount of resources required of an agency is minimal.
5.2.5 Analysis Technique 5; Reference to Decisions by Others
One impact of pollution control regulations to consider for
a source is the availability of capital to purchase the equip-
ment. The inability for a plant source to obtain needed financ-
ing capital is indicative of significant impact, since the plant
may not be able to continue to conduct business.
For a small business as defined by the Small Business Ad-
ministration (SBA), the skill of SBA can be utilized to evaluate
the capital availability impact of a pollution control expendi-
ture by having a source make application. If the financing
request is rejected by the SBA, sometimes called lender of the
last resort, then the source is unlikely to obtain financing by
any conventional means. SBA has specific programs for pollution
control expenditures; currently these programs are adequately
funded.
Although no similar institution is applicable to large
businesses, rejections by two or more financing sources provide a
similar indication of the unavailability of financing. To
attribute financing inability to the pollution control regulation
5-13
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in question, the analyst must know that disapproval of the
financing request was caused by the impact of the regulation
itself and not other factors such as improper documentation or
lack of management expertise.
This technique is particularly relevant when the agency is
engaged in deliberations with the source and can ask the opera-
tions to apply for financing (the debt service coverage ratio
allows the analyst to estimate the availability of financing
without the source having to apply). This technique can be used
for both new and existing sources. It calls for a relatively low
level of effort, since it enlists the skills of an existing
institution set up to do this type of work.
5.2.6 Analysis Technique 6; Computation of Increase in
Operating Expenses or Assets
In some multiplant situations the net income for a plant
will be either extremely difficult to determine or so artifi-
cially determined that it does not represent the true profit
picture of that company if it were independent. The importance
of determining income is that all of the above-presented tech-
niques require it for the analysis. Where income cannot be
determined with an acceptable level of accuracy, the analyst may
wish to examine the operating expenses or asset replacement value
of the plant and to compare them to the magnitude of the pollu-
tion control costs as an indirect evaluation technique.
This technique is applicable to new and existing sources
with which the agency is in deliberations or those being analyzed
at arm's length. This technique is an indirect measure of impact
because it provides no definitive indication that the increase
involved would cause the plant to liquidate or that the plant
could not obtain financing. As with ROI, there are no criteria
for determining when an increase in cost constitutes significant
recognized economic impact. A level of 30 to 40 percent (after
5-14
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price increase considerations) is a reasonable criterion to use
when related to expenses and greater than 40 to 50 percent of the
asset replacement value.
This analysis technique requires a relatively moderate level
of effort.
5.2.7 Comparison of the Analysis Techniques
The six techniques are compared in the accompanying matrix
according to salient characteristics. The matrix describes what
each technique measures, the data required for performing the
technique, the sources of such data and the relative ease of
acquisition, the amount of effort required by the agency, and the
limitations of the technique.
Examination of the matrix reveals several pertinent points:
0 For analysis of sources at arm's length, the two most
appropriate methods are use of the ROI ratio and
reliance upon previous impact studies.
0 The discounted cash flow technique requires the most
work on the part of the agency, followed by ROI, debt
service coverage, and increase in operating costs or
assets.
0 Forecasting is required for all analyses of new sources
except those based on decisions by others and previous
impact studies.
0 Financing decisions by others, debt service coverage,
and perhaps reliance upon previous impact studies are
the techniques for directly determining capital avail-
ability.
0 Discounted cash flow is the most direct measure of
potential for plant closure due to low profitability,
followed by the indirect measure of ROI and increase in
operating costs or assets.
It is emphasized that on some occasions the agency analysts
will not be able to perform an analysis, or judgments will be
very difficult. These techniques will accommodate most situa-
tions, however. In the event that an analyst needs advice, he
5-15
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should contact EPA Division of Stationary Source Enforcement in
Washington or the Economic Analysis Branch in Durham.
5.3 INFORMATION NEEDED TO PERFORM ANALYSIS TECHNIQUES
This section describes more fully the information required
for performing each technique and the alternative sources for
obtaining the necessary information. Sample tables performing
the necessary calculations are presented for each technique.
Prior to a description of the information needed for each
technique, the subject of special Federal pollution control
financial assistance programs will be addressed.
In some cases the benefits of these programs need to be
woven into the calculations of the various techniques.
5.3.1 Special Pollution Control Financial Assistance Programs
The Federal government operates four major Federal programs
to ease the financial burden of pollution control expenditures:
0 Industrial Development Bonds
0 SBA Direct Compliance Loans
0 SBA Lease Guarantees
0 Rapid Amortization
Two of these programs are particularly important to sources
that have difficulty obtaining financing for pollution control
and are provided by SBA.
The other two programs reduce pollution control costs; one
makes available low-cost financing to companies considered
credit-worthy; the other provides for rapid recovery of portions
of the pollution control costs through tax reduction provisions
of the Federal corporate income tax laws.
This section will briefly describe the four programs, focus-
ing on eligible users, benefits, and access to the program.
5-16
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Where it is expected that a source would use any program, the
pertinent information on interest rates and terms is provided for
entry to the tables pertaining to the various analysis tech-
niques.
Additional information on these four programs can be ob-
tained from reference: Choosing Optimum Financial Strategies:
Pollution Control Systems, JACA Corp., Environmental Research
Information Center, U.S. EPA, Cincinnati, Ohio.
5.3.1.1 Industrial Development Bonds—
Industrial Development Bonds (IDE's) are a type of municipal
bond with lower interest rates for the company than a corporate
bond and a repayment period significantly longer than that ob-
tainable from a bank. The reason for lower costs is that the
interest is tax-free to the bond buyers, which makes them willing
to accept interest rates that are two to three points lower than
those on taxable corporate bonds. IDE's are issued by a public
entity on behalf of an industrial source and are issued for a
public purpose. Pollution control equipment is considered a
public purpose and is therefore eligible for this type of financ-
ing.
The amount of an issue is usually quite large, i.e.,
$500,000 and greater. The reasons for such large amounts are the
high fixed costs of obtaining such bonds, due to advertising
expenditures, bond counsels, investment bankers, and printing.
The interest savings accruing to a company from use of these
bonds must therefore be of sufficient magnitude to surpass such
fixed costs.
The bonds are also referred to as revenue bonds as opposed
to general obligation bonds, which means that only the revenue
from the company is used to repay the bonds. Therefore, the
benefiting company must be credit-worthy. Also, because the
bonds are often sold nationwide, the reputation of the benefiting
company must be fairly high. All of these factors point to the
5-17
-------
fact that only financially healthy companies and companies with
large pollution control expenditures can make use of the benefits
of this financing program.
Although small companies generally are not able to benefit
from this program, companies with good credit position and ex-
penditure needs of less than $500,000 can obtain the benefits of
the program in some states. This occurs when the state allows
the private placement of bonds whereby the bonds are sold to a
single entity, such as a bank or an insurance company. The
effect of this mechanism is to lower the amount of fixed costs
incurred and therefore permit pollution control expenditures in
amounts of less than $500,000 to be beneficially financed by
industrial development bonds.
The determination of whether a source is likely to use IDB's
can be based on 1) an indication from operators of the source, 2)
previous use of IDB's by the source plus an expenditure greater
than $500,000, or 3) an expenditure greater than $500,000 plus a
good credit or bond rating. In the latter case, if the company's
rating is not readily available through Dun and Bradstreet,
Moody1s, or Standard & Poor's, then for simplification the
analyst may assume that an IDE will not be used.
When it is likely that an IDE will be used, the values of
interest rate and repayment length to be entered into Table 5-2,
line 2(a) are the current municipal A-rated bond yield* and 25
years. Because the choice of an A-rating and 25 years is some-
what arbitrary, these values should not be used if the analyst
knows a more exact bond rating and repayment period for the
company.
5.3.1.2 SBA Direct Compliance Loans—
The SBA makes loans directly (without having a bank also put
up money) to "small businesses" for pollution control expendi-
tures. The small business must fit the numerical definition of
* Economic Indicators, Council of Economic Advisors or Survey
of Current Business, U.S. Department of Commerce.
5-18
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Table 5-2. POLLUTION CONTROL COSTS
1. Capital costs including installation
2. Interest Rate (i)
a. When anticipating impact or
specific financing source
cannot be determined
b. If IDE rate possible
c. If SBA rate possible
10
3. Tax depreciable life (n)
years
10.
Annualized costs (capital
recovery factor equation
times capital costs)
Line 1 x
id
i)
(1 + i
n
- 1
Average annual depreciation expense
1
n
(1)
Line 1 x
6. Average annual interest expense
(Line 4 - Line 5)
7. Annual O&M costs, including
insurance, & G&A<2'and
excluding depreciation
and interest
8. Average annual by-product value
9.
Annual control costs
(Lines 4 + 7 - line 8)
Investment tax credit
(.1 x Line 1)
(1) Straight line depreciation is assumed for purposes of
simplifying the calculations
(2) Assume 4% of capital costs is insurance and G&A if no
other figures readily available.
5-19
-------
small as established by SBA, face a compliance requirement that
can be traced to a Federal requirement, and be unable to obtain
the loan or able to obtain it only at unreasonable terms. The
numerical qualification is usually in terms of number of em-
ployees, ranging between 250 and 1500 depending on the industry.
By a telephone call to SBA, the analyst should obtain the specif-
ic numerical limit for the Standard Industrial Classification
Code (SIC) applicable to the plant's line of business. Deter-
mination of size for SBA qualifications is based on the entire
company and not on only the plant being analyzed.
This SBA program :.s not to be confused with SBA's tradition-
al loan programs for businesses that often have limited funds and
often only guarantee bank loans having high interest rates.
Presently, the SBA interest rate on direct compliance loans
is 6-5/8 percent. Loans are allowed to 30 years, although typi-
cally they are granted for a shorter period that is reasoncible
for the company to repay. These loans are available for purchase
of add-on pollution control equipment as well as process change
equipment.
To obtain an SBA loan the company should first be refused
financing by a conventional source or offered financing at un-
reasonable terms. The source should then determine from SBA the
numerical employee limits for their SIC; if the number employed
is under that limit, the source may apply. Documentation of the
bank situation will be required, along with a statement by the
control agency of the adequacy and necessity of the proposed
control equipment. The application process can be very time-
consuming and may require several exchanges of information with
the SBA.
If the analyst can determine by calling SBA that the source
is small, and if there is some indication that the source will
have difficulty obtaining conventional financing, then the ana-
lyst should use the current SBA terms as data for entry into
5-20
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Table 5-2. The current SBA interest rate (obtainable from SBA)
should be entered, and the repayment life should be assumed to
equal the equipment's useful life.
5.3.1.3 SBA Lease Guarantees—
Some small businesses will also be eligible for conducting a
lease of pollution control equipment under terms the SBA will
guarantee. In the pollution control field, a lease typically
occurs with Industrial Development Bond (IDE) financing, ex-
plained above. Until this program began, small businesses could
not "afford" IDE's because of the high fixed costs of obtaining
them. This program therefore groups the needs of several small
businesses under an IDB issue guaranteed 100 percent by SBA.
Interest rates and repayment terms are similar to those of
IDE's. The eligibility criteria for this program are different
from those criteria of a direct compliance loan program. A
company is eligible for this program if:
together with its affiliates, (it) is independently owned
and operated, is not dominant in its field of operation,
does not have assets exceeding $9 million, does not have net
worth in excess of $4 million, and does not have an average
net income, after Federal income taxes, for the preceding
two years in excess of $400,000 (average net income to be
computed without benefit of any carryover loss).*
To participate in this program the small business must first
obtain the sponsorship of a bank. The bank prepares a statement
of opinion that the company is credit-worthy. Then the require-
ments of the SBA direct compliance loan program apply, i.e., the
company must obtain a certificate from the control agency that
the equipment is adequate and necessary, and must complete an
application.
If there is some indication that this program will be used
by a source, then the interest rates and repayment period as
* Part 121.3-11(a), Chapter 1, Title 13.
5-21
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determined under SBA's compliance loan program will provide a
sufficient degree of accuracy for analysis.
5.3.1.4 Rapid Amortization—
This is the only one of the four Federal programs that in-
volves tax deductions for pollution control equipment. Although
it is a special program for purchase of pollution control equip-
ment, very few companies use it, and those that do use it do so
under certain circumstances explained below.
The rapid amortization program allows expenditures for
pollution control equipment to be deducted for Federal income tax
purposes over a 60-month period, which is usually shorter than
the normal tax-depreciable life. Along with this accelerated
write-off, the source is entitled to one-half the normal 10
percent investment tax credit, or 5 percent.
To determine whether rapid amortization is beneficial, the
analyst must compare, for example, using net present value (NPV)
techniques, the value of 60 months' depreciation plus a 5 percent
investment tax credit versus the normal tax life of the equipment
and a 10 percent investment tax credit.
The results of such a comparison are presented in Figure
5-1. A company with equipment of 15 years taxable life and a 10
percent discount rate would prefer the rapid amortization, since
the point at which those two figures meet on the graph is to the
right of the line. If the equipment had a 10-year life and a 10
percent discount rate, however, a normal accelerated rate would
be preferred. The special circumstances under which rapid amor-
tization is preferred, then, are a relatively long (12 years or
more) normal useful life of the equipment or a high discount rate
coupled with equipment that has a slightly shorter useful life.
To simplify the impact analysis, it is suggested that this
program not be considered as beneficial to the source. Even if
the source does use rapid amortization, the difference in the
5-22
-------
Ul
I
to
U)
20
f- IS _
a:
UJ
1
w
H
c< 10
o
u>
00
t—<
Q
TRADITIONAL DEPRECIATION
YIELDS GREATER
TAX BENEFITS
RAPID AMORTIZATION
YIELDS GREATER
TAX BENEFITS
10 1 b 20
ASSET LIFE - YEARS
Source: Economic Analysis Division, Office of Planning and Evaluation, Environmental
Protection Agency.
Figure 5-1. Indifference curve for amortization options under the Tax Reform Act of
1976 traditional vs. rapid amortization.
-------
results will be minor. The analytical tables are formulated to
reflect normal taxable useful lives of equipment and the 10
percent investment tax credit.
5.3.2 Information Required
5.3.2.1 Pollution Control Costs—
In most impact analysis techniques described here, the
pollution control costs must be numerically imposed on financial
information supplied by or constructed for the source. The
following format for control costs, if completed, will suffice
for all techniques that require this information. (As mentioned
earlier, it is assumed that control costs are available.)
0 Capital costs including installation
0 Yearly interest rate on those capital costs
0 Depreciation period in years (taxable life)
0 Annual operating and maintenance costs, including
insurance, general and administrative, but excluding
interest and depreciation
0 Byproduct recovery yearly value
0 Investment tax credit
Values for the above cost items should be entered into Table
5-2 by either the source operator or the control agency staff.
If the depreciation period cannot be given, then the Industrial
Revenue Code asset depreciation range (ADR) can be obtained from
the Federal tax manual. Since a range of figures is presented,
the midpoint of the range should be selected.
The method of computing annual depreciation and interest
expenses utilizes the capital recovery factor, which determines a
uniform annual series of payments for a given interest rate, and
life equals the initial capital expenditure.
5-24
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5.3.2.2 Debt Service Coverage Ratio—
The data required to perform the debt burden coverage anal-
ysis are specified in Tables 5-2 through 5-6. Table 5-2, pollu-
tion control cost, has been discussed. Tables 5-3 and 5-4 are
the profit and loss summaries for an existing and a new or ex-
panded plant, respectively. The portion of Table 5-5 that is
required for this analysis consists of lines 10 through 13; this
information, to be obtained from the plant (or a suitable
secondary source), consists of the future obligations, including
principal, interest, lease payments, and other long-term contract
obligations. Table 5-6 is the analytical table based on infor-
mation from Tables 5-2 through 5-5, and is used in the coverage
ratio computation.
The sources of data for Tables 5- 2 through 5-6 are as
follows. The data for Table 5-2 are assumed given. The data for
Tables 5-3 and 5-4 should come primarily from the plant. Second-
ary sources of information for constructing Tables 5-3 and 5-4
can be found in other studies and references. Other studies
include those previously conducted by the Environmental Protec-
tion Agency and the Occupational Safety and Health Administra-
tion. References for secondary source data would include the
Robert Morris Associates, the Troy Almanac, trade associations,
the Census of Manufacturers, the Federal Trade Commission, vari-
ous periodicals, and equipment suppliers to the industry. When
these studies and references will not provide all of the elements
of Tables 5- 3 and 5- 4, the analyst must use judgment or ask
members of industry or trade associations where to obtain the
necessary data. In some cases, rough estimates may be required
for such completions.
Table 5- 3, the profit and loss summary for an existing
plant, consists of 16 line items. The first eight are for the
basic net income data prior to the impact of pollution controls.
The first line calls for revenue data broken down by revenue from
5-25
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Table 5-3. PROFIT AND LOSS SUMMARY FOR
EXISTING PLANT
Most Recent 5 Years
"19 19 19 19 19
Revenue
a. From operations
b. From Non-operations
c. Total Revenue
2. Cost of Sales
a. Cost of Sales m
b. Pollution control expenses (existing) ^'
c. Total Cost of Sales
3. Gross Operating Profits
(l(c)-2(c))
4. Depreciation & Amortization
a. Pollution control (existing)(1)
b. Building and iirprovements
c. Transportation
d. Machinery and equipment
e. Other
f. Total Depr. & Amort.
5. Other Expenses
a. Selling, general & administrative
b. Taxes other than income tax
c. Research
d. Interest, existing obligations
e. Bad debt allowance
f. Long term lease payments (z>
g. Total Expenses
6. Net Income Before Tax
(3-(4(f)+5(g))
7. Income Taxes
a. State
b. Federal
c. Total Income Taxes
8. Net Income After Tax, Before Pollution
Control6-7(c)
(Computations below are only performed for column of most recent year unless
the source is in a cyclical business)
9. Annual Control Costs (from Table 5-2, Line 9)
10. Line 9 x (1-T)
T = (.48 if line 6 > $50,000)
T = (.22 if line 6 < $50,000 but * $25,000)
T = (.20 if line 6 <• $25,000)
(continued)
5-26
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Table 5-3 (continued).
11. Net Income After Tax and After Pollution
Control Without Product Price Increase (Line 8-Line 10)
12. Product Price Increase Under Full Recovery
(Annual Control Costs 4- Number of Units
Sold per year)
13. % of Full Price Recovery Possible x Line 10
14. Net Income After Tax, and After Pollution
Control With Product Price Increase
Lines 11 + 13)
If elasticity coefficient known and price increase expected
15.(3^A Profits = QAP x {I+T3---~)
16. Net Income After Tax and After Pollution Control
With Product Price Increase (Line 11 + (l-T)Line 15)
(1) Existing means expenses already being incurred for oonpliance to any air,
water, solid waste, radiation, etc. pollution control regulations
(2) Greater than one year
(3) Q = Quantity Products Sold
P = Avg. Product Selling Price
Revenue Line1 (c)
Quantity Products Sold (Q)
AP = increase in price (line 12)
E = elasticity coefficient
C - Unit variable costs = Lines 2+5vQ
5-27
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Table 5-4.
PROFIT AND LOSS SUJYLARY FOR NEW OR
EXPANDED EXISTING PLANT
First 3 Years of Operation
19 19 19
(1)
1. Revenue
a) Number Units Sold
b) Price Per Unit
(2)
c) Total Revenue
2. Cost of Sales
a) Purchased Materials
# @
(use supplementary sheets for each year
and for more materials if necessary)
b) Fuel Oil
Gals @ $
c) Natural Gas
cf@ $
d) Electricity
kwh @ $
e> I^or wage
Categories flhrs x Rate
(3)
f) Total Cost of Sales
3. Gross Operating Profits
(l(c) - 2(f))
4. Depreciation and Amortization
Depr.
Categories Cost Rate
Total Depreciation & Amortization
(4)
5. Other Esqr—
Category
Total Other Expenses
(continued)
5-28
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Table 5-4 (continue^) .
First 3 Years of Operation
19 19 19
6. Net Income Before Taxes
(3 - (4+5))
7. Income Taxes
Rates
Stipulated Avg.
a) State
b) Federal (5)
c) Total Income Taxes
8. Net Income After Taxes
(6 - 7(c)) __
9. Annual Control Costs
(from Table 5-2 Line 9
10. Line 9 x (1 - T)
T = (.48 if line 6> $50,000)
T = (.22 if line 6< $50,000 but> $25,000)
T = (.20 if line 6< $25,000)
11. Net Income After Tax and After Pollution
Control Without Price Increase
(Line 8 - Line 10)
12. Product Price Increase Under Full Recovery
(Annual Control Costs * number units sold
per year)
13. Percent of Full Price Recovery
'Possible x Line 10
14. Net Income After Tax and After Pollution
Control With Product Price Increase
(Line 11+13)
If elasticity coefficient known and price increase expected:
15. (6)A Profits = Q A P x (1 + E-^p)
16. Net Income After Tax and After Pollution
Control With Product Price Increase
(Line 11 + a ~ T) x Line 15)
(1) After initial construction period.
(2) Include supplementary sheets for multi-product plant.
(3) Including benefits.
(4) If allocated then describe the basis and calculations for allocation on
separate sheet.
(5) Provide separate schedule that reconciles difference between stipulated
and average rate.
(6) Q = Quantity Products sold; Revenue Line l(c)
P = Avg. ProductSelling Price = Quantity Products Sold(Q)
AP = Increase in Price (line 12) J
E = Elasticity Coefficient
C = Unit Variable Cost = Lines Q. + 5)* Q
5-29
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Table 5-5. INVESTED CAPITAL SUMMARY
NEW, EXPANDED OR EXISTING PLANT
Exist
Plant (^ New or Expanded Plant
3 Years of Operation
19 19 19 19
1. Property, Plant, Equipment and
Other Assets (Book Value)
(See bottom of Table D for details)
a. Land and minerals
b. Buildings and improvments
c. Machinery and equipment facilities
d. Pollution control (existing)
e. Transportation equipment
f. Other fixed assets (including long
term marketable securities)
h. Total Book Value
2. Current Assets
a. Cash on hand and deposit
b. Temporary cash investments
c. Trade receivables, net
d. Inventories
e. Other current assets
f. Total Current Assets
3. Current Liabilities
a. Trade accounts payable
b. Other expense accruals
c. Notes payable, current
d. Other current liabilities
e. Total current liabilities
4. Total Net Working Capital (Line 3 minus 2)
5. Total Investment (l(h)+4) Before Controls)
6. Total Invested Capital Without
Pollution ControT
a. Debt % $
b. Equity (Preferred & Camon Stock)
% $
c.Total % $
7. Pollution Control Capital Costs,
Book Value (From Table 5-2, Line 1)
(continued)
5-30
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Table 5-5 (continued).
Existing
Plant/1) New or Expanded Plant
First 3 Years of Operation
19 19 19
8. Total Investment After Controls (5+7)
9. Total Invested Capital With Pollution
Control
a. Debt % $
b. Equity (Preferred & Cannon Stock
% $
c. Total 100% $
(Figures Below Required Over Life of Pollution Control Equipment)
10. Current Installments on Long Term Debt
Without Pollution Control
a. Interest etc.
b. Principal etc.
11. Current Installments on Pollution
Control Debt
a. Interest etc.
b. Principal etc.
12. Lease Payments and Long Term Contracts etc.
13. Lines 10 + 11 + 12 etc.
List of Major Property, Plant and Equipment Items
Item Cost % Rate of Depreciation Item Cost % Rate of Depreciation
(1) Figures for existing plant do not have to include physical descriptions of
facilities if obtained from audited statements.
5-31
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Table 5-6. DEBT SERVICE ANALYSIS
Numerator of Debt Service Ratio
Denominator of Debt Service Ratio
I
OJ
FDR EXISTIN3 SOURCE BEFORE POLLUTION OONTROL
1. Net income, before taxes
and interest plus 1/3 x
lease payments, most
recent 5 years
2. Depreciation, most
recent 5 years
3. Sub-total (Cash Flow Fran
Operations)
4. Principal Payments, Next
5 years T (1-T)
5. Interest Payments, Next 5 years
6. Lease and Long Term Contract
Payments
7. Capital Expenditures for Re-
placement, Next 5 years -r(l-T)
8. Sub-Total
FOR EXISTING SOURCES AFTER POLLUTION OONTROL, WITH3UT PRICE INCREASES
9. Pollution Control, O&M
Costs (Line 7 - Line 8,
Table 5-2
10. Pollution Control Equip-
ment Depreciation
11. Line 3 (above)+Line 10
Line 9
12. Pollution Control Interest
Payments (Line 11(a) Table 5-5)
13. Pollution Control Principal
Payments (Line 1Kb) Table 5-5)
T (1-T)
14. Line 12 + 13
15. Line 8 (above) + 14
FOR EXISTING SOURCES AFTER POLLUTION COmTOL, WITH PRICE INCREASE
16. Line 13 or Line 15,
Table 5-3 or 5-4 x(l-T)
17. Line 11 (above) + Line 16
18. Line 14 (above)
-------
the operations of the basic business and additional revenues that
are ancillary to the main business of the plant or are sporadic
operations. The cost of sales category, line 2, consists of all
of the costs of producing the product. The value for line 3 is
the difference between lines 1 and 2. Line 4 consists of the
noncash flow, depreciation, and/or amortization amounts for the
various items of land, equipment, and buildings. Line 5 consists
of all of the other nonproduction expenses incurred by the
company, broken down into various categories as shown. Where
these or any other costs are allocated from other plants or
headquarters offices, the basis for the allocation should be
explained and quantified. Line 6 is the net income before tax,
which consists of line 3 minus lines 4 and 5. Line 7 is the
income tax burden for the net income before tax and line 8 is the
net income after tax but before the impact of pollution controls,
Lines 9 through 16 call for three different net income com-
putations. The computation on lines 10 and 11 assumes that the
pollution control costs are totally absorbed by the company with
no product price increase and therefore that profits are de-
creased by the amount of the annual control costs times one minus
the marginal income tax rate. The computation on lines 12
through 14 assumes that there is a price increase of a percent-
age, perhaps 100, of the product price increase that would be
necessary to fully recover the cost of the pollution control
equipment. This computation assumes that an elasticity coeffi-
cient is not available and that the analyst would use judgment as
to what percent of the full product price recovery is possible.
Lines 15 and 16 of Table 5-3 determine profits when an elasticity
coefficient is known and when a price increase is expected.
Table 5-4 is a profit and loss summary for a new or an
expanded existing plant. The line items 1 through 16 are the
same as those of Table 5-3. The difference in Table 5-4 is
largely in lines 1 through 7, which present the various revenue
5-33
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and cost items. The primary difference is that the entries in
Table 5-4 require physical input data, which are then factored by
costs to determine the financial result. This method can be used
by itself as the sole financial forecast, or it can be used to
verify any strictly financial forecast provided by the source for
the various line items.
The primary source for these line item inputs is the plant
source under consideration. Secondary sources of information
would be the various studies and references mentioned earlier.
Table 5-5, applicable to an existing or new plant, calls for
invested capital data for such plants. The lines that are
necessary for the performance of the debt service coverage anal-
ysis are lines 10 through 13, explained above.
Table 5-6 is for the debt service coverage analysis, which
brings together the elements of the previous tables. As ex-
plained in Section 5.2, the debt service coverage is a ratio, the
numerator of which is the cash flow from operations and the
denominator of which is the future debt burden. Table 5-6 is
divided into three parts: the ratio before pollution control
impacts, the ratio after pollution control impacts but without a
price increase, and the ratio after pollution control and with a
price increase.
The table is to be read as if there are two columns. The
column on the left represents the numerator of the debt service
coverage ratio and the column on the right, the denominator.
Lines 1 through 3 of the left-hand column in the before-pollu-
tion-control situation show that the cash flow consists of the
net income before taxes and interest payments plus one-third
times any lease payments that might be present and depreciation.
The reason for multiplying the lease payments by one-third is to
approximate the interest that is part of those lease payments.
Lines 4 through 8 of Table 5-6 in the before-pollution-
control situation lists the obligations, consisting of principal
5-34
-------
payments, interest payments, lease payments, other long-term
contracts, and the capital expenditures necessary for replacement
items. The principal and capital expenditures payments are
divided by one minus the marginal tax rate in order to compute
the amount of after-tax cash flow that pays for capital expendi-
tures and principal payments. The division by one minus the
marginal tax rate gives the appearance of making the principal
payments larger than they actually are. The division is neces-
sary, however, to make both sides comparable from a tax stand-
point. If the left-hand part of the table could have been
presented on an after-tax basis, the division would not have been
necessary.
A question arises in this analysis in conjunction with the
cash flow from depreciation and the capital expenditures for
replacement. The question is whether the agency would wish to
force the operators of source to forego replacement expenditures
and use the cash flow that would have gone for these expenditures
to meet the principal interest and lease payment obligations. If
the agency would not like to make that assumption, then it may
want to consider making the future yearly capital expenditure
levels equal to the depreciation funds. The effect of this is to
make lines 2 and 7 cancel each other.
The second section of Table 5-6, left hand column, computes
the cash flow from operations after the occurrence of pollution
control costs. This cash flow is then compared with the adjusted
cash flow, right hand column, from line. 8 above, which consists
of adding the pollution control interest payments and the princi-
pal payments, the latter divided by 1 minus the marginal tax
rate.
The next section provides a similar analysis for the impact
after pollution control where a price increase does occur. The
left-hand column adjusts the cash flow from operations for the
additional revenue from the price increase, and the right-hand
5-35
-------
column does not adjust the payments, but has them equal to line
14 of the second part of the table.
The coverage ratios can be computed in more than one way.
The analyst may wish to average the last 5 years with the next 5
years. This has the effect of dampening out any cyclical effects
in operation of the source. Or, the analyst may wish to choose
the funds flow from operations for the most recent year, if he
considers it more representative than the previous years, and
compare that level with future years.
The analyst may wish to account for inflation in adjusting
the ratio. If it appears that the plant under consideration is
increasing earnings on a real basis (i.e., after inflation), then
the analyst may wish to adjust the cash flows of the previous
years by a rate of inflation to more accurately compare past and
future cash flows.
Concerning the decision criteria, if the ratio is greater
than 2.0, it is considered that cash flow is adequate to cover
the future obligations. A ratio of 1.5 to 2.0 indicates that the
cash flow is probably adequate to cover future obligations, but
that some risk is inherent. As a criterion for this technique, a
numerical figure of less than 1.5 was chosen as the level below
which the cash flow is not considered adequate to cover debt-
burden and therefore as the level that constitutes significant
impact. The benefit of performing this calculation for condi-
tions before pollution control is that the analyst can identify
those cases where a significant impact may not occur even though
the ratio after pollution control is less than 1.5 but greater
than 1.0. This situation would occur where the plant source is
accustomed to operating at such a ratio.
The analyst also needs to determine whether the source has
"unproductive" long-term assets that can be sold to finance the
pollution control equipment. Such assets would appear in Table
5-5, line l(f) (see next section for the explanation of Table
5-5).
5-36
-------
The analyst should note that the values developed for many
lines of the various tables are not entered into the final calcu-
lations in application of an analysis technique. In some cases,
therefore, it is not necessary to know the breakdown of certain
line items, or the analyst may wish to obtain information only
for critical line items of the tables, as long as the information
is highly accurate. Sometimes, the "extra" lines serve as a
validation or as input for compiling values for other lines.
5.3.2.3 Return on Investment (ROI) Ratio--
Tables 5-2 through 5-5 and Table 5-7 are necessary to per-
form the Return on Investment (ROI) technique. Tables 5-2
through 5-4 are to be completed as described above. Lines 1
through 9 of Table 5-5 are to be completed for this analysis.
These lines consist of the asset values of the plant source, to
be reported at book value. The best source for these data would
be other EPA or OSHA impact studies performed on the industry,
plus the sources referenced earlier. Line 1 is for long-term
assets; lines 2 and 3 are current assets and current liabilities,
respectively. Line 4 is the difference between lines 2 and 3,
which is called Net Working Capital. Line 5 is the total invest-
ment value of the plant without the pollution control expenditure
*
under consideration. Line 5 is the sum of lines 1 and 4. Line 6
calls for a listing of the invested capital of the source divided
into the debt and equity portions. (In calculation of debt
amounts, deferred taxes should be treated as a debt item if it
appears that in the next few years the amount of deferred taxes
will decrease; otherwise they are to be treated as equity.) In
addition to dividing debt and equity by their percentage contri-
butions to the total, the absolute dollar value should also be
listed as a subcategory of line 6. Line 7 is pollution control
capital costs taken from Table 5-2. Line 8 is the total of
assets before pollution control. The debt to equity breakdown in
5-37
-------
Table 5-7. ROI SUMMARY FOR NEW, EXPANDED OR EXISTING PLANT
1. Net Income After Taxes, Before Controls
a". Existing (Line 8, Table 5-3)
b. New or Expanded (Line 8, Table 5-4)
2. Investment: Fixed Assets Plus Net
Working Capital (Lines 1 + 4,Table 5-5^
3. ROI Before Controls (1 4 2)
4. Total Investment with Controls
(Line 2 (above) + Line 1 (Table 5-2)
5. Net Income After Taxes, After Controls
Without Price Increase
a. Existing (Line 11, Table 5-3)
b. New (Line 11, Table 5-4)
6. ROI After Controls Without Price
Increase (5 - 4)
7. Net Income After Controls With Price
Increase
a. Existing (Line 14 or 16, Table 5-3)
b. New (Line 14 or 16, Table 5-4)
8. RQI After Controls With Price
Increase 744)
Existing
Plant
19
xxxxxx
xxxxxx
xxxxxx
Year 1,2 or 3 of Operations
New or Expanded Plant
19
xxxxxx
xxxxxx
xxxxxx
5-38
-------
percentage and dollar amounts should be presented here as a
subcategory of line 9.
Table 5-7 is the analytical table for which the analysis of
ROI is performed. ROI is essentially a fraction, the numerator
of which is an income figure, the denominator of which is an
asset figure. Table 5-7 presents the ROI before pollution con-
trol in lines 1 through 4 for existing and for new or expanded
plants. Lines 5 and 6 are for computing the ROI after the
occurrence of the pollution control expenditure without a price
increase to cover the cost of pollution control. Lines 7 and 8
are for the ROI calculation with a price increase.
There are no established criteria for determining when the
percentage change in ROI or the absolute ROI is to be considered
as being significantly impacted by pollution controls. As des-
cribed earlier, the analyst should first compare ROI with the
plant's threshold rate of ROI for new investments. If that rate
is not obtainable, the analyst should obtain an average ROI for
the industry or, lastly, should obtain the firm's cost of funds
for the next financing.
5.3.2.4 Discounted Cash Flow (DCF)—
To perform the Discounted Cash Flow technique, the analyst
must complete Tables 5-2 through 5-4 plus Tables 5-8 and 5-9.
Table 5-8 is a preliminary to the analysis conducted in Table
5-9.
The first line of Table 5-8 calls for an extrapolation of
net income after tax, pollution controls, and price considera-
tions plus interest payments over a period of years equal to the
useful life of the control equipment. The analyst should use a
text on extrapolation to determine which extrapolation procedure
would be most applicable to the data at hand. Line 2 of Table
5-8 calls for the liquidated value of the plant. The liquidated
value of a plant can be considered as the current book value of
5-39
-------
Table 5-1
INFORMATION FOR VALUE ANALYSIS FOR NEW, EXPANDED,OR EXISTING PLANT
Ul
I
1. Extrapolation of Net Inccme After Tax After Controls,
With or Without Price Increase Plus Interest Payments
for Number of Years Bqual to Control Bquipment Life
(Lines 11, 14 or 16, Tables 5-3 or 5-4 + Line 5, Table 5-3 or 5-4
etc.
2. Liquidated Value
a. New Source =
b. Expanded or Existing Source =
3. Terminal Value
4. Cost of Equity = 15% (I-T) or =
JCurrent book value of assets (Line 1 (h)
~ unless appraisal obtained frcm source.)
(Require source to document estimate)
Line 4 , liable 5-5)
Net Incone after Controls with or without price increase
(Line 11, 14 or 16, Table 5-3 or Line 11,14 or 16,TabloJ5--4--
Market value of Equitey (See financial text tor computation
5. Weighted Average Cost of Capital (C)
McLI.Js.cT_ Vd-HJc ui- 04 vu. i-^y \ ^.K-n— J-J-IILUI^.^"^ i .
or if pvtolicly owned company use eaminqs oer share t stock once)
(1)
(2) (3)
(4)
Cost or
Interest
RateilOO
(5)
Qjuity
Debt or
Preferred
Stock
II
#2
#3
In
J f 100
100
100
100
100
100%
Cost
(From
Line 4)
Total
= (C) Weighted Avg.
Cost of Capital
-------
Table 5-9. PRESENT VS. FUTURE VALUE ANALYSIS FOR NEW, EXPANDED, OR EXISTING PLANT
Pollution Control Equipnent #1 |2 |3 |4 |5 ... #n
Depreciable Life Years (n) 19 19 19 19 19 ... 19
1. Net Inocme After Tax After
Controls, With or Without
Price Increase Plus Interest
Payments (Line 1, Table 5-8)
2. Plus: Pollution Control
Depreciation (Line 5, Table 5-2)
Subtotal
3. Less: Each year's current
Portion of long-term debt
plus leases (Line 13, Table 5-5)
4. Less: Future new enviromental
Annualized Pollution Control
Expenditures x (1-T) + Depr.
5. Net Cash Flow
6. Discount Rate (l+C)n (C is from
Line 5, Column 5, Table 5-8)
7. Discounted Cash Flow (5 4- 6)
Total of
Line 7
(1) (1+C) numbers under each line are not
divisors, they are descriptive of
number to be entered on line.)
8. Terminal Value T (l+C)n
9. Investment Tax Credit (line 10,Table 5-2)
10. Sub-total (7+8+9) ~
11. Less Liouidated Value ~
12. Present Value ~~
-------
the fixed assets plus the net working value, both figures being
taken from Table 5-5. If the agency so desires, a source can be
asked to provide its own appraisal of the liquidated value of its
assets and net working capital. Such an appraisal would require
documentation as to the basis for the amount provided. Line 3 of
Table 5-8 is the terminal value, that is, the value of the plant
at the end of the useful life of the pollution control equipment.
If it is difficult for the source to estimate such a value, the
analyst may wish to take the present liquidated value of the
plant and increase the figure by an appropriate inflationary
rate. The analyst may use discretion as to whether to use the
results of the figure shown in the second part of line 4 or to
use an arbitrarily high figure, such as 15 percent before tax if
the plant is in financial difficulty. The arbitrary figure is
based on the fact that the inherent cost of equity capital for a
marginal plant is really at least 15 percent before tax in order
to attract capital. Line 5 of Table 5-8 calls for calculation of
the weighted average costs of capital. The capital consists of
the equity cost plus the cost of the various debt or preferred-
stock issues. These are to be computed on an after-tax basis.
The various volumns of line 5 indicate the calculations needed, to
derive the weighted average costs of capital. In the event that
deferred taxes are included in the capital items, the cost of
such capital is to be considered zero.
Table 5-9 contains the calculations for computing the dis-
counted cash flow technique. The period over which the calcula-
tions are to be performed is equal to the depreciable life of the
pollution control equipment. The future value of the plant
consists of the net income over the useful life of the pollution
control equipment plus the cash flow that will be available from
depreciation of the pollution control equipment. To be deducted
from those amounts are the obligations of the company plus future
pollution control expenditures. These pollution control expendi-
tures are other than the one under consideration and should only
5-42
-------
be those for which the company has already entered into a con-
tract. Additional pollution control expenditures not contracted
for could be added at the discretion of the analyst if they are
verifiable. The results of these calculations thus far will be a
net cash flow for each of the years of the pollution control
equipment's useful life. These future cash flows must be dis-
counted to a present value by dividing each yearly figure by a
compounded weighted average cost of capital, as shown in the
appropriate line, The results are discounted cash flows for each
year, which are summed to the right of Table 5-9. Added to these
discounted cash flows are the terminal value of the plant, appro-
priately discounted, and the investment tax credit from the
pollution control investment under consideration. To be deducted
from this amount is the liquidated value of the plant as if
liquidated today. If the result is greater than 0, the plant
would decide to continue operations with the pollution control
equipment installed. If the value is less than 0, the plant
would decide, in rational decision-making theory, that greater
profits are to be gained elsewhere. Thus, significant impact is
considered to occur when the value is less than 0.
5.3.2.5 Previous Impact Studies—
The analyst should obtain a list of the industry economic
impact studies available from EPA's Office of Water Programs and
Office of Air Quality Planning and Standards. The analyst may
also wish to contact OSHA for industry impact studies.
Since the sizes of the plants analyzed in such economic
impact studies are likely to be different from that of the plant
under consideration, it will be necessary to scale the control
costs for the plants in the economic impact studies to the size
of the plant being analyzed or vice versa. Scaling can be done
with the aid of another EPA publication (available from the
5-43
-------
Office of Air Quality Planning and Standards), Capital and
Operating Costs of Selected Air Pollution Control Systems, EPA-
450/3-76-014, May 1976.
In addition to scaling the control costs the analyst may
also need to update the control costs, since some of the EPA
economic impact studies may be up to 5 years old. Appropriate
indices for updating those control costs are the Marshall and
Swift (M&S) indices published by McGraw-Hill in Chemical Engi-
neering.
As mentioned earlier, the analyst must use judgment to
determine whether the two sets of control costs being compared
justify a judgment concerning the impact of the proposed expendi-
tures on the plant in question. There are no established criter-
ia for the analyst to follow in making such judgment.
The earlier EPA economic impact studies will also be helpful
in application of several of the other analysis techniques.
5.3.2.6 Financing Decisions by Others—
This analysis technique is applicable only to a source that
is alleging difficulty in making the pollution control expendi-
tures because of the inability to obtain financing. The tech-
nique cannot be used to anticipate the impact of air pollution
control costs on a source.
First a determination of the size (number of employees) and
the business Standard Industrial Classification code (SIC) of the
company (not solely the plant) must be made to determine whether
the source is eligible for an SBA loan. The plant is the best
source for this information on number of employees and SIC. A
phone call to the nearest SBA office will determine whether the
company is indeed a small business. If the company is involved
in more than one line of business the percent of sales for each
line must be supplied to SBA.
5-44
-------
If the business is small by SBA standards, it should be
directed to apply for one of the pollution control programs of
the Small Business Administration, described in Section 5.3.1.
If a determination is made by the SBA that the source is refused
financing solely because of the pollution control expenditure in
question, then significant impact has been determined. The
necessity for attributing the rejection to the pollution control
expenditure is that there are many other reasons why any loan
could be refused by any type of lending organization. Even
without the impact the company would not have received financing;
other possible reasons for refusal are lack of SBA funds, improp-
er application documentation, management difficulties, or the
inability to make a determination. The entire SBA application
process may require 60 to 120 days.
If the company does not meet the SBA definition of small, it
should be directed to obtain at least two letters of financing
refusal from commercial financing organizations. Again, these
organizations should state the refusal is attributable to pollu-
tion control costs.
This method does not adhere to the definition of "plant"
#
given earlier because any financing organization looks to the
entire company, and not just the plant, as security repayment of
a loan.
5.3.2.7 Increase in Operating Expenses or Assets—
For analysis of cost increases attributable to pollution
control that could lead to significant impact, the analyst must
complete Tables 5-2 through 5-5, explained earlier. The cost of
pollution control, i.e., annual control costs, is to be compared
with lines 2, 4, and 5 of Tables 5-3 or 5-4, depending upon
whether the plant is existing or new. These line items consist
of plant expenses. If the annual control costs are greater than
30 to 40 percent after accounting for price increases, the sig-
nificant impact may be thought to occur.
5-45
-------
In the event that the analyst wishes to compare the fixed
capital costs increase from pollution control expenditures, the
first line of Table 5-2 should be compared with the first line
[l(h)j of Table 5-5. The percentage increase deemed to be sig-
nificant in this case is higher, i.e., 40 to 50 percent, because
of the normal situation in which a new plant may have a signifi-
cant portion of its cost devoted to pollution control expendi-
tures. The figures of 30 to 40 percent for an expense increase
and 40 to 50 percent for an asset increase are not based on any
recognized criteria. The analyst may wish to use judgment to
modify these expenditure levels.
5-46
-------
APPENDIX A
A-l
-------
Table A-l. CHEMICAL ENGINEERING PLANT AND EQUIPMENT COST INDEXES'
Index
CE plant index
Engineering and
supervision
Building
Construction labor
tquipment, machinery
supports
Fabricated equipment
Process machinery
Pipe, valves, and
fittings
Process instruments
and controls
Pumps and compressors
Electric equipment
and materials
Structural supports,
insulation, and paint
1969
Annual
119.0
110.9
122.5
128.3
116.6
115.1
116.8
123.1
126.1
119.6
92.8
112.6
1968
Annual
113.6
108.6
115.7
120.9
111.5
109.9
112.1
117.4
120.9
115.2
91.4
105.7
1967
Annual
109.7
107.9
110.3
115.8
107.7
106.2
108.7
113.0
115.2
111.3
90. 1
102.1
1966
Annual
107.2
106.9
107.9
112.5
105.3
104.8
106.1
109.6
110.0
107.7
86.4
101.0
1965
Annual
104.2
105.6
104.5
109.5
102.1
103.4
103.6
103.0
106.5
103.4
84.1
98.8
1964
Annual
103.3
104.2
103.3
108.5
101.2
102.7
102.5
101.6
105.8
101.0
85.5
98. 3
1963
Annual
102.0
103.4
102.1
107.2
100.5
101.7
102.0
100.7
105.7
100.1
87.6
97. 3
1962
Annual
101.5
102.6
101.4
105.6
100.6
101.0
101.9
100.6
105.9
101.1
89.4
99.2
1961
Annual
102.0
101.7
100.8
105.1
100. 2
100. 1
101. 1
101. 1
105.9
100. 8
92. 3
99.8
1960
Annual
101.8
101.3
101.5
103.7
101.7
101.2
108.1
104.1
105.4
101.7
95.7
101.9
1959
Annual
101.8
102.5
101.4
101.4
101.9
100.9
101.8
103.3
102.9
102. 5
101.0
101.6
1958
Annual
99.7
99. 3
99.5
100.0
99.6
99.6
100.1
98.8
100.4
100. 0
100.6
100.4
1957
Annual
98.5
98.2
99.1
98.6
98.5
99. 5
98.1
97.9
96.7
97.5
98.4
98.0
I
to
From Card, Inc., Reference 2. More details on other cost indexes are available from this manual.
(continued)
-------
Table A-l (continued).
Index
CE plant index
Engineering and
supervision
Building
Construction labor
Equipment, machinery
supports
Fabricated equipment
Process machinery
Pipe, valves, and
fittings
Process instruments
and controls
Pumps and compressors
Electric equipment
and materials
Structural supports,
insulation, and paint
1977
Annual
204.1
161.7
197.2
176.8
218.8
212.8
210.1
247.3
201. 5
238.8
159.2
223.6
1976
Annual
. 191.1
150.7
185.3
172.9
205.0
198.5
196.9
235.1
192.5
221.2
147.6
206.7
1975
Annual
182.3
141.8
176.9
168.4
194.7
192. 2
184.7
217.0
181.4
208.3
143.0
198.6
1974
Annual
165.4
134.4
165.5
163.4
171.2
170.1
160.3
192.2
164.8
175.7
126.4
172.4
1973
Annual
144.1
122.8
150.6
157.9
141.9
142.5
137.6
151.3
147.1
139.5
104.2
140.9
1972
Annual
137.2
111.9
142.0
152.2
135.4
136.3
132.1
142.9
143.8
135.9
99.1
133.6
1971
Annual
132.3
111.4
135.5
146.2
130.4
130.3
127.1
137.3
139.9
133.2
98.7
126.6
1970
Annual
125.7
110.6
127.2
137.4
123.8
122.7
122.9
132.0
132.1
125.6
99.8
117.9
From Card, Inc., Reference 2.
this manual.
More details on other cost indexes are available from
-------
Table A-2. CAPITAL RECOVERY FACTORS
Equipment
life, yr
1
2
3
4
~
5
6
\J
7
8
U
9
10
11
_I_ ~L
12
_1_ £i
13
14
15
16
17
18
19
20
21
22
23
24
25
Annual compounded interest, %
5
1. 05000
0. 53780
0. 36721
0. 28201
0.23097
0. 19702
0. 17282
0. 15472
0. 14069
0.12950
0. 12039
0.11283
0.10646
0.10102
0.09634
0. 09227
0. 08870
0.08555
0.08275
0.08024
0.07800
0.07597
0.07414
0.07247
0.07095
6
1.06000
0.54544
0.37311
0.28859
0.23740
0.20336
0.17914
0.16104
0.14702
0.13587
0.12679
0.11928
0.11296
0.10758
0.10296
0.09895
0.09544
0.09236
0.08962
0.08718
0.08500
0.08305
0.08128
0.07968
0.07823
7
1.07000
0.55309
0.38105
0.29523
0.24389
0.20980
0.18555
0.16747
0.15349
0.14238
0.13336
0.12590
0.11965
0.11434
0.10979
0.10586
0.10342
0.09941
0.09675
0.09439
0.09229
0.09041
0.08871
0.08719
0.08581
8
1.08000
0.56077
0.38803
0.30192
0.25046
0.21632
0.19207
0.17401
0.16008
0.14903
0.14008
0.13270
0.12652
0.12130
0.11683
0.11298
0.10963
0.10670
0.10413
0.10185
0.09983
0.09803
0.09642
0.09498
0.09368
10
1.10000
0.57619
0.40211
0.31547
0.26380
0.22961
0.20541
0.18744
0.17464
0.16275
0.15396
0.14676
0.14078
0.13575
0.13147
0.12782
0.12466
0.12193
0.11955
0.11746
0.11562
0.11401
0.11257
0.11130
0.11017
12
1.12000
0.59170
0.41635
0.32923
0.27741
0.24323
0.21912
0.20130
0.18768
0.17698
0.16842
0.16144
0.15568
0.15087
0.14682
0.14339
0.14046
0.13794
0.13576
0.13388
0.13224
0.13081
0.12956
0.12846
0.12750
15
1.15000
0.61512
0.43798
0.35027
0.29832
0.26424
0.24036
0.22285
0.20957
0.19925
0.19107
0.18448
0.22526
0.21689
0.17102
0.16795
0.16537
0.16319
0.16134
0.15976
0.15842
0.15727
0.15628
0.15543
0.15470
20
1.20000
0.65455
0.47473
0. 38629
0.33438
0.30071
0.27742
0. 26061
0.24808
0. 23852
0.23110
0. 22526
0.17911
0.17469
0.21388
0.21144
0. 20944
0.20781
0.20646
0.20536
0. 20444
0.20369
0.20307
0.20255
0.20212
(continued)
-------
Table A-2 (continued).
i
Ui
Equipment
lire, yr
26
27
28
29
30
31
32
33
34
35
40
45
50
5
0.06956
0.06829
0.06712
0.06605
0.06505
0.06413
0.06328
0. 06249
0. 06176
0.06107
0.05828
0. 05626
0.05478
Annual compounded interest, %
6
0.07690
0.07570
0.07459
0.08385
0.07265
0.07179
0.07100
0.07027
0.06960
0. 06897
0.06646
0.06480
0.06344
7
0.08456
0.08343
0.08239
0.08145
0.08059
0.07980
0.07907
0.07841
0.07780
0.07723
0.07501
0.07350
0.08246
8
0.09251
0.09145
0.09049
0.08962
0.08883
0.08811
0.08745
0.08685
0.08630
0.08580
0.08386
0.08259
0.08174
10
0.10916
0.10826
0.10745
0.10673
0.10608
0.10550
0.10497
0.10450
0.10407
0.10369
0.10226
0.10139
0.10086
12
0.12665
0.12590
0.12524
0.12466
0.12414
0.12369
0.12328
0.12292
0.12260
0.12232
0.12130
0.12074
0.12042
15
0.15407
0.20176
0.20122
0.20102
0.20085
0.15200
0.15173
0.15150
0.15131
0.15113
0. 15056
0.15028
0.15014
20
0.20176
0.15353
0.15306
0.15265
0.15230
0.20070
0.20059
0. 20049
0 20041
0.20034
0. 20014
0.20005
0.20002
-------
Table A-3 CAPITAL COST ESTIMATION
Equipment
item
Purchase
price
Direct
cost factor'
Direct
costb
Equipment
cost0
Total
direct
costd _
A. Total direct costs
B. Total indirect costs at 38% (A)
C. Contingencies at 15% (A + B)
Total capital costs
(A + B + C)
From Tables 4-1, 4-2, and 4-3.
Includes equipment cost and installation, instrumentation,
electrical work, foundations, structural work, site work,
painting, piping, and labor.
Sum of equipment purchase prices.
Sum of individual direct costs.
Includes engineering, contractor's fee, interest during
construction, shakedown, spares, freight, taxes, offsite,
and field and labor expenses.
A-6
-------
Table A-4. SUMMARY OF PREDESIGN ESTIMATE OF ANNUALIZED COSTS
DIRECT
I.
II.
Item
OPERATING COST
Utilities
Raw materials
Electricity
Water
Steam
Gas
Fuel oil
Operating labor
Direct labor
Supervision
Unit
$
$
$
$
$
$
$
15%
cost
/ton
/kWh
/103 gal
/103/lb
/106 Btu
103 gal
/man-hour
direct labor
Quantity Cost
tons/yr
kWh
103 gal/yr
103 Ib/yr
106 Btu/yr
103 gal/yr
man-hours/h
operation
III. Maintenance (see Tables 4
Labor and materials
Supplies
Replacement parts
IV. Sludge disposal
V. Wastewater treatment
FIXED COSTS
I. Taxes, insurance, over-
head, etc.
II. Capital recovery charges
PRODUCT RECOVERY CREDIT
-6, 4-7)
$
$
/ton
/103 gal
tons/yr
103 gal/yr
4% of total capital investment
% of total capital investment
TOTAL FIXED COSTS
$ /ton tons/yr
TOTAL ANNUALIZED COSTS
-------
PLANT AND PROCESS PARAMETERS
Type of process:.
Production capacity, tons/h.
Throughput capacity, tons/h
Annual production, tons/h
Operating time, h/yr
Emission limitation, Ib/h
gr/scf
Estimated length of ductruns, ft
Space limitations:
Other limitations/restrictions:
A-8
-------
EMISSION DATA SUMMARY
Parameter
High
Variation
average
Low
Gas flow rate, acfm
Temperature, °F
Moisture content, % V
Grain loading, gr/scf
Particle size distribution
% W < vim-
Gas analysis
% V 02
% V C02
% V CO
% V SO
x
% V N,
Uncontrolled emission
rate, Ib/h
gr/scf
Emission limitation,
Ib/h
gr/scf
A-9
-------
SUMMARY OF PREDESIGN CAPITAL COST ESTIMATES
>
I
Equipment
item
Footnotes :
Design
basis
Capacity/
size
Cost sources
and basis
Bare
cost
Installation
factor
Direct
installed
cost
A. Total direct cost
B. Total indirect cost
% A
C. Contingency 20% (A+B)
Total capital cost
-------
APPENDIX B
SAMPLE COST ESTIMATES
FOR AN AIR POLLUTION CONTROL SYSTEM
USING THE COST ESTIMATING PROCEDURE
B-l
-------
DESIGN DATA FOR THE CONTROL SYSTEM
Process Parameters
Type: Reverberatory furnace
Production capacity: 45 Mg/h (50 TPD)
Operating time: 6000 h/yr
Emission limit: 3.6 kg/h (7.9 Ib/h)
Ductwork: 110 feet total
Solid waste disposal: landfill in sealed barrels
Emission Characteristics
Exhaust volume: 18.4 m3/s (39,000 acfm)
Temperature: 1090°C (2000°F)
Emission rate: 83 kg/h3(183 Ib/h) particulate matter
Grain loading: 5.7 g/m (2.5 gr/scf)
Particle size: Majority between 0.03 - 0.5 ym
Control System Design
Shaker-type fabric filter
Superficial velocity, 1.2 cm/s (2.5 ft/min)
System pressure drop, 1.8 kPa (7 in. H20)
Efficiency, greater than 99 percent
Annual labor, 2000 h
B-2
-------
PUMP FAN
30ftLINED 300 gpm '
39,000 acfm / ' \
t 2000°F *" QUENCH
TOWER
CD *"
w 30 gpm
Mni/rim
RbVLRBLRAIOkY MAKLUI »•
FURNACE
' 20 ft 20 ft A-X ^20 ft
18,000 acfm / J INSULATION
250°F / 1
SHAKER-TYPET
FABRIC-FILTER DISPQSAL
300-GAL
HOLD TANK
A/C = air-to-cloth ratio.
Figure B-l. Control system diagram for reverberatory furnace.
-------
CAPITAL COST ESTIMATE
A. QUENCH TOWER
A carbon steel quench tower is required to cool the
exhaust gases from 2000° to 250°F. The following design
specifications and purchase costs were obtained from a
Croll-Reynolds representative:
Exhaust volume - 39,000 acfm
Diameter of tower - 10 ft
Depth of packing - 3 ft
Pressure drop - 2 in. H20
Height of tower - 16 ft high
Liquid flow rate - 300 gpm water
Purchase cost - $26,000
Prices are in mid-1977 dollars and include vessel, spray
heads, controls, arid supports.
Refractory lining for the tower is estimated at $50 per
ft installed. The lining is 4 in. thick, and a total of
220 ft of refractory brick is needed at an installed cost
of $11,000.
Direct cost factor =3.0 (Table 4-2)
Purchase cost = $26,000
Total direct costs
Tower $78,000
Lining 11,000
Total $89,000
B. PUMP SYSTEM
A cast iron centrifugal pump capable of handling 300
gpm at 100 ft head is required for the gas cooling system.,
A 20-hp pump system was previously purchased from an Ingersoll-
B-4
-------
Rand supplier in 1971 for $1000. The price included the
base, couples, and motor. This application requires a 15-hp
pumps system, arrived at in the following manner:
(gpm) (ft head) _ 300 (100)
horsepower = 3g87 (efficiency)~3387 (0.5)
= 15 hp
The price of the 15-hp pump in 1977 is estimated as follows:
Purchase price = (^TR^ ' x $100° x irllf = $130°
The direct cost factor is 2.4 (Table 4-2).
Direct cost =2.4 ($1300) = $3100
C. HOLD TANK
It is estimated that 30 gpm of water will be lost and
must be made up on a continuous basis. A retention tank of
10-min capacity (300 gallons) is required. Carbon steel
construction is adequate. A 1968 purchase price of $4270 is
obtained from a technical journal. The CE indexes yield an
estimated 1977 price of $6900. The direct cost factor of
2.0 is applied and results in a total direct cost of $13,800.
D. FABRIC FILTER
A shaker-type fabric filter is selected as the desired
control. The exhaust gas volume at the inlet is 18,000 acfm
at 250°F. Purchase costs were obtained from Fisher Kloster-
inann for the following specifications:
Air-to-cloth ratio of 2.5
Dacron bags
7500 ft2 cloth area
Insulation, shaker units, bags, ladder,
supports, hopper, factory assembly
Purchase price = $22,500
B-5
-------
Direct cost factor =2.0 (Table 4-1)
Direct cost = $45,000
E. FAN SYSTEM
The system pressure drop is predicted at 7 in. E^O
during normal operation. At 18,000 acfm capacity, the fan
is sized at 35 hp in the following manner:
, (acfm) (pressure drop, in. H0O)
horsepower = -- 6356 (efficiency) - 2~
~ 6356 (0.6)
From a compilation of fan system purchase prices, the
1977 price is estimated to be $2600 for a motor, starter,
and drive of carbon steel construction.
A direct cost factor of 2.5 is applied and results in a
total direct cost of $6500.
F. DUCTWORK
Approximately 50 ft of 1/4 in. carbon steel ductwork
lined with refractory is required for the duct run from the
furnace to the quench tower. Recommended velocity through
the ductwork is 400 ft/min. A price of $1.50/lb of installed
carbon steel ductwork was obtained from a construction cost
manual .
An additional 60 feet of ductwork is needed between the
quench tower and stack.
i f4-2 39,000 acfm _ Q .,,- f 2
A = cross-sectional area, ft = "4000 fpm -- 9.75 ft
, .1/2 , ,Q -,r\
ri- 4 A 4(9.75) _ „
D = diameter, ft = — =— = -- ^ - = 3.52 ft
A 42-in. -diameter duct of 1/4 in. carbon steel is selected.
2
The weight is 5.5 Ib/ft and the length is 50 feet.
B-6
-------
Total surface area, ft = (length) (diameter) n
= 50 (42/12) n = 550 ft2
Because the temperature in this duct run is 2000°F, a refrac
tory lining is installed at a cost of $50/ft3. A 4-in.
thickness is recommended by the supplier.
Installed cost = 550 ft2 (~- ft) $50/ft3 = $9200
The 60-ft duct run from the quench chamber to the stack is
1/4-in. carbon steel. An exhaust volume of about 18,000
acfm is handled at a velocity of 400 fpm.
Dieters, ft = -foi -2.5ft
Total surface area, ft2 = 60 (2.5) n = 471 ft2
The direct costs for ductwork installation is calculated
at $1.50/lb.
2 ••)
Total surface area, ft = 471 + 550 = 1021 ft .
Total weight, Ib = 1021 ft2 (5.5 lb/ft2) = 5600 Ib
Direct cost for ductwork = 5600 ($1.50) = $ 8,400
Direct cost for refractory = 9,200
Total direct cost = $17,600
The material portion of ductwork is $3200.
G. INSULATION
The ductwork from the quench tower to the fabric filter
and the fabric filter itself must be insulated. Mineral
wool insulation 4 in. thick and an aluminum casing are
needed for about 3000 ft2 of surface area (estimated from
ductwork and fabric filter dimensions). The direct costs
are estimated from a construction cost manual at $7.50/ft2.
B-7
-------
Table B-l. SUMMARY OF CAPITAL COSTS
Item
A. Quench tower and
refractory lining
B . Pump system
C. Hold tank
D. Fabric filter
E. Fan system
F. Ductwork
G. Insulation
H. Refractory
Equipment and
material
purchase cost
$ 26,000
1,300
6,900
22,500
2,600
3,200a
8,700a
5,100b
Direct cost
factor
3.0
3.5
2.0
2.0
2.5
2.6
2.6
4.0
Direct
cost
$ 78,000
4,550
13,800
45,000
6,500
8,400
22,500
20,200
Total direct cost (rounded) $199,000
Total direct cost =
Q
Total indirect cost =
d
Contingency
Total capital cost =
$199,000
75,600
41,200
$316,000 (rounded)
a Back-calculated from an estimated direct cost factor of 2.6
to approximate purchase cost.
b Back-calculated from an estimated direct cost factor of 4.0
Included is refractory for ductwork and quench chamber.
c Estimated at 38 percent of direct cost.
d Estimated at 15 percent of direct and indirect cost.
B-8
-------
Direct cost = $7.50/ft2 (3000 ft2) = $22,500.
The material portion is $8700.
H. REFRACTORY
The refractory is $9200 for the ductwork and $11,000
for the quench tower. The total installed cost is $20,200
The material portion is $5100.
B-9
-------
ESTIMATE OF ANNUAL COSTS
A. ELECTRICITY
Electricity is required to operate the shaker motors,
fan, pump, conveyor, and lights. Total kilowatt hours are
computed as follows :
Item Horsepower Kilowatts MWh
Fan system 35 26 156
Pump system 15 11 66
Screw conveyor 5 4 24
Shaker motors 7 5 30
Lighting 10 30
Total 306
The price of electricity in this area is 5 cents/kWh.
Therefore the total annual cost of electricity is:
306,000 kWh/yr ($0.50/kWh) = $15,300
B . WATER
Makeup water is required for the gas cooling system at
the rate of 1.9 liters/s (30 gpm) . The price of water in
the area is 6.6 cents/m ($0.2
total annual cost of water is:
the area is 6.6 cents/m ($0.25/10 gal). Therefore the
*0.066/m3 - "700
C. SOLID WASTE DISPOSAL
A total of 490 Mg/yr (540 tons/yr) of collected dust
will be disposed of by landfilling in sealed barrels. This
will cost $95 /Mg, including labor, shipment, barrels, and
disposal charge at the landfill. Therefore the annual cost
of solid waste disposal is:
490 Mg/yr ($95 } = $46,600.
B-10
-------
D. LABOR
It was estimated that about 2000 hours of labor would
be required to operate the entire system. Labor costs
$10/man-hour. Therefore the annual labor cost is:
2000 h/yr ($10/man-hour) = $20,000.
E. MAINTENANCE
Labor and materials, including bag replacement, are
estimated at 6 percent of the capital costs. An additional
15 percent of the labor and material is added to cover
supplies. The total maintenance expense is:
Labor and materials 0.06 ($316,000) = $18,960
Supplies 0.15 ($ 18,960) = 2,840
Total = $21,800
F. FIXED COSTS
Annual capital charges are estimated on the basis of a
10-year equipment life and a compound annual interest rate
on the capital of 10 percent. The capital recovery factory
is 0.16275. Therefore the capital charges are:
0.16275 ($316,000) = $51,400
Property taxes, insurance, overhead, and other admin-
istrative costs amount to 4 percent of the capital investment,
or 0.04 ($316,000) = $12,600.
B-ll
-------
SUMMARY OF ESTIMATED ANNUAL COSTS
Direct operating costs
A. Electricity $ 15,300
B. Water 2,700
C. Solid waste disposal 46,600
D. Labor 20,000
E. Maintenance 21,300
Total direct operating costs = $106,000
Fixed costs
F. Capital charges $ 51,400
Property taxes, insurance, etc. 12,600
Total fixed costs = $ 64,000
Direct operating = $106,000
Fixed costs = 64,000
Total annualized costs = $170,000
B-12
-------
TECHNICAL REPORT DATA
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-------
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